[Federal Register Volume 85, Number 234 (Friday, December 4, 2020)]
[Rules and Regulations]
[Pages 78412-78538]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-23164]
[[Page 78411]]
Vol. 85
Friday,
No. 234
December 4, 2020
Part II
Environmental Protection Agency
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40 CFR Parts 60, 63, 79, et al.
Fuels Regulatory Streamlining; Final Rule
Federal Register / Vol. 85, No. 234 / Friday, December 4, 2020 /
Rules and Regulations
[[Page 78412]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60, 63, 79, 80, 1042, 1043, 1065 and 1090
[EPA-HQ-OAR-2018-0227; FRL-10014-97-OAR]
RIN 2060-AT31
Fuels Regulatory Streamlining
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: This action updates many of EPA's existing gasoline, diesel,
and other fuel quality programs to improve overall compliance assurance
and maintain environmental performance, while reducing compliance costs
for industry and EPA. EPA is streamlining 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 applies to all gasoline, diesel, and
other fuel quality programs. This action does not change the stringency
of the existing fuel quality standards.
DATES: This rule is effective on January 1, 2021, except for amendatory
instructions 48, 51, and 52, which are effective on December 4, 2020,
and amendatory instructions 16, 18, and 19, which are effective on
January 1, 2022. The incorporation by reference of certain publications
listed in this regulation is approved by the Director of the Federal
Register as of December 4, 2020. The incorporation by reference of ASTM
D86-12, D93-13, D445-12, D613-13, D4052-11, and D5186-03 (R2009) in
part 1065 was approved by the Director of the Federal Register as of
June 27, 2014.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2018-0227. All documents in the docket are listed on the
https://www.regulations.gov website. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material is
not available on the internet and will be publicly available only in
hard copy form. Publicly available docket materials are available
electronically through https://www.regulations.gov.
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].
SUPPLEMENTARY INFORMATION:
Does this action apply to me?
Entities potentially affected by this final rule are those involved
with the production, distribution, and sale of transportation fuels,
including gasoline and diesel fuel. Potentially affected categories
include:
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Examples of potentially
Category NAICS \1\ code affected entities
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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.
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\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
action. This table lists the types of entities that EPA is now aware
could potentially be affected by this action. Other types of entities
not listed in the table could also be affected. To determine whether
your entity would be affected by this action, you should carefully
examine the applicability criteria in 40 CFR part 1090. If you have any
questions regarding the applicability of this 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 Other Parts of Title 40
III. Structure of 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. Extreme, Unusual, and Unforeseen 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
G. Downstream BOB 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. 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
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B. Special Provisions for Importation by Rail or Truck
C. Special Provisions for Importation by Marine Vessel
D. Gasoline 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 Waivers
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
L. Congressional Review Act (CRA)
XVI. Statutory Authority
I. Executive Summary
A. Overview of Fuels Regulatory Streamlining
1. Why EPA Is Taking This Action
In this action, we are streamlining and modernizing our 40 CFR part
80 (``part 80'') fuel quality regulations to minimize the
implementation burden associated with them while still ensuring that
the fuel quality standards previously established under the Clean Air
Act (CAA) continue to be met in real-world use. We are doing so by
transferring the relevant part 80 provisions into a new set of
regulations in 40 CFR part 1090 (``part 1090''). After taking a
detailed look at the many different and overlapping requirements in the
part 80 regulations, it became apparent that a holistic update to the
regulations was better accomplished by redrafting them into an entirely
new part. The new part 1090 regulations will also better reflect how
fuels, fuel additives, and regulated blendstocks are produced,
distributed, and sold in today's marketplace and help regulated parties
more easily identify regulatory requirements.
2. What Is and Is Not Covered in This Action
This action focuses primarily on streamlining and consolidating the
gasoline and diesel fuel programs that reside in part 80.\1\ To
accomplish this, we are removing expired provisions and consolidating
the remaining provisions from multiple fuel quality programs into a
single set of provisions. 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 streamlining
action combines 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 Renewable Fuel Standard (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, which are established
under CAA section 211(a), (b), (e) and (o), are significantly
different in scope, and would involve different considerations to
update those regulatory requirements.
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The majority of this action's changes 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 impose any new standards on fuels. As such, this action is
mostly a compilation of numerous, relatively minor changes to the
existing provisions under part 80. Many of these 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 changes will lead to a more effective,
efficient EPA fuel quality program.
While this action changes many aspects of our fuel quality
programs, there are several areas of the part 80 regulations that
remain unchanged even as those regulations are transposed into part
1090. Most importantly, this action does not change the stringency of
the existing fuel quality standards. We are simply streamlining and
consolidating the part 80 fuel quality programs into a single
streamlined fuel quality program that will make compliance with the
existing fuel quality standards established under part 80 more
straightforward to implement and comply with. As a result, in addition
to reducing costs, it may also enable improved fuel quality through
increased compliance with our fuel quality standards. This action
transfers the part 80 fuel quality standards mostly unchanged to part
1090, though in some cases we are modifying the form of a standard to
translate it into a format more conducive to streamlining the
regulations and ensuring in-use compliance.
With minor exceptions, this action also does not change the
provisions of the RFS program, which will remain in subpart M of part
80, The subpart M regulations are mostly unique to the RFS program.
However, since the RFS program uses similar, if not the same, reporting
systems and compliance mechanisms for parties to demonstrate
compliance, we are finalizing some parallel changes to help ensure that
this consistency is maintained or enhanced as a result of this action.
This will help ensure consistency in how parties comply with our
regulatory requirements and report information to EPA. We received a
number of comments asking for more substantive changes to the RFS
program; we consider these comments outside the scope of this
rulemaking.\2\
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\2\ We also noted in the NPRM that we would treat these comments
outside the scope of this action. See 85 FR 29036 (May 14, 2020).
Additionally, we are not reopening any aspects of the RFS program or
any RFS regulations, other than to make minor edits that are
intended to ensure consistency with the new language used in part
1090.
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Finally, this action does not remove any statutory requirement for
fuels specified by the CAA. For example, this action does not 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 remove cetane index limits for diesel fuel under
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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, we
are not eliminating any requirement under the CAA for fuels and parties
that make, distribute, and sell such fuels.
We recognize that while we are not changing the standards, in some
cases, the consolidation of certain provisions may slightly, indirectly
affect in-use fuel quality. For example, 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 national annual average sulfur
level. On the other hand, the provisions that 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 streamlined fuels program will maintain
the same overall level of fuel quality as the part 80 regulations. We
discuss the cumulative costs and benefits of these changes in more
detail in Section XIV.
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 taken action
on three key elements that are included in part 1090:
A simplification of the RFG summer volatile organic
compound (VOC) standards.\3\
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\3\ CAA section 211(h)(1) requires EPA to establish volatility
requirements--that is, a restriction on Reid Vapor Pressure (RVP)--
during the high ozone season. To implement these requirements, under
part 80, EPA defined ``high ozone season'' as the period from June 1
to September 15. Also under part 80, the regulations specify that
all parties (except for retailers) must make and distribute gasoline
meeting the RVP standards from May 1 through September 15 and calls
this period the ``regulatory control period.'' In general practice
by industry and for purposes of this preamble, the high ozone season
and regulatory control period are referred to as the ``summer'' or
``summer season'' and gasoline produced to be used during the
regulatory control period and high ozone season is called ``summer
gasoline.'' EPA's regulations do not impose any volatility
requirements on any type of blend of gasoline outside of the summer
season. In part 1090, we are maintaining the terms regulatory
control period and high ozone season as they are implemented under
part 80.
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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 simplifying the RFG standards by translating the part
80 summer RFG VOC standard into an RVP per-gallon cap of 7.4 psi. This
change allows us to remove the use of the Complex Model \4\ as a
requirement to certify batches of gasoline and remove all the
provisions associated with demonstrating compliance on average. This
change also allows for us to minimize the restrictions on the
commingling of RFG and CG, allowing for a more fungible and efficient
gasoline distribution system.
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\4\ 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.
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Under part 80, the main remaining difference between RFG and CG is
the summer volatility. Under part 80, RFG's volatility is functionally
controlled through a summer VOC performance standard determined with
the Complex Model pursuant to CAA section 211(k). In contrast, CG
volatility is controlled through the RVP per-gallon maximum standards
established under CAA section 211(h). EPA has previously aligned the
treatment of RFG and CG for NOX performance through the Tier
2 gasoline sulfur program and toxics performance through the national
gasoline benzene program.\5\ This action aligns treatment for RFG and
CG by translating the existing RFG VOC performance standard into a
maximum RVP per-gallon standard, as is the case for CG in the summer.
In Section V.A.2, we describe how the 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 quality standards. With this
translation of the RFG summer VOC performance standards into a summer
RFG maximum RVP per-gallon standard, the required controls on RFG fuel
properties will be identical to the control of CG fuel properties, even
though the RVP standards themselves will remain different.
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\5\ See 72 FR 8428 (February 26, 2007).
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Second, since the standards for volatility, benzene, and sulfur
will be treated similarly for both RFG and CG, this will allow for the
streamlining and consolidation of the compliance and enforcement
provisions of the various part 80 gasoline quality programs into a
single fuel quality program in part 1090. This consolidation will
improve consistency, remove duplication, and ultimately reduce
compliance burden on both regulated parties and EPA. For example, 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. In part 1090, we are
consolidating the various gasoline reporting requirements into a
single, unified annual reporting requirement.
Third, the streamlined fuel quality program aims to improve
oversight of our fuel quality programs while reducing its cost. We hope
to accomplish this by updating and improving the third-party oversight
programs we already use in part 80. In part 1090, we are consolidating
the four existing in-use survey programs into a single national in-use
fuel quality survey. This program will help ensure that all fuels
nationwide continue to meet EPA fuel quality standards when dispensed
into vehicles and engines, not just at the fuel manufacturing facility
gate. We are also replacing the RFG independent lab testing requirement
with a voluntary national sampling and testing oversight program
(NSTOP). The NSTOP will 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
updating and modernizing the annual attest engagement program. These
updated procedures will help ensure the quality and consistency of
reported information. Taken together, we believe these provisions will
help improve oversight of our streamlined fuel quality program.
B. Summary of Stakeholder Involvement and Rule Development
We 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 fuels
regulatory streamlining program achieved its goals
[[Page 78415]]
and that the final regulations were ready for a smooth implementation.
This included making available four discussion drafts of the proposed
regulations on our Fuels Regulatory Streamlining website.\6\ We also
held a three-day public workshop on a variety of topics in Chicago on
May 21-23, 2018.\7\ 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. The streamlined fuel quality program in
this action reflects the valuable input of all those who provided
feedback to EPA both before and after the proposal.
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\6\ See https://www.epa.gov/diesel-fuel-standards/fuels-regulatory-streamlining. The four discussion drafts are available in
the docket for this action.
\7\ See 83 FR 20812 (May 8, 2018).
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C. Timing
As discussed in more detail in Section III.B, most of the part 1090
regulations will 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 will provide for a smooth transition to the new
regulatory requirements. This is supported by commenters who have had
to prepare for this transition. However, we also received a number of
comments requesting that certain provisions begin implementation at a
later date due to the short lead time available. As discussed in
Section III.B, we are allowing certain provisions to begin
implementation at a later date.
D. Costs and Benefits
We do not anticipate changes in air quality as a result of this
action. This is largely due to the fact that we are not making changes
to the existing fuel quality standards. As such, we do not expect that
regulated parties will 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.
We believe that this action will 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 largely arise from the reduction
of the administrative costs on both 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 $40.4 million per year ($2019). Other savings
associated with improving the fungibility of fuel and providing greater
flexibility could potentially be even more significant but we have been
unable to quantify these savings. Section XIV discusses in more detail
the potential costs and benefits of this action.
II. Changes to Other Parts of Title 40
We are transferring several provisions in part 80 that are
currently in effect to part 1090. These provisions are all discussed in
the subsequent sections of this preamble and are now presented in a
manner that makes them easier to understand. Within part 80, we are
also removing subparts D, E, F, G, H, I, J, K, L, N, and O and
appendices A and B to part 80 in their entirety, along with most of
subpart B. 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 superseded by subpart O (Tier 3 Sulfur),
and subpart J (MSAT1) was supplanted by subpart L (MSAT2)). However, in
order to help enable the transition from part 80 to part 1090 and since
a number of 2020 compliance demonstration requirements have deadlines
in 2021 (e.g., reporting, attest engagements), these part 80 provisions
will remain in the CFR until the end of 2021.
We are not transferring some provisions from part 80 to part 1090.
First, we are retaining the current RFS provisions in subpart M. We are
making 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 will make it consistent with part
1090 and much easier to find terms.
Third, 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.
Finally, we received a comment concerning how to adapt or apply the
filler-neck requirements for current and future vehicle designs. The
commenter suggested that it would be inappropriate for EPA to carry-
forward these provisions without significant changes to address issues
related to current and future vehicle designs and that such an effort
should be taken in a future rulemaking that specifically addresses
these issues. We agree with commenter's suggestion to address these
issues in a later rulemaking as such modifications to the filler-neck
requirements were not proposed and thus, are outside the scope of this
rulemaking. As a result, we are not finalizing the movement of the
filler-neck provisions of 40 CFR 80.24 to part 1090. Those provisions
in part 80 will continue to apply.
In addition, several commenters identified cross-references to part
80 in other parts of Title 40 that need to be revised to instead
reference part 1090. We have made the revisions identified by the
commenters and have updated cross-references in 40 CFR parts 60, 63,
and 1043. We similarly determined that there were references to part 80
in 40 CFR parts 1042 and 1065. Most of these updated cross-references
simply correct citations. These changes are discussed in more detail in
Section 2 of the RTC document.
III. Structure of Regulations and General Provisions
This section describes the general structure of part 1090 (i.e.,
the modified structure of the regulations to make them more accessible
to users and readers of the regulations). This section also describes
implementation dates, how we will treat prior approvals made under part
80, and our approach to consolidating the existing definitions in part
80. Finally, this section discusses key provisions (e.g., the
definition of fuels) in more detail, as these provisions are
fundamental to the streamlined fuel quality program.
A. Structure of the Regulations
We are finalizing a regulatory 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
[[Page 78416]]
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 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).
Under part 1090, subpart A contains general requirements that apply
throughout the rest of the part. 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 provisions are described elsewhere in this
preamble; for example, rounding of data is discussed Section VIII.F and
batch numbering is discussed in Section VIII.G.
We are also including a list of general regulatory requirements for
parties in subpart B. This subpart lays out the general regulatory
requirements for regulated parties. This will help 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. We
received feedback from several stakeholders that such a roadmap would
be helpful for them to find and follow the regulatory requirements in
part 1090 and would be especially helpful to those new to the
regulations.
We also placed the standards for different fuels in separate
subparts so as to make it easier for parties to identify the specific
standards that apply to each fuel, regulated blendstock, and additive.
We placed the gasoline-related standards and the diesel-related (plus
IMO marine fuel) standards separately in subparts C and D,
respectively. We are leaving subpart E reserved, as we may need to use
that subpart for future standards and this will enable us to maintain
subsequent subparts to avoid unnecessary confusion within regulated
community.
The next block of subparts (F through Q) 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
(e.g., we have consolidated all the registration sections of part 80
into 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 manufacturer or oxygenate blenders).
Subpart R includes the liability, compliance, and violation
provisions that EPA will use to enforce the program. This subpart
consolidates the similar sections from across part 80 into a single
streamlined subpart.
Finally, subpart S includes the attest engagement procedures that
auditors will use to conduct annual auditing of reports and records for
gasoline manufacturers. These procedures are updated versions of the
those previously included in part 80.
We believe that this new structure will 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. In general, comments received on the
structure were supportive of the ease and clarity with which regulatory
requirements were laid out. Therefore, we are finalizing the regulatory
structure in part 1090 as proposed.
B. Implementation Dates
We are finalizing the implementation date for most provisions of
part 1090 on January 1, 2021. This implementation date will result in
the first compliance reports under the new part 1090 regulations being
due March 31, 2022, for the 2021 compliance period, and the first
attest engagement reports being due June 1, 2022.
We believe that this schedule minimizes the need for immediate
changes to how regulated parties comply with our fuel quality
regulations, and therefore 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 will
result from consolidating the programs into a single national program.
Where possible, we wrote the requirements to allow flexibility for
regulated parties to adjust as needed. We also believe that this
schedule honors the significant effort and commitment that those
impacted by the regulations have already put into their plans to
transition from part 80 to part 1090 compliance.
In the NPRM, we sought comment on whether regulated parties needed
more lead time to comply with any of the proposed regulatory
provisions. While we received strong support for most provisions
beginning on January 1, 2021, we received many comments suggesting that
certain provisions of part 1090 be implemented at a later date to
provide sufficient lead time but without impacting the overall
implementation schedule. In particular, commenters highlighted the
product transfer document (PTD) requirements and the NSTOP provisions
as two areas where more lead time is needed.
For PTDs, several commenters suggested that it will take several
months to modify computer systems to print the appropriate language on
PTDs and work with pipelines and other distributors of fuels to develop
the necessary product codes to comply with the part 1090 PTD
requirements. They expressed concern that the time between when this
action is finalized and its implementation on January 1, 2021, may not
allow sufficient lead time, and suggested that we allow regulated
parties to begin complying with the PTD provisions no later than May 1,
2021. This would then coincide with the next natural change in the
marketplace with the onset of the summer RVP requirements in gasoline.
Since the need for PTD changes is also less important prior to May 1,
2021, as RFG and CG are fungible in the winter under part 1090, we are
delaying the
[[Page 78417]]
PTD implementation date until May 1, 2021, as requested. However,
parties may opt to comply with the part 1090 PTD requirements earlier
than May 1, 2021.
Regarding the NSTOP, parties noted that the mechanics of signing up
with an independent surveyor, having EPA approve a plan, and then to
begin having the independent surveyor obtain samples from fuel
manufacturing facilities would require several months. Commenters also
noted that since the program was new, there were several details that
would need to be worked out in advance prior to the NSTOP being able to
be implemented. Commenters also requested that if EPA did grant more
lead time for the NSTOP, that the number of visits under the NSTOP
should be adjusted to account for the fact that the program would not
run for the entire 2021 compliance period. We believe it is both
reasonable to provide more lead time for the NSTOP and that the number
of visits under the NSTOP should be adjusted accordingly. Therefore, we
are allowing the NSTOP to begin no later than June 1, 2021, as
suggested by the commenters. We believe that this will provide enough
lead time for fuel manufacturers to register with the program, the
independent surveyor to have a plan approved by EPA, and for the
independent surveyor to begin visiting fuel manufacturing facilities.
We are also only requiring the independent surveyor to visit
participating fuel manufacturing facilities one time during the 2021
compliance period instead of the typical two visits. Since our goal is
to maximize participation in this voluntary program, we believe
providing more lead time and reducing the number of required visits in
2021 will help incentivize fuel manufacturers to participate in the
program.
We address other comments related to implementation dates and lead
times in Section 4 of the response to comments (RTC) document.
C. Prior Approvals
We are allowing regulated parties with existing approvals under
part 80 to maintain those approvals under part 1090. For example,
parties registered under part 80 will not need to re-register 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, and also
not be consistent with the purposes of regulatory streamlining.
However, this action requires that any new requests or updates to
approvals currently necessary under part 80 will have to meet the new
regulatory requirements of part 1090.
For existing approvals under part 80, regulated parties do not need
to update any previously approved submission under part 1090. For
example, we have approved alternative E15 labels under part 80. Parties
do not need to have these labels reapproved in order to use them under
part 1090. One notable exception is for in-line blending waivers for
gasoline. As discussed more in Section XIII.G, we are making
significant changes to the in-line blending waiver provisions for RFG
(mostly to remove provisions related to parameters that will no longer
need to be reported) and for CG to make them consistent with the RFG
in-line blending waiver provisions. As such, we are requiring
resubmission of all in-line blending waiver requests to ensure that
they meet the new requirements under part 1090.
Commenters were supportive of our proposed treatment of prior
approvals from part 80 under part 1090 and we are finalizing as
proposed. We address these comments in Section 4 of the RTC document.
D. Definitions
In part 1090, we are streamlining and updating the definitions
contained throughout part 80, as well as adding and removing terms as
needed to write the 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 have added additional subparts to part 80 for each new fuels
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 of the same term for the different standards, making 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. Generally, we have tried to avoid
having a definition section within individual subparts; however, some
infrequently-used terms may still be defined in the context of the
regulatory text. We believe this approach helps the regulated community
and the public at large to more easily comprehend the regulations.
For the most part, we are simply transferring the existing part 80
definitions into part 1090 with minor changes to specific terms for
consistency. However, in some cases, we are redefining or reclassifying
key terms in 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 revising the definition of fuels (e.g.
``gasoline'' and ``diesel fuel''), which is discussed in Section
III.D.3.
For most proposed definitions, commenters were supportive or
provided suggestions or requests for clarification regarding specific
terms. We address these comments in Section 4 of the RTC document.
1. Fuels, Fuel Additives, and Regulated Blendstocks
In order to improve the clarity and consistency of our regulations,
we are changing how we classify products regulated under our fuel
quality regulations in part 1090. In part 80, most fuel programs were
written as a separate fuel program rather than a single, consolidated
fuel quality program. For example, under part 80, subpart I almost
exclusively deals with distillate fuels and subpart N deals with
gasoline-ethanol blended fuels. Since part 1090 consolidates all fuel
quality programs from part 80 (excluding the RFS program) 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 in (i.e., gasoline-
fueled, diesel-fueled, or in a vessel subject to Annex VI to the
International Convention for the Prevention of Pollution from Ships
(``MARPOL Annex VI'') requirements (e.g., vessels that must use
Emission Control Area (ECA) or IMO marine fuel)). For gasoline-fueled
engines, we not only define the term gasoline (discussed 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 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),
[[Page 78418]]
we are defining this fuel simply as ULSD, as it is more commonly known
in the market. 500 ppm diesel fuel produced from transmix continues to
be allowed in limited circumstances for certain locomotive and marine
applications.
Regarding regulated blendstocks, we have historically not imposed
quality specifications on such blendstocks, choosing instead to focus
compliance requirements on fuels that are ultimately used in vehicles
and engines. However, as the fuels marketplace has continued to evolve,
using this structure has become increasingly difficult to accommodate
the complexity of fuel manufacturing and distribution practices today.
Therefore, we are including alternative provisions, which are currently
allowed in 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 imposed standards collectively as ``regulated
blendstocks.'' For example, under both part 80 and part 1090, we allow
gasoline manufacturers 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 (referred to as
``certified butane'').\8\ These certified butane blenders can use these
provisions instead of certifying the finished gasoline and having to
meet sulfur and benzene annual standards as these provisions are
designed to ensure that the amount of sulfur and benzene in the
national gasoline pool does not increase as a result of blending these
feedstocks. Under part 1090, we are including similar flexibilities as
under part 80 for gasoline manufacturers that wish to blend butane that
has been certified to meet specifications (differences regarding butane
blending between part 80 and part 1090 are discussed in Section V.A.3).
---------------------------------------------------------------------------
\8\ 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 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, under part 80 and part 1090 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. 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.
We received a comment suggesting that our proposed definition of
fuel additive was unnecessarily restrictive on gasoline-ethanol blends.
In response, we have revised the part 1090 definition of fuel additive
to have the same meaning as ``additive'' under part 79. We further
address this comment in Section 6 of the RTC document.
2. Fuel Manufacturers, Regulated Blendstock Producers, and Fuel
Additive Manufacturers
We are finalizing the definitions related to parties described as
fuel manufacturers, regulated blendstock producers, and fuel additive
manufacturers as proposed. In part 80, a refinery is broadly 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.'' \9\ A refiner is ``any person who owns, leases, operates,
controls, or supervises a refinery.'' \10\ 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 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.
---------------------------------------------------------------------------
\9\ 40 CFR 80.2(h).
\10\ 40 CFR 80.2(i).
---------------------------------------------------------------------------
Under part 1090, the term fuel manufacturer describes 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 to make fuel or blending blendstocks into a previously
certified fuel to make a new batch of 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 part 79 and the CAA. Under
part 1090, we also distinguish further between parties that refine
feedstocks to make fuels (more commonly known as ``crude refiners'' or
simply ``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.\11\ Part 1090 includes requirements specific to the
type of fuel manufacturer, and this nomenclature makes it easier for us
to describe the specific requirements for each type of fuel
manufacturer and for parties to understand what requirements apply
specifically to whom. However, while we are modifying the terminology
used in part 1090 for these parties, these parties will generally have
the same obligations and responsibilities as currently required under
part 80.
---------------------------------------------------------------------------
\11\ Under this approach, transmix processors are also
considered fuel manufacturers.
---------------------------------------------------------------------------
We are defining producers of regulated blendstocks as regulated
blendstock producers. For example, these parties would include
certified butane/pentane producers.
As is the case currently under part 79 and part 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 is a blending manufacturer, as
the compound added is considered a blendstock and parties that add
blendstocks into fuel are considered fuel manufacturers and need to
meet all the applicable regulatory requirements. Consistent with part
79, oxygenate blenders that only add oxygenates at levels permissible
under
[[Page 78419]]
CAA section 211(f) continue to be considered oxygenate blenders and not
fuel manufacturers.
3. Definition of Fuels
We are finalizing our proposed definitions for fuels (e.g.,
gasoline, diesel fuel, ECA marine fuel, etc.), largely as proposed. In
the NPRM, we outlined a consistent framework for how we would define
fuels to help ensure that compliant fuel is ultimately used in
vehicles, engines, and equipment. To achieve this goal, we believe that
the definition of fuels 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 crude oil refineries still have
the most direct impact on 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 a key determinant
of the quality of the fuel that actually goes into the vehicle. For
example, downstream parties add oxygenates to gasoline (primarily
ethanol) and often augment the volume of gasoline through the blending
of various blendstocks into PCG to produce new fuels.
To ensure that fuels meet fuel quality standards from the crude oil
refinery until they are dispensed into vehicles or engines, in light of
the changing fuels marketplace, we believe that any definition of a
fuel should contain three elements. First, when a party represents a
fuel as meeting EPA's fuel quality standards, such fuel is subject to
EPA standards regardless of whether the fuel actually meets the
standards. Were this not the case, then anytime a fuel failed to meet
EPA standards, we could not hold anyone accountable for failing to meet
the standards. In part 1090, we define regulated fuels as anything
commonly and commercially known as that particular fuel. This portion
of the definition is consistent with the existing definitions of
gasoline, diesel fuel, and ECA marine fuel in part 79 and part 80.
The second element of the definition of a fuel is whether a product
is used or intended for use as a fuel in a vehicle or engine covered by
EPA regulations (e.g., a product that is used or intended for use in
vehicles and engines that are designed to use gasoline is gasoline).
Since the ultimate purpose of EPA's fuel quality standards is to ensure
that compliant fuel is used in vehicles and engines, if a person uses
or 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 is gasoline (i.e.,
a fuel) and is subject to EPA's gasoline standards. The same holds true
for diesel fuel or any other regulated fuel. We have used this
terminology previously when describing other fuels under part 80,
notably in definitions related to motor vehicle diesel fuel \12\ and
ECA marine fuel.\13\
---------------------------------------------------------------------------
\12\ See 40 CFR 80.2(y).
\13\ See 40 CFR 80.2(ttt).
---------------------------------------------------------------------------
The third element of the definition of a fuel relates to the
physical and chemical characteristics of the fuel. Whether a product is
a fuel and therefore subject to our standards and regulatory
requirements cannot be solely based on whether a regulated party calls
or labels it as a particular fuel. This would create an incentive for
parties to simply label products intended for use as fuels by another
name to avoid having to meet EPA's fuel quality standards and
regulatory requirements. Therefore, when a manufacturer produces a
product that is chemically and physically similar to a fuel, the
product is a fuel and is subject to EPA's fuel quality standards and
regulatory requirements. To address this element, we are specifying
that gasoline is any product that meets the voluntary consensus
standards body (VCSB) industry specifications for gasoline (ASTM D4814)
and diesel fuel is any product that meets industry specifications for
diesel fuel (ASTM D975).
In the NPRM, we proposed that certain blendstocks that met ASTM
D4814 could be excluded from the definition of gasoline if those
blendstocks were not made available as gasoline even though they may
otherwise meet the definition of gasoline by meeting ASTM D4814
specifications. We also proposed to apply this same ``made available''
provision to diesel fuel and other fuels covered by part 1090. We
explained that ``[s]ince 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 and ECA marine fuel.'' \14\
---------------------------------------------------------------------------
\14\ 85 FR 29034, 29040 (May 14, 2020).
---------------------------------------------------------------------------
We received several comments asking for compliance assistance
regarding how a company can make sure that EPA will not consider a
blendstock that has the same chemical and physical characteristics as a
fuel to be a fuel subject to part 1090 standards. In general, we
consider any fuel that is stored, sold, or placed into a fuel
distribution system that supplies fuel for use in gasoline-fueled
vehicles, diesel-fueled vehicles, or marine vessels as being ``made
available for use'' in these vehicles or vessels unless the party who
produces or distributes the fuel can demonstrate that the fuel was not
used, intended for use, or made available for use in these vehicles or
vessels.
For example, if a person mixes two distillate blends in a tank and
identifies the product as a distillate blend when it loads the product
onto a barge that will transfer the fuel to a ECA marine fuel
propulsion tank in a marine vessel, we would consider the product to be
ECA marine fuel that has been made available for use in a marine vessel
and the person would be subject to all of the requirements that apply
to fuel manufacturers and distributors under part 1090, including
sampling, testing, recordkeeping, and PTD requirements and marine fuel
standards. On the other hand, if a person loads a product identified as
a distillate blend onto a rail car and has commercial documents showing
that the product was sold to a heating oil distributor who only
distributes heating oil and the fuel is specifically identified to be
used for the sole purpose of heating oil, we would not consider the
fuel to be made available for use in a marine vessel.
There are certain products currently in the fuel distribution
system that were previously not designated as ``ECA Marine Fuel'' or
``Global Marine Fuel.'' Instead, fuel suppliers have designated these
products in accordance with other naming conventions and commonly using
terms identified in the International Organization for Standardization
(ISO) Petroleum products--Fuels (class F)--Specification of marine
fuels (ISO 8217). Examples of these fuel designations include DMX, DMA,
DMZ, and DMB (generally referred to by industry as ``marine gas oil''
or ``MGO'') and RMA, RMB, RMD, RME, RMG, and RMK. If a fuel is
designated by one of these terms or as a product that is commonly or
commercially known to be made available fuel use in marine vessels, we
will consider the product to be IMO marine fuel as the fuel has been
made available for use in a marine vessel and is subject to all of the
requirements for IMO marine fuel in part 1090 (as well as the
applicable regulations in part 1043). We also note that intentionally
mis-designating a fuel to avoid
[[Page 78420]]
regulatory requirements does not mean those requirements are not
applicable nor does it insulate a fuel supplier from potential civil or
criminal enforcement.
Since there are many different and complex fuel distribution
systems and channels in the U.S., we will evaluate whether a fuel is
made available for use in a gasoline-fueled vehicle, diesel-fueled
vehicle, or marine vessel on a case-by-case basis.
IV. General Requirements for Regulated Parties
We are including a subpart dedicated to outlining the general
regulatory requirements for each regulated party in part 1090 (subpart
B). The regulations in part 80 are almost 1,000 pages long, and many
regulated parties currently spend a substantial amount of time and
resources to comprehend and interpret them or ask EPA staff to identify
applicable regulatory requirements.
To make the streamlined regulations more accessible, we are making
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 part 1090 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 will 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 hiring consultants to help them understand
their regulatory requirements. Retailers also have a relatively small
number of regulatory requirements under part 80 and part 1090. By
identifying the generally applicable requirements that apply to all
retailers, these small businesses could more easily identify those
requirements that apply to them, helping them to more easily comply
with EPA's 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 will still need to comply with all
applicable requirements contained in part 1090, regardless of whether
they are identified for them in subpart B. We cannot predict every
possible situation a party may be in within the marketplace now or in
the future. Accordingly, regulated parties, as always, should pay
careful attention to all the applicable regulatory requirements to
ensure compliance.
Commenters were generally supportive of the proposed structure of
subpart B and found it helpful to regulated parties in general. We also
received comments that included suggested edits to subpart B. We
address these comments in Section 5 of the RTC document.
V. Standards
A. Gasoline Standards
1. Overview and Streamlining of Gasoline Program
We are consolidating the various gasoline standards from part 80
into a single subpart in part 1090 (subpart C). We are neither changing
the gasoline lead, phosphorous, sulfur, benzene or RVP standards, nor
modifying the standards for oxygenates (including DFE), certified
ethanol denaturant, gasoline additives, and standards for certified
butane and certified pentane. These standards are simply being moved
and consolidated into subpart C.
To further streamline the gasoline program, we are altering 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 will 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 translating the RFG standard from the demonstration
of the VOC performance standard via the Complex Model into an
equivalent maximum RVP per-gallon standard, which allows us to greatly
simplify the compliance demonstration requirements for RFG. Of all the
provisions being finalized, this is the key provision enabling
considerable streamlining of the existing gasoline regulations.
Second, we are consolidating the two grades of butane and 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 greatly simplifies the registration and reporting of
activities related to blending certified butane and certified pentane.
Finally, we are establishing 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.\15\
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\15\ The proposed changes to the transmix provisions for
gasoline and diesel fuel are addressed in Section XIII.E.
---------------------------------------------------------------------------
2. RFG 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
volatility of 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: (1) Replacing the
existing compliance mechanism used for RFG batch certification--the
Complex Model--with a summer maximum RVP per-gallon standard (``RVP
standard''); (2) applying that same single RVP standard to all RFG
nationwide; (3) provide greater flexibility for blending of oxygenates
(e.g., ethanol and isobutanol) and E0 in RFG areas; and (4) removing
several other restrictions that currently create a distinction without
a difference between RFG and CG.
We intend these changes to maintain the stringency of all standards
associated with RFG while alleviating unnecessary compliance burden. We
acknowledge that the CAA requires the existence of RFG in specified
nonattainment areas \16\ and certification procedures to certify RFG as
complying with the requirements.\17\ This action will simplify and
translate the previously established requirements while still
maintaining the same level of VOC emissions reductions as currently
required. This will be accomplished by translating the current VOC
emissions reductions demonstrated through the Complex Model into an RVP
standard that will be used to demonstrate RFG
[[Page 78421]]
VOC compliance in lieu of the Complex Model.\18\
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\16\ CAA section 211(k)(1).
\17\ CAA section 211(k)(4)(A).
\18\ Currently, refiners use the Complex Model to demonstrate
compliance with the RFG provisions. Under part 1090, refiners are
required to instead demonstrate compliance by testing the RVP of the
fuel, along with benzene and sulfur as currently required under part
80.
---------------------------------------------------------------------------
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 largely through the use of an RVP standard
in combination with the previously established sulfur standard.
The RFG RVP standard of 7.4 psi was specifically chosen in order to
maintain the summer VOC performance required by the statute,\19\ and
this RVP is currently observed in the RFG 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.b. This consolidation
of RFG VOC Regions, along with other changes in this action, will
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.
---------------------------------------------------------------------------
\19\ 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.'' Our 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).
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Additional benefits from this action are potentially wide reaching
as it could create opportunities for broader availability of fuels and
reduced consumer costs. By having a single RVP standard for RFG, in
situations of fuel shortage in RFG areas during the summer, 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
(e.g., E0 or isobutanol blends) 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, using
the downstream gasoline before oxygenate blending (BOB) recertification
provisions discussed in Section VII.G, it will be easier for
distributors to provide ethanol-free gasoline to consumers in these
areas.
a. 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, we proposed
that, under part 1090, any summer RFG batch meeting an RVP standard of
7.4 psi would be deemed compliant with the RFG VOC emission performance
reduction standard. Many commenters were supportive of this approach,
and we are finalizing these regulations as proposed.20 21
Along with RVP, benzene concentration for MSAT2 compliance, and sulfur
content for Tier 3 compliance will also be reported to EPA. Thus, all
three of the emission reduction standards for RFG will be covered by
just three parameters: RVP, benzene, and sulfur. This will reduce the
compliance and reporting burden for gasoline manufacturers by reducing
the number of parameters they need to test and report from 11 to as few
as 3 in the summer.22 23
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\20\ 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.
\21\ The process and rationale for the RFG maximum RVP per-
gallon standard of 7.4 psi discussed in ``History, Methods, and
Underlying Data Support for RFG Standard Translation to RVP,''
available in the docket for this action.
\22\ As discussed in Sections VIII and IX, blending
manufacturers will need to sample, test, and report for additional
fuel parameters.
\23\ Typically, under part 1090, gasoline manufacturers must
sample for sulfur, benzene, and, for summer gasoline, RVP for batch
certification. In cases where gasoline manufacturers are certifying
a batch of gasoline that has already had oxygenate added (not
including a hand blend), the manufacturer must also test for
oxygenates. In addition, blending manufacturers must also test
batches of gasoline for distillation parameters. Therefore, a
gasoline manufacturer must test between 3 and 5 parameters under
part 1090.
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Our intent in translating the VOC performance standards into a
maximum RVP per-gallon standard is to both ensure that the emission
reduction targets for RFG and the current emissions performance will
continue to be achieved. In determining the RFG 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 7.4 psi RVP
standard for RFG will 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 national fuels
survey program (NFSP). Continued adherence to the RFG VOC emission
performance reduction standard will be monitored through samples
collected from RFG areas as part of the NFSP. This oversite function
will help ensure that the emission reductions the Complex Model was
intended to certify at the fuel manufacturing facility gate are being
maintained in use.
b. Consolidation of RFG VOC Control Regions
Translating the VOC emissions performance standard into a summer
RVP standard enables EPA to simplify the RFG program significantly.
Additionally, the creation of a single summer RVP standard for all RFG
areas further simplifies the RFG program and automatically consolidates
the VOC regions as required under section 1504(c) of EPAct, which
directs EPA to revise the RFG regulations to consolidate the
regulations for the VOC-Control Regions by eliminating the less
stringent requirements.\24\
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\24\ 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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[[Page 78422]]
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 RFG areas. The summertime RFG VOC emission performance
standard for RFG VOC Region 2 is slightly less stringent than RFG VOC
Region 1. To date, EPA had not taken action to consolidate the VOC
regions as directed by EPAct. However, the creation of a single RFG RVP
standard provided both an opportunity and a mechanism by which to act
on this requirement. A benefit of this consolidation will be the
increased fungibility of RFG amongst historically distinct VOC-control
regions. Furthermore, we find that the EPAct language provides EPA with
an additional source of authority to take this final action to
translate the VOC performance standard into a single RVP standard.
c. Additional Changes Related to RFG
We are also finalizing regulations intended to allow for greater
compliance flexibility and increased gasoline fungibility for the RFG
program. Specifically, as discussed in Section VIII.G, we are
finalizing 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
comingling RFG and CG in the winter exists.
To address this situation, we are finalizing provisions to allow
all winter gasoline to be used in RFG areas without recertification.
Distributors of gasoline will be allowed to designate winter gasolines
without recertification as RFG or CG to comport with state or pipeline
specifications, which may require those distinctions.
All comments received on the proposed RFG RVP standard of 7.4 psi,
consolidation of the VOC control regions, and improved fungibility
provisions for RFG were supportive. We did, however, we receive
comments asking for minor edits to and clarifications of the regulatory
requirements for RFG under part 1090. We address these comments in
Section 6 of the RTC document.
3. Certified Butane and Pentane
We are streamlining the provisions for gasoline blending
manufacturers that blend butane and pentane of certified quality
(certified butane and certified pentane, respectively) into PCG.\25\
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 basic approach is maintained in
part 1090.
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\25\ 40 CFR 80.82 and 80.85, respectively.
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Part 80 has two grades of butane and pentane (commercial and
noncommercial) that can be used by gasoline blender manufacturers under
these provisions. We are combining these grades into single grades of
``certified butane'' and ``certified pentane.'' Consolidating the
grades of butane and pentane allows for streamlined compliance
demonstrations for certified butane and certified pentane blenders to
produce gasoline using certified butane and certified pentane.
The part 80 standards for commercial and noncommercial grades of
butane and pentane contain specifications on the maximum sulfur,
benzene, olefin, and aromatics content. Consistent with the changes to
RFG certification discussed in Section V.A.2, we are removing the
maximum olefin and aromatics standards from the specifications for
certified butane and certified pentane. Under part 1090, both certified
butane and certified pentane will continue to 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 under part 80. 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 and higher carbon number hydrocarbons specification.\26\
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. In
part 1090, we are removing the standard on C6 and higher hydrocarbon
content for certified pentane given that compliance with the 95 volume
percent pentane purity specification ensures that no more than 5 volume
percent C6 and higher hydrocarbons are present. We did not receive any
adverse comments to this proposal for certified pentane standards, and
so we are finalizing the certified pentane standards as proposed.
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\26\ C6 refers to a hydrocarbon molecule that contains six
carbon atoms. Pentane has 5 hydrocarbons (i.e., it is C5).
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Unlike the part 80 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 removal of
the maximum olefin and aromatics specifications for certified butane,
it is appropriate to impose controls on the purity of certified butane
that are consistent with the purity specification for certified
pentane. In the NPRM, we proposed a 92 volume percent purity
specification for certified butane. While slightly lower than the 95
volume percent purity specification for certified pentane, we argued
that the slightly lower standard would not result in increased
emissions from the use of certified butane compared to a 95 volume
percent purity specification and would allow necessary flexibility to
industry. We received several comments suggesting that we should impose
a lower certified butane purity standard. Commenters suggested a range
of options from 80 volume percent to 90 volume percent. Most commenters
suggested that a purity specification of 85 volume percent would allow
for a high-quality product without disrupting existing butane blending
practices. We agree with these comments and are therefore finalizing an
85 volume percent purity specification for certified butane.
We are also simplifying the quality assurance requirements for
certified butane and certified 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. The sampling
and testing frequency for butane received from each butane supplier
under part 80 is one sample for every 500,000 gallons, or one
[[Page 78423]]
sample every three months, whichever is more frequent. The sampling and
testing frequency for commercial grade pentane received from each
pentane supplier under part 80 is once for every 350,000 gallons of
pentane received, or one sample every three months, whichever is more
frequent. Under Part 80, noncommercial-grade pentane is 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, under part 1090
we are requiring the same sampling and testing frequency for certified
butane and certified pentane to be once every 500,000 gallons of butane
or pentane received, or one sample every three months, whichever is
more frequent. More frequent sampling and testing is not needed for
certified pentane versus certified butane, given that they are subject
to similar standards. Existing registration requirements for certified
pentane producers will help to mitigate concerns that pentane
manufacturing processes may increase concentration of high boiling
range hydrocarbons (such as C7-C20 hydrocarbons).\27\ We received no
adverse comments on this aspect of the proposal, and so we are
finalizing these provisions as proposed.
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\27\ 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 of concern with respect to increased emissions.
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4. State and Local Fuel Standards
a. Overview
As proposed, we have transferred and consolidated the part 80
regulations that relate to RVP and RFG requirements in 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
finalizing 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 finalizing
procedures for states that request a relaxation of the federal RVP
standard of 7.8 psi. These procedures are similar to the existing
procedures used for RFG opt-out by states. We are not finalizing any
regulatory revisions for current fuel programs that apply in several
states. The following sections detail the changes we are finalizing.
We are also announcing that an updated boutique fuel list is
currently posted on our website.\28\ 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.\29\ Several fuels have ceased to be
included in SIPs since the boutique fuel list was originally published
in 2006.\30\ The boutique fuel list on our website, however, provides
up-to-date information on where such fuels are currently used.
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\28\ See http://www.epa.gov/gasoline-standards/state-fuels.
\29\ See CAA section 211(c)(4)(C)(v)(III).
\30\ See 71 FR 78195 (December 28, 2006).
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b. Consolidating Gasoline Volatility Standards
As proposed, we have transferred summer gasoline requirements
related to RVP standards that are currently in part 80 to part 1090.
Summer gasoline for use in the continental U.S. must comply with either
the federal RVP standard of 9.0 psi or the more stringent RVP standard
of 7.8 psi, unless it is either for use in a RFG covered area, is
subject to California's gasoline regulations, or EPA has waived
preemption and approved a state request to adopt a more stringent RVP
standard into a SIP.31 32 33 Part 1090 simplifies and
clarifies the regulatory text previously located in 40 CFR 80.27(a) and
80.70, and does not change the current RFG and summer gasoline
standards nationwide, and requires all gasoline designated as summer
gasoline or located at any location in the U.S. during the summer
season to meet applicable RVP per-gallon standards. The regulations
include a limited exception to facilitate the movement and storage of
gasoline that does not meet the applicable RVP standards if it is
locked down and is not delivered to any retail station or wholesale
purchase consumer. This exception is primarily designed to accommodate
the transition from summer to winter gasoline and allow the
transportation and storage of higher RVP fuel through areas that are
subject to more stringent standards. The exception places the burden on
the regulated community to demonstrate that the gasoline is properly
designated and isolated and is not delivered to any retail station or
wholesale purchaser consumers during a time or place prohibited by the
regulations.
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\31\ Some states where the federal 7.8 psi RVP standard is
required have chosen instead to apply 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.
\32\ California has set requirements for gasoline sold
throughout the entire state (``California gasoline''), 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.
\33\ In the absence of California's RFG regulation, either
federal RVP standards or RFG would apply in California. Some areas
would be RFG covered areas because either they were among the
original nine RFG covered areas or they were reclassified to Severe
nonattainment for an ozone National Ambient Air Quality Standard
(NAAQS). See CAA section 211(k)(10)(D).
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c. Reformatting the List of Areas Where the Federal 7.8 psi RVP
Standard Applies
As proposed, we have transferred to part 1090 the current RVP
standards in 40 CFR 80.27(a)(2), which previously set out the current
federal RVP standards. Areas subject to the federal 7.8 psi RVP
standard are listed in a table in 40 CFR 1090.215(a)(1), describing the
geographic areas subject to the 7.8 psi RVP standard. Part 1090
specifies that any gasoline that is not subject to a lower RVP standard
is subject to the federal 9.0 psi RVP standard. We did not propose and
therefore are not finalizing any changes or revisions to applicable RVP
standards. Specifically, we:
Removed the regulatory text in 40 CFR 80.27(a)(1) because
it was outdated and has not applied since 1991.
Replaced the regulatory text, table, and footnotes that
were 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 standard for summer
gasoline currently applies.
The table in 40 CFR 80.27(a)(2) dates back to the initial one-hour
ozone NAAQS and is overly complex and has caused confusion among states
and industry. The new table in 40 CFR 1090.215(a)(1) includes the name
of the nonattainment area and the county or counties in the area where
the federal 7.8 psi RVP standard applies. The new table under part 1090
also includes a description of the boundaries for areas that include
partial counties where RVP standards are currently in effect. Under 40
CFR 80.27(a)(2), interested parties had to search 40 CFR part 81 in
order to identify these specific boundaries of the area where the 7.8
psi RVP standard applies. As previously noted, this action does not
change any existing requirements.
d. Reformatting RFG Applicability and Covered Areas
As proposed, we have transferred part 80 requirements relating to
RFG to part 1090, and we have reformatted how the information on RFG
covered areas is
[[Page 78424]]
presented. Specifically, in 40 CFR 1090.285 we present the description
of RFG covered areas in a table format and have grouped the covered
areas by the statutory provision under which the area became a covered
area. The following are four requirements under which an area could
have become an RFG 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 nation's 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 RFG.
We have also transferred the existing regulatory processes by which
an area may become an RFG covered area in the future to part 1090.
These processes apply 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 an RFG covered area.
We also now include two additional California areas on the list of
RFG covered areas in part 1090 because the areas became RFG covered
areas when they were reclassified as Severe ozone nonattainment
areas.\34\ The two areas are the Sacramento Metro area and the San
Joaquin Valley area.\35\ 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
continued applicability of California's regulations that require the
sale of California gasoline in these areas, but should California's
regulations no longer apply in the future, EPA's RFG regulations would
likely still apply in keeping with the CAA.
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\34\ See CAA section 211(k)(10)(D).
\35\ The Sacramento Metro area was reclassified as a severe
ozone nonattainment area on June 1, 1995, and became an 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 an RFG covered area on
December 10, 2002. See 66 FR 56476 (November 8, 2001).
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e. Continuation of 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 EPA's opt-
out regulations. We also included regulatory text in 40 CFR
80.70(m),\36\ parts of which have become outdated and unnecessary
because they were specific to the transition from the 1-hour ozone
NAAQS to the 1997 ozone NAAQS, both of which have since been revoked.
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\36\ See 70 FR 71684-9 (November 29, 2005).
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As proposed, in part 1090 we are maintaining and clarifying our
intention and existing practice with regard to applicable RFG
requirements. Specifically, 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)). Requiring the
continued implementation of RFG in all covered areas is consistent with
how the RFG program has been implemented during the transitions to the
1997, 2008, and 2015 ozone NAAQS. Part 1090 includes procedures for
either removing a prohibition on or opting out of RFG, consistent with
CAA requirements; thus, part 1090 continues to allow states to revise
RFG requirements under certain circumstances.
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 areas where RFG use was mandated pursuant to CAA
section 211(k)(10)(D) (i.e., the areas with the nine highest 1-hour
ozone design values from 1987-1989 or areas reclassified to Severe for
an ozone NAAQS).\37\
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\37\ See 70 FR 71687 (November 29, 2005).
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As proposed, we are finalizing a new provision in part 1090 that
will allow a 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 40 CFR 1090.290(d), 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
of the request 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
either be redesignated to attainment for the 2015 ozone NAAQS (if it
had been designated as nonattainment for that NAAQS) or be designated
as an attainment area for the 2015 ozone NAAQS. On the other hand, if
the area is designated as an attainment area for the most stringent
ozone NAAQS in effect, the area would have to be redesignated to
attainment for the prior ozone NAAQS before the RFG program could be
removed. For example, 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 a nonattainment area that has been
redesignated to attainment for the 2015 NAAQS to be eligible for
consideration for removal of the RFG program. In either case, we are
requiring that any request to remove the RFG requirements must include
an approved maintenance plan that demonstrates maintenance of the ozone
NAAQS throughout the period addressed by the maintenance plan without
the emission reductions from the RFG program. Additionally, we are
requiring that a state must also demonstrate that the removal of the
requirement for the 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.\38\
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\38\ See CAA section 110(l).
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States with current mandatory RFG covered areas may seek to remove
the requirement for RFG 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 have the ability to
use their 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
over 30 years ago or were reclassified as Severe for a prior ozone
NAAQS. This approach is premised on our view that once a covered area
attains the most stringent ozone NAAQS, states should
[[Page 78425]]
be able to determine whether an emission reduction strategy (in this
case RFG) should either continue or be removed as long the state 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 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). The opt-out procedures, which were established in 1996 and
1997, are not being revised in this action except for transferring them
to part 1090, removing obsolete regulatory text (e.g., removing
requirements that applied for specific periods of time that are now in
the past), and making minor clarifications.
A commenter stated that Congress created mandatory RFG covered
areas, and it is up to Congress to eliminate this provision. This
commenter believed that EPA does not have the authority to remove the
RFG program for a mandatory RFG area created by Congress and the
statute is unambiguous regarding this matter. We disagree and have
concluded that there is legal authority to support removal of RFG
requirements in mandatory RFG areas as long as the criteria established
in part 1090 are met. This comment is addressed in more detail in
Section 6 of the RTC document.
Another commenter asked whether the RFG opt-out procedures apply to
both opt-in and mandatory areas because the proposed regulations could
be read to allow only opt-in areas to request removal of an RFG program
from a portion of the covered area. The commenter also sought
clarification on whether a mandatory RFG area must be in attainment for
all prior ozone NAAQS, or only the immediately prior ozone NAAQS (in
addition to the most stringent NAAQS) in order to request removal of
the RFG requirement.
As proposed, the RFG opt-out regulations could be read to draw a
distinction between opt-in areas and mandatory areas under CAA section
211(k)(10)(D). We intended that these opt-out regulations would apply
to both opt-in areas and mandatory areas in the same way. In response
to this comment, we have revised the RFG opt-out procedures to clarify
that the provisions apply to both opt-in areas and mandatory areas in
the same manner. Specifically, both opt-in areas and mandatory areas
can have the RFG requirement removed from either the entire area or
from a portion of the area, provided that the relevant criteria and
procedures are followed.
With respect to the request for clarification regarding whether a
mandatory RFG area must be in attainment for all prior ozone NAAQS,
mandatory RFG areas will remain RFG covered areas until the criteria in
part 1090 are met, and the state follows the procedures to have the
requirements to sell RFG removed, the EPA Regional Office approves the
state's SIP revision and CAA section 110(l) demonstration, and EPA
establishes an effective date for the removal of the area. Such an area
would have to attain the most stringent ozone NAAQS in effect at the
time. The state would have to revise any relevant CAA section 175A
maintenance plan and comply with CAA section 110(l) non-interference
requirements. Two examples are provided in the following paragraphs.
One example is for a state seeking removal of the RFG program from
a mandatory RFG area that was initially designated as nonattainment for
the most stringent ozone NAAQS in effect at the time of the request for
the removal (e.g., currently the 2015 ozone NAAQS) and the area has
been redesignated to attainment with an approved CAA section 175A
maintenance plan for that NAAQS. In this case, the state need only
address that most stringent ozone NAAQS by revising the approved CAA
section 175A maintenance plan for that ozone NAAQS to show continued
maintenance of that ozone NAAQS without the emissions reductions from
RFG and comply with CAA section 110(l) non-interference requirements.
Another example is if a state is seeking removal of the RFG program
from a mandatory RFG area that was initially designated as an
attainment area for the most stringent ozone NAAQS in effect. In this
case, it needs to address the prior ozone NAAQS by revising the CAA
section 175A maintenance plan for that area for the prior ozone NAAQS
(i.e., currently the 2008 ozone NAAQS) to show continued maintenance of
that ozone NAAQS without the emissions reductions from RFG and comply
with CAA section 110(l) non-interference requirements. We also expect a
state seeking the removal of the RFG requirement in a mandatory area to
briefly discuss its air quality status with respect to the 1-hour ozone
NAAQS (i.e., the area's current design value) because all mandatory
areas under CAA section 211(k)(10)(D) became mandatory areas due the
severity of the 1-hour ozone NAAQS problem in these areas.
g. Providing Streamlined Procedures for Areas Relaxing the Federal 7.8
psi RVP Standard
As proposed, we are finalizing 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. Part 1090 provides
procedures similar to those that are currently used when states opt out
of the RFG program.\39\
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\39\ 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 standard took effect in 1992 and
was initially required in certain 1-hour ozone NAAQS nonattainment
areas. States have had the ability to request relaxation of this RVP
standard provided that all CAA requirements are fulfilled (e.g.,
revising approved SIPs as necessary and EPA's approval of those SIP
revisions and approval of a CAA section 110(l) non-interference
demonstration). 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.\40\ 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 standard continues to apply.
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\40\ For more information on EPA's actions, see www.epa.gov/gasoline-standards/federal-gasoline-regulations.
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Under our previous regulations, the process for accomplishing a 7.8
psi RVP relaxation required two EPA approval actions before a state's
request could become effective. First, the EPA Regional Office needed
to approve a state's revision to an area's SIP, such as a maintenance
plan, for the relevant ozone NAAQS and a CAA section 110(l) non-
interference demonstration. After the EPA Regional Office rulemaking
was completed, a second rulemaking by EPA Headquarters was necessary to
remove the subject area(s) from the federal 7.8 psi RVP regulations in
40 CFR
[[Page 78426]]
80.27(a)(2).\41\ The process involving both of these approval actions
before a state's request could become effective was cumbersome and time
consuming given the number of linear steps involved. There was also an
element of confusion and uncertainty to states, local businesses,
industry, and the public concerning the effective date of an RVP
relaxation.
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\41\ 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. See, e.g., 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 proposed that the current
RFG opt-out regulatory procedures would provide a better model for
considering and approving state requests to relax the federal 7.8 psi
RVP standard. Thus, the part 1090 regulations for relaxing the federal
7.8 psi RVP standard mirror the RFG opt-out procedures, and are as
follows:
The governor of the state, or the governor's designee,
requests in writing that EPA relax the federal 7.8 psi RVP standard.
The state is 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
standard 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 EPA Regional Office's action is complete, EPA
Headquarters would establish an effective date for the relaxation,
which would be no less than 90 days after the effective date of the EPA
Regional Office's approval. We then 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 standard
continues to apply (i.e., from the list of areas in part 1090). We have
concluded that notice-and-comment rulemaking to revise the list of
areas in part 1090 is not necessary for relaxation actions to become
effective because it merely codifies a change that has been made
through a process that is included in our regulations and is thus,
merely administrative in nature.
This process will eliminate the need for EPA to complete a notice-
and-comment rulemaking to update the list of areas in part 1090 each
time we act on a request to relax a federal 7.8 psi RVP standard to
remove the subject area from the list of areas subject to that
standard. Under the process in part 1090, which is similar to the RFG
opt-out procedures, the effective date of the federal 7.8 psi RVP
relaxation would be known shortly after the EPA Regional Office's
rulemaking on the state's SIP revision and CAA section 110(l) non-
interference demonstration becomes effective. Using similar procedures
for acting on state requests to change either federal 7.8 psi RVP or
RFG programs will also avoid unnecessary confusion and still continue
to provide the same level of environmental protection. Under both the
former part 80 regulations and the current part 1090 regulations, 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 7.8 psi RVP fuel and comply with the CAA's non-
interference requirements.\42\ Further, we will continue to act on such
SIP revisions and CAA section 110(l) non-interference demonstrations
through notice-and-comment rulemaking. Finally, this process, which
streamlines the RVP relaxation program, results in the conservation of
limited government resources and brings certainty for states, the
public, and gasoline suppliers as to when a state's request to relax
RVP would take effect.
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\42\ See CAA section 110(l).
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h. Transitioning From RFG or a Boutique Fuel Program to the Federal 9.0
psi RVP Standard in Certain States
In this action we are providing information for states that decide
to either opt out of RFG or remove a state SIP fuel rule that regulates
gasoline RVP (i.e., a boutique fuel). Specifically, a state in its SIP
revision (e.g., maintenance plan revision) may request that EPA apply
the federal 9.0 psi RVP standard rather than the federal 7.8 psi RVP
standard.\43\ 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.\44\ 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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\43\ In 1990 and 1991, 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. See June 11, 1990 (55
FR 23658) and December 12, 1991 (56 FR 64704).
\44\ 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 in
lieu of a more restrictive standard. States have previously
accomplished this goal by first submitting a SIP revision (e.g., a
maintenance plan revision) that removes the state fuel RVP standard or
opts out of the RFG program and applies the federal 7.8 psi RVP
standard and addresses CAA section 110(l) non-interference
demonstration requirements. Later, such states would submit 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 in this action
to ensure that states are aware that they can accomplish the goal of
relaxing the federal RVP standard to 9.0 psi through one SIP revision
as long as the associated SIP revision meets 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 that SIP revision, and one EPA action to
update the lists areas subject to the specific gasoline standards will
conserve state and federal resources.
Allowing the transition to the federal 9.0 psi RVP standard 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 when gasoline that complies with the federal 9.0 psi RVP
standard is sold in the area. This approach also provides fuel
suppliers with certainty and stability. Transitioning directly to the
9.0 psi RVP standard through one SIP revision, rather than
accomplishing this through two SIP revisions as has occurred in the
past, avoids the need for fuel suppliers to supply the area with 7.8
psi RVP gasoline for a short period of time, only to ultimately switch
to supplying gasoline that meets the 9.0 psi RVP standard.
[[Page 78427]]
We note, however, that if such a state wants EPA to apply the
federal 7.8 psi RVP standard, 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 standard. In such a
case, we 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 State Fuels website.\45\ 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 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 December 28,
2006.\46\
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\45\ See https://www.epa.gov/gasoline-standards/state-fuels.
\46\ See 71 FR 78192 (December 28, 2006).
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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.\47\ Since the original list was published, several fuels have
been removed from approved SIPs and have thus ceased to exist in
SIPs.\48\ In addition to our aforementioned website, we are providing
an updated list of boutique fuels that includes all of the boutique
fuels that are currently in approved SIPs in Table V.4.h-1 below. 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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\47\ See CAA section 211(c)(4)(C)(v)(III).
\48\ 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.
Table V.4.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 \49\.
3 6--Texas.
Low Emission Diesel............ 3 6--Texas.
Cleaner Burning Gasoline 5 9--Arizona (May 1-
(Summer). September 30) \*\.
Cleaner Burning Gasoline (Non- 5 9--Arizona (October 1-
Summer). April 30).
Winter Gasoline (aromatics & 5 9--Nevada \50\.
sulfur).
------------------------------------------------------------------------
* 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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\49\ 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).
\50\ 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, it was not listed in part
80 among the requirements for fuel.\51\ As part of our effort to
consolidate fuels compliance requirements and make it easier for
regulated parties to understand their obligations, we are finalizing a
requirement in part 1090 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).\52\
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\51\ The FFARs 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).
\52\ Our authority to codify the ``substantially similar''
requirement in regulations is explained at 81 FR 80877-78 (November
16, 2016).
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EPA has issued two coexisting definitions of substantially similar
for gasoline, one in 2008 \53\ and one in 2019,\54\ and several CAA
section 211(f)(4) waivers. The part 1090 regulations refer to the
statutory provisions (CAA section 211(f)(1) and (4)). EPA has issued
interpretative rules on the meaning of ``substantially similar'' under
this provision.\55\ EPA has also issued many CAA section 211(f)(4)
waivers from the substantially similar provision, including, but not
limited to the E10 (``gasohol'') waiver and the Octamix waiver.\56\
Fuel and fuel additive manufacturers are expected to comply with the
parameters associated with the definitions of ``substantially similar''
when introducing gasoline or gasoline additives into commerce under CAA
section 211(f)(1). Fuel and fuel additive manufacturers are expected to
comply with any conditions associated with a CAA section 211(f)(4)
waiver when introducing gasoline or gasoline additives into commerce
under a waiver.
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\53\ See 73 FR 22277 (April 25, 2008).
\54\ See 84 FR 26980 (June 10, 2019).
\55\ See 73 FR 22277 (April 25, 2008) and 84 FR 26980 (June 10,
2019).
\56\ See 44 FR 20777 (April 6, 1979), Octamix Waiver, 53 FR 3636
(February 8, 1988).
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We have made some modifications to the ``substantially similar''
requirement in response to comments received by stakeholders. We have
also added the ``substantially similar'' requirement to the diesel
standards in this final rule in order to comprehensively cover the
requirements imposed by CAA section 211(f)(1) and (f)(4) as they
pertain to gasoline and diesel fuels. We further address these comments
in Section 6 of the RTC document.
[[Page 78428]]
B. Diesel Fuel
1. Overview and Streamlining of Diesel Fuel Program
Similar to our approach for the gasoline standards, we are
consolidating the diesel fuel standards into a single subpart in part
1090 (subpart D). We are not making 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. However, we
are removing expired provisions that were needed to support the phase-
in of the current diesel fuel sulfur program. The phase-in period was
completed in 2014; however, these now expired phase-in provisions are
imbedded throughout the diesel fuel program regulations in part 80,
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 also making revisions to the part 80 regulations in moving
them to part 1090 as discussed in the following sections. First, we are
removing the requirement that motor vehicle diesel fuel be free of red
dye because we believe this requirement is no longer necessary to
evaluate compliance with the diesel sulfur standards. Second, we are
streamlining the requirements that pertain to importation of diesel
fuel that does not meet EPA standards. Third, we are removing the
requirement for ECA marine fuel distributors and associated
requirements to include a registration number on PTDs. Finally, we are
streamlining the means for downstream parties to redesignate heating
oil, kerosene, or jet fuel as ULSD.
We expect that these changes will simplify the diesel fuel
programs, resulting in reduced burden associated with demonstrating
compliance with the 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
Under the Internal Revenue Code, non-road, locomotive, and marine
(NRLM) diesel fuel, heating oil, and exempt highway diesel fuel \57\
must contain red dye before leaving a fuel distribution terminal to
indicate its tax-exempt status. 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. Consequently, 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.\58\
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\57\ Such as diesel fuel used in school buses.
\58\ See 40 CFR 80.520(b).
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However, as other distillate fuels have become subject to the same
15 ppm sulfur standard that applies to highway diesel fuel, the
presence of red dye has ceased to be a useful indicator of sulfur
noncompliance. With the completion of the phase-in of EPA's 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 also currently subject to
a 15 ppm standard.\59\ Therefore, we believe that the requirement that
red dye should not be present in motor vehicle diesel fuel no longer
provides any meaningful added assurance of compliance with ULSD
standards. Rather, the existence of this requirement now just
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 as specified under CAA section
211(c)(4)(C)(ii). State authorities are currently required to request a
waiver from both 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.
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\59\ 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.
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Commenters were generally supportive of removing the red-dye
requirement. Consequently, we are removing the EPA requirement that
motor vehicle diesel fuel must be free from visual evidence of red dye
as proposed.\60\ This change does 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. However, EPA
will continue to coordinate with IRS staff in cases where supply issues
arise if needed.
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\60\ See 40 CFR 80.520(b)(1).
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3. Importation of Off Spec Diesel Fuel
We are replacing the provisions for the importation of diesel fuel
treated as blendstock (DTAB) under part 80 \61\ with a streamlined
procedure to handle imported off-spec diesel fuel. 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 may 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 part 1090, the
importer is required to offload the imported diesel fuel into one or
more shore tanks containing diesel fuel, 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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\61\ See 40 CFR 80.512.
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We received no adverse comments to our proposed streamlining of the
DTAB provisions and therefore we are finalizing these provisions as
proposed.
4. MARPOL Annex VI Marine Fuel Standards
In this action, we are mostly transposing 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 MARPOL Annex VI. The U.S. ratified MARPOL
Annex VI and became a Party to this Protocol effective January 2009.
MARPOL Annex VI requires marine vessels operating globally to use fuel
that meets the 0.50
[[Page 78429]]
percent sulfur standard starting January 1, 2020 (``global marine
fuel''). The MARPOL Annex VI standard is 0.10 percent sulfur for fuel
used in vessels operating in designated ECAs.\62\
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\62\ Designated ECAs 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 the 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.\63\ We are incorporating those provisions
into part 1090 with minor changes to be consistent with the new part
1090 structure.
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\63\ 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 manufacturer to the
point of transfer to a vessel were required to register with EPA and
include this registration number on PTDs.\64\ Distributors of other
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.\65\ The majority of these requirements
gradually expired with the phase-out of the ULSD program's small
refiner and early credit provisions that ended in 2014, which had
allowed the production of limited volumes of 500 ppm highway diesel
fuel. Beginning in 2014, the only fuel distributors still required to
register with EPA were those that handle ECA marine fuel and 500 ppm LM
diesel fuel produced by transmix processors.\66\
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\64\ See 40 CFR 80.597(d)(3).
\65\ See 40 CFR 80.597 regarding the distributor registration
requirements and 40 CFR 80.590(a)(6)(i) for the associated PTD
requirements.
\66\ 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 does not outweigh the burdens associated
with this requirement. All comments received on this issue supported
the elimination of the registration requirement for ECA marine fuel
distributors, and we are finalizing its removal as proposed.
5. Heating Oil, Kerosene, and Jet Fuel
When we first established the diesel fuel sulfur program under part
80, it required only on-highway or motor vehicle diesel fuel to meet
the 15 ppm sulfur standard. In order to implement and enforce this
standard and avoid the contamination of ULSD with higher sulfur
distillate fuels (which at the time were non-road diesel, heating oil,
kerosene, and jet fuel), it required that we include a number of
regulatory provision to designate, segregate, and label distillate
fuels. Now the 15 ppm sulfur standard to all diesel fuel (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 are no longer serving any purpose. However, the provisions have
remained in place under part 80 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.).
In the NPRM, we proposed 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
provisions, downstream parties may rely on documentation from pipelines
or fuel manufacturers that the heating oil, kerosene, or jet fuel was
certified to meet the 15 ppm sulfur standard and cetane/aromatics
specifications to fungibly transport, store, and dispense all 15 ppm
sulfur distillate fuels downstream. We also proposed to 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.
Comments were supportive of the proposed provisions for the
redesignation of distillate fuels certified to meet the ULSD standards
and we are finalizing these provisions as proposed. We believe that
these provisions will maximize the fungibility of distillate fuels,
resulting in substantially reduced distributional costs and greater
efficiency in the fuels market.
6. Downstream Testing Adjustment for ULSD
In part 80 there is a 2-ppm sulfur downstream testing tolerance for
ULSD.\67\ This was not carried over into the proposed part 1090
regulations as diesel sulfur levels are typically much lower than the
15 ppm standard and the opportunities for contamination in the
distribution system have been reduced with the establishment of sulfur
limits on all gasoline, diesel fuel, and most heating oil. We received
a number of comments highlighting that this adjustment remains
necessary to account for test variability in the measurement of sulfur
in ULSD. Based on these comments, we are including the 2-ppm sulfur
downstream testing adjustment for ULSD in part 1090. We believe that
the variability in the most commonly used test methods for measuring
sulfur in ULSD appears to continue to necessitate the adjustment. In
the future, as improvements are made to the measurement of sulfur in
ULSD, we may revisit the need for this testing adjustment.
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\67\ See 40 CFR 80.580(d).
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VI. Exemptions, Hardships, and Special Provisions
A. Exemptions
We are transferring provisions that exempt fuels from applicable
standards that are currently contained in part 80 to part 1090. We are
making minor revisions for purposes of modernizing these exemptions, as
well as removing obsolete exemption provisions. Any exemptions that
were granted under part 80 will remain in effect with their original
conditions as applicable under part 1090. As a result of moving these
provisions to part 1090, instead of being scattered through various
subparts as is the current practice in part 80, they will be
consolidated into a single subpart (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 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) under part 1090.
We are not making any revisions to exemptions nor the related
requirements that apply to fuels used for national security and
military purposes, temporary research and development
[[Page 78430]]
(R&D), racing, and aviation. Similarly, we are not changing the
exemption that applies to fuels for use 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 will also
continue to be exempt from the federal volatility regulations.
We are, however, making minor revisions to these exemptions for
consistency and as a result of consolidating the various part 80
exemptions, and to modernize the exemption provisions. First, we are
including language that imposes conditions on parties operating under
an 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 requested 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. However, we received no
comments on this topic and therefore are finalizing the R&D exemption
provisions as proposed. We address comments related to the R&D
exemption in Section 9 of the RTC document.
Second, we are allowing 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 part 1090,
fuel additives and regulated blendstocks will now be exempt from
applicable requirements if certain conditions are met. For example, the
military use exemption now explicitly exempts fuels, fuel additives and
regulated blendstocks used in either military vehicles or in support of
military operations.
Third, we are finalizing as proposed the regulatory provision to
prevent contamination of motor vehicle fuels by exempt fuels, such as
racing and aviation gasoline containing lead additives, at 40 CFR
1090.615(c) (which is carried over from part 80). This regulatory
provision requires the segregation of exempt fuels from production
through consumption. We had also proposed a new provision at 40 CFR
1090.615(e) that was also designed to shore up protection against
contamination of motor vehicle fuels during distribution by tanker
trucks. For example, when a tanker truck carrying exempt racing
gasoline or aviation gasoline is later used to transport non-exempt
gasoline, residual exempt gasoline could remain in the tanker truck and
contaminate the non-exempt gasoline. We referred regulated parties to
follow established voluntary consensus-based standards for managing the
transportation of both exempt and non-exempt fuels in the same
transportation vessel.\68\
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\68\ API Recommended Practice 1595 and Energy Institute & Joint
Inspection Group (EI/JIG) Standard 1530.
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A commenter requested that we remove the proposed examples that
referenced industry guidance from the regulations because these
standards can change over time. In response to those comments, we
considered incorporating these API and EI/JIG standards by reference,
or drafting and including appropriate portions of these standards into
part 1090. However, in reviewing the regulations we realized that the
new provision proposed at 40 CFR 1090.615(e) may be superfluous with
the existing requirement for product segregation throughout the entire
distribution system now under 40 CFR 1090.615(c). The intent of
proposed 40 CFR 1090.615(e) had been to enhance the prevention of
product contamination in cases when both exempt and non-exempt fuels
are being transported in the same transportation vessel. However, in
some cases, this provision could have been interpreted as relaxing
product segregation requirements when exempt fuels are being
transported using transportation vessels totally dedicated to that
fuel. This was not our intent. For this reason, we will continue to
rely on the existing regulatory language at 40 CFR 1090.615(c).
Finally, California gasoline and diesel fuel used in California 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
sunsetted 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 creating provisions that clarify how California
gasoline and diesel fuels may be used in states other than California.
Under part 80, fuel manufacturers that make California gasoline and
diesel fuel must recertify those fuels in order to sell them outside
the state of California.\69\ Under part 1090, we are providing
California fuel manufacturers and distributors the choice of whether to
recertify the California fuel, as currently required under part 80, or
redesignate the California fuel without recertification if certain
conditions are met. In order for a fuel manufacturer or distributor of
California gasoline to redesignate without recertification such fuel
for use outside of California, the fuel must meet all applicable
requirements for California reformulated gasoline under Title 13 of the
California Code of Regulations and the manufacturer or distributor must
meet applicable designation and recordkeeping requirements.\70\ Under
part 1090, parties that redesignate California gasoline without
recertification 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.\71\
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\69\ Under part 80, fuel manufacturers of California gasoline
that recertify their fuels must recertify their gasoline and comply
with federal fuel quality standards (per-gallon and average
standards).
\70\ The explanation for the analysis we performed to determine
the equivalency of the California fuel standards can be found in the
technical memorandum, ``California Fuel Equivalency,'' available in
the docket for this action.
\71\ The California reformulated gasoline and diesel fuel
standards are at least as stringent as the standards under part
1090; therefore, these fuels should be allowed to be used throughout
the rest of the U.S. 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, PTDs, and gasoline
[[Page 78431]]
segregation for fuels designated for export that currently apply under
part 80 to part 1090.
In the NPRM, we proposed that in order for a fuel, fuel additive,
or regulated blendstock to receive an export exemption, it would have
to be segregated from the point of production to the point of
exportation from the U.S. Commenters suggested that the inclusion of
fuel additives and regulated blendstocks in the segregation requirement
for exports was unnecessary, as exported fuel additives and regulated
blendstocks do not need to be segregated and are unlikely to cause fuel
quality issues if commingled. As such, we are not finalizing a
segregation requirement for exported fuel additives and regulated
blendstocks.
Regarding exported fuels, commenters suggested that we should only
require that exempt fuels for export be segregated from non-exempt
fuels from the point that the fuel was designated as for export until
the fuel is exported. Commenters stated that the proposed segregation
requirement could create challenges, as often times fuels for export
are produced simultaneously with fuels for domestic use. To avoid
unintended increases in the burden of producing domestic and exported
fuels, we have revised the segregation requirement for fuels to begin
at the point of designation.
Commenters also asked for more clarity on how diesel fuel export
segregation requirements would work under part 1090. Under part 80,
diesel fuel not designated for export can be exported without
restriction as long as it meets the applicable fuel quality standards.
However, the fuel remains subject to the provisions of this part while
in the U.S. For example, diesel 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 designation
until it is exported, as currently required under part 80.
We address other comments related to exports in Section 9 of the
RTC document.
C. Extreme, Unusual, and Unforeseen Hardships
Under part 80, the various subparts associated with each standard
include separate provisions for receiving an exemption from that
subpart's fuel quality standards due to extreme, unusual, and
unforeseeable hardship. We are consolidating these exemptions into one
hardship provision for extreme, unusual, and unforeseeable
circumstances (e.g., a natural disaster or refinery fire excluding
financial and supply chain hardship) that a refinery cannot avoid with
prudent planning.\72\ The part 1090 organization 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 applies only to the
standards in part 1090; the parallel provision for the RFS program
requirements remains in part 80. Accordingly, any exemptions available
under the RFS program would similarly remain unaffected.
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\72\ The part 80 programs generally had two hardship provisions:
(1) Unusual circumstances that significantly affected the refiner's
ability to initially comply by the applicable date, under which EPA
allowed financial and supplier difficulties as a reason for
additional lead time; and (2) extreme, unusual, and unforeseen
events, like a natural disaster or refinery fire, that occur after
the standards have become effective, and for which economic and
supplier difficulties have never been a qualifying hardship event.
Since part 1090 is not introducing new standards, we did not propose
and have effectively removed the first (sunsetted) hardship
provision, which allowed for financial and supplier difficulties for
initial compliance relief, and are only keeping the second (ongoing)
extreme, unusual, and unforeseen hardship provision.
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Commenters on the proposed extreme, unusual, and unforeseen
hardship provision objecting to the explicit exclusion of financial and
supplier difficulties from the grounds for hardship relief. The
commenter described this language as a change from the extreme,
unusual, and unforeseen hardship provisions of part 80. We believe that
this is a clarification of the kinds of extreme, unusual, and
unforeseen events that qualify for relief under this hardship provision
under part 80. As such, we are finalizing the extreme, unusual, and
unforeseen hardship provision as proposed and have addressed the
comment in Section 9 of the RTC document.
VII. Averaging, Banking, and Trading Provisions
A. Overview
We have often used averaging, banking, and trading (ABT) provisions
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. As such, they are integral
to our standards and we are transferring the currently applicable ABT
provisions for gasoline sulfur and benzene from part 80 to part
1090.\73\ In doing so, we are making modifications that will facilitate
consolidation of these various ABT regulatory provisions in part 80
into a single set of ABT provisions in part 1090. In particular, this
includes changes to how gasoline manufacturers can account for
oxygenate added to gasoline downstream of fuel manufacturing facilities
in compliance calculations. It also includes a new mechanism that
allows downstream parties that recertify batches of gasoline to use
different types and amounts of oxygenate downstream of a manufacturing
facility. We are not transferring expired part 80 ABT provisions that
were temporary provisions associated with initial implementation of the
standards, such as the separate ABT provisions for small refiners and
small volume refineries that expired at the end of 2019.
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\73\ 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 finalizing minor changes to the format of the average
compliance calculations to align the sulfur and benzene compliance
calculations more closely with each other and 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. These changes to the compliance calculations will not
affect how gasoline manufacturers currently comply with the average
standards or their stringency; however, the streamlined equations
appear slightly different compared to the similar equations in part 80.
We are also adding to the compliance calculation the deficits incurred
on an annual basis due to the recertification of BOBs downstream to use
a different type(s) and amount(s) of oxygenate. We discuss this change
in detail in Section VII.G.
As previously noted, part 80 regulations had separate ABT
provisions for small refiners and small volume refineries associated
with the initial implementation of the gasoline sulfur and benzene
standards that have expired. The last such provisions related to the
Tier 3 gasoline sulfur program, which expired on December 31, 2019,
resulting in small refiners and small volume refineries being required
to comply with the same part 80 fuel quality standards and use the same
ABT
[[Page 78432]]
provisions as other refiners. As a result, part 1090 does not include
separate ABT provisions for small refiners and small volume refineries.
C. Deficit Carryforward
Under part 80 we allow gasoline manufacturers to carryforward
deficits for the gasoline and sulfur benzene standards, 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. In part 1090, we are
consolidating the separate gasoline sulfur and benzene deficit
carryforward provisions from part 80 into a single provision and
slightly modifying the language simply to accommodate the
consolidation. We do not believe that the modifications will
substantively affect how gasoline manufacturers are permitted to carry
forward deficits.
Commenters requested additional flexibilities related to the
deficit carryforward provisions. However, we are not finalizing any
additional flexibility related to deficit carryforward. These comments
are addressed in Section 10 of the RTC document.
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
making minor changes to the language largely to ensure consistency
between the sulfur and benzene credit trading programs.
We are not making any changes to the lifespan of generated credits
(i.e., credits generated under part 1090 have the same lifespan as
afforded them under part 80). Additionally, credits generated under
part 80 are still 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 are still valid for compliance under part 1090 for the specified
life of the credits under part 80. For example, credits generated for
the 2020 compliance period could be used through the 2025 compliance
period.
In general, we are finalizing the credit generation, use, and
transfer provisions of part 1090 as proposed. We did, however, receive
several comments that suggested clarifying edits to the regulations.
These comments are addressed in Section 10 of the RTC document.
E. Invalid Credits
We are transferring the part 80 provisions for treatment of invalid
credits to part 1090 without modification. Since the establishment of
the sulfur and benzene ABT programs, we migrated tracking of credit
transactions into the EPA Moderated Transaction System (EMTS). We did
not receive substantive adverse comments related to the treatment of
invalid credits under part 1090 and we are finalizing the provisions
related to invalid credits under part 1090 as proposed. We did however
receive a comment asking about published guidance for remedial actions
to address issues related to invalid credits in EPA electronic
reporting systems. We address this comment in Section 10 of the RTC
document.
F. Downstream Oxygenate Accounting
Under part 80, we 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, test the hand blend for reported parameters, and include these
values in their compliance calculations to demonstrate compliance with
the sulfur and benzene average standards and the RFG performance
standards. The refiner or importer then specifies the type(s) and
amount(s) of oxygenate 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.
While there are provisions in part 80 for refiners and importers of
CG to also account for downstream oxygenate addition, they are much
more limited and difficult to utilize given the fungible nature of most
CG and conventional gasoline before oxygenate blending (CBOB) and the
requirements imposed. 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/CBOB. This regulatory disparate
treatment of CG and CBOB compared to RFG and reformulated gasoline
before oxygenate blending (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 at a time when
virtually all gasoline now has ethanol added downstream.
In order to remedy this disparity, we are finalizing a single
method for gasoline manufacturers to account for oxygenate added
downstream of a fuel manufacturing facility to comply with the average
sulfur and benzene standards, as proposed. In part 1090, we are
requiring gasoline manufacturers to use ``hand blends'' when accounting
for oxygenate added downstream. We are also requiring that oxygenate
blenders follow instructions for the type(s) and amount(s) of oxygenate
from the BOB manufacturer. These requirements for gasoline
manufacturers and oxygenate blenders under part 1090 largely mirror the
requirements for oxygenate blending and accounting found in the RFG
program under part 80.
The main differences between the part 1090 hand blend approach and
the part 80 RFG program is that the accompanying in-use survey under
part 1090 will be national in scope (instead of just a survey of RFG
areas), and the BOB manufacturer must participate in NSTOP.\74\
Additionally, since we are broadening the scope of the oxygenate
accounting process from RBOB to all BOB, we are also requiring that
gasoline manufacturers prepare samples using the hand blend procedures
in ASTM D7717 and that commercially available oxygenate (e.g., DFE) 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 part 1090 requirements
are the same as currently specified for the RFG program under part 80.
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\74\ The accompanying in-use survey requirements and the NSTOP
are discussed in more detail in Section X.
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In the NPRM, we sought comment on whether to allow for alternative
mechanisms for downstream oxygenate accounting. We received comments
suggesting that we include provisions to allow fuel manufacturers to
use a set of specified assumptions for benzene, sulfur, and oxygenate
content values to account for oxygenate added downstream. For reasons
discussed in detail in Section 10 of the RTC document, we are only
finalizing the proposed hand blend approach.
We also received other comments with suggestions or requests for
clarification regarding the downstream oxygenate accounting provisions,
which we have reflected in the final regulations as appropriate. We
address these comments in Section 10 of the RTC document.
[[Page 78433]]
G. Downstream BOB Recertification
We are finalizing provisions that will allow parties to recertify
BOBs downstream for different type(s) and amount(s) of oxygenate
(including E0) if certain requirements are met. Under the part 80 RFG
program, oxygenate blenders must add the type(s) and amount(s) of
oxygenate to RBOB as specified by refiners.\75\ 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 the cost
associated with recertifying batches of RBOB downstream in keeping with
these requirements under the part 80 RFG program, oxygenate blenders
have not typically opted to assume the role of a gasoline refiner. This
has all but precluded the availability of E0, E15, and the use of
isobutanol in RFG areas. The batch sizes are relatively small
(typically the volume of a single tanker truck) and do not support the
added cost.
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\75\ See 40 CFR 80.69.
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These restrictions, currently limited to RFG areas under part 80,
would have been compounded by the expansion of the downstream oxygenate
accounting flexibility to all gasoline under part 1090 discussed in
Section VII.F. As such, we are including 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.
Under part 1090, we are requiring 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, they would need to make up for the lost
dilution of the sulfur and benzene in the national gasoline 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 use default assumed values for the
amount of sulfur and benzene from the BOB and are setting default
values of 11 ppm sulfur and 0.68 volume percent benzene. These values
are reflective of the national sulfur and benzene average values
adjusted for the absence of DFE added at 10 volume percent ethanol.\76\
The goal of these 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 will be low and small changes from actual benzene and sulfur
content will likely be offset by improved compliance oversight in other
areas of the program, as discussed in Section XIV.
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\76\ 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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We received comments on the proposed compliance calculations for
downstream BOB recertification and have made some minor modifications
based on suggestions from commenters. These changes are discussed in
more detail in Section 10 of the RTC document.
In cases where a party adds the same volume of oxygenate or more,
these credit makeup regulations do not apply, as more than enough
sulfur and benzene dilution will have occurred (e.g., 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 EPA regulations 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) or
meet all waiver conditions under CAA section 211(f)(4). 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
does 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.
We received several comments asking for clarity on how the
downstream BOB recertification requirements apply to parties that add
the same or more oxygenate to a BOB. We have added language to the
regulations that clarify that these parties do not incur deficits and
are not expected to submit additional reports as fuel manufacturers. We
address these comments in Section 10 of the RTC document.
In order to ensure that parties that recertify BOBs downstream
adhere to the provisions for downstream oxygenate recertification, we
are requiring that these parties register with EPA, transact for 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 requiring that these parties simply
undergo an annual attest engagement audit and submit an attest report
similar to the report required for gasoline manufacturers. These
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, they must include the total number of
credits needed as a result of downstream oxygenate recertification in
their annual compliance calculations as a deficit.
In the NPRM, we proposed to exempt parties that blended 200,000
gallons or less per year from the annual attestation audit for purposes
of reducing the potential costs for small volume blenders that
recertify BOBs. We sought comment on both the 200,000-gallon threshold
and whether additional flexibility was needed to control costs for
small volume blenders. Several commenters requested an increase of the
annual threshold, ranging from 1,000,000 to 2,000,000 gallons per year.
We also received several comments suggesting that we exempt these small
volume blenders from not only the annual attestation engagement, but
also the deficits themselves or from having any compliance burden
whatsoever. Commenters argued that without either increasing the
threshold or reducing the compliance burden, BOB recertification would
still be prohibitively expensive and limit the availability of E0 and
isobutanol blends for vehicles and engines where their use is
recommended (e.g., marine engines).
[[Page 78434]]
Based on these comments, we believe it is appropriate to both
increase the exemption threshold and provide additional flexibility for
small volume blenders to avoid unnecessarily increasing the costs of
such blends. Therefore, we are increasing the annual threshold to
1,000,000 gallons per year. We are also exempting parties that blend
1,000,000 gallons or less per year from incurring sulfur and benzene
deficits related to downstream BOB recertification. In combination, we
believe these changes will provide adequate flexibility for parties
that recertify BOBs to supply E0 and isobutanol blends while also
ensuring that large volume blenders do not significantly increase the
national average sulfur and benzene levels. These small volume blenders
are still required to register, report, and keep records under part
1090. We believe these requirements are necessary to help ensure
oversight of the program and do not anticipate that this will
substantially increase burdens on such blenders, as many of these
parties already are registered with EPA and submit reports under part
80.
Because the downstream BOB recertifications were a new flexibility
under part 1090, we sought comment on several issues, including whether
there were alternative mechanisms to allow for downstream BOB
recertification that would be less burdensome. While several commenters
suggested that the proposed downstream BOB recertification provisions
were unnecessary, we did not receive any comments suggesting an
alternative mechanism to allow parties to recertify BOBs downstream. We
address comments suggesting that the downstream BOB recertification
provisions are unnecessary in Section 13 of the RTC document.
We did not propose a deficit carryforward for deficits incurred
from downstream BOB recertification, as we believed that the amount of
credits needed to satisfy such deficits would be relatively small,
parties may fail to satisfy those deficits, and enforcement would be
impractical. Nevertheless, we sought comment on whether to allow for a
deficit carryforward for deficits incurred under the proposed
downstream BOB recertification provisions. Several commenters suggested
that we should provide such deficit carryforward provisions. However,
in light of the exemption provided for volumes up to 1,000,000 gallons
per year as discussed earlier, and for reasons explained in more detail
in Section 13 of the RTC document, we are not providing deficit
carryforward provisions for deficits incurred from downstream BOB
recertification.
Several other commenters suggested modifications to the downstream
BOB recertification provisions. We address these comments in Section 13
of the RTC document.
VIII. Registration, Reporting, Product Transfer Document, and
Recordkeeping Requirements
A. Overview
This rule transfers and consolidates many of the existing part 80
registration, reporting, PTD, and recordkeeping provisions in new part
1090. As discussed in the NPRM, we have sought to reduce the impacts on
regulated parties and reduce the burden associated with maintaining and
submitting information, an approach generally supported by commenters.
In certain cases, we have simplified and better aligned reporting
requirements with current industry practice, which is particularly true
of the batch reporting requirements described in greater detail in
Section VIII.C.
Except for certain information discussed in Section XIII.H,
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
treat such information from public release in accordance with the
provisions of 40 CFR part 2, subpart B. 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. Information that may
be publicly released 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. We did not propose a
comprehensive CBI determination and, therefore, are not finalizing one
here.
B. Registration
1. Purpose of Registration
Registration is necessary to: (1) Identify parties engaged in
regulated activities under EPA regulations; (2) allow regulated parties
access to systems to submit information required under EPA's fuel
quality regulations; and (3) provide regulated parties with company and
compliance-level identification numbers for producing PTDs and other
records. Part 1090 makes modest changes to the existing registration
system, including modernizing certain terminology and updates that make
registration easier to understand and implement.
A number of commenters sought clarification on the proposed
registration requirements under part 1090 and we have incorporated them
to the extent appropriate. We address these comments in detail in
Section 11 of the RTC document.
2. Who Must Register
The registration regulations update terminology to better reflect
current roles and activities in the fuel production and distribution
system. This rule includes registration requirements for certain third
parties, such as auditors. These are explained in greater detail below.
The following parties must register 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 under 40 CFR
1090.515(g)
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 are subject to registration under part 1090
are already registered under part 80. We did not propose to require
parties who are already registered under part 80 to go through the
effort to re-register their company or their facilities under part
1090. Some commenters specifically stated that they believe parties
should not have to re-register and we agree.
Part 1090 includes specific provisions that ensure such parties do
not need to re-register. For example, although we do not currently
register parties under part
[[Page 78435]]
80 as ``gasoline manufacturers,'' parties who are currently registered
as ``refiners'' are covered under this new term and do not have to re-
register. We do not believe that migration of part 80 requirements to
part 1090 will result in a significant number of new registrants, and
existing registrants will 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). Existing
registrants may also need to access the registration system in order to
associate with auditors or other third parties who will submit reports
on their behalf. Association is a step within the existing registration
system and is designed to ensure that the company for which the reports
are submitted by a third party 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.
Part 1090 removes the registration requirement for independent
laboratories that existed in part 80. As a result, independent
laboratories are no longer required to register unless they submit
information directly on behalf of another party, such as a gasoline
manufacturer. In such cases, they will need to update their
registration to reflect that they are submitting reports on behalf of a
regulated party and will have to associate with the company or
companies for which they will submit reports.
We are finalizing registration requirements for independent
surveyors and auditors under part 1090. These parties were 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. Independent surveyors perform
the compliance surveys and the 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.9,
independent surveyors have to register with EPA 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. Having the independent surveyor
register and be able to submit reports via EPA's established reporting
system will allow us to more quickly publicly post in-use survey
results.
As also previously noted, auditors already performed 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 engage an auditor to perform the
attest engagement, and the auditor gives the attest engagement to the
party who then must submit it to EPA. Some parties have found this
process cumbersome. In order to streamline the reporting process, we
proposed to establish a means by which auditors may submit the attest
engagement directly to EPA and in a manner that ensures the party for
whom it was performed is aware of the submission. To implement this
change, auditors will register and associate with the regulated party;
then, the auditor will submit reports directly to EPA. This will ensure
that they are submitting reports on behalf of a regulated party and
that the attest engagement is properly submitted. This will also help
EPA to contact the company and the auditor regarding any difficulty
with the submission.
3. What Is Included in Registration
Like the existing provisions in part 80, registration under part
1090 entails 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 set up the necessary accounts. Part 1090 updates the
terminology for companies to more modern usage; it does not change the
fundamental activity or purpose of registration.
4. Deadlines for Registration
Under part 80 new registrants have to register 60 days prior to
engaging in regulated activity. This timeframe remains a useful
guideline, as we must be allowed an appropriate amount of time to
process and activate registration-related requests. Part 1090 requires
that registration occur 60 days prior to a party engaging in any
activity that requires registration. We are retaining the requirements
from part 80 that updates to existing registration must occur within 30
days of the event requiring the change. As previously discussed, we do
not expect many new registrants under part 1090, as existing
registrants under part 80 will continue to be registered under part
1090. Company and compliance-level (e.g., facility) identification
numbers issued under part 80 will remain valid under part 1090. We do,
however, anticipate newly registering up to 100 auditors, one surveyor,
and 50 third parties.
5. Changes in Ownership
As explained in the NPRM, we have received feedback over the years
from registrants that changes in ownership should be addressed more
clearly in the regulations. Consequently, we proposed provisions to
clarify how a company may initiate a change in ownership for
registration purposes. The provisions on updating registrations for
ownership change largely codify existing guidance provided to companies
under part 80.
Part 1090 clarifies that companies will 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. In the case of a change in ownership requiring
an update to an existing registration, a company will 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 will 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 as
currently required under part 80) is not workable due to how ownership
changes are effectuated in the business world. Although we did not
propose, and are not finalizing, a specific, advance deadline, we note
that it may take several days or weeks 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 to ownership change as a
good guideline. Based on our experience with ownership changes under
part 80, companies will want EPA to activate registration changes for
ownership changes in a timely manner to ensure that registrations are
up-to-
[[Page 78436]]
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 complicated and involve many facilities, 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
finalizing 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 of which 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. Cancellation of Registration
We are finalizing new provisions for voluntary and involuntary
cancellation of registration under part 1090. 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 under
part 1090.
Voluntary cancellation is initiated by the registered party (e.g.,
if the party's business changes and it no longer engages in an activity
that requires registration). We are including voluntary cancellation
language in part 1090 because registered parties often ask for
clarification of the procedure involved.
Involuntary cancellation is 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 will provide notification of our intention to cancel the party's
registration and the registrant will 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 30 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.
Several commenters noted that there was a discrepancy in the NPRM
between the preamble and the regulations regarding the period by which
missing reports must be received. The NPRM preamble said 14 days, but
the regulatory text said 30 days. We are clarifying that we intended
the longer response time (i.e., 30 days).
In instances of willfulness or where public health, interest, or
safety requires, EPA may deactivate the registration of the party
without any notice to the party. In such cases, EPA will provide
written notification to the RCO identifying the reason(s) EPA
deactivated the registration of the party. We expect such situations to
be extremely rare.
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 reducing the number of
parameters to be tested and reported and, in some cases, reducing the
required frequency of reporting.
A number of commenters sought clarification on the proposed
reporting requirements under part 1090 and we have incorporated them to
the extent appropriate. We address these comments in detail in Section
12 of the RTC document.
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
Certified pentane blenders
Independent surveyors
Auditors
As discussed in Section VIII.B, certain parties are required to
register to receive company and compliance-level identification numbers
for use on PTDs and for recordkeeping, although they do not have
reporting requirements under part 1090. For example, parties involved
in the manufacture and distribution of 500 ppm LM diesel fuel are
required to register and receive company and compliance-level
identification numbers to use on PTDs and records but do not submit
reports under part 1090.
3. Key Differences Between Part 1090 and Part 80
We are eliminating 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
[[Page 78437]]
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 (as a percent reduction from baseline)
VOCs (as a percent reduction from baseline)
Exhaust Toxics Emission
Other identifying information (i.e., Batch Grade, lab waiver,
independent lab analysis requirement)
We are retaining the four main parameters for gasoline reporting:
Sulfur, benzene, RVP, and oxygenate type/content.\77\ The parameters
being eliminated from reporting, although once useful, are no longer
needed in reports, as discussed in Section V.A.2. Removing these
parameters reduces compliance costs related to reporting, sampling, and
testing, without sacrificing our goal of protecting human health and
the environment. Under part 1090, we are also simplifying the annual,
batch, and credit transactions reporting, which results in many fewer
forms and data elements for respondents.
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\77\ For batches that are certified using the hand blend
approach (discussed in more detail in Section VII.F), the hand blend
will not typically be tested for oxygenates; however, gasoline
manufacturers will report the type and amount of each oxygenate
blended to make the hand blend. Manufacturers that certify batches
of gasoline using a different approach will still need to test and
report oxygenate content unless they can demonstrate that the
gasoline contains no oxygenate (i.e., the gasoline is E0).
Furthermore, in all cases, we only require that gasoline
manufacturers report the oxygenates added or tested for, instead of
reporting information for all potential oxygenates. We believe this
greatly simplifies oxygenate reporting requirements compared to part
80.
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Under part 80, there are numerous reporting forms in use; these
reporting forms are now simplified and reduced under part 1090.
Reporting forms and format 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. 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. In doing this, we are also
eliminating collection of information that is no longer necessary,
reducing the number of parameters and test methods reported,
simplifying the type and number of reports to be filed, and, in many
cases, reducing the frequency of reporting (e.g., going from quarterly
to annual).
The reporting requirements for gasoline manufacturers include 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.
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.
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 regulations address reporting for
gasoline, oxygenates, and regulated blendstocks and explain 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 detailed color-coded
batch reporting summary table as part of the reporting form
instructions and this table reflects 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.
Attest engagements. Under part 1090, we have changed the
method of submission of annual attest engagements. Under part 80,
refiners and importers submit attest engagement reports themselves.
Under part 1090, the attest engagement report will be submitted on the
fuel manufacturer's behalf by the auditor. Fuel manufacturers remain
responsible for engaging an auditor to conduct the attest engagement,
and for ensuring that a proper attest engagement is submitted to EPA.
To do this, as explained in Section X.A.2.d, the auditor will register
with EPA and be associated with a registered company. To ensure that
the auditor and the company for whom they are preparing the report
agree, these parties must associate with each other within the
registration system. This action aligns the submission of the attest
engagements under part 1090 with the requirements of the RFS program.
We had proposed that the attest engagement submission would require a
description of the findings and the steps the regulated party would
take to address remedial actions, but did not require that all the
remedial action steps occur before submission. We are finalizing the
requirement that the submission include a description of the findings.
We are not finalizing the requirement that the submission by the
auditor address remedial actions related to the attest engagement, as
we agree with commenters that this report item may be beyond the normal
scope of the auditor. Some commenters expressed a desire to receive the
attest engagement report prior to submission to EPA by the auditor; we
believe that this is within the ability of the party to arrange with
the auditor and need not be specified in the regulations. The auditor
and the party with whom they are associated (and for whom the attest
engagement was prepared) will be able to download the report submitted
to EPA. Attest engagements are discussed in detail in Section XII.B.
5. Reporting Requirements for Gasoline Manufacturers That Recertify BOB
for Different Type(s) and Amount(s) of Oxygenate
In order to implement the optional provisions discussed in Section
VII.G with respect to treatment of BOBs, we are finalizing 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 BOB manufacturer, they
will 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.\78\ Credit transactions
associated with re-certification of the BOB will also be reported.
Parties that recertify BOBs may include all volumes and deficits in a
single reported batch of up to 30 days. (Allowing this reduces the
reporting burden.)
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\78\ 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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[[Page 78438]]
6. Reporting for Oxygenate Producers and Importers
Similar to part 80, oxygenate producers and importers must submit
batch reports providing information about the oxygenate they produce or
import. Reporting for oxygenate producers is 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 DFE, the
reported information will specify whether the denaturant is certified
ethanol denaturant or non-certified.
7. Reporting for Certified Pentane Producers and Importers
Similar to part 80, certified pentane producers and importers must
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.
8. Reporting by Diesel Manufacturers
We are finalizing limited batch reporting for manufacturers of
diesel fuel. Specifically, manufacturers of diesel fuel (excluding 500
LM diesel fuel from transmix) that test any batch found to exceed the
applicable 15 ppm sulfur standard must report information about that
batch. Batches that do not exceed the applicable 15 ppm sulfur standard
will not be reported to EPA. The specific information 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,
the burden of reporting a relatively small number of batches found to
exceed the applicable 15 ppm is small. This limited batch reporting
will assist us in our compliance oversight efforts and in ensuring that
the human health and environmental benefits of the program are
realized. This action also transitions the diesel fuel property
reporting from part 79 to part 1090 in a simplified form, which
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).\79\ We believe that the simplified property
reporting for diesel fuel will help us better oversee the fuel quality
requirements or diesel fuel under part 79 and part 1090.
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\79\ Diesel fuel manufacturers must still submit periodic
reports related to the additives used in their diesel fuel as
specified under 40 CFR 79(a)(1).
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9. Reporting by Independent Surveyors
Independent surveyors are required to register and report. The
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 are also expected to comply with an annual
reporting requirement that addresses summary statistics and describes
compliance rates and non-compliance issues. Independent surveyors must
also submit similar reports under NSTOP. The independent survey program
and NSTOP are discussed in Section X.
10. Deadlines for Reporting
The following reporting deadlines apply to part 1090:
Annual compliance reports for sulfur and benzene 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
March 31, 2022).
Batch reports must be submitted by March 31 for the
preceding compliance period.
Attest engagements must be submitted by auditors by June 1
for the preceding compliance period.
Reports by independent surveyors will 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.
Part 1090 reporting deadlines are the same as part 80 with one
exception. Under part 80, RFG refiners and importers had to submit
quarterly batch reports compared to CG refiners and importers who only
had to submit annual batch reports. Under part 1090, we are requiring
that all batch reports must be submitted annually for all gasoline
manufacturers.
Some commenters had suggested that aligning the compliance
reporting and the attest engagement due date of June 1 might lead to
fewer report resubmissions, and that the auditor would be able to
perform the attest engagement using the batch reports that were due on
March 31. Although we agree that reducing resubmissions of reports is a
consideration, we must balance this against the compliance need to be
able to process and utilize ABT and credit reports in a timely manner
and against the data transparency purpose of making information about
the program available to the public in a timely manner. Therefore, we
are finalizing the reporting deadlines as proposed.
11. Reporting Forms
We have docketed the reporting forms and have submitted them to OMB
for review with the ICR for this rule. We received several comments
related to the content and structure of the forms and have amended
several forms in response to these comments. We address these comments
in detail in Section 12 of the RTC document.
D. Product Transfer Documents (PTDs)
The general purpose and requirements for PTDs under part 1090 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. 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 removes PTD language that is no longer needed and provides
standard, updated language to address a variety of common products and
situations. We are, however, making some minor modifications from the
part 80 requirements.
The PTD requirements apply on each occasion when any person
transfers custody or title of IMO marine fuel except when the IMO
marine fuel is dispensed for use in marine vessels. Part 1090
incorporates the Bunker Delivery Note (BDN) requirements from 40 CFR
1043.80 to address the transfer of IMO marine fuel by a fuel supplier
onto a vessel.\80\ Each fuel supplier is independently responsible for
meeting the BDN requirements. However, the BDN requirements must be met
only once for each delivery of fuel onto a vessel. As a result, if the
BDN requirements are properly met by the fuel supplier that transfers
custody or the fuels supplier who transfers title of the fuel onto a
vessel, EPA will consider the requirements to have been met by each
fuel supplier. This approach
[[Page 78439]]
provides parties with the flexibility to contractually allocate the BDN
responsibilities as they see fit among themselves and ensures that the
BDN requirements will be met. Pursuant to 40 CFR 1043.80, each fuel
supplier must keep copies of the BDNs.
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\80\ A fuel supplier includes a person who transfers custody or
title of marine fuel to a vessel.
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As proposed, we are including 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
in its language requirements across the various part 80 fuel quality
programs. To make our PTD requirements more consistent, we are
requiring 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 requirements. To address these potential issues, we are
adding flexibilities for parties to seek approval for alternative PTD
language for all PTD language requirements. Based on experience
implementing part 80, we do not anticipate that many parties will
request alternative PTD language.
We received several comments suggesting clarifying edits to the PTD
requirements to help the part 1090 regulations address common
situations that arise in the production and distribution of fuels. We
address these comments in Section 13 of the RTC document and have
reflected these suggestions where appropriate in the part 1090
regulations.
E. Recordkeeping
Part 1090 contains the same record retention requirements as those
in part 80. All parties that were required to keep records under part
80 will 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 will
decrease.
In general, we received few comments on the proposed recordkeeping
requirements. These comments suggested edits to the regulations for
clarity. We made slight modifications to the regulations in response to
these comments. These comments are addressed in Section 14 of the RTC
document.
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 calculations of 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. As proposed, we are finalizing a much broader
and consistent approach in part 1090 using the standard approach to
rounding in 40 CFR 1065.20 that is consistent with ASTM E29. We are
requiring this rounding protocol for all recorded values under part
1090.
Part 1090 includes additional specifications for calculating and
recording numerical values. First, we are specifying 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 requiring 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 does not 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. 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.
We did not receive any comments on the rounding provisions and we
are finalizing the rounding provisions as proposed with one exception.
In order to avoid confusion associated with the rounding of batch
volumes for small batches of fuel that might be produced in standard-
size tanker truck volumes, we are changing the batch size threshold for
rounding to the nearest 10 gallons from 10,000 to 11,000 gallons.
G. Certification and Designation of Batches
We are finalizing the batch certification and designation
provisions largely as proposed. 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
currently outlined in guidance. We are incorporating such guidance into
part 1090 and establishing a clear process to certify batches. The
[[Page 78440]]
part 1090 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 certify
products under part 80. These requirements also satisfy CAA section
211(k)(4) describing certification procedures for RFG.
Regarding designation, for gasoline and gasoline-related additives
and regulated blendstocks, we are modifying the designation
requirements for these products. Most of these 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
removing those designations. Additionally, we are providing flexible
redesignation provisions for distributors of gasoline. These proposed
provisions largely reflect the streamlining of the RFG program and the
more fungible nature that results.
Under part 1090, distributors of gasoline are 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 resultant mixture and designate the new batch accurately
to reflect the RVP of the gasoline as described under this section.
When transitioning tanks from winter to summer gasoline, parties are
not required to test the RVP but must be able to assure that the
gasoline meets the applicable RVP standard.
We are also making it clear in part 1090 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 maintaining the part 80 designation
requirements. We are, however, making two notable changes. First, we
are providing for a more flexible ULSD designation for distillate fuels
certified to meet ULSD standards. The intent of this flexibility is to
ensure that fuels that meet the ULSD standards could be designated as
necessary to be used as home heating oil, MVNLRM diesel fuel, or IMO
marine fuel. This change will allow parties to make sure that fuels are
designated appropriately throughout the distribution system.\81\
Second, similarly to gasoline, we are allowing parties to redesignate
California diesel fuel that meets the ULSD standards without
recertification. We believe the designation changes for diesel fuel
would help maximize the fungibility of distillate fuels that meet the
ULSD standards.
---------------------------------------------------------------------------
\81\ This action does not address how these fuels are accounted
for inclusion in obligated parties' renewable volume obligation
(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 7054-57, February 6,
2020).
---------------------------------------------------------------------------
We received several suggestions and requests for clarification
regarding the certification and designation provisions under part 1090
from commenters and have made slight modifications to the regulations
in response to these comments. We address these comments in Section 13
of the RTC document.
IX. Sampling, Testing, and Retention Requirements
Our fuel quality programs consist 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 test procedures
essentially unchanged from part 80 into part 1090 and updating them in
the process as proposed. We are also reorganizing the testing
provisions in part 1090 and codifying 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
changes relative to what currently applies under part 80.\82\
---------------------------------------------------------------------------
\82\ 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. As proposed, and in keeping with the discussion in Section
V.A.2, for part 1090 we have reduced this to just three parameters:
Sulfur, benzene, and RVP (in summer) for all gasoline, except for some
unique situations discussed in more detail below. Diesel fuel
manufacturers will continue to have to test for the sulfur content.
Similar to part 80, under part 1090, gasoline manufacturers will
also be required to sample and test finished fuels for oxygenates
unless the gasoline manufacturer is making gasoline without oxygenates.
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. This will provide some
confirmation that the blended product has a distillation profile that
is generally consistent with gasoline meeting the substantially-similar
requirements of the CAA. The results of the distillation testing is not
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 gasoline manufacturers.
Under part 1090, CG refiners and diesel fuel manufacturers must
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. 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 refinery.
Similar to part 80, we are requiring under part 1090 that all
gasoline manufacturers obtain test results for sulfur and RVP (during
the summer months) before shipping gasoline from the fuel manufacturing
facility. Part 80 also requires refiners to obtain test results for
benzene before shipping RFG, but does not require refiners to first
obtain these results for CG. Under part 1090, we are not requiring
gasoline manufacturers to test for benzene before shipping gasoline
from the fuel manufacturing facility.
We are maintaining part 80 exceptions to testing under current
waivers that do not require measurement of fuel properties prior to
[[Page 78441]]
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 proposed to allow for the in-line
blending waiver only for certain shipment configurations that do not
allow for conventional batch testing. We received comments requesting
that we clarify whether storage tanks prior to pipeline injection,
typically used to accommodate cases where gasoline needs to be held
prior to pipeline injection, could be included in an in-line blending
waiver request. Under part 80, we have allowed such storage tanks to
serve as an extension to the pipeline system as these tanks are
typically not suitable for use as a certification tank. Based on these
comments, we have revised the final rule to continue allowing the
approach from part 80 in which refiners may apply for the in-line
blending waiver for shipment configurations that include storage tanks
that act as an extension of the pipeline system.
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 part 80
sampling procedures and demonstration of homogeneity of fuel samples
that are currently specified in 40 CFR 80.8 to part 1090 as proposed.
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 relating 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.\83\ We are reflecting that guidance in part
1090 by adding numerous minor clarifications and adjustments to the
regulatory text to reflect current best sampling practices. Several
commenters suggested edits to the proposed regulations, as well as
sought clarification of the various sampling procedures for fuels. We
have reflected these comments in the final regulations as appropriate,
and address these comments in Section 15 of the RTC document.
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\83\ 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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2. Sample Preparation for BOB Testing
Section VII.F describes the ``hand blend'' approach for gasoline
that would allow gasoline manufacturers to account for the impacts of
downstream blending of oxygenate into BOB in their sulfur and benzene
compliance calculations.\84\ The hand blend procedure involves
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, as a
result of homogeneity testing, three tested BOB samples are commonly
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 addressing these
examples of discretion in the specified procedures by requiring that
the hand blend represent a worst-case test condition with respect to
oxygenate content. In the case of sulfur measurements from multiple
samples to represent a batch of BOB, the regulation requires taking
steps to avoid introducing high or low bias in sulfur content when
selecting from available samples to create the hand blend.
---------------------------------------------------------------------------
\84\ The regulations at 40 CFR 80.69 and 80.101 practically
limits this practice to RBOB. As discussed in Section VII, we are
making it more practical for all fuel manufacturers of BOB to
account for the addition of oxygenate added downstream. Part 80 also
does not currently specify preparation procedures for hand blends.
---------------------------------------------------------------------------
Under part 1090, winter gasoline must 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 approach is necessary to properly select
the type and amount of oxygenate for hand blending in summer gasoline
to properly account for the impacts on RVP. Summer gasoline will need
to be blended with the lowest specified percentage of oxygenate 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 part 80 regulations requires sample
retention for 30 or 90 days. We are requiring 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 oil 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 leased
terminal tanks). We therefore believe it is appropriate to require a
longer retention period for blending manufacturers to help trace
potential issues with fuel quality. We proposed 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. We received several comments suggesting that the proposed
120-day retention period was too long. Commenters contended that such a
long retention period would result in the need to develop new capacity
to retain fuel samples which would be quite burdensome. Commenters
suggested a range of different retention periods from 30 days, as
proposed for other fuel manufacturers, to 90 days. In response to these
comments, we now believe that a 90-day retention window is the most
appropriate balance to ensure robust controls on fuel quality from
fuels made by a blending manufacturer. We address this issue in more
detail in Section 15 of the RTC document.
For testing BOB and hand blended samples of oxygenated gasoline as
described in Section IX.C, the sample-retention requirements apply for
only for the BOB sample. 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
[[Page 78442]]
demonstrate compliance. For any testing, with the retained sample, EPA
or the fuel manufacturer would use any standard supply of DFE or other
oxygenate to re-create the hand blend.
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
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. As discussed in Section
X.A.2, the independent surveyor will test for the full suite of Complex
Model gasoline parameters, and testing will be performed by an EPA-
approved test lab on fuels intended to represent the range of fuels in
distribution over time.
Survey measurements must 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 received comments asking for minor clarification on the test
procedures that independent surveyors would use under part 1090. We
have reflected these comments on the final regulations as appropriate,
and address these comments in Section 15 of the RTC document.
2. Procedures To Determine Cetane Index for Diesel Fuel
Part 80 and the CAA establishes a cetane index standard at or above
40 for diesel fuel used with motor vehicles and nonroad equipment.\85\
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.
We proposed to allow the use of both ASTM D976 and ASTM D4737 in
determining cetane index and received comments in support. As such, the
final rule specifies that either of the referenced ASTM procedures are
acceptable for determining cetane index for diesel fuel.
---------------------------------------------------------------------------
\85\ See CAA section 211(i) and 40 CFR 80.520(a)(2).
---------------------------------------------------------------------------
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
exempting biodiesel from testing to verify compliance with the cetane
index or aromatic content requirement for diesel fuel.
Several commenters suggested that we should modify our proposed
definition for biodiesel to tie it to industry specifications under
ASTM D6751. These comments noted that the proposed definition only
required that biodiesel contain a minimum 80 volume percent mono-alkyl
esters and asked EPA to clarify what the other 20 volume percent of the
biodiesel could be.
While we do not believe that we should limit biodiesel covered
under part 1090 to only biodiesel that meets ASTM D6751 (this issue is
addressed in more detail in Section 4 of the RTC document), we
appreciate the need for clarification regarding which biodiesel fuels
are exempt from cetane index/aromatics testing. We believe, based on
suggestions from commenters, that exempting all biodiesel from cetane
index and aromatics testing, while allowing biodiesel to contain 20
volume percent of substances other than mono-alkyl esters, would not be
appropriate. We also believe that ASTM D6751 provides sufficient
limitations on the concentrations of impurities in biodiesel to ensure
that the biodiesel would not have any aromatics content, thereby
meeting the cetane index/aromatics diesel fuel requirements. Therefore,
we are finalizing that biodiesel that meets ASTM D6751 is exempt from
cetane index and aromatics testing under part 1090. Conversely,
biodiesel or biodiesel blends that do not meet ASTM D6751 are not
exempt from cetane index and aromatics testing.
3. Performance-Based Measurement System
Part 80 contains the Performance-Based Measurement System (PBMS)
that establishes objective criteria for qualifying laboratories and
measurement procedures.\86\ 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.
---------------------------------------------------------------------------
\86\ See 40 CFR 80.46 and 80.47.
---------------------------------------------------------------------------
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 broadening 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 points in the fuel distribution system.
PBMS provisions also apply for quality audits such as what is required
for in-line blending waivers, for truck and rail imports where the
importer has elected to comply with the alternative per-gallon
standards, and for blending certified butane and pentane into PCG. Any
other application 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 to part 1090 that
currently apply under part 80, subject to the following exceptions and
clarifications.
First, we are changing the designated referee procedure for
measuring benzene in gasoline from ASTM D3606 to ASTM D5769. We believe
ASTM D5769 is 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 and the prevalence of ethanol in
gasoline now makes its use more challenging. Since ASTM D3606 is
[[Page 78443]]
the referee procedure for measuring benzene in gasoline under part 80,
we are waiving 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. We received several comments suggesting that
we should not update the referee procedures for benzene from ASTM D3606
to ASTM D5769. These commenters mostly highlighted potential logistical
issues with converting to a new designated referee method but not with
the method itself. As such, we continue to believe that ASTM D5769
should be the referee method, as it does not suffer from matrix effects
when testing gasoline-oxygenate blended fuels, which are predominant in
the marketplace today. We address this issue in more detail in Section
15 of the RTC document.
Second, we are removing measurement of aromatic content in diesel
fuel from the PBMS protocol since, consistent with part 80, we are not
requiring aromatics testing for every batch of diesel fuel under part
1090. 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 specifying ASTM D1319
and ASTM D5186 as acceptable procedures for measuring aromatic content
in diesel fuel and allowing for alternative procedures that correlate
with either of these specified procedures.
We proposed to specify ASTM D6667 as the procedure for measuring
sulfur in pentane. Based on comments, we have revised the final rule to
instead specify ASTM D5453 as the appropriate method as discussed in
Section 15 of the RTC document.
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 DFE, 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. We did not receive any comments on subjecting
oxygenates to the PBMS requirements and are finalizing these provisions
as proposed.
c. Updated Versions of Referenced Procedures
EPA fuel regulations rely on 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, part 1090 allows laboratories to use
updated versions of referee procedures or qualified alternative
procedures without prior approval from EPA, as long as the updated
version has published repeatability and reproducibility that is the
same as or better than the version referenced in part 1090.
Laboratories wanting to use an updated method of a referee
procedure to qualify alternative procedures must first get EPA approval
because using an updated referee method to qualify an alternative
method could potentially change the baseline for which other previously
approved alternative methods were compared. This could create
disparities in how alternative methods are qualified, and we would like
the ability to ensure that such disparities do not result in
inappropriate qualification of new alternative methods. 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. 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 unchanged with two exceptions. First, we 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 specify precision and
accuracy criteria for gasoline benzene based on the most recently
published reproducibility values from ASTM D5769 instead of ASTM D3606
in keeping with the change in the designated referee method described
in Section IX.C.3.b. 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 require 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 allows 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 is
difficult for measuring sulfur in neat biodiesel, since it has
inherently low sulfur concentrations. We 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.
Part 1090 requires the between-methods-repeatability,
Rxy, for qualifying alternative procedures for method-
defined parameters using non-VCSB methods to 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 as a viable option.
e. Ongoing Testing for Statistical Quality Control
Further, we are transferring the statistical quality control
procedures (SQC) established under 40 CFR 80.47 to part 1090. By
rewriting these procedures in their own section, the provisions in part
1090 will likely clarify some points that were previously subject to
differing interpretations. We have also updated the SQC procedures to
the latest version of ASTM D6299. This should provide additional
flexibility to meet ongoing SQC requirements. We address other comments
related to ongoing SQC requirements in Section 15 of the RTC document.
[[Page 78444]]
X. Third-Party Survey Provisions
Third-party verification plays an important role in overseeing
compliance with EPA's fuel quality programs under part 80. One key
element to the existing third-party oversight regime is in-use retail
level surveys. An advantage of retail survey programs is that they
target fuel quality at the point where 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 ethanol content, which are tracked in
RFG areas, and 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 pool. We are finalizing provisions
for a national survey program in part 1090 that will consolidate the
four programs under part 80 into a single national in-use retail survey
program, thereby reducing overall costs, while at the same time
expanding the benefits of the survey program nationwide. The part 1090
survey builds upon the part 80 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,\87\ and reducing
the number of fuel parameters that fuel manufacturers need to test and
report.
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\87\ See Section VII.F.
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Part 1090 includes two survey programs: (1) A national survey
program of retail outlets that offer gasoline and diesel to ensure that
in-use standards are met; and (2) a voluntary national sampling and
testing oversight program (NSTOP) 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 EPA's fuel quality program. This section
discusses both programs in detail.
A. National Survey Program
As previously explained, we are finalizing 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 Minimum
Program 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 EPA's 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 relying 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). 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 part 80 compliance oversight has been on
refiners that manufacture fuels at crude oil refineries with provisions
that then attempt to ensure that the fuel quality as measured at the
refinery is maintained all the way to retail. What happens at the
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 finished fuels
(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 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 parties are taking actions that can impact fuel
quality downstream of the refinery, all in-use gasoline could benefit
from a retail survey. Without it we could not implement 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 extending the retail survey that
[[Page 78445]]
has been applicable for over 20 years in RFG areas to all gasoline
nationwide. The national in-use gasoline survey will 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 will also enable EPA to
provide compliance flexibility to CG refiners and importers similar to
RFG refiners and importers.
2. National Fuels Survey Program
a. Consolidation and Scope
We are finalizing the consolidation of the four in-use survey
programs outlined in Table X.A-1 into a single national fuels survey
program (NFSP). We believe the expanded scope of gasoline samples
tested nationwide will help us ensure fuel quality oversight and
compliance with EPA's applicable fuel quality standards in-use. This
will also provide compliance flexibility for CG manufacturers to
account for oxygenate (as discussed in Section VII.F). As previously
explained, the ULSD and E15 survey programs under part 80 are national
surveys of retail stations but only test for sulfur in diesel fuel and
ethanol content and RVP of gasoline 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. Under part 80, 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, the required sample size of the NFSP under part 1090
could be reduced to less than 7,000 retail outlets sampled. Since the
largest expense in retail surveying is the cost to collect and ship a
sample from a retail station, reducing the sample size from more than
18,000 to less than 7,000 will substantially decrease the costs of the
program.
The main benefit to EPA and the public is the expanded scope of
testing for regulated fuel parameters to all fuel nationwide. Under the
part 80 programs, 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, the gasoline properties tested for will
also be consolidated. Sulfur, benzene, RVP (in the summer), and
oxygenates will be tested for all the samples. A statistically
determined subset of the national gasoline sample will 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
NFSP will also continue to ensure E15 pump labeling compliance at
retail stations. For diesel samples, the survey will continue to test
for sulfur.
We received several comments that supported this consolidation and
most of those comments appreciated the reduced burden associated with
the sample size reduction. We also received comments suggesting the
removal of the verification of E15 compliance from the NFSP. We did not
propose and are not removing the existing survey requirement for fuel
and fuel additive manufacturers that make E15 or ethanol for use in
making E15. Participation in this survey is mandatory under CAA section
211(f) and was established under CAA section 211(c) to ensure that E15
fuel dispensers are labeled correctly. We consider these comments
outside the scope of this action.
b. Survey Participation
Gasoline manufacturers only need to participate in the NFSP if they
choose to account for oxygenate added downstream in their compliance
calculations. Under part 80, the RFG regulations imposed a similar
survey requirement on RFG refiners and importers that accounted for
oxygenate added downstream \88\ and since we are now allowing this
flexibility for manufacturers of CG, we are imposing 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.
---------------------------------------------------------------------------
\88\ See 40 CFR 80.69.
---------------------------------------------------------------------------
Under part 1090, parties that participate in the NFSP will satisfy
one of the elements of an affirmative defense for downstream violations
of our applicable fuel quality standards. Under part 80, we provide 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 NFSP 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 will
continue to participate in the NFSP 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.\89\
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 finalizing as proposed that participation in the NFSP
would satisfy the national survey option for purposes of compliance
with the E15 waiver conditions or E15 substantially similar
determination. The E15 waiver conditions and E15 substantially similar
determination allow E15 fuel and fuel additive manufacturers to
continue to use 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
will continue to elect to participate in the NFSP due to its
significant cost savings.
---------------------------------------------------------------------------
\89\ See 75 FR 68094 (November 4, 2010), 76 FR 4662 (January 26,
2011), and 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------
c. Sample Sizes
For the NFSP, we are finalizing the proposed minimum sample size of
5,000 gasoline retail outlets and 2,000 diesel outlets. As outlined in
the NPRM, 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
[[Page 78446]]
proposed the same sample size determination methodology that is used
for those programs. This resulted in approximately 5,000 retail outlets
since the existing survey program for E15 misfueling mitigation is
national in scope. We also highlighted that since most retail outlets
offer both gasoline and diesel fuel, the total number of retail outlets
sampled could be closer to 5,000 retail outlets rather than 7,000
outlets. This is significantly lower than the 18,000 retail outlets
required under part 80. We believe that it will maintain the
statistical rigor of the existing part 80 programs while reducing
costs. We received several supportive comments in the burden reduction
associated with the consolidation of the part 80 survey programs into a
single program. We did not receive any comments suggesting that we use
a different sample size or sample size selection methodology.
For the subset of gasoline samples that would continue to be tested
for the full suite of Complex Model fuel parameters, we proposed that
the sample size would be determined using a standard calculation to
estimate national fuel parameters. We estimated that around 1,200
gasoline samples would need to be analyzed for the full suite of
Complex Model fuel parameters using this methodology. We received no
comment suggesting an alternative methodology to calculate the number
of gasoline samples that would be tested for the full suite of Complex
Model fuel parameters, therefore, we are finalizing as proposed the
requirement to test a subset of gasoline samples for all fuel
parameters of the Complex Model and the methodology to determine the
sample size of such gasoline samples.
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 must conduct the NFSP and meet
similar independence requirements from parties that hire the surveyor
to conduct the program. The independent surveyor is not allowed to have
financial interest in companies that hire the independent surveyor to
conduct the survey, nor are companies that hire the independent
surveyor allowed to have a financial interest in the independent
surveyor's organization. Like the part 80 survey programs, the surveyor
must submit an annual plan for surveys conducted under part 1090 to EPA
for approval. The plan must identify how the independent surveyor
intends to meet the survey regulatory requirements and is subject to
EPA approval prior to conducting the survey. Additionally, the
independent surveyor must submit annually to EPA proof that the NFSP
has been fully funded for the next compliance period by December 15.
Except for comments that suggested that the employment criteria for
independence should be shortened from three years to one year
(discussed in more detail in Section XIII.A, we received no comments on
the proposed requirements for the independent surveyor. Therefore, we
are otherwise finalizing these provisions as proposed.
As part of our effort to modernize the fuel quality programs, we
are requiring under part 1090 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 will help
EPA more quickly provide information collected as part of the NFSP and
promote greater transparency in the fuel quality program. The proposed
reporting requirements for independent surveyors are similar to those
currently specified in part 80, and the independent surveyor will need
to keep records in a similar manner. We received no comments on our
proposal to require independent surveyors to register with EPA and
submit reports electronically and therefore are finalizing these
provisions as proposed.
B. National Sampling and Testing Oversight Program
The RFG regulations in part 80 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. Since arranging to
have an independent laboratory collect a sample is the most expensive
part of the process, commenters argued that this requirement is
unnecessarily burdensome. Part 80 also requires that every 33rd batch
of RFG collected by an independent lab must be sent to EPA for
analysis.\90\ As part of consolidating the compliance provisions across
the various gasoline and diesel fuel to create a single fuel quality
program, and in light of the retirement of the Complex Model for batch
certification and removal of various restrictions on the production and
use of RFG, we considered how best to ensure proper EPA oversight of
the sampling and testing for fuels compliance.
---------------------------------------------------------------------------
\90\ 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.
---------------------------------------------------------------------------
In lieu of the existing RFG requirements, we are finalizing the
more flexible and less burdensome NSTOP as proposed. The purpose of
this proposed program is to help ensure that fuel manufacturers are
sampling and testing in a manner consistent with the required
procedures discussed in more detail in Section IX.
As part of the NSTOP, we are requiring that the independent
surveyor review appropriate PBMS qualification and SQC data for the
samples collected and tested from gasoline manufacturers. We believe
that this will help ensure that labs that test gasoline for compliance
under our fuel quality programs are complying with EPA quality control
provisions for labs.
Like the NFSP 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 requiring an estimated 500-750 samples to be collected
as part of NSTOP annually. This compares to the several thousand
samples currently collected from RFG refiners each year under the part
80 independent laboratory requirements. These samples would be spread
across all gasoline manufacturers instead of just RFG refiners. This
provides a substantial reduction in associated burden with independent
sampling while still providing the necessary oversight.
We are finalizing the requirement that gasoline manufacturers that
elect to account for oxygenate added downstream must participate in
NSTOP. We believe this requirement will help ensure that fuel
manufacturers are sampling, testing, and reporting results of gasoline
that is representative of gasoline (i.e., BOB) leaving the fuel
manufacturing facility gate. We are also exempting refineries that have
in-line blending waivers from NSTOP as proposed since these refineries
must meet the annual audit requirement using an auditor.
Gasoline manufacturers that participate in the program will 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
requiring that an additional number of random samples be collected to
ensure an effective deterrent against complacency
[[Page 78447]]
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 will
help ensure that gasoline manufacturers are following appropriate
sampling and testing procedures year-round, even if sampled early in
the season.
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 and independent labs, which totals
between 300-400 RFG samples per year.\91\ Under part 1090, we will no
longer collect these oversight samples from RFG refiners and
independent labs, as proposed. However, as part of the NSTOP, we are
requiring that the independent surveyor send a random selection of
samples collected to NVFEL for comparison to the results obtained from
the independent surveyor and fuel manufacturer's lab. This will allow
NVFEL to continue to serve as a reference installation and maintain EPA
oversight of the NSTOP. We intend to collect a similar amount of
gasoline samples, around 300 per year, as we currently receive under
the RFG program. We received one comment noting that having NSTOP
samples shipped to NVFEL would unnecessarily add costs to the NSTOP for
little value. For reasons discussed in more detail in Section 16 of the
RTC document, we are finalizing as proposed that some NSTOP samples be
shipped to NVFEL.
---------------------------------------------------------------------------
\91\ 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 NFSP, we are requiring that an independent surveyor
conduct the NSTOP. We envision that these parties would function
similar to the way that independent surveyors operate under the part 80
survey programs. Therefore, we are requiring the same independence and
plan approval process as those used for independent surveyors under the
NFSP, which is similar to the part 80 survey requirements. The only
difference would be a change in the reported elements as samples are
collected from gasoline manufacturing facilities instead of retail
stations. We did not receive any comments on this aspect of the NSTOP
and are finalizing the requirements for independent surveyors
conducting the NSTOP as proposed.
In the proposal, we also sought comment on whether to maintain the
existing RFG independent laboratory testing requirement or whether to
require that third-party laboratories that perform testing for fuel
manufacturers under the NSTOP also register and associate. We received
several comments suggesting that the RFG independent laboratory testing
requirement was no longer necessary and that associated burdens with
requiring all third-party laboratories to register and associate with
fuel manufacturers would be cost prohibitive. We also received
comments, mostly from third-party laboratories, noting that we should
maintain the RFG independent testing requirement or require the
registration of third-party labs as a means to help ensure the
integrity of sampling and testing performed by third-parties for fuel
manufacturers. For reasons discussed in more detail in Section 13 of
the RTC document, we are finalizing as proposed the removal of the RFG
independent lab testing requirement and are not finalizing a
requirement that all third-party laboratories register and associate
with fuel manufacturers.
A number of commenters included suggestions and requests for
clarification regarding the NSTOP and we have reflected them in the
final regulations as appropriate. We address these comments in Section
13 of the RTC document.
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 Q). As described in this section,
importers will continue to be subject to the same requirements as
refiners, while exporters will continue to be subject to certain fuel
designation and recordkeeping provisions. Overall, we are making
several changes to how imported and exported fuel products are treated
relative to the provisions of part 80, although we are significantly
updating the regulatory text. Many of the modified part 1090 provisions
are merely codification of existing implementation policies summarized
in a 2003 question and answer (Q&A) document (``2003 Q&A
document'').\92\
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\92\ 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 finalizing the proposed requirements
under part 1090 for importers that largely mirror what we require under
part 80. However, we are updating some provisions for imports in part
1090. First, importers that import fuel at multiple import facilities
within a single PADD must aggregate the facilities within that PADD for
purposes of complying with the maximum benzene average standard. For
compliance with other average standards, importers will 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.\93\
---------------------------------------------------------------------------
\93\ See 19 CFR part 151, subpart C.
---------------------------------------------------------------------------
Second, under part 80, current guidance allows gasoline classified
as ``American Goods Returned'' to the United States by the U.S. Customs
Service to not count as imported gasoline.\94\ As proposed, we are
finalizing language consistent with that guidance in part 1090,
provided all the following conditions are met:
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
fuel manufacturing facility prior to being imported into the U.S.
We are not changing how importers are defined in part 1090 compared
with part 80.\95\ 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
[[Page 78448]]
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.
---------------------------------------------------------------------------
\95\ See 40 CFR 80.2(r).
---------------------------------------------------------------------------
B. Special Provisions for Importation by Rail or Truck
We are finalizing as proposed the compliance options for meeting
testing requirements when importing fuels by either rail or truck.
These provisions allow importers via rail or truck to meet the sampling
and testing requirements based on test results from the supplier
instead of testing each batch after the fuel is imported, under certain
conditions.
First, for gasoline, the truck or rail importer electing to use
supplier test results must meet 0.62 volume percent benzene content and
10 ppm sulfur content per-gallon maximum standards. This requirement is
identical to what is currently required under part 80.\96\
---------------------------------------------------------------------------
\96\ See 40 CFR 80.1349 and 80.1641. It should also be noted
that under part 1090 we are allowing these provisions to be used for
rail imports in addition to the currently allowed truck imports
under part 80. Under part 1090, diesel fuel is only subject to per-
gallon standards, so alternative standards to diesel fuel imported
via rail or truck are not necessary.
---------------------------------------------------------------------------
Second, the importer must get documentation of test results from
the supplier for each batch of fuel. Testing for a given batch must
occur after the most recent delivery into the supplier's storage tank
and before transferring product to the railcar or truck.
Third, the importer must conduct testing to verify test results
from each supplier, by collecting samples either once every 30 days or
every 50 rail or truckloads of fuel from a given supplier, whichever is
most frequent.
We received several comments that suggested that our proposal to
allow added flexibility was forcing importers via truck and rail to
comply with more stringent per-gallon standards. This was not our
intent and we have revised the regulations to clarify that importers
that import via truck or rail have the option to sample and test each
batch of imported gasoline and comply with average benzene and sulfur
standards or rely on test results from the gasoline supplier and meet a
per-gallon standard. We address other comments related to imports by
truck and rail in Section 18 of the RTC document.
C. Special Provisions for Importation by Marine Vessel
We are finalizing as proposed the provisions that specifically
address importation of fuels by marine vessels. These provisions are
generally the same as those addressed in the 2003 Q&A document.\97\
Under part 1090, separate certification is 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 not allowing importers who
import by marine vessels to rely on testing from a foreign source given
our lack of jurisdiction generally. 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.
---------------------------------------------------------------------------
\97\ 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.
---------------------------------------------------------------------------
Under these provisions, different ship compartments would generally
be considered different batches of fuel. However, we are allowing for
the following exceptions. First, importers may 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 required for
all composite samples. As is the case under part 80, importers must
demonstrate that results for homogeneity testing fall within the
specified range for the test method used(s) used to determine
homogeneity. Under the updated homogeneity testing procedures in part
1090, this should 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 the decrease in the number of fuel parameters for homogeneity
testing from as many as 11 under part 80 to two under part 1090. This
change would result in a substantial decrease in testing burden.
Second, we will 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 if each individual vessel compartment is shown,
through sampling and testing, to meet all applicable standards.
We received several comments suggesting edits and requesting
clarifications to the part 1090 marine vessel import provisions that we
have reflected in the final regulations as appropriate. We address
these comments in Section 18 of the RTC document.
D. Gasoline Treated as Blendstocks
We are transferring part 80 provisions for gasoline treated as
blendstock (GTAB) to part 1090 largely unchanged. We are also
substantially reducing the number of parameters that are tested and
reported to EPA for GTAB. Our primary concern with GTAB has been to
ensure that off-spec gasoline imported into the U.S. is 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 EPA's fuel
quality standards is based on sampling and testing the finished fuel
and part 1090 no longer requires 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 must continue to be reported. Other provisions related
to GTAB are consistent with current part 80 requirements and published
guidance.
In general, comments were supportive of this proposal. However, we
received some suggestions for clarification of the GTAB provisions that
we have reflected in the final regulations as appropriate. We address
these comments in Section 18 of the RTC document.
XII. Compliance and Enforcement Provisions and Attest Engagements
A. Compliance and Enforcement Provisions
We are finalizing the compliance and enforcement provisions as
proposed with one exception. We are also finalizing lower sulfur and
benzene default values that will apply to sampling and testing
requirements violations for fuel content standards.
As explained in the NPRM, the 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 it difficult for EPA and the public to know if the
fuel meets the applicable standards. Several commenters suggested that
the proposed levels, which were identical to the levels in part 80,
were too high. The commenters suggested that the default values had not
been updated in over 25 years and were not reflective of modern fuel
manufacturing. Several commenters
[[Page 78449]]
suggested default levels that were at or below EPA's regulatorily
specified levels. We believe that it would be inappropriate and
counterproductive to assume that fuels, fuel additives, and regulated
blendstocks met EPA's fuel quality standards if a party failed to
appropriately sample and test for compliance. Such levels would provide
a strong incentive for parties to forgo compliance sampling and testing
altogether, which would jeopardize fuel quality. Other commenters
suggested more modest reductions in the default values, but no
commenter provided compelling data to support alternative default
values.
However, we acknowledge that fuels are made and distributed
differently today than they were when we promulgated the part 80
default values in the 1990s. Therefore, we have chosen to use the
sulfur and benzene levels specified in CAA section 211(k)(10)(B) for
summer (339 ppm sulfur) and winter (1.64 volume percent benzene)
baseline fuel, respectively.\98\ We believe these values represent
fuels prior to the promulgation of current EPA fuel quality standards,
which have controlled sulfur and benzene contents to their current
regulatory levels (10.00 ppm and 0.62 volume percent, respectively).
---------------------------------------------------------------------------
\98\ We choose the summer baseline for sulfur as it was 1 ppm
higher (339 ppm for summer versus 338 ppm for winter) and the winter
baseline for benzene as it was 0.09 volume percent higher (1.64
volume percent for winter versus 1.53 volume percent for summer).
---------------------------------------------------------------------------
The final rule provides that if a fuel, fuel additive or regulated
blendstock manufacturer fails to comply with the sampling and testing
requirements, the gasoline will be deemed to have the parameters in
Table XII.A-1 below, 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.
Table XII.A-1--Default Values for Fuel, Fuel Additive, and Regulated Blendstock Parameters
----------------------------------------------------------------------------------------------------------------
Benzene value
Product Sulfur value (volume RVP value
(ppm) percent) (psi)
----------------------------------------------------------------------------------------------------------------
Gasoline........................................................ 339 1.64 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.................................................. 339 n/a n/a
Regulated Blendstocks........................................... 339 1.64 n/a
----------------------------------------------------------------------------------------------------------------
As mentioned above, the default values approximate uncontrolled
levels prior to promulgation of current EPA fuel quality standards and
create an additional incentive for fuel, fuel additive and regulated
blendstock producers to properly sample and test gasoline and ensure
that they will not benefit by underreporting the sulfur, benzene, or
RVP of gasoline that is not properly sampled or tested. For fuel
manufacturers that produce gasoline using the PCG by subtraction
approach, the default values for sulfur is 0 ppm and the default value
for benzene is 0 volume percent. This approach attributes all sulfur
and benzene to the added blendstock and provides incentives for a
blending manufacturer to appropriately sample and test the PCG.
In addition to the comments received on default values, one
commenter asked for additional detail regarding how to inform EPA about
a failure to comply with the sampling and testing requirements and what
type of information EPA will consider when determining whether to
approve a value that is different than the default values. Regulated
parties should inform EPA of a failure to comply with the sampling and
testing requirements through EPA's eDisclosure portal.\99\
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\99\ See https://www.epa.gov/compliance/epas-edisclosure.
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The determination about whether to approve a request to use an
alternative value will be made on a case-by-case basis. EPA will
consider all relevant information in making this determination,
including but not limited to engineering analyses and results from
tests that do not meet the regulatory standards.
We address comments related to the compliance and enforcement
provisions in more detail in Section 19 of the RTC document.
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 the various existing attest requirements in
part 80 to a single subpart in part 1090 (subpart S). 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 have added a requirement for auditors to review
the fuel manufacturer's calculations showing that they comply with the
sulfur and benzene average standards. We note that EPA's Office of
Inspector General made certain findings and recommendations regarding
compliance with these standards as part of their review of the auditing
requirements under part 80.\100\ One recommendation was to modify the
attest engagement regulations to require that auditors verify
compliance calculations for gasoline manufacturers to help ensure that
the benzene average standard was met. We believe the revised attest
engagement provisions are consistent with this recommendation and will
provide better oversight of the gasoline sulfur and benzene average
standards.
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\100\ 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 codifying the existing attest requirements spelled out
in the 2003 Q&A document.\101\ We are adopting these requirements for
both CG and RFG. The most significant new provision is 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 require a relatively straightforward review by auditors of whether
labs used to test gasoline for
[[Page 78450]]
compliance have records demonstrating that their 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 requiring
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 require that the independent surveyor review this type of
information under the NSTOP.) We do not believe that this simple review
will greatly increase the burden associated with the annual attest
audits. We believe this laboratory record review will help ensure that
labs used for testing fuels for compliance are doing so consistent with
EPA's quality control requirements helping to ensure a level playing
field and program integrity.
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\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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We received several comments that suggested edits to the proposed
regulations and asked for clarification on the various attest
engagement provisions that we have reflected in the final regulations
as appropriate. We address these comments in Section 20 of the RTC
document.
C. RVP Test Enforcement Tolerance
Under part 80, EPA recognizes and allows a 0.3 psi downstream
enforcement test tolerance over applicable RVP standards for RVP test
results.\102\ This test tolerance was based on RVP testing variability
and the reproducibility of the test methods at the time the RVP
standards were established. Under this approach, we rely on test
results from locations downstream of fuel manufacturing facilities to
bring enforcement actions against downstream parties only if the
downstream test results are more than 0.3 psi above 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 gasoline
manufacturer'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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\102\ 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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We are continuing 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 will 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 finalizing 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 requirements are consistent with part 80 independence and
technical competency requirements for independent third-parties. We
believe the requirements will preserve and strengthen the integrity of
our independent third-party verification programs.
We remain concerned 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. Therefore, we are
maintaining 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 clarifying that independence requirements
apply not only for the third parties and their employees, but also for
any contractors and subcontractors.
Similar to part 80, we are imposing restrictions on both employment
history and financial interest. We proposed 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.
We are also finalizing 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 requested 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. We have
adopted some of the suggested changes and have addressed these comments
in Section 4 of the RTC document.
Part 1090 also includes 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.\103\ These provisions
ensure that program oversight is being conducted by parties with the
requisite technical capabilities. However, we do not currently require
this demonstration under part 80 for in-use surveys. Under part 1090,
we are requiring that the independent surveyors 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 are
unchanged in part 1090.
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\103\ See 40 CFR 80.92 and 80.1469.
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Several commenters suggested that the technical qualification
requirements were too restrictive. First, commenters suggested that the
requirement that independent parties could not provide services that
require independence until 3 years after the point when the independent
party was last employed by the regulated party was too long and would
result in a significant constraint on the availability of technically
competent auditors and surveyors. Based on these comments, we reduced
the 3-year period to a 1-year period as commenters suggested. Second,
one commenter suggested that the technical competency requirement for a
lab to qualify non-VCSB methods was too strict and could not be
fulfilled by a single person. We are finalizing these provisions as
proposed since we believe that a laboratory that is going to qualify
[[Page 78451]]
non-VCSB methods must have appropriate personnel to evaluate the new
method. We have addressed these comments in Section 4 of the RTC
document.
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 dispenser labeling
requirements) into one subpart (subpart P) with only minor changes
(including removing several obsolete provisions from part 80). We are
finalizing, as proposed, the description of the E15 label by replacing
descriptive paragraphs with a graphic example of the E15 pump label. We
believe these changes will make the regulations easier to identify and
follow for retailers and WPCs.
We are finalizing minor modifications to the existing label
language for heating oil by removing the now obsolete label language
identifying that the heating oil contains greater than 500 ppm
sulfur.\104\ Most heating oil sold today meets state 15 ppm sulfur
standards, and we believe that it is now 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
allowing retailers to continue to use existing labels to satisfy the
part 1090 labeling requirements until such time as the existing part 80
label needs replacement.
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\104\ See 40 CFR 80.573.
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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. However, if there were situations
where ECA marine fuel is co-dispensed with other fuels, a label might
still help avoid the misfueling of diesel engines that require the use
of ULSD with ECA marine fuel. We proposed to maintain the existing part
80 label requirement but requested 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 received no comments on this question, so we are maintaining the ECA
marine fuel labels that are currently required under part 80.
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 updated nozzle requirements for refueling motor vehicles are
aligned with the requirements adopted under part 80. There is one
noteworthy adjustment. We 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 updated specifications,
including rounding, are 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 do not need to be modified.
Similar nozzle requirements apply for dispensing gasoline into
marine vessels. We are similarly adopting a singular set of nozzle-
geometry specifications in millimeters in a way that is aligned with
the specifications as originally adopted. We are also concluding 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 now require that
they be replaced with a nozzle that meets the standardized
configuration. This requirement applies January 1, 2021, when part 1090
becomes effective.
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 proposed 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. However, based on a comment received, we are deferring action
on this item. As we are not taking any final action on that provision
in this action, the regulations at 40 CFR 80.24 remain unchanged. We
intend to revisit this issue in a future rulemaking related to vehicle
standards.
D. Previously Certified Gasoline (PCG)
We are largely maintaining the existing part 80 provisions for how
blending manufacturers may make new batches of gasoline from PCG and
blendstocks.\105\ In the Tier 3 rule, we finalized changes to improve
the consistency of the PCG provisions across part 80 programs; \106\
however, we maintained separate PCG provisions for each part 80
gasoline program. In part 1090 we are consolidating these provisions
into a single set of PCG provisions that maintain both options used in
part 80: (1) PCG by subtraction; and (2) PCG by addition.\107\ Other
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.
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\105\ The purpose of allowing parties to make new batches of
gasoline using PCG is to provide flexibility for parties making new
fuels to accommodate market demands while ensuring that the fuel
quality standards are met. The provisions are designed to ensure
that the new batch meets gasoline per-gallon standards and that the
blending manufacturer does not increase the average sulfur and
benzene levels in the national gasoline pool.
\106\ See 79 FR 23575-23576 (April 28, 2014).
\107\ 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 will need to sample and test for sulfur year-round and
for RVP in the summer.
---------------------------------------------------------------------------
We received several comments related mostly to how to address
various scenarios where blendstocks are added into PCG that has been
identified for oxygenate blending by the original PCG manufacturer. For
example, commenters requested clarification on whether a party that
adds blendstock to PCG must account for the fact that the PCG was
intended to have oxygenate added to it. In response to these comments,
we are modifying the PCG provisions to ensure that oxygenate is
accounted for properly.
Several commenters also suggested edits and clarifications to the
part 1090 regulations and have made edits to the regulations where
appropriate to address these comments. We address these comments in
Section 21 of the RTC document.
[[Page 78452]]
E. Transmix and Pipeline Interface Provisions
With few exceptions, we are finalizing the proposed requirements
under part 1090 for transmix processors that largely mirror what we
require under part 80. In part 1090 we are consolidating and
simplifying the flexibilities provided to fuel manufacturers that use
transmix to produce gasoline and diesel fuel, and are aligning the
requirements applicable to these parties to the requirements applicable
to other fuel manufacturers under part 1090.\108\ 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 [specified] sampling and testing
requirements and standards instead of the sampling and testing
requirements and standards otherwise applicable to a refiner under this
subpart O.'' \109\ 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.
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\108\ Refiners that produce gasoline and diesel fuel by
processing crude oil must not use the provisions that apply to
transmix processors and are subject to all requirements that apply
to a fuel manufacturer.
\109\ See 40 CFR 80.1607.
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1. Clarifying and Consolidating Requirements Relating to Transmix and
Pipeline Interface
Provisions related to the treatment of transmix are currently
located in various sections in part 80.\110\ To improve clarity, we
have consolidated most of the special provisions related to the
treatment of transmix into a single subpart in part 1090 (subpart F).
We also incorporated 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.\111\
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\110\ See 40 CFR 80.84, 80.213, 80.513, 80.840, and 80.1607.
\111\ See 40 CFR 80.84.
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2. Blending Transmix Into Previously Certified Gasoline
In part 1090 we made a minor change to the requirements that apply
to parties that blend transmix into PCG.\112\ 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 were temporarily required
under part 80 to conduct more frequent sampling and testing. We changed
this requirement so that no more than one sample per day may be used to
demonstrate compliance with this increased testing requirement. This
change in part 1090 will ensure that the required increase in sampling
and testing frequency fulfills the intended purpose of verifying that
the issue(s) that caused the violation have been resolved.
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\112\ 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
As proposed, we are consolidating the different RFG and CG
provisions that apply to transmix processors into one set of provisions
that largely mirrors the part 80 transmix provisions. Transmix gasoline
product, or TGP, is the gasoline blendstock that is produced when
transmix is separated into blendstocks at a transmix processing
facility. The part 1090 regulations require transmix processors and
blending manufacturers that produce gasoline with TGP to exclude the
volume of TGP and PCG used to produce gasoline from their annual
compliance calculations for the sulfur and benzene average standards.
Parties that produce gasoline with TGP and other blendstocks must
follow the PCG procedures to account for the sulfur and benzene levels
of the added blendstocks for demonstrating compliance with annual
average sulfur and benzene standards. Transmix processors and blending
manufacturers that only produce gasoline from TGP or TGP and PCG are
deemed to be in compliance with the sulfur and benzene average
standards. In all cases, fuel manufacturers that produce gasoline using
TGP must 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. If transmix
processors can demonstrate that the transmix and any blendstock they
use to produce gasoline contain no oxygenate, they are not be required
to test the gasoline they produce for oxygenate content.
Based on suggestions from commenters, we are also finalizing
provisions that will allow for TGP to be transferred from a transmix
processor to another fuel manufacturer to be used to produce gasoline.
The transmix processor will use a PTD that designates the product as
TGP and note that it is not suitable for use as gasoline. In such cases
where TGP is blended to produce gasoline, the TGP is treated as PCG
(i.e., the blending manufacturer must take steps to ensure that the
sulfur and benzene content from the TGP is excluded from their average
standard compliance demonstrations).
4. 500 ppm LM Diesel Fuel Produced From Transmix
We are finalizing as proposed the 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, with one exception. One commenter pointed out
that since part 1090 requires all volume measurements to be temperature
adjusted, thermal expansion should not result in differences between
the volume of 500 ppm LM diesel fuel received versus the volume
delivered and used on a compliance period basis. We agree with this
comment and removed this as an allowable justification for volume
differences.
5. Streamlining the Requirements for Pipeline Interface That Is Not
Transmix
We are finalizing the regulatory provisions that allow pipeline
operators to 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 than were imposed under part
80. During the winter months there are no restrictions relating to how
operators cut pipeline gasoline interface. 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, pipeline operators may
not cut pipeline interface from a batch of RFG shipped adjacent to a
batch of CG into the batch of RFG.
F. Gasoline Deposit Control
1. Overview
We are finalizing streamlined and updated regulations for gasoline
deposit control. 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
[[Page 78453]]
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.\113\ 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.\114\
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\113\ See 61 FR 35310 (July 5, 1996).
\114\ Under part 80, this period can be up to 30 days. Part 1090
does not change this period.
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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.\115\ 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 provided by the
detergent program today.
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\115\ 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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At the same time, there is considerable cost and effort associated
with continuing to implement the detergent program. Consequently, we
are streamlining the program to the extent possible to minimize its
cost. Specifically, we are: (1) Eliminating the requirement that a
detergent that is demonstrated to control intake valve deposits must
also be tested to demonstrate the ability to control fuel injector
deposits; (2) easing the adoption of updated deposit control test
procedures when they become available; (3) simplifying the process for
registration and certification of detergents and the demonstration of
compliance by detergent blenders; (4) removing expired and unused
provisions; and (5) removing the requirement that the gasoline portion
of E85 must contain a certified detergent. In response to several
comments, we are finalizing testing requirements for new detergents
consistent with part 80 requirements that will maintain the
specifications for detergents, while updating them to accommodate new
circumstances discussed in this section. The following sections detail
the changes we are finalizing.
2. Eliminating the Port Fuel Injector Deposit Control Testing
Requirement
We are finalizing our proposal to eliminate the requirement that
detergents be tested to demonstrate the ability to control port fuel
injector deposits. We received several comments in support of this
proposal. This change will substantially decrease the burden of
introducing new detergents while maintaining the benefits of the
detergent program.
Under part 80, we required 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 and from comments supports the conclusion that
detergents that are capable of controlling intake valve deposits are
inherently capable of controlling port fuel injector deposits.\116\
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 used a 1985-1987 Chrysler 2.2L
vehicle.\117\ The fuel injector technology used in these old 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 (discussed in
the next section) and the evaluation of deposit control in gasoline
direct injection engines that represent an increasing share of the new
vehicle fleet.
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\116\ 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.
\117\ 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.
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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 antiquated and of questionable
relevance to the in-use fleet today. New detergents under part 80 are
tested using the EPA ASTM D5500 BMW-based deposit control test
procedure (``EPA ASTM D5500 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 35-year-old vehicle is no longer representative of the
technology used in modern vehicles.\118\ 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.\119\
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\118\ CRC Gasoline Engine Deposit Task Group, CRC Project No.
CM-136, CRC Annual Report, September 2018.
\119\ Id.
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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.\120\ 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
market shifts. 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. 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
[[Page 78454]]
finished gasoline.\121\ 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.\122\
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\120\ 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.
\121\ See 65 FR 6698 (February 10, 2000) and 82 FR 23414 (April
28, 2014).
\122\ The approved sulfur doping compound is di-tertiary di-
butyl sulfide.
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Consequently, we proposed to disallow new detergents that had
established a lowest additive concentration (LAC) through the EPA ASTM
D5500 procedure. We proposed that new detergent deposit control testing
could be conducted using the Top Tier program or California's deposit
control program.\123\ We also proposed that existing detergent
certifications based on the EPA ASTM D5500 procedure would remain valid
indefinitely while new testing procedures could be adopted with EPA-
approval.
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\123\ See Title 13, California Code of Regulations, Section
2257.
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Several commenters suggested that the proposal to disallow new
additives tested on the EPA ASTM D5500 procedure would constitute a de
facto change in the stringency of the part 80 deposit control
standards, which would result in a substantial increase in costs to
industry. While we believe that the commenters may have overstated the
expected costs, especially considering that we proposed that previously
tested detergents under EPA ASTM D5500 would remain valid indefinitely,
we agree that the removal of the option to test new detergents using
the EPA ASTM D5500 procedure could result in a slight increase in the
stringency and cost for new deposit control formulations. As such, we
will continue to allow the EPA ASTM D5500 procedure to be used to
certify new detergent formulations.
4. Expanding the Applicability of Detergent Certifications Based on
Compliance With the California Deposit Control Regulations
Under the part 80 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 if 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 gasoline that does not meet
California requirements. When EPA's detergent program was finalized in
1996, the composition of gasoline that complies with California
standards differed substantially from gasoline that met EPA's
requirements.\124\ 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 EPA's program allows the accumulation of up to 100 mg per valve
using the EPA ASTM D5500 procedure. Consequently, we proposed that a
detergent certified under California's program could be used to meet
EPA's deposit control requirements in all gasoline. Comments received
were supportive, as long as we continued to allow for new detergent
testing to be done on the EPA ASTM D5500 procedure. As such, we are
finalizing the proposal to allow California detergent testing to be
used to satisfy EPA detergent testing requirements.
---------------------------------------------------------------------------
\124\ See 61 FR 35326-27 (July 5, 1996).
---------------------------------------------------------------------------
5. Easing the Adoption of Future Updates To Deposit Control Test
Procedures
We are finalizing provisions that allow for an administrative
process to approve new deposit control test protocols in a streamlined
manner. In the proposal, we co-proposed 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.
We are finalizing the primary approach, which allows for deposit
control test procedures accepted by EPA to be specified in a publicly
available document that could be updated as EPA accepts new
procedures.\125\ The use of this streamlined process will 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 administrative process.
---------------------------------------------------------------------------
\125\ It is worth noting that the test protocols will be
compared to a baseline established by the EPA ASTM D5500 procedure
using the part 80 test fuels. This baseline was adopted since that
was the baseline for determining the deposit control specifications
under CAA section 211(l).
---------------------------------------------------------------------------
Under this approach, stakeholders may 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 will 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 meets applicable regulatory requirements, we will
publish on our web page and by direct communications with stakeholders
that we have accepted the change. We may also periodically update the
detergent regulations in the CFR to reflect accepted alternatives.
Comments received were supportive of EPA providing added
flexibility to approve new detergent testing protocols via an
administrative process. Therefore, we are finalizing the primary
approach as proposed.
6. Removing Expired and Unused Provisions
We are finalizing the removal of expired and unused provisions in
the detergent program to make the detergent regulations more
accessible, understandable, and to eliminate the ongoing costs of
maintaining these provisions.
The detergent program in part 80 includes provisions allowing a
detergent to be certified for use in different gasoline pools using
test fuels that have specifications representative of the deposit-
forming characteristics of the 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.\126\ We also
accept detergent certifications under the California program in lieu of
meeting our requirements. Since all applications for
[[Page 78455]]
detergent certification to date other than those based on the
California program have been under the national-generic option we are
removing the other options. 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
will 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 will also remain valid.\127\
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\126\ See 40 CFR 80.163.
\127\ See Section XIII.F.4 regarding the expansion to the
applicability of California-based detergent certifications.
---------------------------------------------------------------------------
We are also removing regulatory provisions associated with the
interim detergent program that were superseded by the detergent program
in 1996.\128\ Comments received on this aspect of the proposal were
supportive, and we are therefore finalizing the removal of expired and
unused provisions as proposed.
---------------------------------------------------------------------------
\128\ See 40 CFR 80.141 through 80.156.
---------------------------------------------------------------------------
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 EPA's deposit control requirements. To speed
up the introduction of new detergents and to reduce the burden of
detergent certification, we are allowing detergent manufacturers to
begin marketing a detergent once the manufacturer has satisfied EPA
testing requirements without the need for a prior submission of the
data to EPA and approval by EPA. Under this approach, detergent
manufacturers will still 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 part 79. Additional composition
information is also required for detergents to be evaluated for deposit
control efficacy under part 80, including the LAC established by
detergent deposit control testing. In lieu of requiring a separate
submission of this additional information under part 1090, we are
requiring it to be submitted with a detergent's part 79 additive
registration. Comments on this aspect of the proposal were supportive
and we are finalizing the provisions as proposed.
8. Simplifying the Detergent Volumetric Accounting Reconciliation
Requirements
Under parts 80, 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; this is not changing
under part 1090. However, under part 80, the VAR provisions require
that detergent blenders compile a separate record for each monthly VAR
period in a standard format. During the rule development process,
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 represented a significant burden. To reduce the burden, we
proposed to remove the requirement that a VAR report be prepared for
each accounting period. This 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. We also proposed 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. All comments received on the proposal to
simplify VAR requirements were supportive, and we are finalizing these
provisions as proposed.
9. Removing the Requirement That the Gasoline Portion of E85 Contain
Detergent
We are finalizing an exemption to the deposit control requirement
for the gasoline portion of E85. The part 80 deposit control
regulations require that the gasoline portion of E85 must contain a
detergent additive at or above the LAC.\129\ 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.\130\
---------------------------------------------------------------------------
\129\ See 40 CFR 80.161(a)(3).
\130\ See 81 FR 80828 (November 16, 2016).
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In the REGS rule, we noted that we were 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
instead contribute to deposit formation. We also noted that certain
detergents may not be 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.
In the NPRM, we explained that this action is allowable because 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.\131\ All
comments received on this aspect of the proposal were supportive and we
are finalizing these provisions as proposed.
---------------------------------------------------------------------------
\131\ See 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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G. In-Line Blending Waivers
Under part 1090, we will continue the policy of approving in-line
blending waivers. These waivers allow refiners 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 that we have
consolidated into a single set of requirements for in-line blending in
part 1090. For RFG manufacturers, the in-line blending requirements
remain largely unchanged except that RFG manufacturers' in-line
blending waivers need not cover parameters no longer required for
certifying batches of gasoline (discussed in more detail in Section
V.A.2). RFG manufacturers will 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 manufacturers, we will allow in-line
blending waivers to cover all regulated gasoline parameters instead of
just sulfur. CG refiners will also have to undergo the same annual
audit procedure that currently exists for RFG refiners under part 80.
The flexibility to cover additional parameters for CG refiners through
the in-line blending waiver should far exceed any costs associated with
the additional audit.
[[Page 78456]]
Due to the substantial changes in part 1090 to the requirements for
in-line blending waivers, we are requiring all gasoline manufacturers
with existing in-line blending waivers to resubmit their in-line
blending waiver requests. This will help to ensure that in-line
blending waivers appropriately cover the new requirements. Gasoline
manufacturers must have EPA-approved updated waiver requests by January
1, 2022. This allows time for refiners to prepare new submissions and
for EPA to review and approve those submissions. Note that diesel fuel
manufacturers with an existing in-line blending waiver do not need to
submit new requests for diesel fuel under part 1090 and may continue to
operate under their part 80 in-line blending waiver.
Several commenters expressed concern regarding in-line blending
waivers for locations that are blending into tanks. We did not intend
to disallow in-line blending into tankage and the part 1090 regulations
have been updated to address this concern. We further address these
comments in Section 21 of the RTC document.
H. Confidential Business Information
We are finalizing regulations that will 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. The regulations
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.'' \132\ 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.\133\
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\132\ 5 U.S.C. 552(b)(4).
\133\ 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 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.'' \134\ The Court identified two conditions
``that might be required for information communicated to another to be
considered confidential.'' \135\ 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.
---------------------------------------------------------------------------
\134\ Argus Leader, 139 S. Ct. at 2366.
\135\ 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.\136\ 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.\137\
---------------------------------------------------------------------------
\136\ ``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.
\137\ 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. In particular, this decision
applies to requests under the following processes: R&D testing
exemptions under 40 CFR 1090.610, hardship exemptions under 40 CFR
1090.635, alternative quality assurance programs under 40 CFR 1090.500,
alternative PTD language under 40 CFR 1090.1125, 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 improve processing of information requests and increase
transparency related to EPA determinations, we are clarifying 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. 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.\138\ For information submitted under part 1090
claimed as confidential that is outside the categories described above,
and not specified in the regulations at 40 CFR 1090.15(b) or (c), EPA
will evaluate such confidentiality claims in accordance with Argus
Leader and our regulations at 40 CFR part 2, subpart B.
---------------------------------------------------------------------------
\138\ We note that this list does not convey the entire scope of
information that we may release. Other information that does not
meet the legal requirements for confidential treatment can also be
released despite not being listed here.
---------------------------------------------------------------------------
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. Given the fungible
fuel supply, and the resulting impacts of fuel quality specifications
on emissions and emissions control systems when fuels are used in
vehicles and engines, the regulations we are
[[Page 78457]]
finalizing in this action will better inform the public about
exemptions to EPA's fuel quality regulations under part 1090 and will
allow for the timely release of basic information relating to the
requests. In particular, exemptions granted under part 1090 could
result in higher levels of sulfur, benzene, or RVP in fuel, as well as
changes in other fuel properties, which can have direct impacts on
human health and the environment or on the functioning of vehicles,
engines, and their emissions control systems. 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.
We received comments suggesting that our treatment of this basic
information should be maintained as CBI if so claimed by submitters.
Commenters suggested that refineries would have to choose between
regulatory relief and release of information that may harm the
refinery's reputation or finances. Commenters also suggested that the
regulatory relief was specifically promulgated to help entities, and
that disclosing information about the refinery would instead result in
harm. We find that establishing the potential release of this basic
information through regulation appropriately balances the interest in
transparency for the public and the protection of information that
could harm a refinery's reputation or finances. As noted above,
providing the public with information about exemptions and
flexibilities will maintain confidence in EPA's regulatory programs
assuring fuel quality and expedite the process for the release of this
information. It will also better inform the public about the use of
these exemptions and flexibilities given the wide use of fuel and its
impacts on air quality and engines and equipment. We note that post-
Argus Leader substantial competitive harm is no longer the standard for
evaluating whether information is confidential within the meaning of
Exemption 4, and we are prospectively, via rulemaking, providing that
we will not provide this specific information with confidential
treatment. Additionally, we disagree with commenters that the
disclosure of this information would necessarily result in harm. For
many of the flexibilities mentioned above, the mere fact of a request
is not often claimed as CBI (e.g., alternative labels or PTD language),
and commenters have provided no explanation as to why the disclosure of
the fact of a request for these non-hardship regulatory flexibilities
and EPA's response could result in harm. For extreme, unusual, and
unforeseen hardship exemptions, as discussed in Section VI.A, the
conditions under which a refinery can request extreme, unusual, and
unforeseen hardship relief going forward are limited (e.g., for natural
disasters or refinery fires), and would very likely be known to the
public such that the release of the fact of a request and EPA's
decision would not result in reputational or financial harm to the
refinery. Additionally, the public interest in the release of
information relating to fuel quality is high, particularly when, as
discussed above, increases in sulfur, benzene, and RVP, or changes in
other fuel properties, have direct impacts on human health, the
environment, and the functioning of vehicles, engines, and their
emissions control systems. Commenters suggested, without any further
explanation as to why, that the mere fact of a petition for relief
would have ``tremendously negative effects on the submitter's
competitive petition'' and that ``[c]ompetitors could seize upon the
company's identified vulnerabilities to gain a competitive advantage
through any number of methods.'' \139\ In addition to failing to
clearly articulate why or how the release of the fact of a petition
would result in harm, commenters have not articulated why the basis for
relief would not already be known in light of the remaining
justifications available for hardship relief under part 1090 (i.e.,
extreme, unusual and unforeseen hardship relief).
---------------------------------------------------------------------------
\139\ Comments from Small Refineries Coalition, Docket Item No.
EPA-HQ-OAR-0227-0080.
---------------------------------------------------------------------------
Commenters suggested that this action contradicts Congress's intent
in providing provisions for hardship relief and that Congress must
amend the CAA to allow for the release of this information. However,
the opportunities for regulatory relief under part 1090 are not
statutorily prescribed, nor is the confidential nature of the fact of a
petition for relief or EPA's decision on it provided in the CAA.
Commenters pointed to no CAA text that would suggest otherwise.
Commenters suggested that EPA has treated requests for regulatory
relief as confidential for many years. While EPA has treated some
requests as confidential, particularly some small refinery hardship
exemptions under the RFS program,\140\ historically EPA has also
disclosed other types of hardship exemption decisions and names of
parties who have received exemptions and other regulatory
flexibilities.\141\ Regardless of our past treatment of submissions,
future submissions under part 1090 will be subject to the provisions
laid out in this rulemaking, and will result in the potential
disclosure of the information described above.
---------------------------------------------------------------------------
\140\ See, e.g., https://www.epa.gov/fuels-registration-reporting-and-compliance-help/rfs-small-refinery-exemptions, which
provides only aggregated information.
\141\ See, e.g., press release regarding hardship exemptions
from the sulfur standards, available at: https://archive.epa.gov/epapages/newsroom_archive/newsreleases/d07550f8d366e3c485256b1300637472.html.
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As stated above, EPA will continue to evaluate other information
submitted to EPA and claimed as CBI and not articulated in 40 CFR
1090.15(b) and (c) in accordance with Argus Leader and our regulations
at 40 CFR part 2, subpart B.
XIV. Costs and Benefits
A. Overview
In general, we expect that this action will reduce the cost of fuel
distribution by improving fuel fungibility, reducing the costs for
regulated parties to comply with our fuel quality regulations, and
reducing the costs for EPA to implement these regulations. We do not
expect a measurable effect on regulated emissions or air quality as
this rule does not change the stringency of EPA's fuel quality
standards. This section lays out the general areas of potential cost
savings for producing fuels that we believe will result from this
action.\142\
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\142\ We outline in more detail these areas for savings in the
technical memorandum, ``Economic Analysis: Fuels Regulatory
Streamlining Final Rule,'' available in the docket for this action.
---------------------------------------------------------------------------
B. Reduced Fuel Costs to Consumers From Improved Fuel Fungibility
A number of the provisions being finalized in part 1090 are
expected to improve fuel fungibility. This should result in decreased
costs associated with the distribution and sale of such fuels. Some
examples of ways that this should result in potential cost savings are
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, we are
unable to quantify these
[[Page 78458]]
types of costs savings. In the proposal, we sought comment on these
potential areas of savings and information that might enable
quantification. While commenters generally supported the provisions
that allowed for improved fungibility, we did not receive any comments
that provided any additional information or analysis to support the
quantification of benefits from improved fungibility. Therefore, we
have not quantified the savings from the improved fungibility of fuels
as a result of this action.
C. Costs and Benefits for Regulated Parties
We anticipate that the streamlined fuels provisions in part 1090
will significantly reduce the administrative burden for regulated
parties to comply with EPA's fuel quality standards. The opportunities
to reduce such administrative burden have been discussed throughout
this action. Some examples of areas where savings will 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 (discussed in Section X.A).
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.\143\ As part of
this action, we are replacing the multiple existing ICRs for part 80
into a single ICR for all fuel quality programs that are now 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 new ICR. This results in a burden reduction of about $10.7 million
per year. Furthermore, there are additional areas of potential
administrative savings for industry that may not be captured in
ICRs.\144\ We estimate these savings to be about $29.7 million per
year. Including the $10.7 million cost reductions estimated under the
ICR, the total estimated savings in administrative costs to industry is
$40.4 million per year. Table XIV.C-1 outlines the categories
identified for savings.\145\
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\143\ The supporting statement for the ICR and other supporting
materials are available in the docket for this action.
\144\ These savings are discussed in the technical memorandum,
``Economic Analysis: Fuels Regulatory Streamlining Final Rule,''
available in the docket for this action.
\145\ Id.
Table XIV.C-1--Estimated Annual Cost Savings by Savings Category \a\
------------------------------------------------------------------------
Savings (in
Savings category 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................................. 15.2
Information Collection Request............................. 10.7
------------
Total Savings............................................ 40.4
------------------------------------------------------------------------
\a\ 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 will be
less time and effort for staff to understand and be trained on EPA's
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 making changes to the
stringency of the fuel quality standards, we do not expect fuel
manufacturers to have to alter their production processes in order to
comply with part 1090. In prior fuels rulemakings, retooling crude oil
refineries often serves as the most significant costs associated with
changes in fuel quality standards. Similarly, other parties in the fuel
distribution system are not 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
small one-time costs associated with updating recordkeeping and
reporting systems and practices associated with the modified
regulations. For example, parties will 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.\146\
---------------------------------------------------------------------------
\146\ The ICR supporting statement is available in the docket
for this action.
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Overall, we expect the savings from increased fungibility of fuels,
the decrease in administrative costs, and other indirect cost savings
resulting from the modified regulations to far exceed any one-time
administrative costs needed to begin compliance with part 1090. These
cost savings are expected to be passed along to consumers in the form
of lower fuel prices, given the highly competitive fuels
marketplace.\147\ 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.\148\
---------------------------------------------------------------------------
\147\ We discuss many of these areas, including a much more
detailed analysis of the cost savings, in the technical memorandum,
``Economic Analysis: Fuels Regulatory Streamlining Final Rule,'' and
the ICR supporting statement, available in the docket for this
action.
\148\ These results are discussed in more detail in the
technical memorandum, ``Economic Analysis: Fuels Regulatory
Streamlining Final Rule,'' available in the docket for this action.
Table XIV.C-2--Estimated Net Present Value Cost Savings \a\
------------------------------------------------------------------------
Seven percent
Three percent discount rate (in millions) discount rate (in
millions)
------------------------------------------------------------------------
$715.............................................. $479
------------------------------------------------------------------------
\a\ Cost savings in 2019 dollars.
D. Environmental Impacts
Since we are not making 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 this action, there are certain areas where changes to
compliance requirements could be viewed as marginally affecting in-use
fuel quality.\149\ These marginal changes could then have a ripple
effect on regulated emissions. In general, such changes are very small,
typically well below the levels that we have historically attempted to
quantify in rulemakings where we establish fuel quality 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
[[Page 78459]]
the overall air quality effects that will result from this action.
---------------------------------------------------------------------------
\149\ In the NPRM we identified those areas that had the
potential to have an effect on in-use fuel quality. These areas
included whether the proposed RFG maximum RVP per-gallon standard of
7.4 psi was too high, whether allowing CG manufacturers the ability
to account for oxygenate added downstream would slightly increase
average in-use sulfur and benzene levels, and whether making
compliance with EPA fuel requirements less burdensome would result
in a number of new, less sophisticated fuel manufacturers that would
be less likely to comply with EPA fuel quality standards. We also
noted that the improved oversight, especially through third-party
surveys, may improve the quality of fuel sold at retail and that by
simplifying and modernizing our reporting requirements information
would be more readily available to better enable the fuel quality
oversight.
---------------------------------------------------------------------------
We sought comment on the potential effect of this action on fuel
quality and we did not receive any adverse comments on potential fuel
quality issues. We believe the streamlining of the fuel quality
programs will 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 improved oversight
mechanisms will allow us to better oversee compliance with the current
fuel standards and take appropriate action when issues are identified.
The net result of this may 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 http://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 Final Rule,'' is available in
the docket.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is considered an Executive Order 13771 deregulatory
action. Details on the estimated cost savings of this final rule can be
found in EPA's analysis of the potential costs and benefits associated
with this action. This analysis, ``Economic Analysis: Fuels Regulatory
Streamlining Final Rule,'' is available in the docket.
C. Paperwork Reduction Act (PRA)
The information collection activities in this 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
2607.02. You can find a copy of the ICR in the docket for this rule,
and it is briefly summarized here. The information collection
requirements are not enforceable until OMB approves them.
The information collection activities include 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 case 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 fuel dispenser labels.
The information collection for part 1090 will not result in
duplication of requirements under existing part 80, as this action will
replace nearly all non-RFS provisions under part 80. Part 1090
represents a change from part 80 that will significantly reduce many
recordkeeping and reporting burdens associated with complying with
EPA's fuel quality standards, including:
A reduction in the number of unique fuels compliance
reporting forms from 30 to six;
A change in the frequency of batch reporting from
quarterly to annual;
A reduction in the parameters or properties required to be
tested and reported, from 13 to four;
Improvements to forms and procedures to make them more
intuitive and remove duplication; and
A consolidation and updating of PTD and attest engagement
requirements.
Most respondents are already registered under part 80 and will not
have to re-register under part 1090. The exact information collection
requirements in this final rule are tied directly 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
registration, reporting, sampling, testing, recordkeeping, survey, and
attest engagement responsibilities; whereas, a party who owns a retail
station has limited information collection requirements involving the
retention of customary business records (e.g., PTDs) or affixing
labels.
This information collection will result in the replacement of the
following existing and approved information collections under part 80:
2060-0178 (Reid Vapor Pressure), 2060-0275 (Detergent Additives), 2060-
0277 (Reformulated Gasoline and Anti-Dumping), 2060-0308 (Diesel
Sulfur), 2060-0692 (Performance-Based Test Methods), 2060-0675 (E15),
and 2060-0437 (``Tier 3'') Gasoline Sulfur. These collections currently
total $64,375,590. This collection totals $53,704,290, which represents
a cost savings of $10,671,300.
Respondents/affected entities: The respondents to this information
collection are parties involved in the 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 40 CFR part
1090.
Estimated number of respondents: 134,668.
Frequency of response: Annual, quarterly, and occasionally.
Total estimated burden: 608,992 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $53,704,290 (per year), of which $36,787,434
represents capital/overhead and maintenance cost ($5,744,016) and
purchased services ($31,043,418). The estimated labor costs are
$19,722,363.
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. When OMB approves
this ICR, EPA will announce that approval in the Federal Register and
publish a technical amendment to 40 CFR part 9 to display the OMB
control number for the approved information collection activities
contained in this 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 consolidates EPA's existing
fuel quality regulations into the new 40 CFR part 1090, and the
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 changes.
[[Page 78460]]
To the contrary, we have quantified overall cost savings from this
action.\150\ Even in those areas where we are imposing provisions with
new costs for some entities, they are either offset by other larger
cost savings or far below having any significant economic impact on a
substantial number of small entities. We have therefore concluded that
this action will have no net regulatory burden for all directly
regulated small entities.
---------------------------------------------------------------------------
\150\ See Section XIV.C.
---------------------------------------------------------------------------
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. EPA believes,
however, that this rule may be of significant interest to state and
local governments. To the extent that states have adopted fuel
regulations based on EPA's regulatory provisions that we are changing,
they may need to make corresponding changes to their regulations to
maintain their effectiveness. Consistent with the EPA's policy to
promote communications between EPA and state and local governments, EPA
consulted with representatives of various state and local governments
early in the process of developing this rule to permit them to have
meaningful and timely input into its development. 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).
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 action 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 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 consolidates 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 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 action involves technical standards. EPA is updating 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, EPA is
incorporating by reference the use of test methods and standards from
American Institute of Certified Public Accountants, American Society
for Testing and Materials International (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.
EPA continues to reference the following standards, previously
approved for incorporation by reference, without change in part 1065:
ASTM D86-12, D93-13, D445-12, D613-13, D4052-11, D5186-03 (R2009).
This rulemaking involves environmental monitoring or measurement.
Consistent with EPA's Performance Based Measurement System (PBMS), for
those fuel parameters that fall under PBMS (e.g., sulfur, benzene, Reid
Vapor Pressure, and oxygenate content), EPA has decided not to require
the use of specific, prescribed analytic methods. Rather, EPA will
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. EPA is
not precluding the use of any method, whether it constitutes a
voluntary consensus standard or not, as long as it meets the
performance criteria specified. EPA will also allow 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.
[[Page 78461]]
Table XV.J-1--Standards and Test Methods To Be Incorporated by Reference
------------------------------------------------------------------------
Organization and standard or test
method Description
------------------------------------------------------------------------
American Institute of Certified Public Document describes principles
Accountants--AICPA Code of to establish a code of
Professional Conduct, updated through professional conduct for
June 2020. external auditors.
American Institute of Certified Public Document describes an external
Accountants--Statements on Quality auditor's CPA firm's
Control Standards (SQCS) No. 8, QC responsibilities for its
Section 10: A Firm's System of Quality system of quality control for
Control, current as of July 1, 2019. its accounting and auditing
practices.
American Institute of Certified Public Document describes standard
Accountants--Statement on Standards practices for external
for Attestation Engagements No. 18, auditors to perform
Attestation Standards: Clarification attestation engagements using
and Recodification, Issued April 2016. agreed-upon procedures.
ASTM D86-20a, 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 July 1, 2020. 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 D975-20a, Standard Specification Specification describes the
for Diesel Fuel, approved June 1, 2020. characteristic values for
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 D3606-20e1, Standard Test Method Test method describes how to
for Determination of Benzene and measure the benzene content of
Toluene in Spark Ignition Fuels by Gas gasoline and similar fuels.
Chromatography, approved July 1, 2020.
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.
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 D4806-20, 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 May 1, 2020. denatured fuel ethanol for
blending with gasoline.
ASTM D4814-20a, Standard Specification Specification describes the
for Automotive Spark-Ignition Engine characteristic values for
Fuel, approved April 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 D5186-20, 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 July 1, 2020.
ASTM D5191-20, Standard Test Method for Test method describes how to
Vapor Pressure of Petroleum Products determine the vapor pressure
and Liquid Fuels (Mini Method), of gasoline and other
approved May 1, 2020. 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.
[[Page 78462]]
ASTM D5500-20a, Standard Test Method Test method describes a vehicle
for Vehicle Evaluation of Unleaded test procedure to evaluate
Automotive Spark-Ignition Engine Fuel intake valve deposit formation
for Intake Deposit Formation, approved of gasoline.
June 1, 2020.
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 D5769-20, 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 June 1, 2020.
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 D6299-20, 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 May 1, 2020. ensuring reliable
measurements.
ASTM D6550-20, 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 July 1, 2020.
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 D6729-14, Standard Test Method for Test method describes how to
Determination of Individual Components determine the benzene content
in Spark Ignition Engine Fuels by 100 of butane and pentane.
Metre Capillary High Resolution Gas
Chromatography, approved October 1,
2014.
ASTM D6730-19, Standard Test Method for Test method describes how to
Determination of Individual Components determine the benzene content
in Spark Ignition Engine Fuels by 100- of butane and pentane.
Metre Capillary (with Precolumn) High-
Resolution Gas Chromatography,
approved July 1, 2019.
ASTM D6751-20, Standard Specification Document establishes
for Biodiesel Fuel Blend Stock (B100) specifications for neat
for Middle Distillate Fuels, approved biodiesel to be blended into
January 1, 2020. diesel fuel.
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 (Reapproved 2020), Test method describes how to
Standard Test Method for Sulfur in measure sulfur in gasoline and
Gasoline, Diesel Fuel, Jet Fuel, other petroleum products.
Kerosine, Biodiesel, Biodiesel Blends,
and Gasoline-Ethanol Blends by
Monochromatic Wavelength Dispersive X-
ray Fluorescence Spectrometry,
approved May 1, 2020.
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.
ASTM D7777-13 (Reapproved 2018)e1, 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,
Liquid Petroleum by Portable Digital expressed in terms of API
Density Meter, approved October 1, gravity.
2018.
CARB Test Method, 13 CA ADC Sec. Test method describes a vehicle
2257; California Code of Regulations test procedure to evaluate
Title 13. Motor Vehicles, Division 3. intake valve deposit formation
Air Resources Board, Chapter 5. of gasoline.
Standards for Motor Vehicle Fuels,
Article 1. Standards for Gasoline,
Subarticle 1. Gasoline Standards that
Became Applicable Before 1996, Sec.
2257. Required Additives in Gasoline;
amendment filed May 17, 1999.
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.
NIST Handbook 158, Field Sampling Document describes procedures
Procedures for Fuel and Motor Oil for drawing fuel samples from
Quality Testing--A Handbook for Use by blender pumps and other in-
Fuel and Oil Quality Regulatory field installations for
Officials, 2016 Edition, April 2016. testing to measure fuel
parameters.
------------------------------------------------------------------------
[[Page 78463]]
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 action 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.
L. Congressional Review Act (CRA)
This action is subject to the CRA, and EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is not a ``major rule'' as defined by 5
U.S.C. 804(2).
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 as well as
Public Law 109-58. Additional support for the procedural and compliance
related aspects of this action 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 Parts 60, 63, 1042, and 1043
Administrative practice and procedure, Air pollution control.
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 1065
Administrative practice and procedure, Air pollution control,
Incorporation by reference.
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.
Dated: October 15, 2020.
Andrew Wheeler,
Administrator.
For the reasons set forth in the preamble, EPA amends 40 CFR parts
60, 63, 79, 80, 1042, 1043, and 1065 and adds 40 CFR part 1090 as
follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart IIII--Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines
0
2. Amend Sec. 60.4207 by:
0
a. Removing and reserving paragraph (a);
0
b. In paragraph (b), removing ``40 CFR 80.510(b)'' and adding ``40 CFR
1090.305'' in its place; and
0
c. Revising paragraph (d).
The revision reads as follows:
Sec. 60.4207 What fuel requirements must I meet if I am an owner or
operator of a stationary CI internal combustion engine subject to this
subpart?
* * * * *
(d) Beginning June 1, 2012, owners and operators of stationary CI
ICE subject to this subpart with a displacement of greater than or
equal to 30 liters per cylinder must use diesel fuel that meets a
maximum per-gallon sulfur content of 1,000 parts per million (ppm).
* * * * *
Subpart JJJJ--Standards of Performance for Stationary Spark
Ignition Internal Combustion Engines
Sec. 60.4235 [Amended]
0
3. Amend Sec. 60.4235 by removing ``40 CFR 80.195'' and adding ``40
CFR 1090.205'' in its place.
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
4. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart R--National Emission Standards for Gasoline Distribution
Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)
0
5. Amend Sec. 63.421 by revising the definitions for ``Oxygenated
gasoline'' and ``Reformulated gasoline'' to read as follows:
Sec. 63.421 Definitions.
* * * * *
Oxygenated gasoline means the same as defined in 40 CFR 80.2.
* * * * *
Reformulated gasoline means the same as defined in 40 CFR 80.2.
* * * * *
Subpart ZZZZ--National Emissions Standards for Hazardous Air
Pollutants for Stationary Reciprocating Internal Combustion Engines
Sec. 63.6604 [Amended]
0
6. In Sec. 63.6604, amend paragraphs (a), (b), and (c) by removing
``40 CFR 80.510(b)'' and adding ``40 CFR 1090.305'' in its place.
PART 79--REGISTRATION OF FUEL AND FUEL ADDITIVES
0
7. 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
8. 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 fuel in subpart
D of this part, or the later registration of a fuel 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
9. Amend Sec. 79.21 by:
0
a. Revising paragraphs (f) and (g); and
[[Page 78464]]
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 1090.260.
* * * * *
(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 1090.260.
(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) Nomenclature. 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) Designation. 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.
(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 1090.260. 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 1090.260.
(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 1090.260.
(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
[[Page 78465]]
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
10. 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 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 terminated by the
Administrator if the EPA determines that the detergent additive is not
compliant with the gasoline deposit control requirements of 40 CFR
1090.260.
Subpart D--Designation of Fuels and Additives
0
11. 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
12. Amend Sec. 79.33 by revising paragraph (c) to read as follows:
Sec. 79.33 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
13. 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
14. 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
15. 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 (C3) 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)
(42 U.S.C. 7545(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) (42 U.S.C. 7545(m)(2)).
Conventional gasoline or CG means any gasoline that has been
certified under 40 CFR 1090.1000(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
[[Page 78466]]
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 (2) of this definition.
(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.
Locomotive engine means an engine used in a locomotive as defined
under 40 CFR 92.2.
Marine engine has the meaning given in 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
(42 U.S.C. 7545(f)(1)), or be permitted under a waiver granted by the
Administrator under the authority of section 211(f)(4) of the Clean Air
Act (42 U.S.C. 7545(f)(4)).
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 40 CFR 1090.1000(b), and which meets each of
the standards and requirements prescribed under 40 CFR 1090.220.
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
[[Page 78467]]
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
16. Effective January 1, 2022, remove and reserve Sec. 80.3.
Sec. 80.7 [Amended]
0
17. In Sec. 80.7, amend paragraph (c) by removing ``Sec. 80.22'' and
adding ``40 CFR 1090.1550'' in its place.
Subpart B--Controls and Prohibitions
Sec. Sec. 80.22, 80.23, and 80.26 through 80.33 [Removed and
reserved]
0
18. Effective January 1, 2022, remove and reserve Sec. Sec. 80.22,
80.23, and 80.26 through 80.33.
Subparts D, E, F, G, H, I, J, K, L, N, and O and Appendices A and B
to Part 80--[Removed and reserved]
0
19. Effective January 1, 2022, remove and reserve subparts D through L,
N, and O and appendices A and B to Part 80.
Subpart M--Renewable Fuel Standard
Sec. 80.1400 [Amended]
0
20. Amend Sec. 80.1400 by removing the second sentence of the
introductory text.
0
21. Amend Sec. 80.1401 by:
0
a. Revising the definition of ``Certified non-transportation 15 ppm
distillate fuel'';
0
b. In paragraph (2) in the definition of ``Fuel for use in an ocean-
going vessel'', removing ``Sec. Sec. 80.2(ttt) and 80.510(k)'' and
adding ``Sec. 80.2 and 40 CFR 1090.80'' in its place;
0
c. In paragraph (1) in the definition of ``Heating oil'', removing
``Sec. 80.2(ccc)'' and adding ``Sec. 80.2'' in its place;
0
d. In the definition of ``Renewable gasoline'', removing ``Sec.
80.2(c)'' and adding ``Sec. 80.2'' in its place; and
0
e. In the definition of ``Renewable gasoline blendstock'', removing
``Sec. 80.2(s)'' and adding ``Sec. 80.2'' in its place. The revision
reads as follows:
Sec. 80.1401 Definitions.
* * * * *
Certified non-transportation 15 ppm distillate fuel or certified
NTDF means distillate fuel that meets all the following:
(1) The fuel has been certified under 40 CFR 1090.1000 as meeting
the ULSD standards in 40 CFR 1090.305.
(2) The fuel has been designated under 40 CFR 1090.1015 as
certified NTDF.
(3) The fuel has also been designated under 40 CFR 1090.1015 as 15
ppm heating oil, 15 ppm ECA marine fuel, or other non-transportation
fuel (e.g., jet fuel, kerosene, or distillate global marine fuel).
(4) The fuel has not been designated under 40 CFR 1090.1015 as ULSD
or 15 ppm MVNRLM diesel fuel.
(5) The PTD for the fuel meets the requirements in Sec.
80.1453(e).
* * * * *
0
22. Amend Sec. 80.1407 by:
0
a. In paragraph (e), removing ``Sec. 80.2(qqq)'' and adding ``Sec.
80.2'' in its place; and
0
b. Revising paragraph (f)(7).
The revision reads 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 1090.500.
* * * * *
Sec. 80.1416 [Amended]
0
23. In Sec. 80.1416, amend paragraph (b)(1)(i) by removing ``Sec.
80.76'' and adding ``40 CFR 1090.805'' in its place.
Sec. 80.1427 [Amended]
0
24. Amend Sec. 80.1427 by:
0
a. In paragraph (a)(2) introductory text, removing ``Except as
described in paragraph (a)(4) of this section,''; and
0
b. Removing and reserving paragraph (a)(4).
Sec. 80.1429 [Amended]
0
25. Amend Sec. 80.1429 by:
0
a. In paragraph (b)(9) introductory text, removing ``RBOB, or CBOB''
and adding ``or BOB'' in its place; and
0
b. Removing paragraphs (f) and (g).
Sec. 80.1440 [Amended]
0
26. In Sec. 80.1440, amend paragraph (a)(2) by removing ``any other
subpart of 40 CFR part 80 (e.g., Sec. Sec. 80.606, 80.1655)'' and
adding ``40 CFR 1090.605'' in its place.
Sec. 80.1441 [Amended]
0
27. Amend Sec. 80.1441 by removing paragraphs (a)(6) and (b)(4).
Sec. 80.1442 [Amended]
0
28. Amend Sec. 80.1442 by removing paragraphs (a)(3) and (b)(6).
Sec. 80.1450 [Amended]
0
29. Amend Sec. 80.1450 by:
0
a. In paragraphs (a), (b) introductory text, and (c), removing ``Sec.
80.76'' and adding ``40 CFR 1090.805'' in its place;
0
b. In paragraph (d)(3)(iii), removing ``Sec. 80.127'' and adding ``40
CFR 1090.1805'' in its place; and
0
c. In paragraphs (e) and (g)(1), removing ``Sec. 80.76'' and adding
``40 CFR 1090.805'' in its place.
Sec. 80.1453 [Amended]
0
30. In Sec. 80.1453, amend paragraph (e)(1) by removing ``Sec.
80.590'' and adding ``40 CFR 1090.1115'' in its place.
Sec. 80.1454 [Amended]
0
31. In Sec. 80.1454, amend paragraph (h)(2)(i) by removing ``Sec.
80.68(c)(13)(i)'' and adding ``40 CFR 1090.55'' in its place.
Sec. 80.1464 [Amended]
0
32. Amend Sec. 80.1464 by:
0
a. In the introductory text, removing ``Sec. Sec. 80.125 through
80.127, and 80.130,'' and adding ``40 CFR 1090.1800'' in its place;
0
b. In paragraph (a)(1)(iii), removing ``Sec. 80.133'' and adding ``40
CFR 1090.1810'' in its place; and
0
c. In paragraphs (a)(1)(iv)(D), (a)(2)(i), (b)(1)(iv), (b)(1)(v)(A),
(b)(2)(i), and (c)(1)(i), removing ``Sec. 80.127'' and adding ``40 CFR
1090.1805'' in its place.
Sec. 80.1465 [Removed and reserved]
0
33. Remove and reserve Sec. 80.1465.
Sec. 80.1466 [Amended]
0
34. Amend Sec. 80.1466 by:
0
a. In paragraph (d)(3)(ii), removing ``Sec. 80.65(f)(2)(iii)'' and
adding ``40 CFR 1090.1805'' in its place;
0
b. In paragraphs (m)(3) introductory text, (m)(4) introductory text,
and (m)(5), removing ``Sec. 80.127'' and adding ``40 CFR 1090.1805''
in its place; and
0
c. In paragraphs (m)(6)(ii) and (iii), removing ``Sec. Sec. 80.125
through 80.127, 80.130'' and adding ``40 CFR 1090.1800'' in its place.
Sec. 80.1467 [Amended]
0
35. In Sec. 80.1467, amend paragraphs (h)(2) and (3) by removing
``Sec. Sec. 80.125 through 80.127, 80.130,'' and adding ``40 CFR
1090.1800'' in its place.
* * * * *
Sec. 80.1469 [Amended]
0
36. In Sec. 80.1469, amend paragraph (c)(5) by removing ``Sec.
80.127'' and adding ``40 CFR 1090.1805'' in its place.
[[Page 78468]]
Sec. 80.1475 [Amended]
0
37. In Sec. 80.1475, amend paragraph (d)(4)(ii) by removing ``Sec.
80.590'' and adding ``40 CFR 1090.1115'' in its place.
PART 1042--CONTROL OF EMISSIONS FROM NEW AND IN-USE MARINE
COMPRESSION-IGNITION ENGINES AND VESSELS
0
38. The authority citation for part 1042 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart G--Special Compliance Provisions
Sec. 1042.660 [Amended]
0
39. In Sec. 1042.660, amend paragraph (a) by removing ``40 CFR part
80'' and adding ``40 CFR part 1090'' in its place.
Subpart J--Definitions and Other Reference Information
Sec. 1042.901 [Amended]
0
40. In Sec. 1042.901, amend the definition of ``Diesel fuel'' by
removing ``40 CFR 80.2'' and adding ``40 CFR 1090.80'' in its place.
PART 1043-- CONTROL OF NOX, SOX, AND PM EMISSIONS FROM MARINE
ENGINES AND VESSELS SUBJECT TO THE MARPOL PROTOCOL
0
41. The authority citation for part 1043 continues to read as follows:
Authority: 33 U.S.C. 1901-1912.
Sec. 1043.1 [Amended]
0
42. In Sec. 1043.1, amend paragraph (f) by removing ``40 CFR part 80''
and adding ``40 CFR part 1090'' in its place.
Sec. 1043.60 [Amended]
0
43. In Sec. 1043.60, amend paragraphs (d) and (e) by removing ``40 CFR
part 80'' and adding ``40 CFR part 1090'' in its place.
Sec. 1043.70 [Amended]
0
44. In Sec. 1043.70, amend paragraphs (c) and (d) by removing ``40 CFR
part 80'' and adding ``40 CFR part 1090'' in its place.
Sec. 1043.80 [Amended]
0
45. In Sec. 1043.80, amend paragraph (b)(5) by removing ``40 CFR part
80'' and adding ``40 CFR part 1090'' in its place.
PART 1065--ENGINE-TESTING PROCEDURES
0
46. The authority citation for part 1065 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart H--Engine Fluids, Test Fuels, Analytical Gases and Other
Calibration Standards
0
47. Amend Sec. 1065.701 by revising paragraph (d)(2) to read as
follows:
Sec. 1065.701 General requirements for test fuels.
* * * * *
(d) * * *
(2) The fuel parameters specified in this subpart depend on
measurement procedures that are incorporated by reference. For any of
these procedures, you may instead rely upon the procedures identified
in 40 CFR part 1090 for measuring the same parameter. For example, we
may identify different reference procedures for measuring gasoline
parameters in 40 CFR 1090.1360.
* * * * *
0
48. Effective December 4, 2020, amend Sec. 1065.703 by revising Table
1 of Sec. 1065.703 to read as follows:
Sec. 1065.703 Distillate diesel fuel.
* * * * *
Table 1 of Sec. 1065.703--Test Fuel Specifications for Distillate Diesel Fuel
----------------------------------------------------------------------------------------------------------------
Ultra low Reference
Property Unit sulfur Low sulfur High sulfur procedure \a\
----------------------------------------------------------------------------------------------------------------
Cetane Number................. .............. 40-50 40-50 40-50 ASTM D613
Distillation range:
Initial boiling point..... [deg]C........ 171-204 171-204 171-204 ASTM D86
10 pct. point............. 204-238 204-238 204-238
50 pct. point............. 243-282 243-282 243-282
90 pct. point............. 293-332 293-332 293-332
Endpoint.................. 321-366 321-366 321-366
Gravity....................... [deg]API...... 32-37 32-37 32-37 ASTM D4052
Total sulfur.................. mg/kg......... 7-15 300-500 800-2500 ASTM D2622, ASTM
D5453, or ASTM
D7039
Aromatics, min. (Remainder g/kg.......... 100 100 100 ASTM D5186
shall be paraffins,
naphthenes, and olefins).
Flashpoint, min............... [deg]C........ 54 54 54 ASTM D93
Kinematic Viscosity........... mm\2\/s....... 2.0-3.2 2.0-3.2 2.0-3.2 ASTM D445
----------------------------------------------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec. 1065.1010. See Sec. 1065.701(d) for other allowed procedures.
* * * * *
Sec. 1065.705 [Amended]
0
49. In Sec. 1065.705, amend the introductory text by removing ``40 CFR
80.2'' and adding ``40 CFR 1090.80'' in its place.
Sec. 1065.725 [Amended]
0
50. In Sec. 1065.725, amend paragraph (c) by removing ``denatured
ethanol meeting the specifications in 40 CFR 80.1610'' and adding
``denatured fuel ethanol meeting the specifications in 40 CFR
1090.270'' in its place.
Subpart K--Definitions and Other Reference Information
0
51. Effective December 4, 2020, amend Sec. 1065.1010 by revising the
last sentence of paragraph (a) and paragraphs (b)(19), (35), and (46)
to read as follows:
Sec. 1065.1010 Incorporation by reference.
(a) * * * 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) * * *
(19) ASTM D2622-16, Standard Test Method for Sulfur in Petroleum
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry,
approved January 1, 2016 (``ASTM
[[Page 78469]]
D2622''), IBR approved for Sec. Sec. 1065.703(b) and 1065.710(b) and
(c).
* * * * *
(35) 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. Sec. 1065.703(b) and
1065.710(b).
* * * * *
(46) ASTM D7039-15a (Reapproved 2020), Standard Test Method for
Sulfur in Gasoline, Diesel Fuel, Jet Fuel, Kerosine, Biodiesel,
Biodiesel Blends, and Gasoline-Ethanol Blends by Monochromatic
Wavelength Dispersive X-ray Fluorescence Spectrometry, approved May 1,
2020 (``ASTM D7039''), IBR approved for Sec. Sec. 1065.703(b) and
1065.710(b).
* * * * *
0
52. Effective December 4, 2020, 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.
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 RFG standards.
1090.225 Anti-dumping standards.
1090.230 Limitation on use of gasoline-ethanol blends.
1090.250 Certified butane standards.
1090.255 Certified pentane standards.
1090.260 Gasoline deposit control standards.
1090.265 Gasoline additive standards.
1090.270 Gasoline oxygenate standards.
1090.275 Ethanol denaturant standards.
1090.285 RFG covered areas.
1090.290 Changes to RFG covered areas and procedures for opting out
of RFG.
1090.295 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, ECA marine fuel, 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 Gasoline produced from blending transmix into PCG.
1090.505 Gasoline produced from TGP.
1090.510 Diesel and distillate fuel produced from TDP.
1090.515 500 ppm LM diesel fuel produced from TDP.
1090.520 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 fuel manufacturers.
Subpart K--Batch Certification and Designation
1090.1000 Batch certification requirements.
1090.1005 Designation of batches of fuels, fuel additives, and
regulated blendstocks.
1090.1010 Designation requirements for gasoline and regulated
blendstocks.
1090.1015 Designation requirements for diesel and distillate fuels.
1090.1020 Batch numbering.
Subpart L--Product Transfer Documents
1090.1100 General requirements.
1090.1105 PTD requirements for exempt fuels.
1090.1110 PTD requirements for gasoline, gasoline additives, and
gasoline regulated blendstocks.
1090.1115 PTD requirements for distillate and residual fuels.
1090.1120 PTD requirements for diesel fuel additives.
1090.1125 Alternative PTD language.
Subpart M--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, ECA marine
fuel, and distillate global marine fuel manufacturers.
1090.1220 Recordkeeping requirements for oxygenate blenders.
1090.1225 Recordkeeping requirements for gasoline additives.
[[Page 78470]]
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 N--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 or PCG to TGP.
1090.1330 Preparing denatured fuel ethanol.
Handling and Preparing Samples
1090.1335 Collecting, preparing, and testing samples.
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 O--Survey Provisions
1090.1400 General provisions.
1090.1405 National fuels survey program.
1090.1410 Independent surveyor requirements.
1090.1415 Survey program plan design requirements.
1090.1420 Additional requirements for E15 misfueling mitigation
surveying.
1090.1450 National sampling and testing oversight program.
Subpart P--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 Q--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 R--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.
Subpart S--Attestation Engagements
1090.1800 General provisions.
1090.1805 Representative samples.
1090.1810 General procedures for gasoline manufacturers.
1090.1815 General procedures for 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 introduced into commerce 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. A party that produces and distributes 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 sulfur content
for fuel used in marine vessels, including separate standards for
marine 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. A party 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. A party 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.
[[Page 78471]]
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) 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 for
gasoline as specified in paragraph (b)(8) of this section), any
approval granted under 40 CFR part 80 continues to be in effect under
this part. For example, if EPA approved the use of an alternative label
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, a regulated party 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.
(6) A party may comply with the PTD requirements of 40 CFR part 80
instead of the requirements of subpart L of this part until May 1,
2021.
(7) A party may comply with the automatic sampling provisions of 40
CFR 80.8 instead of the requirements in Sec. 1090.1335(c) until
January 1, 2022.
(8) A gasoline manufacturer may operate under an in-line blending
waiver issued under 40 CFR part 80 until January 1, 2022, or until EPA
approves a revised in-line blending waiver under Sec. 1090.1315,
whichever is earlier. The following provisions apply:
(i) A gasoline manufacturer operating under an in-line blending
waiver under 40 CFR 80.65 must monitor and test for sulfur content,
benzene content, and for summer gasoline, RVP, and may discontinue
monitoring and testing for other properties that are included in their
in-line blending waiver.
(ii) The auditing requirements in Sec. 1090.1850 do not apply to
an in-line blending waiver issued under 40 CFR part 80.
(c) The following requirements apply for the 2021 compliance
period:
(1) The NSTOP specified in Sec. 1090.1450 must begin no later than
June 1, 2021.
(2) A gasoline manufacturer that accounts for oxygenate added
downstream under Sec. 1090.710 is deemed compliant with the
requirement to participate in the NSTOP specified in Sec.
1090.710(a)(3) until June 1, 2021, if the gasoline manufacturer meets
all other applicable requirements specified in Sec. 1090.710.
(3) The independent surveyor conducting the NSTOP must submit the
proof of contract required under Sec. 1090.1400(b) no later than April
15, 2021.
(4) The independent surveyor may collect only one summer or winter
gasoline sample for each participating fuel manufacturing facility
instead of the minimum two samples required under Sec.
1090.1450(c)(2)(i).
Sec. 1090.10 Contacting EPA.
A party must submit all reports, registrations, and documents for
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 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, if applicable.
(3) The general nature of a request.
(4) The relevant time period for a 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, if applicable.
(3) The general nature of a request.
(4) The relevant time period for a request, if applicable.
(5) The extent to which EPA either granted or denied the request
and any relevant terms and 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 may impose terms and conditions on any approval of any
submission required or allowed under this part.
(c) EPA will deny any request for approval if the submission is
incomplete, contains inaccurate or misleading information, or does not
meet all specified requirements.
(d) 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.
(e) 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.
(f) 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) 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.
[[Page 78472]]
(b) Do not round intermediate values to transfer data unless the
rounded number has at least 6 significant digits.
(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 N 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 11,000 gallons to the
nearest 10 gallons.
(ii) Round batch volumes above 11,000 gallons to the nearest 100
gallons.
Sec. 1090.55 Requirements for independent parties.
This section specifies how a third party demonstrates 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 each person involved in the specified
activities in this part that the independent third party is hired to
perform for a regulated party, except that an internal auditor may
instead meet the requirements in Sec. 1090.1800(b)(1)(i).
(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 12
months 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.
(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:
(1) An independent surveyor that conducts a survey under subpart O
of this part must have personnel familiar with petroleum marketing, the
sampling and testing of gasoline and diesel fuel at retail stations,
and the designing of surveys to estimate compliance rates for fuel
parameters nationwide. The independent surveyor must demonstrate this
technical ability in plans submitted under subpart O of this part.
(2) A laboratory 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. The
independent third party must demonstrate work experience and a good
working knowledge of the VCSB methods 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) Any person auditing in-line blending operations must
demonstrate work experience and be proficient in the VCSB methods
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 that is produced by a transmix
processor under Sec. 1090.515.
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 in order 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 S 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. This also includes
fuel, fuel additive, or regulated blendstock for which homogeneity
testing is not required under Sec. 1090.1337(a).
Biodiesel means a diesel fuel composed of mono-alkyl esters made
from nonpetroleum feedstocks.
Blender pump means any fuel dispenser where PCG is blended with E85
(made only with PCG and DFE) or DFE to produce gasoline that has an
ethanol content greater than that of the PCG. A fuel dispenser that
produces gasoline with anything other than PCG and DFE (e.g., natural
gas liquids) is a fuel blending facility.
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.
[[Page 78473]]
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) that meets 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) that meets 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) that meets the definition of ``Category 3'' in 40 CFR part
1042.901.
CBOB means a BOB produced or imported for use outside of an RFG
covered area.
Certified butane means butane that is certified to meet the
requirements in Sec. 1090.250.
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(b) 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. 1090.250.
Certified ethanol denaturant means ethanol denaturant that is
certified to meet the requirements in Sec. 1090.275.
Certified ethanol denaturant producer means any person that
certifies ethanol denaturant as meeting the requirements in Sec.
1090.275.
Certified non-transportation 15 ppm distillate fuel or certified
NTDF has the meaning given in 40 CFR 80.1401.
Certified pentane means pentane that is certified to meet the
requirements in Sec. 1090.255.
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. 1090.255.
Compliance period means the calendar year (January 1 through
December 31).
Conventional gasoline (CG) means gasoline that is not certified to
meet the requirements for RFG in Sec. 1090.220.
Crosscheck program means 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 accuracy
of individual laboratories and measurement systems.
Days means calendar days, including weekends and holidays.
Denatured fuel ethanol (DFE) means anhydrous ethanol that contains
a denaturant to make it unfit for human consumption, that is produced
or imported for use in gasoline, and that meets the standards and
requirements in Sec. 1090.270.
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. 1090.260. 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.
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. A detergent
manufacturer is a fuel additive manufacturer.
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 or a fuel blend that
contains NP diesel fuel) that is intended or used to power a vehicle or
engine that is designed to operate using diesel 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 that owns,
leases, operates, controls, or supervises a fuel manufacturing facility
where diesel fuel is produced or imported.
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. T90 temperature is based on the
distillation test method specified in Sec. 1090.1350.
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 fuel manufacturing facility gate at which it was
certified (e.g., fuel at facilities of distributors, pipelines,
terminals, carriers, retailers, oxygenate blenders, and WPCs).
E0 means 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. E85
is not gasoline.
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 ECA, or an ECA associated area.
Ethanol means an alcohol of the chemical formula
C2H5OH.
Ethanol denaturant means PCG, gasoline blendstocks, or natural gas
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,
[[Page 78474]]
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.
Fuel additive means has the same meaning as additive in 40 CFR
79.2(e).
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 the fuel manufacturer
certified the fuel.
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.
(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 (BOB) means gasoline for which a
gasoline manufacturer has accounted for oxygenate added downstream
under Sec. 1090.710. 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 that owns, leases,
operates, controls, or supervises a fuel manufacturing facility where
gasoline is produced, imported, or recertified.
Gasoline regulated blendstock means a regulated blendstock that is
used or intended for use as a component of gasoline.
Gasoline treated as blendstock (GTAB) means a gasoline regulated
blendstock that is imported and used to produce gasoline as specified
in 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.
(Note: This part regulates global marine fuel only if it qualifies as a
distillate fuel.)
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 O of
this part.
Intake valve deposits (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 (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 (NGLs) means natural gasoline or other mixtures
of hydrocarbons (primarily but not limited to 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 renewable fuel under 40
CFR part 80, subpart M, that is used or intended for use to power a
vehicle or engine that is designed to operate using diesel fuel or that
is made available for use in a vehicle or engine designed to operate
using diesel fuel.
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,
[[Page 78475]]
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,
Territories. 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 that abut each other during shipment by a 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 (PCG) means CG, RFG, or BOB that has
been certified as a batch by a gasoline manufacturer.
Product transfer documents (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 a BOB produced or imported for use in an RFG covered
area.
Refiner means any person who owns, leases, operates, controls, or
supervises a refinery in the United States.
Refinery means a facility where fuels are produced from feedstocks,
including crude oil or renewable feedstocks, through physical or
chemical processing equipment.
Reformulated gasoline (RFG) means gasoline that is certified under
Sec. 1090.1000(b) and that meets each of the standards and
requirements in Sec. 1090.220.
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 a retailer
or WPC, 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. For example, No. 5 fuels and No. 6 fuels are residual
fuels. Residual fuel grades are specified in ASTM D396 and ISO 8217.
T90 temperature is based on the distillation test method specified in
Sec. 1090.1350.
Responsible corporate officer (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 fuel 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.
1090.285 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. 1090.285.
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 (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 if it 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 of gasoline and distillate fuel 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
[[Page 78476]]
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 under Sec. 1090.500.
Transmix distillate product (TDP) means the diesel fuel blendstock
that is produced when transmix is separated into blendstocks at a
transmix processing facility.
Transmix gasoline product (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. A transmix
processor is a fuel manufacturer.
Ultra low-sulfur diesel (ULSD) means diesel fuel that is certified
to meet the standards 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 the following:
(1) For an automated detergent blending facility, the VAR period is
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.
(2) For a non-automated detergent blending facility, the VAR Period
constitutes the blending of one batch of gasoline.
Voluntary consensus standards body (VCSB) means 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.
Wholesale purchaser-consumer (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 duration 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 parties.
(a) Types of provisions. The term ``provision'' includes all
aspects of the regulations in this part. As specified in this section,
regulatory provisions include standards, requirements, and
prohibitions, along with a variety of other types of provisions.
(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. 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 must not do. 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) Subject to. 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 exempt 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 are not exhaustive.
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.
[[Page 78477]]
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.
NFSP......................... national fuels survey program.
NGL.......................... natural gas liquids.
NIST......................... National Institute for Standards and
Technology.
NSTOP........................ national sampling and testing oversight
program.
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 distillate product.
TGP.......................... transmix gasoline product.
U.S.......................... United States.
U.S.C........................ United States Code.
ULSD......................... ultra-low-sulfur diesel fuel.
VCSB......................... voluntary consensus standards body.
------------------------------------------------------------------------
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 also available from the
sources listed in this section. This material 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, (888) 777-7077, or www.aicpa.org.
(1) AICPA Code of Professional Conduct, updated through June 2020;
IBR approved for Sec. 1090.1800(b).
(2) Statements on Quality Control Standards (SQCS) No. 8, QC
Section 10: A Firm's System of Quality Control, current as of July 1,
2019; IBR approved for Sec. 1090.1800(b).
(3) Statement on Standards for Attestation Engagements No. 18,
Attestation Standards: Clarification and Recodification, Issued April
2016; 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 D86-20a, Standard Test Method for Distillation of
Petroleum Products and Liquid Fuels at Atmospheric Pressure, approved
July 1, 2020 (``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(d).
(3) ASTM D975-20a, Standard Specification for Diesel Fuel, approved
June 1, 2020 (``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(d).
(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
[[Page 78478]]
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 D3606-20e1, Standard Test Method for Determination of
Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography,
approved July 1, 2020 (``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(d).
(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(a) 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 D4806-20, Standard Specification for Denatured Fuel
Ethanol for Blending with Gasolines for Use as Automotive Spark-
Ignition Engine Fuel, approved May 1, 2020 (``ASTM D4806''); IBR
approved for Sec. 1090.1395(a).
(18) ASTM D4814-20a, Standard Specification for Automotive Spark-
Ignition Engine Fuel, approved April 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 D5186-20, Standard Test Method for Determination of the
Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By
Supercritical Fluid Chromatography, approved July 1, 2020 (``ASTM
D5186''); IBR approved for Sec. 1090.1350(b).
(21) ASTM D5191-20, Standard Test Method for Vapor Pressure of
Petroleum Products and Liquid Fuels (Mini Method), approved May 1, 2020
(``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 D5500-20a, Standard Test Method for Vehicle Evaluation of
Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit
Formation, approved June 1, 2020 (``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 D5769-20, Standard Test Method for Determination of
Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas
Chromatography/Mass Spectrometry, approved June 1, 2020 (``ASTM
D5769''); IBR approved for Sec. Sec. 1090.1350(b), 1090.1360(d), and
1090.1365(b).
(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(a).
(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 D6299-20, Standard Practice for Applying Statistical
Quality Assurance and Control Charting Techniques to Evaluate
Analytical Measurement System Performance, approved May 1, 2020 (``ASTM
D6299''); IBR approved for Sec. Sec. 1090.1370(c), 1090.1375(a), (b),
and (c), and 1090.1450(c).
(31) ASTM D6550-20, Standard Test Method for Determination of
Olefin Content of Gasolines by Supercritical-Fluid Chromatography,
approved July 1, 2020 (``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. 1090.1360(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 D6729-14, Standard Test Method for Determination of
Individual Components in Spark Ignition Engine Fuels by 100 Metre
Capillary High Resolution Gas Chromatography, approved October 1, 2014
(``ASTM D6729''); IBR approved for Sec. 1090.1350(b).
(35) ASTM D6730-19, Standard Test Method for Determination of
Individual Components in Spark Ignition Engine Fuels by 100-Metre
Capillary (with Precolumn) High-Resolution Gas Chromatography, approved
July 1, 2019 (``ASTM D6730''); IBR approved for Sec. 1090.1350(b).
(36) ASTM D6751-20, Standard Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels, approved January 1, 2020
(``ASTM D6751''); IBR approved for Sec. 1090.1350(b).
(37) 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. 1090.1450(c).
(38) ASTM D7039-15a (Reapproved 2020), Standard Test Method for
Sulfur in Gasoline, Diesel Fuel, Jet Fuel, Kerosine, Biodiesel,
Biodiesel Blends, and Gasoline-Ethanol Blends by Monochromatic
Wavelength Dispersive X-ray Fluorescence Spectrometry, approved May 1,
2020 (``ASTM D7039''); IBR approved for Sec. 1090.1365(b).
(39) ASTM D7717-11 (Reapproved 2017), Standard Practice for
Preparing Volumetric Blends of Denatured Fuel Ethanol and Gasoline
Blendstocks for Laboratory Analysis, approved May 1,
[[Page 78479]]
2017 (``ASTM D7717''); IBR approved for Sec. 1090.1340(b).
(40) ASTM D7777-13 (Reapproved 2018)e1, Standard Test Method for
Density, Relative Density, or API Gravity of Liquid Petroleum by
Portable Digital Density Meter, approved October 1, 2018 (``ASTM
D7777''); IBR approved for Sec. 1090.1337(d).
(d) Environmental Protection Agency, Air and Radiation Docket and
Information Center, WJC West Building, Room 3334, 1301 Constitution
Ave. NW, Washington, DC 20460, (202) 566-1742.
(1) CARB Test Method, 13 CA ADC Sec. 2257; California Code of
Regulations Title 13. Motor Vehicles, Division 3. Air Resources Board,
Chapter 5. Standards for Motor Vehicle Fuels, Article 1. Standards for
Gasoline, Subarticle 1. Gasoline Standards that Became Applicable
Before 1996, Sec. 2257. Required Additives in Gasoline; amendment
filed May 17, 1999.
(2) [Reserved]
(e) The Institute of Internal Auditors, 1035 Greenwood Blvd., Suite
401, Lake Mary, FL 32746, (407) 937-1111, or www.theiia.org.
(1) International Standards for the Professional Practice of
Internal Auditing (Standards), Revised October 2016; IBR approved for
Sec. 1090.1800(b).
(2) [Reserved]
(f) 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, Field Sampling Procedures for Fuel and Motor
Oil Quality Testing--A Handbook for Use by Fuel and Oil Quality
Regulatory Officials, 2016 Edition, April 2016; IBR approved for Sec.
1090.1410(b).
(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
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 that also
transports fuel must meet the requirements applicable to a fuel
manufacturer and a distributor. A regulated party is 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 M 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 R 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 of paragraphs (a) through (c)
of this section and Sec. 1090.105, an importer must also comply with
subpart Q of this part.
Sec. 1090.105 Fuel manufacturers.
This section provides an overview of general requirements
applicable to a fuel manufacturer. A gasoline manufacturer must comply
with the requirements of paragraph (a) of this section. A diesel fuel
or IMO marine fuel manufacturer must comply with the requirements of
paragraph (b) of this section.
(a) Gasoline manufacturers. Except as specified otherwise in this
subpart, a gasoline manufacturer must comply with the following
requirements:
(1) Producing compliant gasoline. A gasoline manufacturer must
produce or import gasoline that meets the standards of subpart C of
this part and must comply with the ABT requirements in subpart H of
this part.
(2) Registration. A gasoline manufacturer must register with EPA
under subpart I of this part.
(3) Reporting. A gasoline manufacturer must submit reports to EPA
under subpart J of this part.
(4) Certification and designation. A gasoline manufacturer must
certify and designate the gasoline they produce under subpart K of this
part.
(5) 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 L of this part.
(6) Sampling, testing, and sample retention. A gasoline
manufacturer must conduct sampling, testing, and sample retention in
accordance with subpart N of this part.
(7) Surveys. A gasoline manufacturer may participate in applicable
fuel surveys under subpart O of this part.
(8) Annual attest engagement. A gasoline manufacturer must submit
annual attest engagement reports to EPA under subpart S of this part.
(b) Diesel fuel and IMO marine fuel manufacturers. A diesel fuel or
IMO marine fuel manufacturer must comply with the following
requirements, as applicable:
(1) Producing compliant diesel fuel and ECA marine fuel. A diesel
fuel or ECA marine fuel manufacturer must produce or import diesel fuel
or ECA marine fuel that meets the requirements of subpart D of this
part.
(2) Registration. A diesel fuel or ECA marine fuel manufacturer
must register with EPA under subpart I of this part.
(3) Reporting. A diesel fuel manufacturer must submit reports to
EPA under subpart J of this part.
(4) Certification and designation. A diesel fuel or ECA marine fuel
manufacturer must certify and designate the diesel fuel or ECA marine
fuel they produce under subpart K of this part. A distillate global
marine fuel manufacturer must designate the distillate global marine
fuel they produce under subpart K of this part.
(5) PTDs. On each occasion when a diesel fuel or IMO marine fuel
manufacturer transfers custody or title to any diesel fuel or IMO
marine fuel, the transferor must provide to the transferee PTDs under
subpart L of this part.
(6) Sampling, testing, and retention requirements. A diesel fuel or
ECA marine fuel manufacturer must conduct sampling, testing, and sample
retention in accordance with subpart N of this part.
(7) Surveys. A diesel fuel manufacturer may participate in
applicable fuel surveys under subpart O of this part.
(8) Distillate global marine fuel manufacturers. A distillate
global marine fuel manufacturer does not need to comply with the
requirements of paragraphs (b)(1) through (3), and (6) of this section
for 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.
A detergent blender must comply with the requirements of this
section.
(a) Gasoline standards. A detergent blender 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 L of this part.
(c) Recordkeeping. A detergent blender must demonstrate compliance
with the requirements in Sec. 1090.260(a) as specified in Sec.
1090.1240.
(d) Equipment calibration. A detergent blender at an automated
[[Page 78480]]
detergent blending facility must calibrate their detergent blending
equipment in accordance with subpart N of this part.
Sec. 1090.115 Oxygenate blenders.
An oxygenate blender must comply with the requirements of this
section.
(a) Gasoline standards. An oxygenate blender must comply with the
applicable requirements of subpart C of this part.
(b) Registration. An oxygenate blender 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 L of
this part.
(d) Oxygenate blending requirements. An oxygenate blender must
follow the blending instructions specified by the gasoline manufacturer
under Sec. 1090.710(a)(5) 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 an oxygenate producer (e.g., a DFE or isobutanol
producer). A DFE producer must comply with the requirements for an
oxygenate producer in paragraph (a) of this section and the additional
requirements specified in paragraph (b) of this section.
(a) Oxygenate producers. An oxygenate producer must comply with the
following requirements:
(1) Gasoline standards. An oxygenate producer must comply with the
applicable requirements of subpart C of this part.
(2) Registration. An oxygenate producer must register with EPA
under subpart I of this part.
(3) Reporting. An oxygenate producer must submit reports to EPA
under subpart J of this part.
(4) Certification and designation. An oxygenate producer must
certify and designate the oxygenate they produce under subpart K of
this part.
(5) 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 L of
this part.
(6) Sampling, testing, and retention requirements. An oxygenate
producer must conduct sampling, testing, and sample retention in
accordance with subpart N of this part.
(b) DFE producers. In addition to the requirements specified in
paragraph (a) of this section, a DFE producer must meet all the
following requirements:
(1) Use denaturant that complies with the requirements specified in
Sec. Sec. 1090.270(b) and 1090.275.
(2) Participate in a survey program conducted by an independent
surveyor under subpart O of this part if the DFE producer produces DFE
made available for use in the production of E15.
Sec. 1090.125 Certified butane producers.
A certified butane producer must comply with the requirements of
this section.
(a) Gasoline standards. A certified butane producer must comply
with the applicable requirements of subpart C of this part.
(b) Certification and designation. A certified butane producer must
certify and designate the certified butane they produce under subpart K
of this part.
(c) 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 L of this part.
(d) Sampling, testing, and retention requirements. A certified
butane producer must conduct sampling, testing, and sample retention in
accordance with subpart N of this part.
Sec. 1090.130 Certified butane blenders.
A certified butane blender that blends certified butane into PCG is
a gasoline manufacturer that may comply with the requirements of this
section in lieu of the requirements in Sec. 1090.105.
(a) Gasoline standards. A certified butane blender must comply with
the applicable requirements of subpart C of this part.
(b) Registration. A certified butane blender must register with EPA
under subpart I of this part.
(c) Reporting. A certified butane blender must submit reports to
EPA under subpart J of this part.
(d) PTDs. When certified butane is blended with PCG, PTDs that
accompany the gasoline blended with certified butane must comply with
subpart L of this part.
(e) Sampling and testing requirements. A certified butane blender
must comply with the alternative sampling and testing approach in Sec.
1090.1320(b).
(f) Survey. A certified butane blender may participate in the
applicable fuel surveys of subpart O of this part.
(g) Annual attest engagement. A certified butane blender must
submit annual attest engagement reports to EPA under subpart S of this
part.
Sec. 1090.135 Certified pentane producers.
A certified pentane producer must comply with the requirements of
this section.
(a) Gasoline standards. A certified pentane producer must comply
with the applicable requirements of subpart C of this part.
(b) Registration. A certified pentane producer must register with
EPA under subpart I of this part.
(c) Reporting. A certified pentane producer must submit reports to
EPA under subpart J of this part.
(d) Certification and designation. A certified pentane producer
must certify and designate the certified pentane they produce under
subpart K of this part.
(e) 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 L of this part.
(f) Sampling, testing, and retention requirements. A certified
pentane producer must conduct sampling, testing, and sample retention
in accordance with subpart N of this part.
Sec. 1090.140 Certified pentane blenders.
A certified pentane blender that blends certified pentane into PCG
is a gasoline manufacturer that may comply with the requirements of
this section in lieu of the requirements in Sec. 1090.105.
(a) Gasoline standards. A certified pentane blender must comply
with the applicable requirements of subpart C of this part.
(b) Registration. A certified pentane blender must register with
EPA under subpart I of this part.
(c) Reporting. A certified pentane blender must submit reports to
EPA under subpart J of this part.
(d) PTDs. When certified pentane is blended with PCG, PTDs that
accompany the gasoline blended with pentane must comply with subpart L
of this part.
(e) Sampling, testing, and retention requirements. A certified
pentane blender must comply with the alternative sampling and testing
approach in Sec. 1090.1320(b).
(f) Survey. A certified pentane blender may participate in the
applicable fuel surveys of subpart O of this part.
(g) Annual attest engagement. A certified pentane blender must
submit annual attest engagement reports to EPA under subpart S of this
part.
Sec. 1090.145 Transmix processors.
A transmix processor must comply with the requirements of this
section.
(a) Transmix requirements. A transmix processor must comply with
[[Page 78481]]
the transmix requirements of subpart F of this part.
(b) Registration. A transmix processor must register with EPA under
subpart I of this part.
(c) Certification and designation. A transmix processor must
certify and designate the fuel they produce under subpart K of this
part.
(d) 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 L of this part.
(e) Sampling, testing, and retention requirements. A transmix
processor must conduct sampling, testing, and sample retention in
accordance with subparts F and N of this part.
(f) Reporting. A transmix processor must submit reports to EPA
under subpart J of this part.
(g) Annual attest engagement. A transmix processor must submit
annual attest engagement reports to EPA under subpart S of this part.
Sec. 1090.150 Transmix blenders.
A transmix blender must comply with the requirements of this
section.
(a) Transmix requirements. A transmix blender must comply with the
transmix requirements of subpart F 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 L of this part.
(c) Sampling, testing, and retention requirements. A transmix
blender must conduct sampling, testing, and sample retention in
accordance with subparts F and N of this part.
Sec. 1090.155 Fuel additive manufacturers.
This section provides an overview of general requirements
applicable to a fuel additive manufacturer. A gasoline additive
manufacturer must comply with the requirements of paragraph (a) of this
section. A diesel fuel additive manufacturer must comply with the
requirements of paragraph (b) of this section. A certified ethanol
denaturant producer must comply with the requirements of paragraph (c)
of this section.
(a) Gasoline additive manufacturers. A gasoline additive
manufacturer must meet the following requirements:
(1) Gasoline additive standards. A gasoline additive manufacturer
must produce gasoline additives that comply with subpart C of this
part.
(2) Certification. A gasoline additive manufacturer must certify
the gasoline additives they produce under subpart K of this part.
(3) 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 L of this part.
(4) Gasoline detergent manufacturers. A gasoline detergent
manufacturer must comply with the following requirements:
(i) Part 79 registration and LAC determination. A gasoline
detergent manufacturer 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: 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 detergent standards. Report the LAC determined under
Sec. 1090.260(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 L of this part.
(iv) Sampling, testing, and retention requirements. A gasoline
detergent manufacturer that registers detergents must conduct sampling,
testing, and sample retention in accordance with subpart N of this
part.
(b) Diesel fuel additive manufacturers. A diesel fuel additive
manufacturer must meet the following requirements:
(1) Diesel fuel additive standards. A diesel fuel additive
manufacturer must produce diesel fuel additives that comply with
subpart D of this part.
(2) Certification. A diesel fuel additive manufacturer must certify
the diesel fuel additives they produce under subpart K of this part.
(3) 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 L of this part.
(c) Certified ethanol denaturant producers and importers. A
certified ethanol denaturant producer or importer must meet the
following requirements:
(1) Certification. A certified ethanol denaturant producer or
importer must certify that certified ethanol denaturant meets the
requirements in Sec. 1090.275 using the procedures specified at Sec.
1090.1000(g).
(2) Registration. A certified ethanol denaturant producer or
importer 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 transferor must provide to the transferee
PTDs under subpart L of this part.
Sec. 1090.160 Distributors, carriers, and resellers.
A distributor, carrier, or reseller must comply with the
requirements of this section.
(a) Gasoline and diesel standards. A distributor, carrier, or
reseller must comply with the applicable requirements of subparts C and
D of this part.
(b) Registration. A distributor or carrier 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.
1090.515(g).
(c) PTDs. On each occasion when a distributor, carrier, or reseller
transfers custody or title to any fuel, fuel additive, or regulated
blendstock, the transferor must provide to the transferee PTDs under
subpart L of this part.
Sec. 1090.165 Retailers and WPCs.
A retailer or WPC must comply with the requirements of this
section.
(a) Gasoline and diesel standards. A retailer or WPC must comply
with the applicable requirements of subparts C and D of this part.
(b) Labeling. A retailer or WPC that dispenses fuels requiring a
label under this part must display fuel labels under subpart P of this
part.
(c) Fuels made through fuel dispensers. A retailer or WPC that
produces gasoline (e.g., E15) through a fuel dispenser with anything
other than PCG and DFE is also a blending manufacturer and must comply
with the applicable requirements in Sec. 1090.105.
Sec. 1090.170 Independent surveyors.
An independent surveyor that conducts fuel surveys must comply with
the requirements of this section.
(a) Survey provisions. An independent surveyor must conduct fuel
surveys under subpart O of this part.
(b) Registration. An independent surveyor must register with EPA
under subpart I of this part.
(c) Reporting. An independent surveyor must submit reports to EPA
under subpart J of this part.
[[Page 78482]]
(d) Sampling, testing, and retention requirements. An independent
surveyor must conduct sampling, testing, and sample retention in
accordance with subpart N of this part.
(e) Independence requirements. In order to perform a survey program
under subpart O of this part, an independent surveyor must meet the
independence requirements in Sec. 1090.55.
Sec. 1090.175 Auditors.
An auditor that conducts an audit for a responsible party under
this part must comply with the requirements of this section.
(a) Registration. An auditor must register with EPA under subpart I
of this part.
(b) Reporting. An auditor must submit reports to EPA under subpart
J of this part.
(c) Attest engagement. An auditor must conduct audits under subpart
S of this part.
(d) Independence requirements. In order to perform an annual attest
engagement under subpart S of this part, an auditor 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.
A pipeline operator must comply with the requirements of this
section.
(a) Gasoline and diesel standards. A pipeline operator must comply
with the applicable requirements of subparts C and D of this part.
(b) PTDs. On each occasion when a pipeline operator transfers
custody or title to any fuel, fuel additive, or regulated blendstock,
the transferor must provide to the transferee PTDs under subpart L of
this part.
(c) Transmix requirements. A pipeline operator 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. A gasoline
manufacturer, gasoline additive manufacturer (e.g., an oxygenate or
certified ethanol denaturant producer), or gasoline regulated
blendstock producer (e.g., a certified butane or certified pentane
producer) must demonstrate compliance with the per-gallon standards in
this subpart by measuring fuel parameters in accordance with subpart N
of this part.
(c)(1) Except as specified in paragraph (c)(2) of this section, 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. A fuel
manufacturer must demonstrate compliance with average standards by
measuring fuel parameters in accordance with subpart N of this part and
by determining compliance under subpart H of this part.
(2) The sulfur average standard in Sec. 1090.205(a) and the
benzene average standards in Sec. 1090.210(a) and (b) do not apply to
gasoline produced by the following:
(i) Truck and rail importers using the provisions of Sec.
1090.1610 to meet the alternative per-gallon standards of Sec. Sec.
1090.205(d) and 1090.210(c).
(ii) Certified butane blenders.
(iii) Certified pentane blenders.
(iv) Transmix blenders.
(v) Transmix processors that produce gasoline from only TGP or both
TGP and PCG.
(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.
(f) No fuel or fuel additive manufacturer may introduce into
commerce gasoline or gasoline additives (including oxygenates) that are
not ``substantially similar'' under 42 U.S.C. 7545(f)(1) or permitted
under a waiver granted under 42 U.S.C. 7545(f)(4).
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. A gasoline manufacturer 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. A gasoline manufacturer
must 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. (1) An importer that imports 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.
(2) An importer that imports gasoline by rail or truck but does not
comply with the alternative sampling and testing requirements in Sec.
1090.1610 must conduct sampling, testing, and sample retention in
accordance with subpart N of this part and comply with the sulfur
standards in paragraphs (a) and (b) 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:
(a) Benzene average standard. A gasoline manufacturer must meet a
benzene average standard of 0.62 volume percent for each compliance
period.
(b) Maximum benzene average standard. A gasoline manufacturer 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. (1) An importer that imports 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.
(2) An importer that imports gasoline by rail or truck that does
not comply with the alternative sampling and testing requirements in
Sec. 1090.1610 must conduct sampling, testing, and sample retention in
accordance with subpart N of this part and comply with the benzene
standards in paragraphs (a) and (b) of this section.
[[Page 78483]]
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)(1) 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 lower
maximum RVP per-gallon standards specified in paragraphs (a)(2) through
(5) of this section.
(2) 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)(2)--Federal 7.8 psi RVP Areas
------------------------------------------------------------------------
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.
(3) RFG maximum RVP per-gallon standard. Gasoline designated as
Summer RFG or located in an RFG covered area during the summer season
must meet a maximum RVP per-gallon standard of 7.4 psi.
(4) 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.
(5) 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)(1) or (2) 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 paragraph (a)(1) or (2) of 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 SIP-controlled gasoline 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 the person(s) who produced, imported, sold,
offered for sale, distributed, offered to distribute, supplied, offered
for supply, dispensed, stored, transported, or introduced the gasoline
into commerce 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 WPC 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 RFG standards.
The standards in this section apply to gasoline that is designated
as RFG or RBOB or that is used in an RFG covered area. 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) and the sulfur per-gallon
standards in Sec. 1090.205(b) and (c).
(b) Benzene standards. RFG or RBOB must comply with the benzene
average standards in Sec. 1090.210(a) and (b).
(c) RVP standard. Summer RFG or Summer RBOB must comply with the
RFG RVP standard in Sec. 1090.215(a)(3).
(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
[[Page 78484]]
butane and certified pentane must not be blended with Summer RFG or
Summer RBOB under Sec. 1090.1320.
Sec. 1090.225 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. 1090.230 Limitation on use of gasoline-ethanol blends.
(a) No person may sell, introduce, cause or permit the sale or
introduction of gasoline containing greater than 10 volume percent
ethanol (e.g., E15) 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 engine, vehicle, 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. 1090.250 Certified butane standards.
Butane designated as certified butane under Sec. 1090.1000(e) for
use under the butane blending provisions of Sec. 1090.1320(b) must
meet the following per-gallon standards:
(a) Butane content. Minimum 85 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. 1090.255 Certified pentane standards.
Pentane designated as certified pentane under Sec. 1090.1000(f)
for use under the pentane blending provisions of Sec. 1090.1320(b)
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. 1090.260 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 that meets
the requirements of paragraph (b) of this section at a rate at least as
high as the detergent's LAC over the 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). A party
compliant with this paragraph (b)(2) is exempt from the port fuel
injector deposit control requirements of 40 CFR 80.165(a).
(3) A gasoline detergent manufacturer 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. 1090.265 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 that 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 sulfur per-gallon
standard in Sec. 1090.205(c), if all the following conditions are met:
(1) The fuel additive blender blends gasoline additives into
gasoline at a concentration less than or equal to a combined total of
1.0 volume percent.
(2) The fuel additive blender does not add any other blendstock
into the gasoline except for oxygenates that meet the requirements in
Sec. 1090.270.
(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 a
gasoline manufacturer under this part.
(d) Any gasoline additive used or intended for use to comply with
the gasoline deposit control requirement in Sec. 1090.260(a) must meet
the gasoline deposit control standards under Sec. 1090.260(b).
Sec. 1090.270 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.
1090.275 may be used as denaturants.
(2) Denaturant concentration. The concentration of all denaturants
used in DFE must not exceed 3.0 volume percent.
Sec. 1090.275 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. In addition to the
requirements of paragraph (a) of this section, certified ethanol
denaturant must meet the following requirements:
(1) Sulfur content per-gallon standard. Maximum 330 ppm. If the
certified ethanol denaturant producer represents a batch of denaturant
as having a maximum sulfur content less than 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. 1090.285 RFG covered areas.
For purposes of this part, the RFG covered areas are as follows:
[[Page 78485]]
(a) RFG covered areas specified in 42 U.S.C. 7545(k)(10)(D):
Table 1 to Paragraph (a)--RFG Covered Areas Under 42 U.S.C. 7545(k)(10)(D)
----------------------------------------------------------------------------------------------------------------
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)--Additional RFG Covered Areas Under 42 U.S.C. 7545(k)(10)(D)
----------------------------------------------------------------------------------------------------------------
Area designation State or district Counties Independent cities
----------------------------------------------------------------------------------------------------------------
Washington, DC-Maryland-Virginia... District of Columbia.. Washington.................
Maryland.............. Calvert, Charles,
Frederick, Montgomery,
Prince George's.
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\.
[[Page 78486]]
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)--RFG Covered Areas Under 42 U.S.C. 7545(k)(6)(A)(i)
----------------------------------------------------------------------------------------------------------------
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 78487]]
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)--RFG Covered Areas Under 42 U.S.C.
7545(k)(6)(B)(i)(I)
------------------------------------------------------------------------
State Counties
------------------------------------------------------------------------
Maine............................. Androscoggin, Cumberland, Kennebec,
Knox, Lincoln, Sagadahoc, York.
------------------------------------------------------------------------
Sec. 1090.290 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 will become 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 do all the following:
(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 required 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 required by 42 U.S.C. 7545(k)(6)(B)(i). EPA must do all the
following:
(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 required 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 a 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 either the removal of an RFG opt-in area (or portion
of an RFG opt-in area), or the removal of a covered area (or portion of
a covered area) under 42 U.S.C. 7545(k)(10)(D) that meets the
[[Page 78488]]
criteria in paragraph (c) of this section, from the list of RFG covered
areas in Sec. 1090.285 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 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 the governor's authorized representative, and must include all the
following:
(i) A geographic description of each RFG area (or portion of each
RFG area) that is covered by the request.
(ii) A description of all the means 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 an RFG area 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 the governor's 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, or the governor's authorized representative, 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, or the governor's authorized representative, 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 an RFG opt-out request and its effective date.
(5) Upon the effective date for the removal of an RFG area (or
portion of an RFG 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.
1090.285.
Sec. 1090.295 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 RVP 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 the
governor's 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) that is covered by the request.
(2) A description of all the means 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 the governor's 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 RVP
standard as requested by the governor, or the governor's authorized
representative, 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 RVP standard as requested by the governor, or the
governor's authorized representative, 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 RVP 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
[[Page 78489]]
subject to the federal 7.8 psi RVP standard in Sec. 1090.215(a)(2).
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 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) A diesel fuel manufacturer or diesel fuel additive manufacturer
must demonstrate compliance with the standards in this subpart by
measuring fuel parameters in accordance with subpart N 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 does not meet any standard
set forth in this subpart.
(2) Notwithstanding paragraph (e)(1) of this section, an importer
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 each new batch of diesel fuel under
Sec. 1090.1000(c) and demonstrates that it complies with the standards
in this subpart by measuring fuel parameters in accordance with subpart
N of this part before custody or title to each new batch of diesel fuel
is transferred.
(f) No fuel or fuel additive manufacturer may introduce into
commerce diesel fuel or diesel fuel additives that are not
``substantially similar'' under 42 U.S.C. 7545(f)(1) or permitted under
a waiver granted under 42 U.S.C. 7545(f)(4).
(g) Distillate global marine fuel that does not qualify for an
exemption under Sec. 1090.650 is subject to the standards,
requirements, and prohibitions that apply for ULSD under this part.
(h) 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), 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 of 35 volume percent.
Sec. 1090.310 Diesel fuel additives standards.
(a) Except as specified in paragraph (b) and (c) of this section,
diesel fuel additives blended into diesel fuel that is subject to the
standards in Sec. 1090.305 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 diesel fuel in a quantity less than
1.0 volume percent of the resultant mixture of additive and diesel
fuel.
(2) The PTD for the diesel fuel additive complies with the
requirements in Sec. 1090.1120(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, ECA marine fuel, and jet fuel
provisions.
Heating oil, kerosene, ECA marine fuel, and jet fuel must not be
sold for use in motor vehicles or nonroad equipment and are not subject
to the ULSD standards in Sec. 1090.305 unless also designated as ULSD
under Sec. 1090.1015(a).
Sec. 1090.320 500 ppm LM diesel fuel standards.
(a) Overview. 500 ppm LM diesel fuel produced or distributed by a
transmix processor or pipeline operator under Sec. 1090.515 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).
Sec. 1090.325 ECA marine fuel standards.
(a) Overview. Except as specified in paragraph (c) of this section,
ECA marine fuel must meet the per-gallon standards of this section.
(b) Sulfur standard. Maximum sulfur content of 1,000 ppm.
(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 exempts or excludes the vessel
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 Gasoline produced from blending transmix into PCG.
(a) Applicability. (1) Except as specified in paragraph (a)(2) of
this section, a transmix blender that blends transmix into PCG must
comply with the requirements of this section.
(2) 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
requirements in this section.
(b) Requirements. (1) The distillation end-point of the resultant
transmix-blended gasoline must not exceed 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 that meets the requirements of paragraph (c) of this
section.
(5) In the event that the test result for any sample collected
under the quality assurance program specified in
[[Page 78490]]
paragraph (c) of this section indicates that the gasoline does not
comply with any of the applicable standards in this part, the transmix
blender must do all the following:
(i) Immediately take steps to stop the sale of the gasoline that
was sampled.
(ii) Take reasonable steps to determine the cause of the
noncompliance and prevent future instances of noncompliance.
(iii) Notify EPA of the noncompliance.
(iv) 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.
(c) Quality assurance program. (1) The quality assurance program
must be designed to assure that the type and amount of transmix blended
into PCG will not cause violations of the applicable fuel quality
standards.
(2) Except as specified in paragraph (c)(3) of this section, as a
part of the quality assurance program, a transmix blender must collect
samples of gasoline after blending transmix and test the samples to
ensure the end-point temperature of the resultant transmix-blended
gasoline does not exceed 437 degrees Fahrenheit, using one of the
following sampling methods:
(i) For transmix that is blended in a tank (including a tank on a
barge), collect a representative sample of the resultant transmix-
blended gasoline following each occasion transmix is blended.
(ii) For transmix that is blended by a computer controlled in-line
blending system, the transmix blender must collect composite samples of
the resultant transmix-blended gasoline at least twice each calendar
month during which transmix is blended.
(3) Any transmix blender may petition EPA for approval of a quality
assurance program that does not include the minimum sampling and
testing requirements of paragraph (c)(2) 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:
(i) 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.
(ii) 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.
(iii) A transmix blender that petitions 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.
Sec. 1090.505 Gasoline produced from TGP.
(a) General provisions. (1) A transmix processor or blending
manufacturer that produces gasoline from TGP must meet the requirements
of this section.
(2) A transmix processor must not use any feedstock other than
transmix to produce TGP.
(3) A transmix processor or blending manufacturer 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. A transmix processor or blending
manufacturer may also blend fuel additives into gasoline in accordance
with Sec. Sec. 1090.260 and 1090.265.
(b) Demonstration of compliance with sulfur per-gallon standard.
(1) A transmix processor or blending manufacturer that produces
gasoline with TGP must meet one of the following sulfur standards for
each batch of gasoline they produce, as applicable:
(i) Each batch of gasoline produced from only TGP or both TGP and
PCG must comply with the downstream sulfur per-gallon standard in Sec.
1090.205(c).
(ii) 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).
(2) A transmix processor or blending manufacturer that produces
gasoline with TGP must demonstrate compliance with the applicable
sulfur standard in paragraph (b)(1) of this section by measuring the
sulfur content of each batch of gasoline they produce in accordance
with subpart N of this part.
(c) Demonstration of compliance with sulfur and benzene average
standards. (1) A transmix processor or blending manufacturer that
produces gasoline with TGP must exclude TGP and PCG used to produce
gasoline under the provisions of this section from their compliance
calculations to demonstrate compliance with the sulfur and benzene
average standards in Sec. Sec. 1090.205(a) and 1090.210(a) and (b),
respectively. A transmix processor or blending manufacturer that
exclusively produces gasoline from only TGP or both TGP and PCG is
deemed to be in compliance with the sulfur and benzene average
standards in Sec. Sec. 1090.205(a) and 1090.210(a) and (b),
respectively.
(2) A transmix processor or blending manufacturer that produces
gasoline with TGP must include all blendstocks other than TGP and PCG
in their compliance calculations to demonstrate compliance with the
sulfur and benzene average standards in Sec. Sec. 1090.205(a) and
1090.210(a) and (b), respectively.
(3) A transmix processor or blending manufacturer that produces
gasoline by adding blendstock to TGP must comply with Sec. 1090.1325.
(d) Demonstration of compliance with RVP standard. A transmix
processor or blending manufacturer that produces gasoline with TGP 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 N of this part.
(e) Distillation point determination. A transmix processor or
blending manufacturer that produces gasoline with TGP must determine
the following distillation parameters for each batch of gasoline they
produce in accordance with subpart N of this part:
(1) T10.
(2) T50.
(3) T90.
(4) End-point.
(5) Distillation residue.
Sec. 1090.510 Diesel and distillate fuel produced from TDP.
(a) A transmix processor must not use any feedstock other than
transmix to produce TDP.
(b) A transmix processor must demonstrate that each batch of diesel
fuel or distillate fuel produced from TDP meets the applicable standard
in subpart D of this part and must comply with all other requirements
applicable to a diesel fuel or distillate fuel manufacturer under this
part.
(c) A transmix processor that produces 500 ppm LM diesel fuel from
[[Page 78491]]
TDP must also comply with the requirements in Sec. 1090.515.
Sec. 1090.515 500 ppm LM diesel fuel produced from TDP.
(a) Applicability. A transmix processor that produces 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. A transmix processor may only
use the following components to produce 500 ppm LM diesel fuel:
(1) TDP.
(2) ULSD.
(3) Diesel fuel additives that comply with the requirements in
Sec. 1090.310.
(c) Volume requirements. A party that handles 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) 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 or marine engines that are not required to use ULSD under 40
CFR 1033.815 or 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. A transmix processor or distributor
must segregate 500 ppm LM diesel fuel from other fuels except as
follows:
(1) A pipeline operator 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) A WPC or retailer 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 resultant
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 in order to comply with the segregation requirement in
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 will handle the 500 ppm LM diesel
fuel through to the ultimate consumer.
(4) Identify all ultimate consumers that will be 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. 1090.520 Handling practices for pipeline interface that is not
transmix.
(a) Subject to the limitations in paragraph (b) of this section, a
pipeline operator 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, a pipeline operator must 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, a pipeline operator must not cut
pipeline interface from a batch of RFG shipped adjacent to a batch of
conventional gasoline into the batch of RFG.
Subpart G--Exemptions, Hardships, and Special Provisions
Sec. 1090.600 General provisions.
(a) Gasoline, diesel fuel, or IMO marine fuel subject to an
exemption under this subpart is exempt from the standards and
provisions of this part as specified in this subpart.
(b) Fuel that does not meet 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 or 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 or 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 that meet the requirements of
subpart L 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 dispenser stand, fueling
truck, or tank that is labeled with the appropriate designation of the
fuel.
(4) It must 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
[[Page 78492]]
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 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 that the exemption is for an appropriate R&D
purpose.
(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.
(5) Meet the requirements specified in paragraphs (c) and (d) of
this section.
(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 that meets the requirements of subparts C and D of
this part, as applicable, and how fuel dispensers will be labeled to
ensure that the fuel is not dispensed for use in motor vehicles or
nonroad engines, vehicles, or equipment, including locomotive or marine
engines, that are part of the R&D test program.
(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 (c), 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 the requirements of subpart L of this part.
(2) The fuel must be designated as exempt fuel by the fuel
manufacturer or supplier, as applicable.
(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 retail outlet or 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 approval 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 an approval for 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 with the requirements of this section.
(3) 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.
(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 on any fuel dispenser from which the 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 or marine engines, except for those used only in aircraft or
in sanctioned racing events.
[[Page 78493]]
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 ECA 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 that meet the requirements of
subpart L of this part.
(d) The fuel is completely segregated from non-exempt fuel at all
points 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
segregated from fuel that is not California gasoline or diesel fuel at
all points in the distribution system.
(3) Except for as specified in paragraph (d) or (e) of this
section, 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 L 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 M of this part.
(6) California gasoline or diesel fuel must 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 must do one of the following:
(1) Comply with the sampling and testing provisions in subpart N of
this part, as applicable.
(2) Sample and test using methods approved in Title 13 of the
California Code of Regulations.
(3) Sample and test per a current and valid protocol agreement
between the fuel manufacturer and the California Air Resources Board or
by Executive Order from the California Air Resources Board. Such
protocols or Executive Orders must be provided to EPA upon request.
(d) California gasoline used outside of California. California
gasoline may be used in any part of the United States outside of the
state of California if the manufacturer or distributor of the
California gasoline does one of the following:
(1) Recertifies the California gasoline as gasoline under this part
and includes the recertified gasoline in their average standard
compliance calculations.
(2) Designates the California gasoline as gasoline under this part
without recertification and does all the following:
(i) Demonstrates that the fuel meets all applicable requirements
for California reformulated gasoline under Title 13 of the California
Code of Regulations.
(ii) Properly redesignates the fuel under Sec.
1090.1010(b)(2)(vi).
(iii) Generates PTDs under subpart L of this part.
(iv) Keeps records under subpart M of this part.
(v) Does not include the California gasoline in their average
standard compliance calculations.
(e) California diesel used outside of 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 the fuel does all the following:
(1) The manufacturer or distributor properly redesignates the fuel
under Sec. 1090.1015(b)(3)(iii).
(2) The manufacturer or distributor generates PTDs under subpart L
of this part.
(3) The manufacturer or distributor keeps records under subpart M
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 that meet the
requirements of subpart L of this part.
(d) The summer gasoline is completely segregated from non-exempt
gasoline at all points 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., 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 temporary shortfalls in the supply of the
fuel in a state or region of the United States for which the shortfall
is 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.
[[Page 78494]]
(3) The refiner shows how compliance will be achieved as
expeditiously as possible.
(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 and accurate 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. 1090.260.
(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.
(a) 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:
(1) The fuel, fuel additive, or regulated blendstock is designated
for export by the fuel manufacturer, fuel additive manufacturer, or
regulated blendstock producer.
(2) The fuel, fuel additive, or regulated blendstock designated for
export is accompanied by PTDs that meet the requirements of subpart L
of this part.
(3) The fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer keeps records that demonstrate that the fuel, fuel
additive, or regulated blendstock was ultimately exported from the
United States.
(4) The fuel, fuel additive, or regulated blendstock is completely
segregated from non-exempt fuels, fuel additives, and regulated
blendstocks from the point the fuel, fuel additive, or regulated
blendstock is designated for export to the point where it is ultimately
exported from the United States.
(5) Fuel, fuel additive, or regulated blendstock certified and
designated for export may be certified for use in the United States if
all the applicable requirements of this part are met.
(b) 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) Exempt distillate global marine fuel under paragraph (a) of
this section must meet all the following requirements:
(1) The fuel must not exceed 0.50 weight percent sulfur (5,000
ppm).
(2) The fuel must be accompanied by PTDs as specified in Sec.
1090.1115.
(3) The fuel must be designated as specified in Sec. 1090.1015.
(4) The fuel must be segregated from non-exempt fuel at all points
in the distribution system.
(5) The fuel must not be used in vehicles, engines, or equipment
other than those referred to in paragraph (a) of this section.
(c)(1) Fuel that does not meet 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 M of this part must 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, a gasoline manufacturer 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)(2), 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] TR04DE20.000
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] TR04DE20.001
(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] TR04DE20.002
(b) Compliance with the benzene average standards. For each of
their facilities, a gasoline manufacturer must 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:
CBVy = Btot,y + DBz,(y-1) +
DBz_Oxy_Total - CBz
Where:
CBVy = Compliance benzene value for compliance period
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.
[[Page 78495]]
DBz,(y-1) = Benzene deficit from the previous
compliance period, per Sec. 1090.715(a)(2), in benzene gallons.
DBz_Oxy_Total = The 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] TR04DE20.003
Vi = The volume of gasoline produced or imported in batch
i, in gallons.
Bi = The benzene content of batch i, in volume percent.
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] TR04DE20.004
(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] TR04DE20.005
(3) Average benzene concentration calculation. The average benzene
concentration is determined as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.006
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 compliance period y if the following equation is true:
Ba,y <= 1.30 vol%
(5) Rounding and reporting benzene values. (i) The total amount of
benzene produced, as calculated in paragraph (b)(1)(ii) of this
section, must be rounded to the nearest whole benzene gallon in
accordance with Sec. 1090.50.
(ii) The average benzene concentration, as 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 content and benzene
content in compliance calculations under this subpart.
(d) Inclusions. A gasoline manufacturer 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 under Sec. 1090.1320(a)(1), include the
PCG batch as a batch with a negative volume, positive sulfur content,
and positive benzene content and include the new batch of gasoline as a
batch with a positive volume, positive sulfur content, and positive
benzene content in compliance calculations under this section. Any
negative compliance sulfur value or compliance benzene value must be
reported as zero and not as a negative result.
(ii) For PCG by addition under Sec. 1090.1320(a)(2), include only
the blendstock added to make the new batch of gasoline as a batch with
a positive volume, positive sulfur content, and positive benzene
content 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)(i) 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. 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.
(ii) For PCG by subtraction under Sec. 1090.1320(a)(1), include
PCG in the compliance period in which it was blended with blendstock.
This may necessitate reporting a portion of the volume of PCG received
in one compliance period as a separate PCG batch in the following
compliance period.
(e) Exclusions. A gasoline manufacturer must exclude the following
products from their compliance calculations:
(1) Gasoline that was not produced by the gasoline manufacturer.
(2) Blendstock, unless the 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(b).
(5) TGP.
(6) GTAB that meets the requirements in Sec. 1090.1615(a).
(7) Gasoline imported by truck or rail using the provisions of
Sec. 1090.1610 to meet the alternative per-gallon standards of
Sec. Sec. 1090.205(d) and 1090.210(c).
(8) Gasoline exempt 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, a
gasoline manufacturer must comply with average standards at the
individual facility level.
(b) A gasoline importer must comply with average standards at the
company level, except that aggregation of all import facilities within
a PADD as a single facility is required for compliance with the maximum
benzene average standard in Sec. 1090.210(b).
Sec. 1090.710 Downstream oxygenate accounting.
The requirements of this section apply to BOB for which a gasoline
manufacturer accounts for the effects of the oxygenate blending that
occurs downstream of the fuel manufacturing facility in the gasoline
manufacturer's average standard compliance calculations under this
subpart. This section also includes requirements for oxygenate blenders
to ensure that oxygenate is added in accordance with the blending
instructions specified by the gasoline manufacturer in order to ensure
fuel quality standards are met.
(a) Provisions for gasoline manufacturers. In order to account for
the effects of oxygenate blending downstream, a gasoline manufacturer
must meet all the following requirements:
(1) Produce or import BOB such that the gasoline continues to meet
the applicable gasoline standards in subpart C of this part after the
addition of the specified type and amount of oxygenate.
[[Page 78496]]
(2) For each batch of BOB produced or imported, create a hand blend
in accordance with Sec. 1090.1340 and determine the properties of the
hand blend using the methods specified in subpart N of this part.
(3) Participate in the NSTOP specified in Sec. 1090.1450 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 on the PTD for the BOB each oxygenate type and amount
(or range of amounts) for which the hand blend was certified for
compliance under Sec. 1090.1340.
(6) Participate in the NFSP under subpart O of this part.
(b) Requirements for oxygenate blenders. An oxygenate blender 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 must not include the volume, sulfur content, 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
recertify 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. A person who recertifies BOB for use as gasoline without the
addition of the specified type and amount of oxygenate is a gasoline
manufacturer and must meet all applicable requirements for a gasoline
manufacturer 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
(a)(2) of this section for benzene.
(1) The sulfur deficit incurred is determined as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.007
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] TR04DE20.008
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)(i), 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) A gasoline manufacturer 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) A gasoline manufacturer that incurs a deficit under this
section must satisfy that deficit and demonstrate compliance with the
annual average standards 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 a gasoline manufacturer 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. A gasoline manufacturer may also bank credits for
future use, transfer credits to another facility within the 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 must
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 incurring a compliance deficit under Sec. 1090.715.
(3) Credits must not be used to meet per-gallon standards.
(4) Credits must not be used to meet the maximum benzene average
standard in Sec. 1090.210(b).
(5) Credits may only be used if the gasoline manufacturer owns them
at the time of use.
(d) Credit reporting. A gasoline manufacturer that generates,
transacts, or uses credits under this subpart must report to EPA as
specified in Sec. 1090.905 using forms and procedures specified by
EPA.
(e) Part 80 credit use. Valid credits generated under 40 CFR
80.1615 and 80.1290 may be used by a gasoline manufacturer 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) No person other than a
gasoline manufacturer may generate credits for use towards an average
standard specified in subpart C of this part.
(2) No credits may be generated for gasoline produced by any of the
following activities:
[[Page 78497]]
(i) Transmix processing.
(ii) Transmix blending.
(iii) Oxygenate blending.
(iv) Certified butane blending.
(v) Certified pentane blending.
(vi) 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] TR04DE20.009
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] TR04DE20.010
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)(i), 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. A gasoline manufacturer may only
generate credits after they have finished producing or importing
gasoline for the compliance period.
(f) Credit generation reporting. A gasoline manufacturer that
generates credits under this section must report to EPA all credit
generation information as specified in Sec. 1090.905 using forms and
procedures specified by EPA.
Sec. 1090.730 Credit transfers.
A gasoline manufacturer may only transfer or 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 in accordance with the
limitations on credit use specified in Sec. 1090.720(c).
(c) Any credit transfer must take place no later than the deadline
specified in Sec. 1090.900(c) following the compliance period in which
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'') must 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 year(s) 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 must 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 must not be used to achieve compliance with an
average standard under this part, 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 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) A gasoline manufacturer 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.
[[Page 78498]]
(2) A gasoline manufacturer must comply with applicable
requirements of this part and incur deficits to be included in their
compliance calculations in Sec. 1090.700 for each facility at which
the gasoline manufacturer recertifies BOB.
(3) Unless otherwise required under this part, a gasoline
manufacturer that recertifies 1,000,000 or less gallons of BOB under
this section at a facility does not need to obtain credits to satisfy
deficits incurred under this section or arrange for an auditor to
conduct audits under subpart S of this part for that facility. The
gasoline manufacturer must still comply with all other applicable
provisions of this part (e.g., register and submit reports under
subparts I and J of this part, respectively).
(4) A party that only recertifies BOB that contains a greater
amount of a specified oxygenate (e.g., a party adds 15 volume percent
DFE instead of 10 volume percent to an E10 BOB) or a different
oxygenate at an equal or greater amount (e.g., a party adds 16 volume
percent isobutanol instead of 10 volume percent to an E10 BOB) does not
incur deficits under this section, does not need to submit reports
under subpart J of this part, and does not need to arrange for an
auditor to conduct an audit under subpart S of this part. The party
must still comply with all other applicable provisions of this part
(e.g., register and keep records under subparts I and M of this part,
respectively).
(b) A gasoline manufacturer that recertifies 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] TR04DE20.011
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.
ACTUALOxy = The volume fraction of oxygenate that was
actually added to the BOB. If no oxygenate was added to the BOB,
then ACTUALOxy = 0.
(2) Total sulfur deficit from downstream BOB recertification.
Calculate the total sulfur deficit from downstream BOB recertification
for each facility as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.012
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] TR04DE20.013
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.
ACTUALOxy = The volume fraction of oxygenate that was
actually added to the BOB. If no oxygenate was added to the BOB,
then ACTUALOxy = 0.
(4) Total benzene deficit from downstream BOB recertification.
Calculate the total benzene deficit from downstream BOB recertification
for each facility as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.014
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) A gasoline manufacturer does not incur a deficit, nor may they
generate
[[Page 78499]]
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 must not be carried forward
under Sec. 1090.715.
Sec. 1090.745 Informational annual average calculations.
(a) A gasoline manufacturer must calculate and report annual
average sulfur and benzene concentrations for each of their facilities
as specified in this section. The values calculated and reported under
this section are not used to demonstrate compliance with average
standards under this part.
(b) A gasoline manufacturer must calculate and report their
unadjusted average sulfur concentration as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.015
Where:
Sa,y = The facility unadjusted average sulfur
concentration for compliance period y, in ppm. Round and 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) A gasoline manufacturer must calculate and report their net
average sulfur concentration as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.016
Where:
SNET,y = The facility net average sulfur concentration
for compliance period y, in ppm. Round and report SNET,y
to two decimal places.
CSVy = Compliance sulfur value for compliance period y,
per Sec. 1090.700(a)(1), in ppm-gallons.
(d) A gasoline manufacturer must calculate and report their net
average benzene concentration as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.017
Where:
BNET,y = The facility net average benzene concentration
for compliance period y, in volume percent benzene. Round and report
BNET,y to two decimal places.
CBVy = Compliance benzene value for compliance period y,
per Sec. 1090.700(b)(1)(i), in benzene gallons.
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 that are part of
the 500 ppm LM fuel distribution chain under a compliance plan
submitted under Sec. 1090.515(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, a party not currently registered with EPA must register
with EPA no later than 60 days in advance of the first date that such
party engages in any activity under this part requiring registration
under paragraph (a) of this section.
(2) Existing registrants. Any party that is already registered with
EPA under 40 CFR part 80 as of January 1, 2021, is deemed to be
registered for purposes of this part, except that such party is
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) RCO submission. Registration information must be submitted by
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.
(e) Forms and procedures for registration. All registrants must use
forms and procedures specified by EPA.
(f) Company and facility identification. EPA will provide
registrants with company and facility identifiers to be used for
recordkeeping and reporting under this part.
(g) English language. Registration information submitted to EPA
must be in English.
Sec. 1090.805 Contents of registration.
(a) General information required for all registrants. A party
required to register under this part must submit all the following
general information to EPA:
(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.
(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, email address, 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 an importer, 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
[[Page 78500]]
addition to the information in paragraph (a) of this section, a
certified pentane producer 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 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 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.
(4) Will still be required to meet any applicable requirements
under this part (e.g., the recordkeeping provisions under subpart M 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, or any of a party's facilities, 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 (42
U.S.C. 7414 or 7542) 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 under
subpart M 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, EPA may deactivate the
registration of the party without any notice to the party. EPA will
provide written notification to the RCO identifying the reason(s) 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 M 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 the 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 company
or 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 company or 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.
[[Page 78501]]
(3) Reported volumes must be temperature-corrected in accordance
with Sec. 1090.1350(d).
(4) Report values as specified in Sec. 1090.1335(e).
(b) English language. All reports submitted under this subpart must
be submitted in English.
(c) Report deadlines. All annual, batch, and credit transaction
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 paragraph (a)(4) in
Sec. 1090.925.
(d) RCO submission. Reports must be signed and submitted by an RCO
or their delegate of the RCO.
Sec. 1090.905 Annual, batch, and credit transaction reporting for
gasoline manufacturers.
(a) Annual compliance demonstration for sulfur. For each compliance
period, a gasoline manufacturer must submit a report for each of their
facilities 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:
(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 in order to administer
reporting systems.
(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 concentration, per Sec. 1090.745(c),
in ppm.
(vii) Any other information as EPA may require in order to
administer reporting systems.
(b) Annual compliance demonstration for benzene. For each
compliance period, a gasoline manufacturer must submit a report for
each of their facilities 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 in order to administer
reporting systems.
(2) Facility-level reporting. For each fuel manufacturing facility
or importer, as applicable:
(i) The EPA-issued company and facility identifiers.
(ii) The compliance benzene value, per Sec. 1090.700(b)(1)(i), 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. For an importer, report the average benzene
concentration for each aggregated import facility.
(v) The net average benzene concentration, 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 in order to
administer reporting systems.
(c) Batch reporting. A gasoline manufacturer must report the
following information for each of their facilities on a per-batch basis
for gasoline and gasoline regulated blendstocks:
(1) For all gasoline for which the gasoline manufacturer has not
accounted for oxygenate added downstream under 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 as RFG, CG, RFG ``Intended for
Oxygenate Blending'', or CG ``Intended for Oxygenate Blending''.
(vi) The tested sulfur content of the batch separately for per-
gallon and average compliance, 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.
(viii) For all batches of summer gasoline:
(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. If the gasoline is Summer RFG that is designated as
``Intended for Oxygenate Blending'' under Sec. 1090.1010(a)(4), report
the tested RVP for the hand blend.
(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 for which the gasoline manufacturer has accounted for
oxygenate added downstream under Sec. 1090.710:
(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
[[Page 78502]]
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 a gasoline manufacturer
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 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. If the PCG is a BOB, report
the tested sulfur content of the hand blend prepared under Sec.
1090.1340.
(G) The tested benzene content of the batch, as a volume
percentage, and the test method used to measure the benzene content. If
the PCG is a BOB, report the tested benzene content of the hand blend
prepared under Sec. 1090.1340.
(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(s) added to PCG by a gasoline manufacturer
complying by addition under Sec. 1090.1320(a)(2), report each
blendstock as a separate batch and all the following:
(i) For the blendstock, the sulfur content and benzene content of
the batch.
(ii) For batches produced by adding blendstock to PCG, the sulfur
content, oxygenate type and amount (unless not required under Sec.
1090.1310(e)), and for summer gasoline, RVP, of the batch.
(5) For certified butane blended by a certified butane blender or
certified pentane blended by a certified pentane blender:
(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 volume of certified butane or certified pentane blended, 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 certified butane or certified
pentane supplier.
(F) The sulfur content of the batch, in ppm, provided by the
certified butane or certified pentane supplier.
(G) The benzene content of the batch, in volume percent, provided
by the certified butane or certified pentane supplier.
(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) For a new batch of gasoline (e.g., a blended gasoline
containing certified butane and PCG) that is summer gasoline or summer
BOB, the tested RVP of the batch, in psi, and the test method used to
measure the RVP.
(6) For gasoline produced by adding any blendstocks to TGP:
(i) For each batch of gasoline produced with TGP, the sulfur
content and for summer gasoline, RVP, of the batch.
(ii) For blendstocks added to TGP, a transmix processor or blending
manufacturer must treat the TGP like PCG and report 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) For each batch of gasoline produced by a transmix processor or
blending manufacturer from only TGP or both TGP and PCG under Sec.
1090.505:
(i) The EPA-issued company and facility identifiers.
(ii) The batch number.
(iii) The date the batch was produced.
(iv) The batch volume, in gallons.
(v) The designation of the gasoline.
(vi) The tested sulfur content of the batch, in ppm, and the test
method used to measure the sulfur content.
(vii) For summer gasoline:
(A) The applicable RVP standard in Sec. 1090.215.
(B) The tested RVP of the batch, in psi, and the test method used
to measure the RVP.
(9) Any other information as EPA may require in order to administer
reporting systems.
(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 in order to administer
reporting systems.
[[Page 78503]]
Sec. 1090.910 Reporting for gasoline manufacturers that recertify BOB
to gasoline.
A party that recertifies BOB under Sec. 1090.740 must report the
information of this section, as applicable.
(a) Batch reporting. (1) A party that recertifies a BOB under Sec.
1090.740 with less oxygenate than specified by the BOB manufacturer
must report the following for each batch:
(i) The EPA-issued company and facility identifiers for the
recertifying party.
(ii) The batch number assigned by the recertifying party.
(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 0.68 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) A party that recertifies a BOB under Sec. 1090.740 with more
oxygenate than specified by the BOB manufacturer does not need to
report the batch.
(b) Annual sulfur and benzene compliance reporting. A party 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. A party 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.
An oxygenate producer, for each of their production facilities, or
an 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. 1090.275.
(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.
(d) Any other information as EPA may require in order to administer
reporting systems.
Sec. 1090.920 Reports by certified pentane producers.
A certified pentane producer 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 in order to administer
reporting systems.
Sec. 1090.925 Reports by independent surveyors.
(a) General procedures. An independent surveyor must meet the
following requirements:
(1) Electronically submit any plans, notifications, or reports
required under this part using forms and procedures specified by EPA.
(2) For each report required under this section, affirm that the
survey was conducted in accordance with an EPA-approved survey plan and
that the survey results are accurate.
(3) Include EPA-issued company identifiers on each report required
under this section.
(4) Submit quarterly reports required under paragraphs (b) and (d)
of this section by the following deadlines:
Table 1 to Paragraph (a)(4)--Quarterly Reporting Deadlines
----------------------------------------------------------------------------------------------------------------
Calendar quarter Time period covered Quarterly report deadline
----------------------------------------------------------------------------------------------------------------
Quarter 1............................... January 1-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) NFSP quarterly reporting. An independent surveyor conducting
the NFSP under Sec. 1090.1405 must submit the following information
quarterly, as applicable:
(1) For each retail outlet sampled by the independent surveyor:
(i) The identification information for the retail outlet, as
assigned by the surveyor in a consistent manner and as specified 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.
(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.
[[Page 78504]]
(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, 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 in order to administer
reporting systems.
(c) NFSP annual reporting. An independent surveyor conducting the
NFSP under Sec. 1090.1405 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 in order to administer
reporting systems.
(d) NSTOP quarterly reporting. An independent surveyor conducting
the NSTOP under Sec. 1090.1450 must submit the following information
quarterly, as applicable:
(1) For each gasoline manufacturing facility sampled by the
independent surveyor:
(i) The EPA-issued company and facility identifiers for the
gasoline manufacturer and the gasoline manufacturing facility.
(2) For each gasoline sample collected by the independent surveyor:
(i) The designation of the gasoline.
(ii) The date and time the independent surveyor collected the
sample.
(iii) The batch number or the sample identification number as
assigned by the independent surveyor in a consistent manner and as
specified in the survey plan.
(iv) A description of any instance in which the gasoline
manufacturer did not follow the applicable sampling procedures.
(v) The test results for the sample, and the test methods used, as
determined by the independent surveyor, including the following
parameters:
(A) The sulfur content, in ppm.
(B) The benzene content, in volume percent.
(C) The RVP in psi, if tested.
(vi) The test results for the sample, and the test methods used, as
determined by the gasoline manufacturer, including the following
parameters:
(A) The sulfur content, in ppm.
(B) The benzene content, in volume percent.
(C) The RVP in psi, if tested.
(vii) If available, the test results for the sample, and the test
methods used, as determined by EPA's National Vehicle and Fuel
Emissions Laboratory, including the following parameters:
(A) The sulfur content, in ppm.
(B) The benzene content, in volume percent.
(C) The RVP in psi, if tested.
(viii) The determined site precision under Sec.
1090.1450(c)(10)(i) and the test performance index under Sec.
1090.1450(c)(10)(ii) for each method and instrument that the gasoline
manufacturer used to test the sample.
(ix) The reproducibility of each method that the gasoline
manufacturer used to test the sample.
(x) Any applicable correlation equations used to compare the
gasoline manufacturer's test results to the independent surveyor's test
results.
(3) Any other information as EPA may require in order to administer
reporting systems.
Sec. 1090.930 Reports by auditors.
(a) Attest engagement reports required under subpart S of this part
must be submitted by an independent auditor registered with EPA and
associated with a company, or companies, through 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 available to the company for
which it was performed.
(c) The attest engagement must comply with subpart S of this part
and the attest engagement report must clearly identify the
methodologies followed and any findings, exceptions, and variances.
(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) The auditor must submit written acknowledgement from the RCO
that the gasoline manufacturer has reviewed the attest engagement
report.
Sec. 1090.935 Reports by diesel fuel manufacturers.
(a) Batch reporting. (1) For each compliance period, a ULSD
manufacturer must submit the following information:
(i) The EPA-issued company and facility identifiers for the ULSD
manufacturer.
(ii) The highest sulfur content observed for a batch of ULSD
produced during the compliance period on a company level, in ppm.
(iii) The average sulfur concentration 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 and Designation
Sec. 1090.1000 Batch certification requirements.
(a) General provisions. (1) A fuel manufacturer, fuel additive
[[Page 78505]]
manufacturer, or regulated blendstock producer must certify batches of
fuel, fuel additive, or regulated blendstock as specified in this
section.
(2) A fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer does not need to certify fuel, fuel additive, or
regulated blendstock that is exempt under subpart G of this part.
(3)(i) For purposes of this part, the volume of a batch is one of
the following:
(A) 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.
(B) The entire volume of a tank or vessel may be certified as a
single batch. In such cases, any heel left in the tank or vessel after
shipments of the batch becomes PCG.
(ii) If a volume of fuel, fuel additive, or regulated blendstock is
placed in a tank, certified (if not previously certified), and is not
altered in any manner, then it is considered to be the same batch even
if several shipments or transfers are made out of that tank.
(iii) Batch volumes must be temperature-corrected in accordance
with Sec. 1090.1350(d).
(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 in Sec. 1090.1337
and is produced during a period not to exceed 10 days.
(5) A fuel manufacturer must certify each batch of fuel at the
facility where the fuel is produced or at a facility that is under the
complete control of the fuel manufacturer before they transfer custody
or title of the fuel to any other person.
(6) No person may sell, offer for sale, distribute, offer to
distribute, supply, offer for supply, dispense, store, transport, or
introduce into commerce gasoline, diesel fuel, or ECA marine fuel that
is not certified under this section.
(b) Gasoline. (1) A gasoline manufacturer must certify gasoline as
specified in paragraph (b)(2) of this section prior to introduction
into commerce.
(2) To certify batches of gasoline, a gasoline manufacturer must
comply with 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 N of this part. A transmix processor 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. 1090.1020.
(iv) Designate batches of gasoline as specified in Sec. 1090.1010.
(3) PCG may be mixed with other PCG without re-certification if the
resultant mixture complies with the applicable standards in subpart C
of this part and is accurately and clearly designated under Sec.
1090.1010. Resultant 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 comply with one of the
following:
(i) Designate the resultant mixture as meeting the least stringent
RVP designation of any batch that is mixed. For example, a distributor
that 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 N of this part and designate the new batch under
Sec. 1090.1010 to reflect the RVP of the resultant 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) A diesel fuel or ECA
marine fuel manufacturer must certify diesel fuel or ECA marine fuel as
specified in paragraph (c)(2) of this section prior to introducing the
fuel into commerce.
(2) To certify batches of diesel fuel or ECA marine fuel, a diesel
fuel or ECA marine fuel manufacturer must comply with 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 N of this part. A transmix
processor 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. 1090.1020.
(iv) Designate batches of diesel fuel as specified in Sec.
1090.1015.
(d) Oxygenates. (1) An oxygenate producer must certify oxygenates
intended to be blended into gasoline as specified in paragraph (d)(2)
of this section.
(2) To certify batches of oxygenates, an oxygenate producer must
comply with 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. 1090.270 by using the applicable procedures specified in subpart
N of this part.
(iii) Assign batch numbers as specified in Sec. 1090.1020.
(iv) Designate batches of oxygenate as intended for blending with
gasoline as specified in Sec. 1090.1010(c).
(e) Certified butane. (1) A certified butane producer 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, a certified butane
producer must comply with all the following:
(i) Ensure that each batch of certified butane meets the
requirements in Sec. 1090.250 by using the applicable procedures
specified in subpart N of this part.
(A) Testing must occur after the most recent delivery into the
certified butane producer's storage tank.
(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. 1090.1010(d).
(f) Certified pentane. (1) A certified pentane producer 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, a certified pentane
producer must comply with 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. 1090.255 by using the applicable
[[Page 78506]]
procedures specified in subpart N 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. 1090.1020.
(iv) Designate batches of certified pentane as intended for
blending with gasoline as specified in Sec. 1090.1010(d).
(g) Certified ethanol denaturant. (1) A certified ethanol
denaturant producer must certify certified ethanol denaturant intended
to be used to make DFE that meets the requirements in Sec. 1090.275 as
specified in paragraph (g)(2) of this section.
(2) To certify batches of certified ethanol denaturant, a certified
ethanol denaturant producer must comply with 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. 1090.275 by using the applicable procedures
specified in subpart N of this part.
(iii) Assign batch numbers as specified in Sec. 1090.1020.
(iv) Designate batches of certified ethanol denaturant as intended
for blending with gasoline as specified in Sec. 1090.1010(e).
Sec. 1090.1005 Designation of batches of fuels, fuel additives, and
regulated blendstocks.
(a) A fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer must designate batches of fuel, fuel additive, or
regulated blendstock as specified in this subpart.
(b) A fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer must designate the fuel, fuel additive, or
regulated blendstock prior to the fuel, fuel additive, or regulated
blendstock leaving the facility where it was produced and must include
the designations on PTDs as specified in this subpart.
(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. 1090.1010 Designation requirements for gasoline and regulated
blendstocks.
(a) Designation requirements for gasoline manufacturers. A gasoline
manufacturer must accurately and clearly designate each batch of
gasoline as follows:
(1) A gasoline manufacturer must designate each batch of gasoline
as one of the following fuel types:
(i) Winter RFG.
(ii) Summer RFG.
(iii) Winter RBOB.
(iv) Summer RBOB.
(v) Winter CG.
(vi) Summer CG.
(vii) Winter CBOB.
(viii) Summer CBOB.
(ix) Exempt gasoline under subpart G of this part (including
additional identifying information).
(x) California gasoline.
(2) A gasoline manufacturer must further designate gasoline
designated as Summer CG or Summer CBOB as follows:
(i) 7.8 psi Summer CG or Summer CBOB, respectively.
(ii) 9.0 psi Summer CG or Summer CBOB, respectively.
(iii) SIP-controlled Summer CG or Summer CBOB, respectively.
(3) A CBOB or RBOB manufacturer 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(a)(5).
(4) In addition to any other applicable designation in this
paragraph (a), gasoline designed for downstream oxygenate blending for
which the gasoline manufacturer has not accounted for oxygenate added
downstream under Sec. 1090.710 must be designated as ``Intended for
Oxygenate Blending'', along with a designation indicating the type(s)
and amount(s) of oxygenate to be blended with the gasoline.
(b) Designation requirements for gasoline distributors and certain
gasoline blending manufacturers. A gasoline distributor, certified
butane blender, certified pentane blender, or party that recertifies
BOB under Sec. 1090.740 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) A distributor must accurately and clearly classify each batch
or portion of a batch of gasoline as specified by the gasoline
manufacturer in paragraph (a) of this section.
(2) Except as specified in paragraph (b)(2)(vii) of this section, a
distributor, certified butane blender, certified pentane blender, or
party that recertifies BOB under Sec. 1090.740 may redesignate a batch
or portion of a batch of gasoline without recertifying the batch or
portion of a batch as follows:
(i) Winter RFG or Winter RBOB may be redesignated as either Winter
CG or Winter CBOB.
(ii) Winter CG or Winter CBOB may be redesignated as either Winter
RFG or Winter RBOB.
(iii) Summer RFG, Summer RBOB, Summer CG, or Summer CBOB may be
redesignated without recertification 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, Summer RBOB, Summer CG, or Summer CBOB may be
redesignated without recertification as either Winter RFG, Winter RBOB,
Winter CG, or Winter CBOB.
(v) Summer CG, Summer CBOB, or any winter gasoline may be
redesignated to either Summer RFG or Summer RBOB, provided the RVP is
determined using the applicable procedures specified in subpart N of
this part and the new batch meets the RFG RVP standard specified in
Sec. 1090.215(a)(3).
(vi)(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)(vi)(A) of this section may instead be recertified as gasoline
under Sec. 1090.1000(b).
(vii) CG or RFG must not be redesignated as BOB.
(3) A distributor, certified butane blender, certified pentane
blender, or party that recertifies BOB under Sec. 1090.740 that
redesignates a batch or portion of a batch 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. An oxygenate
producer 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).
[[Page 78507]]
(d) Designation requirements for certified butane and certified
pentane. A certified butane or certified pentane producer must
accurately and clearly designate each batch of certified butane or
certified pentane as one of the following types:
(1) Certified butane.
(2) Certified pentane.
(e) Designation requirements for certified ethanol denaturant. A
certified ethanol denaturant producer must accurately and clearly
designate batches of certified ethanol denaturant as ``certified
ethanol denaturant''.
(f) Designation requirements for TGP. A transmix processor must
accurately and clearly designate any TGP that they transfer to any
other person as ``TGP''.
Sec. 1090.1015 Designation requirements for diesel and distillate
fuels.
(a) Designation requirements for diesel and distillate fuel
manufacturers. (1) Except as specified in paragraph (a)(3) of this
section, a diesel fuel or distillate fuel manufacturer must accurately
and clearly designate each batch of diesel fuel or distillate fuel as
at least one of the following fuel types:
(i) ULSD. A diesel fuel manufacturer may also designate ULSD as 15
ppm MVNRLM diesel fuel.
(ii) 500 ppm LM diesel fuel.
(iii) Heating oil.
(iv) Jet fuel.
(v) Kerosene.
(vi) ECA marine fuel.
(vii) Distillate global marine fuel.
(viii) Certified NTDF.
(ix) Exempt diesel fuel or distillate fuel under subpart G of this
part (including additional identifying information).
(2) Only a fuel manufacturer that complies with the requirements in
Sec. 1090.515 may designate fuel as 500 ppm LM diesel fuel.
(3) Any batch of diesel fuel or distillate fuel that is certified
and designated as ULSD may also be designated as heating oil, kerosene,
ECA marine fuel, jet fuel, or distillate global marine fuel if it is
also suitable for such use.
(b) Designation requirements for distributors of diesel and
distillate fuels. A distributor of diesel and distillate fuels must
accurately and clearly designate each batch of diesel fuel or
distillate fuel for which they transfer custody as follows:
(1) A distributor must accurately and clearly designate such diesel
fuel or distillate fuel by sulfur content while it is in their custody
(e.g., as 15 ppm or 500 ppm).
(2) A distributor must accurately and clearly designate such diesel
fuel or distillate fuel as specified by the diesel fuel or distillate
fuel manufacturer under paragraph (a) of this section.
(3) A distributor may redesignate batches or portions of batches of
diesel fuel 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 500 ppm LM diesel fuel, heating
oil, kerosene, ECA marine fuel, jet 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, ECA marine fuel, or jet fuel may be
redesignated as ULSD if the fuel meets the ULSD standards in Sec.
1090.305 and was designated as ULSD under paragraph (a) of this
section.
(v) 500 ppm LM diesel fuel may be redesignated as ECA marine fuel,
distillate global marine fuel, or heating oil. 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.
1090.1115) to demonstrate compliance with the 500 ppm sulfur standard
in Sec. 1090.320(b).
(vi) Fuel designated as certified NTDF may be redesignated as ULSD
without recertification if the applicable requirements of 40 CFR
80.1408 are met.
(c) ULSD designation limitation. No person may designate distillate
fuel with a sulfur content greater than the sulfur standard in Sec.
1090.305(b) as ULSD.
Sec. 1090.1020 Batch numbering.
(a) A fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer 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.
(c) A gasoline manufacturer that recertifies BOBs under Sec.
1090.740 may include up to a single month's volume as a single batch
for purposes of reporting to EPA.
Subpart L--Product Transfer Documents
Sec. 1090.1100 General requirements.
(a) General provisions. (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 to the ultimate end user at a
retail outlet or WPC facility, the transferor must provide the
transferee PTDs that include 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.
(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. 1090.1010 or distillate-related products
specified in Sec. 1090.1015.
(b) Use of codes. Except for transfers to a truck carrier,
retailer, or WPC, product codes may be used to convey the information
required under this subpart, if such codes are clearly understood by
each transferee.
(c) Part 80 PTD requirements. For fuel, fuel additive, or regulated
blendstock subject to 40 CFR part 80, subpart M, a party must also
include the applicable PTD information required under 40 CFR 80.1453.
Sec. 1090.1105 PTD requirements for exempt fuels.
(a) In addition to the information required under Sec. 1090.1100,
on each occasion when any person transfers custody or title to any
exempt fuel
[[Page 78508]]
under subpart G of this part, other than when fuel is sold or dispensed
to the ultimate end user at a retail outlet or WPC facility, the
transferor must provide 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 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. 1090.1110 PTD requirements for gasoline, gasoline additives, and
gasoline regulated blendstocks.
(a) General requirements. On each occasion when any person
transfers custody or title of any gasoline, gasoline additive, or
gasoline regulated blendstock, other than when fuel is sold or
dispensed to the ultimate end user at a retail outlet or WPC facility,
the transferor must provide the transferee PTDs that include the
following information:
(1) All applicable information required under Sec. 1090.1100 and
this section.
(2) An accurate and clear statement of the applicable designation
of the gasoline, gasoline additive, or gasoline regulated blendstock
under Sec. 1090.1010.
(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) for which the BOB was
certified under Sec. 1090.710(a)(5).
(2) Summer BOB language requirements. (i) Except as specified in
paragraph (b)(2)(ii) 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:
(A) ``9.0 psi CBOB. This product does not meet the requirements for
summer reformulated gasoline.''
(B) ``7.8 psi CBOB. This product does not meet the requirements for
summer reformulated gasoline.''
(C) ``RBOB. This product meets the requirements for summer
reformulated or conventional gasoline.''
(ii) For BOBs designed to produce a finished gasoline that must
meet an RVP 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 Sec.
1090.215(a)(1): ``9.0 psi Gasoline.''
(B) For gasoline that meets the 7.8 psi RVP standard in Sec.
1090.215(a)(2): ``7.8 psi Gasoline.''
(C) For gasoline that meets the RFG 7.4 psi RVP standard in Sec.
1090.215(a)(3): ``Reformulated Gasoline.''
(ii) For finished gasoline that meets an RVP 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 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 between 10
and 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.
[[Page 78509]]
(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. 1090.260.
(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 in Sec. 1090.265(a), the transferor must provide to
the transferee PTDs that include 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 in Sec. 1090.275, the
transferor must provide to the transferee PTDs that include 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, for the certified pentane producer, the 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 must be transferred from each party transferring certified
butane or certified pentane for use by a certified butane or certified
pentane blender to each party that receives the certified butane or
certified pentane through to the certified butane or certified pentane
blender, respectively.
(i) TGP language requirements. In addition to any other PTD
requirements of this subpart, on each occasion when any person
transfers custody or title to any TGP, the transferor must provide to
the transferee PTDs that include the following information:
(1) The following statement: ``Transmix Gasoline Product--not for
use as gasoline.''
(2) [Reserved]
Sec. 1090.1115 PTD requirements for distillate and residual fuels.
(a) General requirements. On each occasion when any person
transfers custody or title of any distillate or residual fuel, other
than when fuel is sold or dispensed to the ultimate end user at a
retail outlet or WPC facility, 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. 1090.1015 (e.g., ``ULSD'', ``500
ppm LM diesel fuel'', or ``ECA marine fuel'').
(3) If the fuel does not meet the sulfur standard in Sec.
1090.305(b) for ULSD, 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, PTDs must include the following
information:
(1) The following statement: ``500 ppm sulfur (maximum) LM diesel
fuel. For use only in accordance with a compliance plan under 40 CFR
1090.515(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, PTDs must include the following information:
(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) A party 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, a fuel supplier (i.e., the person who
transfers custody or title of marine fuel onto a vessel) must provide
bunker delivery notes to vessel operators.
(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, PTDs must
include the following information:
(1) The following statement: ``5,000 ppm sulfur (maximum)
Distillate Global Marine Fuel. 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. 1090.1120 PTD requirements for diesel fuel additives.
In addition to any other PTD requirements in this subpart, on each
occasion when 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), 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 in Sec.
1090.310(b), the transferor must provide to the transferee PTDs that
identify the additive as such, and comply with 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.''
[[Page 78510]]
(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 content 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:
(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. 1090.1125 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 Sec. 1090.10.
Subpart M--Recordkeeping
Sec. 1090.1200 General recordkeeping requirements.
(a) Length of time records must be kept. Records required under
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) PTDs. Any party that transfers custody or title of any fuel,
fuel additive, or regulated blendstock must maintain the PTDs for which
the party is the transferor or transferee.
(c) Sampling and testing. Any party that performs any sampling and
testing on any fuel, fuel additive, or regulated blendstock must keep
records of the following information:
(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, all the results must be
retained.
(4) The methodology used for any testing 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) Records demonstrating the actions taken to stop the sale of any
fuel, fuel additive, or regulated blendstock that is 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) Registration. Any party required to register under subpart I of
this part 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) Reporting. Any party required to submit reports under subpart J
of this part 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) Exemptions. Any party that produces or distributes exempt fuel,
fuel additive, or regulated blendstock under subpart G of this part
must keep the following records:
(1) Records demonstrating the 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 exempt 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, a
gasoline manufacturer must keep records for each of their facilities
that include the information in this section.
(b) Batch records. For each batch of gasoline, a gasoline
manufacturer 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 N 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. 1090.1010.
(6) The PTDs for any gasoline produced or imported.
(7) The PTDs for any gasoline received.
(c) Downstream oxygenate accounting. For BOB for which the gasoline
manufacturer has accounted for oxygenate added downstream under Sec.
1090.710, a gasoline manufacturer 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 NFSP under Sec. 1090.1405.
(3) Records that demonstrate that the gasoline manufacturer
participates in the NSTOP under Sec. 1090.1450.
(4) Compliance calculations specified in Sec. 1090.700 based on an
assumed addition of oxygenate.
(d) PCG and TGP. For new batches of gasoline produced by adding
blendstock to PCG or TGP, a gasoline manufacturer must keep records of
the following information:
(1) Records that reflect the storage and movement of the PCG or TGP
and blendstock within the fuel manufacturing facility to the point such
[[Page 78511]]
PCG or TGP is used to produce gasoline or BOB.
(2) For new batches of gasoline produced by adding blendstock to
PCG or TGP under Sec. 1090.1320(a)(1) or Sec. 1090.1325,
respectively, keep records of the following additional information:
(i) The results of tests to determine the sulfur content, benzene
content, oxygenate(s) content, and in the summer, RVP, for the PCG or
TGP and volume of the PCG or TGP when received at the fuel
manufacturing facility.
(ii) Records demonstrating which specific batches of PCG or TGP
were used in each new batch of gasoline.
(iii) Records demonstrating which blendstocks were used in each new
batch of gasoline.
(iv) Records of the test results for sulfur content, benzene
content, oxygenate(s) content, distillation parameters, and in the
summer, RVP, for each new batch of gasoline.
(3) For new batches of gasoline produced by adding blendstock to
PCG or TGP under Sec. 1090.1320(a)(2), keep records of the following
additional information:
(i) Records of the test results for sulfur content, benzene
content, oxygenate(s) content, and in the summer, RVP, of each
blendstock used to produce the new batch of gasoline.
(ii) Records of the test results for sulfur content and in the
summer, RVP, of each new batch of gasoline.
(iii) Records demonstrating which blendstocks were used in each new
batch of gasoline.
(e) Certified butane and certified pentane blenders. For certified
butane or certified pentane blended into gasoline or BOB under Sec.
1090.1320, a certified butane or certified pentane blender must keep
records of the following information:
(1) The volume of certified butane or certified pentane added.
(2) The purity and properties of the certified butane or certified
pentane specified in Sec. 1090.250 or Sec. 1090.255, respectively.
(f) Importation of gasoline treated as blendstock. For any imported
GTAB, an importer 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 or the point at which the
GTAB was certified as gasoline.
(g) ABT. A gasoline manufacturer 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 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, ECA marine
fuel, and distillate global marine fuel manufacturers.
(a) Overview. In addition to the requirements in Sec. 1090.1205, a
diesel fuel or ECA marine fuel manufacturer 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, a diesel fuel or ECA marine fuel manufacturer 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. 1090.1015.
(5) All documents and information created or used for the purpose
of batch designation under Sec. 1090.1015, including PTDs for the
batch.
(c) Distillate global marine fuel manufacturers. For distillate
global marine fuel, a distillate global marine fuel manufacturer must
keep records of the following information:
(1) The designation of the fuel as distillate global marine fuel.
(2) The PTD for the distillate global marine fuel.
Sec. 1090.1220 Recordkeeping requirements for oxygenate blenders.
(a) Overview. In addition to the requirements in Sec. 1090.1205,
an oxygenate blender that blends oxygenate into gasoline must keep
records that include the information in this section.
(b) Oxygenate blenders. For each occasion that an oxygenate blender
blends oxygenate into gasoline, the oxygenate blender 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 manufacturers. In addition to the
requirements in Sec. 1090.1205, a gasoline additive manufacturer 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) Parties that take custody of gasoline additives. 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 gasoline
additive blender 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 each case where a new
batch of additive is mixed into a storage tank from which
[[Page 78512]]
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, an oxygenate producer 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 content of the batch was determined by
analytical testing.
(b) DFE producers. In addition to the requirements of paragraph (a)
of this section, a DFE producer 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) Parties that take custody of oxygenate. All parties that take
custody of oxygenate--from the oxygenate producer through to the
oxygenate blender--must keep records of the following information:
(1) The PTD for each batch of oxygenate.
(2) [Reserved]
Sec. 1090.1235 Recordkeeping requirements for ethanol denaturant.
(a) Certified ethanol denaturant producers. In addition to the
requirements in Sec. 1090.1205, a certified ethanol denaturant
producer 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. 1090.270(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, a
gasoline detergent blender must keep records that include the
information in this section.
(b) Gasoline detergent blenders. A gasoline detergent blender must
keep records of the following information:
(1) The PTD for each detergent used.
(2) For an automated detergent blending facility, 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 a facility that uses 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 a facility that uses 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 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 a non-automated detergent blending facility, keep records
of the following information:
(i) The date of additization.
[[Page 78513]]
(ii) The volume of detergent added.
(iii) The volume of gasoline to which the detergent was added.
(iv) The actual detergent concentration, calculated as the volume
of detergent added (per paragraph (b)(3)(ii) of this section) divided
by the volume of gasoline (per 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) Overview. In addition to the requirements in Sec. 1090.1205,
an independent surveyor must keep records that include the information
in this section.
(b) Independent surveyors. An independent surveyor must keep
records of the following information, as applicable:
(1) Records related to the NFSP under Sec. 1090.1405.
(2) Records related to a geographically-focused E15 survey program
under Sec. 1090.1420(b).
(3) Records related to the NSTOP under Sec. 1090.1450.
Sec. 1090.1250 Recordkeeping requirements for auditors.
(a) Overview. In addition to the requirements in Sec. 1090.1205,
an auditor must keep records that include the information in this
section.
(b) Auditors. An auditor must keep records of the following
information:
(1) Documents pertaining to the performance of each audit performed
under subpart S of this part, including all correspondence between the
auditor and the fuel manufacturer.
(2) Copies of each attestation report prepared and all related
records developed to prepare the attestation report.
Sec. 1090.1255 Recordkeeping requirements for transmix processors,
transmix blenders, transmix distributors, and pipeline operators.
(a) Overview. In addition to the requirements in Sec. 1090.1205, a
transmix processor, transmix blender, transmix distributor, or pipeline
operator must keep records that include the information in this
section.
(b) Transmix. (1) A transmix processor or transmix distributor must
keep records that reflect the results of any sampling and testing
required under subpart F or M of this part.
(2) A transmix processor 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. 1090.505.
(3) A transmix processor that adds blendstock to TGP or PCG must
keep records under Sec. 1090.1210(d).
(4) A transmix blender must keep records showing compliance with
the quality assurance program and/or sampling and testing requirements
in Sec. 1090.500, 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.
(c) 500 ppm LM diesel fuel. A manufacturer or distributor 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. 1090.515(g).
(2) Documents demonstrating how the party complies with each
applicable element of the compliance plan under Sec. 1090.515(g).
(3) Documents and copies of calculations used to determine
compliance with the 500 ppm LM diesel fuel volume requirements under
Sec. 1090.515(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.
(d) Pipeline operators. A pipeline operator must keep records that
demonstrate compliance with the interface handling practices in Sec.
1090.520.
Subpart N--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 a 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 acting on behalf of a regulated party to demonstrate
compliance with requirements under this part must meet the requirements
of this subpart in the same way that the party needs to meet those
requirements for its own testing. The regulated party and the third
party will both be liable for any violations arising from the third
party's failure to meet the requirements of this subpart.
(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 Q of this part has provisions related to importation,
including additional provisions that specify how to meet the sampling
and testing requirements of this subpart.
Scope of Testing
Sec. 1090.1310 Testing to demonstrate compliance with standards.
(a) Perform testing as needed to certify fuel, fuel additive, or
regulated blendstock as specified in subpart K of this part. This
section specifies additional test requirements.
[[Page 78514]]
(b) A fuel manufacturer, fuel additive manufacturer, or regulated
blendstock producer must perform the following measurements before
fuel, fuel additive, or regulated blendstock from a given batch leaves
the facility, except as specified in Sec. 1090.1315:
(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 standards and perform testing for
each batch of summer gasoline to demonstrate compliance with RVP
standards.
(c) The following testing provisions apply for gasoline, oxygenate,
certified ethanol denaturant, certified butane, and certified pentane:
(1) A gasoline manufacturer producing BOB for which oxygenate added
downstream is accounted for under Sec. 1090.710 must prepare a hand
blend as specified in Sec. 1090.1340 and perform the following
measurements:
(i) Measure the sulfur content of both the BOB and the hand blend.
(ii) Except as specified in Sec. 1090.1325(c), measure the benzene
content of the hand blend.
(iii) For Summer CG, measure the RVP of the BOB.
(iv) For Summer RFG, measure the RVP of the hand blend.
(2) A gasoline manufacturer producing gasoline for which oxygenate
added downstream is not accounted for under Sec. 1090.710 (e.g., E0 or
so-called suboctane gasoline) must perform the following measurements:
(i) Measure the sulfur content of the gasoline.
(ii) Except as specified in Sec. 1090.1325(c), measure the benzene
content of the gasoline.
(iii) For Summer CG and Summer RFG, measure the RVP of the
gasoline.
(iv) For Summer RFG that is designated as ``Intended for Oxygenate
Blending'' under Sec. 1090.1010(a)(4), create a hand blend as
specified in Sec. 1090.1340 and measure the RVP of the hand blend.
(v) For gasoline blended with oxygenate, measure the oxygenate
content of the gasoline.
(3) An oxygenate producer must measure the sulfur content of each
batch of oxygenate, except that a DFE producer may meet the alternative
requirements in Sec. 1090.1330.
(4) An ethanol denaturant producer that certifies denaturant under
Sec. 1090.1330 must measure the sulfur content of each batch of
denaturant.
(5) A certified butane or certified pentane producer must perform
sampling and testing to demonstrate compliance with purity
specifications and sulfur and benzene standards as specified in Sec.
1090.1320.
(6) A transmix processor producing gasoline from TGP must test each
batch of gasoline for parameters required to demonstrate compliance
with Sec. 1090.505 as specified in Sec. 1090.1325.
(d) A blending manufacturer 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, a gasoline manufacturer must measure such gasoline
for oxygenate and for distillation parameters (i.e., T10, T50, T90,
final boiling point, and percent residue). However, a fuel manufacturer
or transmix processor does not need to measure the oxygenate content of
gasoline if PCG, transmix, TGP, and blendstocks used to produce the
batch did not contain any oxygenates, based on the following
documentation:
(1) For PCG, documentation consists of oxygenate content identified
on PTDs.
(2) For transmix, TGP, and blendstocks, documentation consists of
affidavits or oxygenate test results from the person providing the
transmix or blendstock stating that these products do not contain
oxygenate.
Sec. 1090.1315 In-line blending.
A fuel manufacturer 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) 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 it 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. Describe clearly
which portions of your blending operation are the subject of your
waiver request.
(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. Also describe how your
procedures 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. Explain how you
will ensure that all fuel will meet all applicable per-gallon
standards. Describe any experiences from the previous 3 years where
these quality assurance procedures led you to make corrections to your
in-line blending operation. Describe how you will deal with release of
fuel that fails to meet a per-gallon standard.
(5) Describe any times from the previous 3 years that you modified
fuel after it left your facility. Describe how you modified the fuel
and why that was necessary.
(6) Describe how you will meet the auditing requirements specified
in Sec. 1090.1850 and any additional, facility-specific considerations
that relate to those auditing requirements.
(b) You must arrange for an audit of your blending operation each
calendar year as specified in Sec. 1090.1850. The audit must review
procedures and documents to determine whether measured and calculated
values properly represent the aggregate fuel properties for the blended
fuel.
(c) You must submit an updated in-line blending waiver request to
EPA 60 days before making any material change to your in-line blending
process. Examples of material changes include changing analyzer
hardware or programming, changing the location of the analyzer,
changing the piping configuration, changing the mixing control hardware
or programming logic, changing sample compositors or compositor
settings, or expanding fuel blending capacity. Changing the name of the
company or business unit is an example of a change that is not
material.
(d) 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 a refiner or blending
manufacturer that adds blendstock to PCG to produce a new batch of
gasoline.
[[Page 78515]]
Paragraph (b) of this section specifies an alternative approach for a
certified butane or certified pentane blender. Section 1090.1325
describes additional provisions that apply to a transmix processor.
(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) Determine the sulfur content,
benzene content, and oxygenate content of the PCG before blending
blendstocks to produce a new batch of gasoline as follows:
(A) Sample and test the sulfur content, benzene content, and
oxygenate content of each batch of PCG. The blending manufacturer does
not need to test PCG for oxygenate content if they can demonstrate that
the PCG does not contain oxygenates as specified in paragraph
(a)(1)(i)(C) of this section or Sec. 1090.1310(e)(1).
(B) If the PCG is a BOB, prepare a hand blend under Sec. 1090.1340
and test the hand blend for sulfur content and benzene content.
(C) The blending manufacturer may use the PCG manufacturer's
certification test results if the PCG was received directly from the
PCG manufacturer by an in-tank transfer or tank-to-tank transfer within
the same terminal as long as the results are from the PCG that is being
transferred.
(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
content, benzene content, and for summer gasoline, RVP, 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 content
and benzene content of each batch of blendstock used to produce a new
batch of gasoline from PCG using the procedures in Sec. 1090.1350. The
homogeneity requirements for gasoline specified in Sec. 1090.1337
apply to blendstock and GTAB collected with manual sampling.
(ii) Determine the volume of each batch of blendstock used to
produce the new batch of gasoline.
(iii) Determine the volume of each blended batch of gasoline, and
measure the sulfur content and for summer gasoline, RVP, for each
blended batch of gasoline using the procedures specified in Sec.
1090.1350. Testing the blended batch of gasoline for sulfur content,
however, is not required if the fuel manufacturer tests the added
blendstock and determines that both the blendstock and PCG meet the
fuel manufacturing facility gate sulfur per-gallon standard in Sec.
1090.205(b).
(iv) Report each batch of blendstock as specified in Sec.
1090.905(c)(4).
(v) Include each batch of blendstock in compliance calculations as
specified in Sec. 1090.700(d)(4)(ii).
(vi) The sample retention requirements in Sec. 1090.1345 apply for
the new batch of gasoline and for each blendstock.
(b) A certified butane or certified pentane blender that blends
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 paragraph (a) 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.
1090.220(e) disallows adding certified butane or certified pentane to
Summer RFG or Summer RBOB.
(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.
1090.250 or Sec. 1090.255, 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. 1090.250 or
Sec. 1090.255, 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
distributor. The certified butane or certified pentane blender may rely
on a third party to perform the testing.
(c) This paragraph describes provisions that apply in cases where
PCG is a BOB for which the PCG manufacturer accounted for oxygenate
added downstream under Sec. 1090.710 and the blending manufacturer
makes a new batch that includes less oxygenate than was specified for
the BOB by the PCG manufacturer. A blending manufacturer in this
circumstance does not qualify for the small volume blender exemption
for BOB recertification under Sec. 1090.740(a)(3) and must comply with
all the following.
(1) Calculate and incur sulfur and benzene deficits under the BOB
recertification provisions in Sec. 1090.740.
(2) Comply with either the compliance by subtraction requirements
of paragraph (a)(1) of this section or the compliance by addition
requirements of paragraph (a)(2) of this section. For compliance by
subtraction, test the PCG without adding oxygenate (i.e., test the PCG
``neat''), and report the PCG volume without adjusting for the volume
of oxygenate that the PCG manufacturer specified under Sec. 1090.740.
Sec. 1090.1325 Adding blendstock or PCG to TGP.
The following provisions apply to a transmix processor or blending
manufacturer producing gasoline by adding blendstock or PCG to TGP:
(a) 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.
(b) Sample and test the gasoline made from TGP and PCG or
blendstock to demonstrate compliance with the fuel manufacturing
facility gate sulfur per-gallon standard in Sec. 1090.205(b) and the
applicable RVP standard in Sec. 1090.215.
(c) A transmix processor producing gasoline by only adding TGP to
PCG does not have to measure the benzene content of the finished
gasoline.
Sec. 1090.1330 Preparing denatured fuel ethanol.
Instead of measuring every batch, a DFE producer or importer 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
[[Page 78516]]
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, preparing, and testing samples.
(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. A
description of how to determine compliance based on single or multiple
tests on single or multiple samples is specified in paragraph (e) 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) to demonstrate compliance with standards as follows:
(1) 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.
(2)(i) Use tap sampling or spot sampling to collect upper, middle,
and lower samples if a running or all-levels sample is impractical for
a given storage configuration. Collect samples that most closely match
the recommendations in Table 5 of ASTM D4057. Adjust spot sampling for
partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057, as
applicable.
(ii) Spot sampling must not be used for certification testing
unless the tank contains less than 10 feet of product.
(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.
(5) Except as specified for marine vessels in Sec. 1090.1605, you
must not do certification testing with a composite sample from manual
sampling.
(c) Automatic sampling. (1) For in-line blending waivers under
Sec. 1090.1315, follow all specifications for automatic sampling as
specified in EPA's approval letter instead of or in addition to the
specifications in paragraph (c)(2) of this section. Automatic sampling
is also appropriate for a configuration involving a pipeline filling a
tank that will be certified as compliant before it leaves the fuel
manufacturing facility gate.
(2) Perform automatic sampling as specified in ASTM D4177
(incorporated by reference in Sec. 1090.95), with the following
additional specifications:
(i) Configure the system to ensure a well-mixed stream at the
sampling point. Align the start and end of sampling with the start and
end of creating the batch.
(ii) The default sampling frequency must follow the recommended
approach of at least 9,604 samples to represent a batch. Less frequent
sampling is acceptable as long as the interval between samples does not
exceed 20 seconds throughout the batch.
(iii) Collect three samples for individual measurements in addition
to the composite sample. Draw head, middle, and tail samples after
flowing 15, 50, and 85 percent of the estimated batch volume,
respectively.
(iv) EPA may approve a different sampling strategy under an
approved in-line blending waiver under Sec. 1090.1315 if it is
appropriate for a given facility or for a small-volume 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 other fuel parameters for a given sample in
addition to RVP testing, always measure RVP first.
(e) Testing to demonstrate compliance with standards. (1) Perform
testing as specified in this subpart.
(2) For parameters subject to per-gallon standards, report the
highest measured value (or the lowest measured value for testing
related to cetane index or other parameters that are subject to a
standard representing a minimum value). This applies for repeat tests
on a given sample and for testing multiple samples (including head,
middle, and tail samples from automatic sampling). A batch is
noncompliant if any tested sample does not meet all applicable per-
gallon standards.
(3) In the case of automatic sampling for parameters subject to
average standards, report the result from the composite sample to
represent the batch for demonstrating compliance with the average
standard. For any repeat testing with the composite sample, calculate
the arithmetic average from all tests to represent the batch.
(4) In the case of manual sampling for parameters subject to
average standards, determine the value representing the batch as
follows:
(i) For testing with only a single sample, report that value to
represent the batch. If there are repeat tests with that sample, report
the arithmetic average from all tests to represent the sample.
(ii) For testing with more than one sample, report the arithmetic
average from all tested samples to represent the batch. If there are
repeat tests for any sample, calculate the arithmetic average of those
repeat tests to determine a single value to represent that sample
before calculating the average value to represent the batch.
Sec. 1090.1337 Demonstrating homogeneity.
(a) Certification test results corresponding to manual sampling as
specified in Sec. 1090.1335(b) are valid only if collected samples
meet the homogeneity specifications in this section, except that the
homogeneity testing requirement does not apply in the following cases:
(1) There is only a single sample using the procedure specified in
Sec. 1090.1335(b)(2).
(2) Upright cylindrical tanks that have a liquid depth of less than
10 feet.
(3) You draw spot or tap samples as specified in paragraph (c) of
this section, 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.
(4) Sampling at a downstream location where it is not possible to
collect separate samples and steps are taken to ensure that the batch
is well mixed.
(b)(1) Testing performed to establish homogeneity is not considered
certification testing, except as specified in paragraph (b)(2) of this
section.
(2) Homogeneity testing may be used as certification testing if any
of the following criteria are met:
[[Page 78517]]
(i) All tested samples meet all applicable per-gallon standards.
(ii) The testing meets the requirement in Sec.
1090.1335(b)(2)(ii).
(iii) The testing follows the procedures specified in paragraph
(a)(3) of this section.
(c) Use spot sampling as specified in Sec. 1090.1335(b)(2) for
homogeneity testing. Tap sampling is acceptable if spot sampling is
impractical for a given facility.
(d) Demonstrate homogeneity for gasoline using two of the
procedures specified in this paragraph (d) with each sample. For summer
gasoline, the homogeneity demonstration must include RVP measurement.
(1) Measure API gravity using ASTM D287, ASTM D1298, ASTM D4052, or
ASTM D7777 (incorporated by reference in Sec. 1090.95).
(2) Measure the sulfur content as specified in Sec. 1090.1360.
(3) Measure the benzene content as specified Sec. 1090.1360.
(4) Measure the RVP as specified in Sec. 1090.1360.
(e) For testing to meet the diesel fuel standards in subpart D of
this part, demonstrate homogeneity using one of the procedures
specified in paragraph (d)(1) or (2) of this section.
(f) Consider the batch to be homogeneous for a given parameter if
the measured values for all tested samples vary by less than the
published reproducibility of the test method multiplied by 0.75 (R x
0.75). If reproducibility is a function of measured values, calculate
reproducibility using the average value of the measured parameter
representing all tested samples. Calculate using all meaningful
significant figures as specified for the test method, even if Sec.
1090.1350(c) describes a different precision. For cases that do not
require a homogeneity demonstration under paragraph (a) of this
section, 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 requirements of this subpart by
blending oxygenate that reflects the anticipated sulfur content and
benzene content of the oxygenate for blending into a BOB sample. To do
this, prepare each hand blend 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 as follows:
(1) Take steps to avoid introducing high or low bias in sulfur
content when selecting from available samples to prepare 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 a downstream blender to add more
than one type or concentration of oxygenate, prepare the hand blend as
follows:
(i) For summer gasoline intended for blending with ethanol, use the
lowest specified ethanol blend.
(ii) For all winter gasoline and for summer gasoline intended for
blending only with oxygenate other than ethanol, use the lowest
specified oxygenate concentration, regardless of the type of oxygenate.
(iii) As an 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) Prepare the hand blend using the procedures specified in ASTM
D7717 (incorporated by reference in Sec. 1090.95). The hand blend must
have an amount of oxygenate that does not exceed the oxygenate
concentration specified on the PTD for the BOB under Sec.
1090.1110(b)(1).
Sec. 1090.1345 Retaining samples.
(a) Retain samples as follows:
(1) A fuel manufacturer, regulated blendstock producer, or
independent surveyor must keep representative samples of gasoline,
diesel fuel, or oxygenate that is subject to certification testing
requirements under this subpart for at least 30 days after testing is
complete, except that a longer sample retention of 90 days applies for
a blending manufacturer that produces gasoline.
(2) A certified pentane producer must keep representative samples
of certified pentane for at least 30 days after testing is complete.
(3) A blending manufacturer required to test blendstock under Sec.
1090.1320(a)(2) must keep representative samples of the blendstock and
the new batch of gasoline for at least 90 days after testing is
complete.
(4) An oxygenate producer or importer must keep oxygenate samples
as follows:
(i) 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.
(ii) 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.
(5) The nominal volume of retained liquid 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 are required to test a hand blend under Sec. 1090.1340,
keep a sample of the BOB and a sample representative of the oxygenate
used to prepare the hand blend.
(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.
(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 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.
A fuel manufacturer, fuel additive manufacturer, regulated
blendstock producer, or independent surveyor meets 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
[[Page 78518]]
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 that meets ASTM
D6751 (incorporated by reference in Sec. 1090.95).
(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. There is no aromatics-related test
requirement for biodiesel that meets ASTM D6751.
(3) Measure the purity of butane as specified in ASTM D2163
(incorporated by reference in Sec. 1090.95). Measure the purity of
pentane as specified in ASTM D2163 or ASTM D5134 (incorporated by
reference in Sec. 1090.95).
(4) Measure the benzene content of butane and pentane as specified
in ASTM D2163, ASTM D5134, ASTM D6729, or ASTM D6730 (incorporated by
reference in Sec. 1090.95).
(5) Measure the sulfur content of pentane as specified in ASTM
D5453 (incorporated by reference in Sec. 1090.95).
(6) Measure distillation parameters 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. You may use an alternative procedure if you adequately 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 O of this part:
Table 1 to Paragraph (b)(11)--Additional Survey Test Methods
------------------------------------------------------------------------
Fuel parameter Units Test method \1\
------------------------------------------------------------------------
Distillation.................. [deg]C........... ASTM D86.
Aromatic content.............. volume percent... ASTM D5769.
Olefin content................ volume percent... ASTM D6550.
------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference, see 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 the same or better than 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 15.56 [deg]C. 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 as follows:
(a) Adjust measured values for total vapor pressure as follows:
RVP (psi) = 0.956 [middot] Ptotal - 0.347
Where:
Ptotal = Measured total vapor pressure, in psi.
(b) For measuring the sulfur content 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 sulfur content of ULSD at a downstream
location, subtract 2 ppm from the result.
(d) 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.
(e) If measured content of any oxygenate compound is less than 0.20
percent by mass, record the result as ``None detected.''
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
[[Page 78519]]
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 a laboratory that uses either referee
procedures or alternative procedures.
(3) Streamlined requirements for alternative procedures apply for
procedures adopted by a voluntary consensus standards body (VCSB).
Certification 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 use updated versions of the referee procedures as
alternative procedures subject to the limitations of Sec.
1090.1365(a)(2). 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 repeatability and
reproducibility compared to the version specified in Sec. 1090.95. If
the updated procedure has worse repeatability or reproducibility
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
laboratory, 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 a laboratory that
measures 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 Procedures for Qualifying Alternative
Procedures
------------------------------------------------------------------------
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, see 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. For referee procedures and for alternative procedures for
method-defined fuel parameters that you have qualified for your
laboratory, updated versions of those same procedures are qualified
without further testing, as long as the 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 laboratory 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 laboratory.
(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 (b). 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
[[Page 78520]]
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] TR04DE20.018
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
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Fixed
Fuel, fuel additive, or regulated Fuel parameter Range x1 x2 = Repeatability (r) or x3 values of Source \2\
blendstock reproducibility (R) \1\ [sigma]max
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ULSD.............................. Sulfur............... 5 ppm minimum........ 1.5 r = 1.33........................... 2.77 0.72 ASTM D3120-08 (R2019).
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 = 0.1152.x....................... 2.77 .......... ASTM D6667-14 (R2019).
Gasoline.......................... Sulfur............... ..................... 1.5 r = 0.4998.x \0.54\................ 2.77 .......... ASTM D7039-15a (R2020).
Gasoline.......................... oxygenate............ ..................... 0.3 R = 0.13.x \0.83\.................. 1 .......... ASTM D5599-18.
Gasoline.......................... RVP \3\.............. ..................... 0.3 R = 0.40........................... 1 0.12 ASTM D5191-20.
Gasoline.......................... Benzene.............. ..................... 0.15 R = 0.221.x \0.67\................. 1 .......... ASTM D5769-20.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\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, see 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
this paragraph 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
Sulfur content maximum
Fuel (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
------------------------------------------------------------------------
(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
[[Page 78521]]
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
procedure 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 laboratories
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 (e)(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
(e)(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 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 in 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 laboratories 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 laboratory that uses the
referee procedure 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
laboratory qualifies as a reference installation, that qualification is
valid for five years from the qualifying date, consistent with good
laboratory practices.
(b) You may 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) You may qualify a reference installation for VCSB or 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
laboratory using the appropriate referee procedure. Calculate 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
[[Page 78522]]
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. 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
laboratory 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 laboratory.
(2) If you fail to conduct specified testing, your test instrument
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 instrument
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 instrument and perform testing to show that the test
instrument 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 instrument for performing up to 20 tests or 7 days, whichever
is less. Include all tests except for testing to meet precision or
accuracy requirements.
(2) Perform precision testing using the control-chart procedures in
ASTM D6299. If you opt to use procedure 2A (Q-Procedure) or 2B
(dynamically updated exponentially weighted moving average), 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.
(3) Use I charts and MR charts as specified in ASTM D6299 to show
that the standard deviation for the test instrument 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 (c). For method-defined VCSB procedures, you may meet
accuracy requirements as specified in this paragraph (c) 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 instrument 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] TR04DE20.019
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 78523]]
Table 1 to Paragraph (c)(4)--Criteria for Qualifying Alternative Procedures
----------------------------------------------------------------------------------------------------------------
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, see 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) An automated detergent blending facility 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.
A gasoline detergent manufacturer must perform testing using one of
the methods specified in 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 must 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. 1090.270 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 Test Method. Use the procedures specified by CARB in Title
13, California Code of Regulations, section 2257 (incorporated by
reference in Sec. 1090.95).
(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) EPA BMW method. Use the procedures specified in ASTM D5500
(incorporated by reference in Sec. 1090.95), as follows:
(1) Prepare the test fuel with the following specification:
(i) Sulfur--minimum 340 ppm.
(ii) T90--minimum 171 [deg]C.
(iii) Olefins--minimum 11.4 volume percent.
(iv) Aromatics--minimum 31.1 volume percent.
(v) Ethanol--minimum 10 volume percent.
(vi) Sulfur, T90, olefins, and aromatics specifications must be met
before adding ethanol.
(vii) Di-tert-butyl disulfide may be added to the test fuel.
(2) The duration of testing may be less than 10,000 miles. Measured
deposits must meet the following specified values to qualify the test
fuel and establish a detergent's LAC:
(i) Measured deposits for the fuel without detergent must be at
least 290 mg per valve on average.
(ii) Measured deposits for the fuel with detergent must be less
than 100 mg per valve on average.
(d) Alternative test methods. (1) An EPA-approved alternative test
method may be used if the alternative test method can be correlated to
any of the methods specified in paragraphs (a) through (c) of this
section.
(2) Information describing the alternative test method and analysis
demonstrating correlation must be submitted for EPA approval as
specified in Sec. 1090.10.
Subpart O--Survey Provisions
Sec. 1090.1400 General provisions.
(a) Program plan approval process. (1) A program plan that complies
with the requirements in Sec. 1090.1415 or Sec. 1090.1450 must be
submitted to EPA no later than October 15 of the year preceding the
calendar year in which the program will be conducted.
(2) The program plan must be signed by an RCO of the independent
surveyor conducting the program.
(3) The program plan must be submitted as specified in Sec.
1090.10.
(4) EPA will send a letter to the party submitting the program plan
that indicates whether EPA approves or disapproves the plan.
(b) Independent surveyor contract. (1) No later than December 15 of
the year
[[Page 78524]]
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.
(2) 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. 1090.1405 National fuels survey program.
(a) Program participation. (1) A gasoline manufacturer that elects
to account for oxygenate added downstream under Sec. 1090.710 must
participate in the national fuels survey program (NFSP) specified in
this paragraph (b) of this section.
(2) A party required to participate in an E15 survey under Sec.
1090.1420(a) must participate in the NFSP specified in paragraph (b) of
this section or a survey program approved by EPA under Sec.
1090.1420(b) or (c).
(3) Other parties may elect to participate in the NFSP for purposes
of establishing an affirmative defense against violations of
requirements and provisions under this part as specified in Sec.
1090.1720.
(b) Program requirements. The NFSP must meet all the following
requirements:
(1) 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.
(2) The survey program must be conducted by collecting samples
representative 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 NFSP 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 N 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 under Sec.
1090.1415(e)(3), must also be analyzed for aromatics content, olefins
content, and distillation parameters.
(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 N 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 downstream sulfur per-gallon 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 quarterly and annual summary reports that include the
information specified in Sec. 1090.925(b) and (c), respectively.
(g) Keep records related to the NFSP as specified in Sec.
1090.1245(b)(1).
(h) Submit contracts to EPA as specified in Sec. 1090.1400(b).
(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 program plan design requirements.
The 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
[[Page 78525]]
or diesel was collected during a survey and 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.
(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
program plan for each calendar year is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TR04DE20.020
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 program plan,
[phiv]0 will be 2.3%. For subsequent survey program
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 NFSP
must be approved annually as part of the survey program plan approval
process in Sec. 1090.1400(a). 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 crosscheck program for the most recent 12 months prior to
submission of the survey program plan.
(g) Submission. Survey program plans submitted under this section
must be approved annually under Sec. 1090.1400(a).
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 an oxygenate producer that produces or imports DFE, the DFE
is deemed as intended for use in E15 unless the oxygenate producer
demonstrates that it was not intended for such use. The oxygenate
producer 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. 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 that meets 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. 1090.1405(a) and (b)(2), 1090.1410(c)(2)
and (3), and 1090.1415(b), (d)(1), (2), and (4), and (e). In lieu of
meeting these sections, the
[[Page 78526]]
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. The gasoline manufacturer, oxygenate blender,
or oxygenate producer must participate in the NFSP under Sec.
1090.1405.
Sec. 1090.1450 National sampling and testing oversight program.
(a) Program participation. (1) Except for a gasoline manufacturer
that has an approved in-line blending waiver under Sec. 1090.1315 that
covers all gasoline produced at their facility, a gasoline manufacturer
that elects to account for oxygenate added downstream under Sec.
1090.710 must participate in the national sampling and testing
oversight program (NSTOP) in this section.
(2) Other gasoline manufacturers may elect to participate in the
NSTOP for purposes of establishing an affirmative defense to a
violation under Sec. 1090.1720. A gasoline manufacturer that has an
approved in-line blending waiver under Sec. 1090.1315 does not need to
participate in the NSTOP in order to establish an affirmative defense
to a violation under Sec. 1090.1720.
(3) A gasoline manufacturer that elects to participate in the NSTOP
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 that the sample was collected.
(b) Program requirements. The NSTOP must meet all the following
requirements:
(1) The NSTOP 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 NSTOP must be conducted at each gasoline manufacturing
facility from all participating gasoline manufacturers.
(c) Independent surveyor requirements. The independent surveyor
conducting the NSTOP must meet all the following requirements:
(1) Submit a proposed NSTOP 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. If the fuel manufacturer only produces fuel
during either the summer or winter season, obtain at least one sample
during the season that the fuel manufacturer produces fuel.
(ii)(A) Observe the gasoline manufacturer collect at least one
sample representing each gasoline required under paragraph (c)(2)(i) of
this section for each participating gasoline manufacturing facility and
evaluate whether the gasoline manufacturer collected representative
sample(s) in accordance with applicable sampling procedures specified
in Sec. 1090.1335. Immediately notify EPA and the gasoline
manufacturer if the applicable sampling procedures are not followed.
(B) 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.
(C) 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. A
gasoline manufacturer that refuses to allow the independent surveyor to
take portions of collected samples is no longer considered by EPA to be
participating in the NSTOP and must not account for oxygenate added
downstream under Sec. 1090.710.
(iv) Samples must be retained by the independent surveyor as
specified in Sec. 1090.1345(a)(1).
(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 N of this part.
(iv) All analyses must be completed by the EPA-approved laboratory
within 10 business days after receipt of the sample.
(v) A gasoline manufacturer must analyze gasoline samples for
sulfur content, 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
that exceeds the fuel manufacturing facility gate sulfur per-gallon
standard in Sec. 1090.205(b).
(ii) A test result for a gasoline sample yields an RVP 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 notify 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 N of this part.
(7) Provide quarterly reports to EPA that include the information
specified in Sec. 1090.925(d).
(8) Keep records related to the NSTOP as specified in Sec.
1090.1245(b)(3).
(9) Submit contracts to EPA as specified in Sec. 1090.1400(b).
(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 Ratio (PR) from Table 2
Guidelines for Action Based on TPI in ASTM D6792 (incorporated by
reference in Sec. 1090.95).
(iii) A gasoline manufacturer must supply copies of the necessary
information to the independent surveyor to review the TPI and PR for
[[Page 78527]]
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 NSTOP, including sample collection, transportation,
storage, and analysis.
(d) NSTOP plan requirements. The NSTOP plan specified in paragraph
(c)(1) of this section must include, at a minimum, all the following:
(1) Advance notice of sampling. The NSTOP plan must include
procedures on how to keep the identification of the gasoline
manufacturing facilities included in the NSTOP 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 each season they produce fuel. 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 season samples 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 NSTOP
plan.
(ii) The minimum number of samples to be included in the NSTOP 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
NSTOP (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 NSTOP
must be approved annually as part of the program plan approval process
in Sec. 1090.1400(a). The independent surveyor must include the
following information regarding each 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) Records demonstrating the laboratory's performance in a
laboratory crosscheck 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 NSTOP 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. NSTOP plans submitted under this section must be
approved annually under Sec. 1090.1400(a).
Subpart P--Retailer and Wholesale Purchaser-Consumer Provisions
Sec. 1090.1500 Overview.
(a) A retailer or WPC must comply with 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 as the EPA-required label.
(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 paragraph 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 78528]]
[GRAPHIC] [TIFF OMITTED] TR04DE20.021
Sec. 1090.1515 Diesel sulfur labeling provisions.
A 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 must 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.
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.
(d) The retaining spring (if applicable) must terminate at least 76
mm from the terminal end.
[[Page 78529]]
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 that
meets the requirements of 40 CFR 86.1813-17(f)(1).
(b) Determine the amount of natural gas vented 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 Q--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)(1) Except as specified in paragraph (b)(2) of this section, all
applicable gasoline and diesel standards in subparts C and D of this
part apply to imported gasoline and diesel.
(2) A gasoline importer that imports gasoline at multiple import
facilities must comply with the gasoline average standards in
Sec. Sec. 1090.205(a) and 1090.210(a) as specified in Sec.
1090.705(b), unless the importer complies with the provisions of Sec.
1090.1610 to meet the alternative per-gallon standards for rail and
truck imports specified in Sec. Sec. 1090.205(d) and 1090.210(c).
(c) An importer must separately comply with any applicable
certification or other requirements for U.S. Customs.
(d) Alternative testing requirements for an importer that imports
gasoline or diesel fuel by rail or truck are specified in Sec.
1090.1610.
Sec. 1090.1605 Importation by marine vessel.
An importer that imports fuel, fuel additive, or regulated
blendstock using a marine vessel must comply with the requirements of
this section.
(a) The importer must certify each fuel, fuel additive, or
regulated blendstock imported at each port, unless the fuel is
certified at the first port of entry in the United States and then
transported by the same vessel to subsequent ports without picking up
additional fuel.
(b) Except as specified in paragraph (d) of this section, the
importer must certify each fuel, fuel additive, or regulated blendstock
while it is on-board the vessel used to transport it to the United
States. Certification sampling must be performed after the vessel's
arrival at the port where the fuel, fuel additive, or regulated
blendstock will be offloaded.
(1) The importer must sample each compartment of the vessel and use
one of the following methods to meet testing requirements:
(i) Treat each compartment as a separate batch.
(ii) Combine samples from separate compartments into a single,
vessel volumetric composite sample using the procedures in Section
9.2.4 of ASTM D4057 (incorporated by reference in Sec. 1090.95). Test
results from the composite sample are valid only after samples are
collected from each affected compartment and homogeneity is
demonstrated for all samples as specified in Sec. 1090.1337.
(2) The importer must ensure that all applicable per-gallon
standards are met before offloading the fuel, fuel additive, or
regulated blendstock.
(3) The importer 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 requirements of subpart L of this part.
(d) As an alternative to paragraphs (b) and (c) of this section,
the importer may offload fuel, fuel additive, or regulated blendstock
into shore tanks that contain the same fuel, fuel additive, or
regulated blendstock if the importer meets the following requirements:
(1) For gasoline, the importer must offload gasoline into one or
more empty shore tanks or tanks containing PCG that the importer owns.
(i) If the importer offloads gasoline into one or more empty shore
tanks, they must sample and test the sulfur content and benzene
content, and for summer gasoline, RVP, of each shore tank into which
the gasoline was offloaded.
(ii) If the importer offloads 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
content and benzene content, and report this PCG as a negative batch as
specified in Sec. 1090.905(c)(3)(i). After offloading the gasoline
into the shore tanks, the importer must sample and test the sulfur
content, benzene content, and for summer gasoline, RVP, of each shore
tank into which the gasoline was offloaded and report the volume,
sulfur content, and benzene content as a positive batch.
(iii) Include the PCG in the shore tank before offloading and the
volume and properties after offloading in compliance calculations as
specified in Sec. 1090.700(d)(4)(i).
(iv) The sample retention requirements in Sec. 1090.1345 apply to
the samples taken prior to offloading and those taken after offloading.
(2) For all other fuel, fuel additive, or regulated blendstock, the
importer must sample and test the fuel, fuel additive, or regulated
blendstock in each shore tank into which it was offloaded. The importer
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.
(a) An importer that imports fuel, fuel additive, or regulated
blendstock by rail or truck must meet the sampling and testing
requirements of subpart N of this part by sampling and testing each
compartment of the truck or railcar unless they do one of the
following:
(1) Use supplier results. The importer may rely on test results
from the supplier for fuel, fuel additive, or regulated blendstock
imported by rail or truck if the importer meets all the following
requirements:
(i) The importer obtains documentation of test results from the
supplier for each batch of fuel, fuel additive, or regulated blendstock
in
[[Page 78530]]
accordance with the following requirements:
(A) The testing includes measurements for all the fuel parameters
specified in Sec. 1090.1310 using the measurement procedures specified
in Sec. 1090.1350.
(B) Testing for a given batch occurs 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.
(ii) The importer conducts testing to verify test results from each
supplier as follows:
(A) Collect a sample at least once every 30 days or every 50 rail
or truckloads from a given supplier, whichever is more frequent. Test
the sample as specified in paragraphs (a)(1)(i)(A) and (B) of this
section.
(B) 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.
(2) Certify in a storage tank. The importer may transfer the fuel,
fuel additive, or regulated blendstock imported by rail or truck into
storage tanks that also contain the same product if the importer meets
the following requirements:
(i) For gasoline, the importer transfers gasoline into one or more
empty tanks or tanks containing PCG that the importer owns.
(A) If the importer transfers gasoline into one or more empty
tanks, they must sample and test the sulfur content, benzene content,
and for summer gasoline, RVP, of each tank into which the gasoline was
transferred.
(B) If the importer transfers gasoline into one or more tanks
containing PCG, they must sample the PCG already in the tank prior to
transferring gasoline from the truck or train, test the sulfur content
and benzene content, and report this PCG as a negative batch as
specified in Sec. 1090.905(c)(3)(i). After transferring the gasoline
into the tanks, the importer must sample and test the sulfur content,
benzene content, and for summer gasoline, RVP, of each tank into which
the gasoline was transferred and report the volume, sulfur content, and
benzene content as a positive batch.
(C) Include the PCG in the tank before transferring and the volume
and properties after transferring in compliance calculations as
specified in Sec. 1090.700(d)(4)(i).
(D) The sample retention requirements in Sec. 1090.1345 apply to
the samples taken prior to transferring and those taken after
transferring.
(ii) For all other fuel, fuel additive, or regulated blendstock,
the importer must sample and test the fuel, fuel additive, or regulated
blendstock in each tank into which it was transferred. The importer
must ensure that all applicable per-gallon standards are met before the
fuel, fuel additive, or regulated blendstock is shipped from the tank.
(b) If an importer that elects to comply with paragraph (a)(1) or
(2) of this section fails to meet the applicable requirements, they
must meet the sampling and testing requirements of subpart N of this
part for each compartment of the truck or railcar until EPA determines
that the importer has adequately addressed the cause of the failure.
Sec. 1090.1615 Gasoline treated as a blendstock.
(a) An importer may exclude GTAB from their compliance calculations
if they meet all the following requirements:
(1) The importer reports the GTAB to EPA under Sec.
1090.905(c)(7).
(2) The 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 the GTAB and must include the gasoline produced
using the GTAB in their compliance calculations.
(b) After importation, the title of the GTAB must not be
transferred to another party until the GTAB has been either certified
as gasoline under subpart K of this part or used to produce gasoline
that meets all applicable standards and requirements under this part.
(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 it were imported
gasoline and complete all requirements for a gasoline manufacturer
under Sec. 1090.105(a) (except for the sampling, testing, and sample
retention requirements in Sec. 1090.105(a)(6)) 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,
fuel produced, imported, distributed, or offered for sale in the United
States is subject to the standards and requirements of this part.
(a) Fuel designated for export by a fuel manufacturer is not
subject to the standards in this part, provided all the requirements in
Sec. 1090.645 are met.
(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
United States by the U.S. Customs Service under 19 CFR part 10 is not
considered to be imported for purposes of this part, provided all the
following requirements are met:
(1) The 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) The 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 United States and none may be used in a
foreign country.
(4) No fuel classified as American Goods Returned to the United
States may be combined with any fuel produced at a foreign fuel
manufacturing facility prior to reentry into the United States.
Subpart R--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 under 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
[[Page 78531]]
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 each day of
such violation and the amount of economic benefit or savings resulting
from the 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 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 day in
any compliance period in which invalid credits are generated,
transferred, used, or made available for use.
(c)(1) Any person liable under this part for a violation of a per-
gallon standard, or for causing another party to violate a per-gallon
standard, is subject to a separate day of violation for each 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 day such provision remains unfulfilled.
(e) Failure to meet separate requirements of this part count as
separate violations.
(f) Violation of any misfueling prohibition under this part counts
as a separate violation for each 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 comply with the sampling or testing requirements and must be
reported, unless EPA, in its sole discretion, approves a different
value. EPA may consider any relevant information to determine whether a
different value is appropriate.
(1) For gasoline: 339 ppm sulfur, 1.64 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: 339 ppm sulfur.
(6) For regulated blendstocks: 339 ppm sulfur and 1.64 volume
percent benzene.
Sec. 1090.1715 Liability provisions.
(a) Any person who violates any prohibited act or 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 any violation of this part that
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.
(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) If 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) A retailer or WPC is 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
[[Page 78532]]
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 the NFSP under Sec. 1090.1405 that was in effect at
the time of the violation.
(ii) In addition to the requirements of paragraph (d)(1)(i) of this
section, a gasoline manufacturer must also participate in the NSTOP
specified in Sec. 1090.1450 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 periodic sampling and testing
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 evidence of an oversight program for monitoring compliance
with the requirements of this part relating to the transport or storage
of the 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 oxygenate 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 oxygenate blender, distributor, reseller,
carrier, retailer, or WPC 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 oxygenate
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 oxygenate 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 S--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) A gasoline manufacturer that produces or imports gasoline
subject to the requirements of subpart C of this part.
(2) A gasoline manufacturer that performs testing as specified in
subpart N of this part or that relies on testing from a third-party
laboratory.
(b) An auditor performing attestation engagements must meet the
following requirements:
(1) The auditor 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.
Such an auditor 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 an auditor must comply with the AICPA Code of Professional
Conduct, including its independence requirements, the AICPA Statements
on Quality Control Standards (SQCS) No. 8, A Firm's System of Quality
Control (both incorporated by reference in Sec. 1090.95), and
applicable rules of state boards of public accountancy. Such an auditor
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.
[[Page 78533]]
(c) An auditor 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 a laboratory 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 a gasoline manufacturer that relies on a third-party
laboratory for 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)--Sample Size Determination
------------------------------------------------------------------------
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. An auditor that determines 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 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 for gasoline manufacturers.
An auditor must perform the procedures in this section for a
refiner, blending manufacturer, or transmix processer that produces
gasoline.
(a) Registration and EPA reports. An auditor 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 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 and report 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 and report 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. An auditor must perform an
inventory reconciliation analysis review 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 and report 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. An auditor 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 and report any variances.
(d) Listing of batches. An auditor 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 and report 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. An auditor 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) Detailed testing of BOB tenders. An auditor must review a
detailed listing of BOB tenders as follows:
(1) Select a representative sample from the listing of BOB tenders.
(2) Obtain the associated PTD for each selected sample.
(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 and report any exceptions.
(4) Confirm that the PTD associated with each selected BOB tender
contains all the applicable language requirements under subpart L of
this part and report any exceptions.
(g) Detailed testing of BOB batches. An auditor must review a
detailed listing of BOB batches as follows:
(1) Select a representative sample from the BOB batch reports
submitted under subpart J of this part.
(2) Obtain the volume documentation and laboratory analysis for
each selected BOB batch.
(3) Compare the reported volume for each selected BOB batch to the
volume documentation and report any exceptions.
(4) Compare the reported properties for each selected BOB batch to
the laboratory analysis and report any exceptions.
[[Page 78534]]
(5) Compare the reported test methods used for each selected BOB
batch to the laboratory analysis and report any exceptions.
(6) Determine each oxygenate type and amount that is required for
blending with the BOB.
(7) Confirm that each oxygenate type and amount included in the BOB
hand blend agrees with the manufacturer's blending instructions for
each selected BOB batch and report any exceptions.
(8) Confirm that the manufacturer participates in the NFSP under
Sec. 1090.1405, if applicable.
(9) For a blending manufacturer, confirm that the laboratory
analysis includes test results for oxygenate content, if applicable,
and distillation parameters (i.e., T10, T50, T90, final boiling point,
and percent residue). For a blending manufacturer not required to
measure oxygenate content, confirm that records demonstrate that the
PCG or blendstock contained no oxygenate, no oxygenate was added to the
final gasoline batch, and the blending manufacturer did not account for
oxygenate added downstream under Sec. 1090.710.
(h) Detailed testing of finished gasoline tenders. An auditor must
review a detailed listing of finished gasoline tenders as follows:
(1) Select a representative sample from the listing of finished
gasoline tenders.
(2) Obtain the associated PTD for each selected sample.
(3) 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 and report any
exceptions.
(4) Confirm that the PTD associated with each selected finished
gasoline tender contains all the applicable language requirements under
subpart L of this part and report any exceptions.
(i) Detailed testing of finished gasoline batches. An auditor 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.
(2) Obtain the volume documentation and laboratory analysis for
each selected finished gasoline batch.
(3) Compare the reported volume for each selected finished gasoline
batch to the volume documentation and report any exceptions.
(4) Compare the reported properties for each selected finished
gasoline batch to the laboratory analysis and report any exceptions.
(5) Compare the reported test methods used for each selected
finished gasoline batch to the laboratory analysis and report any
exceptions.
(6) For a blending manufacturer, confirm that the laboratory
analysis includes test results for oxygenate content, if applicable,
and distillation parameters (i.e., T10, T50, T90, final boiling point,
and percent residue). For a blending manufacturer not required to
measure oxygenate content, confirm that records demonstrate that the
PCG or blendstock contained no oxygenate, no oxygenate was added to the
final gasoline batch, and the blending manufacturer did not account for
oxygenate added downstream under Sec. 1090.710.
(j) Detailed testing of blendstock batches. In the case of adding
blendstock to TGP or PCG under Sec. 1090.1320(a)(2), an auditor must
review a detailed listing of blendstock batches as follows:
(1) Select a representative sample of blendstock batches from the
batch reports submitted under subpart J of this part.
(2) Obtain the volume documentation and the laboratory analysis for
each selected blendstock batch.
(3) Compare the reported volume for each selected blendstock batch
to the volume documentation and report any exceptions.
(4) Compare the reported properties for each selected blendstock
batch to the laboratory analysis and report any exceptions.
(5) Compare the reported test methods used for each selected
blendstock batch to the laboratory analysis and report any exceptions.
(6) For blending a manufacturer not required to measure oxygenate
content, confirm that records demonstrate that the PCG or blendstock
contained no oxygenate, no oxygenate was added to the final gasoline
batch, and the blending manufacturer did not account for oxygenate
added downstream under Sec. 1090.710.
Sec. 1090.1815 General procedures for gasoline importers.
An auditor must perform the procedures in this section for a
gasoline importer.
(a) Registration and EPA reports. An auditor must review
registration and EPA reports for a gasoline importer as specified in
Sec. 1090.1810(a).
(b) Listing of imports. An auditor 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 and report any variances.
(6) Report in the attestation report the total imported volume for
each product type.
(c) Listing of batches. An auditor 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 obtained under paragraph
(b)(1) of this section for each product type and report 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. An auditor 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. An auditor 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 and report 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 L of this part and
report any exceptions.
(f) Detailed testing of BOB batches. An auditor 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
[[Page 78535]]
and laboratory analysis for each selected BOB batch.
(2) Compare the reported volume for each selected BOB batch to the
volume inspection report and report any exceptions.
(3) Compare the reported properties for each selected BOB batch to
the laboratory analysis and report any exceptions.
(4) Compare the reported test methods used for each selected BOB
batch to the laboratory analysis and report 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
and report any exceptions.
(7) Confirm that the importer participates in the NFSP under Sec.
1090.1405, if applicable.
(g) Detailed testing of finished gasoline imports. An auditor 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 and report 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 L of this part and
report any exceptions.
(h) Detailed testing of finished gasoline batches. An auditor 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 and report any exceptions.
(3) Compare the reported properties for each selected finished
gasoline batch to the laboratory analysis and report any exceptions.
(4) Compare the reported test methods used for each selected
finished gasoline batch to the laboratory analysis and report any
exceptions.
(i) Additional procedures for certain gasoline imported by rail or
truck. An auditor must perform the following additional procedures for
an importer that imports 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)(1) 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(a)(2).
(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 N 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 applicable method specified in subpart N 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, an auditor must perform the procedures in this
section for a gasoline manufacturer that imports GTAB under Sec.
1090.1615.
(a) Listing of GTAB imports. An auditor 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 and report 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. An auditor 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 listing of GTAB imports in paragraph (a)(6) of
this section and report any variances.
(c) Detailed testing of GTAB imports. An auditor must review a
detailed listing of GTAB imports as follows:
(1) Select a representative sample from the listing of GTAB imports
obtained under 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 and report any
exceptions.
(d) Detailed testing of GTAB batches. An auditor must review a
detailed listing of GTAB batches as follows:
(1) Select a representative sample from the GTAB 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 and report any exceptions.
(e) GTAB tracing. An auditor must trace and review the movement of
GTAB from importation to gasoline production 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 each
selected
[[Page 78536]]
GTAB batch from importation to gasoline production.
(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) Match the location of the facility where gasoline was
produced from each selected GTAB batch to the location where each
selected 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 and report any discrepancies.
Sec. 1090.1825 Additional procedures for PCG used to produce
gasoline.
In addition to any applicable procedures required under Sec.
1090.1810, an auditor must perform the procedures in this section for a
gasoline manufacturer that produces gasoline from PCG under Sec.
1090.1320.
(a) Listing of PCG batches. An auditor 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) and report any variances.
(b) Detailed testing of PCG batches. An auditor must review a
detailed listing of PCG batches as follows:
(1) Select a representative sample from the PCG batch reports
obtained under paragraph (a)(1) 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 and report any exceptions.
(4) For each selected PCG batch, 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 and report any exceptions.
(6) Compare the product type and grade for each selected PCG batch
to the associated PTDs and report any exceptions.
(7) Compare the reported properties for each selected PCG batch to
the laboratory analysis and report any exceptions.
(8) Compare the reported test methods used for each selected PCG
batch to the laboratory analysis and report any exceptions.
Sec. 1090.1830 Alternative procedures for certified butane blenders.
An auditor must use the procedures in this section instead of or in
addition to the applicable procedures in Sec. 1090.1810 for a
certified butane blender that blends certified butane into PCG under
Sec. 1090.1320(b).
(a) Registration and EPA reports. An auditor 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.
(2) For each 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 and report 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 and report 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. An auditor must perform an
inventory reconciliation analysis review as follows:
(1) Obtain an inventory reconciliation analysis from the certified
butane blender for each butane 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 and report any variances.
(4) Compare the total volume of certified butane received from the
batch reports obtained under paragraph (a)(1) of this section to the
inventory reconciliation analysis and report any variances.
(5) Compare the total volume of certified butane blended from the
batch reports to the inventory reconciliation analysis and report any
variances.
(6) Report in the attestation report the total volume of certified
butane received and blended.
(c) Listing of certified butane receipts. An auditor must review a
listing of certified butane receipts as follows:
(1) Obtain a detailed listing of all certified butane batches
received at the butane 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 and report any
variances.
(d) Detailed testing of certified butane batches. An auditor 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 and report any exceptions.
(4) Compare the reported properties for each selected certified
butane batch to the laboratory analysis and report any exceptions.
(5) Compare the reported test methods used for each selected
certified butane batch to the laboratory analysis and report any
exceptions.
(6) Confirm that the butane meets the standards for certified
butane under subpart C of this part and report any exceptions.
(e) Quality control review. An auditor must obtain the certified
butane
[[Page 78537]]
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(b)(4) and report any discrepancies.
Sec. 1090.1835 Alternative procedures for certified pentane blenders.
(a) An auditor must use the procedures in this section instead of
or in addition to the applicable procedures in Sec. 1090.1810 for a
certified pentane blender that blends certified pentane into PCG under
Sec. 1090.1320(b).
(b) An auditor 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.
An auditor must perform the procedures in this section for a
gasoline manufacturer that complies with the standards in subpart C of
this part using the procedures specified in subpart H of this part.
(a) Annual compliance demonstration review. An auditor 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 a gasoline refiner or blending manufacturer, compare the
gasoline production volume from the annual compliance report to the
inventory reconciliation analysis under Sec. 1090.1810(b) and report
any variances.
(ii) For a gasoline importer, compare the gasoline import volume
from the annual compliance report to the corresponding volume from the
listing of imports under Sec. 1090.1815(b) and report 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)(i).
(ii) Unadjusted average sulfur concentration, per Sec.
1090.745(b), and 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.
(v) Net average sulfur concentration, per Sec. 1090.745(c), and
net average benzene concentration, per Sec. 1090.745(d).
(4) Compare the recalculated values in paragraph (a)(3) of this
section to the reported values in the annual compliance reports and
report 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. An auditor 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 and report 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. An auditor 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.
(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 and report any variances.
(4) For an importer, the procedures of this paragraph (c) apply at
the company level.
(d) Company-level credit reconciliation. An auditor 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. An
auditor must perform the following procedures for a gasoline
manufacturer that recertifies a BOB under Sec. 1090.740 and incurs a
deficit:
(1) 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 and report any
exceptions.
(6) Recalculate the deficits in accordance with the provisions of
Sec. 1090.740 and report any discrepancies.
(7) Confirm that the deficits are included in the annual compliance
demonstration calculations and report any exceptions.
Sec. 1090.1845 Procedures related to meeting performance-based
measurement and statistical quality control for test methods.
(a) General provisions. (1) An auditor must conduct the procedures
specified in this section for a gasoline manufacturer.
(2) An auditor 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 employs, contracts, or subcontracts
an external specialist, all the requirements in 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. A third-party laboratory may also arrange for an auditor to
perform a single attestation engagement on the third-party laboratory
and make that available to gasoline manufacturers that have testing
performed by the third-party laboratory.
(b) Non-referee method qualification review. For each test method
used to
[[Page 78538]]
measure a parameter for gasoline as specified in a report submitted
under subpart J of this part that is not one of the referee procedures
listed in Sec. 1090.1360(d), the auditor must review the following:
(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) Confirm that the gasoline manufacturer supplied the supporting
documentation for each test method specified in paragraph (b)(1) of
this section and report any exceptions.
(4) If an auditor has previously reviewed supporting documentation
under this paragraph (b) 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) Confirm that the facility completed the qualification
procedures and report any exceptions.
(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 a listing from the laboratory of the instruments and
period when the instruments were used to measure gasoline parameters
during the compliance period for batches selected as part of the
representative sample under Sec. 1090.1810.
(2) Obtain statistical quality assurance data and control charts
demonstrating ongoing quality testing to meet the accuracy and
precision requirements specified in Sec. 1090.1375 or 40 CFR 80.47, as
applicable.
(3) Confirm that the facility performed statistical quality
assurance monitoring of its instruments under Sec. 1090.1375 and
report any exceptions.
(4) Report as a finding in the attestation report the instrument
lists obtained under paragraph (d)(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, an
auditor must perform the procedures specified in this section for a
gasoline manufacturer that relies on an in-line blending waiver under
Sec. 1090.1315.
(a) Obtain a copy of the gasoline manufacturer's in-line blending
waiver submission and EPA's approval letter.
(b) Confirm that the sampling procedures and composite calculations
conform to specifications as specified in Sec. 1090.1315(a)(2).
(c) Review the gasoline manufacturer'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.
(d) Confirm that the gasoline manufacturer corrected their
operations because of previous audits, if applicable.
(e) Confirm that the equipment and procedures are not materially
changed from the gasoline manufacturer's in-line blending waiver. In
cases of material change in equipment or procedure, confirm that the
gasoline manufacturer updated their in-line blending waiver and report
any exceptions.
(f) Perform any additional procedures unique to the blending
operation, as specified in the in-line blending waiver, and report any
findings, variances, or exceptions, as applicable.
(g) Confirm that the gasoline manufacturer has complied with all
provisions related to their in-line blending waiver and report any
exceptions.
[FR Doc. 2020-23164 Filed 12-3-20; 8:45 am]
BILLING CODE 6560-50-P