[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: parsons.nick@epa.gov.

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

[[Page 78413]]

    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

[[Page 78414]]

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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
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    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \26\ C6 refers to a hydrocarbon molecule that contains six 
carbon atoms. Pentane has 5 hydrocarbons (i.e., it is C5).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \40\ For more information on EPA's actions, see www.epa.gov/gasoline-standards/federal-gasoline-regulations.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \42\ See CAA section 110(l).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \57\ Such as diesel fuel used in school buses.
    \58\ See 40 CFR 80.520(b).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \60\ See 40 CFR 80.520(b)(1).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \61\ See 40 CFR 80.512.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \63\ See 84 FR 69335 (December 18, 2019).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \67\ See 40 CFR 80.580(d).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \68\ API Recommended Practice 1595 and Energy Institute & Joint 
Inspection Group (EI/JIG) Standard 1530.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \73\ We do not have ABT provisions for diesel fuel, so this 
section is only applicable to gasoline.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \74\ The accompanying in-use survey requirements and the NSTOP 
are discussed in more detail in Section X.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \75\ See 40 CFR 80.69.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \76\ We took the national average values for sulfur (10 ppm) and 
benzene (0.62 volume percent) and multiplied them by 110 percent.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.)
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \80\ A fuel supplier includes a person who transfers custody or 
title of marine fuel to a vessel.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \87\ See Section VII.F.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \99\ See https://www.epa.gov/compliance/epas-edisclosure.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \103\ See 40 CFR 80.92 and 80.1469.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \104\ See 40 CFR 80.573.
---------------------------------------------------------------------------

    During the rule development process, we received feedback from 
stakeholders suggesting that the ECA marine fuel labels were no longer 
necessary due to the way that ECA marine fuel is sold and dispensed for 
use in Category 3 marine vessels. 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \110\ See 40 CFR 80.84, 80.213, 80.513, 80.840, and 80.1607.
    \111\ See 40 CFR 80.84.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \118\ CRC Gasoline Engine Deposit Task Group, CRC Project No. 
CM-136, CRC Annual Report, September 2018.
    \119\ Id.
---------------------------------------------------------------------------

    In addition, the test fuel specified by EPA for use in the ASTM 
D5500 procedure is no longer representative of current gasoline. The 
composition of the requisite test fuel is specified to assure a 65th 
percentile concentration of gasoline parameters that affect deposit 
formation based on 1990 gasoline survey data.\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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \123\ See Title 13, California Code of Regulations, Section 
2257.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 fedreg.legal@nara.gov 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 
fedreg.legal@nara.gov, or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) American Institute of Certified Public Accountants, 220 Leigh 
Farm Rd., Durham, NC 27707-8110, (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


