Document ID: EPA-HQ-OAR-2018-0227-0002
Agency: epa
Document Type: Proposed Rule
Title: Fuels Regulatory Streamlining
Posted Date: 2020-05-14T04:00Z

[Federal Register Volume 85, Number 94 (Thursday, May 14, 2020)]
[Proposed Rules]
[Pages 29034-29162]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2020-09337]

[[Page 29033]]

Vol. 85

Thursday,

No. 94

May 14, 2020

Part II

Environmental Protection Agency

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40 CFR Parts 79, 80, 86, et al.

Fuels Regulatory Streamlining; Proposed Rule

  Federal Register / Vol. 85 , No. 94 / Thursday, May 14, 2020 / 
Proposed Rules  

[[Page 29034]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 79, 80, 86, 1037, and 1090

[EPA-HQ-OAR-2018-0227; FRL-10007-52-OAR]
RIN 2060-AT31

Fuels Regulatory Streamlining

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This action proposes to update the Environmental Protection 
Agency's (EPA) existing gasoline, diesel, and other fuels programs to 
improve overall compliance assurance and maintain environmental 
performance, while reducing compliance costs for industry and EPA. EPA 
is proposing to streamline its existing fuel quality regulations by 
removing expired provisions, eliminating redundant compliance 
provisions (e.g., duplicative registration requirements that are 
required by every EPA fuels program), removing unnecessary and out-of-
date requirements, and replacing them with a single set of provisions 
and definitions that will apply across all gasoline, diesel, and other 
fuels programs that EPA currently regulates. This action does not 
propose to change the stringency of the existing fuel quality 
standards.

DATES: 
    Comments. Comments must be received on or before June 29, 2020. 
Under the Paperwork Reduction Act (PRA), comments on the information 
collection provisions are best assured of consideration if the Office 
of Management and Budget (OMB) receives a copy of your comments on or 
before June 15, 2020.
    Public Hearing. EPA will announce the public hearing date and 
location for this proposal in a supplemental Federal Register document.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2018-0227, at http://www.regulations.gov. Follow the online 
instructions for submitting comments. Once submitted, comments cannot 
be edited or removed from Regulations.gov. The EPA may publish any 
comment received to its public docket. Do not submit electronically any 
information you consider to be Confidential Business Information (CBI) 
or other information whose disclosure is restricted by statute. 
Multimedia submissions (audio, video, etc.) must be accompanied by a 
written comment. The written comment is considered the official comment 
and should include discussion of all points you wish to make. EPA will 
generally not consider comments or comment contents located outside of 
the primary submission (i.e., on the web, cloud, or other file sharing 
system). For additional submission methods, the full EPA public comment 
policy, information about CBI or multimedia submissions, and general 
guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.

FOR FURTHER INFORMATION CONTACT: Nick Parsons, Office of Transportation 
and Air Quality, Assessment and Standards Division, Environmental 
Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 48105; 
telephone number: 734-214-4479; email address: parsons.nick@epa.gov. 
Comments on this proposal should not be submitted to this email 
address, but rather through http://www.regulations.gov as discussed in 
the ADDRESSES section.

SUPPLEMENTARY INFORMATION: 

Does this action apply to me?

    Entities potentially affected by this proposed rule are those 
involved with the production, distribution, and sale of transportation 
fuels, including gasoline and diesel fuel. Potentially affected 
categories include:

------------------------------------------------------------------------
                                                Examples of potentially
         Category            NAICS \1\ Code        affected entities
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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 
proposed action. This table lists the types of entities that EPA is now 
aware could potentially be affected by this proposed action. Other 
types of entities not listed in the table could also be affected. To 
determine whether your entity would be affected by this proposed 
action, you should carefully examine the applicability criteria in 40 
CFR part 80. If you have any questions regarding the applicability of 
this proposed action to a particular entity, consult the person listed 
in the FOR FURTHER INFORMATION CONTACT section.

Table of Contents

I. Executive Summary
    A. Overview of Fuels Regulatory Streamlining
    B. Summary of Stakeholder Involvement and Rule Development
    C. Timing
    D. Costs and Benefits
II. Changes to Part 80
III. Structure of Proposed Regulations and General Provisions
    A. Structure of the Regulations
    B. Implementation Dates
    C. Prior Approvals
    D. Definitions
IV. General Requirements for Regulated Parties
V. Standards
    A. Gasoline Standards
    B. Diesel Fuel
VI. Exemptions, Hardships, and Special Provisions
    A. Exemptions
    B. Exports
    C. Hardships
VII. Averaging, Banking, and Trading Provisions
    A. Overview
    B. Compliance on Average
    C. Deficit Carryforward
    D. Credit Generation, Use, and Transfer
    E. Invalid Credits
    F. Downstream Oxygenate Accounting

[[Page 29035]]

    G. Downstream Oxygenate Recertification
VIII. Registration, Reporting, Product Transfer Document, and 
Recordkeeping Requirements
    A. Overview
    B. Registration
    C. Reporting
    D. Product Transfer Documents (PTDs)
    E. Recordkeeping
    F. Rounding
    G. Certification and Designation of Batches
IX. Sampling, Testing, and Retention Requirements
    A. Overview and Scope of Testing
    B. Handling and Testing Samples
    C. Measurement Procedures
X. Proposed Third-Party Survey Provisions
    A. National Survey Program
    B. National Sampling and Testing Oversight Program
XI. Import of Fuels, Fuel Additives, and Blendstocks
    A. Importation
    B. Special Provisions for Importation by Rail or Truck
    C. Special Provisions for Importation by Marine Vessel
    D. Gasoline and Diesel Fuel Treated as Blendstocks
XII. Compliance and Enforcement Provisions and Attest Engagements
    A. Compliance and Enforcement Provisions
    B. Attest Engagements
    C. RVP Test Enforcement Tolerance
XIII. Other Requirements and Provisions
    A. Requirements for Independent Parties
    B. Labeling
    C. Refueling Hardware Requirements for Dispensing Facilities and 
Motor Vehicles
    D. Previously Certified Gasoline (PCG)
    E. Transmix and Pipeline Interface Provisions
    F. Gasoline Deposit Control
    G. In-Line Blending
    H. Confidential Business Information
XIV. Costs and Benefits
    A. Overview
    B. Reduced Fuel Costs to Consumers From Improved Fuel 
Fungibility
    C. Costs and Benefits for Regulated Parties
    D. Environmental Impacts
XV. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs
    C. Paperwork Reduction Act (PRA)
    D. Regulatory Flexibility Act (RFA)
    E. Unfunded Mandates Reform Act (UMRA)
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act (NTTAA) and 
1 CFR Part 51
    K. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
XVI. Statutory Authority

I. Executive Summary

A. Overview of Fuels Regulatory Streamlining

1. Why EPA Is Taking This Action
    As part of our continual effort to update our regulations to ensure 
that fuel quality standards established under the Clean Air Act (CAA) 
continue to be met in-use, while minimizing the burden associated with 
doing so, we are proposing to streamline and modernize our existing 40 
CFR part 80 (``part 80'') fuel quality regulations by transferring them 
into a new proposed set of regulations in 40 CFR part 1090 (``part 
1090''). In this action, we are taking a wholistic look at the existing 
part 80 regulations in an attempt to consolidate the many different and 
overlapping regulations into the proposed part 1090 regulations that 
will also better reflect how fuels, fuel additives, and regulated 
blendstocks are produced, distributed, and sold in today's marketplace.
2. What Is and Is Not Covered in This Action
    This action focuses primarily on streamlining and consolidating our 
existing gasoline and diesel fuel programs that currently reside in 
part 80.\1\ To accomplish this, we are proposing to remove expired 
provisions and consolidate the remaining provisions from multiple fuel 
quality programs into a single set of requirements. This action covers 
almost all fuel programs and related provisions currently in part 80. 
These programs include, but are not limited to, the reformulated 
gasoline (RFG) program, the anti-dumping program, the diesel sulfur 
program, the gasoline benzene program, the gasoline sulfur programs, 
the E15 misfueling mitigation program, and the national fuel detergent 
program. This proposed streamlining effort aims to combine these 
separate, now fully-implemented programs, all of which affect the same 
regulated parties, into a single, national fuel quality program.
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    \1\ Under the current regulations, EPA's fuels regulations are 
in 40 CFR parts 79 and 80. Part 79 contains provisions related to 
the registration of fuel and fuel additives under CAA sections 
211(a), (b), (e), and (f), while Part 80 contains provisions for 
fuel quality (e.g., fuel controls and prohibitions established under 
CAA section 211(c) and the RFG program requirements promulgated 
under CAA section 211(k)) and the RFS program. This action is 
limited to the provisions related to EPA's fuel quality standards in 
part 80, as the registration requirements in part 79 and the RFS 
program in part 80 are significantly different in scope and would 
involve different considerations to update those regulatory 
requirements.
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    While this action proposes changes to many aspects of our fuel 
quality programs, there are several areas of the existing part 80 
regulations that would remain unchanged. Most importantly, this action 
does not change the stringency of the existing fuel quality standards. 
We are simply proposing to streamline and consolidate the existing part 
80 fuel quality programs into a single streamlined fuel quality program 
that would make compliance with the existing fuel quality standards 
under part 80 more straightforward, and as a result potentially improve 
fuel quality through increased compliance with our fuel quality 
standards. This action proposes to transfer the part 80 fuel quality 
standards mostly unchanged to part 1090, though in some cases we are 
proposing to modify the form of the standards to translate them into a 
format more conducive to streamlining the regulations and ensuring in-
use compliance.
    We recognize that while we are not proposing changes to the 
standards, in some cases, the proposed consolidation of certain 
provisions may slightly, indirectly affect in-use fuel quality. For 
example, proposed changes to how parties record and report test results 
that fall below the test method's lower limits of detection might cause 
parties to have to report slightly higher sulfur and benzene levels in 
gasoline, effectively improving in-use fuel quality by slightly 
decreasing the sulfur national annual average. On the other hand, the 
proposal to make it easier for fuel manufacturers of conventional 
gasoline (CG) to account for oxygenates (e.g., ethanol) added 
downstream of the manufacturing facility, thereby allowing for a 
slightly lower reported level of gasoline benzene and sulfur levels, 
might be perceived as slightly decreasing in-use fuel quality. There 
are many such minor impacts of changes in part 1090 and we believe that 
on balance the proposed program would maintain the same overall level 
of fuel quality as the current part 80 standards. Throughout this 
preamble, we have tried to identify such cases and we discuss the 
cumulative costs and benefits of these changes in more detail in 
Section XIV.
    We are also proposing some slight modifications to the Renewable 
Fuel Standard (RFS) program in subpart M of part 80, primarily for 
administrative purposes that follow from the proposed changes to our 
other fuel programs. These subpart M regulations are mostly unique to 
the RFS program, and

[[Page 29036]]

therefore do not need to be consolidated with the other part 80 fuel 
standard regulations. One of the goals of this action is to help ensure 
consistency in how parties comply with our regulatory requirements and 
report information to EPA. Since the RFS program uses similar, if not 
the same, reporting systems and compliance mechanisms for parties to 
demonstrate compliance, we are proposing changes to help ensure that 
this consistency is maintained or enhanced as a result of this action. 
We will treat public comments received suggesting substantive changes 
to the RFS program as outside the scope of this rulemaking.
    Finally, this action does not propose to remove any statutory 
requirement for fuels specified by the CAA. For example, this action 
does not propose to remove limits on lead levels in gasoline under CAA 
section 211(n), remove the requirement that all gasoline be additized 
with detergents under CAA section 211(l), or cetane index limits for 
diesel fuel under CAA section 211(g) and (i). While this action does 
update some of the provisions put in place to implement many provisions 
of the CAA, and in some cases substantially streamline the implementing 
regulations (e.g., for the gasoline detergents program), we are not 
proposing to eliminate any requirement under the CAA for fuels and 
parties that make, distribute, and sell such fuels.
    The majority of this action's proposed changes relative to part 80 
focus on consolidating and streamlining compliance provisions currently 
in part 80, not on adding new compliance requirements for regulated 
parties. This action also does not propose to impose new standards on 
fuels. As such, this action is mostly a compilation of numerous, 
relatively minor proposed changes to the existing provisions under part 
80. Many of these proposed changes may appear disconnected from one 
another, as they are addressing a specific technical area that needs 
consolidation, streamlining, and/or updating. Together, however, these 
proposed changes will lead to a more effective, efficient EPA fuels 
program.
3. Program Design
    The new part 1090 is designed to reduce compliance burdens for both 
industry and EPA, potentially lower fuel costs for consumers, and 
maintain fuel quality. To accomplish these goals, we have identified 
three key elements that are included in part 1090:
     A simplification of the RFG summer VOC standards.
     A consolidation of the regulatory requirements across the 
part 80 fuel quality programs.
     Improving oversight through the leveraging of third 
parties to ensure in-use fuel quality.
    First, we are proposing to simplify the RFG standards by 
translating the current summer RFG VOC standard into an RVP per-gallon 
cap of 7.4 psi. This proposed change would allow us to remove the use 
of the Complex Model \2\ as a requirement to certify batches of 
gasoline and remove all the provisions associated with demonstrating 
compliance on average. This proposed change would also allow for us to 
minimize the restrictions on the commingling of RFG and CG, allowing 
for a more fungible and efficient gasoline distribution system.
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    \2\ The Complex Model is a predictive model that estimates 
emissions performance of gasoline based on measured fuel parameters 
against a statutory baseline in model year 1990 vehicles (see 40 CFR 
80.45 and CAA section 211(k)(10)). Under part 80, refiners and 
importers are required to use the Complex Model to demonstrate 
compliance with RFG standards. The Complex Model is available at: 
https://www.epa.gov/fuels-registration-reporting-and-compliance-help/complex-model-used-analyze-rfg-and-anti-dumping.
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    The main remaining difference between RFG and CG is that in the 
summer, RFG's volatility is functionally controlled through a summer 
VOC performance standard determined with the Complex Model instead of 
through the RVP per-gallon maximum standards established for CG under 
CAA section 211(h). EPA has previously aligned the treatment RFG and CG 
for NOX performance through the Tier 2 gasoline sulfur 
program and toxics performance through the national gasoline benzene 
program.\3\ This action would align treatment for RFG and CG by 
translating the existing RFG VOC performance standard into an RVP per-
gallon cap standard, as is the case for CG in the summer. In Section 
V.A.2, we describe how the proposed summer RVP per-gallon cap of 7.4 
psi equates to the existing RFG summer VOC standards. This change alone 
allows for the removal of the sampling, testing, and reporting 
requirements associated with several Complex Model parameters, greatly 
simplifying compliance with our fuel standards. With this proposed 
translation of the RFG summer VOC performance standards into a summer 
RFG RVP per-gallon maximum standard, the required controls on fuel 
properties for RFG would be identical to the control of fuel properties 
for CG, even though the standards would remain different.
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    \3\ See 72 FR 8428 (February 26, 2007).
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    Second, since the standards for volatility, benzene, and sulfur 
would be treated similarly between RFG and CG, this would allow for the 
streamlining and consolidation of the compliance and enforcement 
provisions of the various part 80 fuel quality programs into a single 
fuel quality program. This consolidation would improve consistency, 
remove duplication, and ultimately reduce compliance burden on 
regulated parties and EPA. For example, we are proposing to consolidate 
the various gasoline reporting requirements into a single, unified 
annual reporting requirement. Under part 80, we require quarterly batch 
reports for RFG, versus annual reports for CG. We also require separate 
batch reports for the gasoline benzene and gasoline sulfur programs.
    Third, the proposed streamlined fuel quality program aims to 
improve oversight of our fuel quality programs. We hope to accomplish 
this by updating and improving the third-party oversight programs we 
already use in part 80. We are proposing to consolidate the existing 
three in-use survey programs into a single national in-use fuel quality 
survey. This proposed program would help ensure that all fuels 
nationwide continue to meet EPA fuel quality standards when dispensed 
into vehicles and engines, not just at the refinery gate. We are also 
proposing to replace the RFG independent lab testing requirement with a 
voluntary national oversight program. This proposed sampling oversight 
program would impose substantially lower costs across industry than the 
current regulations while helping to ensure the consistency of sampling 
and testing across industry. Finally, we are proposing to update and 
modernize the annual attest engagement program. These updated 
procedures will help ensure that the quality and consistency of 
reported information. Taken together, we believe these proposals will 
help improve oversight of our fuel quality programs.

B. Summary of Stakeholder Involvement and Rule Development

    We have actively engaged stakeholders throughout the development of 
this action to help maximize its potential effectiveness. Due to the 
number of affected stakeholders, the complexity surrounding the 
production and distribution of fuels, and the broad scope of this 
action, active stakeholder involvement was necessary to help ensure 
that the proposed fuels regulatory streamlining program achieved its 
goals.

[[Page 29037]]

    As part of the proposal development process, we provided advance 
notice through four discussion drafts of the proposed regulations.\4\ 
In doing so, we solicited feedback from stakeholders to: (1) Help 
ensure that any gaps in our regulatory requirements were filled prior 
to proposal; and (2) identify potential issues with the streamlined 
regulations. We also held a three-day public workshop on a variety of 
topics in Chicago on May 21-23, 2018.\5\ During this workshop, EPA 
staff discussed a variety of issues related to the development of this 
action to an audience of over 120 affected stakeholders. We also 
reached out on at least two separate occasions to a broad spectrum of 
interested stakeholders, including parties that make and distribute 
fuels, states, environmental non-governmental organizations, and other 
affected stakeholders. The proposed streamlined fuel quality program in 
this action is intended to reflect the input of all of those who 
participated in these activities and events.
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    \4\ The four discussion drafts are available in the docket for 
this action and on our website at: https://www.epa.gov/diesel-fuel-standards/fuels-regulatory-streamlining.
    \5\ See 83 FR 20812 (May 8, 2018).
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C. Timing

    As discussed in more detail in Section III.B, we are proposing that 
the part 1090 regulations would mostly replace the existing part 80 
regulations on January 1, 2021. We believe that having an 
implementation date at the beginning of a new compliance period would 
provide for a smooth transition to new regulatory requirements.

D. Costs and Benefits

    We do not anticipate much, if any, change in air quality as a 
result of this action. This is largely due to the fact that we are not 
proposing changes to the existing fuel quality standards. As such, we 
do not expect that regulated parties would need to make significant 
changes to how fuels are made, distributed, and sold, which are the 
factors EPA typically considers when determining the costs associated 
with imposing or changing fuel quality standards.
    However, we do believe that this proposal could result in savings 
to regulated parties and EPA by simplifying compliance with our fuel 
quality standards and by allowing greater flexibility in the 
manufacture and distribution of fuels. These savings would largely 
arise from the reduction of the administrative costs on regulated 
parties and EPA in complying with and implementing the existing fuel 
quality standards. We estimate the annualized total costs savings in 
administrative cost savings to industry to be $32.9 million per year. 
Other savings associated with improving the fungibility of fuel and 
providing greater flexibility could potentially be even more 
significant but are much more difficult to quantify. Section XIV of the 
preamble discusses in more detail the potential costs and benefits of 
this action.

II. Changes to Part 80

    We are transferring several provisions in part 80 that are 
currently in effect to part 1090.\6\ These provisions are all discussed 
in the subsequent sections of this preamble and are now drafted in a 
manner that makes them easier to understand. We are also proposing to 
remove subparts B, D, E, F, G, H, I, J, K, L, N, and O and appendices A 
and B to part 80. Some of these subparts have either expired (e.g., 
designate and track provisions for diesel fuel) or have been replaced 
by newer subparts (e.g., subpart K (RFS1) was superseded by subpart M 
(RFS2), subpart H (Tier 2 Sulfur) was supplanted by subpart O (Tier 3 
Sulfur), and subpart J (MSAT1) was supplanted by subpart L (MSAT2)).
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    \6\ Note that if we update these provisions in part 80 as part 
of a separate EPA action after this proposal, we plan to incorporate 
those updated provisions to part 1090 in the final rule.
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    We are not transferring some provisions from part 80 to part 1090. 
First, we are retaining the existing Renewable Fuel Standard (RFS) 
provisions in subpart M. We are proposing minor edits to subpart M that 
are intended to ensure consistency with the new language used in part 
1090. These edits will not affect any of the actual requirements in 
subpart M, but rather will homogenize the language used across all of 
our fuels programs.
    Second, because we are retaining the RFS program in part 80, we 
need to maintain certain general provisions contained in subpart A that 
will continue to apply to the RFS program. We are also revising several 
sections within subpart A to remove requirements, such as definitions 
that would no longer be applicable to part 80. In addition, we are 
reorganizing and consolidating the definitions in 40 CFR 80.2 to place 
them in alphabetical order, as this would make it consistent with part 
1090 and much easier to find terms.
    Finally, we are also retaining the Oxygenated Gasoline provisions 
in subpart C in part 80. This subpart contains a single section related 
to a requirement for labeling of oxygenated gasoline at retail pumps, 
as mandated by CAA section 211(m)(4). We are maintaining this 
requirement in part 80 because some state oxygenated fuel programs may 
reference the labeling requirements in part 80 and we want to minimize 
the amount of changes needed by states to revise regulations and update 
state implementation plans.

III. Structure of Proposed Regulations and General Provisions

    This section describes the general structure of the proposed part 
1090 regulations (i.e., how we propose to structure the regulations to 
make them more accessible to users and readers of the regulations). 
This section also describes the proposed implementation dates, how we 
intend to deal with prior approvals made under part 80, and our 
proposed approach to consolidating the hundreds of definitions in the 
part 80 regulations. Finally, this section discusses key proposed 
provisions (e.g., the definition of gasoline) in more detail to solicit 
public feedback on terms fundamental to the proposed streamlined fuel 
quality program.

A. Structure of the Regulations

    We are proposing a structure for part 1090 that differs from the 
structure of our current part 80 regulations. Part 80 includes a 
variety of fuel quality programs that, while designed to operate 
together, appear as distinct programs in the regulations. Historically, 
we have codified new fuel quality programs by adding a new subpart at 
the end of part 80. This was often done because each new fuel quality 
program implemented new regulatory requirements that augmented the 
prior fuel quality programs. These new additions also helped provide 
interim requirements needed to implement the new program. As a result, 
part 80 includes numerous similar sections that either create multiple 
methods of complying with certain regulatory requirements (e.g., 
submitting multiple gasoline batch reports for the RFG, antidumping, 
gasoline benzene, and Tier \2/3\ gasoline sulfur programs) or create 
what might appear to be contradictions in the regulations. Rather than 
have subparts with all the provisions associated with a given fuel 
standard (e.g., a subpart that contains all provisions related to 
gasoline benzene and a separate subpart that contains all provisions 
related to gasoline sulfur), part 1090 contains dedicated subparts 
according to the various functional elements of our fuel regulations 
(e.g., subparts that contain all gasoline standards or contain all 
reporting requirements).
    As proposed, subpart A contains general requirements that apply

[[Page 29038]]

throughout the rest of part 1090. Subpart A includes regulatory 
language that generally outlines the applicability and scope of the 
regulation, defines key terms, and outlines when the part 1090 
requirements come into effect. Subpart A also describes how 
requirements under part 1090 interact with other parts of the 
regulations that affect fuels--parts 79 and 80. Many of these sections 
are described elsewhere; for example, rounding of data is discussed in 
the reporting section (see Section VIII), and batch numbering is 
discussed in the designation and product transfer document section (see 
Section VIII).
    We are also proposing to include a list of general regulatory 
requirements for parties in subpart B. This subpart would lay out the 
general regulatory requirements for regulated parties. This helps 
inform the regulated community of what is generally expected of them in 
a succinct manner and provides references to the specific requirements 
in the appropriate places in the regulations. While the roadmap in 
subpart B does not remove or modify any of the regulatory obligations 
required throughout the rest of part 1090, we believe it will serve as 
a helpful guide. During the development of this proposed rule, we 
received feedback from several stakeholders that such a roadmap would 
not only be helpful for them to follow the part 1090 regulations, but 
would especially help those new to the regulations more easily identify 
general regulatory requirements.
    We are also proposing to keep the standards for different fuels in 
separate subparts so as to make it easier for parties to identify the 
specific standards that apply to fuels, regulated blendstocks, and 
additives. For part 1090, we have put the gasoline-related standards 
and the diesel-related (plus IMO marine fuel) standards in their own 
individual subparts. We are also leaving a subpart reserved after the 
gasoline and diesel standards, as we may need to use that subpart for 
future standards and this would enable us to not have to move 
subsequent subparts in a manner that would cause unnecessary confusion 
on the part of the regulated community.
    The next block of subparts (E through P) involve the provisions and 
requirements that regulated parties are expected to follow to 
demonstrate compliance with the applicable standards. We have 
consolidated the specific types of compliance activities where 
possible. For example, we have consolidated all the registration 
sections of part 80 into a single registration subpart in part 1090 
(subpart I). For these subparts, we have included general provisions 
that apply to all regulated parties, with sections devoted to specific 
requirements for individual groups of regulated parties (e.g., gasoline 
refiners or oxygenate blenders).
    Subpart Q includes the liability, compliance, and violation 
provisions that EPA enforcement staff would use to enforce the program. 
This subpart consolidates the similar sections from across part 80 into 
a single streamlined subpart.
    Finally, subpart R includes the attest engagement procedures that 
independent auditors would need to use to conduct annual auditing of 
reports and records for gasoline refiners. These procedures are updated 
versions of the those already included in part 80.
    We believe that this new structure would make the fuel quality 
regulations more accessible to all stakeholders, help ensure compliance 
by making requirements more easily identifiable by activity, and help 
future participants in this regulated space understand our fuel quality 
regulations in the future. We seek comment on this proposed structure 
of the regulations.

B. Implementation Dates

    We are proposing that regulated parties would begin complying with 
most provisions of part 1090 on January 1, 2021. This proposed date 
would result in the first compliance reports for the 2021 compliance 
period being due March 31, 2022, and the first attest engagement 
reports for the 2021 compliance period being due June 1, 2022.
    We believe that this action minimizes the need for immediate 
changes to how regulated parties comply with our fuel quality 
regulations, and therefore, this proposed implementation schedule will 
allow sufficient time for regulated parties to modify their current 
business practices whenever it makes the most business sense for the 
individual regulated party's situation. In general, we have tried to 
minimize changes to existing requirements for regulated parties so as 
to avoid unnecessary burden. However, to consolidate the RFG program 
with the other fuel quality programs and maximize fuel fungibility, 
some changes to the program design would result from consolidating the 
programs into a single national program. Where possible, we wrote the 
proposed requirements to allow flexibility for regulated parties to 
adjust as needed.
    While we believe a January 1, 2021, implementation date provides 
regulated parties enough time to come into compliance since we are not 
requiring changes that would necessitate substantive investments to 
meet new or modified fuel quality standards, we received feedback 
during the rule development process that we may need to provide 
regulated more time to implement some of the proposed provisions. In 
particular, some stakeholders noted that modifying product transfer 
document (PTD) language and adjusting to some of the proposed changes 
for sampling and testing may not be possible by January 1, 2021. One 
potential solution is to allow more time for these specific provisions 
to phase in. For example, we could allow regulated parties to continue 
to use the part 80 PTD requirements until the beginning or end of the 
high ozone season (June 1 and September 15, respectively). A similar 
approach could be allowed for other provisions that potentially need 
more lead time. We seek comment specifically on what provisions may 
require additional lead time to implement.

C. Prior Approvals

    We are proposing to allow regulated parties with existing approvals 
under part 80 to maintain those approvals under part 1090. For example, 
parties registered under part 80 would not need to reregister under 
part 1090. We believe that making regulated parties resubmit 
information already reviewed and approved by EPA would be duplicative 
and burdensome on both the regulated parties and EPA staff. However, 
this action would require that any new requests or updates to approvals 
currently necessary under part 80 would have to meet the new proposed 
regulatory requirements of part 1090.
    For existing approvals under part 80, regulated parties would not 
need to update a previously approved submission under part 1090. For 
example, we have approved alternative E15 labels under part 80. Parties 
would not need to have these labels reapproved in order to use them 
under part 1090. One notable exception is for in-line blending waivers. 
As discussed more in Section XIII.G, we are proposing significant 
changes to the in-line blending waiver provisions for RFG (mostly to 
remove provisions related to parameters that would no longer need to be 
reported) and for CG, which are designed to make consistent with the 
proposed RFG in-line blending waiver provisions. As such, we are 
proposing to require resubmission of all in-line blending waiver 
requests to ensure that they meet the new requirements.

D. Definitions

    We are proposing to streamline and update the definitions contained

[[Page 29039]]

throughout part 80, as well as add and remove terms as needed to write 
the proposed part 1090 regulations. How we define key terms in the 
regulations has a significant effect on how regulated parties comply 
with the regulations. As our fuel quality programs have expanded in 
scope, definitions in part 80 have expanded as well. Additionally, as 
we added new subparts to the part 80 regulations for each program, we 
have added subpart specific definitions. We have also defined terms in 
the context of specific sections of the regulations. This has created 
situations where sometimes there are differences in definitions for the 
different standards, which makes it more difficult for parties to 
comprehend and comply with the regulations. In part 1090, we have 
consolidated all the applicable definitions into a single section. We 
have tried to avoid having a definition section in individual subparts; 
however, some infrequently-used terms may still be defined in the 
context of the regulatory text. We believe this approach would help the 
regulated community and the public at large to more easily comprehend 
the regulations.
    For the most part, we are proposing to transfer the existing part 
80 definitions into part 1090 with minor proposed changes to specific 
terms for consistency. However, in some cases, we are proposing to 
redefine or reclassify key terms as part of part 1090. Specifically, 
these areas include the defined terms for the types of regulated 
products (discussed in Section III.D.1) and the descriptions of 
regulated parties (discussed in Section III.D.2). We are also proposing 
revisions to the definition of ``gasoline'' and ``diesel fuel'' 
(discussed in Section III.D.3). While we believe these three areas of 
the proposed definitions warrant significant discussion, we seek 
comment on all of the proposed definitions.
1. Fuels, Fuel Additives, and Regulated Blendstocks
    In order to improve the clarity and consistency of our regulations, 
we are proposing changes regarding how to classify products regulated 
under our fuel quality regulations. In part 80, most fuel programs were 
written as a separate fuel program rather than a single, consolidated 
fuel quality program. For example, 40 CFR part 80, subpart I, almost 
exclusively deals with distillate fuels and 40 CFR par 80, subpart N, 
deals with gasoline-ethanol blended fuels. Since part 1090 would 
attempt to consolidate all fuel quality programs under part 80 into a 
single, consolidated fuel quality program, a consistent nomenclature 
for regulated products is needed.
    This action describes requirements for fuel quality on three 
categories of products: Fuels, regulated blendstocks, and fuel 
additives. We further classify these products into bins based on the 
type of vehicle or engine that the fuel is used (i.e., gasoline-fueled, 
diesel fueled, or in a vessel subject to MARPOL Annex VI requirements 
(e.g., vessels that must use ECA or IMO marine fuel)). For gasoline-
fueled engines, we not only define the term gasoline (discussed in 
detail in Section III.D.2), but we also define and place requirements 
on specific types of gasoline based on its ethanol content (e.g., E0, 
E10, and E15), whether the gasoline is intended for use or used as 
summer or winter gasoline, and in the summer, what RVP standard the 
fuel is subject to (i.e., 9.0 psi, 7.8 psi, or the proposed RFG 7.4 psi 
standard). For diesel-fueled engines, since the requirement to use 15 
ppm diesel fuel (or ultra-low-sulfur diesel (ULSD)) is now required in 
almost all motor vehicle, non-road, locomotive, and marine applications 
(called MVNRLM diesel fuel in part 80), we are defining this fuel 
simply as ULSD, as it is more commonly known in the market. 500 ppm 
diesel fuel continues to be allowed for certain locomotive and marine 
applications.
    Regarding regulated blendstocks, we have historically not imposed 
quality specifications on blendstocks, choosing instead to focus 
compliance requirements on finished fuels that are ultimately used in 
vehicles and engines. However, as the fuels marketplace has continued 
to evolve, this structure has become increasingly difficult to 
accommodate the complexity of manufacturing and distributing fuels 
practices today. Therefore, we are proposing alternative provisions, 
which are all currently permissible under part 80, for gasoline 
manufacturers to demonstrate compliance with our fuel quality 
requirements by imposing requirements on certain blendstocks that are 
added to previously certified gasoline (PCG) if certain conditions are 
met. We are referring to blendstocks for which we have proposed 
standards collectively as ``regulated blendstocks.'' For example, under 
both part 80 and the proposed part 1090 regulations, we allow gasoline 
refiners to blend butane into gasoline and to rely on test results from 
the producers of the butane if the butane meets more stringent sulfur 
and benzene per-gallon standards.\7\ These butane blenders can use 
these provisions in lieu of certifying the finished gasoline and having 
to meet sulfur and benzene annual standards as these provisions are 
designed to ensure that the national sulfur and benzene pool do not 
increase as a result of blending these feedstocks. Under part 1090, we 
are proposing the same flexibilities as under part 80 for gasoline 
manufacturers that wish to blend butane that has been certified to meet 
specifications (differences between parts 80 and 1090 are discussed in 
Section V.A.3). We believe that this will also allow more opportunities 
for parties to make cost-effective compliant fuels in the future.
---------------------------------------------------------------------------

    \7\ Under part 80, for summer CG, a butane blender must test the 
finished gasoline (i.e., the resultant fuel from the combined PCG 
and added butane) for the RVP; for RFG, butane blenders cannot blend 
butane into summer RFG. This provision is not changing in part 1090.
---------------------------------------------------------------------------

    This action also includes the current part 80 specifications for 
gasoline and diesel additives, mostly unchanged. Except for oxygenates 
in gasoline, additives are added to fuels in low amounts (less than 1.0 
volume percent of the fuel total) and often serve to help improve fuel 
performance (e.g., to control deposits on intake valves). All diesel 
fuel additives are subject to sulfur limitations. Under both part 80 
and part 1090, gasoline additives are also subject to sulfur 
limitations, but the term ``gasoline additives'' also includes gasoline 
detergents and oxygenates. Also under both part 80 and part 1090, 
gasoline detergents and oxygenates (including denatured fuel ethanol or 
DFE) have specific requirements that apply in addition to the sulfur 
requirements that apply for all gasoline additives.
2. Fuel Manufacturers, Regulated Blendstock Producers, and Fuel 
Additive Manufacturers
    In part 80, a refinery is defined as '' any facility, including but 
not limited to, a plant, tanker truck, or vessel where gasoline or 
diesel fuel is produced, including any facility at which blendstocks 
are combined to produce gasoline or diesel fuel, or at which blendstock 
is added to gasoline or diesel fuel,'' \8\ while a refiner is ``any 
person who owns, leases, operates, controls, or supervises a 
refinery.'' \9\ When these terms were first defined, virtually all 
finished fuels were produced at a crude oil refinery. As we have 
permitted greater flexibility in the production of fuels through the 
blending of regulated blendstocks to make new fuels and the market has 
moved to allowing fuels to be produced downstream of crude oil

[[Page 29040]]

refineries, the use of the term ``refiner'' to encompass all parties 
that make fuels has become less appropriate. Additionally, the 
differences in terminology between part 79 and part 80 have caused 
confusion among those required to or potentially required to comply 
with the requirements of both parts. Refiners and importers of on-
highway motor vehicle gasoline and diesel fuel are fuel manufacturers 
under part 79 and required to register under EPA's fuel and fuel 
additive registration (FFARs) requirements. Under part 79, parties that 
make gasoline or diesel fuel through the blending of blendstocks or 
blending of blendstocks into PCG are also considered fuel manufacturers 
and must registered under part 79. Part 79 also includes importers of 
on-highway motor vehicle gasoline and diesel fuel as fuel manufacturers 
for purposes of FFARs. Part 80 generally requires that importers of 
gasoline and diesel fuel meet the same requirements as refiners, with 
some additional requirements on importers depending on the situation.
---------------------------------------------------------------------------

    \8\ 40 CFR 80.2(h).
    \9\ 40 CFR 80.2(i).
---------------------------------------------------------------------------

    This action uses the term fuel manufacturer to describe any party 
that owns, leases, operates, controls, or supervises a facility where 
fuel is produced, imported, or recertified, whether through a refining 
process (e.g., through the distillation of crude oil), through blending 
of blendstocks or blending blendstocks into a previously certified fuel 
to make fuel, or through the recertification of products not subject to 
our fuel quality standards to fuels that are subject to our fuel 
quality standards (e.g., redesignating heating oil to ULSD). Importers 
of fuels would continue to be fuel manufacturers consistent with parts 
79 and the CAA. We are also proposing to further distinguish between 
parties that refine feedstocks to make fuels (more commonly known as 
``crude refiners'') and blending manufacturers who make fuels through 
blending blendstocks together to make a fuel or into an existing fuel 
to make a new fuel.\10\ This action includes requirements specific to 
the type of fuel manufacturer, and the proposed nomenclature makes it 
easier for us to describe the proposed requirements for the types of 
fuel manufacturers and for parties to understand what requirements 
apply specifically to whom. However, while we are proposing to modify 
the terminology used in part 1090 for these parties, generally, these 
parties would have the same obligations and responsibilities under the 
regulations.
---------------------------------------------------------------------------

    \10\ Under this approach, transmix processors are also 
considered fuel manufacturers.
---------------------------------------------------------------------------

    We are proposing to define producers of regulated blendstocks as 
regulated blendstock producers. For example, these parties would 
include certified butane/pentane producers and oxygenate producers 
(including DFE producers).
    As is the case currently under parts 79 and 80, parties that only 
blend fuel additives into fuels are not fuel manufacturers. Any party 
that adds a compound (other than oxygenate or transmix) that is 1.0 
percent or more of the finished fuel would be a blending manufacturer, 
as the compound added would be considered a blendstock and parties that 
add blendstocks into fuel are considered fuel manufacturers and would 
need to meet all the applicable regulatory requirements. Consistent 
with part 79, oxygenate blenders that only add oxygenates at levels 
permissible under the CAA section 211(f) continue to be considered 
additive blenders and not fuel manufacturers.
3. Definition of Gasoline
    This action includes a new definition of gasoline. When we define 
what constitutes a fuel, this determines which fuels are subject to our 
fuel quality standards. The goal of our fuel quality programs is to 
ensure that compliant fuel is ultimately used in vehicles, engines, and 
equipment. To achieve this goal, we believe that the definition of 
gasoline needs to reflect changes in the fuels marketplace that have 
occurred over the last 40 years, as well as potential changes on the 
horizon. While petroleum refineries still have the most direct impact 
on gasoline fuel quality by volume, every party downstream of the 
refinery can affect fuel quality, and in today's marketplace many of 
these downstream parties are now the determinant of the quality of the 
fuel that actually goes into the vehicle. For example, these parties 
may add oxygenates (primarily ethanol) or augment the volume of 
gasoline through the blending of various blendstocks into PCG to 
produce new fuels.
    To ensure that gasoline meets fuel quality standards from the 
petroleum refinery until it is dispensed into a gasoline-fueled vehicle 
or engine, in light of the changing fuels marketplace, we believe that 
the definition of gasoline should contain three elements. First, when a 
party represents a fuel as meeting our fuel quality standards, such 
fuel is subject to our standards regardless of whether the fuel meets 
the standard. Were this not the case, then anytime a fuel failed to 
meet our standards, we could not hold anyone accountable for failing to 
meet the standards. In the proposed definition of gasoline, we define 
gasoline as anything commonly and commercially known as gasoline. This 
portion of the proposed definition is consistent with the existing 
parts 79 and 80 definitions of gasoline.
    The second element of the definition of gasoline is whether the 
product is made available for use or used in a gasoline-fueled vehicle 
or engine. Since the ultimate purpose of our fuel standards is to 
ensure that compliant fuel is used in vehicles and engines, if a person 
makes a product available for use by designating it as gasoline or 
placing it in the fuel distribution system, or if the product is used 
in a gasoline-fueled vehicle or engine, the product should be subject 
to EPA standards. We have used this terminology when describing other 
fuels under part 80, notably in definitions related to motor vehicle 
diesel fuel \11\ and ECA marine fuel.\12\
---------------------------------------------------------------------------

    \11\ See 40 CFR 80.2(y).
    \12\ See 40 CFR 80.2(ttt).
---------------------------------------------------------------------------

    The third element of the definition of gasoline is the product's 
physical and chemical characteristics. Whether a fuel is subject to our 
standards cannot be solely based on whether a regulated party calls or 
labels a product it produces as gasoline. This would create an 
incentive for parties to simply label fuel intended for use as gasoline 
by another name to avoid having to meet our fuel standards. Therefore, 
when a manufacturer produces a fuel that is chemically and physically 
similar to gasoline, the fuel should be subject to our gasoline fuel 
standards. To address this element, we are proposing that gasoline is 
any product that meets the voluntary consensus standards body (VCSB) 
industry specifications for gasoline (ASTM D4814).
    For the discussion drafts of the regulations,\13\ we presented 
definitions of gasoline that attempted to conservatively capture any 
product that could be used in vehicles and engines designed to operate 
on gasoline. We received feedback from stakeholders suggesting that 
this definition of gasoline was too broad, especially concerning the 
third element, which would have resulted in blendstocks that are never 
intended to be sold in their pure form as gasoline being subject to our 
fuel quality standards. These stakeholders argued that some higher 
quality blendstocks (e.g., alkylates) used to make gasoline would meet 
the ASTM D4814 specifications for gasoline and may therefore be subject 
to EPA

[[Page 29041]]

standards. To address this feedback, we have excluded those blendstocks 
of concern that are not made available as gasoline but may otherwise 
meet the definition of gasoline by meeting ASTM D4814 specifications. 
Since there is an economic incentive for parties to keep these high 
value blendstocks segregated from gasoline in the fuel distribution 
system, these products will not generally be made available for use in 
gasoline-fueled vehicles and engines and would not, therefore, be 
considered gasoline. We seek comment on this approach.
---------------------------------------------------------------------------

    \13\ EPA-420-D-18-001, EPA-420-D-18-002, and EPA-420-D-19-001, 
available in the docket for this action.
---------------------------------------------------------------------------

    We have taken a similar approach in the part 80 definitions for 
diesel fuel and largely mirror the three elements proposed for the 
definition of gasoline in the definition of diesel fuel. We seek 
comment on these definitions.

IV. General Requirements for Regulated Parties

    As part of the streamlined fuel quality program, we are proposing a 
subpart dedicated to outlining the general regulatory requirements for 
each regulated party (subpart B). We received feedback during the rule 
development process that due to the layout of the regulations in part 
80, parties need to read the entire subpart to make sure they have 
identified all applicable regulatory requirements. The current 
regulations in part 80 are almost 1,000 pages long, and many regulated 
parties spend a substantial amount of resources to comprehend and 
interpret them or ask EPA staff through the help desk to identify 
applicable regulatory requirements.
    To make the streamlined regulations more accessible, we are 
proposing to make subpart B a roadmap for regulated parties, directing 
them to those subparts that are most likely to affect them and their 
business. We first outline the general requirements applicable to all 
parties that make and distribute fuels, fuel additives, and regulated 
blendstocks. These requirements include keeping records and being 
subject to regulatory requirements under the proposed subpart if a 
party makes and distributes fuels, fuel additives, and regulated 
blendstocks.
    We then describe the requirements that apply to each group of 
regulated parties based on their business activities. Examples of these 
categories are fuel manufacturers, detergent blenders, oxygenate 
blenders, and retailers. We believe this would help these parties more 
easily identify regulatory provisions that apply to their specific 
activities. For example, retailers are typically small businesses that 
have greater difficulty affording consultants to help them understand 
their regulatory requirements. Retailers also have a relatively small 
number of regulatory requirements under the part 80 and part 1090 
regulations. By identifying the generally applicable requirements that 
apply to all retailers, these small businesses could more easily 
identify those regulatory requirements that apply to them, helping them 
to more easily comply with our fuel quality regulations.
    It is important to note that parties may have more than one 
regulated activity, and, as is the case today, these parties would be 
required to satisfy all regulatory requirements for each regulated 
activity. Regulated parties would still need to comply with all 
applicable requirements contained in part 1090, regardless of whether 
they are identified for them in subpart B. EPA cannot predict every 
possible situation a party may be in within the market place now or in 
the future. Accordingly, regulated parties, as always, should pay 
careful attention to all the applicable regulatory requirements to 
ensure compliance.
    We request comment on the proposed structure of subpart B, as well 
as whether the subpart would be helpful to regulated parties in 
general. We also request comment on how we can improve the streamlined 
regulations to further improve the understandability and navigation of 
part 1090.

V. Standards

A. Gasoline Standards

1. Overview and Streamlining of Gasoline Program
    We are proposing to consolidate the various gasoline-related 
standards into a single subpart in part 1090 (subpart C). We are not 
proposing to change the lead, phosphorous, sulfur, benzene standards or 
the RVP gasoline standards in the summer, nor are we proposing to 
change the standards for oxygenates (including denatured fuel ethanol), 
certified ethanol denaturant, gasoline additives, and standards for 
certified butane and pentane. These standards are simply being moved 
and consolidated into subpart C. Any comments on these standards will 
be treated as beyond the scope of this rulemaking.
    However, to streamline the gasoline program, we are proposing some 
changes in the form of the RFG VOC performance standards. These changes 
are not expected to change the stringency of the gasoline standards. We 
do, however, expect that these changes would greatly simplify the 
gasoline program, resulting in: (1) Reduced burden associated with 
demonstrating compliance with the gasoline standards; (2) improved 
fungibility of gasoline, allowing the market to operate more 
efficiently; and (3) reduced costs to consumers. First, we are 
proposing to translate the RFG standard from the demonstration of the 
VOC performance standard via the complex model into an equivalent 
maximum RVP per-gallon standard, which would allow us to greatly 
simplify the compliance demonstration requirements for RFG. Of all the 
provisions being proposed, this is the key provision enabling 
considerable streamlining of our existing gasoline regulations.
    Second, we are also proposing to consolidate the two grades of 
butane and the two grades of pentane specified in part 80 for use by 
butane and pentane blenders into a single grade each of certified 
butane and certified pentane. This would greatly simplify the 
registration and reporting of activities related to blending certified 
butane and certified pentane.
    Finally, we are proposing certain regulations related to summer 
gasoline, as well as procedures for states to relax the federal 7.8 psi 
RVP standard. These changes are discussed more thoroughly in the 
following sections.\14\
---------------------------------------------------------------------------

    \14\ The proposed changes to the transmix provisions for 
gasoline and diesel fuel are addressed in Section XIII.E.
---------------------------------------------------------------------------

2. Reformulated Gasoline Volatility Standard
    The RFG program was created by EPA in the 1990s in response to a 
directive from Congress in the CAA Amendments of 1990 with the express 
purpose of providing cleaner burning gasoline to the most polluted 
metropolitan areas of the country. The program was very successful in 
that regard. However, since that time, a series of additional fuel 
quality standards and other market changes have resulted in CG meeting 
or exceeding most of the performance requirements for RFG, with the 
primary difference between CG and RFG now being only the lower RVP of 
the RFG during the summer months. At the same time, the extensive RFG 
regulations remain, constraining gasoline fungibility, increasing 
costs, complicating compliance oversight, and limiting the sale of 
certain biofuel blends. Consequently, we are proposing to: (1) Replace 
the existing compliance mechanism used for RFG batch certification--the 
Complex Model--with a summer RVP maximum per-gallon standard; (2) apply 
that same single RVP standard to all RFG nationwide; (3) provide 
greater

[[Page 29042]]

flexibility for blending of oxygenates (ethanol and biobutanol) and E0 
in RFG areas; and (4) remove a number of other restrictions that now 
create a distinction without a difference between RFG and CG.
    We intend these proposed changes to maintain the stringency of all 
standards associated with RFG while alleviating unnecessary compliance 
mechanisms by simplifying the recordkeeping and reporting requirements. 
We acknowledge that the CAA requires the existence of RFG in specified 
nonattainment areas \15\ and certification procedures to certify RFG as 
complying with the requirements.\16\ This action proposes to simplify 
and translate those requirements while still maintaining the same level 
of VOC emissions reductions as currently required. This would be 
accomplished by translating the current VOC emissions reductions 
demonstrated through the Complex Model into an RVP standard that would 
be used to demonstrate RFG VOC compliance in lieu of the Complex 
Model.\17\
---------------------------------------------------------------------------

    \15\ CAA section 211(k)(1).
    \16\ CAA section 211(k)(4)(A).
    \17\ Currently, refiners use the Complex Model to demonstrate 
compliance with the RFG provisions. We are proposing that refiners 
instead could demonstrate compliance by testing the RVP of the fuel, 
along with benzene and sulfur as currently required.
---------------------------------------------------------------------------

    CAA section 211(k)(3)(B) provides that during the high ozone 
season, ``the aggregate emissions of ozone forming volatile organic 
compounds from baseline vehicles when using the reformulated gasoline 
shall be 15 percent below the aggregate emissions of ozone forming 
[VOCs] from such vehicles when using baseline gasoline.'' This section 
also provides for increasing stringency beginning in 2000 of at least 
25 percent, based on technological feasibility and costs. We are 
achieving that demonstration through the use of an RVP standard.
    The proposed RFG summer RVP standard of 7.4 psi was specifically 
chosen in order to maintain the summer VOC performance required by the 
statute,\18\ and this RVP is currently observed in the RFG fuel pool; 
this approach also aligns the RFG compliance provisions with the much 
simpler and more easily enforced provisions currently in place for CG. 
In doing so, we are also acting on the Energy Policy Act of 2005 
(EPAct) directive to consolidate the RFG VOC Regions into a single set 
of RFG standards by applying the southern RFG requirements (VOC control 
region 1) to all RFG areas, as discussed further in Section V.A.2.d. 
This consolidation of RFG VOC Regions, along with other proposed 
changes in this action, would provide greater fungibility in the RFG 
pool and eliminate antiquated restrictions in order to provide greater 
flexibility to fuel manufacturers and distributors, reduce cost for 
those parties, and reduce compliance and enforcement oversight costs.
---------------------------------------------------------------------------

    \18\ The VOC performance standard specifies that reductions are 
as compared to baseline vehicles using baseline gasoline. CAA 
section 211(k)(10) defines ``baseline vehicles'' as representative 
of 1990 vehicles and ``baseline gasoline'' as those with parameters 
specified in Table V.A.2.a-1. Our proposed translation of the VOC 
performance standard uses the statutorily specified points of 
comparison (i.e., 1990 vehicle technology using baseline gasoline as 
specified in the CAA).
---------------------------------------------------------------------------

    Additional benefits from this proposed action are potentially wide 
reaching and could create opportunities for broader availability of 
fuels and reduced consumer costs. With the introduction of a summer RVP 
standard for RFG, in situations of fuel shortage in RFG areas, gasoline 
from other RFG areas or from state low-RVP fuel programs could now be 
moved to affected areas without recertification so long as the RFG RVP 
standard is observed. This increase in gasoline fungibility should 
serve to reduce scarcity and promote lower prices for consumers in 
affected areas. Additionally, the desire for ethanol-free gasoline for 
marine use in RFG areas has regularly been expressed by both citizens 
and elected officials of areas where RFG is required. Under the current 
RFG compliance provisions in part 80, it is difficult for distributors 
to provide ethanol-free gasoline to consumers in RFG areas. Under part 
1090, it would be easier for distributors to provide ethanol-free 
gasoline to consumers in these areas.
a. Review of RFG
    The definition and use of RFG is stipulated in CAA section 211(k). 
The RFG program was established in response to exceedances of the 
National Ambient Air Quality Standards (NAAQS) for ozone being 
experienced in many metropolitan areas across the U.S. in the late 
1980s.\19\ Gasoline motor vehicle emissions were and continue to be a 
major contributor to the inventory of air pollutants in metropolitan 
areas. The RFG program is implemented through a set of gasoline 
standards demonstrated to reduce emissions from vehicles of that 
era.\20\ The demonstration of emissions reductions was predicated on 
changing fuel properties from a baseline fuel composition used in the 
baseline vehicle fleet. The 1990 statutory baseline fuel and fleet 
codified in the RFG regulations in part 80 are presented in Table 
V.A.2.a-1.
---------------------------------------------------------------------------

    \19\ See ``National Air Quality and Emissions Trends Report, 
1988,'' EPA-450/4-90-002, March 1990.
    \20\ Gorse, R.A. et al. (1997). Auto/Oil Air Quality Improvement 
Research Program Final Report. 10.13140/RG.2.2.20882.35521.

          Table--V.A.2.a-1--Statutory Baseline Fuel Composition
------------------------------------------------------------------------
                                           Summer            Winter
------------------------------------------------------------------------
RVP (psi)...........................               8.7              11.5
Benzene (vol%)......................              1.53              1.64
Aromatics (vol%)....................              32.0              26.4
Olefins (vol%)......................               9.2              11.9
Sulfur (ppm)........................               339               338
E200 (%)............................              41.0              50.0
E300 (%)............................              83.0              83.0
Oxygen (wt%)........................               0.0               0.0
------------------------------------------------------------------------
Summer = June 1-September 15.

    The compliance of RFG in comparison to the baseline fuel was 
originally demonstrated by refiners using the Simple Model.\21\ An 
improved version of the compliance model was created and designated the 
Phase II Complex Model after the initial phase of the RFG program. The 
Complex Model has been used by refiners to certify RFG

[[Page 29043]]

under the Phase II RFG program and to meet the emission reduction 
standards outlined in Table V.A.2.a-2.
---------------------------------------------------------------------------

    \21\ See 40 CFR 80.42.

   Table V.A.2.a-2--Phase II Standards and Requirements for Compliance
------------------------------------------------------------------------
 
------------------------------------------------------------------------
                Phase II Complex Model Averaged Standards
------------------------------------------------------------------------
VOC Emission Performance Reduction (%):
    Region 1 standard.................................           >= 29.0
    Region 1 per-gallon standard......................           >= 27.5
    Region 2 standard.................................           >= 27.4
    Region 2 per-gallon standard......................           >= 25.9
    Region 2 (Chi/Milw) standard......................           >= 25.4
    Region 2 (Chi/Milw) per-gallon standard...........           >= 23.9
Toxic Air Pollutants Emission Performance Reduction              >= 21.5
 (%)..................................................
NOX Emission Performance Reduction (%):
    Gasoline designated as VOC-controlled.............            >= 6.8
    Gasoline not designated as VOC-controlled.........            >= 1.5
Benzene (vol%):
    Standard..........................................           <= 0.95
    Per-gallon maximum................................           <= 1.30
------------------------------------------------------------------------

    The Complex Model required refiners to sample and test RFG for 11 
parameters that would then be entered into the model. Refiners could 
either demonstrate compliance on a per-gallon basis or on an average 
basis across the year. Despite the added flexibility associated with 
the Complex Model over the Simple Model, refiners tended to focus 
changes on just a few parameters. To comply with the VOC emissions 
performance standard, refiners primarily lowered the RVP of their RFG 
as was anticipated at the time of the rule. For the NOX 
standard, refiners primarily lowered the sulfur content of RFG, and to 
comply with the toxics standard, benzene and aromatics content was 
reduced in their RFG. Additionally, there have been three different RFG 
VOC regions designated under the Phase II standards; each with slightly 
different required levels of VOC emissions reduction as compared to the 
baseline fuel. The RFG program operated under these standards and 
resulted in a gasoline composition that was vastly different from CG 
when the program was phased in from 1995 through 2000.
b. Gasoline Regulation Changes
    Since 2000, however, through a series of gasoline regulations and 
marketplace changes, the environmental performance of CG has improved 
to equal that of RFG in all respects except for summer VOC emission 
performance (as estimated using the Complex Model).
    We established the Tier 2 gasoline sulfur program to limit the 
average sulfur content in gasoline to 30 ppm beginning in 2004,\22\ 
with an 80 ppm per-gallon maximum standard (95 ppm at any location 
downstream of a refinery or import facility).\23\ A reduction in fuel 
sulfur would reduce NOX emissions on its own accord (as 
expressed in the Complex Model), but fuel sulfur reduction was also 
paramount to protecting the exhaust aftertreatment systems necessitated 
by the more stringent vehicle emission standards established as part of 
the same Tier 2 program rulemaking. By the end of 2007, after the 
conclusion of all early credit, small refinery hardship extensions, and 
other program flexibilities, the sulfur level of all gasoline was 
reduced to less than 30 ppm in-use. The Tier 2 gasoline sulfur 
standards reduced VOC, NOX, and air toxics emissions, and 
brought down RFG and CG sulfur levels to a low enough level that the 
NOX emission performance standard determined using the 
Complex Model were met and exceeded for any compliant RFG. 
Consequently, the NOX emission performance standard was 
thereafter deemed met for both RFG and Antidumping (i.e., CG) if the 
Tier 2 gasoline sulfur standard was met. This represented the first 
time that gasoline standard for CG exceeded an RFG performance standard 
(the NOX performance standard in this case) on average, but 
it also heralded the convergence in gasoline quality between CG and RFG 
that would continue to occur over the next decade.
---------------------------------------------------------------------------

    \22\ See 65 FR 6698 (February 10, 2000).
    \23\ See 40 CFR 80.195 and 40 CFR 80.210, respectively.
---------------------------------------------------------------------------

    In 2007, EPA revised the original Mobile Source Air Toxics (MSAT) 
Rule with the MSAT2 Gasoline Benzene Program.\24\ This rulemaking 
established an annual average standard of 0.62 volume-percent benzene 
on refiners and importers of gasoline.\25\ This standard took effect 
starting January 1, 2011, for non-small refiners and January 1, 2015, 
for small refiners. The standard was fully phased-in on January 1, 
2018. The result was that the air toxics performance standards for RFG 
were surpassed by the MSAT2 benzene standards for CG. Consequently, 
fuels that met MSAT2 benzene standards were deemed compliant with the 
air toxics emission performance standard otherwise calculated using the 
Complex Model. The rationale held, as with Tier 2, that any fuel 
meeting the new standard would meet or exceed the reductions required 
by the statute. The MSAT2 rulemaking also eliminated the NOX 
emissions performance reduction demonstration in the Complex Model as a 
result of the gasoline sulfur program.\26\
---------------------------------------------------------------------------

    \24\ See 72 FR 8428 (February 26, 2007).
    \25\ See 40 CFR 80.815.
    \26\ See 40 CFR 80.41(e)(2) and 72 FR 8428, 8498 (February 26, 
2007).
---------------------------------------------------------------------------

    The combined effect of the sulfur and benzene gasoline standards 
has been that the use of the Complex Model has been narrowed to only 
demonstrating compliance with the summer VOC emission performance 
standard for RFG. While all of the Complex Model fuel parameters 
(except benzene) play a role in determining VOC emission performance, 
by far the primary lever for refiners to use to comply with the VOC 
emission performance standard is RVP.\27\ Given that the changes to all 
the

[[Page 29044]]

other fuel parameters are dictated by other vehicle standards and 
market requirements, refiners today primarily only lower RVP to the 
degree necessary (due to cost reasons) in order to meet the VOC 
emission performance standard of RFG. However, the degree to which 
refiners have needed to reduce the RVP of RFG to demonstrate compliance 
using the Complex Model has relaxed slightly over time with other 
changes, mandated and market, to gasoline.
---------------------------------------------------------------------------

    \27\ The VOC performance standard is made up of two components: 
Non-exhaust and exhaust VOCs. Under the Complex Model, 100 percent 
of the non-exhaust VOCs are calculated using RVP, which also plays a 
significant role in determining exhaust VOC reductions under the 
Complex Model. In both non-exhaust and exhaust VOCs, the Complex 
Model estimates an increase in performance of the fuel on 1990 
vehicle technology relative to the 1990 baseline gasoline 
specifications.
---------------------------------------------------------------------------

    In 2014, EPA finalized the Tier 3 gasoline sulfur program to 
further limit the average sulfur content in gasoline to 10 ppm 
beginning in 2017.\28\ All refineries and importers, including small 
refiners and small volume refineries, must comply with the 10 ppm Tier 
3 sulfur standard starting January 1, 2020. The Tier 3 sulfur standard 
resulted in further reductions in VOC, NOX, and air toxics 
emissions predicted by the Complex Model.
---------------------------------------------------------------------------

    \28\ See 40 CFR 80.1603.
---------------------------------------------------------------------------

    Beginning in the early 2000s, the amount of gasoline blended with 
10 percent ethanol also increased markedly as a result of MTBE bans, 
rising crude oil prices, tax incentives, and the Renewable Fuel 
Standard (RFS) mandates. The addition of ethanol reduced the aromatic, 
olefin, T50, and T90 levels of gasoline, which together with the oxygen 
content reduced the VOC, NOX, and air toxics emissions 
predicted by the Complex Model. Similarly, since about 2009, reduced 
natural gas prices brought on by the proliferation of hydraulic 
fracturing technology has allowed refiners to more economically back 
off on gasoline reforming, continuing to reduce gasoline aromatic 
levels and in turn reducing VOC, NOX, and air toxics 
emissions predicted by the Complex Model.
    The progression in gasoline sulfur, benzene, and aromatic content, 
RVP, distillation, and other Complex Model parameters is documented in 
the Fuel Trends Report released by EPA in 2017.\29\ The evolution of 
these other Complex Model parameters over the past decade has allowed 
for a slight increase in RVP, as seen in Figure V.A.2.b-1.
---------------------------------------------------------------------------

    \29\ See ``Fuel Trends Report: Gasoline 2006--2016,'' EPA-420-R-
17-005, October 2017.
[GRAPHIC] [TIFF OMITTED] TP14MY20.000

    RVP is the only one of the Complex Model parameters that affects 
evaporative emissions; the other fuel parameters (except benzene and 
including RVP) impact VOC exhaust emissions under the Complex Model. As 
a result, there are limits to the extent that these other fuel 
parameters can impact VOC emissions performance under the Complex Model 
and corresponding limits to the extent that RVP can be increased within 
the Complex Model and still result in a compliant RFG.\30\ Figure 
V.A.2.b-2 shows the 95th percentile of RVP levels from the batch 
compliance data EPA receives.
---------------------------------------------------------------------------

    \30\ In the RFG final rule, we found that a fuel with an RVP of 
7.2 would meet the Region 1 VOC performance standards. See 59 FR 
7716, 7721 (February 16, 1994).

---------------------------------------------------------------------------

[[Page 29045]]

[GRAPHIC] [TIFF OMITTED] TP14MY20.001

c. Proposed RVP Standard for VOC Performance Determination
    With the importance of RVP in the Complex Model for VOC emissions 
performance and the combination of MSAT2 and Tier \2/3\ for reducing 
benzene and sulfur, respectively, RFG compliance is now almost 
completely determined by the RVP of the fuel. Consequently, an 
opportunity for greatly simplifying the certification process for RFG 
has presented itself. The 11 parameters required to certify RFG under 
the Complex Model could be reduced to just three (sulfur, benzene, and 
RVP) if a summer RVP standard were adopted along with the existing 
sulfur and benzene content standards.\31\ Therefore, we are proposing 
that any RFG batch meeting a summer RVP standard of 7.4 psi RVP would 
be deemed in compliance with the RFG VOC emission performance reduction 
standard. Along with RVP, benzene concentration for MSAT2 compliance, 
and sulfur content for Tier 3 compliance would also be reported to EPA. 
Thus, all three of the emission reduction standards for RFG would be 
covered by just three parameters: RVP, benzene, and sulfur. This would 
reduce the compliance and reporting burden for fuel manufacturers by 
reducing the number of parameters they need to test and report from 11 
to as few as three in the summer.\32\
---------------------------------------------------------------------------

    \31\ As discussed in Section IX, manufacturers that certify 
batches of oxygenated gasoline would need to test for oxygenates, 
while manufacturers of BOBs would need to follow hand blending 
procedures for batch certification.
    \32\ As discussed in sections VIII and IX, manufacturers would 
need to sample, test, and report for additional fuel.
---------------------------------------------------------------------------

    In Section V.A.2.e, we lay out the process and rationale for the 
proposed summer RVP per-gallon standard of 7.4 psi for RFG. The primary 
intent in proposing to translate the VOC performance standards into an 
RVP maximum per-gallon standard is to maintain the status quo and to 
ensure that the emission reduction targets for RFG would continue to be 
achieved. During the selection process of the proposed summer RVP 
standard, we operated under the statutory constraints that were, and 
remain, present for the formulation of the Complex Model--namely, the 
1990 baselines for both fuel composition and vehicle technology. Thus, 
the proposed 7.4 psi RVP standard for RFG would maintain the gasoline 
quality and its associated emission performance as calculated 
consistent with the statutory requirements and the Complex Model.
    Although it will no longer be required for demonstration of RFG 
batch compliance, the Complex Model will be retained by EPA for 
compliance oversite purposes in conjunction with the proposed national 
fuel survey program. Continued adherence to the VOC emission 
performance reduction standard will be monitored through samples 
collected from RFG areas as part of the survey. This oversite function 
will help ensure that the emission reductions the Complex Model was 
intended to certify at the refinery gate are being maintained in use.
d. Consolidation of RFG Areas
    Translating the VOC emissions performance standard into a summer 
RVP standard would enable EPA to simplify the RFG program 
significantly. Additionally, the creation of a single summer RVP 
standard for all RFG areas would further simplify the RFG program and 
automatically consolidate the VOC regions as required under section 
1504(c) of EPAct.\33\ Section 1504(c) directs EPA to revise the RFG 
regulations to consolidate the regulations for the VOC-Control Regions 
by eliminating the less stringent requirements.
---------------------------------------------------------------------------

    \33\ EPA ``shall . . . revise the [RFG] regulations . . . to 
consolidate the regulations applicable to VOC-Control Regions 1 and 
2 . . . by eliminating the less stringent requirements applicable to 
gasoline designated for VOC-Control Region 2 and instead applying 
the more stringent requirements applicable to gasoline designated 
for VOC-Control Region 1.'' See Energy Policy Act of 2005, Public 
Law 109-58, 119 Stat. 1079. See also USEPA Office of Transportation 
and Air Quality. Assessing the Effect of Five Gasoline Properties on 
Exhaust Emissions from Light-Duty Vehicles Certified to Tier 2 
Standards: Analysis of Data from EPAct Phase 3 (EPAct/V2/E-89): 
Final Report. EPA-420-R-13-002. Assessment and Standards Division, 
Ann Arbor, MI. April 2013.
---------------------------------------------------------------------------

    In practice, there have been three sets of VOC emission performance 
standards for the VOC Regions of the RFG program: VOC-Control Regions 1 
and 2, along with the adjustment to Region 2 provided for the Chicago/
Milwaukee areas. To date, EPA has not taken action to consolidate the 
VOC regions as directed by EPAct. However, the creation of a single 
summer RVP standard provides both an opportunity and a mechanism by 
which to act on this requirement. A benefit of this consolidation would 
be the increased fungibility of RFG amongst historically distinct VOC-
control regions.
    We find that the EPAct language provides EPA with an additional 
source of authority to take this action to

[[Page 29046]]

translate the VOC performance standard into a single RVP standard.
e. Translating the VOC Performance Standard to a Summer RVP Standard
    In order to translate the VOC performance standard into an RVP cap, 
we utilized the Complex Model and the 1990 baseline fuels and vehicles 
to determine the corresponding RVP. In accordance with EPAct, the VOC-
Control Region 1 emission reduction standards were used to establish 
the consolidated RVP standard. More specifically, the per-gallon 
reduction requirements for VOC-Control Region 1 from 40 CFR 80.41 were 
used as the basis for determining the summer RVP standard. Given that 
we are proposing a per-gallon standard, it was deemed the most 
appropriate point of reference for determining the required VOC 
reduction from the statute. We recognize that the current RFG summer 
VOC performance standards under part 80 allow for refiners and 
importers to meet either a per-gallon summer VOC performance standard 
or an annual average summer VOC performance standard. We are proposing 
to replace all RFG summer VOC performance standards with a maximum RVP 
per-gallon standard translated from the RFG Region 1 summer VOC 
performance per-gallon standard. Under this proposal, fuel 
manufacturers would no longer comply through an annual average standard 
and must instead demonstrate compliance on a per-gallon basis during 
the summer.
    The intention of this proposed action is to maintain the level of 
stringency observed in the RFG pool while transitioning away from using 
the Complex Model to demonstrate compliance to instead demonstrate 
compliance with a summer RVP standard. To that end, the starting point 
for our analysis was the batch reports submitted to EPA in the course 
of certifying batches of RFG. Several years were evaluated, but the 
most recent full year of data at the time the analysis was carried out 
was 2018. Summary statistics, based upon volumetrically weighting the 
batches, for the Complex Model parameters for this data are presented 
in Table V.A.2.e-1.

                                                    Table V.A.2.e-1--Summary Statistics for 2018 RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                              Volume
                                                            Weighted 5%    Weighted 25%      Weighted      Weighted 75%    Weighted 95%      weighted
                                                                                              median                                          average
--------------------------------------------------------------------------------------------------------------------------------------------------------
Oxygen (wt%)............................................            3.37            3.46            3.51            3.57            3.65            3.52
Sulfur (ppm)............................................               4              10              18              26              42            19.3
Aromatics (vol%)........................................             6.2            12.7            16.3              20            26.6            16.3
Olefins (vol%)..........................................             1.5             5.9            10.9            14.3            17.8           10.25
Benzene (vol%)..........................................            0.19            0.38             0.5            0.67            0.93            0.53
Ethanol (vol%)..........................................            9.23            9.46            9.61            9.77              10            9.62
E200 (%)................................................            41.7            45.7            48.5            50.7            55.4            48.4
E300 (%)................................................            81.4            84.1            86.5            88.9            92.6            86.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

    There are only eight fuel parameters reported in Table V.A.2-5 
because the remaining three parameters in the Complex Model (MTBE, 
ETBE, and TAME) have become negligible in the past 15 years, in part 
due to the removal of the RFG minimum oxygenate content requirement. 
The reported eight fuel parameters were then used to statistically 
construct ``percentile'' fuels based on how each of the eight 
parameters affected VOC performance in the Complex Model. For instance, 
the ``5th'' percentile is comprised of the 5th percentile values of 
Ethanol, E200, and E300 along with the 95th percentile values for 
aromatics, olefins, sulfur, and benzene. This combination results in 
the strictest set of parameters for RVP control and consequently the 
lowest, or ``5th'' percentile of allowable RVP. The parameter values 
for the 5th, 50th, and 95th percentile \34\ RFG are reported in Table 
V.A.2.e-2, along with the volume-weighted average for each of the 
parameters for 2018 RFG.
---------------------------------------------------------------------------

    \34\ We chose the 5th and 95th percentile to exclude cases of 
misreporting or reported non-compliance from affecting the analysis.

                                       Table V.A.2.e-2--Meeting the Phase II VOC Performance Standard for 2018 RFG
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                             Aromatics
                  Fuel                     Oxygen (wt%)    Sulfur (ppm)       (vol%)      Olefins (vol%)  Benzene (vol%)    E200 (vol%)     E300 (vol%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
5th.....................................            3.37              42            26.6            17.8            0.93            41.7            81.4
50th....................................            3.51              18            16.3            10.9             0.5            48.5            86.5
95th....................................            3.65               4             6.2             1.5            0.19            55.4            92.6
Average.................................            3.51            19.3            16.3            10.3            0.53            48.4            86.6
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Each of the four fuel compositions in Table V.A.2.e-2 was then 
exercised in the Complex Model in order to solve for the maximum 
allowable RVP while still meeting the VOC emissions reduction 
requirement. The maximum allowable RVP was calculated for both the 
average and per-gallon standards for VOC-Control Region 1 and are 
reported for each of the four compositions in Table V.A.2-7.

[[Page 29047]]

   Table V.A.2.e-3--Maximum Allowable RVP Level in the Complex Model for 2018 RFG Percentile Fuel Compositions
----------------------------------------------------------------------------------------------------------------
                                                                  Percentile
                                               ------------------------------------------------  Volume-weighted
                                                      5th            50th            95th            average
----------------------------------------------------------------------------------------------------------------
                                VOC-Control Region 1 Maximum Allowable RVP Level
----------------------------------------------------------------------------------------------------------------
Average Standards.............................             6.7            7.14            7.24              7.12
Per-Gallon Standards..........................            6.90            7.30            7.40              7.29
----------------------------------------------------------------------------------------------------------------

    As would be expected, the volume-weighted average allowable RVP of 
7.12 is nearly identical to the 7.11-7.14 range that was observed in 
the 2012-2017 batch report data presented in Figure V.A.2.b-1. This 
reflects the widespread use of the average standards by most RFG fuel 
manufacturers under the current program. The per-gallon standards would 
have theoretically allowed for a ~0.15 psi higher RVP across the 
average RFG fuel pool, but fuel manufacturers have predominantly used 
the average standards. The percentile fuel compositions demonstrate 
that there is the potential for approximately a half-pound variation in 
RVP for a compliant RFG fuel depending on the balance of the other fuel 
parameters. However, there are two important results from this 
analysis: (1) Solving for maximum allowable RVP for the volume-weighted 
average fuel yields a very similar RVP as observed in the batch reports 
(~7.1 psi); and (2) the per-gallon standards would have allowed for a 
pool average RVP of nearly 7.3 psi with no changes to RFG fuel 
composition.
    Therefore, we believe that the proposed 7.4 psi RVP standard for 
RFG is appropriate.\35\ The proposed standard equates to a 27.5 percent 
reduction in VOC emissions performance as compared to baseline gasoline 
used in baseline vehicles (i.e., 1990 vehicles) using the Complex 
Model. We seek comment on the proposed 7.4 psi RVP standard.
---------------------------------------------------------------------------

    \35\ The data used for this analysis was based on the most 
current information available to EPA at the time (i.e., the 2018 
gasoline batch information). Should new information become 
available, we intend to perform the same analysis using the updated 
information, which may result in a small change in the standard.
---------------------------------------------------------------------------

f. Conventional Gasoline Batch Data Analysis
    In order to translate the existing RFG VOC performance standard as 
an RFG summer RVP maximum per-gallon standard, it is necessary to 
evaluate how RVP per-gallon maximum standards are treated in practice. 
In order to evaluate the treatment of an RVP per-gallon maximum 
standard, we examined the RVP levels in relation to the 9.0 psi 
standard for CG in 2016.\36\ To conduct the analysis, the batch reports 
were submitted to thorough quality control and assurance in order to 
ensure that only batches adhering to the 9.0 psi standard (boutique, 
federal 7.8 psi, etc. were all removed) and that contained less than 
one percent ethanol were considered.\37\ The summary statistics for the 
2016 summer CG batches are presented in Table V.A.2.f-1.
---------------------------------------------------------------------------

    \36\ 2016 was the most recent year for which clean, batch report 
data was available at the time of analysis. We intend to update this 
analysis with the most recent data available for the final rule.
    \37\ The presence of ethanol can result in an increase in the 
RVP of the gasoline-ethanol blended fuel. The purpose of this 
analysis is to evaluate how refiners make fuels relative to the 9.0 
psi RVP maximum per-gallon standard without the addition of ethanol.

                       Table V.A.2.f-1--CG Summary Statistics From the 2016 Batch Reports
----------------------------------------------------------------------------------------------------------------
                                                    Summer CG
-----------------------------------------------------------------------------------------------------------------
                        Percentile                                 RVP          Volume above      Volume below
----------------------------------------------------------------------------------------------------------------
5th.......................................................              7.32    27,187,626,247     1,420,043,309
50th......................................................              8.67    12,984,692,750    15,622,976,806
95th......................................................              8.99     1,194,383,604    27,413,285,952
Mean......................................................              8.47    18,762,397,380     9,845,272,176
Standard..................................................               9.0       489,040,207    28,118,629,349
----------------------------------------------------------------------------------------------------------------

    The CG batch data is represented in histogram form in Figure 
V.A.2.f-1. The graduations of 0.1 psi on the x-axis allow for a clearer 
representation of where the bulk of the fuel resides in relation to the 
9.0 psi RVP standard.

[[Page 29048]]

[GRAPHIC] [TIFF OMITTED] TP14MY20.002

    The data from the CG batch reports show that the median RVP (8.67 
psi) is approximately 0.3 psi below the 9.0 psi RVP standard. As would 
be expected, there is variability in the fuel batches, but the mode of 
the data is 0.2 psi below the standard and more than 95% of the CG fuel 
volume is below the standard. For CG, the mode fell 0.2 psi below the 
standard and the median fell 0.3 psi below the standard. This 
information was taken along with the average RVP of 7.12 psi for 2018 
RFG discussed in Section V.A.2.e to conclude that a summer RVP standard 
for RFG of 7.4 psi would meet the goal of preserving the current 
environmental performance of RFG, while imposing little to no 
additional industry burden based upon the batch reports for CG. We seek 
comment on whether there would be additional industry burden associated 
with the proposed 7.4 psi RVP RFG standard.
g. Additional Changes Related to RFG
    We are also proposing regulations intended to allow for greater 
compliance flexibility and increased gasoline fungibility for the RFG 
program. Specifically, in Section VIII.G we are proposing to address 
several provisions regarding fuel certification and recertification 
that are now commonplace due to the gasoline quality standards 
implemented since the onset of the RFG program. For instance, RFG is 
statutorily required to be used in certain ozone nonattainment or 
maintenance areas in both summer and winter. The differences between 
RFG and CG that require the respective fuels to be segregated in the 
summer (i.e., RFG and CG must meet different standards in the summer) 
are not present during the winter season, where RFG and CG must meet 
identical standards under part 80. However, a similar prohibition on 
co-mingling RFG and CG in the winter exists.
    To address this situation, we are proposing to allow all winter 
gasoline to be used in RFG areas without recertification. Distributors 
of gasoline would be allowed to designate winter gasolines without 
recertification as RFG or CG to comport with state or pipeline 
specifications, which may require those distinctions. We are also 
proposing provisions to allow California manufacturers and distributors 
the flexibility to ship California gasoline and diesel fuel to the rest 
of the U.S. due to their state specifications meeting or exceeding 
EPA's standards. Lastly, new recertification standards are being 
proposed to facilitate end-of-season recertification, emergency fuel 
waivers, and allow greater downstream flexibility. These provisions are 
discussed in more detail in Section VIII.G. We seek comment on the 
proposed approach.
3. Certified Butane and Pentane
    We are proposing to streamline the provisions for gasoline blending 
manufacturers that blend butane and pentane of certified quality 
(certified butane and certified pentane, respectively) into PCG.\38\ 
Under part 80, these flexibilities allow gasoline blending 
manufacturers to rely on test results by the butane or pentane producer 
rather than testing each batch of butane or pentane received as would 
otherwise be required of a gasoline blender manufacturer to demonstrate 
compliance with EPA standards. This approach would be maintained in 
part 1090.
---------------------------------------------------------------------------

    \38\ See 40 CFR 80.82 and 80.85, respectively.
---------------------------------------------------------------------------

    We are proposing to combine these grades into single grades of 
``certified butane'' and ``certified pentane.'' Part 80 currently has 
two grades of butane and pentane (commercial and noncommercial) that 
can be used by gasoline blender manufacturers under these provisions. 
During the rule development process, many stakeholders highlighted the 
burden of demonstrating compliance with the part 80 butane and pentane 
blending provisions. We believe that, coupled with other changes to the 
specifications for certified butane and certified pentane described in 
this section, there is an opportunity to consolidate the grades of 
butane and pentane. This would allow for a streamlining of the 
compliance demonstrations needed for certified butane and certified 
pentane blenders to produce gasoline using certified butane and 
certified pentane.

[[Page 29049]]

    The current standards in part 80 for commercial and noncommercial 
grades of butane and pentane contain specifications on the maximum 
sulfur, benzene, olefin, and aromatics content. Consistent with the 
proposed changes to RFG certification,\39\ we are proposing to remove 
the maximum olefin and aromatics standards from the specifications for 
certified butane and certified pentane as we are proposing to no longer 
require those parameters for the certification of gasoline, as 
discussed in Section V.A.2, and because we do not expect issues to 
occur with other regulated parameters. Both certified butane and 
pentane would be subject to a maximum 10 ppm sulfur standard and 
maximum 0.03 volume percent benzene standard as are the commercial and 
noncommercial grades of butane and pentane today. The sulfur and 
benzene specifications are still needed to ensure that certified butane 
and certified pentane blenders do not increase the amount of sulfur and 
benzene in the national gasoline pool.
---------------------------------------------------------------------------

    \39\ See Section V.A.2.
---------------------------------------------------------------------------

    Under part 80, commercial grade pentane is subject to both 95 
volume percent pentane purity specification and a maximum 5 volume 
percent C6 \40\ and higher carbon number hydrocarbons 
specification.\41\ Non-commercial grade pentane is subject to 95 volume 
percent pentane purity specification but is not subject to 
specifications on the amount of C6 and higher carbon number 
hydrocarbons that may be present. We are proposing to not include a 
standard on C6 and higher hydrocarbon content in part 1090 for 
certified pentane given that compliance with the proposed 95 volume 
percent pentane purity specification would ensure that no more than 5 
volume percent C6 and higher hydrocarbons are present.
---------------------------------------------------------------------------

    \40\ C6 refers to a hydrocarbon molecule that contains six 
carbon atoms.
    \41\ Pentane has 5 hydrocarbons (i.e., it is C5).
---------------------------------------------------------------------------

    Unlike the current standard for non-commercial grade pentane, the 
current standards for commercial and non-commercial grade butane do not 
include a specification on minimum butane purity. With the proposed 
removal of the maximum olefin and aromatics specifications for 
certified butane, it is appropriate to propose controls on the purity 
of certified butane that are consistent with the purity specification 
for certified pentane. During the rule development process, we 
requested input from industry on applying a 95 volume percent purity 
specification to certified butane similar to the proposed purity 
specification for certified pentane. Butane blenders stated that 
implementing a minimum 95 percent purity specification would cause 
unnecessary additional processing costs to remove pentane that is often 
present. They noted that the presence of pentane would not be an 
environmental concern because of the clean burning properties of 
pentane and the lower volatility of pentane compare to butane. Butane 
blenders suggested that implementing a minimum 92 volume percent purity 
specification for certified butane would accomplish our intended goal 
of ensuring that undesirable chemical species do not contaminate 
certified butane while providing the necessary flexibility. We agree 
that a 92 volume percent purity specification would not result in 
increased emissions from the use of certified butane compared to a 95 
volume percent purity specification and would reduce the burden to 
industry; therefore, we are proposing a minimum 92 volume percent 
purity specification for certified butane. We request comment on 
whether the proposed 92 volume percent purity specification for 
certified butane would provide sufficient flexibility to allow for the 
presence of pentane in certified butane while still preserving gasoline 
quality or whether a more or less stringent purity specification would 
be appropriate.
    We are also proposing to simplify the quality assurance 
requirements for certified butane and pentane blenders. Under part 80, 
butane and pentane blenders are required to conduct periodic quality 
assurance testing of the batches of butane or pentane they receive. For 
butane, the current frequency of sampling and testing for the butane 
received from each butane supplier must be one sample for every 500,000 
gallons of butane received, or one sample every three months, whichever 
is more frequent. For commercial-grade pentane, the sampling and 
testing frequency is once for every 350,000 gallons of pentane, or one 
sample every three months, whichever is more frequent. Noncommercial-
grade pentane is currently subject to a more frequent sampling and 
testing frequency of once every 250,000 gallons or one sample every 
three months, whichever is more frequent.
    To simplify these quality assurance requirements, we are proposing 
to require the same sampling and testing frequency for certified butane 
and pentane of once every 500,000 gallons of butane or pentane 
received, or one sample every three months, whichever is more frequent. 
We believe that a more frequent sampling and testing is not needed for 
certified pentane versus certified butane given that they are subject 
to similar standards. To the extent that there may be heightened 
concern with the potential presence of high boiling range hydrocarbons 
that are typically only found in full boiling range gasoline (such as 
C7-C20 hydrocarbons) in certified pentane versus certified butane due 
to difference in manufacturing processes,\42\ we believe that such 
concerns are adequately mitigated by the existing registration 
requirements for certified pentane producers.
---------------------------------------------------------------------------

    \42\ Pentane that is produced from NGLs historically has been 
the bottom distillation cut from the NGL fractionation process, and 
hence contains all heavier hydrocarbons as well as pentane. Since 
butane is more volatile than pentane, butane produced by 
distillation from NGLs is unlikely to contain heavy hydrocarbons 
that may be a concern with respect to increased emissions.
---------------------------------------------------------------------------

4. State and Local Fuel Standards
a. Overview
    We are transferring and consolidating the part 80 regulations that 
relate to RVP, RFG, and other summer gasoline requirements to part 
1090. For example, we are removing outdated provisions and making it 
easier to identify the RVP standard that applies in a given location. 
We are also proposing changes that are intended to update and simplify 
existing regulations and reflect our experience in implementing these 
provisions in partnership with states and industry. For example, we are 
proposing procedures for states that request a relaxation of the 
federal RVP limit of 7.8 psi. This is similar to the existing 
procedures used for RFG opt-out by states. We are not proposing any 
regulatory revisions for current fuel programs that apply in several 
states. The following sections detail the changes we are proposing.
    We are also using this action to announce that an updated boutique 
fuel list is currently posted on our website.\43\ Section 1541(b) of 
EPAct requires EPA to remove any fuel from the published list if the 
fuel either ceases to be included in a state implementation plan (SIP) 
or is identical to a federal fuel.\44\ Several fuels have ceased to be 
included in SIPs since the boutique fuel list was originally published 
in 2006.\45\ The boutique fuel list on our website, however, provides 
up-to-date information on where such fuels are currently used.
---------------------------------------------------------------------------

    \43\ See http://www.epa.gov/gasoline-standards/state-fuels.
    \44\ See CAA section 211(c)(4)(C)(v)(III).
    \45\ See 71 FR 78195 (December 28, 2006).
---------------------------------------------------------------------------

b. Consolidating Gasoline Volatility Standards
    We are transferring summer gasoline requirements related to RVP 
limits that

[[Page 29050]]

are currently in part 80 to part 1090. Summer gasoline for use in the 
continental U.S. must comply with either the federal maximum RVP limit 
of 9.0 psi or the more stringent RVP limit of 7.8 psi, unless it is 
either a federal RFG covered area, is subject to California's RFG 
regulations, or EPA has waived preemption and approved a state request 
to adopt a more stringent RVP into a SIP.46 47 48 The 
proposed regulatory text would simplify and clarify regulatory text 
currently in 40 CFR 80.27(a) and 80.70, and would not change the 
current federal RFG and summer gasoline RVP requirements nationwide.
---------------------------------------------------------------------------

    \46\ Some states where the federal low RVP standard is required 
have chosen instead to apply federal RFG or another state fuel 
regulation that limits RVP to less than 7.8 psi. Such a practice is 
consistent with the CAA. If a state with such an area decided to 
remove its fuel program, the state should work closely with EPA to 
ensure that the state's SIP demonstration also supports removal of 
multiple fuel programs, if desired. See Section V.A.4.g for more 
information.
    \47\ California has set requirements for gasoline sold 
throughout the entire state, and these requirements include limits 
on the gasoline RVP. See Title 13, sections 2250-2273.5 of the 
California Code of Regulations. These standards apply in lieu of 
federal RVP standards.
    \48\ In the absence of California's RFG regulation, either 
federal RVP standards or federal RFG would apply in California. Some 
areas would be federal RFG covered areas because either they were 
among the original nine RFG covered areas or they were reclassified 
to Severe nonattainment for an ozone NAAQS. See CAA section 
211(k)(10)(D).
---------------------------------------------------------------------------

c. Reformatting the List of Areas Where Federal Low RVP Standard 
Applies
    We are also transferring the current RVP standards in 40 CFR 
80.27(a)(2), which sets out the current federal RVP limits to part 
1090. Areas subject to the federal 7.8 psi RVP limit are listed in a 
table in 40 CFR 1090.215(a)(1), describing the geographic areas subject 
to the 7.8 psi RVP limit. The regulatory text specifies that any 
gasoline that is not subject to a lower RVP limit is subject to the 
federal 9.0 psi RVP limit. We are not proposing any changes or 
revisions to applicable RVP limits. Specifically, we are:
     Removing the regulatory text in 40 CFR 80.27(a)(1) because 
it is outdated and has not applied since 1991.
     Replacing the regulatory text, table, and footnotes that 
are currently in 40 CFR 80.27(a)(2) with a reformatted table in part 
1090 that lists the areas where the federal 7.8 psi RVP limit for 
summer gasoline currently applies.
    The table in 40 CFR 1090.215(a)(1) includes the name of the area 
and the county or counties in the area where the federal 7.8 psi RVP 
limit applies, rather than the current table in part 80 that dates back 
to the initial one-hour ozone standard, is overly complex and has 
caused confusion among states and industry. The new table would also 
include a description of the boundaries for areas that include partial 
counties where RVP standards are currently in effect. Under the current 
regulations in part 80, interested parties must search 40 CFR part 81 
in order to identify these specific boundaries of the area where the 
7.8 psi RVP limit applies. As previously noted, this action does not 
change any existing requirements.
d. Reformatting Federal RFG Applicability and Covered Areas
    As part of transferring part 80 requirements relating to federal 
RFG to part 1090, we are reformatting how the information on current 
RFG covered areas is presented. Specifically, in 40 CFR 1090.270 we are 
presenting the description of RFG covered areas in a table format and 
grouping the covered areas by the process under which the area became a 
covered area. There are four ways in which an area could have become an 
RFG covered area:
     It was included in the original RFG covered areas under 
CAA section 211(k)(10)(D) because its 1987-1989 ozone design value was 
among the nine highest design values and its 1980 population was 
greater than 250,000;
     It was subsequently reclassified to Severe for an ozone 
NAAQS;
     It was a classified ozone nonattainment area that opted 
into the RFG program; or
     It was an attainment area in the ozone transport region 
that opted into the RFG program.
    The tables in part 1090 list the areas in each of these groups. As 
previously explained, we are not changing the geographic applicability 
of federal RFG.
    We are also transferring the existing regulatory processes by which 
an area may become a federal RFG covered area in the future, which are 
if: (1) An area is reclassified to Severe nonattainment for an ozone 
NAAQS; (2) a governor requests that a classified ozone nonattainment 
area become a covered area; or (3) a governor requests that an 
attainment area in the ozone transport region be included as a federal 
RFG covered area.
    We are also including two California areas on the list of covered 
areas in part 1090 because the areas became federal RFG covered areas 
when they were reclassified as Severe ozone nonattainment areas.\49\ 
The two areas are the Sacramento Metro area and the San Joaquin Valley 
area.\50\ We have provided information on these RFG covered areas on 
our website but had not previously included them in the list of covered 
areas in 40 CFR 80.70. This does not impact California's regulations 
that require the sale of California RFG in these areas, but should 
California's regulations no longer apply in the future, the federal RFG 
regulations would still apply in keeping with the CAA.
---------------------------------------------------------------------------

    \49\ See CAA section 211(k)(10)(D).
    \50\ The Sacramento Metro area was reclassified as a severe 
ozone nonattainment area on June 1, 1995 and became a federal RFG 
covered area on June 1, 1996. See 60 FR 20237 (April 25, 1995). The 
San Joaquin Valley area was reclassified as a severe ozone 
nonattainment area on December 10, 2001 and became a federal RFG 
covered area on December 10, 2002. See 66 FR 56476 (November 8, 
2001).
---------------------------------------------------------------------------

e. Continuation of Federal RFG Requirements in Covered Areas When 
Revised Ozone NAAQS Are Implemented
    In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we 
stated that areas that became RFG covered areas pursuant to CAA section 
211(k)(10)(D) would remain RFG covered areas at least until they were 
redesignated to attainment for the 1997 ozone NAAQS. We also stated 
that areas that became covered areas because they opted into RFG would 
remain covered areas until they opt out of RFG pursuant to our opt-out 
regulations. We also included regulatory text in 40 CFR 80.70(m),\51\ 
parts of which are now outdated and unnecessary because they were 
specific to the transition from the 1-hour ozone NAAQS to the 1997 
ozone NAAQS and to redesignations to attainment for the 1-hour ozone 
NAAQS. Both the 1-hour and 1997 ozone NAAQS have been revoked.
---------------------------------------------------------------------------

    \51\ See 70 FR 71684-9 (November 29, 2005).
---------------------------------------------------------------------------

    We are maintaining and clarifying in this action our intention and 
existing practice with regard to applicable RFG requirements for the 
implementation of revised ozone NAAQS. Our intention is consistent with 
our past approach and fuel program implementation to date. 
Specifically, for purposes of implementing revised ozone NAAQS, RFG 
will continue to apply in all covered areas (i.e., both areas that 
opted into RFG under CAA section 211(k)(6) and covered areas under CAA 
section 211(k)(10)(D)). As previously explained, this is consistent 
with how the federal RFG program has been implemented during the 
transition to the 1997, 2008, and 2015 ozone NAAQS. As also previously 
explained, part 1090 includes procedures for either removing a 
prohibition on or opting out of RFG requirements, consistent with CAA 
requirements; thus, states should be able

[[Page 29051]]

to change their RFG programs under certain cases.
f. Clarifying When Mandatory RFG Covered Nonattainment Areas Can Be 
Removed From the List of Covered Areas
    In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we 
reserved for future consideration the continued applicability of RFG 
requirements in mandatory RFG covered areas pursuant to CAA section 
211(k)(10)(D) (i.e., they were among the areas with the nine highest 1-
hour ozone design values from 1987-1989 or they have been reclassified 
to Severe for an ozone NAAQS) in the future.\52\
---------------------------------------------------------------------------

    \52\ See 70 FR 71687 (November 29, 2005).
---------------------------------------------------------------------------

    We are proposing a new provision in part 1090 that would allow 
mandatory RFG covered area pursuant to CAA section 211(k)(10)(D) to 
remove the applicability of the RFG program if certain requirements are 
met. Under this proposed provision, a state could request the removal 
of its RFG program if the RFG area was either redesignated to 
attainment for the most stringent ozone NAAQS in effect at the time or 
initially designated as attainment for the most stringent ozone NAAQS 
in effect. For example, the 2015 ozone NAAQS of 70 ppb is currently the 
most stringent ozone NAAQS. Therefore, in order for a mandatory RFG 
area to remove its RFG program, it would have to be either redesignated 
to attainment for the 2015 ozone NAAQS (if had initially been 
designated as attainment for that NAAQS) or be initially designated as 
an attainment area for the 2015 ozone NAAQS. If the area is initially 
designated as an attainment area for the most stringent ozone NAAQS in 
effect, under the proposed requirement the area would have to be 
redesignated to attainment for the prior ozone NAAQS before the RFG 
program could be removed. For example, under this proposal an area 
would either have been designated as an attainment area for the 2015 
ozone NAAQS with an approved maintenance plan for the 2008 ozone NAAQS 
or be redesignated to attainment for the 2015 NAAQS to be eligible for 
consideration for removal of the RFG program. In either case, we are 
proposing to require that any request to remove the federal RFG 
requirements must include an approved maintenance plan that 
demonstrates maintenance of the ozone NAAQS throughout the period of 
time addressed by the maintenance plan without the emission reductions 
from the federal RFG program. Additionally, the proposed provision 
would require a state to also demonstrate that the removal of the 
requirement for the federal RFG program would not interfere with 
reasonable further progress requirements or attainment or maintenance 
of any other NAAQS or interfere with any other CAA requirement.\53\ We 
seek comment on this proposed requirement.
---------------------------------------------------------------------------

    \53\ See CAA section 110(l).
---------------------------------------------------------------------------

    We are proposing to allow states with current mandatory RFG covered 
areas to remove those programs in the future when all ozone NAAQS are 
attained and maintained. Although the CAA requires RFG in certain ozone 
nonattainment areas, it is important that states can use limited 
resources for programs that are necessary for attainment, rather than 
require the implementation of RFG indefinitely simply because such a 
covered area had the highest ozone design values 30 years ago or were 
reclassified as Severe for a prior ozone NAAQS. This proposal is 
premised on our view that once a covered area attains the most 
stringent ozone NAAQS, states should be able to determine whether an 
emission reduction strategy should either continue or be removed.
    We believe that a mandatory RFG covered area should have the 
ability to determine if it is necessary to continue as an RFG covered 
area once it has attained the most stringent ozone NAAQS that is in 
effect and can demonstrate maintenance of the ozone NAAQS without the 
emissions reductions attributable to RFG in the approved CAA section 
175A maintenance plan for the area. Requiring that an area attain the 
most stringent ozone NAAQS and demonstrate maintenance of the ozone 
NAAQS without the emissions reductions from RFG provides adequate 
safeguards with respect to protecting air quality improvements and 
public health, while providing states with the flexibility to determine 
the best course for maintaining the ozone NAAQS.
    This proposed provision is in addition to the current RFG opt-out 
procedures that apply to areas that opted-in to RFG under CAA section 
211(k)(6)(A) or (B) unless an opt-in area under CAA section 
211(k)(6)(A) has been reclassified as a Severe ozone nonattainment 
area. These procedures, which were established in 1996 and 1997, are 
currently in 40 CFR 80.72 and are also being transferred to part 
1090.\54\ We are not changing them except for removing obsolete 
regulatory text and minor clarifications, such as requirements that 
applied for specific periods of time that are now in the past.
---------------------------------------------------------------------------

    \54\ See 61 FR 35673 (July 8, 1996) and 62 FR 54552 (October 20, 
1997).
---------------------------------------------------------------------------

g. Providing Streamlined Procedures for Areas Relaxing the Federal Low 
RVP Standard
    We are proposing to include a new streamlined process for state 
requests to relax the federal 7.8 psi RVP standard for gasoline sold 
between June 1st and September 15th of each year. This action would 
provide procedures similar to those that are currently used when states 
opt out of the RFG program.\55\
---------------------------------------------------------------------------

    \55\ The current RFG opt-out procedures apply to areas that 
opted into RFG under CAA section 211(k)(6)(A) or (B) unless an area 
that opted in under CAA section 211(k)(6)(A) has been reclassified 
as Severe. These procedures are currently in 40 CFR 80.72 and were 
established in 1996 and 1997. See 61 FR 35673 (July 8, 1996) and 62 
FR 54552 (October 20, 1997). We are not changing these RFG opt-out 
procedures except for removing obsolete regulatory text and minor 
clarifications.
---------------------------------------------------------------------------

    The current federal 7.8 psi RVP limit took effect in 1992 and was 
initially required in certain 1-hour ozone NAAQS nonattainment areas. 
We have also allowed for state relaxation requests and since 2014 we 
have approved relaxations of the federal 7.8 psi RVP standard for 12 
areas in the states of Alabama, Florida, Georgia, Louisiana, North 
Carolina, and Tennessee.\56\ As discussed in Section V.A.4.c, we are 
providing a new table in part 1090 that sets out where the federal 7.8 
psi RVP standards currently applies.
---------------------------------------------------------------------------

    \56\ For more information on EPA's actions, see www.epa.gov/gasoline-standards/federal-gasoline-regulations.
---------------------------------------------------------------------------

    Under our current regulations, the process for accomplishing low 
RVP relaxation requires two EPA approval actions before a state's 
request can be effective. First, the EPA Regional Office needs to 
approve a state's revision to an area's SIP, such as a maintenance 
plan, for the relevant ozone NAAQS. After that rulemaking is completed, 
a second rulemaking by EPA Headquarters is necessary to remove the 
subject area(s) from the federal low RVP regulations in 40 CFR 
80.27(a)(2).\57\ The current process of requiring both of these 
approval actions before a state's request is effective is cumbersome 
and time consuming given the number of linear steps involved. There is 
also an element of confusion and uncertainty to states, local 
businesses, industry, and the

[[Page 29052]]

public concerning the effective date of an RVP relaxation.
---------------------------------------------------------------------------

    \57\ In some circumstances, a revision to an approved 
maintenance plan has not been necessary because the subject area was 
beyond the period of time covered by any approved ozone maintenance 
plan under either CAA section 110(a) or 175A. For an example, refer 
to the RVP relaxation for several parishes in Louisiana (82 FR 
60886, December 26, 2017).
---------------------------------------------------------------------------

    Based on our experience since 2014, we have concluded that the 
current RFG opt-out regulatory procedures provide a better model for 
considering state requests to relax the federal 7.8 psi RVP standard. 
Our proposed regulations for relaxing the federal 7.8 psi RVP standard 
in part 1090 mirrors the current part 80 RFG opt-out procedures, and 
are as follows:
     The Governor of the state or his/her designee would 
request in writing that EPA relax the federal 7.8 psi RVP standard.
     The state would continue to be required to revise its 
approved SIP for the area (e.g., the ozone maintenance plan for the 
area) to appropriately account for the change in emissions due to the 
increase in the RVP limit and to address the CAA section 110(l) non-
interference requirements.
     The EPA Regional Office would have to approve that SIP 
revision and CAA section 110(l) demonstration.
     Once, the Regional Office's action is complete, we would 
establish an effective date for the relaxation, which would be no less 
than 90 days after the effective date of the Regional Office's 
approval. We would notify the Governor in writing, typically through a 
letter, of the effective date and publish a notice in the Federal 
Register. Gasoline meeting the 7.8 psi RVP standard would not be 
required to be sold after that effective date.
     Subsequently, we would publish a separate final rule to 
remove the area from the list of areas where the 7.8 psi RVP limit 
continues to apply (i.e., from the list of areas in part 1090). We 
believe that notice-and-comment rulemaking would no longer be necessary 
for relaxation actions because it merely codifies a change that has 
been made through a process that is included in our regulations and 
would be merely administrative in nature.
    Use of this proposed process would eliminate the need for EPA to 
complete a notice-and-comment rulemaking each time EPA acts on a 
request to relax a low volatility gasoline standard to remove the 
subject area from the list of areas subject to that standard. Under 
this proposed process, similar to the current RFG opt-out procedures, 
the effective date of the federal low RVP relaxation would be known 
shortly after the EPA Regional Office's rulemaking on the state's SIP 
revision becomes effective. We believe that using similar procedures 
for acting on state requests to change either federal low RVP or RFG 
programs would avoid unnecessary confusion and still continue to 
provide the same level of environmental protection. Under both the 
current regulations in part 80 and the proposed regulations in part 
1090, the state's SIP revision must include revisions to the on-road 
and nonroad mobile source NOX and VOC inventories to reflect 
the removal of the federal low RVP fuel. The SIP must also demonstrate 
that the area would continue to maintain the relevant ozone NAAQS and 
that the change would not negatively impact the area's compliance with 
other CAA requirements.\58\ Further, we would continue to act on such a 
SIP revision and CAA section 110(l) non-interference demonstration 
through notice-and-comment rulemaking. Finally, this proposed process, 
which streamlines the RVP relaxation program, would result in the 
conservation of limited government resources and bring certainty for 
states, the public and gasoline suppliers as to when a state's request 
to relax RVP would take effect.
---------------------------------------------------------------------------

    \58\ See CAA section 110(l).
---------------------------------------------------------------------------

h. Transitioning From Federal RFG or a Boutique Fuel Program to the 
Federal RVP Standard in Certain States
    We are providing information to states that decide to either opt 
out of federal RFG or remove a state SIP fuel rule that regulates 
gasoline RVP (i.e., a boutique fuel) that the state in its SIP revision 
(e.g., maintenance plan revision) may request that EPA apply the 9.0 
psi RVP standard rather than the federal 7.8 psi RVP standard.\59\ The 
SIP revision will have to document that increasing the summer RVP 
standard to 9.0 psi will not interfere with attainment or maintenance 
of the relevant ozone NAAQS or with requirements for reasonable further 
progress, attainment, or maintenance of any other NAAQS.\60\ This 
reflects our experience in working with states that have decided to 
change their fuel programs in areas where the federal 9.0 psi RVP 
standard could be applied.
---------------------------------------------------------------------------

    \59\ In rulemakings on June 11, 1990 (55 FR 23658) and December 
12, 1991 (56 FR 64704), EPA promulgated regulations that established 
a gasoline RVP standard of 7.8 psi from June 1st to September 15th 
in nonattainment areas for the 1-hour ozone NAAQS in the following 
states: Alabama; Arizona; Arkansas; California; Colorado; Florida; 
Georgia; Kansas; Louisiana; Maryland; Mississippi; Missouri; Nevada; 
New Mexico; North Carolina; Oklahoma; Oregon; South Carolina; 
Tennessee; Texas; Utah and Virginia; and the District of Columbia. 
The federal 9.0 psi RVP standard applies in the remaining states in 
the continental U.S.
    \60\ See CAA section 110(l).
---------------------------------------------------------------------------

    In such cases, the ultimate goal of these states has been to allow 
the sale of gasoline that meets the federal 9.0 psi RVP standard. 
States have previously accomplished this goal by first submitting a SIP 
revision (e.g., a maintenance plan revision) based on the application 
of the federal 7.8 psi standard and then later submitting a second SIP 
revision to initiate the process to relax the federal 7.8 psi RVP 
standard to 9.0 psi. We are providing this information to ensure that 
the relevant states are aware that they can accomplish the goal of 
relaxing the federal RVP standard to 9.0 psi as long as the associated 
SIP revision meet the CAA section 110(l) non-interference requirements 
for the relevant ozone NAAQS and all other pollutants. Accomplishing 
the goal of allowing the sale of gasoline that meets the federal 9.0 
psi RVP standard with one SIP revision, EPA approval of one SIP 
revision, and one EPA action to update the lists areas subject to the 
specific gasoline standards will conserve state and federal resources.
    This proposal allowing the transition to the federal RVP standard 
of 9.0 psi through one SIP revision continues to protect air quality 
and public health because the state must demonstrate through its SIP 
revision and CAA section 110(l) non-interference demonstration that air 
quality goals are met as required by the CAA when gasoline that 
complies with the federal RVP standard of 9.0 psi is sold in the area. 
In addition, EPA must then approve that SIP revision and CAA section 
110(l) demonstration through notice-and-comment rulemaking. This 
approach also provides fuel suppliers with certainty and stability. 
Under part 1090, fuel suppliers in such areas would not be required to 
switch from supplying federal RFG or a state fuel to federal 7.8 psi 
RVP gasoline for a short period of time only to ultimately switch to 
supplying gasoline that meets the federal 9.0 psi RVP standard.
    We note, however, that if such a state wants EPA to apply the 
federal 7.8 psi RVP limit, that state could document this intention in 
its SIP revision, and the associated emissions modeling should be based 
on application of the federal 7.8 psi RVP limit. In such a case, EPA 
Headquarters would also complete a rulemaking to revise the list of 
areas where the federal 7.8 psi RVP standard applies (i.e., add such an 
area to the list in part 1090).
i. Announcing Updates to the Boutique Fuels List
    We are also using this action to announce that an updated boutique 
fuel list is currently posted on our website. Section 1541(b) of EPAct 
required EPA, in consultation with the Department of Energy (DOE), to 
determine the total number of fuels approved into all SIPs

[[Page 29053]]

as of September 1, 2004, under section 211(c)(4)(C), and publish a list 
of such fuels, including the state and Petroleum Administration for 
Defense District (PADD) in which they are used for public review and 
comment. EPA originally published the required list on 2006.\61\
---------------------------------------------------------------------------

    \61\ See 71 FR 78192 (December 28, 2006).
---------------------------------------------------------------------------

    Additionally, we are required to remove any fuels from the 
published list if the fuel either ceases to be included in a SIP or is 
identical to a federal fuel.\62\ Since the original list was published, 
a number of fuels have been removed from approved SIPs and have thus 
ceased to exist in SIPs.\63\ In Table V.5.h-1 we are providing an 
updated list of boutique fuels that includes all of the boutique fuels 
that are currently in approved SIPs. We also maintain a current list of 
boutique fuels on our State Fuels website.\64\ We will continue to 
update that website as changes to boutique fuels occur and periodically 
announce updates in the Federal Register for fuels that are either 
removed or added.
---------------------------------------------------------------------------

    \62\ See CAA section 211(c)(4)(C)(v)(III).
    \63\ Since December 2006, the following fuels have been removed 
from approved SIPs: Pennsylvania--7.8 psi RVP; Maine--7.8 psi RVP; 
Illinois--7.2 psi RVP; and Georgia--7.0 psi RVP with sulfur 
provisions.
    \64\ See https://www.epa.gov/gasoline-standards/state-fuels.

              Table V.5.h-1--Total Number of Fuels Approved in SIPs Under CAA Section 211(c)(4)(C)
----------------------------------------------------------------------------------------------------------------
        Type of fuel control               PADD                              Region-state
----------------------------------------------------------------------------------------------------------------
RVP of 7.8 psi......................               2  5--Indiana.
                                                   3  6--Texas (May 1-October 1).*
RVP of 7.0 psi......................               2  7--Kansas.
                                                   2  5--Michigan.
                                                   2  7--Missouri.
                                                   3  4--Alabama.\65\
                                                   3  6--Texas.
Low Emission Diesel.................               3  6--Texas.
Cleaner Burning Gasoline (Summer)...               5  9--Arizona (May 1-September 30).*
Cleaner Burning Gasoline (Non-                     5  9--Arizona (October 1-April 30).
 Summer).
Winter Gasoline (aromatics & sulfur)               5  9--Nevada.\66\
----------------------------------------------------------------------------------------------------------------
* Dates refer to summer gasoline programs with different RVP control periods from the federal RVP control
  period, which runs from May 1st through September 15th for fuel manufacturers and June 1st through September
  15th for downstream parties.

5. Substantially Similar
---------------------------------------------------------------------------

    \65\ EPA has approved Alabama's request to move its SIP approved 
7.0 psi RVP program to the contingency measure portion of the SIP 
for the Birmingham area. Because the fuel rule was retained as a 
contingency measure it remains on the boutique fuel list (see 77 FR 
23619, April 20, 2012).
    \66\ Nevada's winter gasoline (aromatics and sulfur) fuel rule 
was retained as a contingency measure and therefore remains on the 
boutique fuel list (see 75 FR 59090, September 27, 2010).
---------------------------------------------------------------------------

    CAA section 211(f)(1)(B) prohibits the introduction into commerce 
of ``any fuel or fuel additive for use by any person in motor vehicles 
manufactured after model year 1974 which is not substantially similar 
to any fuel or fuel additive utilized in the certification of any model 
year 1975, or subsequent model year vehicle, or engine.'' While this 
provision has always applied to fuel and fuel additive manufacturers by 
virtue of it being a statutory requirement, we did not listed it in our 
part 80 regulations among the requirements for fuel.\67\ We are 
proposing to address the substantially similar requirements of the CAA 
in part 1090 for gasoline and gasoline fuel additives as part of our 
effort to consolidate fuels compliance requirements and make it easier 
for regulated parties to understand their obligations.\68\ We are 
proposing to include a requirement in the regulation that that all 
gasoline, BOBs, and gasoline fuel additives must be substantially 
similar under CAA section 211(f)(1)(B) or have a waiver under CAA 
section 211(f)(4). We seek comment on this approach.
---------------------------------------------------------------------------

    \67\ The fuel and fuel additive registration requirements do, 
however, require that manufacturers of fuels and fuel additives 
demonstrate that fuels and fuel additives are either substantially 
similar under CAA section 211(f)(1) or have a waiver under CAA 
section 211(f)(4). See 40 CFR 79.11(i) and 79.21(h).
    \68\ See 81 FR 80877-8 (November 16, 2016).
---------------------------------------------------------------------------

    EPA has issued two coexisting definitions of substantially similar 
for gasoline, one in 2008 \69\ and one in 2019,\70\ and several CAA 
section 211(f)(4) waivers. The regulations proposed today refer to the 
statutory provisions (CAA section 211(f)(1)(B) and (4)), and the 
conditions associated with CAA section 211(f)(4) waivers and the 
parameters associated with the 2019 definition of substantially 
similar.
---------------------------------------------------------------------------

    \69\ See 73 FR 22277 (April 25, 2008).
    \70\ See 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------

B. Diesel Fuel

1. Overview and Streamlining of Diesel Fuel Program
    Similar to our approach for the gasoline standards, we are 
proposing to consolidate the diesel fuel standards into a single 
subpart in part 1090 (subpart D). We are not proposing any changes to 
the sulfur or cetane/aromatics standards for diesel fuel, the sulfur 
standards for diesel fuel additives, or the ECA marine fuel standards. 
We are removing expired provisions that were needed to support the 
phase-in of the diesel fuel sulfur program. The phase-in period was 
completed in 2014; however, these now expired phase-in provisions are 
imbedded throughout the diesel program regulations, adding burden to 
regulated parties in identifying their compliance duties and confusing 
other stakeholders. As part of the transfer of current part 80 
regulations to part 1090, we are also consolidating identical 
provisions for highway and other diesel fuels into a single regulatory 
requirement to improve clarity.
    We are proposing the following revisions to existing part 80 
regulations in the following sections. First, we are proposing to 
remove the requirement that motor vehicle diesel fuel be free of red 
dye because we believe this requirement no longer provides an effective 
means of evaluating compliance with the diesel sulfur standards. 
Second, we are proposing to streamline the requirements that pertain to 
importation of diesel fuel that does not meet EPA standards. Third, we 
are proposing to remove the registration requirement for ECA marine 
fuel distributors and associated requirements to include a registration 
number on PTDs. Finally, we are proposing

[[Page 29054]]

streamlined means for downstream parties to redesignate heating oil, 
kerosene, and jet fuel as ULSD that would require specific 
documentation from the original fuel manufacturer.
    We expect that these proposed changes, when finalized, would 
simplify the diesel fuel programs, resulting in reduced burden 
associated with demonstrating compliance with the applicable sulfur 
standards and maximize the fungibility of diesel fuel, allowing the 
market to operate more efficiently. These changes are not expected to 
change the stringency of the diesel fuel and IMO marine fuel standards.
2. Removing the Red Dye Requirement
    Part 80 currently requires that motor vehicle diesel fuel must be 
free of visible evidence of dye solvent red 164 (which has a 
characteristic red color in diesel fuel), except for motor vehicle 
diesel fuel that is used in a manner that is tax exempt under section 
4082 of the Internal Revenue Code.\71\ This EPA requirement is 
consistent with a parallel requirement in the Internal Revenue Code 
that is intended to support compliance with diesel fuel tax 
requirements. Under the Internal Revenue Code, NRLM diesel fuel, 
heating oil, and exempt highway diesel fuel \72\ must contain red dye 
before leaving a fuel distribution terminal to indicate its tax-exempt 
status.
---------------------------------------------------------------------------

    \71\ See 40 CFR 80.520(b).
    \72\ Such as diesel fuel used in school buses.
---------------------------------------------------------------------------

    When the sulfur standards for off-highway diesel fuel were less 
stringent than those for motor vehicle diesel fuel, the presence of red 
dye was a useful screening tool for EPA to identify potential 
noncompliance with the sulfur standards for highway diesel fuel. 
However, the presence of red dye has become a much less useful 
indicator of sulfur noncompliance as other distillate fuels have become 
subject to the same 15 ppm sulfur standard that applies to highway 
diesel fuel. With the completion of the phase-in of our diesel fuel 
sulfur program in 2014, all highway, nonroad, locomotive, and marine 
diesel fuel must meet a 15 ppm sulfur standard except for a limited 
volume of locomotive and marine (LM) diesel fuel produced by transmix 
processors, which is subject to a 500 ppm sulfur standard. The 
distribution of 500 ppm LM diesel fuel is subject to separate 
compliance provisions to ensure that is not misdirected for use in 
highway, nonroad, locomotive, or marine engines that require the use of 
15 ppm diesel fuel (ULSD).
    The other potential source of red-dyed high-sulfur diesel fuel that 
might inappropriately be diverted as highway diesel has been heating 
oil. However, the vast majority of heating is currently subject to a 15 
ppm standard.\73\ Therefore, we believe that the requirement that red 
dye should not be present in motor vehicle diesel fuel no longer 
provides meaningful added assurance of compliance with highway diesel 
ULSD standards. Rather, the existence of this requirement complicates 
the process of providing alternate sources of diesel fuel when supplies 
of highway diesel fuel are constricted due to extreme and unusual 
supply circumstances. State authorities are currently required to 
request a waiver from EPA and the Internal Revenue Service (IRS) from 
the respective agency's red dye requirements to enable the use of 15 
ppm NRLM diesel fuel on highway during such circumstances. Eliminating 
our red dye requirement would reduce state officials' waiver requests 
to just an IRS waiver during such events without substantially 
affecting the ability of EPA to enforce highway ULSD standards. 
Therefore, we are proposing to remove the EPA requirement that motor 
vehicle diesel fuel must be free from visual evidence of red dye.\74\ 
This proposed change would not alter the Internal Revenue Code 
requirement that NRLM diesel fuel, heating oil, and exempt motor 
vehicle diesel fuel must contain red dye before leaving a fuel 
distribution terminal to indicate its tax-exempt status.
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    \73\ The vast majority of heating oil is used in the Northeast 
where states require that heating oil meet a 15 ppm sulfur standard. 
See ``Guidance, Exemptions And Enforcement Discretion For New 
England's ULSHO Transition,'' New England Fuel Institute (NEFI), 
available at https://nefi.com/regulatory-compliance/new-englands-ulsho-transition.
    \74\ See 40 CFR 80.520(b)(1).
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3. Importation of Off Spec Diesel Fuel
    We are proposing to replace the provisions for the importation of 
diesel fuel treated as blendstock (DTAB) \75\ with a streamlined 
procedure to handle imported off-spec diesel fuel. Under part 80, most 
of the DTAB provisions are designed to account for the DTAB in 
compliance calculations that have not been used since 2010. The part 80 
provisions require importers to include DTAB in compliance calculations 
that are no longer applicable, to keep DTAB segregated from other 
diesel fuel, and limit the importer's ability to transfer title of 
DTAB. Under part 1090, importers could import diesel fuel that does not 
comply with EPA standards if certain provisions (which are a subset of 
those currently required under part 80) are met. Under the proposed 
provisions, the importer would be required to offload the imported 
diesel fuel into one or more shore tanks containing diesel, sample and 
test the blended fuel to confirm that it meets all applicable per-
gallon standards before introduction into commerce, and keep all 
applicable records. We believe that this simplification provides the 
needed flexibility for importers while providing improved clarity.
---------------------------------------------------------------------------

    \75\ See 40 CFR 80.512.
---------------------------------------------------------------------------

4. Annex VI Marine Fuel Standards
    In this action, we are mostly proposing to transpose without change 
the regulations in subpart I of part 80 for distillate diesel fuel that 
complies with the 0.10 percent (1,000 ppm) and 0.50 percent (5,000 ppm) 
sulfur standards contained in Annex VI to the International Convention 
for the Prevention of Pollution from Ships (MARPOL Annex VI). The U.S. 
ratified MARPOL Annex VI and became a Party to this Protocol on October 
8, 2009. MARPOL Annex VI requires marine vessels operating globally to 
use fuel that meets the 0.50 percent sulfur standard starting January 
1, 2020, rather than the current standard of 3.50 percent (35,000 ppm) 
sulfur (``global marine fuel''). The MARPOL Annex VI standard is 0.10 
percent sulfur for fuel used in vessels operating in designated 
Emission Control Areas (ECAs).\76\
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    \76\ Designated Emission Control Areas for the U.S. include the 
North American ECA and the U.S. Caribbean Sea ECA. More specific 
descriptions may be found in EPA fact sheets: ``Designation of North 
American Emission Control Area to Reduce Emissions from Ships,'' 
EPA-420-F-10-015, March 2010; and ``Designation of Emission Control 
Area to Reduce Emissions from Ships in the U.S. Caribbean,'' EPA-
420-F-11-024, July 2011.
---------------------------------------------------------------------------

    In a separate action, we modified our diesel fuel regulations in 
part 80 to allow fuel manufacturers and distributors to sell distillate 
diesel fuel meeting the 2020 global marine fuel standard instead of the 
ULSD or ECA marine standards.\77\ We are incorporating those provisions 
into part 1090 with minor changes to be consistent with the proposed 
part 1090 structure.
---------------------------------------------------------------------------

    \77\ 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 refiner to the point 
of transfer to a vessel are currently required to register with EPA and 
must include this registration number on PTDs.\78\ Distributors of 
other

[[Page 29055]]

distillate and residual fuels had similar ``designate and track'' 
requirements during the phase-in of the ULSD standards for highway and 
nonroad diesel fuel to allow the temporary use of limited volumes of 
500 ppm highway and nonroad diesel fuel under the program's small 
refiner and credit provisions.\79\ The majority of these requirements 
gradually expired with the phase-out of the ULSD program's small 
refiner and credit provisions that ended in 2014, which allowed the 
production of limited volumes of 500 ppm highway diesel fuel. Beginning 
in 2014, the only fuel distributors that must register with EPA are 
those that handle ECA marine fuel and 500 ppm LM diesel fuel produced 
by transmix processors.\80\
---------------------------------------------------------------------------

    \78\ See 40 CFR 80.597(d)(3).
    \79\ See 40 CFR 80.597 regarding the distributor registration 
requirements and 40 CFR 80.590(a)(6)(i) for the associated PTD 
requirements.
    \80\ The production of 500 ppm LM diesel fuel is discussed in 
Section XIII.E.4.
---------------------------------------------------------------------------

    We believe that the benefit associated with having ECA marine fuel 
distributors register with EPA may not outweigh the burdens associated 
with this requirement. Like distributors of other regulated fuels, 
distributors of ECA marine fuel would be required to identify 
themselves on the PTD. This information could be used by EPA to help 
determine what parties in the ECA marine fuel distribution chain may be 
responsible for fuel represented as ECA marine fuel in the distribution 
system that does not meet the requisite fuel quality standards. While 
having a registration number on the ECA marine fuel PTD facilitates 
this process, we do not believe that it is necessary. Therefore, we are 
proposing to remove the requirement that distributors of ECA marine 
fuel must register with EPA and include this registration number on ECA 
marine fuel PTDs. We believe that this would meaningfully reduce the 
burden to fuel distributors and would avoid potential delays in the 
transportation of ECA marine fuel due to potential distributors not 
being registered with EPA, while not diminishing the air quality 
benefits of the ECA marine fuel program. Any person who produces diesel 
fuel, including ECA marine fuel, by mixing blendstocks is a blender 
manufacturer and must continue to register and comply with all 
applicable requirements; this is consistent with the current regulatory 
under part 80 and would be unchanged in part 1090. We request comment 
on the benefits and costs of the current registration requirement for 
ECA marine fuel distributors.
5. Heating Oil, Kerosene, and Jet Fuel
    Under part 80, we first established the diesel sulfur program that 
required only on-highway or motor vehicle diesel to meet the 15 ppm 
sulfur standard. We designed most of the provisions related to 
designating, segregating, and labeling distillate fuels to avoid the 
contamination of ULSD with higher sulfur distillate fuels, which at the 
time were non-road diesel, heating oil, kerosene, and jet fuel. Now a 
federal 15 ppm standard applies for motor vehicle, non-road, 
locomotive, and marine diesel fuel, and, as discussed in Section V.B.2, 
a state or local 15 ppm sulfur standard applies to most of the heating 
oil used in the U.S. The provisions designed to avoid contamination of 
ULSD with higher sulfur distillate fuels now exist where there is no 
difference between most distillate fuels; however, the provisions have 
remained in place despite this change in the distillate fuel market. 
These obsolete provisions contribute to inefficiency in the 
distribution system leading to higher costs, and barriers to the free 
movement of fuel during times of unforeseen supply disruptions (e.g., 
refinery fires, hurricanes, etc.). Therefore, we are proposing to allow 
heating oil, kerosene, and jet fuel certified to ULSD standards to be 
redesignated downstream as ULSD for use in motor vehicles and NRLM 
engines without recertification by the downstream party if certain 
conditions are met.
    Under these proposed provisions, downstream parties could rely upon 
documentation from pipelines or fuel manufacturers that the heating 
oil, kerosene, or jet fuel was certified to meet the 15 ppm ULSD sulfur 
standard and cetane/aromatics specifications to fungibly transport, 
store, and dispense all 15 ppm sulfur distillate fuels downstream. We 
are also proposing provisions in part 1090 that would also allow ULSD 
to be used as heating oil, kerosene, jet fuel, or ECA marine fuel 
without recertification as long as records are kept demonstrating that 
the ULSD had been redesignated. We believe that these provisions would 
maximize the fungibility of distillate fuels, resulting in 
substantially reduced distributional costs and greater efficiency in 
the fuels market.
    During the rule development process, several stakeholders asked 
that we address issues regarding accounting for distillate fuels under 
the RFS program. We believe that this is outside the scope of this 
action. We recognize that this proposal could impact RFS compliance and 
have finalized provisions to help clarify how obligated parties (i.e., 
refiners and importers of gasoline and diesel fuel) account for 
distillate fuels under the RFS program in a separate action.\81\
---------------------------------------------------------------------------

    \81\ See 85 FR 7054-57 (February 6, 2020).
---------------------------------------------------------------------------

    We believe these proposed changes could help increase the 
efficiency with which distillate fuels are distributed, resulting in 
significant cost savings to stakeholders and consumers. We seek comment 
on whether this is the case and on how to quantify the associated cost 
savings.

VI. Exemptions, Hardships, and Special Provisions

A. Exemptions

    We are also transferring provisions that exempt fuels from 
applicable standards that are currently contained in part 80 to part 
1090. We are proposing minor revisions for purposes of modernizing 
these exemptions as well as removing obsolete exemption provisions, and 
any exemptions that were granted under part 80 will remain in effect 
with their original conditions as applicable under part 1090. As a 
result, instead of being scattered through various subparts as is the 
current practice in part 80, these provisions would be consolidated 
into a single subpart in part 1090 (subpart G) for all exemptions. This 
includes those exemptions that require a petition such as the hardship 
exemption and those that do not such as the for export exemption. This 
structure is designed to increase their accessibility and usability. 
Consistent with current provisions, exempted fuels, fuel additives, and 
regulated blendstocks do not need to comply with the standards of part 
1090, but remain subject to other requirements (e.g., registration, 
reporting, and recordkeeping) that are now also proposed to be moved to 
part 1090.
    We are not proposing any revisions to exemptions nor the related 
requirements that apply to fuels used for national security and 
military purposes, temporary research and development (R&D), racing, 
and aviation. Similarly, we are not proposing to change the exemption 
that applies to fuel in Guam, American Samoa, and the Commonwealth of 
the Northern Mariana Islands. Summer gasoline in Alaska, Hawaii, Puerto 
Rico, and the U.S. Virgin Islands would also continue to be exempt from 
the federal volatility regulations.
    We are, however, proposing minor revisions to these exemptions for 
consistency and as a result of consolidating the various part 80

[[Page 29056]]

exemptions. We are proposing that exemptions granted under part 80 
would remain in effect under part 1090, and as previously explained 
removing exemption provisions that are no longer active.
    We are proposing some changes to modernize the exemption 
provisions. First, we are proposing to include language that would 
impose conditions on parties operating under a research and development 
(``R&D'') test program to prevent the inadvertent use of test fuels 
exempted under a temporary R&D exemption by participants not included 
in the test program. Recently, we have received requests for R&D 
exemptions that focus on the effects of a certain fuel's use in more 
real world operation conditions (as opposed to a contained laboratory 
type situation). This often requires the test fuel be made available in 
a way that could result in vehicles or engines not included as part of 
the R&D program inappropriately using the test fuel. We believe it is 
appropriate for applicants requesting such an R&D exemption to take 
reasonable precautions to prevent consumers not participating in the 
test program from fueling with the test fuel. We are requesting comment 
on procedures that could be applied to fuels being tested under an R&D 
exemption when the test includes consumer participation that could 
result in the aforementioned misfueling.
    Second, we are proposing to allow certain exemptions for fuel 
additives and regulated blendstocks. Under part 80, it was unclear 
whether some exemptions applied to fuel additives and regulated 
blendstocks under certain programs, such as the gasoline sulfur 
program. Under 1090, fuel additives and regulated blendstocks would now 
be exempt from applicable requirements if certain conditions are met. 
For example, the military use exemption would now explicitly exempt 
fuels, fuel additives and regulated blendstocks used in either military 
vehicles or in support of military operations.
    Third, we are proposing that parties that transport and store 
exempt aviation and racing fuel take reasonable precautions to avoid 
the contamination of exempt fuels when using the same tanker trucks and 
tanks to transport and store exempt and non-exempt fuels. Aviation and 
racing gasoline can often contain lead additives that can harm emission 
controls on vehicles and engines designed to operate on unleaded 
gasoline. For example, when a tanker truck carrying exempt racing 
gasoline is later used to transport non-exempt gasoline, residual 
exempt racing gasoline could remain in the tanker truck and contaminate 
the non-exempt gasoline. We believe it is prudent for parties to follow 
established voluntary consensus-based standards for the cleaning out of 
tanker trucks. As such, part 1090 lists two such examples for cleaning 
tanker trucks to avoid contamination.\82\ We seek comment on this 
proposed requirement and whether there are other voluntary consensus-
based standards we should reference.
---------------------------------------------------------------------------

    \82\ API Recommended Practice 1595 and Energy Institute & Joint 
Inspection Group Standard 1530.
---------------------------------------------------------------------------

    California gasoline and diesel fuel are currently exempt from the 
part 80 standards in separate provisions under the various subparts. We 
are consolidating these existing exemptions for California fuels into a 
single comprehensive section. This reorganization eliminates the 
redundancy that resulted as new programs were implemented with 
California exemptions and old programs sunset but remained in the 
regulations with their original California fuels exemption. 
Additionally, housing all the provisions for the California fuels 
exemption in one section facilitates compliance with its requirements, 
as regulated parties need not scour part 1090 for hidden exemption 
provisions. We are also proposing provisions that clarify how 
California gasoline and diesel fuels may be used in states other than 
California in the consolidated California exemption section that 
explains the provisions. Under the current part 80 regulations, fuel 
manufacturers that make California gasoline and California diesel fuel 
must recertify those fuels in order to sell them outside the state of 
California. We are retaining this recertification requirement in part 
1090. Fuel manufacturers of California gasoline may recertify their 
fuels under the applicable standards of this part in order to sell such 
gasoline outside California. When manufacturers of California gasoline 
recertify their gasoline, they may participate in the Federal 
Averaging, Banking, and Trading (``ABT'') programs for gasoline sulfur 
and benzene. In addition to maintaining the option of recertifying, we 
are proposing to allow California gasoline manufacturers or 
distributors of California gasoline to simply redesignate the fuel as 
CG or RFG, so long as the California gasoline meets all the 
requirements for California reformulated gasoline under Title 13 of the 
California Code of Regulations and the manufacturer or distributor 
meets applicable designation and recordkeeping requirements.\83\ Under 
this proposal, parties that redesignate California gasoline for use 
outside of California would not be permitted to generate sulfur or 
benzene credits from the redesignated fuel. Similarly, California 
diesel fuel used outside of California would be deemed in compliance 
with the standards of this part if it meets all the requirements Title 
13 of the California Code of Regulations and the manufacturer or 
distributor meets applicable designation and recordkeeping 
requirements.\84\
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    \83\ The explanation for the analysis we performed to determine 
the equivalency of the California fuel standards can be found in the 
technical memorandum, ``The California Fuel Equivalency 
Memorandum,'' available in the docket for this action.
    \84\ The California reformulated gasoline and diesel fuel 
standards are at least as stringent as the standards under this 
part, therefore, these fuels should be allowed to be used throughout 
the country. Cal. Code Regs. tit. 13, Sec. Sec.  2281-2282 (2019).
---------------------------------------------------------------------------

B. Exports

    We are transferring the current part 80 exemption from applicable 
standards for fuels, fuel additives, and regulated blendstocks that are 
designated for export to part 1090. Additionally, we are transferring 
requirements for designation, product transfer documents, and gasoline 
segregation for fuels designated for export that currently apply under 
part 80 to part 1090. Diesel fuels not designated for export could be 
exported without restriction as long as those fuels meet the applicable 
fuel quality standards. However, the fuel remains subject to the 
provisions of this part while in the U.S. For example, fuel designated 
as ULSD must meet the applicable sulfur standards even if it will later 
be exported. Such diesel fuel that meets ULSD standards would not need 
to be segregated and may be redesignated for export by a distributor. 
On the other hand, diesel fuel that does not meet the ULSD standards 
would need to be designated for export and segregated from the point of 
production until the diesel fuel was exported, as currently required 
under part 80. We are also not proposing to require segregation of fuel 
additives and regulated blendstocks designated for export. However, 
some regulated parties have suggested applying the segregation 
requirement to those products, and we are seeking comment on whether to 
impose such a requirement as well as the impacts of imposing such a 
requirement.
    Under part 80, gasoline manufacturers are required to segregate 
gasoline designated for export. In this action, we are not proposing to 
change this

[[Page 29057]]

segregation requirement for gasoline exports. The only modification 
from part 80 is that these provisions, instead of being included in 
each gasoline program subpart, will be consolidated into a single 
subpart for exports under part 1090.

C. Hardships

    Under part 80, various subparts include separate provisions for 
receiving an exemption from that subpart's fuel quality standards due 
to unforeseeable hardship. We are proposing to consolidate these 
exemptions into one general hardship provision for unforeseeable 
circumstances (e.g., a natural disaster or refinery fire) that a 
refinery cannot avoid with prudent planning (excluding financial and 
supply chain hardship). The proposed reorganization is intended to make 
the hardship provision easier to find and does not change either the 
opportunity for a hardship or the regulated party's burden to 
demonstrate that its circumstances satisfy the requirements for 
applicable hardship exemptions. This change would not affect the RFS 
program, however, given that we are retaining the program in part 80. 
Accordingly, any exemptions available under that program would 
similarly remain unaffected.

VII. Averaging, Banking, and Trading Provisions

A. Overview

    We are transferring the part 80 averaging, banking, and trading 
(ABT) provisions for compliance with the sulfur and benzene average 
standards for gasoline to part 1090.\85\ We are proposing modifications 
that will facilitate consolidation of these various ABT regulatory 
provisions in part 80 into a single set of ABT provisions in part 1090. 
We are not transferring part 80 regulations that established separate 
ABT provisions for small refiners and small volume refineries given 
that they expired at the end of 2019. We have used ABT provisions to as 
a means to both meet our environmental objectives and provide regulated 
parties with the ability to comply with our fuel standards in the most 
efficient and lowest cost manner. This section also includes changes to 
how gasoline manufacturers could account for oxygenate added to 
gasoline downstream of fuel manufacturing facilities in compliance 
calculations. This section further describes a new proposed mechanism 
that would allow downstream parties that recertify batches of gasoline 
to use different types and amounts of oxygenate downstream of a 
manufacturing facility.
---------------------------------------------------------------------------

    \85\ We do not have ABT provisions for diesel fuel, so this 
section is only applicable to gasoline.
---------------------------------------------------------------------------

B. Compliance on Average

    We are proposing some minor changes to the format of the average 
compliance calculations to align the sulfur and benzene compliance 
calculations more closely to accommodate consolidating annual 
compliance reporting into a single reporting format. Under part 80, 
compliance with the benzene and sulfur average standards is 
demonstrated in separate forms and use a slightly different 
nomenclature. The proposed changes to the compliance calculations would 
not affect how gasoline manufacturers currently comply with the average 
standards or their stringency; however, the proposed equations appear 
slightly different compared to the similar equations in part 80. We are 
also proposing to add deficits incurred on an annual basis due to the 
recertification of BOBs downstream to use different types and amounts 
of oxygenates. This proposed change is discussed in detail in section 
VII.G.
    As previously noted, all part 80 regulations that had separate ABT 
provisions for small refiners and small volume refineries have expired 
or will by the time this proposed rule is implemented. The last such 
provisions are those related to the Tier 3 gasoline sulfur program, 
which will expire on December 31, 2019, resulting in small refiners and 
small volume refineries being required to be in compliance with the 
same part 80 fuel quality standards as other refiners. Since the 
proposed streamlined fuel quality regulations would take effect January 
1, 2021, part 1090 does not include separate ABT provisions for small 
refiners and small volume refineries. If in the future we propose new 
fuel standards, we would likely consider flexibilities for small 
refiners and small volume refineries as part of that future action.

C. Deficit Carryforward

    Under the Tier 3 sulfur and MSAT2 gasoline programs, we allow 
gasoline manufacturers to carryforward deficits, whereby an individual 
fuel manufacturing facility that does not meet either the sulfur or 
benzene standard in each compliance period may carry a credit deficit 
forward into the next compliance period. Under this deficit 
carryforward allowance, the manufacturer for the facility must make up 
the credit deficit and come into compliance with the applicable 
standard(s) in the next compliance period. We are proposing to 
consolidate the deficit carryforward provisions and we have proposed 
language that differs from the part 80 deficit carryforward provisions 
because the proposed language accommodates the consolidation of the 
gasoline sulfur and benzene deficit carryforward provisions into a 
single carryforward provision.

D. Credit Generation, Use, and Transfer

    We are also transferring the part 80 credit generation, use, and 
transfer provisions for gasoline manufacturers to part 1090. We are 
proposing minor changes to the language largely to ensure consistency 
between the sulfur and benzene credit trading programs.
    We are not proposing any changes to the lifespan of generated 
credits (i.e., credits generated under part 1090 would have the same 
lifespan as afforded them under part 80). Additionally, credits 
generated under part 80 would still be usable to comply with average 
standards under part 1090. To facilitate the use of part 80 credits 
under part 1090, we are including language to make it clear that 
credits generated under part 80 would still be valid for compliance 
under part 1090 for the specified life of the credits under part 80. 
For example, for credits generated for the 2020 compliance period, 
gasoline manufacturers could use those credits through the 2025 
compliance period.

E. Invalid Credits

    We are transferring the part 80 provisions for treatment of invalid 
credits to part 1090 without any modifications. Since the establishment 
of the sulfur and benzene ABT programs, we migrated tracking of credit 
transactions into EMTS. During the rule development process, we 
received feedback from stakeholders suggesting that the process for 
remediating invalid credits was onerous due to the administrative 
process associated with modifying credits in EMTS. Stakeholders also 
suggested that we rearrange the compliance deadlines to have annual 
compliance reports due after annual audits have occurred. Some 
stakeholders suggested that since the annual audit process identifies 
several issues after annual compliance reports have been submitted 
(i.e., after credits have been traded and retired for compliance), this 
switch would then allow for fewer resubmissions of reports and fewer 
remedial actions for invalid credits. Responsible parties would not 
need to amend reports since they would have been able to correct the 
original compliance reports based on an audit. We are not proposing to 
change the compliance deadlines. We believe

[[Page 29058]]

changing the compliance deadlines would disrupt a relatively well 
functioning compliance program and we believe other actions proposed as 
part of the streamlined fuel quality regulations would reduce the 
frequency of resubmissions and remedial actions. For example, we 
believe by allowing less precision in the rounding of gallons, 
responsible parties would have fewer remedial actions if audits 
identify that a party was off by a single gallon on their annual 
reports. We also believe that by streamlining the regulatory and 
reporting requirements, compliance demonstrations would be less prone 
to the types of errors that often require resubmissions. We also note 
that companies always have the option of performing their own audits 
internally. However, we seek comment on whether we should rearrange the 
compliance deadlines as a means to reduce resubmissions and remedial 
actions.

F. Downstream Oxygenate Accounting

    We are proposing a single method for gasoline manufacturers to 
account for oxygenate added downstream of a fuel manufacturing 
facility. Oxygenate accounting provides the flexibility for fuel 
manufacturers to ensure that average standards are met. Under part 80, 
we have provided several mechanisms, depending on the gasoline program, 
for refiners and importers to account for oxygenate added downstream. 
Under the current part 80 RFG provisions for oxygenate blending and 
accounting, refiners and importers create a hand blend and test the 
hand blend for reported parameters and include these values in their 
compliance calculations to demonstrate compliance with sulfur and 
benzene average standards and the RFG performance standards. The 
refiner or importer then specifies the type(s) and amount(s) of 
oxygenates on PTDs to be added by the oxygenate blender, who must then 
follow the blending instructions by the refiner or importer. Further, 
refiners and importers must contract with an independent surveyor to 
verify that an oxygenate is added downstream at levels reported to EPA 
in batch reports.
    Due to the fungible nature of most CG and CBOB, it is difficult for 
many CG/CBOB refiners or importers to account for oxygenate that is 
added downstream. Under part 80, CG/CBOB refiners and importers can 
only account for oxygenate if the refiner or importer can establish 
that the oxygenate was in fact added to the CG or CBOB. The CG/CBOB 
refiner or importer can establish that the oxygenate was blended by 
either: (1) Blending the oxygenate themselves; or (2) having a contract 
with an oxygenate blender specifying procedures the oxygenate blender 
will follow to add the amount of oxygenate claimed by the CG/CBOB 
refiner or importer and the refiner or importer has an oversight 
program to ensure that the oxygenate blending takes place. Under Tier 
3, CG/CBOB refiners and importers may assume 10 percent ethanol 
containing 5 ppm sulfur in compliance calculations to account for 
oxygenate added downstream. Further, part 80 does not contain any 
allowance provisions to assume dilution of benzene from oxygenate added 
downstream. Based on information gleaned during the rule development 
process, it appears the average sulfur levels for DFE are lower (2-3 
ppm) than the assumed value of 5 ppm allowed under Tier 3. This 
regulatory disparate treatment of CG/CBOB compared to RFG/RBOB has 
created a scenario where it is more difficult for CG/CBOB refiners and 
importers to account for the benefits of the addition of downstream 
oxygenates.
    In part 1090, we are proposing to require gasoline manufacturers to 
use ``hand blends'' when accounting for oxygenate added downstream. We 
are also proposing to require that oxygenate blenders follow 
instructions for the type(s) and amount(s) of oxygenated from the BOB 
manufacturer. The proposed requirements for gasoline manufacturers and 
oxygenate blenders largely mirror the requirements for oxygenate 
blending and accounting found in the RFG program.
    The main differences between the proposed hand blend approach and 
the current RFG program is that the accompanying in-use survey would be 
national in scope (instead of just a survey of RFG areas), and the BOB 
manufacturer would need to participate in the proposed national 
sampling oversight program. The accompanying in-use survey requirements 
are discussed in more detail in Section X. Additionally, since we are 
broadening the scope of the oxygenate accounting process from RBOB to 
all BOB, we are also proposing that gasoline manufacturers prepare 
samples using the hand blend procedures in ASTM D7717 and that 
commercially available oxygenate (e.g., denatured fuel ethanol) be used 
to make hand blends. The oxygenate used should reflect the anticipated 
sulfur and benzene levels of the oxygenate that will ultimately be 
blended with the BOB. All other proposed requirements would be the same 
as currently specified for the RFG program.
    During the rule development process, we received feedback from some 
stakeholders requesting that we allow multiple different options for 
gasoline manufacturers to account for oxygenate added downstream. These 
stakeholders argued that the use of assumptions in compliance 
calculations, as currently allowed under Tier 3 for sulfur, could be 
easier for some manufacturers to adopt. As discussed earlier, we 
currently allow for many different methods for accounting for oxygenate 
added downstream. While this has allowed some gasoline manufacturers 
(primarily manufacturers of RFG) to benefit from this ability, it has 
practically precluded other gasoline manufacturers (primarily 
manufacturers of CG) from enjoying the same flexibility, creating an 
unlevel playing field. We believe that providing a single method of 
accounting for oxygenate added downstream ensures a level playing field 
for all gasoline manufacturers and allows us to better assure that 
appropriate levels of oxygenate are accounted for through in-use 
verification in the downstream survey. Additionally, setting 
assumptions for manufacturers to use in compliance calculations would 
require information on what those assumptions should be for all 
regulated parameters (i.e., benzene, sulfur, and RVP). The validity of 
such assumptions could change over time as new oxygenates or, in the 
case of DFE, new sources of denaturant are established over time. 
Changing such assumptions would require EPA to amend its regulations, 
potentially resulting in an inadvertent change in in-use fuel quality. 
On the other hand, by utilizing the proposed hand blend approach, we 
would allow gasoline manufacturers to adjust hand blends to adapt to 
market changes almost immediately (e.g., if there was an increased 
demand for E0 or E15). This would ensure that what is reported is 
ultimately reflective of what is happening in the market, thereby 
maintaining the stringency of the fuel quality standards over time. 
However, we seek comment on allowing parties to use assumptions and if 
so, appropriate assumed values for oxygenates added downstream. In 
particular, we seek specific data supporting the use of assumed values.
    Also, during the rule development process, some stakeholders 
highlighted that allowing CG manufacturers that are not currently 
accounting for oxygenate added downstream may result in a change in in-
use fuel quality. These stakeholders pointed out that if CG 
manufacturers are not currently taking advantage of oxygenate 
accounting due to the difficultly of ensuring that

[[Page 29059]]

oxygenate is added downstream, these manufacturers would be slightly 
over-complying with the required sulfur and benzene average standards. 
We expect any such effects to be minimal, and we discuss these 
potential effects in more detail in Section XIV.\86\
---------------------------------------------------------------------------

    \86\ We discuss these effects in more detail in the technical 
memorandum, ``Estimated Effects of Proposed Downstream Oxygenate 
Accounting Provisions,'' available in the docket for this action.
---------------------------------------------------------------------------

G. Downstream Oxygenate Recertification

    Under the part 80 RFG program, oxygenate blenders must add the 
type(s) and amount(s) of oxygenate(s) to RBOB as specified by refiners 
under 40 CFR 80.69. Refiners must specify blending instructions for all 
RBOB, most of which is to be made into E10. An oxygenate blender that 
recertifies a batch of RBOB under part 80 is a gasoline refiner and 
must comply with all the applicable requirements for a gasoline 
refiner. These requirements include registration under part 79 as a 
fuel manufacturer, registering under part 80 as a refiner, complying 
with sulfur and benzene average standards, and batch sampling and 
testing. As a result of these requirements and the relatively low 
volume of E0 needed, oxygenate blenders do not typically opt to assume 
the role of a gasoline refiner, reducing the availability of E0 in RFG 
areas. Similarly, the RFG regulations under part 80 practically 
preclude the use of isobutanol in RBOBs since the regulations require 
that oxygenate blenders add the type and amount of oxygenate specified 
by the RFG refiner or importer (which is predominately E10). Under part 
80, parties may recertify the batch of RFG; however, the high cost 
associated with recertifying batches of RBOB downstream essentially 
precludes oxygenate blenders from blending isobutanol in RFG areas 
since the batch sizes are relatively small (typically the volume of a 
single tanker truck).
    These restrictions, currently limited to RFG areas, could be 
compounded by the proposed downstream oxygenate provisions discussed in 
Section VII.F. Consequently, we are proposing a provision in part 1090 
that would allow parties downstream of gasoline manufacturing 
facilities to more easily recertify BOBs for different types and 
amounts of oxygenates. Specifically, we are proposing a downstream 
certification mechanism to allow for oxygenate blenders to recertify 
batches of BOB for different types and amounts of oxygenates as the 
market demands to make sure that consumers can still have E0, E15, or 
isobutanol-blended gasoline available as needed. In other words, under 
part 1090, oxygenate blenders must follow the blending instructions on 
PTDs by gasoline manufacturers unless they recertify the batch for a 
different type and/or amount of oxygenate.
    We are proposing to require that parties that wish to recertify 
BOBs must determine the number of sulfur and benzene credits lost by 
any lack of downstream oxygenate dilution in cases where the party 
added less oxygenate than was specified by the gasoline manufacturer. 
For example, if a party takes a premium BOB intended for blending with 
ethanol at 10 volume percent and wishes to use it as E0 for 
recreational vehicles, this party would need to make up for the lost 
dilution of the sulfur and benzene in the national fuel pool. We have 
included additional compliance calculations that such parties would 
need to use to determine the number of sulfur and benzene credits 
needed. In this calculation, we are proposing default assumed values 
for the amount of sulfur and benzene from the BOB. We are proposing 
default values of 11 ppm sulfur and 0.68 volume percent benzene. These 
proposed values are reflective of the national sulfur and benzene 
average values adjusted for the absence of denatured fuel ethanol added 
at 10 volume percent ethanol.\87\ The goal of these proposed values is 
to avoid requiring additional sampling and testing from the 
recertifying party. We believe that due to the small batch volume for 
recertified product, typically the size of a tanker truck, the amount 
of credits needed for any given batch of recertified gasoline would be 
low and small changes from actual benzene and sulfur content would be 
in the noise of the proposed compliance calculation and washed out in 
the marketplace. However, we seek comment on whether different default 
values would be appropriate.
---------------------------------------------------------------------------

    \87\ We took the national average values for sulfur (10 ppm) and 
benzene (0.62 volume percent) and multiplied them by 110 percent.
---------------------------------------------------------------------------

    In cases where a party adds the same volume of oxygenate or more, 
these credit makeup regulations would not apply, as more than enough 
sulfur and benzene dilution would have occurred. For example, adding 15 
volume percent ethanol into a BOB intended for the addition of 10 
volume percent ethanol or adding 12 volume percent isobutanol to a 
batch of BOB intended for the addition of 10 volume percent ethanol. 
All other applicable requirements under the CAA and parts 79, 80 and 
1090 would apply to the recertified fuel. For example, the recertified 
gasoline would need to meet RVP requirements in the summer, meet per-
gallon sulfur requirements, and be substantially similar under CAA 
section 211(f). Part 80 currently does not allow oxygenate blenders to 
generate credits in cases where additional oxygenate is added to RBOB 
or CBOB and part 1090 would not change this. The challenges associated 
with implementing and enforcing such a credit provision with so many 
entities on such small volumes has historically created considerable 
difficulties, and there does not appear to be any compelling reason 
here to change from the current regulations.
    In order to ensure that parties that recertify BOBs downstream 
adhere to the proposed provisions for downstream oxygenate 
recertification, we are proposing that these parties would need to 
register with EPA, transact any needed sulfur and benzene credits, 
submit annual compliance reports, and keep records documenting the 
blending activities and reports submitted to EPA. In lieu of requiring 
the burden of sampling and testing each batch, we are also proposing 
that these parties simply undergo an annual attest engagement audit and 
submit an attest report similar to the report required for gasoline 
manufacturers. The proposed requirements would only apply to parties 
that incur a deficit by recertifying BOBs with less oxygenate than 
specified on the PTD. If a party is already registered with EPA and 
complies with sulfur and benzene averaging requirements, the party 
would include the total number of credits needed as a result of 
downstream oxygenate recertification in their annual compliance 
calculations as a deficit.
    During the rule development process, we solicited feedback on 
whether parties that recertify BOBs downstream should undergo an annual 
audit to help ensure that the party complied with the proposed 
requirements correctly. We received feedback from stakeholders stating 
that while many of the parties that would elect to use this flexibility 
are already registered with EPA under part 80, these parties often do 
not have an annual attest engagement as they do not manufacture 
gasoline. Therefore, these stakeholders argued that having an attest 
engagement, which costs tens of thousands of dollars per year, for a 
small volume of fuel (one tanker truck of approximately 8,000 gallons) 
is unreasonably burdensome and would significantly increase the costs 
of recertified fuels. We agree with this feedback; however, we believe 
that parties that recertify a significant

[[Page 29060]]

amount of gasoline for different types and amounts of oxygenates should 
undergo an annual audit as these parties could have a greater effect on 
the larger sulfur and benzene pools. Therefore, we are proposing that 
parties that recertify less than 200,000 total gallons of gasoline for 
different types and amounts of oxygenate during a compliance period 
would be exempt from the annual attest audit and report.\88\ We believe 
this proposed flexibility would allow small blenders to avoid a 
substantial amount of compliance costs associated with recertification 
of batches of gasoline for different types and amounts of oxygenates 
while ensuring integrity in the sulfur and benzene credit markets. We 
seek comment on whether this allowance is appropriate.
---------------------------------------------------------------------------

    \88\ We estimated this value based on the 1st percentile of 
credit transaction sizes for benzene credits in 2018. Our analysis 
for calculating the 200,000 gallon number is included in the 
technical memorandum, ``Estimated Effects of Proposed Downstream 
Oxygenate Accounting Provisions,'' available in the docket for this 
action.
---------------------------------------------------------------------------

    Also, during the rule development process we received feedback 
asking for alternatives to the proposed downstream oxygenate 
recertification approach. Stakeholders suggested potentially developing 
a factor that would go into a gasoline manufacturer's compliance 
calculations that estimated the nationwide level of oxygenate blended 
into gasoline. While we believe this measure could effectively capture 
the amount of oxygenate added downstream, it creates level-playing 
field concerns by effectively increasing the standard for gasoline 
manufacturers that certify 100 percent of their batches with oxygenates 
and decreasing the standards for parties that certify less than 100 
percent. Additionally, we believe that setting the factor creates 
challenges. For example, if we set a level consistent with today's 
oxygenate blending levels and the market changes the amount of 
oxygenate added to the fuel pool in the future, we would have to 
undertake a future rulemaking to accommodate the new amount of 
oxygenate blended into gasoline. If we put in place an administrative 
process to adjust the factor on a periodic basis (e.g., annually), we 
believe it would be challenging to continually monitor and track the 
appropriate number without imposing significant additional reporting 
and tracking burdens on the part of industry. Failure to provide a new 
reporting and tracking mechanism would result in delays in establishing 
the factor on a periodic basis providing uncertainty for gasoline 
manufacturers in determining sulfur and benzene average standards. We 
believe the proposed approach provides the desired marketplace 
flexibility, puts in place appropriate and manageable measures to 
ensure environmental performance, and allows for flexibility both now 
and into the future without the need for additional regulatory action. 
However, we seek comment on other approaches to allow parties to 
recertify batches of BOB for different types and amounts of oxygenates 
downstream.
    Finally, during the rule development process, we received feedback 
asking for an allowance to carry forward a deficit related to 
downstream oxygenate recertification. Stakeholders suggested that it 
would take time for the sulfur and benzene credit markets and regulated 
parties to adjust to this proposed flexibility. They suggested that 
allowing a limited time deficit carry-forward would allow for this 
proposed flexibility to be implemented more smoothly. We believe that 
the amount of credits needed to satisfy deficits incurred related to 
downstream oxygenate recertification is relatively small and that 
allowing parties to carry-forward deficits related to this proposed 
provision would result in some parties failing to satisfy those 
deficits. Therefore, we are not proposing to allow deficit carry-
forwards for deficits created by downstream oxygenate recertification. 
However, we seek comment on whether providing such a deficit carry-
forward is needed to help implement the proposed downstream oxygenate 
recertification provisions. Comments on this subject should include a 
reasonable period of time for consideration.

VIII. Registration, Reporting, Product Transfer Document, and 
Recordkeeping Requirements

A. Overview

    We are mostly transferring the existing part 80 registration, 
reporting, PTD, and recordkeeping provisions that are distributed among 
various subparts in part 80 to part 1090. We also intend to reconcile, 
simplify, and logically organize those provisions. The resulting 
registration, reporting, product transfer document (PTD), and 
recordkeeping requirements proposed for part 1090 are like those 
already in place under part 80. Where possible we have sought to reduce 
the impacts upon regulated parties and reduce the burden associated 
with maintaining and submitting information. In certain cases, we have 
proposed regulations to simplify or better align reporting requirements 
with current industry practice, which is particularly true of the batch 
reporting requirements described in greater detail below.
    Information submitted under part 1090 may be claimed as 
confidential business information (CBI) by the submitter, including 
certain information submitted via registration and reporting systems. 
EPA will protect such information from public release in accordance 
with the provisions of 40 CFR part 2 and in a manner consistent with 
EPA rules and guidelines related to CBI. Our public release of EPA 
enforcement-related determinations and EPA actions, together with basic 
information regarding the party or parties involved and the 
parameter(s) or credits affected, does not involve the release of 
information that is entitled to treatment as CBI. Such information may 
include the company name and company identification number, the 
facility name and facility identification number, the total quantity of 
fuel and parameter, and the time period when the violation occurred. 
Enforcement-related determinations and actions within the scope of this 
release of information include notices of violation, administrative 
complaints, civil complaints, criminal information, and criminal 
indictments. Although we are not proposing a comprehensive CBI 
determination at this time, we may undertake that activity in a future 
rulemaking.

B. Registration

1. Purpose of Registration
    Registration is necessary to: (1) Identify which parties engage in 
regulated activities under our regulations; (2) allow regulated parties 
access to systems to submit information required under our fuel quality 
regulations; and (3) provide regulated parties with company and 
compliance-level identification numbers for producing PTDs and other 
records. This action would make modest changes to the existing 
registration system including modernizing certain terminology and 
making updates that make registration easier to understand and 
implement.
2. Who Must Register
    The proposed registration requirements are designed to update 
terminology to better reflect current roles and activities in the fuel 
production and distribution system. We are proposing registration 
requirements for certain third parties, such as independent auditors. 
These are explained in greater detail below. The following parties 
would have to register

[[Page 29061]]

with EPA prior to engaging in any activity under part 1090:

 Gasoline manufacturers
 Diesel fuel and ECA marine manufacturers
 Oxygenate blenders
 Oxygenate producers
 Certified butane blenders
 Certified pentane producers
 Certified pentane blenders
 Transmix processors
 Certified ethanol denaturant producers
 Distributors, carriers and resellers who are part of a 500 ppm 
LM diesel chain and who are part of a compliance plan proposed under 40 
CFR 1090.515(c)
 Independent surveyors
 Auditors
 Third parties who require access to EPA's registration and 
reporting systems, including those who submit reports on behalf of any 
party regulated under part 1090

    Nearly all parties who would be subject to registration under part 
1090 are already registered under part 80. We are not requiring parties 
who are already registered under part 80 to go through the effort to 
re-register their company or their facilities under part 1090. We are 
proposing to include specific provisions in part 1090 that would ensure 
such parties do not need to re-register. For example, although we do 
not currently register parties under part 80 as ``gasoline 
manufacturers,'' parties who are currently registered as ``refiners'' 
would be understood to fall under this new term and would not have to 
re-register. We do not believe that this action will result in a 
significant number of new registrants, and existing registrants would 
only need to make the type of routine registration updates they already 
are required to make (e.g., to add or delete activities they engage in 
or to change an address).
    We are also proposing to remove an existing registration 
requirement under part 80. Although independent laboratories are 
required to register under part 80, we are proposing to remove this 
registration requirement and are not transferring this requirement from 
part 80 to part 1090. As a result, independent laboratories would no 
longer be required to register unless they submit information directly 
on behalf of another party, such as a gasoline manufacturer. In such 
cases, they would need to update their registration to reflect that 
they are submitting reports on behalf of a regulated party and would 
have to associate with the company or companies for which they will 
submit reports. Association is a step within the existing registration 
system and is designed to ensure that the company for which the reports 
are submitted by the ``agent'' agrees to that arrangement. Association 
is designed to be a simple step that would still prevent an 
unauthorized party from submitting reports on another's behalf without 
their consent or knowledge.\89\
---------------------------------------------------------------------------

    \89\ During the rule development process, we received feedback 
suggesting that we should maintain the registration requirement and 
the itinerant RFG independent laboratory testing program; this issue 
is discussed in more detail in Section X.B.
---------------------------------------------------------------------------

    We are also proposing new registration requirements for independent 
surveyors and independent auditors under part 1090. These parties are 
not subject to registration requirements under part 80 but either 
submit survey plans and periodic reports to EPA under various 
provisions or perform attest engagements for regulated parties under 
part 80. We thus believe that requiring them to register would allow 
them to submit reports directly to EPA and thereby further streamline 
the process of getting the information to EPA.
    Independent surveyors perform the compliance surveys and the 
proposed voluntary sampling oversight program (discussed in more detail 
in Section X). At present, there is only one known independent 
surveyor, performing four types of surveys under part 80. As previously 
noted, independent surveyors already submit survey reports to EPA, in a 
variety of ways. As discussed in Section VIII.C.8, we are proposing to 
have them register so that they may submit reports via EPA's reporting 
systems. Although this would create a small, new class of registrants 
(currently only one new submitter), we believe the burden of 
registering is outweighed by the simplicity and reliability of having 
surveyors utilizing the electronic reporting system to submit their 
information. This proposed change would allow us to more quickly 
publicly post in-use survey results.
    As also previously noted, independent auditors already perform 
attest engagements on behalf of parties who are required to demonstrate 
compliance via reporting. Under part 80, the regulated party (e.g., a 
gasoline manufacturer) is required to hire an auditor to perform the 
attest engagement, and the auditor gives the attest engagement to the 
party who then must submit it to EPA. In order to streamline the 
reporting process, we are proposing to require auditors to submit the 
attest engagement directly to EPA in a manner that ensures that the 
party for whom it was prepared is aware of the submission to EPA. To 
implement this change, auditors would register and associate with the 
party to submit reports directly to EPA. Association will ensure that 
the regulated party knows and agrees that the auditor is submitting 
their report.
3. What Is Included in Registration
    Similar to existing provisions in part 80, registration under part 
1090 would entail submitting general information about the company and 
its compliance-level activities (e.g., facilities), including the 
address, activities engaged in, name of a responsible corporate officer 
(RCO), contact information, and location of records. Parties who submit 
reports to EPA must complete the steps required to set up an account 
with EPA's Central Data Exchange (CDX) and/or with OTAQ Registration 
(OTAQReg). Most regulated parties affected by this action have already 
registered and have already set up the necessary accounts.
4. Deadlines for Registration
    We are proposing that registration must occur prior to a party 
engaging in any activity that requires registration, but we are not 
specifying a firm deadline for registration as we have in the past. 
Under part 80, new registrants had to register 60 days prior to 
engaging in activity. This timeframe remains a useful guideline, 
however, as we must be allowed an appropriate amount of time to process 
and activate registration-related requests. We are retaining the 
requirements from part 80 that updates to existing registration must 
occur within 30 days of the event requiring the change. We do not 
expect many new registrants and existing registrants would continue to 
be registered under part 1090. However, we do anticipate registering up 
to 100 attest auditors, one surveyor, and 50 third parties. We have 
docketed a detailed ICR supporting statement that describes the 
recordkeeping and reporting (including registration) burden in terms of 
number of parties, hours, and dollars.
    Company and compliance-level (e.g., facility) identification 
numbers already in use will remain valid under part 1090.
5. Proposed Approach to Changes in Ownership
    In part 1090 we have sought to address some on-going issues and 
concerns regarding registration updates. For example, we have received 
feedback over the years from registrants that changes in ownership 
should be addressed more clearly in the registration section. 
Consequently, we

[[Page 29062]]

are proposing provisions to clarify how a company may initiate a change 
in ownership for registration purposes. The proposed provisions on 
updating registrations for ownership change largely codify existing 
guidance provided to companies under part 80.
    Proposed provisions in part 1090 clarify that companies would have 
to notify EPA of a change in ownership and, in cases requiring 
registration of a new company, complete registration prior to engaging 
in any activity requiring registration under part 1090. In the case of 
a change in ownership requiring an update to an existing registration, 
the company would need to complete the registration update within 30 
days of the change. For any party that is a fuel or fuel additive 
manufacturer, the new owner would need to be in full compliance with 
any applicable part 79 registration requirements. Since part 1090 
registration is needed in order to report and engage in credit 
transactions and comply with the fuel quality regulations, parties have 
great incentive to submit ownership change information to EPA as soon 
as it is available. We have received feedback from stakeholders who 
have told us that having a requirement that they submit ownership 
change information by a specific, advance deadline (e.g., 60 days 
before the change in ownership occurs) is not workable due to how 
ownership changes are effectuated in the business world. Although we 
are not proposing a specific, advance deadline, we note that it 
typically takes some time for EPA to process a new registration and 
urge companies to attempt to submit materials as soon as possible and 
to consider that 60 days prior is a good guideline. Based on our 
experience with ownership changes under part 80, companies want EPA to 
activate registration changes for ownership changes in a timely manner 
to ensure that registrations are up-to-date and that the company can 
engage in credit generation, trading, and use as soon as practical. 
Often, these companies request a specific date for the ownership change 
to be reflected with respect to their registration. Because many 
ownership changes in the fuel quality programs are quite complicated 
and involve many facilities, in order for EPA to reasonably act on this 
type of registration update, we need adequate time to process 
registration changes.
    We believe common ownership changes may include: Companies and/or 
facilities that are bought in their entirety by another party; 
companies and/or facilities whose majority owner changes; or a merger 
resulting in creation of a new company and/or facility. We are not 
proposing a specific list of documentation that parties may have to 
submit to support a change in ownership affecting their registration. 
What documentation, if any, is needed is highly situational. However, 
we do have experience with typical documentation submitted by parties 
that may be appropriate, and that may include: sale documentation or 
contract (portions may be claimed as CBI and redacted); Articles of 
Incorporation, Certificate of Incorporation, or Corporate Charter 
issued by a state; and/or other legal documents showing ownership 
(e.g., deeds). Parties anticipating the need to update registration due 
to a change in ownership should contact EPA as soon as possible in 
order to discuss their unique situation.
6. Proposed Approach to Cancellation of Registration
    We are proposing provisions regarding voluntary and involuntary 
cancellation of registration. Similar provisions exist for the RFS 
program in 40 CFR part 80, subpart M, and we believe they work well for 
both compliance and compliance assistance purposes; therefore, we are 
proposing to adopt them for part 1090.
    Voluntary cancellation would be initiated by the registered party 
(e.g., if the party's business changes and it no longer engages in an 
activity that requires registration).
    Involuntary cancellation would be initiated by EPA, typically in 
cases where the party has failed to submit required reports or attest 
engagements, or for a prolonged period of inactivity. Specifically, 
involuntary cancellation may occur where:
     The party has not accessed its account or engaged in any 
registration or reporting activity within 24 months.
     The party has failed to comply with any registration 
requirements, such as updating needed information.
     The party has failed to submit any required notification 
or report within 30 days of the required submission date.
     The attest engagement has not been received within 30 days 
of the required submission date.
     The party fails to pay a penalty or to perform any 
requirements under the terms of a court order, administrative order, 
consent decree, or administrative settlement between the party and EPA.
     The party submits false or incomplete information.
     The party denies EPA access or prevents EPA from 
completing authorized activities under sections 114 or 208 of the CAA 
despite presenting a warrant or court order. This includes a failure to 
provide reasonable assistance.
     The party fails to keep or provide the records required by 
part 1090.
     The party otherwise circumvents the intent of the CAA or 
part 1090.
    We would provide notification of our intention to cancel the 
party's registration and the registrant would have an opportunity to 
address any deficiencies identified in the notice (e.g., to submit 
required reports) or to explain why no deficiency exists. If we do not 
receive missing reports within 14 days of notification, then the 
registration may be canceled without further notice. We believe it is 
important to have a procedure to keep registrations up-to-date and to 
ensure that parties perform activities required to maintain active 
registration.
    We are proposing that in instances of willfulness or those in which 
public health, interest, or safety requires otherwise, EPA may 
deactivate the registration of the party without any notice to the 
party. In such cases, we will provide written notification to the RCO 
identifying the reason(s) EPA deactivated the registration of the 
party. We expect such situations to be extreme and rare and intend to 
follow the notice and response provisions described above in nearly all 
cases.

C. Reporting

1. Purpose of Reporting
    We require reports from regulated parties for the following 
reasons: (1) To monitor compliance with standards necessary to protect 
human health and the environment; (2) to allow regulated parties to 
comply with average standards via the use of credits and credit trading 
systems; (3) to have accurate information to inform EPA decisions; and 
(4) to promote public transparency. Regulated parties submit various 
reports to EPA under both parts 79 and 80. Part 1090 updates and, in 
many cases simplifies, what must already be reported to EPA under part 
80. As described further in this section, we are proposing to reduce 
the number of parameters to be tested and reported and, in some cases, 
to reduce the required frequency of reporting.
2. Who Must Report
    The following parties would have to report under part 1090:

 Gasoline manufacturers
 Diesel manufacturers and ECA marine manufacturers
 Transmix Processors
 Oxygenate producers
 Certified butane blenders
 Certified pentane producers

[[Page 29063]]

 Certified pentane blenders
 Independent surveyors
 Auditors

    As discussed earlier in this section, certain parties are required 
to register to receive company and compliance-level identification 
numbers for use on PTDs and for recordkeeping, although they would not 
have reporting requirements under part 1090. For example, parties 
involved in the manufacture and distribution of 500 ppm LM diesel fuel 
would register and receive company and compliance-level identification 
numbers to use on PTDs and records but would not submit reports under 
this part 1090.
3. What Is New With This Proposal
    We are proposing to eliminate reporting of the following gasoline 
parameters that are currently collected under part 80 and no longer 
necessary under part 1090 to certify batches and demonstrate compliance 
with the RFG standards (discussed in more detail in Section V.A.2):
 Aromatics and the associated test method
 Olefins and the associated test method
 Methanol and the associated test method
 MTBE and the associated test method
 Ethanol and the associated test method
 ETBE and the associated test method
 TAME and the associated test method
 T-Butanol and the associated test method
 T50 and the associated test method
 T90 and the associated test method
 E200 and the associated test method
 E300 and the associated test method
 Toxics
 VOCs
 Exhaust Toxics Emission
 Other identifying information (i.e., Batch Grade, lab waiver, 
Independent lab analysis requirement)

    We are proposing to retain only four main parameters for gasoline 
reporting: Sulfur, benzene, RVP, and oxygenate type/content.\90\ We 
believe the parameters we are proposing to eliminate from reporting, 
although once useful, are no longer needed in reports, as discussed in 
Section V.A.2. Removing these parameters would reduce compliance costs 
related to reporting, sampling, and testing, without sacrificing our 
goal of protecting human health and the environment. We are also 
proposing to simplify the annual, batch, and credit transactions 
reporting, which result in many fewer forms and data elements for 
respondents.
---------------------------------------------------------------------------

    \90\ For batches that are certified using the hand blend 
approach (discussed in more detail in Section VII.F), oxygenates 
typically would not be tested; however, gasoline manufacturers would 
report the type and amount of each oxygenate blended to make the 
hand blend. Manufacturers that certify batches of gasoline using a 
different approach would still need to test and report oxygenate 
content unless they know that the gasoline contains no oxygenate 
(i.e., the gasoline is E0). Furthermore, in all cases, we would only 
require that gasoline manufacturers report the oxygenates added or 
tested for instead of reporting information for all potential 
oxygenates. We believe this would greatly simplify oxygenate 
reporting requirements compared to part 80.
---------------------------------------------------------------------------

    There are currently numerous reporting forms in use under part 80; 
we seek to simplify and reduce the number of forms under part 1090. 
Proposed reporting formats are available in the docket for this action 
and have also been included in the information collection request (ICR) 
described in Section XV.C.
4. Proposed Reporting Requirements for Gasoline Manufacturers
    As previously discussed, we are transferring the current part 80 
requirements for annual, batch, and credit transaction reporting for 
gasoline manufacturers to part 1090. We are proposing to: (1) Reduce 
the number of parameters and test methods to be reported under part 
1090 as compared to part 80; and (2) simplify the method of reporting. 
The proposed reporting requirements for these parties includes the 
following:
     Annual compliance demonstration for sulfur, to include 
information about the total volume of gasoline produced or imported, 
the compliance sulfur value, summary information about sulfur credits 
owned, generated, retired, etc., and information about credit deficits. 
This information is like the information already required and submitted 
under part 80.
     Annual compliance demonstration for benzene, to include 
information about the total volume of gasoline produced or imported, 
the compliance benzene value, summary information benzene credits 
owned, generated, retired, etc., and information about credit deficits. 
This information is like the information already required and submitted 
under part 80.
     Batch reporting, including information about individual 
batches of gasoline, to include information about the date of 
production or import, the volume, the designation of the gasoline or 
BOB, the tested sulfur and benzene content of the batch, and the tested 
RVP for summer gasoline or BOB. The proposed regulations address 
reporting for a variety of gasoline products and reporting scenarios 
and explains reporting for specific scenarios, such as the reporting 
for blendstocks added by gasoline manufacturers to PCG by either the 
compliance by addition or compliance by subtraction method and 
reporting for blending of certified butane or pentane. We have prepared 
a technical memorandum and a detailed color-coded batch reporting 
summary table reflecting the information to be submitted for a variety 
of products. This information is available in the docket for this 
action and has been provided as an addendum to the ICR described in 
Section XV.C.
     Credit transaction reporting, including information about 
the generation, purchase, sale, retirement, etc. of sulfur and benzene 
credits. This information is like the information already required and 
submitted under part 80.
     Attest engagements. Under part 1090, there is a change to 
the method of submission of annual attest engagements. As discussed 
above, we are proposing to add independent auditors to the list of 
parties that can submit attest engagements, provided that they first 
register with EPA and are associated with a company. To ensure the 
party for whom the attest engagement is prepared is aware, we are 
proposing that the independent auditor and the company for whom they 
are preparing the report must associate within the registration system. 
The existing attest engagement requirements are sprinkled around part 
80; this action would condense the existing requirements into a single 
subpart (subpart R). We are also proposing to align the submission of 
the attest engagements for the RFS program so that they would be 
submitted directly by the independent auditor and to include 
association, as well. We are aware that some regulated parties have 
expressed concern that they would not know if their attest engagement 
has been submitted by the auditor and would not be afforded time to 
review and respond to the auditor's findings. To address this concern, 
we are requesting comment from regulated parties on what information 
and required steps are needed prior to submission by the attest 
auditor. The attest engagement submission would require a description 
of the findings and the steps the regulated party will take to address 
remedial actions, but does not necessarily require the remedial action 
steps to all occur before submission. Attest engagements are discussed 
in detail in Section XII.B.

[[Page 29064]]

5. Proposed Reporting Requirements for Gasoline Manufacturers That 
Recertify BOB for Different Type(s) and Amount(s) of Oxygenate
    In order to implement the proposed optional provisions discussed in 
Section VII.G with respect to treatment of BOBs, we are proposing 
reporting requirements for gasoline manufacturers that recertify BOB 
for different types and amounts of oxygenate. When a person recertifies 
a BOB with less oxygenate than specified by the fuel manufacturer, they 
would be required to submit information about recertification activity 
on a batch level report and include any deficits incurred in their 
annual sulfur and benzene compliance report.\91\ Credit transactions 
associated with re-certification of the BOB would also be reported. 
Similar to what is currently allowed under part 80 for certified butane 
and pentane blending, we are proposing to allow parties that recertify 
BOBs to include all volumes and deficits in a single reported batch of 
up to 30 days. This will help minimize the potential reporting burden 
associated with this requirement.
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    \91\ Parties that add more of the same type of oxygenate would 
not be expected to submit reports for those volumes. For example, 
under part 1090, if a party only blended 15 volume percent ethanol 
into a BOB that was specified for blending up to 10 volume percent 
ethanol, the blender would not submit reports.
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6. Proposed Reporting for Oxygenate Producers and Importers
    We are proposing that oxygenate producers and importers must 
continue under part 1090 to submit batch reports providing information 
about the oxygenate they produce or import as already required under 
part 80. Reporting for oxygenate producers would be on a compliance-
level (e.g., facility) basis. The information to be submitted includes 
information about the oxygenate produced or imported, including the 
sulfur content of the batch and the test method used. For denatured 
ethanol, the report would specify whether the denaturant is certified 
ethanol denaturant or non-certified. The information contained in these 
reports does not differ from current part 80 reporting requirements, 
but the proposed regulation is designed to standardize the type and 
format of the information submitted.
7. Proposed Reporting for Certified Pentane Producers and Importers
    We are proposing that certified pentane producers and importers 
submit batch reports that provide information about the certified 
pentane produced or imported, including the pentane, sulfur, and 
benzene content of each batch and the test methods used. The 
information contained in these reports does not differ from current 
part 80 reporting requirements, but the proposed regulation is designed 
to standardize the type and format of the information submitted.
8. Proposed Reporting by Diesel Manufacturers
    We are proposing limited batch reporting for manufacturers of 
diesel fuel. Specifically, we are proposing that manufacturers of 
diesel fuel (excluding 500 LM from transmix) that test any batch found 
to exceed the applicable 15 ppm sulfur standard would report 
information about that batch. Batches that do not exceed the applicable 
15 ppm sulfur standard would not be reported to EPA. The specific 
information proposed to be reported includes the company and facility 
identifier, the batch identifier, and the tested sulfur content in ppm, 
and test method used. Since diesel manufacturers are required to test 
their product for sulfur content and must retain information related to 
sampling and test results already, we believe the burden of reporting a 
relatively small number of batches found to exceed the applicable 15 
ppm is small. We acknowledge that diesel sulfur batch reporting under 
40 CFR part 80, subpart I, generally ended on September 1, 2014; 
however, the requirement to test and retain records related to sulfur 
content continues. We are proposing limited batch reporting because we 
believe it will assist us in our compliance oversight efforts and in 
ensuring that the human health and environmental benefits of the 
program are realized.
    We also collect some information about diesel sulfur via the annual 
fuel manufacturer reports, required under part 79. The existing reports 
are limited in their contemporary value for several reasons. First, 
they require only information about highway diesel fuel and do not 
include NRLM diesel fuel. Second, they require information on a 
manufacturer level, rather than on a facility/refinery level and, 
therefore, are of limited use for compliance purposes. Third, the high/
low/average sulfur values are collected as a volume percentage rather 
than in ppm, a throwback to the 1970s when diesel sulfur levels were 
not regulated and sulfur content was much higher. Our purpose in 
collecting this information at that time was to understand, on a high 
level, the general characteristics of fuel that may affect human health 
and the environment and to determine whether future regulation might be 
needed. The part 79 reports have historically collected the information 
to the extent known by the manufacturer. Although manufacturers of 
diesel fuel have been submitting the information, it is submitted in an 
inconsistent format. For example, we typically receive values expressed 
in ppm already, as the use of volume percent is no longer the preferred 
method.
    We are proposing to transition diesel sulfur reporting from part 79 
and move it entirely into part 1090 reporting forms. This transition 
includes reporting total volume and max/average sulfur results (using 
ppm as the unit of measure) by company ID and five-digit reporting ID 
(i.e., facility ID).
9. Reports by Independent Surveyors
    As previously discussed, we are proposing to remove the requirement 
for registration and submission of reports by independent laboratories 
and also proposing a requirement for registration and reporting by 
independent surveyors. The proposed registration requirement for 
independent surveyors are discussed in greater detail in Section 
X.A.2.d. For reporting purposes, an independent surveyor must submit 
plans, notifications, and quarterly survey reports to EPA 
electronically. The quarterly reports include information about retail 
outlets visited by the independent surveyor and the characteristics of 
the fuels samples and tested (e.g., oxygenate type and amount, sulfur 
content, benzene content, etc.). Independent surveyors would also have 
an annual reporting requirement that addresses summary statistics and 
describes compliance rates and non-compliance issues. For the proposed 
national survey program, this type of information is already collected 
as part of the part 80 survey programs. Information collected under the 
proposed national sampling oversight program is like information 
already collected under the RFG independent laboratory testing program 
under part 80.
10. Deadlines for Reporting
    We are proposing that the annual reports by independent surveyors 
must be submitted by March 31. We are retaining the existing deadlines 
for reports under part 80 for reports submitted under part 1090. 
Specifically:
     Annual compliance reports for sulfur and benzene would 
continue to be submitted by March 31 for the preceding compliance 
period (e.g., reports covering the calendar year 2021 must be submitted 
to EPA by March 31, 2022).

[[Page 29065]]

     Batch reports would be submitted by March 31 for the 
preceding compliance period. This was previously the fourth quarter 
batch reporting due date. We are proposing to reduce the frequency of 
batch reporting that currently applies under part 80, going from 
quarterly to annually.
     Attest engagements would continue to be submitted by the 
independent auditor by June 1 for the preceding compliance period.
     Reports by independent surveyors would continue to be 
submitted quarterly on June 1 (covering January 1-March 31), September 
1 (covering April 1-June 30), December 1 (covering July 1-September 
30), and March 31 (covering October 1-December 31). Annual reports by 
independent surveyors must be submitted by March 31.
11. Proposed Reporting Forms
    Proposed reporting formats are discussed in more detail in the 
technical memorandum covering batch reporting, available in the docket 
for this action, and in the ICR. The ICR includes actual proposed 
reporting instructions. Interested parties are urged to review these 
materials and provide feedback.
    The information collected in the proposed reports should be 
familiar to existing registered and reporting parties. We have designed 
part 1090 and the proposed reports to address areas where reporting 
requirements were previously unclear or cumbersome and to reduce the 
existing reporting burden.

D. Product Transfer Documents (PTDs)

    The general purpose and requirements for PTDs do not differ from 
the existing requirements in part 80. PTDs are documents generated in 
the normal course of business that provided a clear description of the 
product being transferred. Under part 1090, PTDs would still be 
required each time a person transfers title or custody to a product 
regulated under part 1090. The typical format of PTDs is not changed by 
this action--basic information including identification of the 
transferor/transferee, location of the transfer, volume and type of 
product, etc. remain familiar. As with existing part 80, commonly 
understood codes may be used by ``upstream parties'' and where a 
transfer is made to those other than truck carriers, retailers, or 
wholesale purchaser-consumers (WPCs). Transfers to truck carriers, 
retailers, or WPCs would require the specified, printed statement and 
product information rather than a code. As with existing part 80, PTDs 
would have to be kept by each transferor and transferee.
    Part 1090 mostly consolidates the various PTD language requirements 
throughout part 80 into a single, consistent section to help bring 
uniformity to the PTD language across fuels, fuel additives, and 
regulated parties. This action would remove PTD language that is no 
longer needed and provide standard, updated language to address a 
variety of common products and situations. We are, however, proposing 
some minor modifications from the existing part 80 requirements.
    We are proposing language to identify fuel covered by all known, 
specific exemptions (e.g., R&D exemption, racing fuel exemption, etc.) 
in a more consistent manner. Part 80 only requires that exempt fuels be 
identified on PTDs as exempt and is inconsistent with its language 
requirements across the various part 80 fuel quality programs. We 
intend to make our PTD requirements more consistent so we are proposing 
a more prescriptive format for exempt fuels.
    Under some programs in part 80, we have allowed parties to petition 
for alternative PTD language for some PTD requirements, but not for 
other PTD requirements. During the rule development process, several 
stakeholders highlighted that instances exist where our PTD 
requirements may conflict with other federal, state, or local PTD or 
identification requirements. In such cases, fuels, fuel additives, or 
regulated blendstocks could be identified with contradictory language 
that makes it difficult for parties in the fuel distribution system to 
comply with all applicable federal, state, and local requirements. To 
address these potential issues, we are also proposing to allow parties 
to seek approval for alternative PTD language for all proposed PTD 
language requirements. Based on experience implementing part 80, we do 
not anticipate that many parties will request alternative PTD language.

E. Recordkeeping

    We are maintaining the record retention requirements in part 80. 
All parties that keep records under part 80 would continue to keep the 
same or similar records under part 1090. Records that must be 
maintained are those already familiar to regulated parties, including: 
Information that supports the registration and reports submitted to 
EPA, information related to waivers (such as R&D programs), copies of 
PTDs, sampling and test results and related laboratory documents, 
information about credit transactions for sulfur and benzene, and 
information related to compliance calculations. We anticipate that the 
number of records retained will decrease under part 1090, in large part 
because the number of sampled, tested, and reported parameters for 
gasoline and certain regulated blendstocks would decrease.

F. Rounding

    The standards and compliance requirements under part 1090 require 
extensive use of numbers to quantify fuel parameters and fuel volumes, 
along with numerous occasions to calculate new quantities to properly 
document compliance. A rigorous compliance demonstration depends on 
properly managing precision and significant figures in recorded values 
and calculations. Part 80 addresses rounding and precision by simply 
instructing regulated parties to round test results to the nearest unit 
of significant digits specified in the applicable fuel standard as 
described in ASTM E29. We are proposing a much broader and consistent 
approach in part 1090. We codified a standard approach to rounding in 
40 CFR 1065.20 that is consistent with ASTM E29. We are proposing to 
apply this rounding protocol to all recorded values under part 1090.
    The action includes additional specifications for calculating and 
recording numerical values. First, we are proposing to specify that 
rounding intermediate values in a calculation is not appropriate. This 
principle is intended to preserve the accuracy and precision until the 
calculations reach a final result, at which point the final result can 
be rounded to the appropriate number of decimal places or significant 
figures. We recognize that intermediate values must sometimes be 
transcribed (such as from an analyzer to a spreadsheet), which cannot 
be done with infinite precision. We are therefore proposing that 
intermediate values should be recorded and used with full precision, 
except that rounding is permissible if the value retains at least six 
significant digits. This is not a proposal to require six significant 
digits for all recorded values. Rather, if an intermediate quantity 
with more than six significant digits needs to be transcribed, parties 
may use the specified rounding protocol to eliminate the additional 
digits. Also note that we generally allow for using measurement devices 
that incorporate proper internal rounding protocols to report test 
results.
    Second, multiplying a value by a percentage must keep the precision 
of the original value. This is equivalent to considering the specified 
percentage to be infinitely precise. For example, calculating 1 percent 
or 1.0 percent of 1,234 would result in a value of 12.34.

[[Page 29066]]

This is relevant for calculating an averaging standard for benzene. 
Fuel volume is multiplied by exactly 0.62 percent, rather than using a 
value of 0.624 (which rounds down to 0.62) before multiplying by fuel 
volume.

G. Certification and Designation of Batches

    The certification and designation of batches of fuels, fuel 
additives, and regulated blendstocks are crucial elements to ensuring 
that fuels, fuel additives, and regulated blendstocks meet our fuel 
quality standards and aid in the distribution of such products. 
Certification is the process where a manufacturer or producer 
demonstrates that their product meets EPA's standards. Designation is 
the identification of a batch (typically on PTDs) as meeting specific 
requirements for a category of fuel (e.g., summer RFG), fuel additive 
(e.g., diesel fuel additives), or regulated blendstocks (e.g., 
certified butane or certified pentane). Parties throughout the fuel 
distribution system rely on designations to appropriately transport, 
store, dispense, and sell fuels. Part 80 generally has provisions for 
certification and designation of products separately for each program. 
Part 1090 consolidates these various certification and designation 
procedures into a single set of provisions.
    Regarding certification, most of the certification procedures for 
fuels, fuel additives, and regulated blendstocks for part 80 are 
outlined in guidance. We are proposing in part 1090 to incorporate such 
guidance into the regulations and establishes a clear process to 
certify batches. The proposed regulations include the following four 
steps:
     Registration prior to the production of fuel, fuel 
additive, or regulated blendstock (if required).
     Sampling and testing the fuel, fuel additive, or regulated 
blendstock to demonstrate that the product meets applicable quality 
standards.
     Assignment of a batch identification number (if required).
     Designation of the batch as appropriate.
    We believe these four steps are consistent with how parties 
currently certify products under part 80. These requirements satisfy 
CAA section 211(k)(4) describing certification procedures for RFG.
    Regarding designation, for gasoline and gasoline-related additives 
and regulated blendstocks, we are proposing to substantially modify the 
designation requirements for these products. Most of these proposed 
changes reflect the removal of the Complex Model for use in the 
certification of batches of RFG and the harmonization of the RFG and CG 
programs. Many of the prior designations to segregate RFG and CG are no 
longer necessary, so we are proposing to remove those designations. 
Additionally, we are proposing more flexible redesignation provisions 
for distributors of gasoline. These proposed provisions largely reflect 
the proposed streamlining of the RFG program and the more fungible 
nature that would result.
    Distributors of gasoline would be allowed to redesignate winter 
RFG/RBOB to winter CG/CBOB (and vice versa) and summer gasoline from a 
more stringent RVP standard to a less stringent RVP standard without 
recertification (e.g., from summer RFG meeting the 7.4 psi RVP standard 
to 9.0 psi RVP summer CG). Any person that mixes summer gasoline with 
summer or winter gasoline that has a different RVP designation must 
either designate the resulting mixture as meeting the least stringent 
RVP designation of any batch in the blend or determine the RVP of the 
mixture and designate the new batch accurately to reflect the RVP of 
the gasoline as described under this section. When transitioning from 
winter to summer gasoline, parties are not required to test the RVP but 
must exercise good engineering judgement to assure that the gasoline 
meets the applicable RVP standard.
    We are also making it clear that parties can redesignate California 
gasoline that meets CARB standards without recertification, as 
explained in more detail in Section VI.A. We believe these 
flexibilities will help maximize the fungibility of gasoline.
    For diesel fuel, diesel additives, and diesel regulated 
blendstocks, we are largely proposing to maintain the part 80 
designation requirements. We are, however, proposing two notable 
changes. First, we are proposing a more flexible designation scheme for 
distillate fuels certified to meet ULSD standards. The intent of the 
proposed regulations is to ensure that fuels that meet the ULSD 
standards could be designated as necessary to be used as home heating 
oil, motor vehicle, nonroad, locomotive, or marine diesel fuel (defined 
as MVNLRM diesel fuel in part 80), or IMO marine fuel. This change 
would allow parties to make sure that fuels are designated 
appropriately throughout the distribution system.\92\ Second, similarly 
to gasoline, we are proposing to allow parties to redesignate 
California diesel fuel that meets the ULSD standards without 
recertification. We believe the proposed designation changes for diesel 
fuel would help maximize the fungibility of distillate fuels that meet 
the ULSD standards.
---------------------------------------------------------------------------

    \92\ This action does not address how these fuels are accounted 
for inclusion in obligated parties' RVO calculations under the RFS 
program. We recently finalized changes to part 80 to account for the 
redesignation of distillate fuels meeting the ULSD standards (see 85 
FR 7054-7057, February 6, 2020).
---------------------------------------------------------------------------

    We seek comment on the proposed certification and designation 
provisions.

IX. Sampling, Testing, and Retention Requirements

    Our fuel quality programs consists of performance standards and 
compliance provisions that require measurement of various fuel 
parameters. These measurements in turn rely on specified procedures 
contained in part 80. We are transferring these same test procedures 
from part 80 into part 1090. We are also reorganizing the testing 
provisions in part 1090 and proposing several clarifications to reflect 
current best practices. We are further consolidating test procedures 
for gasoline and diesel fuel in some cases. This section highlights the 
proposed changes relative to what currently applies under part 80.\93\
---------------------------------------------------------------------------

    \93\ The updated procedures are described in greater detail in 
the technical memorandum, ``Technical Issues Related to Streamlining 
Measurement Procedures for 40 CFR part 1090,'' available in the 
docket for this action.
---------------------------------------------------------------------------

A. Overview and Scope of Testing

    Part 80 requires gasoline manufacturers to measure 11 complex model 
parameters. This action would significantly reduce the number of 
parameters that gasoline manufacturers must measure for determining 
compliance with the fuel standards. Part 1090 would require fuel 
manufacturers to measure the sulfur and benzene content of every batch 
of gasoline and to measure the RVP of every batch of summer gasoline. 
Fuel manufacturers will also be required to sample and test for 
oxygenates in specific situations when EPA believes it could be 
difficult for the fuel manufacturer to assure compliance with oxygenate 
standards without sampling and testing the gasoline. For gasoline 
produced at a blending manufacturing facility or a transmix processing 
facility, we are retaining the part 80 requirement to test gasoline for 
distillation parameters. The distillation testing provides a 
distillation curve that shows how much of the gasoline has flashed off 
as the temperature of the sample is increased. This curve can provide 
some confirmation that the blended product has a distillation profile 
that is generally

[[Page 29067]]

consistent with gasoline meeting the substantially similar requirements 
of the CAA. The results of the distillation testing would not be 
required to be reported, but instead would be retained at the facility 
to provide additional data that can be reviewed in the event of 
complaints about potential compliance or performance issues. We 
understand that distillation parameters are effectively a condition of 
merchantability of gasoline in the U.S., so such testing is already 
being performed by fuel manufacturers.
    Part 80 requires RFG refiners to obtain test results for all 
parameters required to determine compliance. Part 80 also requires CG 
refiners to measure sulfur content in gasoline and diesel fuel prior to 
introduction into commerce. Requiring measurement before shipping from 
the refinery provides assurance of compliance prior to the fuel being 
mixed and commingled in the fungible distribution system and 
potentially even consumed. Unlike many regulatory situations where it 
is possible to go back after the fact and correct the noncompliance, 
this is difficult if not impossible in most situations for fuel once it 
has left the fuel manufacturing facility. Consistent with part 80, we 
are proposing to require all gasoline manufacturers to obtain test 
results for sulfur and RVP (during the summer months) before shipping 
gasoline from the fuel manufacturing facility. Part 80 requires RFG 
refiners to obtain test results for benzene before shipping gasoline, 
but does not require CG refiners to obtain these results before 
shipping from the refinery. We are not proposing to require gasoline 
manufacturers to test for benzene before shipping gasoline from the 
fuel manufacturing facility, but we are seeking comment on whether this 
would be appropriate. Some fuel manufacturers have suggested that being 
able to test after shipping product from the fuel manufacturing 
facility would make the testing substantially less burdensome. Taking 
time to perform testing and verify results can cause delays in managing 
the flow of producing and shipping product. We are not revising fuel 
requirements that impose the obligation to test fuels before shipping 
from the fuel manufacturing facility. With the simplified test 
requirements of the streamlined program, we believe there is no 
justification to avoid the compliance-assurance advantage of individual 
batch measurements whenever that is possible. However, we seek comment 
on this and what provisions could be put in place in its absence to 
provide assurance that the fuel met the standards in the absence of 
testing. For example, we could require fuel manufacturers to keep 
records documenting their engineering assessment that supports a 
conclusion that the fuel meets applicable standards despite the absence 
of test results. Such an assessment would need to account for varying 
refinery processes, maintenance or other system changes, personnel 
changes, source and quality of any blending components, and any other 
relevant variables.
    We are maintaining exceptions to testing under current waivers that 
do not require measurement of fuel properties prior to shipment. 
Currently 40 CFR 80.65, 80.581, and 80.1630 describe separate programs 
for in-line blending configurations to qualify for a waiver from the 
test-before-ship requirements as part of an approved process with 
annual quality audits. We are transferring these existing provisions 
that allow for the in-line blending waiver only for shipment 
configurations because they do not allow for conventional batch 
testing. For example, sending finished fuel directly into a pipeline or 
a marine vessel generally does not allow for conventional batch 
measurement, so we expect refiners to continue to rely on the in-line 
blending waiver for these shipping arrangements. Refiners are similarly 
prevented from timely batch measurements if they create fuel batches 
that are greater than they can contain in a single storage tank. We are 
therefore transferring these existing part 80 waiver provisions for in-
line blending also to operations that involve these over-sized batches 
to part 1090. The transferred provisions, when effective, would mean 
that the restricted application of the in-line blending waiver does not 
prevent refiners from using automated in-line sampling procedures as 
described in ASTM D4177 for measuring fuel parameters for a given 
batch.

B. Handling and Testing Samples

1. Collecting and Preparing Samples for Testing
    Accurate test results are dependent on the sample being 
representative of the fuel batch. We are transferring the sampling 
procedures and demonstrating homogeneity of fuel samples that are 
currently specified in 40 CFR 80.8. This provision generally specifies 
procedures for manual sampling as described in ASTM D4057 or automated 
in-line sampling as described in ASTM D4177. The additional procedures 
for sampling related to gasoline RVP as described in ASTM D5842 are 
also being transferred to part 1090.
    Some of the current regulations in part 80 related to sample 
collection, however, do not adequately address sampling procedures 
because they do not provide the necessary specifications for testing. 
We have addressed some of those omissions through guidance documents 
published over the years.\94\ We are also proposing to add numerous 
minor clarifications and adjustments to the regulatory text to reflect 
current best sampling practices.
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    \94\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

2. Sample Preparation for BOB Testing
    Section VII describes the proposed new approach for oxygenate 
accounting for gasoline that would allow parties that either produce or 
import BOB and instruct downstream blenders to add oxygenates to meet 
sampling requirements by blending oxygenates into a BOB sample to 
represent the final blended fuel--a ``hand blend.'' \95\ This would 
involve preparing each fuel sample by adding oxygenates to the BOB 
sample in a way that corresponds to instructions to downstream blenders 
for the sampled batch of fuel.
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    \95\ The regulations at 40 CFR 80.69 and 80.101 practically 
limits this practice to RBOB. As discussed in Section VII, we are 
proposing to make it more practical for all fuel manufacturers of 
BOB to account for the addition of oxygenate added downstream. Part 
80 does not currently specify preparation procedures for hand 
blends.
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    Preparing the hand blend sample involves decisions about which 
samples to use for blending. For example, three tested BOB samples may 
be available to prepare the hand blend. Also, a single hand blend might 
represent different types and amounts of oxygenate, as reflected in the 
blending instructions for downstream parties. We are proposing to 
address these examples of discretion in the specified procedures by 
requiring that the hand blend represent a worst-case test condition. In 
the case of sulfur measurements from multiple samples to represent a 
batch of BOB, this requires further testing with the sample that has 
the highest sulfur measurement.
    Winter gasoline would need to be blended with the lowest specified 
percentage of any oxygenate type given in the instructions for 
downstream blending. For example, if blending instructions specify an 8 
percent isobutanol blend in addition to E10 and E15, the hand blend 
would need to be an 8 percent isobutanol blend. This reflects the fact 
that dilution is the primary effect of blending on fuel parameters 
other than RVP. A different

[[Page 29068]]

approach is necessary to properly select the type and amount of 
oxygenate for hand blending in summer gasoline. Under this proposal, 
summer gasoline would need to be blended with the lowest specified 
percentage of ethanol given in the instructions for downstream blending 
(i.e., blend for E10 if the instructions identify E10 and E15 for 
downstream blending, even if the blending instructions include an 
option to blend with a lower percentage of a different oxygenate).
3. Sample Retention
    Part 80 currently describes sample-retention requirements in 
multiple provisions. Stakeholders have pointed out that there is 
ambiguity about whether the regulation requires sample retention for 30 
or 90 days. We are proposing to require all fuel manufacturers to keep 
fuel samples used to demonstrate compliance with all applicable 
standards for 30 days, except for blending manufacturers.
    A longer retention time applies for blending manufacturers since 
these manufacturers typically have less control over the quality of the 
blendstocks they use to produce gasoline, which can cause decreased 
fuel quality without robust controls. Crude refineries typically 
distribute fuels through a distribution network with multiple levels of 
control to ensure fuel quality (e.g., through pipelines that have 
strict product specifications prior to injection) while blending 
manufacturers can make fuels on a more ad hoc basis (e.g., in a tanker 
truck). We therefore believe it is appropriate to require a longer 
retention period to help trace potential issues with fuel quality. We 
are proposing a minimum retention period of 120 days for fuel samples 
that blending manufacturers use for testing to demonstrate compliance 
with gasoline or diesel fuel standards.
    For testing BOB and hand blended samples of oxygenated gasoline as 
described in Section IX.C, the sample-retention requirements apply for 
both the BOB sample and the hand-blended sample used to demonstrate 
compliance. Gasoline manufacturers producing BOB have expressed a 
concern that space limitations would make it difficult to store both 
the BOB sample and the hand-blended sample used to demonstrate 
compliance. We are therefore proposing that gasoline manufacturers do 
not need to keep each hand-blended sample; they would instead need to 
keep a DFE sample to allow them to create new hand-blended samples 
corresponding to each BOB sample. With this approach, a single DFE 
sample might be available for blending with multiple BOB samples.

C. Measurement Procedures

    Demonstrating compliance with fuel quality standards requires a 
wide range of measurement procedures. Our fuel quality regulations rely 
heavily on standardized test methods published by voluntary consensus 
standards bodies such as ASTM International. As described below, the 
proposed regulations in part 1090 reference certain measurement 
procedures, in most cases with provisions allowing for using 
alternative procedures, including updated versions of referenced 
procedures in some instances.
1. Procedures for Gasoline Surveys
    Testing for gasoline surveys is intended to provide a consistent 
indication of in-use fuel parameters over time. Testing will generally 
be performed by a selected set of test labs to represent the range of 
fuels in distribution over time.
    We are proposing to require that survey measurements rely on the 
referee procedures identified under PBMS, where applicable. The 
following procedures apply for additional parameters:

 ASTM D5769 for aromatic content
 ASTM D6550 for olefin content
 ASTM D86 for T50 and T90 distillation points

    We request comment on the specified procedures for measuring the 
various fuel parameters for surveys.
2. Procedures To Determine Cetane Index for Diesel Fuel
    Part 80 and the Clean Air Act establishes a cetane index standard 
at or above 40 for diesel fuel used with motor vehicles and nonroad 
equipment. (See 40 CFR 80.520(a)(2)). Part 80 also references ASTM D976 
as the procedure for determining cetane index in diesel fuel. During 
the development of this action, industry stakeholders advocated for 
ASTM D4737 as a more robust method that relies on additional fuel 
parameters for calculating cetane index. In response to stakeholder 
request, we are proposing that either of the referenced ASTM procedures 
are acceptable for determining cetane index.
    Both of the referenced ASTM procedures are valid for the full range 
of distillate fuels qualifying as diesel fuel. However, these 
procedures rely on fuel characteristics for distillate fuel and they 
are therefore not appropriate for biodiesel. The chemical make-up of 
pure biodiesel causes it to inherently have higher cetane values and no 
aromatic content. With no suitable measurement procedure for cetane 
index in biodiesel, and no concern that biodiesel will fail to meet the 
cetane index standard or have greater than 35 percent aromatics, we are 
proposing to exempt biodiesel from testing to verify compliance with 
the cetane index or aromatic content requirement for diesel fuel.
    Additionally, EPA is aware of industry efforts aimed at developing 
new test methods for determining cetane index and similar parameters 
related to cetane number. We request comment on incorporating new 
measurement procedures into part 1090 as an alternative means of 
demonstrating compliance with the cetane index standard. In particular, 
we request comment on quantitative correlations between the new 
procedures with the existing procedures used to determine cetane index. 
Where appropriate, these comments should address whether such 
quantitative correlations depend on fuel formulations of properties 
that may be more or less prevalent than in the past.
3. Performance-Based Measurement System
    EPA adopted the Performance-Based Measurement System (PBMS) that 
establishes objective criteria for qualifying laboratories and 
measurement procedures (see Sec. Sec.  80.46 and 80.47). Our fuel 
quality regulations specify referee test methods for several fuel 
parameters and define precision and accuracy criteria so laboratories 
can demonstrate that they qualify their equipment for using the referee 
procedure, or for using alternative procedures. Precision and accuracy 
criteria apply for initial qualification, and for ongoing quality 
checks.
    Part 80 includes a specified date for laboratories to omit initial 
qualification testing if they have been using the specified referee 
procedure for a given parameter. We are proposing to broaden this 
approach in part 1090 by allowing laboratories to omit initial 
qualification testing if they are using the specified referee test 
procedure. This approach treats all laboratories the same. Since the 
ongoing quality checks apply for laboratories using these procedures, 
the laboratories will still be demonstrating that they are properly 
performing these measurement procedures.
a. Scope
    We have received questions on the applicability of PBMS 
requirements beyond the predominant scenario of testing fuel at a 
refinery. The PBMS provisions for measuring specified fuel parameters 
apply to all parties and at all

[[Page 29069]]

points in the fuel distribution system. PBMS provisions also apply for 
batch testing for compliance, and for quality audits such as what is 
required for in-line blending waivers, for test waivers for truck and 
rail imports, and for blending certified butane and pentane into PCG. 
Any other approach would be inconsistent with PBMS and would create an 
unlevel playing field for different market participants.
b. Referee Procedures
    We are transferring the same referee procedures for part 1090 that 
currently apply under part 80, subject to the following proposed 
exceptions and clarifications.
    First, we are proposing to change the designated referee procedure 
for measuring benzene in gasoline from ASTM D3606 to ASTM D5769. We 
believe ASTM D5769 is as a superior procedure because measurements 
involve little or no interference from ethanol blended into gasoline. 
In contrast, ASTM D3606 has interference effects from ethanol that 
require careful work to adjust for that interference. Since ASTM D3606 
is the referee procedure for measuring benzene in gasoline under part 
80, we are proposing to waive requirements to initially qualify testing 
with ASTM D3606 as an alternative procedure. We believe the ongoing 
PBMS quality demonstrations are sufficient to demonstrate proper 
precision and accuracy using ASTM D3606.
    Second, we are proposing to remove measurement of aromatic content 
in diesel fuel from the PBMS protocol. We are not proposing to require 
aromatic testing for every batch of diesel fuel. As a result, we 
believe the PBMS protocols for referee procedures, qualifying 
alternative procedures, and ongoing quality testing are no longer 
appropriate. We are instead proposing to simply specify that ASTM D1319 
and ASTM D5186 are acceptable procedures for measuring aromatic content 
in diesel fuel and allowing for alternative procedures that correlate 
with either of these specified procedures.
    Part 80 specifies ASTM D6667 as the referee procedure for measuring 
sulfur in butane. We are proposing to specify the same referee 
procedure (and precision and accuracy criteria) for measuring sulfur in 
pentane.
    We have also received questions on the applicability of PBMS to 
oxygenates used in gasoline. We have always intended for the PBMS 
requirements to apply for testing oxygenates in the same way that test 
requirements apply for testing gasoline. Accordingly, we are clarifying 
in part 1090 that oxygenates, including denatured fuel ethanol, are 
subject to PBMS requirements for all testing under part 1090 in the 
same way that these requirements apply for testing gasoline. This 
includes the protocol for qualifying alternative test procedures and 
the requirements for ongoing quality testing.
c. Updated Versions of Referenced Procedures
    Part 80 currently references specific published versions of the 
various test procedures for measuring fuel parameters. These specific 
references do not automatically change with periodic updates to those 
procedures from the publishing organization, which makes it difficult 
for us to keep the regulations current as the industry continues to 
improve measurement procedures. To maintain the integrity of the PBMS 
protocol while allowing for the regulations to remain current with 
evolving industry practices, we are proposing that laboratories may use 
updated versions of referee procedures or qualified alternative 
procedures without our prior approval, as long as the updated version 
has published repeatability and/or reproducibility that is the same as 
or better than the version referenced in part 1090.
    A similar approach applies for using an updated method of a referee 
procedure to qualify alternative procedures. Laboratories wanting to do 
this must first get our approval. We would expect to approve such 
requests based on a demonstration that the repeatability and 
reproducibility are the same as or better than the referenced 
procedure, but we are proposing to establish EPA's approval role to the 
extent the updated version of the referee procedure is used to qualify 
new alternative procedures. This interaction will also help us identify 
instances where we should consider updating the regulation to rely on 
the latest available procedures.
d. Criteria and Methods for Qualifying Procedures
    The precision and accuracy criteria from part 80 are migrating to 
part 1090 with two exceptions. First, we are proposing to specify 
precision and accuracy criteria based on the most recently published 
repeatability values from ASTM D2622 for measuring sulfur in 500 ppm LM 
diesel fuel and ECA marine fuel. Second, we are proposing to specify 
precision and accuracy criteria for gasoline benzene based on the most 
recently published reproducibility values from ASTM D5769 instead of 
ASTM D3606. The published reproducibility for ASTM D5769 is slightly 
higher than for ASTM D3606, which means that it allows for a slightly 
more accommodating approach for qualifying alternative procedures.
    We are proposing to transfer part 80 requirements for calculating 
precision and accuracy criteria for diesel sulfur based on calculated 
values for sulfur concentrations at fixed values to represent 
compliance at the standard. This would allow for a fixed criterion for 
testing all fuel samples. Selecting a test fuel with very low sulfur 
would not be meaningful, since it is not reasonable to compare such 
small quantities of measured sulfur to precision and accuracy criteria 
that are keyed to the standard. As a result, we are simply transferring 
the same specified minimum sulfur values for measuring sulfur in all 
the different types of diesel fuel. This becomes problematic for 
measuring sulfur in neat biodiesel, since it has inherently low sulfur 
concentrations. We would expect testing to qualify methods or to 
perform ongoing quality checks with neat biodiesel to include doping 
the fuel with enough diesel fuel to meet the minimum sulfur 
specification.
    We are proposing to specify that precision and accuracy criteria 
for all fuel parameters other than sulfur are to be determined based on 
the actual value of the tested fuel. For example, for precision testing 
to qualify an alternative method, this would be based on an average 
value from the 20 tests (or more) used to evaluate precision.
    We are also proposing that the between-methods-repeatability, 
Rxy, for qualifying alternative procedures for method-
defined parameters using non-VCSB methods must be at or below 75 
percent of the reproducibility of the designated referee procedure. 
This is an increase from the 70 percent value specified in 40 CFR 
80.47. The increase in the specified value for the Rxy 
criterion is based on the observation that it may be mathematically 
impossible to achieve a 30 percent improvement over the repeatability 
of the designated referee procedure. We are not aware of anyone seeking 
to use a non-VCSB method for fuel-defined procedures, but we want to 
continue to allow this to be a viable option. We request comment on the 
appropriateness of the proposed value of 75 percent for the 
Rxy criterion.
e. Ongoing Testing for Statistical Quality Control
    We are further transferring the statistical quality control 
procedures established under 40 CFR 80.47 to part 1090. However, by 
rewriting these

[[Page 29070]]

procedures in their own section, the proposed provisions may clarify 
some points that were previously subject to differing interpretations. 
We request comment on the proposed rewrite of the statistical quality 
control procedures.

X. Proposed Third-Party Survey Provisions

    Third-party verification plays an important role in overseeing 
compliance with our fuel quality programs under the existing part 80. 
One key element to our existing third-party oversight regime are in-use 
retail level surveys. An advantage of retail survey programs is that 
they target fuel quality at the point the fuel is dispensed from a 
retail outlet. Under part 80, we have four in-use survey programs that 
primarily focus on RFG and RFG areas, ethanol content, E15 labeling, 
and ULSD sulfur levels, which are tracked nationally. For the most 
part, however, we have little or no other retail level information 
under part 80 for CG, which constitutes about 70 percent of the 
national gasoline fuel pool. We are proposing a national survey program 
in part 1090 that would consolidate the four programs into a single 
national survey in-use retail program, thereby reducing costs, while at 
the same time expanding the benefits of the survey program nationwide. 
When finalized, the part 1090 survey would build upon the existing in-
use survey provisions, leveraging independent third-parties to a 
greater extent to ensure that compliant fuels are used in vehicles and 
engines in exchange for allowing fuel manufacturers greater flexibility 
to account for oxygenates added downstream in their annual compliance 
demonstrations,\96\ and reducing the number of fuel parameters that 
fuel manufacturers need to be test and report.
---------------------------------------------------------------------------

    \96\ See Section VII.F.
---------------------------------------------------------------------------

    Part 1090 includes two survey programs: a national survey program 
of retail outlets that offer gasoline and diesel to ensure that in-use 
standards are met, and a voluntary national sampling and testing 
oversight program that is intended to help ensure that gasoline 
manufacturers collect samples for testing in a consistent manner for 
purposes of compliance with applicable standards and thus, maintain the 
integrity of our fuel quality program. This section discusses both 
proposed programs in detail.

A. National Survey Program

    As previously explained, we are proposing provisions for a 
nationwide survey of in-use gasoline and diesel fuel that is intended 
to ensure that gasoline and diesel fuel meet our applicable fuel 
quality standards when dispensed into gasoline- and diesel-fueled 
engines. We have used survey programs to great effect under the 
existing part 80 regulations. Table X.A-1 outlines the four survey 
programs currently in part 80 and describes the geographic scope, 
parties that participate in the survey program, and the estimated 
sample size.

                                Table X.A-1--Existing Survey Programs in Part 80
----------------------------------------------------------------------------------------------------------------
                                                                                                      Minimum
             Program               Regulation citation    Geographic scope     Who participates       sample
----------------------------------------------------------------------------------------------------------------
RFG Survey.......................  Sec.   80.68.......  RFG Areas..........  RFG Refiners.......           4,500
RFG Ethanol Survey...............  Sec.   80.69(a)(11)  RFG Areas..........  RFG Refiners.......           4,500
ULSD Survey......................  Sec.   80.613(e)...  Nationwide, on-      Anyone.............           1,800
                                                         highway diesel
                                                         stations.
E15 Survey.......................  Sec.   80.1502.....  Nationwide gasoline  E15 fuel and fuel             7,500
                                                         stations.            additive
                                                                              manufacturers.
----------------------------------------------------------------------------------------------------------------

1. Background
    We have historically used survey programs to provide flexibilities 
in fuel quality programs that we administer, which allows regulated 
parties to more efficiently meet our fuel quality standards. For 
example, we provided RFG refiners with the option of complying with RFG 
requirements on an average basis by demonstrating that RFG meets the 
applicable in-use oxygen content and NOX, toxics, and 
summertime VOC performance at retail stations. By being able to rely on 
an in-use survey at the retail level to verify overall compliance, the 
regulations thus allow RFG refiners considerable flexibility in their 
day-to-day operations to produce fuel at the lowest cost. The norm for 
over 20 years has thus been that RFG refiners and importers produce a 
sub-octane, oxygenate-free RBOB that is distributed throughout the 
distribution system to which ethanol is added at downstream terminals. 
The retail survey then allows for verification that the RFG standards 
are met in-use. Since most RFG areas are supplied by multiple refiners, 
we allowed RFG refiners and importers to consolidate resources to 
establish a survey to demonstrate that RFG standards were met for RFG 
areas on average.
    Additionally, in order to discourage misfueling of vehicles and 
engines, we have historically imposed pump labeling requirements at the 
retail level. In order to provide oversight of the thousands of retail 
stations, we also currently have provisions for a retail outlet survey 
to ensure that fuel dispensers are labeled appropriately (e.g., E15 
programs). A statistically representative sample of retail outlet fuel 
dispensers gathered through a survey helps inform responsible parties 
and EPA whether labeling requirements are being met without having to 
impose direct costs on the retail outlet to demonstrate compliance.
    The focus of much of our current compliance oversight has been on 
parties that manufacture fuels at crude refineries with provisions that 
then attempt to ensure that the fuel quality as measured at the crude 
refinery is maintained all the way to retail. What happens at the crude 
refinery has historically been and continues to be the greatest factor 
as to whether a fuel is ultimately compliant. However, as the 
transportation fuel market has continued to evolve and parties at all 
locations downstream of refineries (e.g., pipeline, terminal, retail) 
are now increasingly engaged in the process of producing the finished 
fuel (i.e., adding ethanol or gasoline blendstocks into PCG, or adding 
biodiesel into diesel fuel), it has likewise become more important to 
not only receive information from the manufacturers of gasoline and 
diesel fuel at the start of the process, but also from the end of the 
process--at retail level--to ensure fuel quality standards are met. In 
the past this was mostly necessary just for RFG to ensure that the 
oxygenate was in fact

[[Page 29071]]

added to the refinery-certified RBOB downstream and the RFG standards 
were met. However, now that essentially all gasoline has ethanol added 
downstream to a refinery-produced and/or certified CBOB and many 
downstream parties are taking actions that can impact fuel quality, all 
in-use gasoline could benefit from a retail survey. Without it we would 
not propose the changes discussed in Section VII.F to allow refiners 
and importers to account for the downstream addition of ethanol in 
their compliance calculations. Consequently, we are proposing to extend 
the retail survey that has been applicable for over 20 years in RFG 
areas nationwide to all gasoline. The proposed national in-use gasoline 
survey would provide EPA with the data necessary to ensure that in-use 
gasoline is in fact blended with ethanol as claimed by the gasoline 
manufacturer, meets our gasoline standards, and continues to meet RFG 
and anti-dumping statutory requirements. An in-use survey would also 
enable EPA to provide compliance flexibility to CG refiners and 
importers similar to RFG refiners and importers.
    There are no associated overall increased costs or compliance 
burden for the proposed expansion of the scope of the survey to all CG. 
As discussed in Section V.A.2.c, we are proposing a substantial 
reduction in sampling and testing requirements on gasoline refiners and 
importers at the refinery/import facility by removing the requirement 
for the certification of gasoline using the Complex Model. In its 
place, we are proposing requirements for refiners and importers to test 
for just sulfur, benzene, RVP in the summer, and oxygenates.
2. Proposed National Survey Program
a. Consolidation and Scope
    We are proposing to consolidate the existing four in-use survey 
programs outlined in Table X.A-1 into a single national survey program. 
We believe the expanded scope of gasoline samples tested nationwide 
would help us ensure fuel quality oversight and compliance with our 
applicable fuel quality standards. This would also allow for providing 
compliance flexibility for CG refiners and importers to account for 
oxygenate (as discussed in Section VII.F). As previously explained, the 
ULSD and E15 survey programs are national surveys of retail stations 
but only test for sulfur in diesel fuel and ethanol content and RVP in 
the summer. On the other hand, the RFG survey and RFG ethanol survey 
are limited to RFG areas but test for the full suite of Complex Model 
fuel parameters. We believe there is technical support for allowing a 
survey program to collect a sample that satisfies multiple survey 
requirements (i.e., as long as retail stations are identified using 
sound selection procedures, there is no reason an independent surveyor 
could not obtain both a gasoline and a diesel fuel sample to satisfy 
all applicable survey program requirements).
    The main benefit to stakeholders of consolidation of the current 
four survey programs into a single program is a substantial reduction 
in sample size. Currently, the four survey programs require industry 
participants to contract for over 18,000 fuel samples collected 
nationwide (see Table X.A-1 above). As further discussed in Section 
X.A.2.c, we are proposing that the required sample size of our fuels 
survey programs could be reduced to less than 7,000 retail outlets 
sampled through consolidation. Since the largest expense in retail 
surveying is the costs to collect and ship a sample from a retail 
station, reducing the sample size from more than 18,000 to less than 
7,000 would substantially decrease the costs of the program.
    The main benefit to EPA is the expanded scope of testing for 
regulated fuel parameters to all fuel nationwide. Under the existing 
program, the RFG survey programs test approximately 30 percent of the 
national gasoline pool for the entire set of Complex Model fuel 
parameters, while in the nationwide E15 survey, only ethanol content 
year-round and RVP for E15 samples in the summer are tested.
    In addition to consolidating the four survey programs into a 
single, nationwide program, we are proposing that all gasoline samples 
would be tested for sulfur, benzene, RVP (in the summer), and 
oxygenates. A statistically determined subset of the national gasoline 
sample would be tested for the rest of the Complex Model fuel 
parameters to allow us to verify that gasoline continues to meet CAA 
section 211(k) requirements. The survey would continue to ensure E15 
pump labeling compliance at retail stations. For diesel, the survey 
would still test diesel samples for sulfur. We seek comment on the 
proposed consolidation of the four part 80 survey programs and the 
proposed expanded scope of the national survey program.
b. Survey Participation
    We are not proposing any revisions to the existing survey for fuel 
and fuel additive manufacturers that make E15 or ethanol for use in 
making E15, which is the only one of the current surveys that is 
mandatory. Other gasoline manufacturers would need to participate in 
the national survey program if they wanted to account for oxygenate 
added downstream. Under part 80, the RFG regulations impose a similar 
survey requirement on RFG refiners and importers that account for 
oxygenate in compliance calculations (see 40 CFR 80.69) and since we 
are proposing to allow this flexibility for manufacturers of CG, we are 
proposing to impose a similar survey requirement. We believe that 
monitoring in-use sulfur, benzene, and oxygenate content is necessary 
to allow this flexibility for all gasoline manufacturers because 
without in-use verification from a national survey, there would be no 
oversight on whether gasoline manufacturers claimed credit for 
oxygenate that was ultimately not blended.
    Under part 1090, parties that participate in the survey would have 
an affirmative defense for downstream violations of our applicable fuel 
quality standards. Under part 80, we have provided an affirmative 
defense for upstream parties that participate in survey programs to 
ensure downstream compliance for the ULSD survey. We are extending this 
affirmative defense for any party that participates in the national 
survey program to help establish a defense against downstream diesel 
sulfur, gasoline sulfur, gasoline RVP, and E15 misfueling violations in 
part 1090. We believe that parties that are part of the ULSD 
distribution system that participate in the part 80 ULSD survey program 
would continue to participate in the national survey program as well as 
other parties in the gasoline distribution system that wish to use the 
survey to help establish affirmative defenses against downstream 
violations.
    Under the E15 partial waivers and E15 substantially similar 
determination, fuel and fuel additive manufacturers that make E15 or 
ethanol for use in making E15 must participate in a compliance survey 
that ensures that E15 pump dispensers are labeled appropriately.\97\ 
The E15 partial waiver conditions provide fuel and fuel additive 
manufacturers two options to satisfy the compliance survey condition: 
(1) A geographically-focused survey; or (2) a national survey. Under 
part 1090, we are proposing that participation in the national survey 
program would satisfy the national survey option for purposes of 
compliance with the E15 waiver conditions. The E15 waiver conditions 
would allow E15 fuel and

[[Page 29072]]

fuel additive manufacturers to continue using a geographically-focused 
option instead if they so desired, and part 1090 includes provisions to 
facilitate such a program. However, we expect that fuel and fuel 
additive manufacturers would elect to participate in the national 
survey program due to significant amount of cost savings associated 
with participating in it.
---------------------------------------------------------------------------

    \97\ See 75 FR 68094 (November 4, 2010), 76 FR 4662 (January 26, 
2011), and 84 FR 26980 (June 10, 2019).
---------------------------------------------------------------------------

c. Sample Sizes
    We are proposing that the national survey program collect, at a 
minimum, gasoline samples from 5,000 gasoline retail outlets and 2,000 
diesel retail outlets. Since most retail outlets offer both gasoline 
and diesel fuel, we believe that the total number of retail outlets 
sampled would be closer to 5,000 retail outlets rather than 7,000 
outlets. This proposed total would be substantially lower than the 
current regulatory program, which requires sampling for approximately 
17,000 retail outlets. We selected the number of retail outlets for 
gasoline and diesel based on the recent sample size determinations of 
the existing part 80 survey programs and we are proposing the same 
sample size determination methodology that is used for the existing 
part 80 survey programs. This results in approximately 5,000 retail 
outlets since the existing survey program for E15 misfueling mitigation 
is national in scope. Since we are consolidating the four existing 
programs into a national program, the statistical rigor of the sample 
selection methodology is unchanged and would result in the same sample 
size. What is different for this proposed program compared to the E15 
survey program is the types of fuel samples the independent surveyor 
would collect at retail outlets and parameters that are tested for 
those fuel samples once collected (discussed more in Section X.A.2.d).
    For the subset of gasoline samples that would continue to be tested 
for the full suite of Complex Model fuel parameters, we are proposing 
that the sample size would be determined using a standard calculation 
to estimate national fuel parameters. We expect that around 1,200 
gasoline samples would be analyzed for the full suite of Complex Model 
fuel parameters using this methodology. We seek comment on the proposed 
sample size and sample size determination methodology.
d. Requirements for Independent Surveyors
    We are retaining and transferring certain existing requirements for 
independent surveyors in part 80 to part 1090. These include the 
requirement that an independent surveyor would need to conduct the 
national survey program and meet similar independence requirements from 
parties that hire the surveyor to conduct the program. The independent 
surveyor would not be allowed to have financial interest in companies 
that hire the independent surveyor to conduct a survey, nor would 
companies be allowed to have an interest in the independent surveyor's 
organization. Like the part 80 survey programs, the surveyor would need 
to submit an annual plan for surveys conducted under part 1090. The 
plan would identify how the independent surveyor intends to meet the 
proposed regulatory requirements and would be subject to EPA approval 
prior to conducting the survey. Additionally, the independent surveyor 
would need to submit annually to EPA proof that the national survey 
program has been fully funded for the next compliance period by 
December 15.
    As part of our effort to modernize the fuel quality programs, we 
are proposing to require that independent surveyors register with EPA 
and submit periodic reports electronically to EPA, which is not 
currently required under the part 80 survey programs. This would help 
EPA more quickly provide information collected as part of the national 
survey program and promote greater transparency in the fuel quality 
program. The proposed independent surveyor reporting requirements are 
similar to those currently specified in part 80, and the independent 
surveyor would need to keep records in a similar manner. We seek 
comment on the requirements outlined for independent surveyors 
conducting the national survey program under part 1090.

B. National Sampling and Testing Oversight Program

    The RFG regulations in part 80 currently require that each refiner 
have an independent laboratory sample and test batches of RFG unless 
the RFG refiner has an in-line blending waiver. Refiners have the 
choice of having an independent lab sample and test 100 percent of 
their batches or 10 percent of their batches randomly selected. We also 
require that every 33rd batch of RFG collected by an independent lab be 
sent to EPA for analysis.\98\ As part of consolidating the compliance 
provisions across the various gasoline and diesel fuel to create a 
single fuel quality program, we considered how best to ensure proper 
EPA oversight of the sampling and testing for fuels compliance.
---------------------------------------------------------------------------

    \98\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

    During the rule development process, we received feedback that due 
to guidance set forth by EPA in the past on how to select the 10 
percent of batches,\99\ refiners needed to arrange for an independent 
laboratory to sample 100 percent of RFG batches made by a refinery and 
select the 10 percent random sample from among all those RFG batch 
samples. Since arranging to have an independent laboratory collect a 
sample is the most expensive part of the process, parties that provided 
feedback to us argued that this requirement is unnecessarily 
burdensome.
---------------------------------------------------------------------------

    \99\ Id.
---------------------------------------------------------------------------

    At the same time, we are proposing to no longer require the use of 
the Complex Model and remove various restrictions on the production and 
use of RFG. These proposed actions would diminish the need for the 
independent lab testing requirement as currently outlined in the part 
80 RFG regulations. However, we believe that continuing to ensure that 
appropriate sampling and testing is conducted for fuels compliance 
demonstration is an important element of any streamlined fuel quality 
program.
    Consequently, in lieu of the existing RFG requirements, we are 
proposing provisions for a voluntary national sampling oversight 
program designed to ensure that samples are collected in a consistent 
manner by gasoline manufacturers. The purpose of this proposed program 
is to help ensure that fuel manufacturers are sampling and testing in a 
manner consistent with required procedures, as discussed in more detail 
in Section IX.
    As part of the proposed voluntary national sampling oversight 
program, we are also proposing to require that the independent surveyor 
review appropriate PBMS qualification and statistical quality control 
(SQC) data for the samples collected and tested as part of the proposed 
sampling oversight program. We believe that this would help ensure that 
labs that test gasoline for compliance under our fuel quality programs 
are complying with EPA quality control provisions for labs.
    During the rule development process, we discussed whether a review 
of all PBMS qualification and SQC data as part of the annual attest 
audit would be appropriate.\100\ In response, stakeholders suggested 
that auditors, many of whom lack the technical

[[Page 29073]]

expertise to review lab quality control data, would be unable to 
perform such auditing functions for each lab on an annual basis, 
especially before the June 1 annual deadline to complete the attest 
audit process. These stakeholders suggested that in many cases there 
would be too much SQC data across an entire compliance period for 
auditors to reasonably review. Due to the expertise needed to review 
lab PBMS and SQC information and the amount of information needed to 
review, we believe a limited review by the independent survey as part 
of the proposed voluntary national sampling oversight program is 
appropriate. Independent surveyors must demonstrate technical 
competency to EPA as part of the annual plan approval process and 
should be familiar with EPA quality control procedures. Additionally, 
we are proposing a basic record review requirement as part of the 
attest engagement process, discussed in more detail in Section XII.B. 
Combined, we believe these two proposed requirements would help ensure 
that labs are meeting EPA's PBMS and SQC requirements.
---------------------------------------------------------------------------

    \100\ See EPA-420-D-19-001, available in the docket for this 
action.
---------------------------------------------------------------------------

    During the rule development process, we also received feedback 
arguing that a voluntary national sampling oversight program would not 
be necessary due to SQC measures imposed on labs that test fuel samples 
in the Tier 3 gasoline sulfur rule. We disagree with the view that Tier 
3 SQC provisions serve the same function as the national sampling 
oversight program. The SQC provisions place certain control measures on 
the actual testing by the labs of gasoline and diesel fuel samples to 
help ensure valid measurements. However, the SQC provisions do not 
address whether the sample was collected appropriately. Inappropriate 
sampling can affect the validity of test results regardless of whether 
the SQC provisions show the lab is testing appropriately. Additionally, 
EPA enforcement personnel have identified several issues with sampling 
during past audits of fuel testing laboratories that we believe can be 
reduced by a national sampling oversight program.
    Like the national survey program described in Section X.A, we 
believe there is an opportunity to reduce the overall cost of sampling 
oversight while expanding the scope from just RFG to all gasoline 
nationwide. Taken together, we are proposing to require an estimated 
300-400 samples would be collected as part of this proposed national 
sampling oversight program annually. This compares to the several 
thousand samples currently collected from RFG refiners each year. These 
samples would be spread across all gasoline manufacturers instead of 
just RFG refiners. We believe this is a substantial reduction in 
associated burden with independent sampling while still providing the 
necessary oversight.
    We are proposing to require gasoline manufacturers that elect to 
account for oxygenate added downstream to participate in the proposed 
national sampling oversight program. We believe this requirement would 
help ensure that fuel manufacturers are sampling, testing, and 
reporting results of gasoline that is representative of gasoline (i.e., 
BOB) leaving the refinery gate. We are also proposing to exempt 
refineries that have in-line blending waivers from the national 
sampling oversight program since these refineries already have an 
annual audit requirement by an independent auditor.
    Gasoline manufacturers that participate in the program would need 
to arrange for a sample to be overseen by an independent surveyor for 
each season (winter and summer). This would mean that, as long as a 
gasoline manufacturer has product available for testing, the gasoline 
manufacturer would have at least two samples collected per year. We are 
also proposing that an additional number of random samples be collected 
to ensure an effective deterrent against complacency for parties that 
have samples collected early in a season. For example, if we only 
required sampling once per season and a gasoline manufacturer had a 
winter sample surveyed in January of a compliance period, that gasoline 
manufacturer would not be surveyed in the winter for the rest of the 
compliance period. Additional random sampling would help ensure that 
gasoline manufacturers are following appropriate sampling and testing 
procedures year-round, even if sampled early in the season.
    During the rule development process, we received feedback stating 
that having an independent surveyor collect a sample without advanced 
notice would pose a safety hazard and encounter logistical challenges 
that would inhibit the independent surveyor's ability to collect a 
sample. For example, refineries and import facilities would often not 
have product available for sampling, which would create an issue for an 
independent surveyor showing up at random to collect at a refinery. We 
believe that an independent surveyor should provide the minimal amount 
of advanced notice as practical to ensure that product is available for 
sampling and that the independent surveyor could observe whether 
samples are collected in accordance with specified sampling procedures. 
We also believe that since each gasoline manufacturing facility is 
different, the independent surveyor would need to tailor the advanced 
notification procedures for each facility. Specifying a procedure for 
every gasoline manufacturing facility would not be practical given the 
breadth of specific situations, so we are proposing that the 
independent surveyor would need to address advanced notification in its 
annual plan. We seek comment on ways to minimize advanced notification 
for the national sampling oversight program.
    We also received feedback from stakeholders that suggested that 
replacing the RFG independent laboratory testing program with the 
proposed voluntary national sampling oversight program would allow for 
parties to more easily arrange for favorable test results that 
demonstrated a fuel met EPA fuel quality standards. These stakeholders 
suggested that having a requirement that RFG refiners specify a 
registered independent laboratory for testing would make it more 
difficult for RFG refiners to arrange for multiple laboratories to test 
separate samples from a single batch in search of a favorable test 
result. These stakeholders suggested that EPA propose to expand the RFG 
independent laboratory requirement to include CG refiners in addition 
to RFG refiners under part 1090. They suggested that we require that 
all third-party laboratories register and that gasoline refiners be 
limited to using a specified, registered third-party laboratory. While 
we believe that such a proposal would greatly increase the burden 
associated with third-party laboratory testing, which would largely 
fall on smaller gasoline refiners as they typically do not have their 
own testing laboratories, we do believe it could be useful to limit the 
multiple testing of a single batch by multiple laboratories to help 
ensure a level playing and better ensure fuel quality. Therefore, we 
seek comment on whether we should require that all third-party 
laboratories register and that refiners be limited to using a 
specified, registered third-party laboratory.
    Historically, EPA's National Vehicle and Fuel Emissions Laboratory 
(NVFEL) has played a role in the development and quality control of 
analytical test methods used to determine compliance with our fuel 
quality standards. Under part 80, as part of the RFG program, NVFEL 
receives several hundred oversight samples from RFG refiners and 
independent laboratories. NVFEL analyzes these samples and compares the 
results to results from RFG refiners

[[Page 29074]]

and independent labs.\101\ Under part 1090, we would no longer collect 
these oversight samples from RFG refiners and independent labs. 
However, as part of the national sampling oversight program, we are 
proposing that the independent surveyor would send a random selection 
of samples collected as part of the proposed oversight program to NVFEL 
for comparison to the results obtained from the independent surveyor 
and fuel manufacturer's lab. This would allow our lab to continue to 
serve as a reference installation and maintain our oversight of the 
national sampling oversight program.
---------------------------------------------------------------------------

    \101\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

    Like the proposed national survey program, we are proposing that an 
independent surveyor would conduct the national sampling oversight 
program. We envision that these parties would function similar to the 
way that independent surveyors operate under the existing part 80 
program. Therefore, we are proposing a similar independence and plan 
approval process as those used for independent surveyors under part 80 
and the proposed national survey program. The only difference would be 
a change in the reported elements as samples are collected from 
gasoline manufacturing facilities instead of retail stations. We seek 
comment on whether the approach outlined for independent surveyors is 
appropriate for the national sampling oversight program.
    We seek comment on all aspects regarding the proposed national 
sampling oversight program.

XI. Import of Fuels, Fuel Additives, and Blendstocks

    We are transferring most of the current provisions in part 80 that 
address the importation and exportation of fuels, fuel additives, and 
blendstocks to part 1090 (subpart P). As described in this section, 
importers would continue to be subject to the same requirements as 
refiners, while exporters would continue to be subject to certain fuel 
designation and recordkeeping provisions. Overall, we are proposing few 
changes to how imported and exported fuel products are treated relative 
to the current provisions of part 80, although we are proposing to 
significantly change the regulatory text. Many of the proposed 
provisions are merely codification of existing implementation policies 
summarized in a 2003 question and answer (Q&A) document (``2003 
Q&A'').\102\
---------------------------------------------------------------------------

    \102\ See Section IX.C, ``Consolidated List of Reformulated 
Gasoline and Anti-Dumping Questions and Answers: July 1, 1994 
through November 10, 1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

A. Importation

    With few exceptions, we are proposing requirements for importers 
that largely mirror what we currently require under part 80. However, 
we are proposing some updates to provisions for imports. First, under 
part 1090, importers that import fuel at multiple import facilities 
within a single PADD would need to aggregate the facilities for 
purposes of complying with the benzene maximum average standard. For 
compliance with other average standards, importers would continue to 
comply at the company level. Batches of imported fuel that are subject 
to certification requirements must be certified separately for U.S. 
Customs Service purposes at each U.S. port of entry.\103\
---------------------------------------------------------------------------

    \103\ See 19 CFR part 151, subpart C.
---------------------------------------------------------------------------

    Second, under part 80, we currently have guidance that allows 
gasoline classified as ``American Goods Returned'' to the United States 
by the U.S. Customs Service to not count as imported gasoline.\104\ We 
are proposing language consistent with that guidance in part 1090, 
provided all the following conditions are met:
---------------------------------------------------------------------------

    \104\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

     The gasoline was produced at a fuel manufacturing facility 
located within the U.S. and has not been mixed with gasoline produced 
at a fuel manufacturing facility located outside the U.S.
     The gasoline must be included in compliance calculations 
by the producing manufacturer.
     All the gasoline that was exported must ultimately be 
classified as American Goods Returned to the United States and none may 
be used in a foreign country.
     No gasoline classified as American Goods Returned to the 
United States may be combined with any gasoline produced at a foreign 
refinery prior to being imported into the U.S.
    We are not making any significant changes to the definition of an 
importer, which we define as ``a person who imports gasoline, gasoline 
blendstocks or components, or diesel fuel from a foreign country into 
the United States (including the Commonwealth of Puerto Rico, the 
Virgin Islands, Guam, American Samoa, and the Northern Mariana 
Islands).'' The importer under part 1090 would generally be the 
importer of record under the Bureau of Customs and Border Protection 
regulations. This would typically be the entity that owns the fuel, 
fuel additive, or regulated blendstock when the import vessel arrives 
at the U.S. port of entry, or the entity that owns the fuel, fuel 
additive, or regulated blendstock after it has been discharged by the 
import vessel into a shore tank. We seek comment on these proposed 
updates to the import provisions under part 1090, and whether we should 
make changes to the definition of an importer.

B. Special Provisions for Importation by Rail or Truck

    We are proposing reduced compliance options for meeting testing 
requirements when importing fuels by either rail or truck. These 
provisions would allow importers to meet the sampling and testing 
requirements based on test results from the supplier instead of testing 
each batch after the fuel was imported under certain conditions.
    First, the importer would need to get documentation of test results 
from the supplier for each batch of fuel. Testing for a given batch 
would need to occur after the most recent delivery into the supplier's 
storage tank and before transferring product to the railcar or truck.
    Second, the importer would need to conduct testing to verify test 
results from each supplier, by collecting samples either once every 30 
days or every 50 rail or truckloads from a given supplier, whichever is 
most frequent. The proposed provisions would treat importation of 
gasoline and diesel fuel separately but apply to rail and truckloads 
together if the importer imported product from a given supplier by rail 
and truck.

C. Special Provisions for Importation by Marine Vessel

    We are proposing provisions that specifically address importation 
of fuels by marine vessels. These provisions are generally the same as 
those addressed in the 2003 Q&A. Under part 1090, separate 
certification would be required at each import facility, unless the 
fuel is transported by the same vessel making multiple stops but does 
not pick up additional fuel. Consistent with the current part 80 
requirements, we are proposing not to allow importers who import by 
marine vessels to rely on testing from a foreign source.

[[Page 29075]]

Additionally, testing may not be based on samples collected after the 
fuel is off-loaded, unless certain conditions are met that are designed 
to make sure the imported gasoline meets all per-gallon standards and 
that compliance reports accurately reflect the sulfur and benzene 
content of the imported fuel.
    Under these proposed provisions, when finalized, different ship 
compartments would be considered different batches of fuel. However, we 
are proposing the following exceptions. First, importers would be 
allowed to treat the fuel in different compartments of a ship as a 
single batch if they demonstrate that the fuel is homogeneous across 
the compartments as proposed for all composite samples. As is the case 
under part 80, importers would need to demonstrate that results for 
homogeneity testing fell within the specified repeatability range for 
the test method used(s) used to determine homogeneity. Under the 
updated homogeneity testing procedures in part 1090, this would result 
in a decrease in the amount of analytical testing needed to establish 
homogeneity for combining marine vessel compartments compared to part 
80. This decrease in testing is mostly a result of part 80 requiring 
that importers establish homogeneity for all Complex Model parameters, 
which could be as many as 11 fuel parameters. Under part 1090, 
importers would only need to establish homogeneity for two fuel 
parameters. This change would result in a substantial decrease in 
testing burden.
    Second, we would also accept the analysis of samples collected from 
different ship compartments that are combined into a single volume-
weighted composite sample if the compartments are off-loaded into a 
single shore tank, or each individual vessel compartment is shown, 
through sampling and testing, to meet all applicable standards.

D. Gasoline and Diesel Fuel Treated as Blendstocks

    We are largely transferring current provisions for Gasoline treated 
as Blendstocks (GTAB) in part 80 to part 1090. We are also proposing to 
substantially reduce the number of parameters that are tested and 
reported to EPA. Our primary concern with GTAB has been to ensure that 
off-spec gasoline imported into the U.S. are properly blended to 
produce gasoline that meets applicable fuel quality standards. When 
initially established under the RFG and Anti-dumping programs, the GTAB 
provisions focused on the entire set of parameters needed to run the 
Complex Model. Since compliance with our fuel quality standards is 
based on sampling and testing the finished fuel and part 1090 would no 
longer require certification of batches of gasoline using the Complex 
Model, we believe that the testing and reporting of fuel parameters for 
GTAB is no longer necessary. However, volumes for batches of GTAB would 
continue to need to be reported. Other proposed provisions related to 
GTAB are consistent with current part 80 requirements and published 
guidance.
    We are also proposing to replace the existing part 80 requirements 
for diesel treated as blendstock (DTAB) with a simplified procedure. 
Under part 80, most of the DTAB provisions are designed to account for 
the DTAB in compliance calculations that have not been used since 2010. 
The part 80 provisions require importers to include DTAB in compliance 
calculations that are no longer applicable, to keep DTAB segregated 
from other diesel fuel, and limit the importer's ability to transfer 
title of DTAB. Under part 1090, importers would be able to import 
diesel fuel that does not meet applicable EPA standards if the importer 
offloads the imported diesel fuel into one or more shore tanks 
containing diesel and then samples and tests the blended fuel to 
confirm that it meets all applicable per-gallon standards before 
introduction into commerce. We believe this process greatly simplifies 
the certification process for DTAB and seek comment on this approach.

XII. Compliance and Enforcement Provisions and Attest Engagements

A. Compliance and Enforcement Provisions

    We are also transferring compliance and enforcement provisions, 
such as liability, penalty, and prohibited acts and affirmative defense 
provisions that are currently in part 80 to part 1090. We are however, 
revising existing regulatory text by providing them in an easier to 
understand format.\105\ We are proposing regulatory text that 
consolidates and eliminates multiple prohibited acts statements in part 
80 and replacing them with a simple statement that ``[a]ny person who 
violates any requirement in this part is liable for the violation.'' We 
solicit comment as to whether this proposed statement will address the 
universe of regulatory provisions in part 1090.
---------------------------------------------------------------------------

    \105\ See 40 CFR 80.5 (penalties for fuels violations); 80.23 
(liability for lead violations); 80.28 (liability for volatility 
violations); 80.30 (liability for diesel violations); 80.79 
(liability for violation of RFG prohibited acts); 80.80 (penalties 
for RFG/CG violations); 80.610-615 (violation provisions for diesel 
sulfur program); 80.1504-80.1508 (violation provisions for gasoline 
ethanol blends); and 80.1660-80.1666 (violation provisions liability 
for Tier III gasoline sulfur program).
---------------------------------------------------------------------------

    We are also seeking comment on the appropriate default value that 
would be applicable to sampling and testing requirements violations for 
fuel content standards. The existing requirements for regulated parties 
to accurately sample and test fuels are one of the lynchpins of our 
fuel quality regulations. If regulated parties fail to properly sample 
and test fuel, it makes is difficult for EPA and the public to know if 
the fuel meets the applicable standards. Unlike in the case of our 
vehicle and engine regulations where the vehicles and engines still 
exist and can be tested by EPA to verify compliance, in the case of 
fuel, it is typically commingled with other fuel in the distribution 
system immediately upon production, and quickly consumed. The existing 
part 80 regulations provide that if a refiner or importer fails to 
comply with the gasoline sampling and testing requirements, the 
gasoline will be deemed to have a sulfur content of 970 ppm, a benzene 
content of 5 volume percent, and a summer RVP of 11 psi, unless the 
respective party or EPA demonstrates by reasonably specific showings, 
by direct or circumstantial evidence, different properties for the 
gasoline giving rise to the violations.\106\ This creates an additional 
incentive for refiners and importers to properly sample and test 
gasoline and ensures that that they will not benefit by underreporting 
the sulfur, benzene, and/or RVP of gasoline that is not properly 
sampled or tested. However, during the rule development process, 
several stakeholders requested that we reconsider the default values 
that EPA uses for enforcement when a regulated party lacks a valid test 
result for a regulated fuel parameter.
---------------------------------------------------------------------------

    \106\ See 40 CFR 80.80.
---------------------------------------------------------------------------

    We are not proposing any revisions to the default values currently 
found in part 80. We recognize, however, that the gasoline pool today 
has substantially lower levels of sulfur and benzene than at the time 
the default values were promulgated. For this reason, we seek comment 
on whether to establish lower default values for these parameters, and 
what an appropriate default value should be. We are also proposing 
default values for regulated parameters for fuels, fuel additives, and 
regulated blendstocks where we do not have existing default values in 
part 80 for parties that fail to meet the applicable sampling and 
testing requirements. Table XII.A-1 lists the proposed default values.

[[Page 29076]]

       Table XII.A-1--Proposed Default Values for Fuel, Fuel Additive, and Regulated Blendstock Parameters
----------------------------------------------------------------------------------------------------------------
                                                            Sulfur value      Benzene value
                        Product                                (ppm)         (volume percent)   RVP value  (psi)
----------------------------------------------------------------------------------------------------------------
Gasoline...............................................                970                  5                 11
PCG (by subtraction)...................................                  0                  0                n/a
Diesel Fuel............................................              1,000                n/a                n/a
ECA Marine Fuel........................................              5,000                n/a                n/a
Fuel Additives.........................................                970                n/a                n/a
Regulated Blendstocks..................................                970                  5                n/a
----------------------------------------------------------------------------------------------------------------

    In general, for fuel additives and regulated blendstocks, we are 
proposing default values consistent with the existing values for 
gasoline, as we believe these products have similar potential for high 
sulfur levels that would be found in the production of gasoline. During 
the rule development process, some stakeholders pointed out the use of 
default values by blender manufacturers who use PCG by subtraction 
could result in the inappropriate generation of sulfur and benzene 
credits. Since the main purpose of these default values is to provide 
incentives for parties to obtain valid test results, our proposal to 
assume zero sulfur and benzene content from the PCG in a PCG by 
subtraction scenario would attribute all sulfur and benzene to the 
added blendstock and provide incentives for a blending manufacturer to 
appropriately sample and test the PCG.
    For diesel fuel, we are proposing a default 1,000 ppm sulfur value, 
as this level of sulfur content is consistent with the distillate ECA 
marine fuel specification. For ECA marine fuel, we are proposing a 
default 5,000 ppm sulfur value, as this level of sulfur content is 
consistent with global marine fuel standards to meet the 2020 MARPOL 
Annex VI marine fuel sulfur specification. For both diesel fuel and ECA 
marine fuel, we expect that the next higher sulfur standard provides a 
logical default value and would provide incentives for diesel fuel and 
ECA marine fuel manufacturers to obtain valid test results.
    We seek comment on the newly proposed default values. When 
providing comments related to the proposed default values, commenters 
should provide a thorough rationale (including relevant data and 
information) for suggested default values to help EPA consider 
alternative default values.
    We are not proposing any other significant revisions to current 
compliance and enforcement provisions that are in part 80. As earlier 
explained, we are merely consolidating and simplifying these provisions 
in part 1090. We will treat comments on any other compliance and 
enforcement provisions beyond those discussed in this section as 
outside of the scope of this action.

B. Attest Engagements

    Part 80 includes a requirement for gasoline refiners and importers 
to engage auditors to review information reported to EPA. These annual 
attest engagements allow EPA to more effectively ensure compliance with 
regulatory requirements.
    We are transferring existing attest requirements in part 80 to a 
single subpart in part 1090 (subpart R). We are removing obsolete 
material, updating the language for improved clarity, and making some 
minor adjustments and clarifications to improve the quality and 
consistency of reported information.
    For instance, we are proposing to add a requirement for auditors to 
review the refiner's or importer's calculations showing that they 
comply with the sulfur and benzene average standards. We note that the 
EPA's Office of Inspector General made certain findings regarding 
compliance with these standards and recommendation as part of their 
review of the auditing requirements under part 80.\107\ One 
recommendation was to modify the attest engagement regulations to 
require that attest auditors verify compliance calculations for 
gasoline manufacturers to help ensure that the average benzene standard 
was met. We believe the proposed attest engagement provisions are 
consistent with this recommendation and would provide better oversight 
of the gasoline sulfur and benzene average standards.
---------------------------------------------------------------------------

    \107\ See ``Improved Data and EPA Oversight Are Needed to Assure 
Compliance With the Standards for Benzene Content in Gasoline,'' 
Report No. 17-P-0249, June 2017.
---------------------------------------------------------------------------

    We are also proposing to codify the existing attest requirements 
spelled out in the RFG Q&A document.\108\ We are proposing these 
requirements for both CG and RFG. The most significant proposal would 
be the requirement for auditors to review PBMS qualification and SQC 
records related to the sampling and testing requirements for gasoline 
on an annual basis. We are proposing to require a relatively straight-
forward review by auditors of whether labs used to test gasoline for 
compliance have records demonstrating that methods have been qualified 
under the PBMS qualification requirements and that the lab is 
maintaining SQC records. It is worth noting that we are not proposing 
to require auditors to interpret this information as auditors may lack 
the appropriate technical expertise to interpret lab data for 
conformance with PBMS and SQC requirements. Instead, as discussed in 
Section X.B, we are proposing that the independent surveyor review this 
type of information under the voluntary sampling oversight program. We 
do not believe that this simple review will greatly increase the burden 
associated with the annual attest audits. We believe this lab record 
review would help ensure that labs used for testing fuels for 
compliance are doing so in a manner consistent with EPA's quality 
control requirements helping to ensure a level playing field and 
program integrity. We seek comment on this proposed lab record review 
requirement and other aspects of the streamlined attest engagement 
requirements. We are also seeking as to whether there are other 
requirements that would be implemented for purposes of providing 
adequate annual attest audits.
---------------------------------------------------------------------------

    \108\ See ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

C. RVP Test Enforcement Tolerance

    Currently, the agency recognizes and allows a 0.3 psi downstream 
enforcement test tolerance over applicable RVP standards for RVP test 
results.\109\ This test tolerance was based on RVP testing variability 
and the reproducibility of the test methods. Under this approach, we 
rely on test

[[Page 29077]]

results from locations downstream of refineries or import facilities to 
bring enforcement actions against downstream parties only if the 
downstream test results are more than 0.3 psi than the applicable 
standard. Although any sample that is over the standard is a violation, 
we generally do not bring enforcement actions against a downstream 
party if the sample it collects is over the standard but within the 0.3 
psi enforcement test tolerance, as long as there is no reason to 
believe that the downstream party caused the gasoline to exceed the 
standard. Gasoline manufacturers may not use the tolerance to 
effectively raise the applicable standard. If the refiner's or 
importer's test results show the gasoline exceeds the RVP standard, 
then the gasoline is in violation regardless of whether or not the RVP 
test result is within the tolerance.
---------------------------------------------------------------------------

    \109\ See 55 FR 23695 (June 11, 1990), 59 FR 7764 (February 16, 
1994), and ``Consolidated List of Reformulated Gasoline and Anti-
Dumping Questions and Answers: July 1, 1994 through November 10, 
1997,'' EPA-420-R-03-009, July 2003.
---------------------------------------------------------------------------

    At this time, we intend to continue this same RVP enforcement test 
tolerance policy to enforce the gasoline volatility standards in part 
1090. Under part 1090, the 0.3-psi RVP tolerance would apply to both 
summer CG and summer RFG. However, as before, we may change this 
enforcement policy at any time, including adopting new tolerances as 
data on test methods are developed, as technology changes, or as 
further information becomes available concerning the precision of RVP 
test methods.

XIII. Other Requirements and Provisions

A. Requirements for Independent Parties

    We are proposing requirements for third parties performing actions 
authorized under part 1090 regarding their independence from the 
regulated parties who engage them and their technical qualifications. 
These proposed requirements would be consistent with part 80 
independence and technical competency requirements for independent 
third-parties. We believe the proposed requirements would preserve and 
strengthen the integrity of our independent third-party verification 
programs.
    We have always had concerns about the potential for conflicts of 
interest between the independent third-parties that monitor compliance 
on behalf of EPA and the regulated entities who engage them and are 
proposing the same independence requirements for third-parties as 
currently used in part 80. In addition, since proposing the original 
independence requirements for third-parties under the RFG and Anti-
dumping programs in the 1990s, we have seen that third-parties often 
employ contractors or subcontractors to fulfill third-party oversight 
requirements. These contractors or subcontractors should also be free 
from conflicts of interest from regulated parties for whom services are 
performed. Therefore, we are proposing to clarify that independence 
requirements apply not only for the third parties and their employees, 
but also for any contractors and subcontractors.
    Similar to part 80 provisions, we are proposing to impose 
restrictions on both employment history and financial interest. We are 
proposing that independent third parties would be required to ensure 
that their employees, contractors, and subcontractors had not worked 
for the regulated party that hired that third party for any amount of 
time over the previous three years. While the financial independence 
requirements imposed on the independent third party's employees, who 
are directly involved in overseeing the regulated parties, prohibiting 
them from owning or otherwise having any financial interest in that 
regulated party are generally not changing, we are proposing to apply 
these existing independence requirements at the contactor and 
subcontractor levels. There would also be a limitation imposed on the 
independent third party's firm or organization as to the proportion of 
revenue it can generate from any single regulated party. We believe 
this furthers our goal of independent third-party oversight and 
increases the trustworthiness of the program's results. We seek comment 
on these independence requirements and their impacts on the independent 
third parties, as well as the anticipated effectiveness of these 
provisions to increase reliability in our third-party oversight 
program.
    Part 1090 also proposed to include requirements on the technical 
qualifications of the independent third parties. We have employed 
similar requirements under part 80 and have used these requirements in 
other cases where technical competency is important to conduct 
regulated activities for a regulated party; however, we do not 
currently require this demonstration for in-use surveys.\110\ These 
provisions will ensure that program oversight is being conducted by 
parties with the requisite technical capabilities. We are proposing to 
require that the independent surveyors, which are regulated further 
under subpart N, employ personnel with expertise in the areas of 
petroleum marketing, sampling and testing fuels at retail stations, and 
survey design. Technical competency requirements for attest engagement 
auditors and independent laboratories that qualify alternative test 
procedures under PBMS would be unchanged in part 1090.
---------------------------------------------------------------------------

    \110\ See 40 CFR 80.92 and 80.1469.
---------------------------------------------------------------------------

    We request comment on these technical and experience requirements 
and their impacts on the third party oversight program.

B. Labeling

    Part 1090 includes provisions that apply specifically to retailers 
and WPCs, consolidating the various provisions formerly scattered 
throughout part 80 (including the whole set of fuel pump labeling 
requirements) into one subpart (subpart O) with only minor changes 
(including removing several obsolete provisions from part 80). We are 
further proposing to streamline the description of the E15 label by 
replacing descriptive paragraphs with a graphic example of the E15 pump 
label. We believe these changes would make the regulations easier to 
identify and follow for retailers and WPCs.
    We are proposing minor modifications to the existing label 
language. For heating oil, we are proposing to remove the label 
language identifying that heating oil contains greater than 500 ppm 
sulfur.\111\ Most heating oil sold today meets state 15 ppm sulfur 
standards, and we believe that it is misleading and inappropriate to 
require that heating oil dispensers label their product as having 
greater than 500 ppm sulfur. To minimize burden on retailers, we are 
proposing that retailers could use existing labels to satisfy the part 
1090 labeling requirements and that retailers would need to affix a 
heating oil label compliant with the part 1090 label requirements when 
the existing part 80 label needs replacement.
---------------------------------------------------------------------------

    \111\ See 40 CFR 80.573.
---------------------------------------------------------------------------

    During the rule development process, we received feedback from 
stakeholders suggesting that the ECA marine fuel labels were no longer 
necessary due to the way that ECA marine fuel is sold and dispensed for 
use in Category 3 marine vessels. Another option would be to limit 
labeling to situations where ECA marine fuel is co-dispensed with other 
fuels since the purpose of the ECA marine fuel label is to help avoid 
the misfueling of diesel engines that require the use of ULSD with ECA 
marine fuel. This would only be an issue where such diesel engines 
could reasonably be misfueled (i.e., in situations where both ECA 
marine fuel or ULSD are co-

[[Page 29078]]

dispensed). While we are proposing to maintain the ECA marine fuel 
labels currently required under part 80, we seek comment on whether 
maintaining these labels is necessary or whether we could limit the use 
of the label to only situations where ECA marine fuel is co-dispensed 
with other fuels.
    We also seek comment on the structure of proposed fuel pump 
labeling regulations, and on the various modifications to label content 
described in this section.

C. Refueling Hardware Requirements for Dispensing Facilities and Motor 
Vehicles

    As described in the preceding section, part 1090 includes a subpart 
devoted to requirements for retailers and WPCs. This subpart also 
describes requirements related to refueling hardware.
    The proposed nozzle requirements for refueling motor vehicles are 
aligned with the requirements adopted under part 80. There is one 
noteworthy adjustment. We are proposing to identify nozzle 
specifications only in millimeters. The parallel metric and English 
units in part 80 are nearly identical, but this nevertheless creates 
two separate sets of requirements, which is contrary to the objective 
of standardizing hardware. The specifications in part 80 also include a 
level of precision that is greater than is needed to properly identify 
a standard configuration. The single set of specifications, including 
rounding, is consistent with the specifications in part 80, so the 
updated nozzle specifications should not cause any existing hardware to 
be noncompliant, and any existing blueprints for producing nozzles 
would not need to be modified.
    Similar nozzle requirements apply for dispensing gasoline into 
marine vessels. We are similarly proposing a singular set of nozzle-
geometry specifications in millimeters in a way that is aligned with 
the specifications as originally adopted. We are also proposing to 
finish the allowed phase-in of these nozzle-geometry specifications. As 
originally adopted, the nozzle requirements applied as of January 1, 
2009, to new installations and to new nozzles used to repair or replace 
damaged dispensing equipment. Based on industry feedback, the market 
has now transitioned, so there is no need for our regulations to 
continue to allow non-standard nozzles. If there are any remaining 
nozzles for marine refueling that do not meet specifications, we are 
proposing to require that they be replaced with a nozzle that meets the 
standardized configuration. The requirement would apply January 1, 
2021, when part 1090 becomes effective. We request comment on the 
timing of this proposed requirement, and on the extent of modification 
that is required for all installations to meet the nozzle-geometry 
requirements.
    Part 80 additionally specifies a standardized geometry for filler 
necks in light-duty and heavy-duty motor vehicles to correspond with 
the nozzle geometry specifications. We are proposing to move these 
vehicle-based requirements to 40 CFR parts 86 and 1037, which describe 
standards and other requirements for light-duty and heavy-duty motor 
vehicles.

D. Previously Certified Gasoline (PCG)

    We are proposing to largely maintain the existing part 80 
provisions for how blending manufacturers may make new batches of 
gasoline from PCG and blendstocks.\112\ In the Tier 3 rule, we 
finalized changes to improve the consistency of the PCG provisions 
across part 80; \113\ however, we maintained separate PCG provisions 
for each part 80 gasoline program. In part 1090 we are proposing to 
consolidate these provisions into a single set of PCG provision. The 
proposed PCG provisions maintain both options used in part 80: (1) PCG 
by subtraction and (2) PCG by addition.\114\ Other proposed changes are 
minor and designed to improve clarity and consistency of the PCG 
provisions in part 1090. Other provisions related to blending certified 
butane or certified pentane are discussed in Section V.A.3. We seek 
comment on the proposed consolidation of the PCG provisions.
---------------------------------------------------------------------------

    \112\ The purpose of allowing parties to make new batches using 
PCG is to allow flexibility for parties to make new fuels to 
accommodate the market demands while ensuring that the fuel quality 
standards are met. The provisions are designed to ensure that 
gasoline per-gallon standards are met in the new batch and that the 
blending manufacturer does not increase the average sulfur and 
benzene levels in the national gasoline pool.
    \113\ See 79 FR 23575-23576 (April 28, 2014).
    \114\ In PCG by subtraction, a blending manufacturer determines 
the regulated fuel parameters of the PCG and the new batch to 
quantify the sulfur and benzene levels of added blendstocks for 
making the new fuel. In PCG by addition, a blending manufacturer 
directly measures the parameters of added blendstocks to quantify 
the sulfur and benzene levels. In both cases, the new fuel has to 
meet per-gallon specifications for gasoline and blending 
manufacturers would need to sample and test for sulfur year-round 
and for RVP in the summer.
---------------------------------------------------------------------------

E. Transmix and Pipeline Interface Provisions

    In part 1090 we are consolidating and simplifying the flexibilities 
provided to fuel manufacturers that use transmix to produce gasoline 
and diesel fuel. We are also proposing changes to align the 
requirements applicable to these parties to the requirements applicable 
to fuel manufactures under part 1090.\115\ Some of the part 80 
regulations characterize the requirements for transmix processors and 
transmix blenders as alternative compliance mechanisms. For instance, 
the gasoline sulfur regulations state that ''[t]ransmix processors and 
transmix blenders may comply with the following sampling and testing 
requirements and standards instead of the sampling and testing 
requirements and standards otherwise applicable to a refiner under this 
subpart O.'' \116\ The part 1090 regulations set forth specific 
requirements for transmix processors and transmix blenders because we 
believe that virtually all transmix processors and blenders are using 
the alternative approaches set forth in part 80, and because we believe 
that it would be overly complex for transmix processors and blenders to 
comply with the requirements that apply to other fuel manufacturers. We 
seek comment on whether transmix processors and blenders should have 
the option to comply with the requirements that apply to other fuel 
manufacturers. Any comment on this issue should provide specific 
recommendations regarding how to structure the program to assure 
compliance with all per-gallon standards, accurately account for the 
sulfur and benzene content of the fuel, and avoid double counting. 
These proposed changes to the transmix rules are discussed in the 
following sections.
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    \115\ Refiners that produce gasoline and diesel fuel by 
processing crude oil may not use the alternative provisions and are 
subject to all requirements that apply to a fuel manufacturer.
    \116\ See 40 CFR 80.1607.
---------------------------------------------------------------------------

1. Clarifying and Consolidating the Definitions of Transmix and 
Pipeline Interface
    Part 80 currently provides flexibilities for transmix due to the 
unique way in which transmix is reprocessed into useable products and 
the need to expeditiously clear transmix volumes from the fuel 
distribution system to keep product flowing to markets. Transmix has 
traditionally been processed at small facilities that cannot support 
the installation of fuel desulfurization equipment. For example, 
pipelines are permitted to blend limited volumes of transmix into fuels 
subject to EPA standards provided that such blending does not impact 
compliance with the standards. Part 80 also provides that 500 ppm 
diesel fuel from transmix processors can be sold for use in older 
locomotive and marine

[[Page 29079]]

engines that do not require the use of 15 ppm diesel fuel. Other diesel 
fuel producers are required to meet 15 ppm sulfur standard for all LM 
diesel fuel they produce. Transmix processors that produce 500 ppm LM 
diesel fuel are required to submit a compliance plan that demonstrates 
that the 500 ppm LM diesel fuel will not be used in engines that 
require the use of 15 ppm diesel fuel.
    Products are commonly shipped by pipeline adjacent to each without 
any physical barrier between the products. Pipeline interface is 
defined as the volume of petroleum product generated in a pipeline 
between two adjacent volumes of non-identical petroleum product that 
consists of a mixture of the two adjacent products.\117\ The pipeline 
interface ``cut'' refers to the point between the two adjacent pipeline 
batches where physical separations are reintroduced at the end of 
shipment by pipeline. Depending on the quality requirements of the 
adjacent products, pipeline interface can often be cut in one or both 
of the adjacent products. When one of the adjacent products has unique 
quality specifications, it is sometime necessary to cut all of the 
interface into the product with the less stringent specifications. In 
situations where the pipeline interface cannot meet the specifications 
for either of the adjacent batches, it is called transmix and must be 
segregated for further processing before being sold as a fuel. This is 
typically the case when batches of gasoline and diesel fuel must be 
shipped by pipeline adjacent to one another.
---------------------------------------------------------------------------

    \117\ See 40 CFR 80.84(a)(1). We are proposing to maintain the 
current definition of pipeline interface.
---------------------------------------------------------------------------

    Provisions related to the treatment of transmix are currently 
located in various sections in part 80.\118\ To improve clarity, we are 
consolidating most of the special provisions related to the treatment 
of transmix into a single subpart in part 1090 (subpart F). We are also 
incorporating the definitions of transmix and pipeline interface into 
the definitions section of part 1090. These definitions are currently 
imbedded in part 80 in a regulatory section that pertains to the 
treatment of interface and transmix.\119\
---------------------------------------------------------------------------

    \118\ See 40 CFR 80.84, 80.213, 80.513, 80.840, and 80.1607.
    \119\ Current 40 CFR 80.84.
---------------------------------------------------------------------------

2. Blending Transmix Into Previously Certified Gasoline
    In part 1090 we are proposing a minor change to the requirements 
that apply to parties that blend transmix into PCG.\120\ When the 
quality assurance program required of a transmix blender indicates that 
the gasoline does not comply with EPA standards, blenders that use a 
computer controlled in-line blending system are temporarily required 
under part 80 to conduct more frequent sampling and testing. We are 
proposing that no more than one sample per day may be used to 
demonstrate compliance with this increased testing requirement. We 
believe that this is consistent with common industry practice to spread 
out the required samples at the proposed one per day frequency, so 
adoption of this proposed change would not result in an increased 
burden to industry. The existing part 80 regulations would allow 
unscrupulous parties to circumvent the intended purpose of the 
regulations by pulling all of the required samples at one time. This 
proposed change in part 1090 would ensure that the required increase in 
sampling and testing frequency fulfills the intended purpose of 
verifying that the issue that caused the violation has been resolved.
---------------------------------------------------------------------------

    \120\ Industry minimum flash point specifications in ASTM D975 
prevent the blending of transmix into diesel fuel. Hence, there is 
not a need for regulatory provisions regarding blending transmix 
into previously certified diesel fuel.
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3. Gasoline Produced From Transmix Gasoline Product
    Transmix gasoline product (TGP) is the distillation fraction 
produced by a transmix processor that is in the gasoline boiling range. 
Parties that produce gasoline from TGP are currently provided with 
streamlined provisions in part 80 to demonstrate compliance with the 
requirements that apply to fuel manufacturers. These current provisions 
are complicated by the additional fuel parameter specifications for RFG 
beyond those for CG. The proposed elimination of these additional 
requirements for RFG (discussed in Section V.A.2.c) makes these 
complications unnecessary since the only difference between RFG and CG 
would be the applicable volatility standard. Therefore, in the 
streamlined provisions in part 1090 we are proposing to eliminate the 
current differences for producing RFG versus CG from TGP and replace it 
with provisions consistent with the proposed streamlined provisions for 
gasoline.\121\ Under the proposed approach, the only difference between 
the streamlined provisions producing RFG versus CG from TGP would 
pertain to the volatility standard that would apply. Under this 
approach, parties that use these streamlined provisions would exclude 
the volume of TGP and PCG used to produce gasoline from their annual 
compliance calculations to demonstrate compliance with the sulfur and 
benzene average standards under all circumstances. Parties that use 
only TGP or TGP and PCG to produce gasoline would be deemed in 
compliance with the sulfur and benzene average standards, provided they 
are in compliance with the proposed streamlined provisions. Parties 
that made gasoline with TGP and other blendstocks would use PCG 
procedures to account for the sulfur and benzene levels of the added 
blendstocks for demonstrating compliance with annual average sulfur and 
benzene standards. In all cases, as is the case today under part 80, 
parties that make gasoline using TGP would need to meet per-gallon 
sulfur and RVP (in the summer) standards for the resultant gasoline and 
make sure that the gasoline they produce meets the substantially 
similar requirements of the CAA.
---------------------------------------------------------------------------

    \121\ For example, compliance with the anti-dumping requirements 
of part 80 would no longer be required.
---------------------------------------------------------------------------

    To provide additional flexibility, we are proposing that parties 
who use these streamlined provisions and could demonstrate that the 
feedstocks they use to produce gasoline contain no oxygenate would not 
be required to test the gasoline they produce for oxygenate content.
4. 500 ppm LM Diesel Fuel Produced From Transmix
    To improve clarity and remove restrictions that are not cost 
effective, we are proposing minor modifications to the regulatory 
provisions that allow transmix processors to produce 500 ppm LM diesel 
fuel for use in locomotive and marine engines that do not require the 
use of ULSD.
    The current regulations in part 80 require facilities that handle 
500 ppm LM diesel fuel to segregate it from fuel having other 
designations (e.g., ULSD) all the way from the producer through to the 
ultimate consumer.\122\ Locomotive refueling facilities stated that the 
supply of 500 ppm LM diesel fuel is sometimes not consistent enough to 
ensure an adequate supply in their 500 ppm LM storage tanks that are 
dedicated to supplying 500 ppm LM diesel fuel. To facilitate the 
efficient refueling of their locomotives that may use 500 ppm LM diesel 
fuel, they requested that EPA allow ULSD to be introduced to their 500 
ppm LM storage tanks provided that the resultant mixture of 500 ppm LM 
and ULSD is treated as 500 ppm LM. We agreed that

[[Page 29080]]

providing this flexibility would be consistent with the intent of the 
500 ppm LM diesel fuel segregation requirements under part 80 to ensure 
that the 500 ppm LM diesel fuel is not inappropriately swelled by the 
introduction of greater than15 ppm diesel fuel that was not produced 
from transmix. Accordingly, we issued guidance \123\ to retail and WPCs 
of 500 ppm diesel fuel that ULSD may be introduced to their 500 ppm LM 
storage tanks provided that resultant mixture of 500 ppm LM diesel fuel 
and ULSD is treated as 500 ppm LM diesel fuel. We are proposing to 
codify this guidance in part 1090. There is thus no impact of this 
regulatory change, but it will improve the clarity and understanding of 
our regulations.
---------------------------------------------------------------------------

    \122\ See 40 CFR 80.513(h)(3).
    \123\ See Question 14.4, ``Questions and Answers on the Clean 
Diesel Fuel Rules,'' EPA-420-B-06-010, July 2006.
---------------------------------------------------------------------------

    Part 80 currently requires that the volume of 500 ppm LM diesel 
fuel may increase by no more than 2 volume percent while in the custody 
of any party in the distribution system. We are proposing to remove 
this requirement because we believe that the other existing safeguards 
are sufficient to prevent an inappropriate increase in the volume of 
500 ppm LM diesel fuel during distribution due to the introduction of 
other high sulfur distillate streams. For example, pipeline operators 
may only ship 500 ppm LM diesel fuel by pipeline if the fuel does not 
come into physical contact in the pipeline with batches of other 
distillate fuel that have a sulfur content greater than 15 ppm. Other 
parties in the distribution system are required to segregate 500 ppm LM 
diesel fuel from other fuels except for the allowance discussed above 
to introduce ULSD into retail and WPC storage tanks. All parties in the 
distribution system must maintain records to demonstrate that an 
increase in 500 ppm LM diesel fuel while in their custody was due to 
normal interface cutting practices, thermal expansion, and/or the 
addition of ULSD to retail or WPC storage tanks.
    Stakeholders have also requested that regulatory language be added 
to clarify that ULSD may be used as a blendstock with transmix 
distillate product (TDP) to produce 500 ppm LM diesel fuel. They also 
requested that we clarify that 500 ppm LM diesel fuel may be 
redesignated as IMO marine fuel, heating, oil, or blendstock. We are 
proposing that these practices are acceptable under part 1090. We are 
proposing that parties that redesignate 500 ppm LM diesel fuel as IMO 
marine fuel would be required to maintain records from the producer of 
the 500 ppm LM diesel fuel (i.e., PTDs accompanying the fuel) to 
demonstrate compliance with the 500 ppm maximum sulfur standard.
5. Streamlining the Requirements for Pipeline Interface That Is not 
Transmix
    The current requirements for RFG include specifications for 
additional fuel quality parameters beyond those required for CG. These 
additional requirements for RFG necessitated unique requirements 
related to the treatment of the interface between RFG and CG. For 
example, part 80 currently requires that interface containing RFG and 
CG must be designated as CG.\124\ The proposed changes to RFG discussed 
in Section V.A.2 would eliminate concerns over maintaining average RFG 
emission performance and limit the fuel property distinction between CG 
and RFG to just RVP and then only during the summer months. Therefore, 
we are proposing to similarly streamline the provisions regarding 
interface cuts between RFG and CG. We are proposing that pipeline 
operators may cut pipeline interface from batches of RFG and CG that 
are shipped adjacent to each other by pipeline into either or both 
these gasoline batches, with fewer limitations. During the winter 
months there would be no restrictions remaining. Only during the summer 
season are we proposing that pipeline operators could not cut pipeline 
interface from two batches of gasoline subject to different RVP 
standards that are shipped adjacent to each other by pipeline into the 
gasoline batch that is subject to the more stringent RVP standard. For 
example, pipeline operators could not cut pipeline interface from a 
batch of RFG shipped adjacent to a batch of CG into the batch of RFG. 
We believe these reduced restrictions would allow greater flexibility 
and efficiency in the distribution of gasoline.
---------------------------------------------------------------------------

    \124\ See 40 CFR 80.84(b)(1).
---------------------------------------------------------------------------

F. Gasoline Deposit Control

1. Overview
    Section 211(l) of the CAA requires EPA to establish specifications 
for additives to prevent the accumulation of deposits in engines and 
fuel supply systems and that all gasoline contain such additives. In 
response to this requirement, EPA's gasoline deposit control 
(``detergent'') program was finalized in July 1996 and became effective 
in July 1997.\125\ The detergent program requires that all gasoline, 
including the gasoline blend component of E85, contain a detergent that 
satisfies EPA deposit control requirements before being distributed 
from a petroleum terminal. Terminal operators are required to prepare 
and keep volumetric accounting reconciliation (VAR) records to 
demonstrate that a sufficient volume of detergent was added to the 
gasoline they distribute for each accounting period.\126\
---------------------------------------------------------------------------

    \125\ See 61 FR 35310 (July 5, 1996).
    \126\ Under part 80, this period can be up to 30 days. Part 1090 
would not change this period.
---------------------------------------------------------------------------

    Based on a review of emissions test data on circa 1990 vehicles and 
information on the levels of detergent use absent a federal detergency 
requirement, we estimated that the detergent program would result in 
roughly a 1 percent reduction in hydrocarbon and carbon monoxide 
emissions, a 2 percent reduction in NOX emissions, and a 
0.06 percent improvement in fuel economy on average from the gasoline 
vehicle fleet at the time.\127\ Given the considerable changes to 
vehicle technology and to gasoline composition since 1990 that may 
affect both deposit formation and its impact on emissions, and given 
the lack of emissions test data on the effects of deposits on emissions 
from modern vehicles, we are unable to quantify the emissions benefits 
of different levels of deposit control stringency under the detergent 
program today. During the rule development process, some stakeholders 
stated that the existing federal detergents program could affect 
gasoline direct injection engines in a different manner than circa 1990 
vehicles. We have also been informed that there may be situations where 
the presence of a detergent may not provide any benefit and may 
actually exacerbate deposit formation. Given the paucity of data on the 
current effects of the detergent program in the modern vehicle fleet, 
we seek comment on information on the effects of the federal detergent 
program on controlling deposits in modern vehicles and the impact on 
vehicle emission performance.
---------------------------------------------------------------------------

    \127\ Regulatory Impact Analysis and Regulatory Flexibility 
Analysis for the Detergent Certification Program, June 1996. 
Regulatory Impact Analysis and Regulatory Flexibility Analysis for 
the Interim Detergent Registration Program and Expected Detergent 
Certification Program, August 1995.
---------------------------------------------------------------------------

    At the same time, there is considerable cost and effort associated 
with continuing to implement the detergent program. Consequently, we 
are proposing to streamline the program to the extent possible to 
minimize its cost. Specifically, we are proposing to: (1) Eliminate the 
redundant requirement that a detergent that is demonstrated to control 
intake valve deposits also be

[[Page 29081]]

tested to demonstrate the ability to control fuel injector deposits; 
(2) ease the adoption of updated deposit control test procedures when 
they become available; (3) simplify the process for registration and 
certification of detergents and the demonstration of compliance by 
detergent blenders; (4) remove expired and unused provisions; and (5) 
remove the requirement that the gasoline portion of E85 must contain a 
certified detergent. The following sections detail the changes we are 
proposing.
    CAA section 211(l) includes a requirement that gasoline must 
``contain additives to prevent the accumulation of deposits in engines 
or fuel supply systems.'' Our regulations maintain this requirement, 
but we are proposing to modify or eliminate certain testing 
requirements and simplify the registration and certification process 
and compliance demonstrations. CAA section 211(l) also requires that 
EPA promulgate regulations with specifications for detergents. While 
this action modifies those specifications, it maintains the requirement 
that gasoline contain detergents and maintains specifications for 
detergents, updating them to accommodate new circumstances discussed in 
this section. These proposed changes to the detergent program continue 
to be compliant with CAA section 211(l).
2. Eliminating the Port Fuel Injector Deposit Control Testing 
Requirement
    We are proposing to eliminate the requirement that detergents be 
tested to demonstrate the ability to control port fuel injector 
deposits. This would substantially decrease the burden of introducing 
new detergents while maintaining the benefits of the detergent program.
    We currently require separate tests to demonstrate the ability of a 
detergent to control port fuel injector deposits and intake valve 
deposits. Input from stakeholders during the rule development process 
supports the conclusion that detergents that are capable of controlling 
intake valve deposits are inherently capable of controlling port fuel 
injector deposits.\128\ This conclusion is also supported by the 
elimination of a port fuel injector testing requirement in the 
industry-based Top Tier detergency program. The Top Tier program was 
established by industry based on the premise that a superior level of 
deposit control was needed for today's vehicles than that provided by 
EPA requirements. Further support is evidenced by the lack of industry 
activity to have a separate test for port fuel injector deposits. The 
port fuel injector deposit control test required by EPA is based on the 
ASTM D5598 fuel injector deposit control test procedure that uses a 
1985-1987 Chrysler 2.2L vehicle.\129\ The fuel injector technology used 
in these antiquated test vehicles is no longer representative of 
technology used in the current vehicle fleet. Current industry efforts 
are focused on developing an updated intake valve deposit (IVD) control 
test procedure and the evaluation of deposit control in gasoline direct 
injection engines that represent an increasing share of the new vehicle 
fleet.
---------------------------------------------------------------------------

    \128\ Coordinating Research Council (CRC) Annual Report, 
September 2018. The CRC Gasoline Engine Deposit Task Group, CRC 
Project No. CM-136, consists of members of the auto, oil, and 
additive industries. The objectives of this group include developing 
test procedures to evaluate fuel and fuel additive contributions to 
intake valve deposits, and injector deposits in port fuel injection 
and direct injection engines.
    \129\ The detergent program requires demonstration of no more 
than 5 percent flow restriction on any one port fuel injector when 
tested in accordance with ASTM D5598-94.
---------------------------------------------------------------------------

3. Amending the Intake Valve Deposit Control Test Procedures
    Like the port fuel injector test procedure, the intake valve test 
procedure in our regulations is likewise antiquated and of questionable 
relevance to the in-use fleet today. New detergents are currently 
tested using the EPA ASTM D5500 BMW-based deposit control test 
procedure (``EPA ASTM D5500 procedure'') procedure, which uses a 1985 
BMW 318i vehicle. This vehicle was accepted as representative of 
technology in the vehicle fleet when the detergent program was 
finalized in 1996. However, this 34-year-old vehicle is no longer 
representative of the technology used in modern vehicles.\130\ It is 
also increasingly difficult for emissions laboratories to perform the 
EPA ASTM D5500 procedure due to the deterioration of the aged test 
vehicles and the lack of replacement parts. Consequently, CRC is 
currently developing an updated deposit control test procedure.\131\
---------------------------------------------------------------------------

    \130\ CRC Gasoline Engine Deposit Task Group, CRC Project No. 
CM-136, CRC Annual Report, September 2018.
    \131\ Id.
---------------------------------------------------------------------------

    In addition, the test fuel specified by EPA for use in the ASTM 
D5500 procedure is no longer representative of current gasoline. The 
composition of the requisite test fuel is specified to assure a 65th 
percentile concentration of gasoline parameters that affect deposit 
formation based on 1990 gasoline survey data.\132\ The composition of 
gasoline in the U.S. has changed significantly since 1990 due to EPA 
fuel quality requirements and changes in refinery operations due to the 
widespread use of E10. These changes to gasoline composition have 
resulted in current in-use gasoline having a different deposit-forming 
tendency compared to the 1990 gasoline on which the test fuel 
specifications are based. The Tier 2 gasoline sulfur program, finalized 
in 2000, reduced the sulfur content of gasoline by up to 90 
percent.\133\ The Tier 3 gasoline sulfur program, finalized in 2014, 
required a further reduction in gasoline sulfur levels to a 10 ppm 
average from a 30 ppm average under the Tier 2 program.\134\ Parties 
that formulate detergent test fuels stated that the more stringent 
gasoline sulfur requirements were making it impossible to make the 
sufficiently stringent test fuels using only normal refinery 
blendstocks or finished gasoline. As a result, we issued guidance that 
a sulfur doping compound could be used to meet the minimum test fuel 
sulfur specification for test purposes, even though such fuels no 
longer exist in-use.\135\
---------------------------------------------------------------------------

    \132\ 65th percentile concentrations are specified for sulfur, 
aromatics, T90 distillation, and olefins. Under the national generic 
detergent certification option, 10 volume percent ethanol must be 
blended into a base fuel meeting 65th percentile concentrations for 
sulfur, aromatics, T90 distillation, and olefins.
    \133\ See 65 FR 6698 (February 10, 2000).
    \134\ See 82 FR 23414 (April 28, 2014).
    \135\ The approved sulfur doping compound is di-tertiary di-
butyl sulfide.
---------------------------------------------------------------------------

    Consequently, we no longer have confidence that the current EPA 
ASTM D5500 procedure can be used to assess deposits in today's vehicle 
fleet and therefore that the detergent additives tested using it 
provide any of the real world emission benefits quantified in 1996 when 
the detergent regulations were finalized. As a result, we are proposing 
to streamline our intake valve deposit control requirements. 
Specifically, we are proposing that new detergent deposit control 
testing would be conducted using California's deposit control program 
or the Top Tier program.\136\ Data from California's program is 
currently accepted to satisfy EPA requirements only for gasoline that 
meets California's gasoline program.\137\ As discussed in Section 
XIII.F.4, we are proposing to expand the applicability of detergents in 
EPA's gasoline detergent program based on the ability of

[[Page 29082]]

California's program to satisfy EPA requirements for all gasoline. Data 
used to comply with the Top Tier program is currently accepted for EPA 
detergent certification in lieu of data using the EPA ASTM D5500 
procedure. Data used to satisfy the requirements of the Top Tier 
program would continue to be accepted to satisfy EPA deposit control 
requirements.\138\ However, the data from the EPA ASTM D5500 procedure 
would no longer be accepted for new detergents. Existing detergent 
certifications based on the EPA ASTM D5500 procedure would continue to 
remain valid indefinitely. As discussed in Section XIII.F.5, 
stakeholders could petition EPA to adopt updated deposit control test 
procedures for new detergents.\139\ We seek comment on this proposal or 
whether we should continue to accept data from the EPA ASTM D5500 
procedure for new detergents.\140\
---------------------------------------------------------------------------

    \136\ See Title 13, California Code of Regulations, Section 
2257.
    \137\ We are also proposing to incorporate by reference the most 
recent version of the ASTM D5500 procedure.
    \138\ We are also proposing to update the detergent deposit 
control testing provisions that are based on the Top Tier program to 
reflect current Top Tier test fuel composition specifications.
    \139\ The proposed procedures to adopt potential changes to 
detergent deposit control test procedures as they arise in the 
future are discussed in Section XIII.F.5. See Section XIII.F.4 
regarding the geographic applicability of California detergent 
certifications.
    \140\ This approach is not reflected in the proposed regulatory 
text but would only require minor changes to allow.
---------------------------------------------------------------------------

    Eliminating the separate EPA ASTM D5500 procedure for new detergent 
deposit control testing combined with the proposed expanded 
applicability of California-based detergent certifications, would 
substantially streamline the detergent program. Additive manufacturers 
would no longer need to be concerned with the difficulties associated 
with performing a separate EPA ASTM D5500 procedure.
    We acknowledge that similar concerns exist regarding the 
representativeness of the California detergent program's ASTM D5500 
procedure (``California ASTM D5500 procedure''). However, we are 
proposing to continue to accept valid detergent certification under 
California's program as demonstration of compliance with our 
requirements because we believe that the more stringent intake valve 
standard and more representative test fuel specifications for the 
California ASTM D5500 procedure sufficiently mitigates concerns about 
the representativeness of the test vehicle.
    We also acknowledge that even the Top Tier test procedures are not 
new. The ASTM D6201 procedure adopted by the Top Tier program in 2004 
and it is accepted that the technology in the 25-year-old engine used 
in the ASTM D6201 procedure is also no longer representative of the 
majority of the vehicle population.\141\ Hence, the updated deposit 
control test procedure currently under development by CRC would also 
likely replace to the ASTM D6201 procedure. Some industry 
representatives stated that the fading relevance of the ASTM D6201 
procedure suggests that EPA should defer taking action on retiring the 
ASTM D5500 procedure until an updated procedure is developed that would 
replace both the ASTM D6201 and D5500 procedures. Although, we agree 
that it is appropriate to consider retiring the ASTM D6201 procedure as 
soon as a replacement procedure is available, we believe that 
heightened issues regarding the ASTM D5500 procedure no longer allow 
EPA to rely on it. Issues regarding the continued viability of the ASTM 
D5500 procedure are more pronounced than those of the ASTM D6201 
procedure both because the technology used in the ASTM D5500 procedure 
is 9 years older and because it requires vehicle mileage accumulation 
on a test rack whereas the ASTM D6201 procedure is an engine 
dynamometer laboratory procedure. A number of parts necessary to 
maintain the vehicle used in the ASTM D5500 procedure are no longer 
available, forcing the use of substitute parts.\142\ The approximately 
100-hour ASTM D6201 procedure conducted under controlled laboratory 
conditions is inherently less variable than the nearly month-long ASTM 
D5500 road-based procedure, thereby providing improved confidence in 
the repeatability of the results. Therefore, we believe that it is 
appropriate to continue to accept data from the ASTM D6201 procedure in 
the interim while a replacement test is under development, while also 
disallowing new detergent deposit control testing using the EPA ASTM 
D5500 procedure.
---------------------------------------------------------------------------

    \141\ Id.
    \142\ Parts availability is also beginning to be problematic for 
the engine used in the ASTM D6201 procedure, although difficulties 
in maintaining the vehicle used in the ASTM D5500 procedure are much 
more pronounced.
---------------------------------------------------------------------------

    During the rule development process, some stakeholders stated that 
disallowing new detergent deposit control testing using the EPA ASTM 
D5500 procedure in favor of the Top Tier ASTM D6201 procedure or the 
California ASTM D5500 procedure would represent an increase in 
stringency in the detergent program that must be supported by an 
analysis of costs versus benefits. These parties stated that the 
concentration of detergent required to satisfy the requirements of the 
California ASTM D5500 procedure and Top Tier ASTM D6201 procedure is 
somewhat higher and significantly higher, respectively, than required 
under the EPA ASTM D5500 procedure.\143\ We acknowledge that Top Tier, 
and perhaps the California procedure, could result in higher detergent 
treat rates. However, we are not proposing to eliminate the use of 
additives based on the EPA ASTM D5500 procedure. Additive packages can 
continue to be used at their existing treat rates indefinitely. It is 
only the use of new additives that would potentially be impacted, and 
for which we receive only several applications a year. Even then, as 
discussed in Section XIII.F.5, we are proposing an administrative 
process whereby industry could petition EPA to adopt updated deposit 
control test procedures when they become available, provided that such 
procedures are as least as protective as the currently accepted 
procedures. This demonstration could be made compared to any of the 
currently accepted procedures, including the EPA ASTM D5500 procedure.
---------------------------------------------------------------------------

    \143\ The California ASTM D5500 procedure differs from the EPA 
procedure in that it has a more stringent IVD standard (50 versus 
100 mg of IVD per valve), while requiring a test fuel that has less 
deposit forming severity than the test fuel required under the EPA 
procedure.
---------------------------------------------------------------------------

    Furthermore, we have no data to evaluate that there are any 
emissions benefits for the current vehicle fleet resulting from 
satisfying any of the current deposit control test procedures discussed 
in this section. The more modern nature of the California ASTM D5500 
procedure and the Top Tier ASTM D6201 procedure should provide greater 
confidence that compliance with these procedures is providing an 
emissions benefit, whereas we lack confidence that compliance with the 
EPA ASTM D5500 procedure is providing any meaningful emissions benefit.
4. Expanding the Applicability of Detergent Certifications Based on 
Compliance With the California Deposit Control Regulations
    Under the current regulations, a detergent certification based on 
compliance with the California's deposit control regulations may be 
used to demonstrate compliance with EPA's deposit control requirements 
only for gasoline that meets the California's compositional 
requirements and where the detergent is added in a terminal located in 
the California. This limitation was based on concerns that detergents 
certified using test fuels representative of California gasoline might 
not be capable of controlling deposits in

[[Page 29083]]

gasoline that does not meet California requirements. When our detergent 
program was finalized in 1996, the composition of gasoline that 
complies with California standards differed substantially from gasoline 
that met our requirements.\144\ Through subsequent rulemakings, 
expansion of E10 nationwide, and other market changes, the composition 
of gasoline made for use outside of California is much closer to that 
required by California. Therefore, we believe that detergents certified 
under California's requirements should be capable of controlling 
deposits in gasoline that meets EPA's standards. Further support for 
this assessment is that California requires that a detergent limit the 
accumulation of intake valve deposits to less than 50 mg per valve 
whereas our program allows the accumulation of up to 100 mg per valve 
using the ASTM D5500 procedure. Consequently, we are proposing that a 
detergent certified under California's program could be used to meet 
our deposit control requirements in all gasoline.
---------------------------------------------------------------------------

    \144\ See 61 FR 35326-27 (July 5, 1996).
---------------------------------------------------------------------------

5. Easing the Adoption of Future Updates to Deposit Control Test 
Procedures
    We are co-proposing two approaches regarding the process of 
updating deposit control test procedures for the future and how 
regulated parties would reference the specifications for these 
procedures. The primary approach would be through an administrative 
process, and the alternative approach would be through a traditional 
rulemaking process. Under the primary approach, deposit control test 
procedures accepted by EPA would be specified in a publicly available 
document that could be updated as EPA accepts new procedures. The use 
of this streamlined process would greatly facilitate keeping the 
requirements consistent with current industry practice. For example, 
the current need for a notice-and-comment rulemaking to amend test 
procedures specified in the CFR has caused the detergent program to lag 
far behind in reflecting current industry practice regarding the test 
fuels used for the ASTM D6201 procedure. Such noncontroversial changes 
could be made much more been readily through a streamlined process.
    Under this approach, stakeholders could petition EPA to adopt 
changes to the deposit control test procedures previously accepted by 
EPA (e.g., when an update to an existing test procedure is incorporated 
into an existing test method). We would then conduct outreach with 
stakeholders to assess whether there is sufficiently broad support for 
the proposed change. If we determine that this is the case and the 
suggested change met applicable requirements, we would publish on our 
web page and by direct communications with stakeholders that we have 
accepted the change. We would periodically update the detergent 
regulations in the CFR to reflect accepted alternatives.
    Under the alternative approach, a notice-and-comment rulemaking 
would always be required to make changes to the deposit control test 
procedures and the detergent regulations in the CFR would need to be 
amended before such changes could take effect. Based on historical 
experience, this process would make it more difficult to remain current 
with the changing vehicle and fuel marketplace.
6. Removing Expired and Unused Provisions
    The detergent program in part 80 includes provisions to allow a 
detergent to be certified for use in different gasoline pools using 
test fuels that have specifications representative of the deposit-
forming characteristics of these discrete pools. Under the ``national-
generic'' certification option, a detergent can be certified for use in 
all gasoline containing any approved oxygenate. Other options allow a 
detergent to be certified for use only within one of the five Petroleum 
Administration for Defense Districts (PADDs), in regular or premium 
gasoline, in oxygenated or nonoxygenated gasoline, in gasoline 
containing a specific oxygenate other than ethanol, or in a segregated 
gasoline pool defined by the certification applicant. California has 
separate detergency requirements for gasoline sold in California. We 
accept detergent certifications under the California program in lieu of 
meeting our requirements. All applications for detergent certification 
to date other than those based on the California program have been 
under the national-generic option.
    We are proposing to remove expired and unused provisions in the 
detergent program to make the detergent regulations more accessible and 
understandable and eliminate the ongoing costs of maintaining these 
provisions. Despite the lack of utility of these provisions, there is a 
cost to both EPA and industry of maintaining an understanding of them 
as well as the cost of continuing to print them in the CFR. We are 
proposing to remove regulatory provisions associated with the interim 
detergent program that were superseded by the detergent program in 
1996.\145\ We are also proposing to remove the unused options to 
certify a detergent for a discrete gasoline pool under the PADD-
specific, regular versus premium grade, non-oxygenated gasoline, 
oxygenate-specific, and fuel-specific certification options.\146\ We 
believe that it is reasonable to conclude that these options do not 
provide a meaningful flexibility to industry given that they have 
remained unused since the detergent program's inception in 1996. Under 
part 1090, the detergent program would allow all detergents to be used 
in all gasoline containing any approved oxygenate, as is the case today 
under the national-generic detergent certification option. Detergent 
certifications under California's program would also remain valid.\147\
---------------------------------------------------------------------------

    \145\ See 40 CFR 80.141 through 80.156.
    \146\ See 40 CFR 80.163.
    \147\ See Section XIII.F.4 regarding the proposed expansion to 
the applicability of California-based detergent certifications.
---------------------------------------------------------------------------

7. Streamlining the Detergent Registration Process
    Detergent manufacturers are currently required under part 80 to 
submit detergent certification test data and detergent composition 
information for evaluation and approval by EPA prior to the detergent 
being used to comply with our deposit control requirements. To speed up 
the introduction of new detergents and to reduce the burden of 
detergent certification, we are proposing that detergent manufacturers 
could begin marketing a detergent once the manufacturer is satisfied 
that they have met EPA testing requirements without the need for a 
prior submission of the data to EPA and approval by EPA. Under this 
approach, detergent manufacturers would be required to submit data that 
demonstrates compliance with the deposit control testing requirements 
upon request by EPA.
    Composition information is required for all additives that are 
registered for use in gasoline under our Fuel and Fuel Additive Program 
in part 79. We are proposing that the additional composition 
information that is required for detergents to be evaluated for deposit 
control efficacy under part 80, including the lowest additive 
concentration (LAC) established by detergent deposit control testing, 
would be required to be submitted as part of a detergent's part 79 
additive registration rather than requiring a separate submission under 
part 80. Combining all the detergent composition information that must 
be submitted to EPA under part 79 would reduce the

[[Page 29084]]

burden of a separate submission under part 80.
8. Simplifying the Detergent Volumetric Accounting Reconciliation 
Requirements
    Detergent blenders must maintain periodic VAR records to 
demonstrate that they added a volume of detergent to the gasoline they 
distribute at least as great as the LAC associated with the 
certification for the detergent that is used. The current VAR 
provisions require that detergent blenders compile a separate record 
for each monthly VAR period in a standard format. Detergent blenders 
stated that the necessary VAR records are kept in electronic form as 
standard business practice, but that compiling such information into a 
standard format as required by EPA for each VAR period represents a 
significant burden. To reduce the burden, they requested that EPA be 
more flexible regarding the format of these records. We agree that the 
goals of the VAR program can be achieved while providing the requested 
flexibility. Removing the requirement that a VAR report be prepared for 
each accounting period would also eliminate the burden on industry of 
requesting and on EPA of issuing a waiver from this requirement during 
emergency situations to ensure the availability of gasoline. Therefore, 
we are proposing to require that detergent blenders keep the necessary 
records to demonstrate compliance with detergent LAC requirements for 
each blending facility in whatever form that is their common practice. 
The same one calendar month or lesser accounting period would still 
apply.
9. Removing the Requirement That the Gasoline Portion of E85 Contain 
Detergent
    The current deposit control regulations require that the gasoline 
portion of E85 must contain a detergent additive at a concentration at 
least as great as that used during detergent certification testing 
(referred to as the lowest additive concentration or LAC).\148\ The 
addition of ethanol to gasoline, with detergent at the LAC, to produce 
E85 results in a detergent concentration that is lower than the LAC due 
to the increased dilution from the additional ethanol. We proposed to 
remove this requirement in the 2016 Renewables Enhancement and Growth 
Support (REGS) rule.\149\
---------------------------------------------------------------------------

    \148\ See 40 CFR 80.161(a)(3).
    \149\ See 81 FR 80828 (November 16, 2016).
---------------------------------------------------------------------------

    In the REGS rule, we noted that we are not aware of data on the 
deposit control needs of flex-fuel vehicles (FFVs) that operate on E85. 
We also related input from stakeholders that as additive concentration 
diminishes due to dilution with ethanol in making E85, there is a point 
where the presence of a detergent ceases to be beneficial and can 
contribute to deposit formation. We also noted that certain detergents 
are not completely soluble in high ethanol content blends. Comments on 
the REGS rule were supportive of removing the requirement that the 
gasoline portion of E85 contain detergents. During the rule development 
process for this action, stakeholders indicated that they were also 
supportive of this change. Therefore, we are proposing to remove the 
current requirement that the gasoline portion of E85 contain 
detergents.
    This action is allowable under the CAA as CAA section 211(l) only 
refers to deposit control additives for gasoline. E85 is not gasoline 
because only fuels composed of at least 50 volume percent clear 
gasoline are included in the gasoline family under part 79 and E85 
contains at least 51 volume percent ethanol.\150\
---------------------------------------------------------------------------

    \150\ See 40 CFR 79.56(e)(1)(i) regarding the gasoline family 
definition. See ASTM D5798 regarding the ethanol content of E85.
---------------------------------------------------------------------------

G. In-Line Blending

    We are proposing to continue to allow the use of EPA-approved in-
line blending waivers. These in-line blending waiver provisions allow 
refiners to use a procedure to certify batches using in-line blending 
equipment instead of the more typical batch certification procedures. 
Under part 80, we have two different sets of requirements for in-line 
blending for RFG and CG. However, we are proposing to consolidate these 
two sets of requirements into a single set of requirements for in-line 
blending in part 1090. For RFG refiners, the in-line blending 
requirements would remain largely unchanged except that RFG refiners' 
in-line blending waivers would not have to cover parameters we are 
proposing to no longer require for the certification of batches of 
gasoline (discussed in more detail in Section V.A.2). RFG refiners 
would still need to arrange for an annual audit to ensure that the 
terms of the in-line blending waiver are being implemented 
appropriately. For CG refiners, we are proposing to allow in-line 
blending waivers to cover all regulated gasoline parameters instead of 
just sulfur. CG refiners would also have to undergo the same annual 
audit procedure for RFG refiners that currently exists under part 80. 
We believe that the flexibility to cover additional parameters for CG 
refiners through the in-line blending waiver would far exceed any costs 
associated with the additional audit.
    Due to the substantial proposed changes in part 1090 to the 
existing requirements for in-line blending waivers, we are proposing to 
require that all refiners with an existing in-line blending waiver 
would need to resubmit their in-line blending waiver requests. We 
believe this is necessary to ensure that in-line blending waivers 
appropriately cover the proposed changes to the in-line blending 
requirements. Due to the time it would take for refiners to prepare new 
submissions and for us to review and approve those submissions, we are 
proposing to allow refiners to operate under their existing part 80 in-
line blending waiver until January 1, 2022, a full year after we are 
proposing to implement most other proposed part 1090 provisions. We 
believe this would provide an adequate amount of time for refiners to 
submit and receive new in-line blending waivers. We seek comment on 
whether we should require resubmissions and whether we are providing an 
adequate amount of time for refiners to do so.

H. Confidential Business Information

    We are proposing regulations that would streamline our processing 
of claims that requests for exemptions or flexibilities should be 
withheld from public disclosure under Exemption 4 of the Freedom of 
Information Act (FOIA), 5 U.S.C. 552(b)(4), as CBI. If finalized, the 
rules would identify certain types of information collected by EPA 
under part 1090 that EPA will consider as not entitled to confidential 
treatment pursuant to Exemption 4 of the FOIA and which EPA will 
release without further notice.
    Exemption 4 of the FOIA exempts from disclosure ``trade secrets and 
commercial or financial information obtained from a person [that is] 
privileged or confidential.'' \151\ In order for information to meet 
the requirements of Exemption 4, EPA must find that the information is 
either: (1) A trade secret, or (2) commercial or financial information 
that is: (a) Obtained from a person, and (b) privileged or 
confidential. Information meeting these criteria is commonly referred 
to as CBI.\152\
---------------------------------------------------------------------------

    \151\ 5 U.S.C. 552(b)(4).
    \152\ We note that CAA section 114 explicitly excludes emissions 
data from treatment as confidential information.
---------------------------------------------------------------------------

    In June 2019, the U.S. Supreme Court issued its decision in Food 
Marketing

[[Page 29085]]

Institute v. Argus Leader Media, 139 S. Ct. 2356, 2366 (2019) (Argus 
Leader). Argus Leader addressed the meaning of ``confidential'' within 
the context of FOIA Exemption 4. The Court held that ``[a]t least where 
commercial or financial information is both customarily and actually 
treated as private by its owner and provided to the government under an 
assurance of privacy, the information is `confidential' within the 
meaning of Exemption 4.'' \153\ The Court identified two conditions 
``that might be required for information communicated to another to be 
considered confidential.'' \154\ Under the first condition, 
``information communicated to another remains confidential whenever it 
is customarily kept private, or at least closely held, by the person 
imparting it.'' (internal citations omitted). The second condition 
provides that ``information might be considered confidential only if 
the party receiving it provides some assurance that it will remain 
secret.'' (internal citations omitted). The Court found the first 
condition necessary for information to be considered confidential 
within the meaning of Exemption 4, but did not address whether the 
second condition must also be met.
---------------------------------------------------------------------------

    \153\ Argus Leader, 139 S. Ct. at 2366.
    \154\ Id. at 2363.
---------------------------------------------------------------------------

    Following issuance of the Court's opinion, the U.S. Department of 
Justice (DOJ) issued guidance concerning the confidentiality prong of 
Exemption 4, articulating ``the newly defined contours of Exemption 4'' 
post-Argus Leader.\155\ Where the government provides an express or 
implied indication to the submitter prior to or at the time the 
information is submitted to the government that the government would 
publicly disclose the information, then the submitter cannot reasonably 
expect confidentiality of the information upon submission, and the 
information is not entitled to confidential treatment under Exemption 
4.\156\
---------------------------------------------------------------------------

    \155\ ``Exemption 4 After the Supreme Court's Ruling in Food 
Marketing Institute v. Argus Leader Media and Accompanying Step-by-
Step Guide,'' Office of Information Policy, U.S. DOJ, (October 4, 
2019), available at https://www.justice.gov/oip/exemption-4-after-supreme-courts-ruling-food-marketing-institutev-argus-leader-media.
    \156\ See id.; see also ``Step-by-Step Guide for Determining if 
Commercial or Financial Information Obtained from a Person is 
Confidential under Exemption 4 of the FOIA,'' Office of Information 
Policy, U.S. DOJ, (updated October 7, 2019), available at https://www.justice.gov/oip/step-step-guide-determining-if-commercial-or-financial-information-obtained-person-confidential.
---------------------------------------------------------------------------

    Here, EPA is providing an express indication that we may release 
certain basic information incorporated into EPA actions on petitions 
and submissions, as well as information contained in submissions to EPA 
under part 1090 without further notice, and that such information will 
not be entitled to confidential treatment under Exemption 4 of the 
FOIA. In particular, this decision applies to requests under the 
following processes: Testing and R&D exemptions under 40 CFR 1090.610, 
hardship exemptions under 40 CFR 1090.635, alternative quality 
assurance programs under 40 CFR 1090.505, alternative PTD language 
under 40 CFR 1090.1175, in-line blending waivers under 40 CFR 
1090.1315, alternative measurement procedures under 40 CFR 1090.1365, 
survey plans under 40 CFR 1090.1400, and alternative labels under 40 
CFR 1090.1500. Accordingly, such information may be released without 
further notice to the submitter and without following EPA's procedures 
set forth in 40 CFR part 2, subpart B. Thus, to expedite processing of 
information requests and increase transparency related to EPA 
determinations, we are proposing to clarify in the regulations that a 
clearly delineated set of basic information related to our decisions on 
exemptions, waivers, and alternative procedures under part 1090 will 
not be treated as confidential.
    In this action, we are, by rulemaking, providing potential 
submitters notice of our intent to release particular information 
related to future submissions. We are proposing that upon receipt of 
submissions, we may release the following information: Submitter's 
name; the name and location of the facility for which relief is 
requested, if applicable; the general nature of the request; and the 
relevant time period for the request, if applicable. Additionally, once 
we have adjudicated submissions, we may release the following 
additional information: The extent to which EPA either granted or 
denied the request, and any relevant conditions. For information 
submitted under part 1090 claimed as confidential that is outside the 
categories described above, and not specified in the proposed 
regulations at 40 CFR 1090.15(b) or (c), EPA will evaluate such 
confidentiality claims in accordance with our regulations at 40 CFR 
part 2, subpart B.
    We find that it is appropriate to release the information described 
above in the interest of transparency and to provide the public with 
information about entities seeking exemptions or requests for 
alternative compliance procedures under part 1090. This approach will 
also provide certainty to submitters regarding the release of 
information under part 1090. With this advance notice, each potential 
submitter will have the discretion to decide whether to make such a 
request with the understanding that EPA may release certain information 
about the request without further notice.

XIV. Costs and Benefits

A. Overview

    In general, we expect that this action would reduce the cost of 
fuel distribution by improving fuel fungibility, reduce the costs for 
regulated parties to comply with our fuel quality regulations, and 
reduce the costs for EPA to implement those regulations. We do not 
expect a measurable effect on regulated emissions or air quality as 
this rule is not proposing to change the stringency of our fuel quality 
standards. This section lays out the general areas of potential cost 
savings for producing fuels that would result if the proposing 
streamlining rule was finalized. We outline in more detail these areas 
for savings in a technical memo to the docket.\157\ We specifically 
solicit comment on quantifying cost savings associated with increased 
fungibility of fuels, as well as the tables provided and assumptions 
invoked in the technical memo.
---------------------------------------------------------------------------

    \157\ See ``Economic Analysis: Fuels Regulatory Streamlining 
Proposed Rule,'' available in the docket for this action.
---------------------------------------------------------------------------

B. Reduced Fuel Costs to Consumers From Improved Fuel Fungibility

    A number of the provisions being proposed in part 1090 are expected 
to improve fuel fungibility. This would result in decreased costs 
associated with the distribution and sale of such fuels. Some examples 
of ways that this could result in potential cost savings is from the 
decreased need for separate tanks at terminals, the shipment of larger 
batches of fuels through pipelines with less interface downgrade, and 
fewer constraints on distribution and use of certain fuels in various 
markets (e.g., winter RFG in CG areas). While we believe that these 
types of savings could be significant, especially when applied to the 
national gasoline and diesel fuel pools, these types of costs savings 
are difficult to quantify. We reached out to stakeholders to attempt to 
quantify potential costs savings and did not receive any information 
that would help us determine cost savings from increased fuel 
fungibility. Therefore, we seek comment on potential cost savings as 
from increased fuel fungibility directly for the proposed fuels 
regulatory streamlining provisions.

[[Page 29086]]

C. Costs and Benefits for Regulated Parties

    We anticipate that the proposed streamlined fuels provisions would 
significantly reduce the administrative burden for regulated parties to 
comply with our fuel quality standards. The opportunities to reduce 
such administrative burden have been discussed throughout this 
proposal. Some examples of areas where savings could result are the 
decrease in the number of fuel parameters needed to be tested to 
certify gasoline (discussed in Section V.A.2), the reduction in the 
number and frequency of reports submitted to EPA to demonstrate 
compliance with our gasoline requirements (discussed in Section 
VIII.C), and cost savings associated with consolidating the current 
four in-use survey programs into a single, national in-use survey 
program.
    In general, estimates in administrative burden reduction are 
captured in the supporting statement for the proposed information 
collection request (ICR) required under the Paperwork Reduction Act 
(PRA) and discussed in more detail in Section XV.C.\158\ As part of 
this action, we are proposing to replace the multiple existing ICRs for 
part 80 into a single ICR for all fuel programs that would now be 
included in part 1090. As part of that process, we are comparing the 
administrative burden from the existing ICRs to the estimated 
administrative burden in the proposed ICR. This results in a change of 
about $4.6 million less per year. Furthermore, we discuss additional 
areas of potential administrative savings for industry that may not be 
captured in ICRs in a technical memorandum.\159\ We estimate that there 
are potential savings of about $28.3 million per year. Including the 
$4.6 million cost reductions estimated under the ICR, the total 
estimated savings in administrative costs to industry is $32.9 million 
per year. Table XIV.C-1 outlines the categories identified for savings, 
which are described in detail in a memorandum to the docket.\160\
---------------------------------------------------------------------------

    \158\ The supporting statement for the proposed ICR and other 
supporting materials are available in the docket for this action.
    \159\ See ``Economic Analysis: Fuels Regulatory Streamlining 
Proposed Rule,'' available in the docket for this action.
    \160\ Id.

   Table XIV.C-1--Estimated Annual Cost Savings by Savings Category 1
------------------------------------------------------------------------
                                                               Savings
                      Savings category                           (in
                                                              millions)
------------------------------------------------------------------------
Eliminate Olefin, Aromatics and Distillation Testing.......         $5.4
Fewer Batch Reports........................................          4.5
Less Retail Sampling.......................................          1.5
Eliminate Oxygenate Testing................................          2.5
Independent Labs...........................................          0.6
Oversight Testing..........................................          0.2
Barge Distribution Savings.................................         13.8
Information Collection Request.............................          4.6
                                                            ------------
  Total Savings............................................         32.9
------------------------------------------------------------------------
\1\ Cost savings in 2019 dollars.

    In addition, there are other potential savings for all stakeholders 
that are more difficult to quantify. For example, an expected 
consequence of making the regulations clearer and less complex would be 
less time and effort for staff to understand our regulations and fewer 
inquiries to EPA or to hired consultants to untangle regulatory 
ambiguity.
    Aspects of this action that are expected to increase costs are 
expected to be small and offset by a large margin by savings in 
provisions they replace. Since we are not proposing changes to the 
stringency of our standards, we do not expect fuel manufacturers to 
have to alter their production processes in order to comply with the 
proposed streamlined regulations. In prior fuels rulemakings, retooling 
petroleum refiners often serve as the most significant costs associated 
with changes in fuel standards. Similarly, other parties in the fuel 
distribution system should not be expected to have to make any costly 
adjustments to how they produce, distribute, and sell fuels, fuel 
additives, and regulated blendstocks. We do expect there may be some 
one-time costs associated with updating recordkeeping and reporting 
requirements associated with the proposed requirements. For example, 
parties would most likely need to change PTDs to reflect the proposed 
streamlined language. These costs are expected to be small and are 
reflected in the ICR supporting statement.\161\
---------------------------------------------------------------------------

    \161\ The ICR supporting statement is available in the docket 
for this action.
---------------------------------------------------------------------------

    Overall, we expect the savings from increased fungibility of fuels, 
the decrease in administrative costs, and other indirect cost savings 
resulting from the proposal to far exceed any one-time administrative 
costs needed to begin compliance with the proposed streamlined fuel 
quality regulations. These cost savings would be expected to be passed 
along to consumers in the form of lower fuel prices, given the highly 
competitive fuel marketplace. We discuss many of these areas, including 
a much more detailed analysis of the cost savings, in a technical 
memorandum \162\ and the ICR supporting statement.\163\ We also 
estimated the total new present value cost savings if the total savings 
are carried out over 30 years at a 3 percent and 7 percent discounted 
rate, which are presented in Table XIV.C-2.\164\
---------------------------------------------------------------------------

    \162\ See ``Economic Analysis: Fuels Regulatory Streamlining 
Proposed Rule,'' available in the docket for this action.
    \163\ The ICR supporting statement is available in the docket 
for this action.
    \164\ These results are discussed in more detail in the 
technical memorandum, ``Economic Analysis: Fuels Regulatory 
Streamlining Proposed Rule,'' available in the docket for this 
action.

        Table XIV.C-2--Estimated Net Present Value Cost Savings 1
------------------------------------------------------------------------
 Three percent  discount rate  (in    Seven percent  discount rate  (in
             millions)                            millions)
------------------------------------------------------------------------
                     $560                                 $380
------------------------------------------------------------------------
\1\ Cost savings in 2019 dollars.

    We seek comment on the potential costs and benefits that would 
result from this action and whether there are other costs and benefits 
that we should consider.

D. Environmental Impacts

    Since we are not proposing to make changes to the stringency of the 
existing fuel quality standards, we do not expect any measurable impact 
on regulated emissions or air quality. However, as discussed in more 
detail throughout the preamble, there are certain areas of this action 
where changes to compliance requirements could be viewed as marginally 
affecting in-use fuel quality. These marginal changes could then have a 
ripple effect on regulated emissions. In general, such changes would be 
very small, typically well below the levels that we have historically 
attempted to quantify in rulemakings where we establish fuel standards. 
Given the relative size of such changes, it would be difficult if not 
impossible to make an estimate with any level of confidence on the air 
quality effects that would result from this action. Despite this 
limitation, we have attempted to at least identify potential areas that 
could have an effect on in-use fuel quality.
    First, we have heard concerns that the proposed RFG RVP maximum 
per-gallon of 7.4 psi, which is higher than the estimated RFG average 
RVP of 7.1-7.2 psi. might be perceived as a decrease

[[Page 29087]]

in in-use fuel quality. Section V discusses why we believe that based 
on historical information, the fuel system builds in compliance margins 
to assure that per-gallon RVP standards are met and result in RVP 
averages that are between 0.2-0.3 psi lower than the maximum per-gallon 
standard. We have also maintained limitations on the addition of 
certified butane and pentane to summer RFG to help ensure that an 
average RVP of 7.1-7.2 psi is realized in-use for summer RFG. 
Furthermore, by consolidating the three RFG VOC performance standards 
to the most stringent standard, there may be a slight reduction in the 
RVP of RFG supplied to areas with the less stringent VOC performance 
standards.
    Second, we heard that by allowing manufacturers of CG to account 
for oxygenate added downstream, any current unintentional 
overcompliance with the gasoline average benzene and sulfur standards 
would be lost, resulting in a slight increase in the benzene and sulfur 
contents of the fuel pool. While this could result in a slight increase 
in the amount of benzene and sulfur in the national fuel pool,\165\ we 
believe there are some other elements that could offset or eclipse 
these potential increases, making any real world quantification 
difficult. One is the downstream BOB recertification procedures that 
would require downstream parties that recertify BOBs for less oxygenate 
to make up for the unrealized dilution of sulfur and benzene through 
retiring credits (e.g., if a party recertifies an E10 BOB as an E0 
gasoline). This would pull sulfur and benzene out of the gasoline fuel 
pool and help offset some of the reduction in overcompliance. 
Additionally, we are not allowing the generation of credits from the 
over blending of oxygenates into BOB (e.g., if a party recertifies an 
E10 BOB as E15). This would further dilute the amount of sulfur and 
benzene in the gasoline pool and help offset any perceived reduction in 
overcompliance.
---------------------------------------------------------------------------

    \165\ See ``Estimated Effects of Proposed Downstream Oxygenate 
Accounting Provisions,'' available in the docket for this action.
---------------------------------------------------------------------------

    During the rule development process, we also heard from 
stakeholders concerns that reducing the parameters needed to certify 
gasoline would make it easier for parties to blend dirtier gasoline and 
not comply with our fuel quality requirements. Other stakeholders 
suggested that the reduced reporting requirements would make it more 
difficult for EPA to oversee compliance with the fuel requirements. We 
believe the improved oversight, especially by third-party surveys, 
would address these concerns and, contrary to the concerns expressed, 
may improve the quality of fuel sold at retail. While fuel 
manufacturers would still be required to certify fuels for conformance 
with EPA fuel quality standards, the issue is that fuels are now 
blended with oxygenates, additives, and blendstocks at various points 
along the distribution chain before the fuels are used in vehicles and 
engines. Under the existing regulations, EPA monitors the quality of 
gasoline primarily at the refinery gate, not downstream at retail. The 
proposed national in-use survey program is designed to ensure that 
fuels continue to meet our standards when they are dispensed from 
retail stations and would help provide valuable information for EPA to 
oversee the fuel quality programs. In addition, the proposed voluntary 
national oversight program would ensure that manufacturers are sampling 
and testing in a manner consistent with our regulations to help ensure 
that parties are not biasing test results to make dirtier fuels. We 
also believe that by proposing to simplify and modernize our reporting 
requirements, we will be better able to oversee the fuel quality 
program as information is more readily available.
    Taken together, we believe the proposed streamlining of the fuel 
quality programs would on balance ensure greater compliance with our 
regulatory requirements by making the requirements more intuitive to 
the regulated community to comply with. We also believe the increased 
oversight mechanisms proposed would allow us to better oversee 
compliance with the current fuel standards and take appropriate action 
when issues are identified. The net result of this could be a slight 
improvement in fuel quality across the national fuel pool; however, 
such an effect is difficult to quantify.

XV. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be found at 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 Proposed Rule,'' is available 
in the docket.

B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs

    This action is expected to be an Executive Order 13771 deregulatory 
action. Details on the estimated cost savings of this proposed rule can 
be found in our analysis of the potential costs and benefits associated 
with this action in Section XIV.

C. Paperwork Reduction Act (PRA)

    The information collection activities in this proposed rule have 
been submitted for approval to the Office of Management and Budget 
(OMB) under the PRA. The Information Collection Request (ICR) document 
that EPA prepared has been assigned OMB ICR number 2060-NEW; EPA ICR 
number 2607.01. You can find a copy of the ICR in the docket for this 
rule, and it is briefly summarized here.
    The information collection activities under this proposed rule are 
similar to those under existing 40 CFR part 80 and include familiar 
requirements for respondents to register, report, sample, and test 
gasoline for four parameters (i.e., sulfur, benzene, seasonal RVP and 
oxygenate/oxygen content in the cases of gasoline and sulfur in the 
case of diesel), keep records in the normal course of business (e.g., 
PTDs and test results, as applicable), participate in surveys, conduct 
attest engagements, and apply pump labels. Many parties are already 
registered under part 80 and would not have to re-register under the 
proposed approach. The exact information collection requirements 
proposed are tied to the party's control over the quality and type of 
fuel--for example, a refiner of gasoline has great control over the 
quality and type of fuel and has proposed registration, reporting, 
sampling, testing, recordkeeping, survey, and attest engagement 
responsibilities; a party who owns a retail station has only limited, 
proposed information collection requirements involving the retention of 
customary business records (e.g., PTDs) and affixing labels to certain 
pumps from which fuel is dispensed. The proposed information collection 
for part 1090 would not result in duplication of requirements under 
existing part 80, as this proposed regulation would replace nearly all 
non-RFS provisions under the existing part.
    Respondents/affected entities: The respondents to this information 
collection are parties involved in the

[[Page 29088]]

manufacture, blending, distribution, sale, or dispensing of regulated 
fuels and fuel blendstocks. These include refiners, importers, 
blenders, terminals and pipelines, truck facilities, fuel retailers, 
and wholesale purchaser-consumers.
    Respondent's obligation to respond: Mandatory, under proposed 40 
CFR part 1090.
    Estimated number of respondents: 182,269.
    Frequency of response: Annual and occasionally.
    Total estimated burden: 522,368 hours (per year). Burden is defined 
at 5 CFR 1320.3(b).
    Total estimated cost: $ 56,744,171 (per year) including, $5,744,016 
annualized capital or operation and maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for EPA's 
regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on EPA's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to EPA using the docket identified at the 
beginning of this rule. You may also send your ICR-related comments to 
OMB's Office of Information and Regulatory Affairs. These comments and 
recommendations for the proposed information collection should be sent 
within 30 days of publication of this notice to www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting 
``Currently under 30-day Review--Open for Public Comments'' or by using 
the search function. EPA will respond to any ICR-related comments in 
the final rule.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. In 
making this determination, the impact of concern is any significant 
adverse economic impact on small entities. An agency may certify that a 
rule will not have a significant economic impact on a substantial 
number of small entities if the rule relieves regulatory burden, has no 
net burden, or otherwise has a positive economic effect on the small 
entities subject to the rule. This action proposes to consolidate EPA's 
existing fuel quality regulations into the new 40 CFR part 1090, and 
the proposed requirements on small entities are largely the same as 
those already included in the existing 40 CFR part 80 fuel quality 
regulations. While this action makes relatively minor corrections and 
modifications to those regulations, we do not anticipate that there 
will be any significant cost increases associated with these proposed 
changes--to the contrary, we anticipate cost decreases. We have 
therefore concluded that this action will have no net regulatory burden 
for all directly regulated small entities.

E. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. This action imposes 
no enforceable duty on any state, local or tribal governments. 
Requirements for the private sector do not exceed $100 million in any 
one year.

F. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government. However, 
to the extent that states have adopted fuel regulations based on EPA's 
regulatory provisions that we are proposing to change, states may need 
to make corresponding changes to their regulations to maintain their 
effectiveness.
    Although Executive Order 13132 does not apply to this proposed 
rule, EPA did consult with representatives of various State and local 
governments in developing this rule. EPA has also consulted with 
representatives from the National Association of Clean Air Agencies 
(NACAA, representing state and local air pollution officials), 
Association of Air Pollution Control Agencies (AAPCA, representing 
state and local air pollution officials), and Northeast States for 
Coordinated Air Use Management (NESCAUM, the Clean Air Association of 
the Northeast States). In the spirit of Executive Order 13132, and 
consistent with EPA policy to promote communications between EPA and 
state and local governments, EPA specifically solicits comment on this 
proposed action from state and local officials.

G. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. This proposed rule will be implemented at the 
Federal level and potentially affects transportation fuel refiners, 
blenders, marketers, distributors, importers, exporters, and renewable 
fuel producers and importers. Tribal governments would be affected only 
to the extent they produce, purchase, and use regulated fuels. Thus, 
Executive Order 13175 does not apply to this action.

H. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets Executive Order 13045 as applying only to those 
regulatory actions that concern environmental health or safety risks 
that EPA has reason to believe may disproportionately affect children, 
per the definition of ``covered regulatory action'' in section 2-202 of 
the Executive Order. This action is not subject to Executive Order 
13045 because it does not concern an environmental health risk or 
safety risk.

I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. This action proposes to consolidate 
EPA's existing fuel quality regulations into a new part, consistent 
with the CAA and authorities provided therein. There are no additional 
costs for sources in the energy supply, distribution, or use sectors. 
The proposed action would only be anticipated to improve fuel 
fungibility and therefore enhance fuel supply and distribution but in 
ways that are not readily quantifiable.

J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This proposed action involves technical standards. We are proposing 
to update a number of regulations that already contain voluntary 
consensus standards (VCS), practices, and specifications to more recent 
versions of these standards. In accordance with the requirements of 1 
CFR 51.5, we are proposing to incorporate by reference the use of test 
methods and standards from American Institute of Certified Public 
Accountants, American Society for Testing and Materials International

[[Page 29089]]

(ASTM International), National Institute of Standards and Technology 
(NIST), and The Institute of Internal Auditors. A detailed discussion 
of these test methods and standards can be found in Sections III.D.3, 
VII.F, VIII.F, IX, and XIII.F. The standards and test methods may be 
obtained through the American Institute of Certified Public Accountants 
website (www.aicpa.org) or by calling (888) 777-7077, ASTM 
International website (www.astm.org) or by calling ASTM at (610) 832-
9585, the National Institute of Standards and Technology website 
(www.nist.gov) or by calling NIST at (301) 975-6478, and The Institute 
of Internal Auditors website (www.theiia.org) or by calling (407) 937-
1111.
    This rulemaking involves environmental monitoring or measurement. 
Consistent with EPA's Performance Based Measurement System (PBMS), for 
those fuel parameters that fall under PBMS, such as sulfur, benzene, 
Reid Vapor Pressure, and oxygenate content, we are proposing not to 
require the use of specific, prescribed analytic methods. Rather, we 
are proposing to allow the use of any method that meets the prescribed 
performance criteria. The PBMS approach is intended to be more flexible 
and cost-effective for the regulated community; it is also intended to 
encourage innovation in analytical technology and improved data 
quality. We are not precluding the use of any method, whether or not it 
constitutes a voluntary consensus standard, so long as it meets the 
performance criteria specified. We are also proposing the use of 
specific standard practices or test methods for situations when PBMS 
would not be applicable, such as gasoline detergency certification test 
methods or references to gasoline specification ASTM D4814 or ethanol 
specification ASTM D4806.
    ASTM International routinely updates many of its reference 
documents. If ASTM International publishes an updated version of any of 
reference documents included in this proposal, we will consider 
referencing that updated version in the final rule.

 Table XV.J-1--Proposed Standards and Test Methods To Be Incorporated by
                                Reference
------------------------------------------------------------------------
   Organization and standard or test
                 method                            Description
------------------------------------------------------------------------
The Institute of Internal Auditors--     Document describes standard
 International Standards for the          practices for internal
 Professional Practice of Internal        auditors to perform auditing
 Auditing (Standards), Revised October    services.
 2016.
American Institute of Certified Public   Document describes standard
 Accountants--Statements on Standards     practices for external
 for Attestation Engagements (SSAE) No.   auditors to perform
 18, Attestation Standards:               attestation engagements using
 Clarification and Recodification,        agreed-upon procedures.
 Revised April 2016.
American Institute of Certified Public   Document describes principles
 Accountants--AICPA Code of               to establish a code of
 Professional Conduct, September 1,       professional conduct for
 2018.                                    external auditors.
American Institute of Certified Public   Document describes an external
 Accountants--Statements on Quality       auditor's CPA firm's
 Control Standards, July 1, 2019.         responsibilities for its
                                          system of quality control for
                                          its accounting and auditing
                                          practices.
NIST Handbook 158, 2016 Edition, Field   Document describes procedures
 Sampling Procedures for Fuel and Motor   for drawing fuel samples from
 Oil Quality Testing--A Handbook for      blender pumps and other in-
 Use by Fuel and Oil Quality Regulatory   field installations for
 Officials, April 2016.                   testing to measure fuel
                                          parameters.
ASTM D86-19, Standard Test Method for    Test method describes how to
 Distillation of Petroleum Products and   perform distillation
 Liquid Fuels at Atmospheric Pressure,    measurements for gasoline and
 approved December 1, 2019.               other petroleum products.
ASTM D287-12b (Reapproved 2019),         Test method describes how to
 Standard Test Method for API Gravity     measure the density of fuels
 of Crude Petroleum and Petroleum         and other petroleum products,
 Products (Hydrometer Method), approved   expressed in terms of API
 December 1, 2019.                        gravity.
ASTM D975-19c, Standard Specification    Specification describes the
 for Diesel Fuel, approved December 15,   characteristic values for
 2019.                                    several parameters to be
                                          considered suitable as diesel
                                          fuel.
ASTM D976-06 (Reapproved 2016),          Test method describes how to
 Standard Test Method for Calculated      calculate cetane index for a
 Cetane Index of Distillate Fuels,        sample of diesel fuel and
 approved April 1, 2016.                  other distillate fuels.
ASTM D1298-12b (Reapproved 2017),        Test method describes how to
 Standard Test Method for Density,        measure the density of fuels
 Relative Density, or API Gravity of      and other petroleum products,
 Crude Petroleum and Liquid Petroleum     which can be expressed in
 Products by Hydrometer Method,           terms of API gravity.
 approved July 15, 2017.
ASTM D1319-19, Standard Test Method for  Test method describes how to
 Hydrocarbon Types in Liquid Petroleum    measure the aromatic content
 Products by Fluorescent Indicator        and other hydrocarbon types in
 Adsorption, approved August 1, 2019.     diesel fuel and other
                                          petroleum products.
ASTM D2163-14 (Reapproved 2019),         Test method describes how to
 Standard Test Method for Determination   determine the content of
 of Hydrocarbons in Liquefied Petroleum   various types of hydrocarbons
 (LP) Gases and Propane/Propene           in light-end petroleum
 Mixtures by Gas Chromatography,          products, which is used for
 approved May 1, 2019.                    determining the purity of
                                          butane and propane.
ASTM D2622-16, Standard Test Method for  Test method describes how to
 Sulfur in Petroleum Products by          measure the sulfur content in
 Wavelength Dispersive X-ray              gasoline, diesel fuel, and
 Fluorescence Spectrometry, approved      other petroleum products.
 January 1, 2016.
ASTM D3120-08 (Reapproved 2019),         Test method describes how to
 Standard Test Method for Trace           measure the sulfur content in
 Quantities of Sulfur in Light Liquid     diesel fuel and other
 Petroleum Hydrocarbons by Oxidative      petroleum products.
 Microcoulometry, approved May 1, 2019.
ASTM D3231-18, Standard Test Method for  Test method describes how to
 Phosphorus in Gasoline, approved April   measure the phosphorus content
 1, 2018.                                 of gasoline.
ASTM D3237-17, Standard Test Method for  Test method describes how to
 Lead in Gasoline by Atomic Absorption    measure the lead content of
 Spectroscopy, approved June 1, 2017.     gasoline.
ASTM D3606-17, Standard Test Method for  Test method describes how to
 Determination of Benzene and Toluene     measure the benzene content of
 in Spark Ignition Fuels by Gas           gasoline and similar fuels.
 Chromatography, approved December 1,
 2017.
ASTM D4052-18a, Standard Test Method     Test method describes how to
 for Density, Relative Density, and API   measure the density of fuel
 Gravity of Liquids by Digital Density    samples, which can be
 Meter, approved December 15, 2018.       expressed in terms of API
                                          gravity.

[[Page 29090]]

 
ASTM D4057-19, Standard Practice for     Document establishes proper
 Manual Sampling of Petroleum and         procedures for drawing samples
 Petroleum Products, approved July 1,     of fuel and other petroleum
 2019.                                    products from storage tanks
                                          and other containers using
                                          manual procedures.
ASTM D4177-16e1 Standard Practice for    Document establishes proper
 Automatic Sampling of Petroleum and      procedures for using automated
 Petroleum Products, approved October     procedures to draw fuel
 1, 2016.                                 samples for testing.
ASTM D4737-10 (Reapproved 2016),         Test method describes how to
 Standard Test Method for Calculated      calculate cetane index for a
 Cetane Index by Four Variable            sample of diesel fuel and
 Equation, approved July 1, 2016.         other distillate fuels.
ASTM D4806-19a, Standard Specification   Specification describes the
 for Denatured Fuel Ethanol for           characteristic values for
 Blending with Gasolines for Use as       several parameters to be
 Automotive Spark-Ignition Engine Fuel,   considered suitable as
 approved September 15, 2019.             denatured fuel ethanol for
                                          blending with gasoline.
ASTM D4814-20, Standard Specification    Specification describes the
 for Automotive Spark-Ignition Engine     characteristic values for
 Fuel, approved February 1, 2020.         several parameters to be
                                          considered suitable as
                                          gasoline.
ASTM D5134-13 (Reapproved 2017),         Test method describes how to
 Standard Test Method for Detailed        measure benzene in butane,
 Analysis of Petroleum Naphthas through   pentane, and other light-end
 n-Nonane by Capillary Gas                petroleum compounds.
 Chromatography, approved October 1,
 2017.
ASTM D5186-19, Standard Test Method for  Test method describes how to
 Determination of the Aromatic Content    determine the aromatic content
 and Polynuclear Aromatic Content of      in diesel fuel.
 Diesel Fuels By Supercritical Fluid
 Chromatography, approved June 1, 2019.
ASTM D5191-19, Standard Test Method for  Test method describes how to
 Vapor Pressure of Petroleum Products     determine the vapor pressure
 (Mini Method), approved January 1,       of gasoline and other
 2019.                                    petroleum products.
ASTM D5453-19a, Standard Test Method     Test method describes how to
 for Determination of Total Sulfur in     measure the sulfur content of
 Light Hydrocarbons, Spark Ignition       neat ethanol and other
 Engine Fuel, Diesel Engine Fuel, and     petroleum products.
 Engine Oil by Ultraviolet
 Fluorescence, approved July 1, 2019.
ASTM D5500-19 Standard Test Method for   Test method describes a vehicle
 Vehicle Evaluation of Unleaded           test procedure to evaluate
 Automotive Spark-Ignition Engine Fuel    intake valve deposit formation
 for Intake Deposit Formation, approved   of gasoline.
 November 1, 2019.
ASTM D5599-18, Standard Test Method for  Test method describes how to
 Determination of Oxygenates in           measure the oxygenate content
 Gasoline by Gas Chromatography and       of gasoline.
 Oxygen Selective Flame Ionization
 Detection, approved June 1, 2018.
ASTM D5769-15, Standard Test Method for  Test method describes how to
 Determination of Benzene, Toluene, and   determine the benzene content
 Total Aromatics in Finished Gasolines    and other types of
 by Gas Chromatography/Mass               hydrocarbons in gasoline.
 Spectrometry, approved December 1,
 2015.
ASTM D5842-19, Standard Practice for     Document establishes proper
 Sampling and Handling of Fuels for       procedures for drawing samples
 Volatility Measurement, approved         of gasoline and other fuels
 November 1, 2019.                        from storage tanks and other
                                          containers using manual
                                          procedures to prepare samples
                                          for measuring vapor pressure.
ASTM D5854-19a, Standard Practice for    Document establishes proper
 Mixing and Handling of Liquid Samples    procedures for handling,
 of Petroleum and Petroleum Products,     mixing, and conditioning
 approved May 1, 2019.                    procedures to prepare
                                          representative composite
                                          samples.
ASTM D6201-19a, Standard Test Method     Test method describes an engine
 for Dynamometer Evaluation of Unleaded   test procedure to evaluate
 Spark-Ignition Engine Fuel for Intake    intake valve deposit formation
 Valve Deposit Formation, approved        of gasoline.
 December 1, 2019.
ASTM D6259-15 (Reapproved 2019),         Document establishes procedures
 Standard Practice for Determination of   to determine how to evaluate
 a Pooled Limit of Quantitation for a     parameter measurements at very
 Test Method, approved May 1, 2019.       low levels, including a
                                          laboratory limit of
                                          quantitation that applies for
                                          a given facility.
ASTM D6299-19, Standard Practice for     Document establishes procedures
 Applying Statistical Quality Assurance   to evaluate measurement system
 and Control Charting Techniques to       performance relative to
 Evaluate Analytical Measurement System   statistical criteria for
 Performance, approved November 1, 2019.  ensuring reliable
                                          measurements.
ASTM D6550-15, Standard Test Method for  Test method describes how to
 Determination of Olefin Content of       determine the olefin content
 Gasolines by Supercritical-Fluid         of gasoline.
 Chromatography, approved December 1,
 2015.
ASTM D6667-14 (Reapproved 2019),         Test method describes how to
 Standard Test Method for Determination   determine the sulfur content
 of Total Volatile Sulfur in Gaseous      of butane, liquefied petroleum
 Hydrocarbons and Liquefied Petroleum     gases, and other gaseous
 Gases by Ultraviolet Fluorescence,       hydrocarbons.
 approved May 1, 2019.
ASTM D6708-19a, Standard Practice for    Document establishes
 Statistical Assessment and Improvement   statistical criteria to
 of Expected Agreement Between Two Test   evaluate whether an
 Methods that Purport to Measure the      alternative test method
 Same Property of a Material, approved    provides results that are
 November 1, 2019.                        consistent with a reference
                                          procedure.
ASTM D6792-17, Standard Practice for     Document establishes principles
 Quality Management Systems in            for ensuring quality for
 Petroleum Products, Liquid Fuels, and    laboratories involved in
 Lubricants Testing Laboratories,         parameter measurements for
 approved May 1, 2017.                    fuels and other petroleum
                                          products.
ASTM D7039-15a, Standard Test Method     Test method describes how to
 for Sulfur in Gasoline, Diesel Fuel,     measure sulfur in gasoline and
 Jet Fuel, Kerosine, Biodiesel,           other petroleum products.
 Biodiesel Blends, and Gasoline-Ethanol
 Blends by Monochromatic Wavelength
 Dispersive X-ray Fluorescence
 Spectrometry, approved July 1, 2015.
ASTM D7717-11 (Reapproved 2017),         Document establishes procedures
 Standard Practice for Preparing          for blending denatured fuel
 Volumetric Blends of Denatured Fuel      ethanol with gasoline to
 Ethanol and Gasoline Blendstocks for     prepare a sample for testing.
 Laboratory Analysis, approved May 1,
 2017.
------------------------------------------------------------------------

[[Page 29091]]

K. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    EPA believes that this action does not have disproportionately high 
and adverse human health or environmental effects on minority 
populations, low income populations, and/or indigenous peoples, as 
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). 
This proposed rule does not affect the level of protection provided to 
human health or the environment by applicable air quality standards. 
This action does not relax the control measures on sources regulated by 
EPA's fuel quality regulations and therefore will not cause emissions 
increases from these sources.

XVI. Statutory Authority

    Statutory authority for this action comes from sections 202, 203-
209, 211, 213, 216, and 301 of the Clean Air Act, 42 U.S.C. 7414, 7521, 
7522-7525, 7541, 7542, 7543, 7545, 7547, 7550, and 7601. Additional 
support for the procedural and compliance related aspects of this 
proposed rule comes from sections 114, 208, and 301(a) of the Clean Air 
Act, 42 U.S.C. 7414, 7521, 7542, and 7601(a).

List of Subjects

40 CFR Part 79

    Fuel additives, Gasoline, Motor vehicle pollution, Penalties, 
Reporting and recordkeeping requirements.

40 CFR Part 80

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports, 
Oil imports, Petroleum, Renewable fuel.

40 CFR Part 86

    Administrative practice and procedure, Confidential business 
information, Labeling, Motor vehicle pollution, Reporting and 
recordkeeping requirements.

40 CFR Part 1037

    Administrative practice and procedure, Air pollution control, 
Confidential business information, Environmental protection, Labeling, 
Motor vehicle pollution, Reporting and recordkeeping requirements, 
Warranties.

40 CFR Part 1090

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Diesel fuel, Fuel additives, Gasoline, Imports, 
Incorporation by reference, Oil imports, Petroleum, Renewable fuel.

Andrew Wheeler,
Administrator.

    For the reasons set forth in the preamble, EPA proposes to amend 40 
CFR parts 79, 80, 86, 1037, and 1090 as follows:

PART 79--REGISTRATION OF FUEL AND FUEL ADDITIVES

0
1. The authority citation for part 79 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7524, 7545, and 7601.

Subpart A--General Provisions

0
2. Amend Sec.  79.5 by revising paragraph (a)(1) to read as follows:

Sec.  79.5  Periodic reporting requirements.

    (a) * * * (1) For each calendar year (January 1 through December 
31) commencing after the date prescribed for any fuel in subpart D of 
this part, fuel manufacturers must submit to the Administrator a report 
for each registered fuel showing the range of concentration of each 
additive reported under Sec.  79.11(a) and the volume of such fuel 
produced in the year. Reports must be submitted by March 31 for the 
preceding year, or part thereof, on forms supplied by the 
Administrator. If the date prescribed for a particular additive in 
subpart D of this part, or the later registration of an additive is 
between October 1 and December 31, no report will be required for the 
period to the end of that year.
* * * * *

Subpart C--Additive Registration Procedures

0
3. Amend Sec.  79.21 by:
0
a. Revising paragraphs (f) and (g); and
0
b. Adding paragraph (j).
    The revisions and addition read as follows:

Sec.  79.21  Information and assurances to be provided by the additive 
manufacturer.

* * * * *
    (f) Assurances that any change in information submitted pursuant 
to:
    (1) Paragraphs (a), (b), (c), (d), and (j) of this section will be 
provided to the Administrator in writing within 30 days of such change; 
and
    (2) Paragraph (e) of this section as provided in Sec.  79.5(b).
    (g)(1) Assurances that the additive manufacturer will not 
represent, directly or indirectly, in any notice, circular, letter, or 
other written communication or any written, oral, or pictorial notice 
or other announcement in any publication or by radio or television, 
that registration of the additive constitutes endorsement, 
certification, or approval by any agency of the United States, except 
as specified in paragraph (g)(2) of this section.
    (2) In the case of an additive that has its purpose-in-use 
identified as a deposit control additive for use in gasoline pursuant 
to the requirements of paragraph (d) of this section, the additive 
manufacturer may publicly represent that the additive meets the EPA's 
gasoline deposit control requirements, provided that the additive 
manufacturer is in compliance with the requirements of 40 CFR 1090.240.
* * * * *
    (j) If the purpose-in-use of the additive identified pursuant to 
the requirements of paragraph (d) of this section is a deposit control 
additive for use in gasoline, the manufacturer must submit the 
following in addition to the other information specified in this 
section:
    (1) The lowest additive concentration (LAC) that is compliant with 
the gasoline deposit control requirements of 40 CFR 1090.240.
    (2) The deposit control test method in 40 CFR 1090.1395 that the 
additive is compliant with.
    (3) A complete listing of the additive's components and the weight 
or volume percent (as applicable) of each component.
    (i) When possible, standard chemical nomenclature must be used or 
the chemical structure of the component must be given. Polymeric 
components may be reported as the product of other chemical reactants, 
provided that the supporting data specified in paragraph (j)(3) of this 
section is also reported.
    (ii) Each detergent-active component of the package must be 
classified into one of the following designations:
    (A) Polyalkyl amine.
    (B) Polyether amine.
    (C) Polyalkylsuccinimide.
    (D) Polyalkylaminophenol.
    (E) Detergent-active petroleum-based carrier oil.
    (F) Detergent-active synthetic carrier oil.
    (G) Other detergent-active component (identify category, if 
feasible).
    (iii) Composition variability. (A) The composition of a detergent 
additive reported in a single additive registration (and the detergent 
additive product sold under a single additive registration) may not 
include the following:
    (1) Detergent-active components that differ in identity from those 
contained in the detergent additive package at the time of deposit 
control testing.

[[Page 29092]]

    (2) A range of concentrations for any detergent-active component 
such that, if the component were present in the detergent additive 
package at the lower bound of the reported range, the deposit control 
effectiveness of the additive package would be reduced as compared with 
the level of effectiveness demonstrated pursuant to the requirements of 
40 CFR 1090.240. Subject to the foregoing constraint, a gasoline 
detergent additive sold under a particular additive registration may 
contain a higher concentration of the detergent-active component(s) 
than the concentration(s) of such component(s) reported in the 
registration for the additive.
    (B) The identity or concentration of non-detergent-active 
components of the detergent additive package may vary under a single 
registration provided that such variability does not reduce the deposit 
control effectiveness of the additive package as compared with the 
level of effectiveness demonstrated pursuant to the requirements of 40 
CFR 1090.240.
    (C) Unless the additive manufacturer provides EPA with data to 
substantiate that a carrier oil does not act to enhance the detergent 
additive's ability to control deposits, any carrier oil contained in 
the detergent additive, whether petroleum-based or synthetic, must be 
treated as a detergent-active component in accordance with the 
requirements in paragraph (j)(3)(ii) of this section.
    (D) Except as provided in paragraph (j)(3)(iii)(E) of this section, 
detergent additive packages that do not satisfy the requirements in 
paragraphs (j)(3)(iii)(A) through (C) must be separately registered. 
EPA may disqualify an additive for use in satisfying the requirements 
of this subpart if EPA determines that the variability included within 
a given detergent additive registration may reduce the deposit control 
effectiveness of the detergent package such that it may invalidate the 
lowest additive concentration reported in accordance with the 
requirements of paragraph (j)(1) of this section and 40 CFR 1090.240.
    (E) A change in minimum concentration requirements resulting from a 
modification of detergent additive composition does not require a new 
detergent additive registration or a change in existing registration if 
the modification is affected by a detergent blender pursuant to the 
requirements of 40 CFR 1090.1240.
    (4) For detergent-active polymers and detergent-active carrier oils 
that are reported as the product of other chemical reactants:
    (i) Identification of the reactant materials and the manufacturer's 
acceptance criteria for determining that these materials are suitable 
for use in synthesizing detergent components. The manufacturer must 
maintain documentation, and submit it to EPA upon request, 
demonstrating that the acceptance criteria reported to EPA are the same 
criteria which the manufacturer specifies to the suppliers of the 
reactant materials.
    (ii) A Gel Permeation Chromatograph (GPC), providing the molecular 
weight distribution of the polymer or detergent-active carrier oil 
components and the concentration of each chromatographic peak 
representing more than one percent of the total mass. For these results 
to be acceptable, the GPC test procedure must include equipment 
calibration with a polystyrene standard or other readily attainable and 
generally accepted calibration standard. The identity of the 
calibration standard must be provided, together with the GPC 
characterization of the standard.
    (5) For non-detergent-active carrier oils, the following 
parameters:
    (i) T10, T50, and T90 distillation points, and end boiling point, 
measured according to applicable test procedures cited in 40 CFR 
1090.1350.
    (ii) API gravity and viscosity.
    (iii) Concentration of oxygen, sulfur, and nitrogen, if greater 
than or equal to 0.5 percent (by weight) of the carrier oil.
    (6) Description of an FTIR-based method appropriate for identifying 
the detergent additive package and its detergent-active components 
(polymers, carrier oils, and others) both qualitatively and 
quantitatively, together with the actual infrared spectra of the 
detergent additive package and each detergent-active component obtained 
by this test method. The FTIR infrared spectra submitted in connection 
with the registration of a detergent additive package must reflect the 
results of a test conducted on a sample of the additive containing the 
detergent-active component(s) at a concentration no lower than the 
concentration(s) (or the lower bound of a range of concentration) 
reported in the registration pursuant to paragraph (j)(1) of this 
section.
    (7) Specific physical parameters must be identified which the 
manufacturer considers adequate and appropriate, in combination with 
other information in this section, for identifying the detergent 
additive package and monitoring its production quality control.
    (i) Such parameters must include (but need not be limited to) 
viscosity, density, and basic nitrogen content, unless the additive 
manufacturer specifically requests, and EPA approves, the substitution 
of other parameter(s) which the manufacturer considers to be more 
appropriate for a particular additive package. The request must be made 
in writing and must include an explanation of how the requested 
physical parameter(s) are helpful as indicator(s) of detergent 
production quality control. EPA will respond to such requests in 
writing; the additional parameters are not approved until the 
manufacturer receives EPA's written approval.
    (ii) The manufacturer must identify a standardized measurement 
method, consistent with the chemical and physical nature of the 
detergent product, which will be used to measure each parameter. The 
documented ASTM repeatability for the method must also be cited. The 
manufacturer's target value for each parameter in the additive, and the 
expected range of production values for each parameter, must be 
specified.
    (iii) The expected range of variability must differ from the target 
value by an amount no greater than five times the standard 
repeatability of the test procedure, or by no more than 10 percent of 
the target value, whichever is less. However, in the case of nitrogen 
analysis or other procedures for measuring concentrations of specific 
chemical compounds or elements, when the target value is less than 10 
parts per million, a range of variability up to 50 percent of the 
target value will be considered acceptable.
    (iv) If a manufacturer wishes to rely on measurement methods or 
production variability ranges which do not conform to the above 
limitations, then the manufacturer must receive prior written approval 
from EPA. A request for such allowance must be made in writing. It must 
fully justify the adequacy of the test procedure, explain why a broader 
range of variability is required, and provide evidence that the 
production detergent will perform adequately throughout the requested 
range of variability pursuant to the requirements of 40 CFR 1090.1395.
0
4. Revise Sec.  79.24 to read as follows:

Sec.  79.24  Termination of registration of additives.

    (a) Registration may be terminated by the Administrator if the 
additive manufacturer requests such termination in writing.
    (b) Registration for an additive for an additive that has its 
purpose-in-use identified as a deposit control additive for use in 
gasoline pursuant to the requirements of Sec.  79.21(d) may be

[[Page 29093]]

terminated by the Administrator if the EPA determines that the 
detergent additive is not compliant with the gasoline deposit control 
requirements of 40 CFR 1090.240.

Subpart C--Additive Registration Procedures

0
5. Amend Sec.  79.32 by revising paragraph (c) to read as follows:

Sec.  79.32  Motor vehicle gasoline.

* * * * *
    (c) Fuel manufacturers must submit the reports specified in 40 CFR 
part 1090, subpart J.
* * * * *
0
6. Amend Sec.  79.33 by revising paragraph (c) to read as follows:

Sec.  79.3  3 Motor vehicle diesel.

* * * * *
    (c) Fuel manufacturers must submit the reports specified in 40 CFR 
part 1090, subpart J.
* * * * *

PART 80--REGISTRATION OF FUELS AND FUEL ADDITIVES

0
7. The authority citation for part 80 continues to read as follows:

    Authority: 42 U.S.C. 7414, 7521, 7542, 7545, and 7601(a).

Subpart A--General Provisions

0
8. Revise Sec.  80.1 to read as follows:

Sec.  80.1  Scope.

    (a) This part prescribes regulations for the renewable fuel program 
under the Clean Air Act section 211(o) (42 U.S.C. 7545(o)).
    (b) This part also prescribes regulations for the labeling of fuel 
dispensing systems for oxygenated gasoline at retail under the Clean 
Air Act section 211(m)(4) (42 U.S.C. 7545(m)(4)).
    (c) Nothing in this part is intended to preempt the ability of 
state or local governments to control or prohibit any fuel or fuel 
additive for use in motor vehicles and motor vehicle engines which is 
not explicitly regulated by this part.
0
9. Revise Sec.  80.2 to read as follows:

Sec.  80.2  Definitions.

    Definitions apply in this part as described in this section.
    Administrator means the Administrator of the Environmental 
Protection Agency.
    Carrier means any distributor who transports or stores or causes 
the transportation or storage of gasoline or diesel fuel without taking 
title to or otherwise having any ownership of the gasoline or diesel 
fuel, and without altering either the quality or quantity of the 
gasoline or diesel fuel.
    Category 3 marine vessels, for the purposes of this part 80, are 
vessels that are propelled by engines meeting the definition of 
``Category 3'' in 40 CFR 1042.901.
    CBOB means gasoline blendstock that could become conventional 
gasoline solely upon the addition of oxygenate.
    Control area means a geographic area in which only oxygenated 
gasoline under the oxygenated gasoline program may be sold or 
dispensed, with boundaries determined by Clean Air Act section 211(m).
    Control period means the period during which oxygenated gasoline 
must be sold or dispensed in any control area, pursuant to Clean Air 
Act section 211(m)(2).
    Conventional gasoline or CG means any gasoline that has been 
certified under Sec.  1090.1100(b) and is not RFG.
    Diesel fuel means any fuel sold in any State or Territory of the 
United States and suitable for use in diesel engines, and that is one 
of the following:
    (1) A distillate fuel commonly or commercially known or sold as No. 
1 diesel fuel or No. 2 diesel fuel;
    (2) A non-distillate fuel other than residual fuel with comparable 
physical and chemical properties (e.g., biodiesel fuel); or
    (3) A mixture of fuels meeting the criteria of paragraphs (1) and 
(2) of this definition.
    Distillate fuel means diesel fuel and other petroleum fuels that 
can be used in engines that are designed for diesel fuel. For example, 
jet fuel, heating oil, kerosene, No. 4 fuel, DMX, DMA, DMB, and DMC are 
distillate fuels; and natural gas, LPG, gasoline, and residual fuel are 
not distillate fuels. Blends containing residual fuel may be distillate 
fuels.
    Distributor means any person who transports or stores or causes the 
transportation or storage of gasoline or diesel fuel at any point 
between any gasoline or diesel fuel refinery or importer's facility and 
any retail outlet or wholesale purchaser-consumer's facility.
    ECA marine fuel is diesel, distillate, or residual fuel that meets 
the criteria of paragraph (1) of this definition, but not the criteria 
of paragraph (2) of this definition.
    (1) All diesel, distillate, or residual fuel used, intended for 
use, or made available for use in Category 3 marine vessels while the 
vessels are operating within an Emission Control Area (ECA), or an ECA 
associated area, is ECA marine fuel, unless it meets the criteria of 
paragraph (ttt)(2) of this section.
    (2) ECA marine fuel does not include any of the following fuel:
    (i) Fuel used by exempted or excluded vessels (such as exempted 
steamships), or fuel used by vessels allowed by the U.S. government 
pursuant to MARPOL Annex VI Regulation 3 or Regulation 4 to exceed the 
fuel sulfur limits while operating in an ECA or an ECA associated area 
(see 33 U.S.C. 1903).
    (ii) Fuel that conforms fully to the requirements of this part for 
MVNRLM diesel fuel (including being designated as MVNRLM).
    (iii) Fuel used, or made available for use, in any diesel engines 
not installed on a Category 3 marine vessel.
    Gasoline means any fuel sold in any State \1\ for use in motor 
vehicles and motor vehicle engines, and commonly or commercially known 
or sold as gasoline.
---------------------------------------------------------------------------

    \1\ State means a State, the District of Columbia, the 
Commonwealth of Puerto Rico, the Virgin Islands, Guam, American 
Samoa and the Commonwealth of the Northern Mariana Islands.
---------------------------------------------------------------------------

    Gasoline blendstock or component means any liquid compound that is 
blended with other liquid compounds to produce gasoline.
    Gasoline blendstock for oxygenate blending or BOB has the meaning 
given in 40 CFR 1090.80.
    Gasoline treated as blendstock or GTAB means imported gasoline that 
is excluded from an import facility's compliance calculations, but is 
treated as blendstock in a related refinery that includes the GTAB in 
its refinery compliance calculations.
    Heating oil means any No. 1, No. 2, or non-petroleum diesel blend 
that is sold for use in furnaces, boilers, and similar applications and 
which is commonly or commercially known or sold as heating oil, fuel 
oil, and similar trade names, and that is not jet fuel, kerosene, or 
MVNRLM diesel fuel.
    Importer means a person who imports gasoline, gasoline blendstocks 
or components, or diesel fuel from a foreign country into the United 
States (including the Commonwealth of Puerto Rico, the Virgin Islands, 
Guam, American Samoa, and the Northern Mariana Islands).
    Jet fuel means any distillate fuel used, intended for use, or made 
available for use in aircraft.
    Kerosene means any No. 1 distillate fuel commonly or commercially 
sold as kerosene.
    Liquefied petroleum gas or LPG means a liquid hydrocarbon fuel that 
is stored under pressure and is composed primarily of species that are 
gases at atmospheric conditions (temperature = 25 [deg]C and pressure = 
1 atm), excluding natural gas.

[[Page 29094]]

    Locomotive engine means an engine used in a locomotive as defined 
under 40 CFR 92.2.
    Marine engine has the meaning given under 40 CFR 1042.901.
    MVNRLM diesel fuel means any diesel fuel or other distillate fuel 
that is used, intended for use, or made available for use in motor 
vehicles or motor vehicle engines, or as a fuel in any nonroad diesel 
engines, including locomotive and marine diesel engines, except the 
following: Distillate fuel with a T90 at or above 700 [deg]F that is 
used only in Category 2 and 3 marine engines is not MVNRLM diesel fuel, 
and ECA marine fuel is not MVNRLM diesel fuel (note that fuel that 
conforms to the requirements of MVNRLM diesel fuel is excluded from the 
definition of ``ECA marine fuel'' in this section without regard to its 
actual use). Use the distillation test method specified in 40 CFR 
1065.1010 to determine the T90 of the fuel.
    (1) Any diesel fuel that is sold for use in stationary engines that 
are required to meet the requirements of 40 CFR 1090.300, when such 
provisions are applicable to nonroad engines, is considered MVNRLM 
diesel fuel.
    (2) [Reserved]
    Natural gas means a fuel whose primary constituent is methane.
    Non-petroleum diesel means a diesel fuel that contains at least 80 
percent mono-alkyl esters of long chain fatty acids derived from 
vegetable oils or animal fats.
    Nonroad diesel engine means an engine that is designed to operate 
with diesel fuel that meets the definition of nonroad engine in 40 CFR 
1068.30, including locomotive and marine diesel engines.
    Oxygenate means any substance which, when added to gasoline, 
increases the oxygen content of that gasoline. Lawful use of any of the 
substances or any combination of these substances requires that they be 
``substantially similar'' under section 211(f)(1) of the Clean Air Act, 
or be permitted under a waiver granted by the Administrator under the 
authority of section 211(f)(4) of the Clean Air Act.
    Oxygenated gasoline means gasoline which contains a measurable 
amount of oxygenate.
    Refiner means any person who owns, leases, operates, controls, or 
supervises a refinery.
    Refinery means any facility, including but not limited to, a plant, 
tanker truck, or vessel where gasoline or diesel fuel is produced, 
including any facility at which blendstocks are combined to produce 
gasoline or diesel fuel, or at which blendstock is added to gasoline or 
diesel fuel.
    Reformulated gasoline or RFG means any gasoline whose formulation 
has been certified under Sec.  1090.1100(b), and which meets each of 
the standards and requirements prescribed under Sec.  1090.245.
    Reformulated gasoline blendstock for oxygenate blending, or RBOB 
means a petroleum product that, when blended with a specified type and 
percentage of oxygenate, meets the definition of reformulated gasoline, 
and to which the specified type and percentage of oxygenate is added 
other than by the refiner or importer of the RBOB at the refinery or 
import facility where the RBOB is produced or imported.
    Residual fuel means a petroleum fuel that can only be used in 
diesel engines if it is preheated before injection. For example, No. 5 
fuels, No. 6 fuels, and RM grade marine fuels are residual fuels. Note: 
Residual fuels do not necessarily require heating for storage or 
pumping.
    Retail outlet means any establishment at which gasoline, diesel 
fuel, natural gas or liquefied petroleum gas is sold or offered for 
sale for use in motor vehicles or nonroad engines, including locomotive 
or marine engines.
    Retailer means any person who owns, leases, operates, controls, or 
supervises a retail outlet.
    Wholesale purchaser-consumer means any person that is an ultimate 
consumer of gasoline, diesel fuel, natural gas, or liquefied petroleum 
gas and which purchases or obtains gasoline, diesel fuel, natural gas 
or liquefied petroleum gas from a supplier for use in motor vehicles or 
nonroad engines, including locomotive or marine engines and, in the 
case of gasoline, diesel fuel, or liquefied petroleum gas, receives 
delivery of that product into a storage tank of at least 550-gallon 
capacity substantially under the control of that person.

Sec.  80.3  [Removed and reserved]

0
10. Remove and reserve Sec.  80.3.

Sec.  80.7  [Amended]

0
11. In Sec.  80.7 amend paragraph (c), by removing ``Sec.  80.22'' in 
second sentence and adding ``40 CFR 1090.1550'' in its place.

Subparts B, D, E, F, G, H, I, J, K, L, N, and O and Appendices A 
and B to Part 80 [Removed and reserved]

0
12. Remove and reserve subparts B, D, E, F, G, H, I, J, K, L, N, and O 
and appendices A and B to Part 80.

Subpart M--Renewable Fuel Standard

0
13. Amend Sec.  80.1401 by:
0
a. Revising paragraph (2) in the definition of ``Fuel for use in an 
ocean-going vessel'';
0
b. Revising paragraph (1) in the definition of ``Heating oil''; and
0
c. Revising the definitions of ``Renewable gasoline'' and ``Renewable 
gasoline blendstock''.
    The revisions read as follows:

Sec.  80.1401   Definitions.

* * * * *
    Fuel for use in an ocean-going vessel * * *
    (2) Emission Control Area (ECA) marine fuel, pursuant to Sec.  80.2 
and 40 CFR 1090.80 (whether burned in ocean waters, Great Lakes, or 
other internal waters); and
* * * * *
    Heating oil * * *
    (1) A fuel meeting the definition of heating oil set forth in Sec.  
80.2; or
* * * * *
    Renewable gasoline means renewable fuel made from renewable biomass 
that is composed of only hydrocarbons and which meets the definition of 
gasoline in Sec.  80.2.
    Renewable gasoline blendstock means a blendstock made from 
renewable biomass that is composed of only hydrocarbons and which meets 
the definition of gasoline blendstock in Sec.  80.2.
* * * * *
0
14. Amend Sec.  80.1407 by revising paragraph (f)(7) to read as 
follows:

Sec.  80.1407  How are the Renewable Volume Obligations calculated?

* * * * *
    (f) * * *
    (7) Transmix gasoline product (as defined in 40 CFR 1090.80) and 
transmix distillate product (as defined in 40 CFR 1090.80) produced by 
a transmix processor, and transmix blended into gasoline or diesel fuel 
by a transmix blender under 40 CFR 1090.505.
* * * * *
0
15. Amend Sec.  80.1416 by revising paragraph (b)(1)(i) to read as 
follows:

Sec.  80.1416   Petition process for evaluation of new renewable fuels 
pathways.

* * * * *
    (b) * * *
    (1) * * *
    (i) The information specified under 40 CFR 1090.805.
* * * * *
0
16. Amend Sec.  80.1427 by revising paragraph (a)(2) introductory text 
and removing and reserving paragraph (a)(4) to read as follows:

[[Page 29095]]

Sec.  80.1427   How are RINs used to demonstrate compliance?

    (a) * * *
    (2) RINs that are valid for use in complying with each Renewable 
Volume Obligation are determined by their D codes.
* * * * *
0
17. Amend Sec.  80.1429 by:
0
a. Revising paragraph (b)(9) introductory text; and
0
b. Removing paragraphs (f) and (g).
    The revision reads as follows:

Sec.  80.1429   Requirements for separating RINs from volumes of 
renewable fuel.

* * * * *
    (b) * * *
    (9) Except as provided in paragraphs (b)(2) through (b)(5) and 
(b)(8) of this section, parties whose non-export renewable volume 
obligations are solely related to either the importation of products 
listed in Sec.  80.1407(c) or Sec.  80.1407(e) or to the addition of 
blendstocks into a volume of finished gasoline, finished diesel fuel, 
or BOB, can only separate RINs from volumes of renewable fuel if the 
number of gallon-RINs separated in a calendar year is less than or 
equal to a limit set as follows:
* * * * *

Sec.  80.1441  [Amended]

0
18. Amend Sec.  80.1441 by removing paragraph (a)(6).

Sec.  80.1442  [Amended]

0
19. Amend Sec.  80.1442 by removing paragraphs (a)(3) and (b)(6).
0
20. Amend Sec.  80.1450 by:
0
a. Revising the first sentence in paragraph (a);
0
b. Revising the first sentence in paragraph (b) introductory text;
0
c. Revising the first sentence in paragraph (c);
0
d. Revising the last sentence in paragraph (d)(3)(iii);
0
e. Revising the first sentence in paragraph (e); and
0
f. Revising paragraph (g)(1).
    The revisions read as follows:

Sec.  80.1450   What are the registration requirements under the RFS 
program?

    (a) * * * Any obligated party described in Sec.  80.1406, and any 
exporter of renewable fuel described in Sec.  80.1430, must provide EPA 
with the information specified for registration under 40 CFR 1090.805, 
if such information has not already been provided under the provisions 
of this part. * * *
    (b) * * * Any RIN-generating foreign or domestic producer of 
renewable fuel, any foreign renewable fuel producer that sells 
renewable fuel for RIN generation by a United States importer, or any 
foreign ethanol producer that produces ethanol used in renewable fuel 
for which RINs are generated by a United States importer, must provide 
EPA the information specified under 40 CFR 1090.805 if such information 
has not already been provided under the provisions of this part, and 
must receive EPA-issued company and facility identification numbers 
prior to the generation of any RINs for their fuel or for fuel made 
with their ethanol. * * *
* * * * *
    (c) * * * Importers of renewable fuel must provide EPA the 
information specified under 40 CFR 1090.805, if such information has 
not already been provided under the provisions of this part and must 
receive an EPA-issued company identification number prior to generating 
or owning RINs. * * *
    (d) * * *
    (3) * * *
    (iii) * * * The representative sample must be selected in 
accordance with the sample size guidelines set forth at 40 CFR 
1090.1805.
    (e) Any party who owns RINs, intends to own RINs, or intends to 
allow another party to separate RINs as per Sec.  80.1440, but who is 
not covered by paragraph (a), (b), or (c) of this section, must provide 
EPA the information specified under 40 CFR 1090.805, if such 
information has not already been provided under the provisions of this 
part and must receive an EPA-issued company identification number prior 
to owning any RINs. * * *
* * * * *
    (g) * * *
    (1) The information specified under 40 CFR 1090.805, if such 
information has not already been provided under the provisions of this 
part.
* * * * *
0
21. Amend Sec.  80.1454 by revising paragraph (h)(2)(i) to read as 
follows:

Sec.  80.1454   What are the recordkeeping requirements under the RFS 
program?

* * * * *
    (h) * * *
    (2) * * *
    (i) Planned and conducted by an independent surveyor that meets the 
requirements in 40 CFR 1090.55.
* * * * *
0
22. Amend Sec.  80.1464 by:
0
a. Revising the first sentence of the introductory text;
0
b. Revising the first sentence in paragraph (a)(1)(iii); and
0
c. Revising paragraphs (a)(1)(iv)(D), (a)(2)(i), (b)(1)(iv), 
(b)(1)(v)(A), (b)(2)(i), and (c)(1)(i).
    The revisions read as follows:

Sec.  80.1464   What are the attest engagement requirements under the 
RFS program?

    The requirements regarding annual attest engagements in 40 CFR 
1090.1800 also apply to any attest engagement procedures required under 
this subpart M. * * *
    (a) * * *
    (1) * * *
    (iii) For obligated parties, compare the volumes of products listed 
in Sec.  80.1407(c) and (e) reported to EPA in the report required 
under Sec.  80.1451(a)(1) with the volumes, excluding any renewable 
fuel volumes, contained in the inventory reconciliation analysis under 
40 CFR 1090.1810(b) and the volume of non-renewable diesel produced or 
imported. * * *
    (iv) * * *
    (D) Select sample batches in accordance with the guidelines in 40 
CFR 1090.1805 from each separate category of renewable fuel exported 
and identified in Sec.  80.1451(a); obtain invoices, bills of lading 
and other documentation for the representative samples; state whether 
any of these documents refer to the exported fuel as advanced biofuel 
or cellulosic biofuel; and report as a finding whether or not the 
exporter calculated an advanced biofuel or cellulosic biofuel RVO for 
these fuels pursuant to Sec.  80.1430(b)(1) or Sec.  80.1430(b)(3).
* * * * *
    (2) * * *
    (i) Obtain and read copies of a representative sample, selected in 
accordance with the guidelines in 40 CFR 1090.1805, of each RIN 
transaction type (RINs purchased, RINs sold, RINs retired, RINs 
separated, RINs reinstated) included in the RIN transaction reports 
required under Sec.  80.1451(a)(2) for the compliance year.
* * * * *
    (b) * * *
    (1) * * *
    (iv) Obtain product transfer documents for a representative sample, 
selected in accordance with the guidelines in 40 CFR 1090.1805, of 
renewable fuel batches produced or imported during the year being 
reviewed; verify that the product transfer documents contain the 
applicable information required under Sec.  80.1453; verify the 
accuracy of the information contained in the product transfer 
documents; report as a finding any product transfer document that does 
not contain the applicable information required under Sec.  80.1453.
    (v)(A) Obtain documentation, as required under Sec.  80.1451(b), 
(d), and (e) associated with feedstock purchases for a representative 
sample, selected in

[[Page 29096]]

accordance with the guidelines in 40 CFR 1090.1805, of renewable fuel 
batches produced or imported during the year being reviewed.
* * * * *
    (2) * * *
    (i) Obtain and read copies of a representative sample, selected in 
accordance with the guidelines in 40 CFR 1090.1805, of each transaction 
type (RINs purchased, RINs sold, RINs retired, RINs separated, RINs 
reinstated) included in the RIN transaction reports required under 
Sec.  80.1451(b)(2) for the compliance year.
* * * * *
    (c) * * *
    (1) * * *
    (i) Obtain and read copies of a representative sample, selected in 
accordance with the guidelines in 40 CFR 1090.1805, of each RIN 
transaction type (RINs purchased, RINs sold, RINs retired, RINs 
separated, RINs reinstated) included in the RIN transaction reports 
required under Sec.  80.1451(c)(1) for the compliance year.
* * * * *

Sec.  80.1465   [Removed and reserved]

0
23. Remove and reserve Sec.  80.1465.
0
24. Amend Sec.  80.1466 by:
0
a. Revising paragraph (d)(3)(ii), paragraph (m)(3) introductory text, 
and paragraph (m)(4) introductory text;
0
b. Revising the second sentence in paragraph (m)(5); and
0
c. Revising paragraphs (m)(6)(ii) and (iii).
    The revisions reads as follows:

Sec.  80.1466   What are the additional requirements under this subpart 
for RIN-generating foreign producers and importers of renewable fuels 
for which RINs have been generated by the foreign producer?

* * * * *
    (d) * * *
    (3) * * *
    (ii) Be independent under the criteria specified in 40 CFR 1090.55; 
and
* * * * *
    (m) * * *
    (3) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRRF, in 
accordance with the guidelines in 40 CFR 1090.1805, and for each vessel 
selected perform all the following:
* * * * *
    (4) Select a sample from the list of vessels identified in 
paragraph (m)(2) of this section used to transport RFS-FRRF, in 
accordance with the guidelines in 40 CFR 1090.1805, and for each vessel 
selected perform the following:
* * * * *
    (5) * * * Select a sample from this listing in accordance with the 
guidelines in 40 CFR 1090.1805, and obtain a commercial document of 
general circulation that lists vessel arrivals and departures, and that 
includes the port and date of departure and the ports and dates where 
the renewable fuel was offloaded for the selected vessels. * * *
    (6) * * *
    (ii) Be licensed as a Certified Public Accountant in the United 
States and a citizen of the United States, or be approved in advance by 
EPA based on a demonstration of ability to perform the procedures 
required in 40 CFR 1090.1800, Sec.  80.1464, and this paragraph (m); 
and
    (iii) Sign a commitment that contains the provisions specified in 
paragraph (f) of this section with regard to activities and documents 
relevant to compliance with the requirements of 40 CFR 1090.1800, Sec.  
80.1464, and this paragraph (m).
* * * * *
0
25. Amend Sec.  80.1467 by revising paragraphs (h)(2) and (3) to read 
as follows:

Sec.  80.1467   What are the additional requirements under this subpart 
for a foreign RIN owner?

* * * * *
    (h) * * *
    (2) The attest auditor must be licensed as a Certified Public 
Accountant in the United States and a citizen of the United States, or 
be approved in advance by EPA based on a demonstration of ability to 
perform the procedures required in 40 CFR 1090.1800 and Sec.  80.1464.
    (3) The attest auditor must sign a commitment that contains the 
provisions specified in paragraph (c) of this section with regard to 
activities and documents relevant to compliance with the requirements 
of 40 CFR 1090.1800 and Sec.  80.1464.
* * * * *
0
26. Amend Sec.  80.1469 by revising paragraph (c)(5) to read as 
follows:

Sec.  80.1469   Requirements for Quality Assurance Plans.

* * * * *
    (c) * * *
    (5) Representative sampling. Independent third-party auditors may 
use a representative sample of batches of renewable fuel in accordance 
with the procedures described in 40 CFR 1090.1805 for all components of 
this paragraph (c) except for paragraphs (c)(1)(ii), (c)(1)(iii), 
(c)(2)(ii), (c)(3)(vi), (c)(4)(ii), and (c)(4)(iii) of this section.
* * * * *

PART 86--CONTROL OF EMISSIONS FROM NEW AND IN-USE HIGHWAY VEHICLES 
AND ENGINES

0
27. The authority citation for part 86 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

0
28. Amend Sec.  86.1810-17 by adding paragraph (j) to read as follows:

Sec.  86.1810-17   General requirements.

* * * * *
    (j) Gasoline-fueled vehicles must have a refueling inlet that 
allows insertion of the refueling nozzle specified in 40 CFR 
1090.1550(a), and does not allow insertion of a nozzle with an outside 
diameter at or above 24 mm.

PART 1037--CONTROL OF EMISSIONS FROM NEW HEAVY-DUTY MOTOR VEHICLES

0
29. The authority citation for part 1037 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

0
30. Amend Sec.  1037.115 by revising paragraph (c) to read as follows:

Sec.  1037.115   Other requirements.

* * * * *
    (c) Gasoline-fueled vehicles must have a refueling inlet that 
allows insertion of the refueling nozzle specified in 40 CFR 
1090.1550(a), and does not allow insertion of a nozzle with an outside 
diameter at or above 24 mm.
* * * * *
0
31. Add part 1090 to read as follows:

PART 1090--REGULATION OF FUELS, FUEL ADDITIVES, AND REGULATED 
BLENDSTOCKS

Subpart A--General Provisions
Sec.
1090.1 Applicability and relationship to other parts.
1090.5 Implementation dates.
1090.10 Contacting EPA.
1090.15 Confidential business information.
1090.20 Approval of submissions under this part.
1090.50 Rounding.
1090.55 Requirements for independent parties.
1090.80 Definitions.
1090.85 Explanatory terms.
1090.90 Acronyms and abbreviations.
1090.95 Incorporation by reference.
Subpart B--General Requirements and Provisions for Regulated Parties
1090.100 General provisions.
1090.105 Fuel manufacturers.
1090.110 Detergent blenders.
1090.115 Oxygenate blenders.
1090.120 Oxygenate producers.
1090.125 Certified butane producers.
1090.130 Certified butane blenders.

[[Page 29097]]

1090.135 Certified pentane producers.
1090.140 Certified pentane blenders.
1090.145 Transmix processors.
1090.150 Transmix blenders.
1090.155 Fuel additive manufacturers.
1090.160 Distributors, carriers, and resellers.
1090.165 Retailers and WPCs.
1090.170 Independent surveyors.
1090.175 Auditors.
1090.180 Pipeline operators.
Subpart C--Gasoline Standards
1090.200 Overview and general requirements.
1090.205 Sulfur standards.
1090.210 Benzene standards.
1090.215 Gasoline RVP standards.
1090.220 Certified butane standards.
1090.225 Certified pentane standards.
1090.230 Gasoline oxygenate standards.
1090.235 Ethanol denaturant standards.
1090.240 Gasoline deposit control standards.
1090.245 RFG standards.
1090.250 Anti-dumping standards.
1090.255 Gasoline additive standards.
1090.260 Gasoline substantially similar provisions.
1090.265 Requirements for E15.
1090.270 RFG covered areas.
1090.275 Changes to RFG covered areas and procedures for opting out 
of RFG.
1090.280 Procedures for relaxing the federal 7.8 psi RVP standard.
Subpart D--Diesel Fuel and ECA Marine Fuel Standards
1090.300 Overview and general requirements.
1090.305 ULSD standards.
1090.310 Diesel fuel additives standards.
1090.315 Heating oil, kerosene, and jet fuel provisions.
1090.320 500 ppm LM diesel fuel standards.
1090.325 ECA marine fuel standards.
Subpart E--Reserved
Subpart F--Transmix and Pipeline Interface Provisions
1090.500 Scope.
1090.505 Gasoline produced from blending transmix into PCG.
1090.510 Gasoline produced from TGP.
1090.515 ULSD produced from TDP.
1090.520 500 ppm LM diesel fuel produced from TDP.
1090.525 Handling practices for pipeline interface that is not 
transmix.
Subpart G--Exemptions, Hardships, and Special Provisions
1090.600 General provisions.
1090.605 National security and military use exemptions.
1090.610 Temporary research, development, and testing exemptions.
1090.615 Racing and aviation exemptions.
1090.620 Exemptions for Guam, American Samoa, and the Commonwealth 
of the Northern Mariana Islands.
1090.625 Exemptions for California gasoline and diesel fuel.
1090.630 Exemptions for Alaska, Hawaii, Puerto Rico, and the U.S. 
Virgin Islands summer gasoline.
1090.635 Refinery extreme unforeseen hardship exemption.
1090.640 Exemptions from the gasoline deposit control requirements.
1090.645 Exemption for exports of fuels, fuel additives, and 
regulated blendstocks.
1090.650 Distillate global marine fuel exemption.
Subpart H--Averaging, Banking, and Trading Provisions
1090.700 Compliance with average standards.
1090.705 Facility level compliance.
1090.710 Downstream oxygenate accounting.
1090.715 Deficit carryforward.
1090.720 Credit use.
1090.725 Credit generation.
1090.730 Credit transfers.
1090.735 Invalid credits and remedial actions.
1090.740 Downstream BOB recertification.
1090.745 Informational annual average calculations.
Subpart I--Registration
1090.800 General provisions.
1090.805 Contents of registration.
1090.810 Voluntary cancellation of company or facility registration.
1090.815 Deactivation (involuntary cancellation) of registration.
1090.820 Changes of ownership.
Subpart J--Reporting
1090.900 General provisions.
1090.905 Annual, batch, and credit transaction reporting for 
gasoline manufacturers.
1090.910 Reporting for gasoline manufacturers that recertify BOB to 
gasoline.
1090.915 Batch reporting for oxygenate producers and importers.
1090.920 Reports by certified pentane producers.
1090.925 Reports by independent surveyors.
1090.930 Reports by auditors.
1090.935 Reports by diesel manufacturers.
Subpart K--Batch Certification, Designation, and Product Transfer 
Documents

Batch Certification and Designation

1090.1100 Batch certification requirements.
1090.1105 Designation of batches of fuels, fuel additives, and 
regulated blendstocks.
1090.1110 Designation requirements for gasoline.
1090.1115 Designation requirements for diesel and distillate fuels.
1090.1120 Batch numbering.

Product Transfer Documents

1090.1150 General PTD provisions.
1090.1155 PTD requirements for exempted fuels.
1090.1160 Gasoline, gasoline additive, and gasoline regulated 
blendstock PTD provisions.
1090.1165 PTD requirements for distillate and residual fuels.
1090.1170 Diesel fuel additives language requirements.
1090.1175 Alternative PTD language provisions.
Subpart L--Recordkeeping
1090.1200 General recordkeeping requirements.
1090.1205 Recordkeeping requirements for all regulated parties.
1090.1210 Recordkeeping requirements for gasoline manufacturers.
1090.1215 Recordkeeping requirements for diesel fuel and ECA marine 
fuel manufacturers.
1090.1220 Recordkeeping requirements for oxygenate blenders.
1090.1225 Recordkeeping requirements for gasoline additives.
1090.1230 Recordkeeping requirements for oxygenate producers.
1090.1235 Recordkeeping requirements for ethanol denaturant.
1090.1240 Recordkeeping requirements for gasoline detergent 
blenders.
1090.1245 Recordkeeping requirements for independent surveyors.
1090.1250 Recordkeeping requirements for auditors.
1090.1255 Recordkeeping requirements for transmix processors, 
transmix blenders, transmix distributors, and pipeline operators.
Subpart M--Sampling, Testing, and Retention
1090.1300 General provisions.

Scope of Testing

1090.1310 Testing to demonstrate compliance with standards.
1090.1315 In-line blending.
1090.1320 Adding blendstock to PCG.
1090.1325 Adding blendstock to TGP.
1090.1330 Preparing denatured fuel ethanol.

Handling and Preparing Samples

1090.1335 Collecting and preparing samples for testing.
1090.1337 Demonstrating homogeneity.
1090.1340 Preparing a hand blend from BOB.
1090.1345 Retaining samples.

Measurement Procedures

1090.1350 Overview of test procedures.
1090.1355 Calculation adjustments and corrections.
1090.1360 Performance-based Measurement System.
1090.1365 Qualifying criteria for alternative measurement 
procedures.
1090.1370 Qualifying criteria for reference installations.
1090.1375 Quality control procedures.

Testing Related to Gasoline Deposit Control

1090.1390 Requirement for Automated Detergent Blending Equipment 
Calibration.
1090.1395 Gasoline deposit control test procedures.
Subpart N--Survey Provisions
1090.1400 National fuels survey program participation.

[[Page 29098]]

1090.1405 National fuels survey program requirements.
1090.1410 Independent surveyor requirements.
1090.1415 Survey plan design requirements.
1090.1420 Additional requirements for E15 misfueling mitigation 
surveying.
1090.1425 Program plan approval process.
1090.1430 Independent surveyor contract.
1090.1440 National sampling oversight program requirements.
Subpart O--Retailer and Wholesale Purchaser-Consumer Provisions
1090.1500 Overview.

Labeling

1090.1510 E15 labeling provisions.
1090.1515 Diesel sulfur labeling provisions.

Refueling Hardware

1090.1550 Requirements for gasoline dispensing nozzles used with 
motor vehicles.
1090.1555 Requirements for gasoline dispensing nozzles used 
primarily with marine vessels.
1090.1560 Requirements related to dispensing natural gas.
1090.1565 Requirements related to dispensing liquefied petroleum 
gas.
Subpart P--Importer and Exporter Provisions
1090.1600 General provisions for importers.
1090.1605 Importation by marine vessel.
1090.1610 Importation by rail or truck.
1090.1615 Gasoline treated as a blendstock.
1090.1650 General provisions for exporters.
Subpart Q--Compliance and Enforcement Provisions
1090.1700 Prohibited acts.
1090.1705 Evidence related to violations.
1090.1710 Penalties.
1090.1715 Liability provisions.
1090.1720 Affirmative defense provisions related to noncompliant 
fuel, fuel additive, or regulated blendstock.
Subpart R--Attestation Engagements
1090.1800 General provisions.
1090.1805 Representative samples.
1090.1810 General procedures--gasoline manufacturers.
1090.1815 General procedures--gasoline importers.
1090.1820 Additional procedures for gasoline treated as blendstock.
1090.1825 Additional procedures for PCG used to produce gasoline.
1090.1830 Alternative procedures for certified butane blenders.
1090.1835 Alternative procedures for certified pentane blenders.
1090.1840 Additional procedures related to compliance with gasoline 
average standards.
1090.1845 Procedures related to meeting performance-based 
measurement and statistical quality control for test methods.
1090.1850 Procedures related to in-line blending waivers.

    Authority:  42 U.S.C. 7414, 7521, 7522-7525, 7541, 7542, 7543, 
7545, 7547, 7550, and 7601.

Subpart A--General Provisions

Sec.  1090.1   Applicability and relationship to other parts.

    (a) This part specifies fuel quality standards for gasoline and 
diesel fuel in the United States. Additional requirements apply for 
fuel used in certain marine applications, as specified in paragraph (b) 
of this section.
    (1) The regulations include standards for fuel parameters that 
directly or indirectly affect vehicle, engine, and equipment emissions, 
air quality, and public health. The regulations also include standards 
and requirements for fuel additives and regulated blendstocks that are 
components of the fuels regulated under this part.
    (2) This part also specifies requirements for any person that 
engages in activities associated with the production, distribution, 
storage, and sale of fuels, fuel additives, and regulated blendstocks, 
such as collecting and testing samples for regulated parameters, 
reporting information to EPA to demonstrate compliance with fuel 
quality requirements, and performing other compliance measures to 
implement the standards. Parties that produce and distribute other 
related products, such as heating oil, may need to meet certain 
reporting, recordkeeping, labeling, or other requirements of this part.
    (b)(1) The International Convention for the Prevention of Pollution 
from Ships, 1973 as modified by the Protocol of 1978 Annex VI (``MARPOL 
Annex VI'') is an international treaty that sets maximum fuel sulfur 
levels for fuel used in vessels, including separate standards for 
vessels navigating in a designated Emission Control Area (ECA). These 
standards and related requirements are specified in 40 CFR part 1043. 
This part also sets corresponding sulfur standards that apply to any 
person who produces or handles ECA marine fuel.
    (2) This part also includes requirements for parties involved in 
the production and distribution of IMO marine fuel, such as collecting 
and testing samples of fuels for regulated parameters, reporting 
information to EPA to demonstrate compliance with fuel quality 
requirements, and performing other compliance measures to implement the 
standards.
    (c) The requirements for the registration of fuel and fuel 
additives under 42 U.S.C. 7545(a), (b), and (e) are specified in 40 CFR 
part 79. Parties that must meet the requirements of this part may also 
need to comply with the requirements for the registration of fuel and 
fuel additives under 40 CFR part 79.
    (d) The requirements for the Renewable Fuel Standard (RFS) are 
specified in 40 CFR part 80, subpart M. Parties that must meet the 
requirements of this part may also need to comply with the requirements 
for the RFS program under 40 CFR part 80, subpart M.
    (e) Nothing in this part is intended to preempt the ability of 
state or local governments to control or prohibit any fuel or fuel 
additive for use in motor vehicles and motor vehicle engines that is 
not explicitly regulated by this part.

Sec.  1090.5   Implementation dates.

    (a) The provisions of this part apply beginning January 1, 2021, 
unless otherwise specified.
    (b) The following provisions of 40 CFR part 80 are applicable after 
December 31, 2020:
    (1) Positive gasoline sulfur and benzene credit balances and 
deficits from the 2020 compliance period carry forward for 
demonstrating compliance with requirements of this part. Any 
restrictions that apply to credits and deficits under 40 CFR part 80, 
such as a maximum credit life of 5 years, continue to apply under this 
part.
    (2) Unless otherwise specified (e.g., in-line blending waivers as 
specified in Sec.  1090.1315(b)), any approval granted under 40 CFR 
part 80 continues to be in effect under this part. For example, if EPA 
approved the use of alternate labeling under 40 CFR part 80, that 
approval continues to be valid under this part, subject to any 
conditions specified for the approval.
    (3) Unless otherwise specified, regulated parties must use the 
provisions of 40 CFR part 80 in 2021 to demonstrate compliance with 
regulatory requirements for the 2020 calendar year. This applies to 
calculating credits for the 2020 compliance period, and to any 
sampling, testing, reporting, and auditing related to fuels, fuel 
additives, and regulated blendstocks produced or imported in 2020.
    (4) Any testing to establish the precision and accuracy of 
alternative test procedures under 40 CFR part 80 continues to be valid 
under this part.
    (5) Requirements to keep records and retain fuel samples related to 
actions taken before January 1, 2021, continue to be in effect, as 
specified in 40 CFR part 80.

Sec.  1090.10   Contacting EPA.

    Parties must submit all reports, registrations, and documents for

[[Page 29099]]

approval required under this part electronically to EPA using forms and 
procedures specified by EPA via the following website: https://www.epa.gov/fuels-registration-reporting-and-compliance-help.

Sec.  1090.15   Confidential business information.

    (a) Except as specified in paragraphs (b) and (c) of this section, 
any information submitted under this part claimed as confidential 
remains subject to evaluation by EPA under 40 CFR part 2, subpart B.
    (b) The following information contained in submissions under this 
part that have been accepted by EPA for evaluation is not entitled to 
confidential treatment under 40 CFR part 2, subpart B or 5 U.S.C. 
552(b)(4):
    (1) Submitter's name.
    (2) The name and location of the facility for which relief is 
requested, if applicable.
    (3) The general nature of the request.
    (4) The relevant time period for the request, if applicable.
    (c) The following information incorporated into EPA determinations 
on submissions under this section is not entitled to confidential 
treatment under 40 CFR part 2, subpart B or 5 U.S.C. 552(b)(4):
    (1) Submitter's name.
    (2) The name and location of the facility for which relief was 
requested, if applicable.
    (3) The general nature of the request.
    (4) The relevant time period for the request, if applicable.
    (5) The extent to which EPA either granted or denied the request 
and any relevant conditions.
    (d) EPA may disclose the information specified in paragraphs (b) 
and (c) of this section on its website, or otherwise make it available 
to interested parties, without additional notice, notwithstanding any 
claims that the information is entitled to confidential treatment under 
40 CFR part 2, subpart B and 5 U.S.C. 552(b)(4).

Sec.  1090.20   Approval of submissions under this part.

    (a) EPA may approve any submission required or allowed under this 
part if the request for approval satisfies all specified requirements.
    (b) EPA will deny any request for approval if the submission is 
incomplete, contains inaccurate or misleading information, or does not 
meet all specified requirements.
    (c) EPA may revoke any prior approval under this part for cause. 
For cause includes, but is not limited to, any of the following:
    (1) The approval has proved inadequate in practice.
    (2) The party fails to notify EPA if information that the approval 
was based on substantively changed after the approval was granted.
    (d) EPA may also revoke and void any approval under this part 
effective from the approval date for cause. Cause for voiding an 
approval includes, but is not limited to, any of the following:
    (1) The approval was not fully or diligently implemented
    (2) The approval was based on false, misleading, or inaccurate 
information
    (3) Failure of a party to fulfill or cause to be fulfilled any term 
or condition of an approval under this part.
    (e) Any person that has an approval revoked or voided under this 
part is liable for any resulting violation of the requirements of this 
part.

Sec.  1090.50   Rounding.

    (a) Complying with this part requires rounding final values, such 
as sulfur test results and volume of gasoline. Do not round 
intermediate values to transfer data unless the rounded number has at 
least 6 significant digits.
    (b) Unless otherwise specified, round values to the number of 
significant digits necessary to match the number of decimal places of 
the applicable standard or specification. Perform all rounding as 
specified in 40 CFR 1065.20(e)(1) through (6). This convention is 
consistent with ASTM E29 and NIST SP 811.
    (c) When calculating a specified percentage of a given value, the 
specified percentage is understood to have infinite precision. For 
example, if an allowable limit is specified as a fuel volume 
representing 1 percent of total volume produced, calculate the 
allowable volume by multiplying total volume by exactly 0.01.
    (d) Measurement devices that incorporate internal rounding may be 
used, consistent with the following provisions:
    (1) Devices may use any rounding convention if they report 6 or 
more significant digits.
    (2) Devices that report fewer than 6 significant digits may be 
used, consistent with the accuracy and repeatability specifications of 
the procedures specified in subpart M of this part.
    (e) Use one of the following rounding conventions for all batch 
volumes in a given compliance period, and for all reporting under this 
part:
    (1) Identify batch volume in gallons to the nearest whole gallon.
    (2)(i) Round batch volumes between 1,000 and 10,000 gallons to the 
nearest 10 gallons.
    (ii) Round batch volumes above 10,000 gallons to the nearest 100 
gallons.

Sec.  1090.55   Requirements for independent parties.

    This section specifies how third parties demonstrate their 
independence from the regulated party that hires them and their 
technical ability to perform the specified services.
    (a) Independence. The independent third party, their contractors, 
subcontractors, and their organizations must be independent of the 
regulated party. All the criteria listed in paragraphs (a)(1) and (2) 
of this section must be met by every individual involved in the 
specified activities in this part that the independent third party is 
hired to perform for a regulated party, except as specified in 
paragraph (a)(3) of this section.
    (1) Employment criteria. No person employed by an independent third 
party, including contractor and subcontractor personnel, who is 
involved in a specified activity performed by the independent third 
party under the provisions of this part, may be employed, currently or 
previously, by the regulated party for any duration within the 3 years 
preceding the date when the regulated party hired the independent third 
party to provide services under this part.
    (2) Financial criteria. (i) The third-party's personnel, the third-
party's organization, or any organization or individual that may be 
contracted or subcontracted by the third party must meet all the 
following requirements:
    (A) Have received no more than one-quarter of their revenue from 
the regulated party during the year prior to the date of hire of the 
third party by the regulated party for any purpose.
    (B) Have no interest in the regulated party's business. Income 
received from the third party to perform specified activities under 
this part is excepted.
    (C) Not receive compensation for any specified activity in this 
part that is dependent on the outcome of the specified activity.
    (ii) The regulated party must be free from any interest in the 
third-party's business.
    (3) Exceptions. Auditors that meet the requirements in Sec.  
1090.1800(b)(1)(i) do not have to satisfy the employment and financial 
criteria in paragraphs (a)(1) and (2) of this section to be considered 
independent.
    (b) Technical ability. The third party must meet all the following 
requirements in order to demonstrate their technical capability to 
perform specified activities under this part:

[[Page 29100]]

    (1) Independent surveyors that conduct surveys under subpart N of 
this part must have personnel familiar with petroleum marketing, the 
sampling and testing of gasoline and diesel at retail stations, and the 
designing of surveys to estimate compliance rates or fuel parameters 
nationwide. Independent surveyors must demonstrate this technical 
ability in survey plans submitted under subpart N of this part.
    (2) Laboratories attempting to qualify alternative procedures must 
contract with an independent third party to verify the accuracy and 
precision of measured values as specified in Sec.  1090.1365. Such 
independent third parties must demonstrate work experience and a good 
working knowledge of the voluntary consensus standards specified in 
Sec. Sec.  1090.1365 and 1090.1370, with training and expertise 
corresponding to a bachelor's degree in chemical engineering, or 
combined bachelor's degrees in chemistry and statistics.
    (3) Auditors auditing in-line blending operations must demonstrate 
work experience and a good working knowledge of the voluntary consensus 
standards specified in Sec. Sec.  1090.1365 and 1090.1370.
    (c) Suspension and disbarment. Any person suspended or disbarred 
under 40 CFR part 32 or 48 CFR part 9, subpart 9.4, is not qualified to 
perform review functions under this part.

Sec.  1090.80   Definitions.

    500 ppm LM diesel fuel means diesel fuel subject to the alternative 
sulfur standards in Sec.  1090.320 for diesel fuel produced by transmix 
processors that may only be used in locomotive and marine engines that 
do not require the use of ULSD under 40 CFR parts 1033 and 1042, 
respectively.
    Additization means the addition of detergent to gasoline to create 
detergent-additized gasoline.
    Aggregated import facility means all import facilities within a 
PADD owned or operated by an importer and treated as a single fuel 
manufacturing facility to comply with the maximum benzene average 
standards under Sec.  1090.210(b).
    Anhydrous ethanol means ethanol that contains no more than 1.0 
volume percent water.
    Auditor means any person that conducts audits under subpart R of 
this part.
    Automated detergent blending facility means any facility 
(including, but not limited to, a truck or individual storage tank) at 
which detergents are blended with gasoline by means of an injector 
system calibrated to automatically deliver a specified amount of 
detergent.
    Average standard means a fuel standard applicable over a compliance 
period.
    Batch means a quantity of fuel, fuel additive, or regulated 
blendstock that has a homogeneous set of properties.
    Biodiesel means a diesel fuel that contains at least 80 percent 
mono-alkyl esters made from nonpetroleum feedstocks.
    Blender pump means any fuel dispenser where PCG is blended with a 
fuel that contains ethanol (including DFE) to produce gasoline that has 
an ethanol content greater than that of the PCG. Blender pumps are fuel 
blending facilities if PCG is blended with a fuel that contains 
anything other than PCG and DFE.
    Blending manufacturer means any person who owns, leases, operates, 
controls, or supervises a fuel blending facility in the United States.
    Blendstock means any liquid compound or mixture of compounds (not 
including fuel or fuel additive) that is used or intended for use as a 
component of a fuel.
    Business day means Monday through Friday, except the legal public 
holidays specified in 5 U.S.C. 6103 or any other day declared to be a 
holiday by federal statute or executive order.
    Butane means an organic compound with the formula 
C4H10.
    Butane blending facility means a fuel manufacturing facility where 
butane is blended into PCG.
    California diesel means diesel fuel designated by a diesel fuel 
manufacturer as for use in California.
    California gasoline means gasoline designated by a gasoline 
manufacturer as for use in California.
    Carrier means any distributor who transports or stores or causes 
the transportation or storage of fuel, fuel additive, or regulated 
blendstock without taking title to or otherwise having any ownership of 
the fuel, fuel additive, or regulated blendstock, and without altering 
either the quality or quantity of the fuel, fuel additive, or regulated 
blendstock.
    Category 1 (C1) marine vessel means a vessel that is propelled by 
an engine(s) meeting the definition of ``Category 1'' in 40 CFR part 
1042.901.
    Category 2 (C2) marine vessel means a vessel that is propelled by 
an engine(s) meeting the definition of ``Category 2'' in 40 CFR part 
1042.901.
    Category 3 (C3) marine vessel means a vessel that is propelled by 
an engine(s) meeting the definition of ``Category 3'' in 40 CFR part 
1042.901.
    CBOB means conventional gasoline for which a gasoline manufacturer 
has accounted for the effects of oxygenate blending that occurs 
downstream of the fuel manufacturing facility.
    Certified butane means butane that is certified to meet the 
requirements in Sec.  1090.220.
    Certified butane blender means a blending manufacturer that 
produces gasoline by blending certified butane into PCG, and that uses 
the provisions of Sec.  1090.1320 to meet the applicable sampling and 
testing requirements.
    Certified butane producer means a regulated blendstock producer 
that certifies butane as meeting the requirements in Sec.  1090.220.
    Certified ethanol denaturant means ethanol denaturant that is 
certified to meet the requirements in Sec.  1090.235.
    Certified ethanol denaturant producer means any person that 
certifies ethanol denaturant as meeting the requirements in Sec.  
1090.235.
    Certified pentane means pentane that is certified to meet the 
requirements in Sec.  1090.225.
    Certified pentane blender means a blending manufacturer that 
produces gasoline by blending certified pentane into PCG, and that uses 
the provisions of Sec.  1090.1320 to meet the applicable sampling and 
testing requirements.
    Certified pentane producer means a regulated blendstock producer 
that certifies pentane as meeting the requirements in Sec.  1090.225.
    Compliance period means the calendar year (January 1 through 
December 31).
    Conventional gasoline or CG means gasoline that is not certified to 
meet the requirements for RFG in Sec.  1090.245.
    Days means calendar days, including weekends and holidays.
    Denatured fuel ethanol or DFE means anhydrous ethanol that contains 
a denaturant to make it unfit for human consumption, as required and 
defined in 27 CFR parts 19 through 21, and that is produced or imported 
for blending into gasoline.
    Detergent means any chemical compound or combination of chemical 
compounds that is added to gasoline to control deposit formation and 
meets the requirements in Sec.  1090.240. Detergent may be part of a 
detergent additive package.
    Detergent additive package means an additive package containing 
detergent and may also contain carrier oils and non-detergent-active 
components such as corrosion inhibitors, antioxidants, metal 
deactivators, and handling solvents.
    Detergent blender means any person who owns, leases, operates, 
controls, or supervises the blending operation of a detergent blending 
facility, or imports detergent-additized gasoline.

[[Page 29101]]

    Detergent blending facility means any facility (including, but not 
limited to, a truck or individual storage tank) at which detergent is 
blended with gasoline.
    Detergent manufacturer means any person who owns, leases, operates, 
controls, or supervises a facility that produces detergent. Detergent 
manufacturers are fuel additive manufacturers.
    Detergent-additized gasoline or detergent gasoline means any 
gasoline that contains a detergent.
    Diesel fuel means any of the following:
    (1) Any fuel commonly or commercially known as diesel fuel.
    (2) Any fuel (including NP diesel fuel) that is intended or used to 
power a vehicle or engine that is designed to operate using diesel 
fuel, except for residual or gaseous fuel.
    (3) Any fuel that conforms to the specifications of ASTM D975 
(incorporated by reference in Sec.  1090.95) and is made available for 
use in a vehicle or engine designed to operate using diesel fuel.
    Diesel fuel manufacturer means a fuel manufacturer who owns, 
leases, operates, controls, or supervises a fuel manufacturing facility 
where diesel fuel is produced.
    Distillate fuel means diesel fuel and other petroleum fuels with a 
T90 temperature below 700 [deg]F that can be used in vehicles or 
engines that are designed to operate using diesel fuel. For example, 
diesel fuel, jet fuel, heating oil, No. 1 fuel (kerosene), No. 4 fuel, 
DMX, DMA, DMB, and DMC are distillate fuels. These specific fuel grades 
are identified in ASTM D975 and ISO 8217. Natural gas, LPG, and 
gasoline are not distillate fuels.
    Distributor means any person who transports, stores, or causes the 
transportation or storage of fuel, fuel additive, or regulated 
blendstock at any point between any fuel manufacturing facility, fuel 
additive manufacturing facility, or regulated blendstock production 
facility and any retail outlet or WPC facility.
    Downstream location means any point in the fuel distribution system 
other than a fuel manufacturing facility through which the fuel passes 
after it leaves the gate of the fuel manufacturing facility at which it 
was certified (e.g., fuel at facilities of distributors, pipelines, 
terminals, carriers, retailers, kerosene blenders, and WPCs).
    E0 means a gasoline that contains no ethanol. This is also known as 
neat gasoline.
    E10 means gasoline that contains at least 9 and no more than 10 
volume percent ethanol.
    E15 means gasoline that contains more than 10 and no more than 15 
volume percent ethanol.
    E85 means a fuel that contains more than 50 volume percent but no 
more than 83 volume percent ethanol and is used, intended for use, or 
made available for use in flex-fuel vehicles or flex-fuel engines.
    E200 means the distillation fraction of a fuel at 200 degrees 
Fahrenheit expressed as a volume percentage.
    E300 means the distillation fraction of a fuel at 300 degrees 
Fahrenheit expressed as a volume percentage.
    ECA marine fuel means diesel, distillate, or residual fuel used, 
intended for use, or made available for use in C3 marine vessels while 
the vessels are operating within an Emission Control Area (ECA), or an 
ECA associated area.
    Ethanol means an alcohol of the chemical formula 
C2H5OH.
    Ethanol denaturant means PCG, gasoline regulated blendstocks, or 
natural gasoline liquids that are added to anhydrous ethanol to make 
the ethanol unfit for human consumption as required and defined in 27 
CFR parts 19 through 21.
    Facility means any place, or series of places, where any fuel, fuel 
additive, or regulated blendstock is produced, imported, blended, 
transported, distributed, stored, or sold.
    Flex-fuel engine has the same meaning as flexible-fuel engine in 40 
CFR 1054.801.
    Flex-fuel vehicle has the same meaning as flexible-fuel vehicle in 
40 CFR 86.1803-01.
    Fuel means only the fuels regulated under this part, including 
gasoline, diesel fuel, and IMO marine fuel.
    Fuel additive means a substance that is designated for registration 
under 40 CFR part 79 and is added to fuel such that it amounts to less 
than 1.0 volume percent of the resultant mixture, or is an oxygenate 
added up to a level consistent with levels that are ``substantially 
similar'' under 42 U.S.C. 7545(f)(1) or as permitted under a waiver 
granted under 42 U.S.C. 7545(f)(4).
    Fuel additive blender means any person who blends fuel additive 
into fuel in the United States, or any person who owns, leases, 
operates, controls, or supervises such an operation in the United 
States.
    Fuel additive manufacturer means any person who owns, leases, 
operates, controls, or supervises a facility where fuel additives are 
produced or imported into the United States.
    Fuel blending facility means any facility, other than a refinery or 
transmix processing facility, where fuel is produced by combining 
blendstocks or by combining blendstocks with fuel. Types of blending 
facilities include, but are not limited to, terminals, storage tanks, 
plants, tanker trucks, retail outlets, and marine vessels.
    Fuel dispenser means any apparatus used to dispense fuel into motor 
vehicles, nonroad vehicles, engines, equipment, or portable fuel 
containers (as defined in 40 CFR 59.680).
    Fuel manufacturer means any person who owns, leases, operates, 
controls, or supervises a fuel manufacturing facility. Fuel 
manufacturers include refiners, importers, blending manufacturers, and 
transmix processors.
    Fuel manufacturing facility means any facility where fuels are 
produced, imported, or recertified. Fuel manufacturing facilities 
include refineries, fuel blending facilities, transmix processing 
facilities, import facilities, and any facility where fuel is 
recertified.
    Fuel manufacturing facility gate means the point where the fuel 
leaves the fuel manufacturing facility at which it was produced or 
imported by the fuel manufacturer.
    Gasoline means any of the following:
    (1) Any fuel commonly or commercially known as gasoline, including 
BOB.
    (2) Any fuel intended or used to power a vehicle or engine designed 
to operate on gasoline, except for gaseous fuel.
    (3) Any fuel that conforms to the specifications of ASTM D4814 
(incorporated by reference in Sec.  1090.95) and is made available for 
use in a vehicle or engine designed to operate on gasoline.
    Gasoline before oxygenate blending or BOB means gasoline designated 
for downstream oxygenate blending before being dispensed into a vehicle 
or engine's fuel tank, unless recertified as specified in Sec.  
1090.740. BOB is subject to all requirements and standards that apply 
to gasoline, unless subject to a specific alternative standard or 
requirement under this part.
    Gasoline manufacturer means a fuel manufacturer who owns, leases, 
operates, controls, or supervises a fuel manufacturing facility where 
gasoline is produced. Any person recertifying a BOB under Sec.  
1090.740 is considered to be a gasoline manufacturer.
    Gasoline treated as blendstock or GTAB means imported gasoline that 
is excluded from the importer's compliance calculations but is treated 
as blendstock in a related fuel

[[Page 29102]]

manufacturing facility that includes the GTAB in a gasoline 
manufacturer's compliance calculations for the facility under Sec.  
1090.1615.
    Global marine fuel means diesel fuel, distillate fuel, or residual 
fuel used, intended for use, or made available for use in steamships or 
Category 3 marine vessels while the vessels are operating in 
international waters or in any waters outside the boundaries of an ECA. 
Global marine fuel is subject to the provisions of MARPOL Annex VI.
    Heating oil means a combustible product that is used, intended for 
use, or made available for use in furnaces, boilers, or similar 
applications. Kerosene and jet fuel are not heating oil.
    IMO marine fuel means fuel that is ECA marine fuel or global marine 
fuel.
    Importer means any person who imports fuel, fuel additive, or 
regulated blendstock into the United States.
    Import facility means any facility where an importer imports fuel, 
fuel additive, or regulated blendstock.
    Independent surveyor means any person who meets the independence 
requirements in Sec.  1090.55 and conducts a survey under subpart N of 
this part.
    Intake valve deposits or IVD means the deposits formed on the 
intake valve(s) of a gasoline-fueled engine during operation.
    Jet fuel means any distillate fuel used, intended for use, or made 
available for use in aircraft.
    Kerosene means any No.1 distillate fuel that is used, intended for 
use, or made available for use as kerosene.
    Liquefied petroleum gas or LPG means a liquid hydrocarbon fuel that 
is stored under pressure and is composed primarily of compounds that 
are gases at atmospheric conditions (temperature = 25 [deg]C and 
pressure = 1 atm), excluding natural gas.
    Locomotive engine means an engine used in a locomotive as defined 
in 40 CFR 92.2.
    Marine engine has the meaning given under 40 CFR 1042.901.
    Methanol means any fuel sold for use in motor vehicles and engines 
and commonly known or commercially sold as methanol or MXX, where XX 
represents the percent methanol (CH3OH) by volume.
    Natural gas means a fuel that is primarily composed of methane.
    Natural gas liquids or NGLs means the hydrocarbons (primarily 
propane, butane, pentane, hexane, and heptane) that are separated from 
the gaseous state of natural gas in the form of liquids at a facility, 
such as a natural gas production facility, gas processing plant, 
natural gas pipeline, refinery, or similar facility.
    Non-automated detergent blending facility means any facility 
(including a truck or individual storage tank) at which detergent 
additive is blended using a hand blending technique or any other non-
automated method.
    Nonpetroleum (NP) diesel fuel means renewable diesel fuel or 
biodiesel. NP diesel fuel also includes other biomass-based diesel as 
specified under 40 CFR part 80, subpart M.
    Oxygenate means a liquid compound that consists of one or more 
oxygenated compounds. Examples include DFE and isobutanol.
    Oxygenate blender means any person who adds oxygenate to gasoline 
in the United States, or any person who owns, leases, operates, 
controls, or supervises such an operation in the United States.
    Oxygenate blending facility means any facility (including but not 
limited to a truck) at which oxygenate is added to gasoline (including 
BOB), and at which the quality or quantity of gasoline is not altered 
in any other manner except for the addition of deposit control 
additives.
    Oxygenate import facility means any facility where oxygenate, 
including DFE, is imported into the United States.
    Oxygenate producer means any person who produces or imports 
oxygenate for gasoline in the United States, or any person who owns, 
leases, operates, controls, or supervises an oxygenate production or 
import facility in the United States.
    Oxygenate production facility means any facility where oxygenate is 
produced, including DFE.
    Oxygenated compound means an oxygen-containing, ashless organic 
compound, such as an alcohol or ether, which may be used as a fuel or 
fuel additive.
    PADD means Petroleum Administration for Defense District. These 
districts are the same as the PADDs used by other federal agencies, 
except for the addition of PADDs VI and VII. The individual PADDs are 
identified by region, state, and territory as follows:

------------------------------------------------------------------------
                           Regional
         PADD             description           State or territory
------------------------------------------------------------------------
I....................  East Coast......  Connecticut, Delaware, District
                                          of Columbia, Florida, Georgia,
                                          Maine, Maryland,
                                          Massachusetts, New Hampshire,
                                          New Jersey, New York, North
                                          Carolina, Pennsylvania, Rhode
                                          Island, South Carolina,
                                          Vermont, Virginia, West
                                          Virginia.
II...................  Midwest.........  Illinois, Indiana, Iowa,
                                          Kansas, Kentucky, Michigan,
                                          Minnesota, Missouri.
III..................  Gulf Coast......  Alabama, Arkansas, Louisiana,
                                          Mississippi, New Mexico,
                                          Texas.
IV...................  Rocky Mountain..  Colorado, Idaho, Montana, Utah,
                                          Wyoming.
V....................  West Coast......  Alaska, Arizona, California,
                                          Hawaii, Nevada, Oregon,
                                          Washington.
VI...................  Antilles........  Puerto Rico, U.S. Virgin
                                          Islands.
VII..................  Pacific           American Samoa, Guam, Northern
                        Territories.      Mariana Islands.
------------------------------------------------------------------------

    Pentane means an organic compound with the formula 
C5H12.
    Pentane blending facility means a fuel manufacturing facility where 
pentane is blended into PCG.
    Per-gallon standard means the maximum or minimum value for any 
parameter that applies to every volume unit of a specified fuel, fuel 
additive, or regulated blendstock.
    Person has the meaning given in 42 U.S.C. 7602(e).
    Pipeline interface means the mixture between different fuels and 
products that abut each other during shipment by the refined petroleum 
products pipeline system.
    Pipeline operator means any person who owns, leases, operates, 
controls, or supervises a pipeline that transports fuel, fuel additive, 
or regulated blendstock in the United States.
    Previously certified gasoline or PCG means CG, RFG, or BOB that has 
been certified as a batch by a gasoline manufacturer.
    Product transfer documents or PTDs mean documents that reflect the 
transfer of title or physical custody of fuel, fuel additive, or 
regulated blendstock (e.g., invoices, receipts, bills of lading, 
manifests, pipeline tickets) between a transferor and a transferee.
    RBOB means reformulated gasoline for which a gasoline manufacturer 
has accounted for the effects of oxygenate blending that occurs 
downstream of the fuel manufacturing facility.
    Refiner means any person who owns, leases, operates, controls, or 
supervises a refinery in the United States.

[[Page 29103]]

    Refinery means a facility where fuels are produced from feedstocks, 
including crude oil or renewable feedstocks, through physical or 
chemical processing equipment.
    Reformulated gasoline or RFG means gasoline that is certified under 
Sec.  1090.1100(b) to meet the requirements in Sec.  1090.245.
    Regulated blendstock means certified butane, certified pentane, 
TGP, TDP, and GTAB.
    Regulated blendstock producer means any person who owns, leases, 
operates, controls, or supervises a facility where regulated 
blendstocks are produced or imported.
    Renewable diesel fuel means diesel fuel that is made from renewable 
(nonpetroleum) feedstocks and is not a mono-alkyl ester.
    Reseller means any person who purchases fuel identified by the 
corporate, trade, or brand name of a fuel manufacturer from such 
manufacturer or a distributor and resells or transfers it to retailers 
or WPCs, and whose assets or facilities are not substantially owned, 
leased, or controlled by such manufacturer.
    Residual fuel means a petroleum fuel with a T90 temperature at or 
above 700 [deg]F that can only be used in diesel engines if it is 
heated before injection. For example, No. 5 fuels and No. 6 fuels are 
residual fuels. Note that residual fuels might not need heating for 
storage or pumping. Residual fuel grades are specified in ASTM D396 and 
ISO 8217.
    Responsible Corporate Officer or RCO means a person who is 
authorized by the regulated party to make representations on behalf of 
or obligate the company as ultimately responsible for any activity 
regulated under this part (e.g., refining, importing, blending). An 
example is an officer of a corporation under the laws of incorporation 
of the state in which the company is incorporated. Examples of 
positions in non-corporate business structures that qualify are owner, 
chief executive officer, president, or operations manager.
    Retail outlet means any establishment at which gasoline, diesel 
fuel, methanol, natural gas, E85, or LPG is sold or offered for sale 
for use in motor vehicles, nonroad engines, nonroad vehicles, or 
nonroad equipment, including locomotive or marine engines.
    Retailer means any person who owns, leases, operates, controls, or 
supervises a retail outlet.
    RFG covered area means the geographic areas specified in Sec.  
1090.270 in which only RFG may be sold or dispensed to ultimate 
consumers.
    RFG opt-in area means an area that becomes a covered area under 42 
U.S.C. 7545(k)(6) as listed in Sec.  1090.270.
    Round (rounded, rounding) has the meaning given in Sec.  1090.50.
    Sampling strata means the three types of areas sampled during a 
survey, which include the following:
    (1) Densely populated areas.
    (2) Transportation corridors.
    (3) Rural areas.
    State Implementation Plan or SIP means a plan approved or 
promulgated under 42 U.S.C. 7410 or 7502.
    Summer gasoline means gasoline that is subject to the RVP standards 
in Sec.  1090.215.
    Summer season or high ozone season means the period from June 1 
through September 15 for retailers and WPCs, and May 1 through 
September 15 for all other persons, or an RVP control period specified 
in a SIP, whichever is longer.
    Tank truck means a truck used for transporting fuel, fuel additive, 
or regulated blendstock.
    Transmix means any of the following mixtures of fuels, which no 
longer meet the specifications for a fuel that can be used or sold as a 
fuel without further processing:
    (1) Pipeline interface that is not cut into the adjacent products.
    (2) Mixtures produced by unintentionally combining gasoline and 
distillate fuels.
    (3) Mixtures produced from normal business operations at terminals 
or pipelines, such as gasoline or distillate fuel drained from a tank 
or drained from piping or hoses used to transfer gasoline or distillate 
fuel to tanks or trucks, or gasoline or distillate fuel discharged from 
a safety relief valve that are segregated for further processing.
    Transmix blender means any person who owns, leases, operates, 
controls, or supervises a transmix blending facility.
    Transmix blending facility means any facility that produces 
gasoline by blending transmix into PCG.
    Transmix distillate product or TDP means the diesel fuel blendstock 
that is produced when transmix is separated into blendstocks at a 
transmix processing facility.
    Transmix gasoline product or TGP means the gasoline blendstock that 
is produced when transmix is separated into blendstocks at a transmix 
processing facility.
    Transmix processing facility means any facility that produces TGP 
or TDP from transmix by distillation or other refining processes, but 
does not produce gasoline or diesel fuel by processing crude oil or 
other products.
    Transmix processor means any person who owns, leases, operates, 
controls, or supervises a transmix processing facility. Transmix 
processors are fuel manufacturers.
    Ultra low-sulfur diesel or ULSD means diesel fuel that is certified 
to meet the requirements in Sec.  1090.305.
    United States means the 50 states, the District of Columbia, the 
Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana 
Islands, Guam, American Samoa, and the U.S. Virgin Islands.
    Volume Additive Reconciliation (VAR) Period means for automated 
detergent blending facilities a time period lasting no more than 31 
days or until an adjustment to a detergent concentration rate that 
increases the initial rate by more than 10 percent, whichever occurs 
first. The concentration setting for a detergent injector may be 
adjusted by more than 10 percent above the initial rate without 
terminating the VAR Period, provided the purpose of the change is to 
correct a batch misadditization prior to the transfer of the batch to 
another party, or to correct an equipment malfunction and the 
concentration is immediately returned to no more than 10 percent above 
the initial rate of concentration after the correction. For non-
automated detergent blending facilities, the VAR Period constitutes the 
blending of one batch of gasoline.
    Wholesale purchaser-consumer or WPC means any person that is an 
ultimate consumer of fuels and who purchases or obtains fuels for use 
in motor vehicles, nonroad vehicles, nonroad engines, or nonroad 
equipment, including locomotive or marine engines, and, in the case of 
liquid fuels, receives delivery of that product into a storage tank of 
at least 550-gallon capacity substantially under the control of that 
person.
    Winter gasoline means gasoline that is not subject to the RVP 
standards in Sec.  1090.215.
    Winter season means any time outside of the summer season or high 
ozone season.

Sec.  1090.85  Explanatory terms.

    This section explains how certain phrases and terms are used in 
this part, especially those used to clarify and explain regulatory 
provisions. They do not, however, constitute specific regulatory 
requirements and as such do not impose any compliance obligation on 
regulated persons.
    (a) Types of provisions. The term ``provision'' includes all 
aspects of the regulations in this part. As described in this section, 
regulatory provisions include standards, requirements, and 
prohibitions, along with a variety of

[[Page 29104]]

other types of provisions. In certain cases, these terms apply to some 
but not all the provisions of a part or section. For example, 
recordkeeping requirements apply to jet fuel even though it is not 
subject to standards under this part.
    (1) A standard is a limit on the formulation, components, or 
characteristics of any fuel, fuel additive, or regulated blendstock, 
established by regulation under this part. Compliance with or 
conformance to a standard is a specific type of requirement, and in 
some cases a standard may be discussed as a requirement. Thus, a 
statement about the requirements of a part or section also applies with 
respect to the standards in the part or section. Examples of standards 
include the sulfur per-gallon standards for gasoline and diesel fuel.
    (2) While requirements state what someone must do, prohibitions 
state what someone may not do. Prohibitions are often referred to as 
prohibited acts. Failing to meet any requirement that applies to a 
person under this part is a prohibited act.
    (3) The regulations in this part include provisions that are not 
standards, requirements, or prohibitions, such as definitions.
    (b) A fuel is considered ``subject to'' a specific provision if 
that provision applies, even if it falls within an exemption authorized 
under a different part of this regulation. For example, gasoline is 
subject to the provisions of this part even if it is exempted from the 
standards under subpart G of this part.
    (c) Singular and plural. Unless stated otherwise or unless it is 
clear from the regulatory context, provisions written in singular form 
include the plural form and provisions written in plural form include 
the singular form.
    (d) Inclusive lists. Lists in the regulations in this part prefaced 
by ``including'' or ``this includes'' are not exhaustive. The terms 
``including'' and ``this includes'' should be read to mean ``including 
but not limited to'' and ``this includes but is not limited to.''
    (e) Notes. Statements that begin with ``Note:'' or ``Note that'' 
are intended to clarify specific regulatory provisions stated elsewhere 
in the regulations in this part. By themselves, such statements are not 
intended to specify regulatory requirements.
    (f) Examples. Examples provided in the regulations in this part are 
typically introduced by either ``for example'' or ``such as.'' Specific 
examples given in the regulations do not necessarily represent the most 
common examples. The regulations may specify examples conditionally 
(that is, specifying that they are applicable only if certain criteria 
or conditions are met). Lists of examples cannot be presumed to be 
exhaustive lists.

Sec.  1090.90   Acronyms and abbreviations.

500 ppm LM diesel fuel...........................................  As defined in Sec.   1090.80
ABT..............................................................  averaging, banking, and trading
ARV..............................................................  accepted reference value
BOB..............................................................  Gasoline before oxygenate blending
CARB.............................................................  California Air Resources Board
CFR..............................................................  Code of Federal Regulations
CG...............................................................  conventional gasoline
DFE..............................................................  denatured fuel ethanol
E0...............................................................  As defined in Sec.   1090.80
E10..............................................................  As defined in Sec.   1090.80
E15..............................................................  As defined in Sec.   1090.80
E200.............................................................  As defined in Sec.   1090.80
E300.............................................................  As defined in Sec.   1090.80
ECA marine fuel..................................................  As defined in Sec.   1090.80
EPA..............................................................  Environmental Protection Agency
GTAB.............................................................  gasoline treated as blendstock
IMO marine fuel..................................................  As defined in Sec.   1090.80
LAC..............................................................  lowest additive concentration
LLOQ.............................................................  laboratory limit of quantitation
MARPOL Annex VI..................................................  The International Convention for the
                                                                    Prevention of Pollution from Ships, 1973 as
                                                                    modified by the Protocol of 1978 Annex VI
NAAQS............................................................  National Ambient Air Quality Standard
NARA.............................................................  National Archives and Records Administration
NGL..............................................................  natural gas liquids
NIST.............................................................  National Institute for Standards and
                                                                    Technology
PCG..............................................................  previously certified gasoline
PLOQ.............................................................  published limit of quantitation
ppm (mg/kg)......................................................  parts per million (or milligram per kilogram)
PTD..............................................................  product transfer document
R&D..............................................................  research and development
RCO..............................................................  responsible corporate officer
RFG..............................................................  reformulated gasoline
RFS..............................................................  renewable fuel standard
RVP..............................................................  Reid vapor pressure
SIP..............................................................  state implementation plan
SQC..............................................................  statistical quality control
T10, T50, T90....................................................  temperatures representing the points in a
                                                                    distillation process where 10, 50, and 90
                                                                    percent of the sample evaporates,
                                                                    respectively
TDP..............................................................  transmix diesel products
TGP..............................................................  transmix gasoline products
U.S..............................................................  United States
U.S.C............................................................  United States Code
ULSD.............................................................  ultra-low-sulfur diesel fuel
VCSB.............................................................  voluntary consensus standards body
 

[[Page 29105]]

Sec.  1090.95   Incorporation by reference.

    (a) Certain material is incorporated by reference into this part 
with the approval of the Director of the Federal Register under 5 
U.S.C. 552(a) and 1 CFR part 51. All approved material is available for 
inspection at U.S. EPA, Air and Radiation Docket and Information 
Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW, 
Washington, DC 20460, (202) 566-1742, and is available from the sources 
listed in this section. It is also available for inspection at the 
National Archives and Records Administration (NARA). For information on 
the availability of this material at NARA, email fedreg.legal@nara.gov, 
or go to www.archives.gov/federal-register/cfr/ibr-locations.html.
    (b) American Institute of Certified Public Accountants, 220 Leigh 
Farm Rd., Durham, NC 27707-8110, or www.aicpa.org, or (888) 777-7077.
    (1) Statements on Standards for Attestation Engagements (SSAE) No. 
18, Attestation Standards: Clarification and Recodification, Revised 
April 2016; IBR approved for Sec.  1090.1800(b).
    (2) AICPA Code of Professional Conduct, September 1, 2018; IBR 
approved for Sec.  1090.1800(b).
    (3) Statements on Quality Control Standards, July 1, 2019; IBR 
approved for Sec.  1090.1800(b).
    (c) ASTM International, 100 Barr Harbor Dr., P.O. Box C700, West 
Conshohocken, PA 19428-2959, (877) 909-2786, or www.astm.org.
    (1) ASTM D86-19, Standard Test Method for Distillation of Petroleum 
Products and Liquid Fuels at Atmospheric Pressure, approved December 1, 
2019 (``ASTM D86''); IBR approved for Sec.  1090.1350(b).
    (2) ASTM D287-12b (Reapproved 2019), Standard Test Method for API 
Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), 
approved December 1, 2019 (``ASTM D287''); IBR approved for Sec.  
1090.1337(c).
    (3) ASTM D975-19c, Standard Specification for Diesel Fuel, approved 
December 15, 2019 (``ASTM D975''); IBR approved for Sec.  1090.80.
    (4) ASTM D976-06 (Reapproved 2016), Standard Test Method for 
Calculated Cetane Index of Distillate Fuels, approved April 1, 2016 
(``ASTM D976''); IBR approved for Sec.  1090.1350(b).
    (5) ASTM D1298-12b (Reapproved 2017), Standard Test Method for 
Density, Relative Density, or API Gravity of Crude Petroleum and Liquid 
Petroleum Products by Hydrometer Method, approved July 15, 2017 (``ASTM 
D1298''); IBR approved for Sec.  1090.1337(c).
    (6) ASTM D1319-19, Standard Test Method for Hydrocarbon Types in 
Liquid Petroleum Products by Fluorescent Indicator Adsorption, approved 
August 1, 2019 (``ASTM D1319''); IBR approved for Sec.  1090.1350(b).
    (7) ASTM D2163-14 (Reapproved 2019), Standard Test Method for 
Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and 
Propane/Propene Mixtures by Gas Chromatography, approved May 1, 2019 
(``ASTM D2163''); IBR approved for Sec.  1090.1350(b).
    (8) ASTM D2622-16, Standard Test Method for Sulfur in Petroleum 
Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, 
approved January 1, 2016 (``ASTM D2622''); IBR approved for Sec. Sec.  
1090.1350(b), 1090.1360(d), 1090.1365(b), and 1090.1375(c).
    (9) ASTM D3120-08 (Reapproved 2019), Standard Test Method for Trace 
Quantities of Sulfur in Light Liquid Petroleum Hydrocarbons by 
Oxidative Microcoulometry, approved May 1, 2019 (``ASTM D3120''); IBR 
approved for Sec.  1090.1365(b).
    (10) ASTM D3231-18, Standard Test Method for Phosphorus in 
Gasoline, approved April 1, 2018 (``ASTM D3231''); IBR approved for 
Sec.  1090.1350(b).
    (11) ASTM D3237-17, Standard Test Method for Lead in Gasoline by 
Atomic Absorption Spectroscopy, approved June 1, 2017 (``ASTM D3237''); 
IBR approved for Sec.  1090.1350(b).
    (12) ASTM D3606-17, Standard Test Method for Determination of 
Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography, 
approved December 1, 2017 (``ASTM D3606''); IBR approved for Sec.  
1090.1360(c).
    (13) ASTM D4052-18a, Standard Test Method for Density, Relative 
Density, and API Gravity of Liquids by Digital Density Meter, approved 
December 15, 2018 (``ASTM D4052''); IBR approved for Sec.  
1090.1337(c).
    (14) ASTM D4057-19, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, approved July 1, 2019 (``ASTM 
D4057''); IBR approved for Sec. Sec.  1090.1335(b) and 1090.1605(b).
    (15) ASTM D4177-16e1, Standard Practice for Automatic Sampling of 
Petroleum and Petroleum Products, approved October 1, 2016 (``ASTM 
D4177''); IBR approved for Sec. Sec.  1090.1315(b) and 1090.1335(c).
    (16) ASTM D4737-10 (Reapproved 2016), Standard Test Method for 
Calculated Cetane Index by Four Variable Equation, approved July 1, 
2016 (``ASTM D4737''); IBR approved for Sec.  1090.1350(b).
    (17) ASTM D4806-19a, Standard Specification for Denatured Fuel 
Ethanol for Blending with Gasolines for Use as Automotive Spark-
Ignition Engine Fuel, approved September 15, 2019 (``ASTM D4806''); IBR 
approved for Sec.  1090.1395(a).
    (18) ASTM D4814-20, Standard Specification for Automotive Spark-
Ignition Engine Fuel, approved February 1, 2020 (``ASTM D4814''); IBR 
approved for Sec. Sec.  1090.80 and 1090.1395(a).
    (19) ASTM D5134-13 (Reapproved 2017), Standard Test Method for 
Detailed Analysis of Petroleum Naphthas through n-Nonane by Capillary 
Gas Chromatography, approved October 1, 2017 (``ASTM D5134''); IBR 
approved for Sec.  1090.1350(b).
    (20) ASTM D5186-19, Standard Test Method for Determination of the 
Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By 
Supercritical Fluid Chromatography, approved June 1, 2019 (``ASTM 
D5186''); IBR approved for Sec.  1090.1350(b).
    (21) ASTM D5191-19, Standard Test Method for Vapor Pressure of 
Petroleum Products (Mini Method), approved January 1, 2019 (``ASTM 
D5191''); IBR approved for Sec. Sec.  1090.1360(d) and 1090.1365(b).
    (22) ASTM D5453-19a, Standard Test Method for Determination of 
Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel 
Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved July 
1, 2019 (``ASTM D5453''); IBR approved for Sec.  1090.1350(b).
    (23) ASTM D5500-19, Standard Test Method for Vehicle Evaluation of 
Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit 
Formation, approved November 1, 2019 (``ASTM D5500''); IBR approved for 
Sec.  1090.1395(c).
    (24) ASTM D5599-18, Standard Test Method for Determination of 
Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame 
Ionization Detection, approved June 1, 2018 (``ASTM D5599''); IBR 
approved for Sec. Sec.  1090.1360(d) and 1090.1365(b).
    (25) ASTM D5769-15, Standard Test Method for Determination of 
Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas 
Chromatography/Mass Spectrometry, approved December 1, 2015 (``ASTM 
D5769''); IBR approved for Sec. Sec.  1090.1350(b), 1090.1360(d), and 
1090.1365(b).

[[Page 29106]]

    (26) ASTM D5842-19, Standard Practice for Sampling and Handling of 
Fuels for Volatility Measurement, approved November 1, 2019 (``ASTM 
D5842''); IBR approved for Sec.  1090.1335(d).
    (27) ASTM D5854-19a, Standard Practice for Mixing and Handling of 
Liquid Samples of Petroleum and Petroleum Products, approved May 1, 
2019 (``ASTM D5854''); IBR approved for Sec.  1090.1315(b).
    (28) ASTM D6201-19a, Standard Test Method for Dynamometer 
Evaluation of Unleaded Spark-Ignition Engine Fuel for Intake Valve 
Deposit Formation, approved December 1, 2019 (``ASTM D6201''); IBR 
approved for Sec.  1090.1395(a).
    (29) ASTM D6259-15 (Reapproved 2019), Standard Practice for 
Determination of a Pooled Limit of Quantitation for a Test Method, 
approved May 1, 2019 (``ASTM D6259''); IBR approved for Sec.  
1090.1355(b).
    (30) ASTM D6299-19, Standard Practice for Applying Statistical 
Quality Assurance and Control Charting Techniques to Evaluate 
Analytical Measurement System Performance, approved November 1, 2019 
(``ASTM D6299''); IBR approved for Sec. Sec.  1090.1370(c), 
1090.1375(a), (b), and (c), and 1090.1440(c).
    (31) ASTM D6550-15, Standard Test Method for Determination of 
Olefin Content of Gasolines by Supercritical-Fluid Chromatography, 
approved December 1, 2015 (``ASTM D6550''); IBR approved for Sec.  
1090.1350(b).
    (32) ASTM D6667-14 (Reapproved 2019), Standard Test Method for 
Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and 
Liquefied Petroleum Gases by Ultraviolet Fluorescence, approved May 1, 
2019 (``ASTM D6667''); IBR approved for Sec. Sec.  1090.1350(b), 
1090.1360(d), 1090.1365(b), and 1090.1375(c).
    (33) ASTM D6708-19a, Standard Practice for Statistical Assessment 
and Improvement of Expected Agreement Between Two Test Methods that 
Purport to Measure the Same Property of a Material, approved November 
1, 2019 (``ASTM D6708''); IBR approved for Sec. Sec.  1090.1360(c), 
1090.1365(d) and (f), and 1090.1375(c).
    (34) ASTM D6792-17, Standard Practice for Quality Management 
Systems in Petroleum Products, Liquid Fuels, and Lubricants Testing 
Laboratories, approved May 1, 2017 (``ASTM D6792''); IBR approved for 
Sec. Sec.  1090.1375(b) and 1090.1440(c).
    (35) ASTM D7039-15a, Standard Test Method for Sulfur in Gasoline, 
Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and 
Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray 
Fluorescence Spectrometry, approved July 1, 2015 (``ASTM D7039''); IBR 
approved for Sec.  1090.1365(b).
    (36) ASTM D7717-11 (Reapproved 2017), Standard Practice for 
Preparing Volumetric Blends of Denatured Fuel Ethanol and Gasoline 
Blendstocks for Laboratory Analysis, approved May 1, 2017 (``ASTM 
D7717''); IBR approved for Sec.  1090.1340(b).
    (d) The Institute of Internal Auditors, 1035 Greenwood Blvd., Suite 
401, Lake Mary, FL 32746, or www.theiia.org or (407) 937-1111.
    (1) International Standards for the Professional Practice of 
Internal Auditing (Standards), Revised October 2016; IBR approved for 
Sec.  1090.1800(b).
    (2) [Reserved]
    (e) National Institute of Standards and Technology, 100 Bureau Dr., 
Stop 1070, Gaithersburg, MD 20899-1070, (301) 975-6478, or 
www.nist.gov.
    (1) NIST Handbook 158, 2016 Edition, Field Sampling Procedures for 
Fuel and Motor Oil Quality Testing--A Handbook for Use by Fuel and Oil 
Quality Regulatory Officials, April 2016; IBR approved for Sec.  
1090.1410(a).
    (2) [Reserved]

Subpart B--General Requirements and Provisions for Regulated 
Parties

Sec.  1090.100   General provisions.

    This subpart provides an overview of the general requirements and 
other provisions applicable to any regulated party under this part. A 
person who meets the definition of more than one type of regulated 
party must comply with the requirements applicable to each of those 
types of regulated parties. For example, a fuel manufacturer who also 
transports fuel must meet the requirements applicable to fuel 
manufacturers and distributors. Regulated parties are required to 
comply with all applicable requirements of this part, regardless of 
whether they are identified in this subpart. Any person that produces, 
sells, transfers, supplies, dispenses, or distributes fuel, fuel 
additive, or regulated blendstock must comply with all applicable 
requirements.
    (a) Recordkeeping. Any party that engages in activities that are 
regulated under this part must comply with recordkeeping requirements 
under subpart L of this part.
    (b) Compliance and enforcement. Any party that engages in 
activities that are regulated under this part is subject to compliance 
and enforcement provisions under subpart Q of this part.
    (c) Hardships and exemptions. Some regulated parties under this 
part may be eligible, or eligible to petition, for a hardship or 
exemption under subpart G of this part.
    (d) In addition to the requirements in paragraphs (a) through (c) 
of this section and Sec.  1090.105 that apply to importers based on the 
fuel, fuel additive, or regulated blendstock being imported, importers 
must also comply with subpart P of this part.

Sec.  1090.105   Fuel manufacturers.

    This section provides an overview of general requirements 
applicable to fuel manufacturers. Gasoline manufacturers must comply 
with the requirements of paragraph (a) of this section and diesel fuel 
and ECA marine fuel manufacturers must comply with the requirements of 
paragraph (b) of this section.
    (a) Gasoline manufacturers. Except as specified otherwise in this 
subpart, all gasoline manufacturers must comply with the following 
requirements:
    (1) Producing and certifying compliant gasoline. Gasoline 
manufacturers must produce (or import) and certify gasoline under 
subpart K of this part as meeting the standards of subpart C of this 
part and must comply with the ABT requirements in subpart H of this 
part.
    (2) Registration. Gasoline manufacturers must register with EPA 
under subpart I of this part.
    (3) PTDs. On each occasion when a gasoline manufacturer transfers 
custody of or title to any gasoline, the transferor must provide to the 
transferee PTDs under subpart K of this part.
    (4) Designation. Gasoline manufacturers must designate the gasoline 
they produce under subpart K of this part.
    (5) Reporting. Gasoline manufacturers must submit reports to EPA 
under subpart J of this part.
    (6) Sampling, testing, and sample retention. Gasoline manufacturers 
must conduct sampling, testing, and sample retention in accordance with 
subpart M of this part.
    (7) Surveys. Gasoline manufacturers may participate in applicable 
fuel surveys under subpart N of this part.
    (8) Annual attest engagement. Gasoline manufacturers must submit 
annual attest engagement reports to EPA under subpart R of this part.
    (b) Diesel fuel and ECA marine fuel manufacturers. Diesel fuel and 
ECA marine fuel manufacturers must comply with the following 
requirements, as applicable:
    (1) Producing and certifying compliant diesel fuel and ECA marine 
fuel. Diesel fuel and ECA marine fuel

[[Page 29107]]

manufacturers must produce (or import) and certify diesel fuel and ECA 
marine fuel under subpart K of this part as meeting the requirements of 
subpart D of this part.
    (2) Registration. Diesel fuel and ECA marine fuel manufacturers 
must register with EPA under subpart I of this part.
    (3) Reporting. Diesel fuel manufacturers must submit reports to EPA 
under subpart J of this part.
    (4) PTDs. On each occasion when a diesel fuel or ECA marine fuel 
manufacturer transfers custody or title to any diesel fuel or ECA 
marine fuel, the transferor must provide to the transferee PTDs under 
subpart K of this part.
    (5) Sampling, testing, and retention requirements. Diesel fuel and 
ECA marine fuel manufacturers must conduct sampling, testing, and 
sample retention in accordance with subpart M of this part.
    (6) Surveys. Diesel fuel manufacturers may participate in 
applicable fuel surveys under subpart N of this part.
    (7) Manufacturers of distillate global marine fuel. Manufacturers 
of distillate global marine fuel do not need to comply with the 
requirements of paragraphs (b)(1) through (5) of this section if they 
produce global marine fuel that is exempt from the standards in subpart 
D of this part, as specified in Sec.  1090.650.

Sec.  1090.110   Detergent blenders.

    Detergent blenders must comply with the requirements of this 
section.
    (a) Gasoline standards. Detergent blenders must comply with the 
applicable requirements of subpart C of this part.
    (b) PTDs. On each occasion when a detergent blender transfers 
custody of or title to any fuel, fuel additive, or regulated 
blendstock, the transferor must provide to the transferee PTDs under 
subpart K of this part.
    (c) Recordkeeping. Detergent blenders must demonstrate compliance 
with the requirements of Sec.  1090.240(a) as specified in Sec.  
1090.1240.
    (d) Equipment calibration. Detergent blenders at automated 
detergent blending facilities must calibrate their detergent blending 
equipment in accordance with subpart M of this part.

Sec.  1090.115   Oxygenate blenders.

    Oxygenate blenders must comply with the requirements of this 
section.
    (a) Gasoline standards. Oxygenate blenders must comply with the 
applicable requirements of subpart C of this part.
    (b) Registration. Oxygenate blenders must register with EPA under 
subpart I of this part.
    (c) PTDs. On each occasion when an oxygenate blender transfers 
custody or title to any fuel, fuel additive, or regulated blendstock, 
the transferor must provide to the transferee PTDs under subpart K of 
this part.
    (d) Oxygenate blending requirements. Oxygenate blenders must follow 
blending instructions as specified for gasoline manufacturers in Sec.  
1090.710 unless the oxygenate blender recertifies BOBs under Sec.  
1090.740.

Sec.  1090.120   Oxygenate producers.

    This section provides an overview of general requirements 
applicable to oxygenate producers (e.g., DFE and isobutanol producers). 
DFE producers must comply with all requirements for oxygenate producers 
in paragraph (a) of this section and all additional requirements 
specified in paragraph (b) of this section.
    (a) Oxygenate producers. Oxygenate producers must comply with the 
following requirements:
    (1) Gasoline standards. Oxygenate producers must comply with the 
applicable requirements of subpart C of this part and certify batches 
of oxygenate under subpart K of this part.
    (2) Registration. Oxygenate producers must register with EPA under 
subpart I of this part.
    (3) Reporting. Oxygenate producers must submit reports to EPA under 
subpart J of this part.
    (4) PTDs. On each occasion when an oxygenate producer transfers 
custody or title to any fuel, fuel additive, or regulated blendstock, 
the transferor must provide to the transferee PTDs under subpart K of 
this part.
    (5) Designation. Oxygenate producers must designate the oxygenate 
they produce under subpart K of this part.
    (6) Sampling, testing, and retention requirements. Oxygenate 
producers must conduct sampling, testing, and sample retention in 
accordance with subpart M of this part.
    (b) DFE producers. In addition to the requirements specified in 
paragraph (a) of this section, DFE producers must meet all the 
following requirements:
    (1) Use denaturant that complies with the requirements specified in 
Sec. Sec.  1090.230(b) and 1090.235.
    (2) Participate in a survey program conducted by an independent 
surveyor under subpart N of this part if the DFE producer produces DFE 
made available for use in the production of E15.

Sec.  1090.125   Certified butane producers.

    Certified butane producers must comply with the requirements of 
this section.
    (a) Gasoline standards. Certified butane producers must comply with 
the applicable requirements of subpart C of this part and certify 
batches of certified butane under subpart K of this part.
    (b) PTDs. On each occasion when a certified butane producer 
transfers custody of or title to any certified butane, the transferor 
must provide to the transferee PTDs under subpart K of this part.
    (c) Designation. Certified butane producers must designate the 
certified butane they produce under subpart K of this part.
    (d) Sampling, testing, and retention requirements. Certified butane 
producers must conduct sampling, testing, and sample retention in 
accordance with subpart M of this part.

Sec.  1090.130   Certified butane blenders.

    Certified butane blenders that blend certified butane into PCG are 
gasoline manufacturers that may comply with the requirements of this 
section in lieu of the requirements in Sec.  1090.105.
    (a) Gasoline standards. Certified butane blenders must comply with 
the applicable requirements of subpart C of this part.
    (b) Registration. Certified butane blenders must register with EPA 
under subpart I of this part.
    (c) Reporting. Certified butane blenders must submit reports to EPA 
under subpart J of this part.
    (d) Sampling, testing, and retention requirements. Certified butane 
blenders must conduct sampling, testing, and sample retention in 
accordance with subpart M of this part.
    (e) PTDs. When certified butane is blended with PCG, PTDs that 
accompany the gasoline blended with certified butane must comply with 
subpart K of this part.
    (f) Survey. Certified butane blenders may participate in the 
applicable fuel surveys of subpart N of this part.
    (g) Annual attest engagement. Certified butane blenders must submit 
annual attest engagement reports to EPA under subpart R of this part.

Sec.  1090.135   Certified pentane producers.

    Certified pentane producers must comply with the requirements of 
this section.
    (a) Gasoline standards. Certified pentane producers must comply 
with the applicable requirements of subpart C of this part and certify 
batches of certified pentane under subpart K of this part.
    (b) Registration. Certified pentane producers must register with 
EPA under subpart I of this part.
    (c) Reporting. Certified pentane producers must submit reports to 
EPA under subpart J of this part.

[[Page 29108]]

    (d) PTDs. On each occasion when a certified pentane producer 
transfers custody of or title to any certified pentane, the transferor 
must provide to the transferee PTDs under subpart K of this part.
    (e) Designation. Certified pentane producers must designate the 
certified pentane they produce under subpart K of this part.
    (f) Sampling, testing, and retention requirements. Certified 
pentane producers and importers must conduct sampling, testing, and 
sample retention in accordance with subpart M of this part.

Sec.  1090.140   Certified pentane blenders.

    Certified pentane blenders that blend certified pentane into PCG 
are gasoline manufacturers that may comply with the requirements of 
this section in lieu of the requirements in Sec.  1090.105.
    (a) Gasoline standards. Certified pentane blenders must comply with 
the applicable requirements of subpart C of this part.
    (b) Registration. Certified pentane blenders must register with EPA 
under subpart I of this part.
    (c) Reporting. Certified pentane blenders must submit reports to 
EPA under subpart J of this part.
    (d) Sampling, testing, and retention requirements. Certified 
pentane blenders must conduct sampling, testing, and sample retention 
in accordance with subpart M of this part.
    (e) PTDs. When certified pentane is blended with PCG, PTDs that 
accompany the gasoline blended with pentane must comply with subpart K 
of this part.
    (f) Survey. Certified pentane blenders may participate in the 
applicable fuel surveys of subpart N of this part.
    (g) Annual attest engagement. Certified pentane blenders must 
submit annual attest engagement reports to EPA under subpart R of this 
part.

Sec.  1090.145   Transmix processors.

    Transmix processors must comply with the requirements of this 
section.
    (a) Transmix requirements. Transmix processors must comply with the 
transmix requirements of subpart F of this part and certify batches of 
fuel under subpart K of this part.
    (b) Registration. Transmix processors must register with EPA under 
subpart I of this part.
    (c) PTDs. On each occasion when a transmix processor produces a 
batch of fuel or transfers custody of or title to any fuel, fuel 
additive, or regulated blendstock, the transferor must provide to the 
transferee PTDs under subpart K of this part.
    (d) Designation. Transmix processors must designate the batches of 
fuel they produce under subpart K of this part.
    (e) Sampling, testing, and retention requirements. Transmix 
processors must conduct sampling, testing, and sample retention in 
accordance with subparts F and M of this part.
    (f) Reporting. Transmix processors must submit reports to EPA under 
subpart J of this part.

Sec.  1090.150   Transmix blenders.

    Transmix blenders must comply with the requirements of this 
section.
    (a) Transmix requirements. Transmix blenders must comply with the 
transmix requirements of subpart F of this part and certify batches of 
fuel under subpart K of this part.
    (b) PTDs. On each occasion when a transmix blender produces a batch 
of fuel or transfers custody or title to any fuel, fuel additive, or 
regulated blendstock, the transferor must provide to the transferee 
PTDs under subpart K of this part.
    (c) Designation. Transmix blenders must designate the batches of 
fuel they produce under subpart K of this part.
    (d) Sampling, testing, and retention requirements. Transmix 
blenders must conduct sampling, testing, and sample retention in 
accordance with subparts F and M of this part.

Sec.  1090.155   Fuel additive manufacturers.

    This section provides an overview of general requirements 
applicable to fuel additive manufacturers. Gasoline additive 
manufacturers must comply with the requirements of paragraph (a) of 
this section, diesel fuel additive manufacturers must comply with the 
requirements of paragraph (b) of this section, and certified ethanol 
denaturant producers must comply with the requirements of paragraph (c) 
of this section.
    (a) Gasoline additive manufacturers. Gasoline additive 
manufacturers that produce additives with a maximum allowed 
concentration of less than 1.0 volume percent must meet the following 
requirements:
    (1) Gasoline standards. Gasoline additive manufacturers must 
produce gasoline additives that comply with subpart C of this part and 
certify gasoline additives under subpart K of this part.
    (2) PTDs. On each occasion when a gasoline additive manufacturer 
transfers custody of or title to any gasoline additive, the transferor 
must provide to the transferee PTDs under subpart K of this part.
    (3) Gasoline detergent manufacturers. Gasoline detergent 
manufacturers must comply with the following requirements:
    (i) Part 79 registration and LAC determination. Gasoline detergent 
manufacturers must register gasoline detergent(s) under 40 CFR 79.21 at 
a concentration that is greater than or equal to the LAC reported by 
the gasoline detergent manufacturer under 40 CFR 79.21(j). Note that 
EPA provides a list on EPA's website of detergents that have been 
certified by the gasoline detergent manufacturer as meeting the deposit 
control requirement (Search for ``List of Certified Detergent 
Additives'').
    (ii) Gasoline standards. Report the LAC determined under Sec.  
1090.240(b) and provide specific composition information as part of the 
gasoline detergent manufacturer's registration of the detergent under 
40 CFR 79.21(j).
    (iii) PTDs. On each occasion when a gasoline detergent manufacturer 
transfers custody of or title to any gasoline detergent, the transferor 
must provide to the transferee PTDs under subpart K of this part.
    (iv) Sampling, testing, and retention requirements. Gasoline 
detergent manufacturers that register detergents must conduct sampling, 
testing, and sample retention in accordance with subpart M of this 
part.
    (b) Diesel fuel additive manufacturers. Diesel fuel additive 
manufacturers that produce additives with a maximum allowed 
concentration of less than 1.0 volume percent must meet the following 
requirements:
    (1) Diesel fuel standards. Diesel fuel additive manufacturers must 
produce diesel fuel additives that comply with subpart D of this part 
and certify batches of diesel fuel additive under subpart K of this 
part.
    (2) PTDs. On each occasion when a diesel fuel additive manufacturer 
transfers custody of or title to any diesel additive, the transferor 
must provide to the transferee PTDs under subpart K of this part.
    (c) Certified ethanol denaturant producers and importers. Certified 
ethanol denaturant producers must meet the following requirements:
    (1) Certification of certified ethanol denaturant. Certified 
ethanol denaturant producers and importers must certify that certified 
ethanol denaturant meets the requirements in Sec.  1090.235.
    (2) Registration. Certified ethanol denaturant producers and 
importers must register with EPA under subpart I of this part.
    (3) PTDs. On each occasion when a certified ethanol denaturant 
producer transfers custody or title to any fuel, fuel additive, or 
regulated blendstock, the

[[Page 29109]]

transferor must provide to the transferee PTDs under subpart K of this 
part.

Sec.  1090.160   Distributors, carriers, and resellers.

    Distributors, carriers, and resellers must comply with the 
requirements of this section.
    (a) Gasoline and diesel standards. Distributors, carriers, and 
resellers must comply with the applicable requirements of subparts C 
and D of this part.
    (b) Registration. Distributors and carriers must register with EPA 
under subpart I of this part if they are part of the 500 ppm LM diesel 
fuel distribution chain under a compliance plan submitted under Sec.  
1090.520(g).
    (c) PTDs. Distributors, carriers, and resellers may have specific 
PTD requirements under subpart K of this part. For example, a 
distributor that adds diluent to a gasoline detergent may have to 
modify the PTD for the gasoline detergent to specify a new minimum 
concentration that complies with the deposit control requirements in 
Sec.  1090.240.

Sec.  1090.165   Retailers and WPCs.

    Retailers and WPCs must comply with the requirements of this 
section.
    (a) Gasoline and diesel standards. Retailers and WPCs must comply 
with the applicable requirements of subparts C and D of this part.
    (b) Labeling. Retailers and WPCs that dispense fuels requiring a 
label under this part must display fuel labels under subpart O of this 
part.
    (c) Blender Pumps. Retailers and WPCs that produce gasoline (e.g., 
E15) through a blender pump with PCG and E85 that contains anything 
other than PCG and DFE must comply with the applicable requirements in 
Sec.  1090.105.

Sec.  1090.170   Independent surveyors.

    Independent surveyors that conduct fuel surveys must comply with 
the requirements of this section.
    (a) Survey provisions. Independent surveyors must conduct fuel 
surveys under subpart N of this part.
    (b) Registration. Independent surveyors must register with EPA 
under subpart I of this part.
    (c) Sampling, testing, and retention requirements. Independent 
surveyors must conduct sampling, testing, and sample retention in 
accordance with subpart M of this part.
    (d) Reporting. Independent surveyors must submit reports to EPA 
under subpart J of this part.
    (e) Independence requirements. In order to perform a survey program 
under subpart N of this part, independent surveyors must meet the 
independence requirements in Sec.  1090.55.

Sec.  1090.175   Auditors.

    Auditors that conduct audits for responsible parties under this 
part must comply with the requirements of this section.
    (a) Registration. Auditors must register with EPA under subpart I 
of this part.
    (b) Reporting. Auditors must submit reports to EPA under subpart J 
of this part.
    (c) Attest engagement. Auditors must conduct audits under subpart R 
of this part.
    (d) Independence requirements. In order to perform an annual attest 
engagement under subpart R of this part, auditors must meet the 
independence requirements in Sec.  1090.55 unless they are a certified 
internal auditor under Sec.  1090.1800(b)(1)(i).

Sec.  1090.180   Pipeline operators.

    Pipeline operators must comply with the requirements of this 
section.
    (a) Gasoline and diesel standards. Pipeline operators must comply 
with the applicable requirements of subparts C and D of this part.
    (b) PTDs. Pipeline operators must maintain PTDs for the fuel, fuel 
additive, regulated blendstock, and heating oil of which they take 
custody.
    (c) Transmix requirements. Pipeline operators must comply with all 
applicable requirements in subpart F of this part.

Subpart C--Gasoline Standards

Sec.  1090.200   Overview and general requirements.

    (a) Except as specified in subpart G of this part, gasoline, 
gasoline additives, and gasoline regulated blendstocks are subject to 
the standards in this subpart.
    (b) Except for the sulfur average standard in Sec.  1090.205(a) and 
the benzene average standards in Sec.  1090.210(a) and (b), the 
standards in this part apply to gasoline, gasoline additives, and 
gasoline regulated blendstocks on a per-gallon basis. Gasoline 
manufacturers and gasoline additive manufacturers (e.g., oxygenate 
producers and certified ethanol denaturant producers), and gasoline 
regulated blendstock producers (e.g., certified butane producers and 
certified pentane producers) must demonstrate compliance with the per-
gallon standards in this subpart by measuring fuel parameters in 
accordance with subpart M of this part.
    (c) The sulfur average standard in Sec.  1090.205(a) and the 
benzene average standards in Sec.  1090.210(a) and (b) apply to all 
gasoline produced or imported by a fuel manufacturer during a 
compliance period, except for truck and rail importers using the 
provisions of Sec. Sec.  1090.205(d) and 1090.210(c), certified butane 
blenders, certified pentane blenders, and transmix blenders. Fuel 
manufacturers must demonstrate compliance with average standards by 
measuring fuel parameters in accordance with subpart M of this part and 
by determining compliance under subpart H of this part.
    (d) No person may produce, import, sell, offer for sale, 
distribute, offer to distribute, supply, offer for supply, dispense, 
store, transport, or introduce into commerce any gasoline, gasoline 
additive, or gasoline regulated blendstock that does not comply with 
any per-gallon standard set forth in this subpart.
    (e) No person may sell, offer for sale, supply, offer for supply, 
dispense, transport, or introduce into commerce for use as fuel in any 
motor vehicle (as defined in Section 216(2) of the Clean Air Act, 42 
U.S.C. 7550(2)) any gasoline that is produced with the use of additives 
containing lead, that contains more than 0.05 gram of lead per gallon, 
or that contains more than 0.005 grams of phosphorous per gallon.

Sec.  1090.205   Sulfur standards.

    Except as specified in subpart G of this part, all gasoline is 
subject to the following sulfur standards:
    (a) Sulfur average standard. Gasoline manufacturers must meet a 
sulfur average standard of 10.00 ppm for each compliance period.
    (b) Fuel manufacturing facility gate sulfur per-gallon standard. 
Gasoline at any fuel manufacturing facility gate is subject to a 
maximum sulfur per-gallon standard of 80 ppm. Fuel manufacturers may 
not account for the downstream addition of oxygenates in determining 
compliance with this standard.
    (c) Downstream location sulfur per-gallon standard. Gasoline at any 
downstream location is subject to a maximum sulfur per-gallon standard 
of 95 ppm.
    (d) Sulfur standard for importers that import gasoline by rail or 
truck. Importers that import gasoline by rail or truck under Sec.  
1090.1610 must comply with a maximum sulfur per-gallon standard of 10 
ppm instead of the standards in paragraphs (a) through (c) of this 
section.

Sec.  1090.210   Benzene standards.

    Except as specified in subpart G of this part, all gasoline is 
subject to the following benzene standards:

[[Page 29110]]

    (a) Benzene average standard. Gasoline manufacturers must meet a 
benzene average standard of 0.62 volume percent for each compliance 
period.
    (b) Maximum benzene average standard. Gasoline manufacturers must 
meet a maximum benzene average standard of 1.30 volume percent without 
the use of credits for each compliance period.
    (c) Benzene standard for importers that import gasoline by rail or 
truck. Importers that import gasoline by rail or truck under Sec.  
1090.1610 must comply with a 0.62 volume percent benzene per-gallon 
standard instead of the standards in paragraphs (a) and (b) of this 
section.

Sec.  1090.215   Gasoline RVP standards.

    Except as specified in subpart G of this part and paragraph (c) of 
this section, all gasoline designated as summer gasoline or located at 
any location in the United States during the summer season is subject 
to a maximum RVP per-gallon standard in this section.
    (a) Federal 9.0 psi maximum RVP per-gallon standard. Gasoline 
designated as summer gasoline or located at any location in the United 
States during the summer season must meet a maximum RVP per-gallon 
standard of 9.0 psi unless the gasoline is subject to one of the 
following lower maximum RVP per-gallon standards:
    (1) Federal 7.8 maximum RVP per-gallon standard. Gasoline 
designated as 7.8 psi summer gasoline, or located in the following 
areas during the summer season, must meet a maximum RVP per-gallon 
standard of 7.8 psi:

                       Table 1 to Paragraph (a)(1)
------------------------------------------------------------------------
       Area designation               State               Counties
------------------------------------------------------------------------
Denver-Boulder-Greeley-Ft.      Colorado.........  Adams Arapahoe,
 Collins-Loveland.                                  Boulder, Broomfield,
                                                    Denver, Douglas,
                                                    Jefferson,
                                                    Larimer,\1\ Weld.\2\
Reno..........................  Nevada...........  Washoe.
Portland......................  Oregon...........  Clackamas (only the
                                                    Air Quality
                                                    Maintenance Area),
                                                    Multnomah (only the
                                                    Air Quality
                                                    Maintenance Area),
                                                    Washington (only the
                                                    Air Quality
                                                    Maintenance Area).
Salem.........................  Oregon...........  Marion (only the
                                                    Salem Area
                                                    Transportation
                                                    Study), Polk (only
                                                    the Salem Area
                                                    Transportation
                                                    Study).
Beaumont-Port Arthur..........  Texas............  Hardin, Jefferson,
                                                    Orange.
Salt Lake City................  Utah.............  Davis, Salt Lake.
------------------------------------------------------------------------
\1\ That portion of Larimer County, CO that lies south of a line
  described as follows: Beginning at a point on Larimer County's eastern
  boundary and Weld County's western boundary intersected by 40 degrees,
  42 minutes, and 47.1 seconds north latitude, proceed west to a point
  defined by the intersection of 40 degrees, 42 minutes, 47.1 seconds
  north latitude and 105 degrees, 29 minutes, and 40.0 seconds west
  longitude, thence proceed south on 105 degrees, 29 minutes, 40.0
  seconds west longitude to the intersection with 40 degrees, 33 minutes
  and 17.4 seconds north latitude, thence proceed west on 40 degrees, 33
  minutes, 17.4 seconds north latitude until this line intersects
  Larimer County's western boundary and Grand County's eastern boundary.
  (Includes part of Rocky Mtn. Nat. Park).
\2\ That portion of Weld County, CO that lies south of a line described
  as follows: Beginning at a point on Weld County's eastern boundary and
  Logan County's western boundary intersected by 40 degrees, 42 minutes,
  47.1 seconds north latitude, proceed west on 40 degrees, 42 minutes,
  47.1 seconds north latitude until this line intersects Weld County's
  western boundary and Larimer County's eastern boundary.

    (2) RFG maximum RVP per-gallon standard. Gasoline designated as 
Summer RFG or located in RFG covered areas specified in Sec.  1090.270 
during the summer season must meet a maximum RVP per-gallon standard of 
7.4 psi.
    (3) California gasoline. Gasoline designated as California gasoline 
or used in areas subject to the California reformulated gasoline 
regulations must comply with those regulations under Title 13, 
California Code of Regulations, sections 2250-2273.5.
    (4) SIP-controlled gasoline. Gasoline designated as SIP-controlled 
gasoline or used in areas subject to a SIP-approved state fuel rule 
that requires an RVP of less than 9.0 psi must meet the requirements of 
the federally approved SIP.
    (b) Ethanol 1.0 psi waiver. (1) Except as specified in paragraph 
(b)(3) of this section, any gasoline subject to a federal 9.0 psi or 
7.8 psi maximum RVP per-gallon standard in paragraph (a) of this 
section that meets the requirements of paragraph (b)(2) of this section 
is not in violation of this section if its RVP does not exceed the 
applicable standard by more than 1.0 psi.
    (2) To qualify for the special regulatory treatment specified in 
paragraph (b)(1) of this section, gasoline must meet the applicable RVP 
per-gallon standard in this section prior to the addition of ethanol 
and must contain ethanol at a concentration of at least 9 volume 
percent and no more than 15 volume percent.
    (3) RFG and gasoline subject to a state RVP requirement that does 
not allow for the ethanol 1.0 psi waiver does not qualify for the 
special regulatory treatment specified in paragraph (b)(1) of this 
section.
    (c) Exceptions. The RVP per-gallon standard in paragraph (a) of 
this section for the area in which the gasoline is located does not 
apply to that gasoline if a person can demonstrate one of the 
following:
    (1) The gasoline is designated as winter gasoline and was not sold, 
offered for sale, supplied, offered for supply, dispensed, or 
introduced into commerce for use during the summer season and was not 
delivered to any retail station or wholesale purchaser consumer during 
the summer season.
    (2) The gasoline is designated as summer gasoline for use in an 
area other than the area in which it is located and was not sold, 
offered for sale, supplied, offered for supply, dispensed, or 
introduced into commerce in the area in which the gasoline is located. 
In this case, the standard that applies to the gasoline is the standard 
applicable to the area for which the gasoline is designated.

Sec.  1090.220   Certified butane standards.

    Butane designated as certified butane under Sec.  1090.1100(e) for 
use under the butane blending provisions of Sec.  1090.1320(c) must 
meet the following per-gallon standards:
    (a) Butane content. Minimum 92 volume percent.
    (b) Benzene content. Maximum 0.03 volume percent.
    (c) Sulfur content. Maximum 10 ppm.
    (d) Chemical composition. Be composed solely of carbon, hydrogen, 
oxygen, nitrogen, and sulfur.

Sec.  1090.225   Certified pentane standards.

    Pentane designated as certified pentane under Sec.  1090.1100(f) 
for use under the pentane blending provisions

[[Page 29111]]

of Sec.  1090.1320(c) must meet the following per-gallon standards:
    (a) Pentane content. Minimum 95 volume percent.
    (b) Benzene content. Maximum 0.03 volume percent.
    (c) Sulfur content. Maximum 10 ppm.
    (d) Chemical composition. Be composed solely of carbon, hydrogen, 
oxygen, nitrogen, and sulfur.

Sec.  1090.230   Gasoline oxygenate standards.

    (a) All oxygenates designated for blending with gasoline or blended 
with gasoline must meet the following per-gallon standards:
    (1) Sulfur content. Maximum 10 ppm.
    (2) Chemical composition. Be composed solely of carbon, hydrogen, 
oxygen, nitrogen, and sulfur.
    (b) DFE designated for blending into gasoline or blended with 
gasoline must meet the following additional requirements:
    (1) Denaturant type. Only PCG, gasoline blendstocks, NGLs, or 
certified ethanol denaturant that meets the requirements in Sec.  
1090.235 may be used as denaturants.
    (2) Denaturant concentration. The concentration of all denaturants 
used in DFE must not exceed 3.0 volume percent.

Sec.  1090.235   Ethanol denaturant standards.

    (a) Standard for all ethanol denaturant. All ethanol denaturant, 
certified or uncertified, used to produce DFE must be composed solely 
of carbon, hydrogen, nitrogen, oxygen, and sulfur.
    (b) Standards for certified ethanol denaturant. Certified ethanol 
denaturant must meet the following requirements:
    (1) Sulfur per-gallon standard. The sulfur content must not be 
greater than 330 ppm. If the certified ethanol denaturant producer 
represents a batch of denaturant as having a maximum sulfur content 
less than or equal to 330 ppm on the PTD (for example, less than or 
equal to 120 ppm), then the actual sulfur content must be less than or 
equal to the stated value.
    (2) Denaturant type. Only PCG, gasoline blendstocks, or NGLs may be 
used to produce certified ethanol denaturant.

Sec.  1090.240   Gasoline deposit control standards.

    (a) Except as specified in subpart G of this part, all gasoline 
that is sold, offered for sale, dispensed, supplied, offered for 
supply, or transported to the ultimate consumer for use in motor 
vehicles or in any off-road engines, or that is transported to a 
gasoline retailer or WPC must be treated with a detergent meeting the 
requirements of paragraph (b) of this section at a rate at least as 
high as the detergent's LAC over VAR period.
    (b) The LAC of the detergent must be determined by the gasoline 
detergent manufacturer using one of the following methods:
    (1) The detergent must comply with one of the deposit control 
testing methods specified in Sec.  1090.1395.
    (2) The detergent must have been certified prior to January 1, 
2021, under the intake valve deposit control requirements of 40 CFR 
80.165(b) for any of the detergent certification options under 40 CFR 
80.163. Di-tertiary butyl disulfide may have been used to meet the test 
fuel specifications under 40 CFR 80.164 associated with the intake 
valve deposit control requirements of 40 CFR 80.165(b). Parties 
compliant with this paragraph are exempted from the port fuel injector 
deposit control requirements of 40 CFR 80.165(a).
    (3) Gasoline detergent manufacturers must produce detergents 
consistent with their detergent certifications for detergents certified 
prior to January 1, 2021, and with the specific composition information 
submitted as part of the registration of detergents under 40 CFR 
79.21(j) thereafter.

Sec.  1090.245   RFG standards.

    The standards in this section apply to gasoline that is designated 
as RFG or RBOB or that is used in the RFG covered areas listed in Sec.  
1090.270. Gasoline that meets the requirements of this section is 
deemed to be in compliance with the requirements of 42 U.S.C. 7545(k).
    (a) Sulfur standards. RFG or RBOB must comply with the sulfur 
average standard in Sec.  1090.205(a). RFG and RBOB must comply with 
sulfur per-gallon standards in Sec.  1090.205(b) and (c).
    (b) Benzene standards. RFG or RBOB must comply with the benzene 
standards in Sec.  1090.210.
    (c) RVP standard. Summer RFG or Summer RBOB must comply with the 
RFG RVP standard in Sec.  1090.215(a)(2).
    (d) Heavy metals standard. RFG or RBOB must not contain any heavy 
metals, including, but not limited to, lead or manganese. EPA may waive 
this prohibition for a heavy metal (other than lead) if EPA determines 
that addition of the heavy metal to the gasoline will not increase, on 
an aggregate mass or cancer-risk basis, toxic air pollutant emissions 
from motor vehicles.
    (e) Certified butane and certified pentane blending limitation. 
Certified butane and certified pentane may not be blended with Summer 
RFG or Summer RBOB under Sec.  1090.1320.

Sec.  1090.250   Anti-dumping standards.

    Gasoline that meets all applicable standards in this subpart is 
deemed to be in compliance with the anti-dumping requirements of 42 
U.S.C. 7545(k)(8).

Sec.  1090.255   Gasoline additive standards.

    (a) Any gasoline additive that is added to, intended for adding to, 
used in, or offered for use in gasoline at any downstream location must 
meet all the following requirements:
    (1) Registration. The gasoline additive must be registered by a 
gasoline additive manufacturer under 40 CFR part 79.
    (2) Sulfur content. The gasoline additive must contribute less than 
or equal to 3 ppm on a per-gallon basis to the sulfur content of 
gasoline when used at the maximum recommended concentration.
    (3) Treatment rate. Except for oxygenates, the gasoline additive(s) 
must be used at a maximum treatment rate less than or equal to a 
combined total of 1.0 volume percent.
    (b) Any fuel additive blender who is not otherwise subject to any 
other requirement in this part and only blends a gasoline additive that 
meets the requirements of paragraph (a) of this section into gasoline 
is not subject to any requirement in this part solely due to this 
gasoline additive blending, except the downstream gasoline sulfur per-
gallon standard in Sec.  1090.205(c), if all the following conditions 
are met:
    (1) The fuel additive blender blends the gasoline additive into 
gasoline at a concentration less than or equal to 1.0 volume percent.
    (2) The fuel additive blender does not add any other blendstock or 
fuel additive into the gasoline except for oxygenates meeting the 
requirements in Sec.  1090.230.
    (c) Any person who blends any fuel additive that does not meet the 
requirements of paragraphs (a) and (b) of this section is a gasoline 
manufacturer and must comply with all requirements applicable to 
gasoline manufacturer in this part.
    (d) Any gasoline additive intended for use or used to comply with 
the gasoline deposit control requirement in Sec.  1090.240(a) must have 
been certified by the gasoline detergent manufacturer under Sec.  
1090.240(b).

Sec.  1090.260   Gasoline substantially similar provisions.

    (a) Gasoline and gasoline additives (including oxygenates) are 
subject to the substantially similar requirement in 42 U.S.C. 7545(f) 
unless waived under 42 U.S.C. 7545(f)(4).
    (b) No fuel or fuel additive manufacturer may introduce into

[[Page 29112]]

commerce gasoline or gasoline additives (including oxygenates) that 
violate any conditions set forth in a waiver under 42 U.S.C. 
7545(f)(4).
    (c) No fuel or fuel additive manufacturers may introduce into 
commerce gasoline or gasoline additives (including oxygenates) that 
violate any parameters articulated in the definition of ``substantially 
similar.''

Sec.  1090.265  Requirements for E15.

    (a) No person may sell, introduce, cause or permit the sale or 
introduction of gasoline containing greater than 10 volume percent 
ethanol (i.e., greater than E10) into any model year 2000 or older 
light-duty gasoline motor vehicle, any heavy-duty gasoline motor 
vehicle or engine, any highway or off-highway motorcycle, or any 
gasoline-powered nonroad engines, vehicles, or equipment.
    (b) Paragraph (a) of this section does not prohibit a person from 
producing, selling, introducing, or causing or allowing the sale or 
introduction of gasoline containing greater than 10 volume percent 
ethanol into any flex-fuel vehicle or flex-fuel engine.

Sec.  1090.270  RFG covered areas.

    For purposes of this part, the RFG covered areas are as follows:
    (a) RFG covered areas specified in 42 U.S.C. 7545(k)(10)(D):

                                            Table 1 to Paragraph (a)
----------------------------------------------------------------------------------------------------------------
          Area designation                    State                    Counties             Independent cities
----------------------------------------------------------------------------------------------------------------
Los Angeles-Anaheim-Riverside......  California............  Los Angeles, Orange,         ......................
                                                              Ventura, San
                                                              Bernardino,\1\ Riverside
                                                              \2\.
San Diego County...................  California............  San Diego..................  ......................
Greater Connecticut................  Connecticut...........  Hartford, Middlesex, New     ......................
                                                              Haven, New London,
                                                              Tolland, Windham,
                                                              Fairfield (only the City
                                                              of Shelton), Litchfield
                                                              (all except the towns of
                                                              Bridgewater and New
                                                              Milford).
New York-Northern New Jersey-Long    Connecticut...........  Fairfield (all except the    ......................
 Island-Connecticut.                                          City of Shelton),
                                                              Litchfield (only the towns
                                                              of Bridgewater and New
                                                              Milford).
                                     New Jersey............  Bergen, Essex, Hudson,       ......................
                                                              Hunterdon, Middlesex,
                                                              Monmouth, Morris, Ocean,
                                                              Passaic, Somerset, Sussex,
                                                              Union.
                                     New York..............  Bronx, Kings, Nassau, New    ......................
                                                              York, Orange, Putnam,
                                                              Queens, Richmond,
                                                              Rockland, Suffolk,
                                                              Westchester.
Philadelphia-Wilmington-Trenton....  Delaware..............  Kent, New Castle...........  ......................
                                     Maryland..............  Cecil......................  ......................
                                     New Jersey............  Burlington, Camden,          ......................
                                                              Cumberland, Gloucester,
                                                              Mercer, Salem.
                                     Pennsylvania..........  Bucks, Chester, Delaware,    ......................
                                                              Montgomery, Philadelphia.
Chicago-Gary-Lake County...........  Illinois..............  Cook, Du Page, Kane, Lake,   ......................
                                                              McHenry, Will, Grundy
                                                              (only Aux Sable Township
                                                              and Goose Lake Township),
                                                              Kendall (only Oswego
                                                              Township).
                                     Indiana...............  Lake, Porter...............  ......................
Baltimore..........................  Maryland..............  Anne Arundel, Baltimore,     Baltimore.
                                                              Carroll, Harford, Howard.
Houston-Galveston-Brazoria.........  Texas.................  Brazoria, Chambers, Fort     ......................
                                                              Bend, Galveston, Harris,
                                                              Liberty, Montgomery,
                                                              Waller.
Milwaukee-Racine...................  Wisconsin.............  Kenosha, Milwaukee,          ......................
                                                              Ozaukee, Racine,
                                                              Washington, Waukesha.
----------------------------------------------------------------------------------------------------------------
\1\ That portion of San Bernardino County, CA that lies south of latitude 35 degrees, 10 minutes north and west
  of longitude 115 degrees, 45 minutes west.
\2\ That portion of Riverside County, CA that lies to the west of a line described as follows: Beginning at the
  northeast corner of Section 4, Township 2 South, Range 5 East, a point on the boundary line common to
  Riverside and San Bernardino Counties; then southerly along section lines to the centerline of the Colorado
  River Aqueduct; then southeasterly along the centerline of said Colorado River Aqueduct to the southerly line
  of Section 36, Township 3 South, Range 7 East; then easterly along the township line to the northeast corner
  of Section 6, Township 4 South, Range 9 East; then southerly along the easterly line of Section 6 to the
  southeast corner thereof; then easterly along section lines to the northeast corner of Section 10, Township 4
  South, Range 9 East; then southerly along section lines to the southeast corner of Section 15, Township 4
  South, Range 9 East; then easterly along the section lines to the northeast corner of Section 21, Township 4
  South, Range 10 East; then southerly along the easterly line of Section 21 to the southeast corner thereof;
  then easterly along the northerly line of Section 27 to the northeast corner thereof; then southerly along
  section lines to the southeast corner of Section 34, Township 4 South, Range 10 East; then easterly along the
  township line to the northeast corner of Section 2, Township 5 South, Range 10 East; then southerly along the
  easterly line of Section 2, to the southeast corner thereof; then easterly along the northerly line of Section
  12 to the northeast corner thereof; then southerly along the range line to the southwest corner of Section 18,
  Township 5 South, Range 11 East; then easterly along section lines to the northeast corner of Section 24,
  Township 5 South, Range 11 East; and then southerly along the range line to the southeast corner of Section
  36, Township 8 South, Range 11 East, a point on the boundary line common to Riverside and San Diego Counties.

    (b) RFG covered areas based on being reclassified as Severe ozone 
nonattainment areas under 42 U.S.C. 7511(b):

                                            Table 2 to Paragraph (b)
----------------------------------------------------------------------------------------------------------------
          Area designation              State or district              Counties             Independent cities
----------------------------------------------------------------------------------------------------------------
Washington, DC-Maryland-Virginia...  District of Columbia..  Washington.................  ......................
                                     Maryland..............  Calvert, Charles,            ......................
                                                              Frederick, Montgomery,
                                                              Prince George's.

[[Page 29113]]

 
                                     Virginia..............  Arlington, Fairfax,          Alexandria, Fairfax,
                                                              Loudoun, Prince William,     Falls Church,
                                                              Stafford.                    Manassas, Manassas
                                                                                           Park.
Sacramento Metro...................  California............  Sacramento, Yolo, El Dorado  ......................
                                                              (except Lake Tahoe and its
                                                              drainage area), Placer,\1\
                                                              Solano,\2\ Sutter \3\.
San Joaquin Valley.................  California............  Fresno, Kings, Madera,       ......................
                                                              Merced, San Joaquin,
                                                              Stanislaus, Tulare, Kern
                                                              \4\.
----------------------------------------------------------------------------------------------------------------
\1\ All portions of Placer County except that portion of the County within the drainage area naturally tributary
  to Lake Tahoe including said Lake, plus that area in the vicinity of the head of the Truckee River described
  as follows: commencing at the point common to the aforementioned drainage area crestline and the line common
  to Townships 15 North and 16 North, Mount Diablo Base and Meridian (M.D.B.&M.), and following that line in a
  westerly direction to the northwest corner of Section 3, Township 15 North, Range 16 East, M.D.B.&M., thence
  south along the west line of Sections 3 and 10, Township 15 North, Range 16 East, M.D.B.&M., to the
  intersection with the said drainage area crestline, thence following the said drainage area boundary in a
  southeasterly, then northeasterly direction to and along the Lake Tahoe Dam, thence following the said
  drainage area crestline in a northeasterly, then northwesterly direction to the point of beginning.
\2\ That portion of Solano County that lies north and east of a line described as follows: beginning at the
  intersection of the westerly boundary of Solano County and the \1/4\ section line running east and west
  through the center of Section 34; T. 6 N., R. 2 W., M.D.B.&M. thence east along said \1/4\ section line to
  the east boundary of Section 36, T. 6 N., R. 2 W.; thence south \1/2\ mile and east 2.0 miles, more or less,
  along the west and south boundary of Los Putos Rancho to the northwest corner of Section 4, T. 5 N., R. 1 W.;
  thence east along a line common to T. 5 N. and T. 6 N. to the northeast corner of Section 3, T. 5 N., R. 1 E.;
  thence south along section lines to the southeast corner of Section 10, T. 3 N., R. 1 E.; thence east along
  section lines to the south \1/4\ corner of Section 8, T. 3 N., R. 2 E.; thence east to the boundary between
  Solano and Sacramento Counties.
\3\ That portion of Sutter County south of a line connecting the northern border of Yolo Co. to the SW tip of
  Yuba Co. and continuing along the southern Yuba Co. border to Placer Co.
\4\ Boundary between the Kern County and San Joaquin Valley air districts that generally follows the ridge line
  of the Sierra Nevada and Tehachapi Mountain Ranges. That portion of Kern County that lies west and north of a
  line described as follows: beginning at the Kern-Los Angeles County boundary and running north and east along
  the northwest boundary of the Rancho La Liebre Land Grant to the point of intersection with the range line
  common to Range 16 West and Range 17 West, San Bernardino Base and Meridian; north along the range line to the
  point of intersection with the Rancho El Tejon Land Grant boundary; then southeast, northeast, and northwest
  along the boundary of the Rancho El Tejon Grant to the northwest corner of Section 3, Township 11 North, Range
  17 West; then west 1.2 miles; then north to the Rancho El Tejon Land Grant boundary; then northwest along the
  Rancho El Tejon line to the southeast corner of Section 34, Township 32 South, Range 30 East, Mount Diablo
  Base and Meridian; then north to the northwest corner of Section 35, Township 31 South, Range 30 East; then
  northeast along the boundary of the Rancho El Tejon Land Grant to the southwest corner of Section 18, Township
  31 South, Range 31 East; then east to the southeast corner of Section 13, Township 31 South, Range 31 East;
  then north along the range line common to Range 31 East and Range 32 East, Mount Diablo Base and Meridian, to
  the northwest corner of Section 6, Township 29 South, Range 32 East; then east to the southwest corner of
  Section 31, Township 28 South, Range 32 East; then north along the range line common to Range 31 East and
  Range 32 East to the northwest corner of Section 6, Township 28 South, Range 32 East; then west to the
  southeast corner of Section 36, Township 27 South, Range 31 East; then north along the range line common to
  Range 31 East and Range 32 East to the Kern-Tulare County boundary.

    (c) RFG covered areas based on being classified ozone nonattainment 
areas at the time that the state requested to opt into RFG under 42 
U.S.C. 7545(k)(6)(A)(i):

                                            Table 3 to Paragraph (c)
----------------------------------------------------------------------------------------------------------------
Area designation at the time of opt-
                 in                           State                    Counties             Independent cities
----------------------------------------------------------------------------------------------------------------
Sussex County......................  Delaware..............  Sussex.....................  ......................
St. Louis, Missouri-Illinois.......  Illinois..............  Jersey, Madison, Monroe,     ......................
                                                              St. Clair.
                                     Missouri..............  Franklin, Jefferson, St.     St. Louis.
                                                              Charles, St. Louis.
Kentucky portion of Louisville.....  Kentucky..............  Jefferson, Bullitt,\1\       ......................
                                                              Oldham \2\.
Kent and Queen Anne's Counties.....  Maryland..............  Kent, Queen Anne's.........  ......................
Statewide..........................  Massachusetts.........  All........................  ......................
Strafford, Merrimack, Hillsborough,  New Hampshire.........  Hillsborough, Merrimack,     ......................
 Rockingham Counties.                                         Rockingham, Strafford.
Atlantic City......................  New Jersey............  Atlantic, Cape May.........  ......................
New Jersey portion of Allentown-     New Jersey............  Warren.....................  ......................
 Bethlehem-Easton.
Dutchess County....................  New York..............  Dutchess...................  ......................
Essex County.......................  New York..............  Essex (the portion of        ......................
                                                              Whiteface Mountain above
                                                              4,500 feet in elevation).
Statewide..........................  Rhode Island..........  All........................  ......................
Dallas-Fort Worth..................  Texas.................  Collin, Dallas, Denton,      ......................
                                                              Tarrant.
Norfolk-Virginia Beach, Newport      Virginia..............  James City, York...........  Chesapeake, Hampton,
 News (Hampton Roads).                                                                     Newport News,
                                                                                           Norfolk, Poquoson,
                                                                                           Portsmouth, Suffolk,
                                                                                           Virginia Beach,
                                                                                           Williamsburg.

[[Page 29114]]

 
Richmond...........................  Virginia..............  Charles City, Chesterfield,  Colonial Heights,
                                                              Hanover, Henrico.            Hopewell, Richmond.
----------------------------------------------------------------------------------------------------------------
\1\ In Bullitt County, KY, beginning at the intersection of Ky 1020 and the Jefferson-Bullitt County Line
  proceeding to the east along the county line to the intersection of county road 567 and the Jefferson-Bullitt
  County Line; proceeding south on county road 567 to the junction with Ky 1116 (also known as Zoneton Road);
  proceeding to the south on KY 1116 to the junction with Hebron Lane; proceeding to the south on Hebron Lane to
  Cedar Creek; proceeding south on Cedar Creek to the confluence of Floyds Fork turning southeast along a creek
  that meets Ky 44 at Stallings Cemetery; proceeding west along Ky 44 to the eastern most point in the
  Shepherdsville city limits; proceeding south along the Shepherdsville city limits to the Salt River and west
  to a point across the river from Mooney Lane; proceeding south along Mooney Lane to the junction of Ky 480;
  proceeding west on Ky 480 to the junction with Ky 2237; proceeding south on Ky 2237 to the junction with Ky 61
  and proceeding north on Ky 61 to the junction with Ky 1494; proceeding south on Ky 1494 to the junction with
  the perimeter of the Fort Knox Military Reservation; proceeding north along the military reservation perimeter
  to Castleman Branch Road; proceeding north on Castleman Branch Road to Ky 44; proceeding a very short distance
  west on Ky 44 to a junction with Ky 1020 and proceeding north on Ky 1020 to the beginning.
\2\ In Oldham County, KY, beginning at the intersection of the Oldham-Jefferson County Line with the southbound
  lane of Interstate 71; proceeding to the northeast along the southbound lane of Interstate 71 to the
  intersection of Ky 329 and the southbound lane of Interstate 71; proceeding to the northwest on Ky 329 to the
  intersection of Zaring Road on Ky 329; proceeding to the east-northeast on Zaring Road to the junction of
  Cedar Point Road and Zaring Road; proceeding to the north-northeast on Cedar Point Road to the junction of Ky
  393 and Cedar Point Road; proceeding to the south-southeast on Ky 393 to the junction of county road 746 (the
  road on the north side of Reformatory Lake and the Reformatory); proceeding to the east-northeast on county
  road 746 to the junction with Dawkins Lane (also known as Saddlers Mill Road) and county road 746; Proceeding
  to follow an electric power line east-northeast across from the junction of county road 746 and Dawkins Lane
  to the east-northeast across Ky 53 on to the La Grange Water Filtration Plant; proceeding on to the east-
  southeast along the power line then south across Fort Pickens Road to a power substation on Ky 146; proceeding
  along the power line south across Ky 146 and the Seaboard System Railroad track to adjoin the incorporated
  city limits of La Grange; then proceeding east then south along the La Grange city limits to a point abutting
  the north side of Ky 712; proceeding east-southeast on Ky 712 to the junction of Massie School Road and Ky
  712; proceeding to the south-southwest and then north-northwest on Massie School Road to the junction of Ky 53
  and Massie School Road; proceeding on Ky 53 to the north-northwest to the junction of Moody Lane and Ky 53;
  proceeding on Moody Lane to the south-southwest until meeting the city limits of La Grange; then briefly
  proceeding north following the La Grange city limits to the intersection of the northbound lane of Interstate
  71 and the La Grange city limits; proceeding southwest on the northbound lane of Interstate 71 until
  intersecting with the North Fork of Currys Fork; proceeding south-southwest beyond the confluence of Currys
  Fork to the south-southwest beyond the confluence of Floyds Fork continuing on to the Oldham-Jefferson County
  Line and proceeding northwest along the Oldham-Jefferson County Line to the beginning.

    (d) RFG covered area that is located in the ozone transport region 
established by 42 U.S.C. 7511c(a) that a state has requested to opt 
into RFG under 42 U.S.C. 7545(k)(6)(B)(i)(I):

                                            Table 4 to Paragraph (d)
----------------------------------------------------------------------------------------------------------------
                                State                                                  Counties
----------------------------------------------------------------------------------------------------------------
Maine...............................................................  Androscoggin, Cumberland, Kennebec, Knox,
                                                                       Lincoln, Sagadahoc, York.
----------------------------------------------------------------------------------------------------------------

Sec.  1090.275   Changes to RFG covered areas and procedures for opting 
out of RFG.

    (a) New RFG covered areas. (1) Effective 1 year after an area has 
been reclassified as a Severe ozone nonattainment area under 42 U.S.C. 
7511(b), such Severe area becomes a covered area under the RFG program 
as required by 42 U.S.C. 7545(k)(10)(D). The geographic extent of each 
such covered area must be the nonattainment area boundaries as 
specified in 40 CFR part 81, subpart C, for the ozone NAAQS that was 
the subject of the reclassification.
    (2) Any classified ozone nonattainment area identified in 40 CFR 
part 81, subpart C, as Marginal, Moderate, Serious, or Severe may be 
included as a covered area upon the request of the governor of the 
state in which the area is located. EPA must:
    (i) Publish the governor's request in the Federal Register upon 
receipt.
    (ii) Establish an effective date that is not later than 1 year 
after the request is received unless EPA determines that there is 
insufficient capacity to supply RFG as governed by 42 U.S.C. 
7545(k)(6)(A)(ii).
    (3) Any ozone attainment area in the ozone transport region 
established by 42 U.S.C. 7511c(a) may be included as a covered area 
upon petition by the governor of the state in which the area is located 
as governed by 42 U.S.C. 7545(k)(6)(B)(i). EPA must:
    (i) Publish the governor's request in the Federal Register as soon 
as practicable after it is received.
    (ii) Establish an effective date that is not later than 180 days 
after the request is received unless EPA determines that there is 
insufficient capacity to supply RFG as governed by 42 U.S.C. 
7545(k)(6)(B)(iii).
    (b) Opting out of RFG. Any area that opted into RFG under 42 U.S.C. 
7545(k)(6)(A) or (B) and has not subsequently been reclassified as a 
Severe ozone nonattainment area may opt out of RFG using the opt-out 
procedure in paragraph (d) of this section.
    (c) Eligibility for opting out of RFG. The governor of the state in 
which any covered area under 42 U.S.C. 7545(k)(10)(D) is located may 
request that EPA remove the prohibition specified in 42 U.S.C. 
7545(k)(5) in such area by following the opt-out procedure specified in 
paragraph (d) of this section upon one of the following:
    (1) Redesignation to attainment for such area for the most 
stringent ozone NAAQS in effect at the time of redesignation.
    (2) Designation as an attainment area for the most stringent ozone 
NAAQS in effect at the time of the designation. The area must also be 
redesignated to attainment for the prior ozone NAAQS.
    (d) Procedure for opting out of RFG. EPA may approve a request from 
a state asking for removal of any RFG opt-in area, or portion of an RFG 
opt-in area, from inclusion as a covered area listed in Sec.  
1090.270(c) and (d), if it meets the requirements of paragraph (d)(1) 
of this section. If EPA approves such a request, an effective date will 
be set as specified

[[Page 29115]]

in paragraph (d)(2) of this section. EPA will notify the state in 
writing of EPA's action on the request and the effective date of the 
removal when the request is approved.
    (1) An opt-out request must be signed by the governor of a state, 
or their authorized representative, and must include all the following:
    (i) A geographic description of each RFG opt-in area, or portion of 
each RFG opt-in area, which is covered by the request.
    (ii) A description of all ways in which emissions reductions from 
RFG are relied upon in any approved SIP or any submitted SIP that has 
not yet been approved by EPA.
    (iii) For any RFG opt-in areas covered by the request where 
emissions reductions from RFG are relied upon as specified in paragraph 
(d)(1)(ii) of this section, the request must include all the following 
information:
    (A) Identify whether the state is withdrawing any submitted SIP 
that has not yet been approved.
    (B)(1) Identify whether the state intends to submit a SIP revision 
to any approved SIP or any submitted SIP that has not yet been 
approved, which relies on emissions reductions from RFG, and describe 
any control measures that the state plans to submit to EPA for approval 
to replace the emissions reductions from RFG.
    (2) A description of the state's plans and schedule for adopting 
and submitting any revision to any approved SIP or any submitted SIP 
that has not yet been approved.
    (C) If the state is not withdrawing any submitted SIP that has not 
yet been approved and does not intend to submit a revision to any 
approved SIP or any submitted SIP that has not yet been approved, 
describe why no revision is necessary.
    (iv) The governor of a state, or their authorized representative, 
must submit additional information upon request by EPA.
    (2)(i) Except as specified in paragraph (d)(2)(ii) of this section, 
EPA will set an effective date of the RFG opt-out as requested by the 
governor, but no less than 90 days from EPA's written notification to 
the state approving the RFG opt-out request.
    (ii) Where emissions reductions from RFG are included in an 
approved SIP or any submitted SIP that has not yet been approved, other 
than as a contingency measure consisting of a future opt-in to RFG, EPA 
will set an effective date of the RFG opt-out as requested by the 
governor, but no less than 90 days from the effective date of EPA 
approval of the SIP revision that removes the emissions reductions from 
RFG, and, if necessary, provides emissions reductions to make up for 
those from RFG opt-out.
    (iii) Notwithstanding the provisions of paragraphs (d)(2)(i) and 
(ii) of this section, for an area in the ozone transport region that 
opted into RFG under 42 U.S.C. 7545(k)(6)(B), EPA will not set the 
effective date for removal of the area earlier than 4 years after the 
commencement date of opt-in.
    (4) EPA will publish a notice in the Federal Register announcing 
the approval of any RFG opt-out request and its effective date.
    (5) Upon the effective date for the removal of any RFG opt-in area 
or portion of an RFG opt-in area included in an approved request, such 
geographic area will no longer be considered an RFG covered area.
    (e) Revising list of RFG covered areas. EPA will periodically 
publish a final rule revising the list of RFG covered areas in Sec.  
1090.270.

Sec.  1090.280   Procedures for relaxing the federal 7.8 psi RVP 
standard.

    (a) EPA may approve a request from a state asking for relaxation of 
the federal 7.8 psi gasoline standard for any area, or portion of an 
area, required to use such gasoline, if it meets the requirements of 
paragraph (b) of this section. If EPA approves such a request, an 
effective date will be set as specified in paragraph (c) of this 
section. EPA will notify the state in writing of EPA's action on the 
request and the effective date of the relaxation when the request is 
approved.
    (b) The request must be signed by the governor of the state, or 
their authorized representative, and must include all the following:
    (1) A geographic description of each federal 7.8 psi gasoline area, 
or portion of such area, which is covered by the request.
    (2) A description of all ways in which emissions reduction from the 
federal 7.8 psi gasoline are relied upon in any approved SIP or in any 
submitted SIP that has not yet been approved by EPA.
    (3) For any federal 7.8 psi gasoline area covered by the request 
where emissions reductions from the federal 7.8 psi gasoline are relied 
upon as specified in paragraph (b)(2) of this section, the request must 
include the following information:
    (i) Identify whether the state is withdrawing any submitted SIP 
that has not yet been approved.
    (ii)(A) Identify whether the state intends to submit a SIP revision 
to any approved SIP or any submitted SIP that has not yet been 
approved, which relies on emissions reductions from federal 7.8 psi 
gasoline, and describe any control measures that the state plans to 
submit to EPA for approval to replace the emissions reductions from 
federal 7.8 psi gasoline.
    (B) A description of the state's plans and schedule for adopting 
and submitting any revision to any approved SIP or any submitted SIP 
that has not yet been approved.
    (iii) If the state is not withdrawing any submitted SIP that has 
not yet been approved and does not intend to submit a revision to any 
approved SIP or any submitted SIP that has not yet been approved, 
describe why no revision is necessary.
    (4) The governor of a state, or their authorized representative, 
must submit additional information upon request by EPA.
    (c)(1) Except as specified in paragraph (c)(2) of this section, EPA 
will set an effective date of the relaxation of the federal 7.8 psi 
gasoline standard as requested by the governor, but no less than 90 
days from EPA's written notification to the state approving the 
relaxation request.
    (2) Where emissions reductions from the federal 7.8 psi gasoline 
are included in an approved SIP or any submitted SIP that has not yet 
been approved, EPA will set an effective date of the relaxation of the 
federal 7.8 psi gasoline standard as requested by the governor, but no 
less than 90 days from the effective date of EPA approval of the SIP 
revision that removes the emissions reductions from the federal 7.8 psi 
gasoline, and, if necessary, provides emissions reductions to make up 
for those from the federal 7.8 psi gasoline relaxation.
    (d) EPA will publish a notice in the Federal Register announcing 
the approval of any federal 7.8 psi gasoline relaxation request and its 
effective date.
    (e) Upon the effective date for the relaxation of the federal 7.8 
psi gasoline standard in a subject area or portion of a subject area 
included in an approved request, such geographic area will no longer be 
considered a federal 7.8 psi gasoline area.
    (f) EPA will periodically publish a final rule revising the list of 
areas subject to the federal 7.8 psi gasoline standard in Sec.  
1090.215(a)(1).

Subpart D--Diesel Fuel and ECA Marine Fuel Standards

Sec.  1090.300   Overview and general requirements.

    (a) Diesel fuel is subject to the ULSD standards in Sec.  1090.305, 
except as follows:
    (1) Alternative sulfur standards apply for 500 ppm LM diesel fuel 
and ECA

[[Page 29116]]

marine fuel as specified in Sec. Sec.  1090.320 and 1090.325, 
respectively.
    (2) Exemption provisions apply as specified in subpart G of this 
part.
    (b) Diesel fuel additives must meet the requirements in Sec.  
1090.310.
    (c) Diesel fuel manufacturers and diesel fuel additive 
manufacturers must demonstrate compliance with the standards in this 
subpart by measuring fuel parameters in accordance with subpart M of 
this part.
    (d) All the standards in this part apply to diesel fuel and diesel 
fuel additives on a per-gallon basis.
    (e)(1) No person may produce, import, sell, offer for sale, 
distribute, offer to distribute, supply, offer for supply, dispense, 
store, transport, or introduce into commerce any diesel fuel, ECA 
marine fuel, or diesel fuel additive that exceeds any standard set 
forth in this subpart.
    (2) Notwithstanding paragraph (e)(1) of this section, importers may 
import diesel fuel that does not comply with the standards set forth in 
this subpart if all the following conditions are met:
    (i) The importer offloads the imported diesel fuel into one or more 
tanks that are physically located at the same import facility at which 
the imported diesel fuel first arrives in the United States or at a 
facility to which the imported diesel fuel is directly transported from 
the import facility at which the imported diesel fuel first arrived in 
the United States.
    (ii) The importer uses the imported diesel fuel to produce one or 
more new batches of diesel fuel.
    (iii) The importer certifies the new batch of diesel fuel under 
Sec.  1090.1100(c) and demonstrates that it complies with the standards 
in this subpart by measuring fuel parameters in accordance with subpart 
M of this part before title or custody to any new batch of diesel fuel 
is transferred.
    (f) No person may introduce used motor oil, or used motor oil 
blended with diesel fuel, into the fuel system of model year 2007 or 
later diesel motor vehicles or engines or model year 2011 or later 
nonroad diesel vehicles or engines (not including locomotive or marine 
diesel engines).

Sec.  1090.305   ULSD standards.

    (a) Overview. Except as specified in Sec.  1090.300(a)(1) and (2), 
diesel fuel must meet the ULSD per-gallon standards of this section.
    (b) Sulfur standard. Maximum sulfur content of 15 ppm.
    (c) Cetane index or aromatic content. Diesel fuel must meet one of 
the following standards:
    (1) Minimum cetane index of 40.
    (2) Maximum aromatic content 35 volume percent.

Sec.  1090.310   Diesel fuel additives standards.

    This section specifies how the ULSD sulfur standard applies to 
additives blended into diesel fuel that is subject to the standards in 
Sec.  1090.305.
    (a) Except as specified in paragraph (b) and (c) of this section, 
diesel fuel additives must have a sulfur concentration less than or 
equal to 15 ppm on a per-gallon basis.
    (b) Diesel fuel additives do not have to comply with paragraph (a) 
of this section if all the following conditions are met:
    (1) The additive is added to or used in diesel fuel in a quantity 
less than 1.0 volume percent of the resultant additive/diesel fuel 
mixture.
    (2) The PTD complies with the requirements in Sec.  1090.1170(b).
    (3) The additive is not commercially available as a retail product 
for ultimate consumers.
    (c) The provisions of this section do not apply to additives used 
with 500 ppm LM diesel fuel or ECA marine fuel.

Sec.  1090.315   Heating oil, kerosene, and jet fuel provisions.

    Heating oil, kerosene, and jet fuel may not be sold for use in 
motor vehicles or non-road equipment and are not subject to the ULSD 
standards in Sec.  1090.305 unless also designated as ULSD under Sec.  
1090.1115(a).

Sec.  1090.320   500 ppm LM diesel fuel standards.

    (a) Overview. Transmix processors and pipeline operators that 
produce and distribute 500 ppm LM diesel fuel under Sec.  1090.520 for 
use only in the eligible locomotives and marine engines must meet the 
per-gallon standards of this section.
    (b) Sulfur standard. Maximum sulfur content of 500 ppm.
    (c) Cetane index or aromatic content. The standard for cetane index 
or aromatic content in Sec.  1090.305(c) applies to 500 ppm LM diesel 
fuel.

Sec.  1090.325   ECA marine fuel standards.

    (a) Overview. Expect as specified in paragraph (c) of this section, 
ECA marine fuel must meet the per-gallon standards and provisions of 
this section.
    (b) Standards. ECA marine fuel is subject to the following per-
gallon standards.
    (1) Sulfur per-gallon standard. Maximum sulfur content of 1,000 
ppm.
    (2) [Reserved]
    (c) Exceptions. The standards in paragraph (b) of this section do 
not apply to the following:
    (1) Residual fuel made available for use in a steamship or C3 
marine vessel if the U.S. government allows the vessel to be exempt or 
excluded from MARPOL Annex VI fuel standards. Diesel fuel and other 
distillate fuel used in diesel engines operated on such vessels is 
subject to the standards in this section instead of the standards in 
Sec.  1090.305 or Sec.  1090.320.
    (2) Distillate global marine fuel that is exempt under Sec.  
1090.650.

Subpart E--Reserved

Subpart F--Transmix and Pipeline Interface Provisions

Sec.  1090.500   Scope.

    (a) This subpart contains provisions for transmix blenders, 
transmix processors, and distributors that produce and distribute the 
specified fuels from transmix.
    (b) Any person other than a transmix blender that uses the 
provisions of this subpart must be registered with EPA under subpart I 
of this part.

Sec.  1090.505   Gasoline produced from blending transmix into PCG.

    (a) Except as specified in paragraph (f) of this section, transmix 
blenders who blend transmix into PCG under Sec.  1090.150 must comply 
with the requirements of this section.
    (b)(1) The resultant transmix-blended gasoline must not exceed a 
distillation end-point of 437 degrees Fahrenheit.
    (2) The resultant transmix-blended gasoline must meet the 
downstream sulfur per-gallon standard in Sec.  1090.205(c) and the 
applicable RVP standard in Sec.  1090.215.
    (3) The transmix blender must comply with the recordkeeping 
requirements in Sec.  1090.1255.
    (4) The transmix blender must maintain and follow a written quality 
assurance program designed to assure that the type and amount of 
transmix blended into PCG will not cause violations of the applicable 
fuel quality standards.
    (c) Except as specified in paragraph (d) of this section, as a part 
of the quality assurance program, transmix blenders must collect 
samples of gasoline after blending transmix and test the samples to 
ensure the end-point temperature of the final transmix-blended gasoline 
does not exceed 437 degrees Fahrenheit, using one of the following 
sampling methods:
    (1) For transmix that is blended in a tank (including a tank on a 
barge), collect a representative sample of the final transmix-blended 
gasoline following each occasion transmix is blended.
    (2) For transmix that is blended by a computer controlled in-line 
blending

[[Page 29117]]

system, the transmix blender must collect composite samples of the 
final transmix-blended gasoline at least twice each calendar month 
during which transmix is blended. In-line samples may be collected to 
comply with the requirements of this paragraph if the applicable 
requirements in paragraph (d)(2) of this section are met.
    (d) Any transmix blender may petition EPA for approval of a quality 
assurance program that does not include the minimum sampling and 
testing requirements in paragraph (c) of this section. To seek approval 
for such an alternative quality assurance program, the transmix blender 
must submit a petition to EPA that includes all the following:
    (1) A detailed description of the quality assurance procedures to 
be carried out at each location where transmix is blended into PCG, 
including a description of how the transmix blender proposes to 
determine the ratio of transmix that can be blended with PCG without 
violating any of the applicable standards in this part, and a 
description of how the transmix blender proposes to determine that the 
gasoline produced by the transmix blending operation meets the 
applicable standards.
    (2) If the transmix is blended by a computer controlled in-line 
blending system, the transmix blender must also include the information 
required for refiners related to the approval by EPA of the use of an 
in-line blending system under Sec.  1090.1315.
    (3) A letter signed by the RCO or their delegate stating that the 
information contained in the submission is true to the best of their 
belief must accompany the petition.
    (4) Transmix blenders that petition EPA to use an alternative 
quality assurance program must comply with any request by EPA for 
additional information or any other requirements that EPA includes as 
part of EPA's evaluation of the petition. However, the transmix blender 
may withdraw their petition or approved use of an alternative quality 
assurance program at any time, upon notice to EPA.
    (5) EPA reserves the right to modify the requirements of an 
approved alternative quality assurance program, in whole or in part, at 
any time, or withdraw approval of such an alternative quality assurance 
program if EPA determines that the transmix blender's operation does 
not effectively or adequately control, monitor, or document the end-
point temperature of the gasoline produced, or if EPA determines that 
any other circumstance exists that merits modification of the 
requirements of an approved alternative quality assurance program.
    (e) In the event that the test results for any sample collected 
under a quality assurance program indicate that the gasoline does not 
comply with any of the applicable standards in this part, the transmix 
blender must do all the following:
    (1) Immediately take steps to stop the sale of the gasoline that 
was sampled.
    (2) Take reasonable steps to determine the cause of the 
noncompliance and prevent future instances of noncompliance.
    (3) Notify EPA of the noncompliance.
    (4) If the transmix was blended by a computer controlled in-line 
blending system, increase the rate of sampling and testing to a minimum 
frequency of once per week and a maximum frequency of once per day and 
continue the increased frequency of sampling and testing until the 
results of 10 consecutive samples and tests indicate that the gasoline 
complies with applicable standards, at which time the sampling and 
testing may be conducted at the original frequency.
    (f) Small volumes of fuel that are captured in pipeline sumps or 
trapped in pipeline pumps or valve manifolds and that are injected back 
into batches of gasoline or diesel fuel are exempt from the transmix 
blending requirements in this section.

Sec.  1090.510   Gasoline produced from TGP.

    (a) General provisions. (1) Transmix processors who produce 
gasoline from TGP under Sec.  1090.145 must meet the requirements of 
this section.
    (2) Transmix processors may not use any feedstock other than 
transmix to produce TGP or TDP.
    (3) Transmix processors may produce gasoline using only TGP, a 
combination of TGP and PCG, a combination of TGP and blendstock(s), or 
a combination TGP, PCG, and blendstock(s) under the provisions of this 
section.
    (b) Demonstration of compliance with sulfur per-gallon standard. 
Transmix processors must demonstrate that each batch of gasoline they 
produce meets one of the following sulfur standards, as applicable, by 
measuring the sulfur content of each batch of gasoline in accordance 
with subpart M of this part:
    (1) Each batch of gasoline produced solely from TGP or a 
combination of TGP and PCG must comply with the downstream sulfur per-
gallon standard in Sec.  1090.205(c).
    (2) Each batch of gasoline produced from a combination of TGP and 
any blendstock must comply with the fuel manufacturing facility gate 
sulfur per-gallon standard in Sec.  1090.205(b).
    (c) Demonstration of compliance with sulfur and benzene average 
standards. (1) Transmix processors must exclude TGP and PCG used to 
produce gasoline under the provisions of this section and PCG blended 
with TGP from their compliance calculations to demonstrate compliance 
with the sulfur and benzene average standards in Sec. Sec.  1090.205(a) 
and 1090.210, respectively. Transmix processors that produce gasoline 
from only TGP or TGP and PCG are deemed to be in compliance with the 
sulfur and benzene average standards in Sec. Sec.  1090.205(a) and 
1090.210, respectively.
    (2) Transmix processors must include any blendstocks other than TGP 
and exclude any TGP and PCG used to produce gasoline under the 
provisions of this section in calculations to demonstrate compliance 
with the sulfur and benzene average standards in Sec. Sec.  1090.205(a) 
and 1090.210, respectively.
    (3) Transmix processors must comply with the provisions in Sec.  
1090.1325 for gasoline produced by adding blendstock to TGP.
    (d) Demonstration of compliance with RVP standard. Transmix 
processors must demonstrate that each batch of gasoline they produce 
meets the applicable RVP standard in Sec.  1090.215 by measuring the 
RVP of each batch in accordance with subpart M of this part.
    (e) Distillation point determination. Transmix processors must 
determine the following distillation parameters for each batch of 
gasoline they produce in accordance with subpart M of this part:
    (1) T10.
    (2) T50.
    (3) T90.
    (4) End-point.
    (5) Distillation residue.

Sec.  1090.515   ULSD produced from TDP.

    Except as specified in Sec.  1090.520, transmix processors must 
demonstrate that each batch of diesel fuel produced from TDP meets the 
ULSD standards in Sec.  1090.305 by measuring the sulfur content of 
each batch of diesel fuel in accordance with subpart M of this part.

Sec.  1090.520   500 ppm LM diesel fuel produced from TDP.

    (a) Overview. Transmix processors who produce 500 ppm LM diesel 
fuel from TDP must comply with the requirements of this section and the 
standards for 500 ppm LM diesel fuel specified in Sec.  1090.320.
    (b) Blending component limitation. Transmix processors may only use 
the following components to produce 500 ppm LM diesel fuel:
    (1) TDP.

[[Page 29118]]

    (2) ULSD.
    (3) Diesel fuel additives that comply with the requirements in 
Sec.  1090.310.
    (c) Volume requirements. Parties that handle 500 ppm LM diesel fuel 
must calculate the volume of 500 ppm LM diesel fuel received versus the 
volume delivered and used on a compliance period basis. An increase in 
the volume of 500 ppm LM diesel fuel delivered compared to the volume 
received must be due solely to one or more of the following:
    (1) Normal pipeline interface cutting practices under paragraph 
(e)(1) of this section.
    (2) Thermal expansion due to a temperature difference between the 
times when the volume of 500 ppm LM diesel fuel received and the volume 
of 500 ppm LM diesel fuel delivered were measured.
    (3) The addition of ULSD to a retail outlet or WPC 500 ppm LM 
diesel fuel storage tank under paragraph (e)(2) of this section.
    (d) Use restrictions. 500 ppm LM diesel fuel may only be used in 
locomotive and marine engines that are not required to use ULSD under 
40 CFR 1033.815 and 40 CFR 1042.660, respectively. No person may use 
500 ppm LM diesel fuel in locomotive or marine engines that are 
required to use ULSD, in any nonroad vehicle or engine, or in any motor 
vehicle engine.
    (e) Segregation requirement. Transmix processors and distributors 
must segregate 500 ppm LM diesel fuel from other fuels except as 
follows:
    (1) Pipeline operators may ship 500 ppm LM diesel fuel by pipeline 
provided that the 500 ppm LM diesel fuel does not come into physical 
contact in the pipeline with distillate fuels that have a sulfur 
content greater than 15 ppm. If 500 ppm LM diesel fuel is shipped by 
pipeline adjacent to ULSD, the pipeline operator must cut ULSD into the 
500 ppm LM diesel fuel.
    (2) WPCs and retailers of 500 ppm LM diesel fuel may introduce ULSD 
into a storage tank that contains 500 ppm LM diesel fuel, provided that 
the other requirements of this section are satisfied. The resulting 
mixture must be designated as 500 ppm LM diesel fuel.
    (f) Party limit. No more than 4 separate parties may handle the 500 
ppm LM diesel fuel between the producer and the ultimate consumer.
    (g) Compliance plan. For each facility, a transmix processor that 
produces 500 ppm LM diesel fuel must obtain approval from EPA for a 
compliance plan at least 60 days prior to producing 500 ppm LM diesel 
fuel. The compliance plan must detail how the transmix processor 
intends to meet all the following requirements:
    (1) Demonstrate how the 500 ppm LM diesel fuel will be segregated 
by the producer through to the ultimate consumer from fuel having other 
designations under paragraph (e) of this section.
    (2) Demonstrate that the end users of 500 ppm LM diesel fuel will 
also have access to ULSD for use in those engines that require ULSD.
    (3) Identify the parties that handle the 500 ppm LM diesel fuel 
through to the ultimate consumer.
    (4) Identify all ultimate consumers that are supplied with the 500 
ppm LM diesel fuel.
    (5) Demonstrate how misfueling of 500 ppm LM diesel fuel into 
vehicles, engines, or equipment that require the use of ULSD will be 
prevented.
    (6) Include an EPA registration number.

Sec.  1090.525   Handling practices for pipeline interface that is not 
transmix.

    (a) Subject to the limitations in paragraph (b) of this section, 
pipeline operators may cut pipeline interface from two batches of 
gasoline subject to EPA standards that are shipped adjacent to each 
other by pipeline into either or both these batches of gasoline 
provided that this action does not cause or contribute to a violation 
of the standards in this part.
    (b) During the summer season, pipeline operators may not cut 
pipeline interface from two batches of gasoline subject to different 
RVP standards that are shipped adjacent to each other by pipeline into 
the gasoline batch that is subject to the more stringent RVP standard. 
For example, during the summer season, pipeline operators may not cut 
pipeline interface from a batch of RFG shipped adjacent to a batch of 
conventional gasoline into the batch of RFG.
    (c) 500 ppm LM diesel fuel may be shipped via pipeline as specified 
in Sec.  1090.520(e)(1).

Subpart G--Exemptions, Hardships, and Special Provisions

Sec.  1090.600   General provisions.

    (a) Gasoline, diesel fuel, or IMO marine fuel that is exempt under 
this section is exempt from all other provisions of this part, unless 
otherwise stated.
    (b) Fuel not meeting all the requirements and conditions specified 
in this subpart for an exemption is subject to all applicable standards 
and requirements of this part.

Sec.  1090.605   National security and military use exemptions.

    (a) Fuel, fuel additive, and regulated blendstock that is produced, 
imported, sold, offered for sale, supplied, offered for supply, stored, 
dispensed, or transported for use in the following tactical military 
vehicles, engines, or equipment, including locomotive and marine 
engines, are exempt from the standards specified in this part:
    (1) Tactical military vehicles, engines, or equipment, including 
locomotive and marine engines, that have an EPA national security 
exemption from the motor vehicle emission standards under 40 CFR parts 
85 or 86, or from the nonroad engine emission standards under 40 CFR 
parts 89, 92, 94, 1042, or 1068.
    (2) Tactical military vehicles, engines, or equipment, including 
locomotive and marine engines, that are not subject to a national 
security exemption from vehicle or engine emissions standards specified 
in paragraph (a)(1) of this section but, for national security purposes 
(e.g., for purposes of readiness, including training, for deployment 
overseas), need to be fueled on the same fuel as the vehicles, engines, 
or equipment that EPA has granted such a national security exemption.
    (b) The exempt fuel must meet all the following requirements:
    (1) It must be accompanied by PTDs meeting the requirements of 
subpart K of this part.
    (2) It must be segregated from non-exempt fuel at all points in the 
distribution system.
    (3) It must be dispensed from a fuel pump stand, fueling truck, or 
tank that is labeled with the appropriate designation of the fuel.
    (4) It may not be used in any vehicles, engines, or equipment, 
including locomotive and marine engines, other than those specified in 
paragraph (a) of this section.

Sec.  1090.610   Temporary research, development, and testing 
exemptions.

    (a) Requests for an exemption. (1) Any person may receive an 
exemption from the provisions of this part for fuel used for research, 
development, or testing (``R&D'') purposes by submitting the 
information specified in paragraph (c) of this section as specified in 
Sec.  1090.10.
    (2) Any person that is performing emissions certification testing 
for a motor vehicle or motor vehicle engine under 42 U.S.C. 7525 or 
nonroad engine or nonroad vehicle under 42 U.S.C. 7546 is exempt from 
the provisions of this part for the fuel they are using for emissions 
certification testing if they

[[Page 29119]]

have an exemption under 40 CFR parts 85 and 86 to perform such testing.
    (b) Criteria for an R&D exemption. For an R&D exemption to be 
granted, the person requesting an exemption must meet all the following 
conditions:
    (1) Demonstrate a purpose that constitutes an appropriate basis for 
exemption.
    (2) Demonstrate that an exemption is necessary.
    (3) Design an R&D program that is reasonable in scope.
    (4) Have a degree of control consistent with the purpose of the 
program and EPA's monitoring requirements.
    (c) Information required to be submitted. To aid in demonstrating 
each of the elements in paragraph (b) of this section, the person 
requesting an exemption must include, at a minimum, all the following 
information:
    (1) A concise statement of the purpose of the program demonstrating 
that the program has an appropriate R&D purpose.
    (2) An explanation of why the stated purpose of the program is 
unable to be achieved in a practicable manner without meeting the 
requirements of this part.
    (3) A demonstration of the reasonableness of the scope of the 
program, including all the following:
    (i) An estimate of the program's duration in time (including 
beginning and ending dates).
    (ii) An estimate of the maximum number of vehicles, engines, and 
equipment involved in the program, and the number of miles and engine 
hours that will be accumulated on each.
    (iii) The manner in which the information on vehicles, engines, or 
equipment used in the program will be recorded and made available to 
EPA upon request.
    (iv) The quantity of the fuel that does not comply with the 
requirements of this part, as applicable.
    (v) The specific applicable standard(s) of this part that would 
apply to the fuel expected to be used in the program.
    (4) With regard to control, a demonstration that the program 
affords EPA a monitoring capability, including all the following:
    (i) A description of the technical and operational aspects of the 
program.
    (ii) The site(s) of the program (including facility name, street 
address, city, county, state, and ZIP code).
    (iii) The manner in which information on vehicles, engines, and 
equipment used in the program will be recorded and made available to 
EPA upon request.
    (iv) The manner in which information on the fuel used in the 
program (including quantity, fuel properties, name, address, telephone 
number, and contact person of the supplier, and the date received from 
the supplier) will be recorded and made available to EPA upon request.
    (v) The manner in which the party will ensure that the fuel will be 
segregated from fuel meeting the requirements of subparts C and D of 
this part, as applicable, and how fuel pumps will be labeled to ensure 
proper use of the fuel.
    (vi) The name, business address, telephone number, and title of the 
person(s) in the organization requesting an exemption from whom further 
information on the application may be obtained.
    (vii) The name, business address, telephone number, and title of 
the person(s) in the organization requesting an exemption who is 
responsible for recording and making available the information 
specified in this paragraph, and the location where such information 
will be maintained.
    (viii) Any other information requested by EPA to determine whether 
the test program satisfies the criteria of paragraph (b) of this 
section.
    (d) Additional requirements. (1) The PTDs associated with fuel must 
comply with subpart K of this part.
    (2) The fuel must be designated by the fuel manufacturer or 
supplier, as applicable, as exempt fuel.
    (3) The fuel must be kept segregated from non-exempt fuel at all 
points in the distribution system.
    (4) The fuel must not be sold, distributed, offered for sale or 
distribution, dispensed, supplied, offered for supply, transported to 
or from, or stored by a fuel retail outlet, or by a WPC facility, 
unless the WPC facility is associated with the R&D program that uses 
the fuel.
    (5) At the completion of the program, any emission control systems 
or elements of design that are damaged or rendered inoperative must be 
replaced on vehicles remaining in service, or the responsible person 
will be liable for a violation of 42 U.S.C. 7522(a)(3) unless 
sufficient evidence is supplied that the emission controls or elements 
of design were not damaged.
    (e) Approval of exemption. EPA may grant an R&D exemption upon a 
demonstration that the requirements of this section have been met. The 
R&D exemption may include such terms and conditions as EPA determines 
necessary to monitor the exemption and to carry out the purposes of 
this part, including restoration of emission control systems.
    (1) The volume of fuel subject to the approval must not exceed the 
estimated amount in paragraph (c)(3)(iv) of this section, unless EPA 
grants a greater amount.
    (2) Any exemption granted under this section will expire at the 
completion of the test program or 1 year from the date of approval, 
whichever occurs first, and may only be extended upon re-application 
consistent will all requirements of this section.
    (3) In granting an exemption, EPA may include terms and conditions, 
including replacement of emission control devices or elements of 
design, which EPA determines are necessary for monitoring the exemption 
and for assuring that the purposes of this part are met.
    (4) If any information required by paragraph (c) of this section 
changes after approval of the exemption, the responsible person must 
notify EPA in writing immediately. Failure to do so may result in 
disapproval of the exemption or may make it void ab initio and may make 
the party liable for a violation of this part.
    (f) Notification of completion. Any person with an approved 
exemption under this section must notify EPA in writing within 30 days 
after completion of the R&D program.

Sec.  1090.615   Racing and aviation exemptions.

    (a) Fuel, fuel additive, and regulated blendstock that is used in 
aircraft, or racing vehicles or racing boats in sanctioned racing 
events, is exempt from the standards in subparts C and D of this part 
if all the requirements of this section are met.
    (b) The fuel, fuel additive, or regulated blendstock is identified 
on PTDs and any fuel dispenser from which such fuel, fuel additive, or 
regulated blendstock is dispensed, as restricted for use either in 
aircraft, or in racing motor vehicles or racing boats that are used 
only in sanctioned racing events.
    (c) The fuel, fuel additive, or regulated blendstock is completely 
segregated from all other non-exempt fuel, fuel additive, or regulated 
blendstock throughout production, distribution, and sale to the 
ultimate consumer.
    (d) The fuel, fuel additive, or regulated blendstock is not made 
available for use as gasoline or diesel fuel subject to the standards 
in subparts C and D of this part, as applicable, or dispensed for use 
in motor vehicles or nonroad engines, vehicles, or equipment, including 
locomotive and marine engines, except for those used only in sanctioned 
racing events.

[[Page 29120]]

    (e) Any party that transports fuel exempt under this section must 
take reasonable precautions to avoid the contamination of nonexempt 
fuel. For example, parties should prepare tanker trucks under API 
recommended practice 1595 or the Energy Institute & Joint Inspection 
Group standard 1530 to avoid contamination of nonexempt fuel when the 
same tanker truck is used to transport exempt and nonexempt fuels.

Sec.  1090.620   Exemptions for Guam, American Samoa, and the 
Commonwealth of the Northern Mariana Islands.

    Fuel that is produced, imported, sold, offered for sale, supplied, 
offered for supply, stored, dispensed, or transported for use in the 
territories of Guam, American Samoa, or the Commonwealth of the 
Northern Mariana Islands, is exempt from the standards in subparts C 
and D of this part if all the following requirements are met:
    (a) The fuel is designated by the fuel manufacturer as gasoline, 
diesel fuel, or IMO marine fuel for use only in Guam, American Samoa, 
or the Commonwealth of the Northern Mariana Islands.
    (b) The fuel is used only in Guam, American Samoa, or the 
Commonwealth of the Northern Mariana Islands.
    (c) The fuel is accompanied by PTDs meeting the requirements of 
subpart K of this part.
    (d) The fuel is completely segregated from non-exempt gasoline, 
diesel fuel, and IMO marine fuel at all points throughout production, 
distribution, and sale to the ultimate consumer from the point the fuel 
is designated as exempt fuel for use only in Guam, American Samoa, or 
the Commonwealth of the Northern Mariana Islands, while the exempt fuel 
is in the United States (including an ECA or an ECA associated area 
under 40 CFR 1043.20) but outside these territories.

Sec.  1090.625   Exemptions for California gasoline and diesel fuel.

    (a) California gasoline and diesel fuel exemption. California 
gasoline or diesel fuel that complies with all the requirements of this 
section is exempt from all other provisions of this part.
    (b) California gasoline and diesel fuel requirements. (1) Each 
batch of California gasoline or diesel fuel must be designated as such 
by its fuel manufacturer.
    (2) Designated California gasoline or diesel fuel must be kept 
segregated from fuel that is not California gasoline or diesel fuel at 
all points in the distribution system.
    (3) Designated California gasoline or diesel fuel must ultimately 
be used only in the state of California.
    (4) Transferors and transferees of California gasoline or diesel 
fuel produced outside the state of California must meet the PTD 
requirements of subpart K of this part.
    (5) Each transferor and transferee of California gasoline or diesel 
fuel produced outside the state of California must maintain copies of 
the PTDs as specified in subpart L of this part.
    (6) California gasoline or diesel fuel may not be used in any part 
of the United States outside of the state of California unless the 
manufacturer or distributor recertifies or redesignates the batch of 
California gasoline or diesel fuel as specified in paragraph (d) or (e) 
of this section.
    (c) Use of California test methods and offsite sampling procedures. 
For any gasoline or diesel fuel that is not California gasoline or 
diesel fuel and that is either produced at a facility located in the 
state of California or is imported from outside the United States into 
the state of California, the manufacturer may do any of the following:
    (1) Use the sampling and testing methods approved in Title 13 of 
the California Code of Regulations instead of the sampling and testing 
methods required by subpart M of this part.
    (2) Determine the sulfur content, benzene content, and RVP (during 
the summer) of gasoline at offsite tankage (which would otherwise be 
prohibited under Sec.  1090.1615(c)) if the following requirements are 
met:
    (i) The samples are properly collected under the terms of a current 
and valid protocol agreement between the manufacturer and the 
California Air Resources Board with regard to sampling at the offsite 
tankage and consistent with the requirements specified in Title 13, 
California Code of Regulations, section 2250 et seq. (May 1, 2003).
    (ii) The manufacturer provides a copy of the protocol agreement to 
EPA upon request.
    (d) California gasoline used outside of California. California 
gasoline may either be recertified as gasoline under this part or may 
be used in any part of the United States outside of the state of 
California if the fuel designated as California gasoline meets all 
applicable requirements for California reformulated gasoline under 
Title 13 of the California Code of Regulations and the manufacturer or 
distributor of such fuel does all the following:
    (1) The manufacturer or distributor properly redesignates the fuel 
under Sec.  1090.1110(b)(2)(v).
    (2) The manufacturer or distributor generates PTDs under subpart K 
of this part.
    (3) The manufacturer or distributor keeps records under subpart L 
of this part.
    (4) The manufacturer or distributor does not include the California 
gasoline in their average standard compliance calculations.
    (e) California diesel used outside California. California diesel 
fuel may be used in any part of the United States outside of the state 
of California and is deemed to meet the standards in subpart D of this 
part without recertification if the fuel designated as California 
diesel fuel meets all applicable requirements for diesel fuel under 
Title 13 of the California Code of Regulations and the manufacturer or 
distributor of such fuel does all the following:
    (1) The manufacturer or distributor properly redesignates the fuel 
under Sec.  1090.1115(b)(3)(iii).
    (2) The manufacturer or distributor generates PTDs under subpart K 
of this part.
    (3) The manufacturer or distributor keeps records under subpart L 
of this part.

Sec.  1090.630   Exemptions for Alaska, Hawaii, Puerto Rico, and the 
U.S. Virgin Islands summer gasoline.

    Summer gasoline that is produced, imported, sold, offered for sale, 
supplied, offered for supply, stored, dispensed, or transported for use 
in the Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, is 
exempt from the RVP standards in Sec.  1090.215 if all the following 
requirements are met:
    (a) The summer gasoline is designated by the fuel manufacturer as 
summer gasoline for use only in Alaska, Hawaii, Puerto Rico, or the 
U.S. Virgin Islands.
    (b) The summer gasoline is used only in Alaska, Hawaii, Puerto 
Rico, or the U.S. Virgin Islands.
    (c) The summer gasoline is accompanied by PTDs meeting the 
requirements of subpart K of this part.
    (d) The summer gasoline is completely segregated from non-exempt 
gasoline at all points throughout production, distribution, and sale to 
the ultimate consumer from the point the summer gasoline is designated 
as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. 
Virgin Islands, while the exempt summer gasoline is in the United 
States but outside these states or territories.

Sec.  1090.635   Refinery extreme unforeseen hardship exemption.

    (a) In appropriate extreme, unusual, and unforeseen circumstances 
(e.g.,

[[Page 29121]]

circumstances like a natural disaster or refinery fire; not financial 
or supplier difficulties) that are clearly outside the control of the 
refiner and that could not have been avoided by the exercise of 
prudence, diligence, and due care, EPA may permit a refiner, for a 
brief period, to distribute fuel that is exempt from the standards in 
subparts C and D of this part if all the following requirements are 
met:
    (1) It is in the public interest to do so (e.g., distribution of 
the nonconforming fuel will not damage vehicles or engines and is 
necessary to meet projected shortfalls that are unable to otherwise be 
compensated for).
    (2) The refiner exercised prudent planning and was not able to 
avoid the violation and has taken all reasonable steps to minimize the 
extent of the nonconformity.
    (3) The refiner can show how the requirements for making compliant 
fuel, and/or purchasing credits to partially or completely offset the 
nonconformity, will be expeditiously achieved.
    (4) The refiner agrees to make up any air quality detriment 
associated with the nonconforming fuel, where practicable.
    (5) The refiner pays to the U.S. Treasury an amount equal to the 
economic benefit of the nonconformity minus the amount expended under 
paragraph (a)(4) of this section, in making up the air quality 
detriment.
    (b) Hardship applications under this section must be submitted to 
EPA as specified in Sec.  1090.10 and must contain a letter signed by 
the RCO, or their delegate, stating that the information contained in 
the application is true to the best of their knowledge.

Sec.  1090.640   Exemptions from the gasoline deposit control 
requirements.

    (a) Gasoline that is used to produce E85 is exempt from the 
gasoline deposit control requirements in Sec.  1090.240.
    (b) Any person that uses the exemption in paragraph (a) of this 
section must keep records to demonstrate that such exempt gasoline was 
used to produce E85 and was not distributed from a terminal for use as 
gasoline.

Sec.  1090.645   Exemption for exports of fuels, fuel additives, and 
regulated blendstocks.

    Fuel, fuel additive, and regulated blendstock that is exported for 
sale outside of the United States is exempt from the standards in 
subparts C and D of this part if all the following requirements are 
met:
    (a) The fuel manufacturer, fuel additive manufacturer, or regulated 
blendstock producer designated the fuel, fuel additive, or regulated 
blendstock for export as specified in Sec.  1090.1650(a).
    (b) The fuel, fuel additive, or regulated blendstock designated for 
export is accompanied by PTDs meeting the requirements of subpart K of 
this part.
    (c) The fuel, fuel additive, or regulated blendstock is ultimately 
exported from the United States.
    (d) The fuel, fuel additive, or regulated blendstock must be 
completely segregated from non-exempt fuels, fuel additives, and 
regulated blendstocks at all points throughout the production and 
distribution system, from the point the fuel, fuel additive, or 
regulated blendstock is produced or imported to the point where the 
fuel, fuel additive, or regulated blendstock is ultimately exported 
from the United States.
    (e) Any fuel dispensed from a retail outlet within the geographic 
boundaries of the United States is not exempt under this section.

Sec.  1090.650   Distillate global marine fuel exemption.

    (a) The standards of subpart D of this part do not apply to 
distillate global marine fuel that is produced, imported, sold, offered 
for sale, supplied, offered for supply, stored, dispensed, or 
transported for use in steamships or Category 3 marine vessels when 
operating outside of ECA boundaries.
    (b) The exempt fuel must meet all the following:
    (1) It must not exceed 0.50 weight percent sulfur (5,000 ppm).
    (2) It must be accompanied by PTDs as specified in Sec.  1090.1165.
    (3) It must be designated as specified in Sec.  1090.1115.
    (4) It must be segregated from non-exempt fuel at all points in the 
distribution system.
    (5) It must not be used in vehicles, engines, or equipment other 
than those referred to in paragraph (a) of this section.
    (c)(1) Fuel not meeting the requirements specified in paragraph (b) 
of this section is subject to the standards, requirements, and 
prohibitions that apply for ULSD under this part.
    (2) Any person who produces, imports, sells, offers for sale, 
supplies, offers for supply, stores, dispenses, or transports 
distillate global marine fuel without meeting the applicable 
recordkeeping requirements in subpart L of this part may not claim the 
fuel is exempt from the standards, requirements, and prohibitions that 
apply for ULSD under this part.

Subpart H--Averaging, Banking, and Trading Provisions

Sec.  1090.700   Compliance with average standards.

    (a) Compliance with the sulfur average standard. For each of their 
facilities, gasoline manufacturers must demonstrate compliance with the 
sulfur average standard in Sec.  1090.205(a) by using the equations in 
paragraphs (a)(1) and (2) of this section.
    (1) Compliance sulfur value calculation. (i) The compliance sulfur 
value is determined as follows:

CSVy = Stot,y + DS,(y-1) + 
DS_Oxy_Total - CS

Where:

CSVy = Compliance sulfur value for compliance period y, 
in ppm-gallons.
Stot,y = The total amount of sulfur produced in 
compliance period y, per paragraph (a)(1)(ii) of this section, in 
ppm-gallons.
Ds,(y-1) = Sulfur deficit from the previous compliance 
period, per Sec.  1090.715(a)(1), in ppm-gallons.
DS_Oxy_Total = The total sulfur deficit from BOB 
recertification, per Sec.  1090.740(b)(3), in ppm-gallons.
CS = Sulfur credits used by the gasoline manufacturer, 
per Sec.  1090.720, in ppm-gallons.

    (ii) The total amount of sulfur produced is determined as follows:
    [GRAPHIC] [TIFF OMITTED] TP14MY20.003
    
Where:

Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.
If the calculation of Stot,y results in a negative 
number, replace it with zero.

    (2) Sulfur compliance calculation. (i) Compliance with the sulfur 
average standard in Sec.  1090.205(a) is achieved if the following 
equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.004

    (ii) Compliance with the sulfur average standard in Sec.  
1090.205(a) is not achieved if a deficit is incurred two or more 
consecutive years. A gasoline manufacturer incurs a deficit under Sec.  
1090.715 if the following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.005

    (b) Compliance with the benzene average standards. For each of 
their facilities, gasoline manufacturers must

[[Page 29122]]

demonstrate compliance with the benzene average standard in Sec.  
1090.210(a) by using the equations in paragraphs (b)(1) and (2) of this 
section and with the maximum benzene average standard in Sec.  
1090.210(b) by using the equations in paragraphs (b)(3) and (4) of this 
section.
    (1) Compliance benzene value calculation. (i) The compliance 
benzene value is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.006

Where:

CBVy = Compliance benzene value for year y, in benzene 
gallons.
Btot,y = The total amount of benzene produced in 
compliance period y, per paragraph (b)(1)(ii) of this section, in 
benzene gallons.
DBz,(y-1) = Benzene deficit from the previous compliance 
period, per Sec.  1090.715(a)(2), in benzene gallons.
DBz_Oxy_Total = Benzene deficit from BOB recertification, 
per Sec.  1090.740(b)(4), in benzene gallons.
CBz = Benzene credits used by the gasoline manufacturer, 
per Sec.  1090.720, in benzene gallons.

    (ii) The total amount of benzene produced is determined as follows:
    [GRAPHIC] [TIFF OMITTED] TP14MY20.007
    
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
Bi = The benzene content of batch i, in volume percent.
m = The number of batches of BOB gasoline recertified during the 
compliance period.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.
If the calculation of Btot,y results in a negative 
number, replace it with zero.

    (2) Benzene average compliance calculation. (i) Compliance with the 
benzene average standard in Sec.  1090.210(a) is achieved if the 
following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.008

    (ii) Compliance with the benzene average standard in Sec.  
1090.210(a) is not achieved if a deficit is incurred two or more 
consecutive years. A gasoline manufacturer incurs a deficit under Sec.  
1090.715 if the following equation is true:
[GRAPHIC] [TIFF OMITTED] TP14MY20.009

    (3) Average benzene concentration calculation. The average benzene 
concentration is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.010

Where:

    Ba,y = Average benzene concentration for compliance 
period y, in volume percent benzene.

    (4) Maximum benzene average compliance calculation. Compliance with 
the maximum benzene average standard in Sec.  1090.210(b) is achieved 
for calendar year y if the following equation is true:

Ba,y <= 1.30 vol%

    (5) The average benzene concentration calculated in paragraph 
(b)(3) of this section must be rounded and reported to two decimal 
places in accordance with Sec.  1090.50.
    (c) Accounting for oxygenate added at a downstream location. A 
gasoline manufacturer that complies with the requirements in Sec.  
1090.710 may include the volume of oxygenate added at a downstream 
location and the effects of such blending on sulfur and benzene content 
in compliance calculations under this subpart.
    (d) Inclusions. Gasoline manufacturers must include the following 
products that they produced or imported during the compliance period in 
their compliance calculations:
    (1) CG.
    (2) RFG.
    (3) BOB.
    (4) Added gasoline volume resulting from the production of gasoline 
from PCG as follows:
    (i) For PCG by subtraction as specified in Sec.  1090.1320(a)(1), 
include the PCG batch as a batch with a negative volume and positive 
sulfur and benzene content and include the new batch of gasoline as a 
batch with a positive volume and positive sulfur and benzene content in 
compliance calculations under this section. Any negative compliance 
sulfur or benzene value must be reported as zero and not as a negative 
result.
    (ii) For PCG by addition as specified in Sec.  1090.1320(a)(2), 
include only the blendstock added to make the new batch of gasoline as 
a batch with a positive volume and positive sulfur and benzene content 
of in compliance calculations under this section. Do not include any 
test results or volumes for the PCG or new batch of gasoline in these 
calculations.
    (5) Inclusion of a particular batch of gasoline for compliance 
calculations for a compliance period is based on the date the batch is 
produced, not shipped. For example, a batch produced on December 30, 
2021, but shipped on January 2, 2022, would be included in the 
compliance calculations for the 2021 compliance period. However, the 
volume included in the 2021 compliance period for that batch would be 
the entire batch volume, even though the shipment of all or some of the 
batch did not occur until 2022.
    (e) Exclusions. Gasoline manufacturers must exclude the following 
products from their compliance calculations:
    (1) Gasoline that was not produced by the gasoline manufacturer.
    (2) Regulated blendstock, unless the regulated blendstock is added 
to PCG or TGP under Sec.  1090.1320 or Sec.  1090.1325, respectively.
    (3) PCG, except as specified in paragraph (d)(4)(i) of this 
section.
    (4) Certified butane and certified pentane blended under Sec.  
1090.1320.
    (5) TGP.
    (6) Gasoline exempted under subpart G of this part from the average 
standards of subpart C of this part (e.g., California gasoline, racing 
fuel, etc.).

Sec.  1090.705   Facility level compliance.

    (a) Except as specified in paragraph (b) of this section, gasoline 
manufacturers must comply with average standards at the individual 
facility level.
    (b) Gasoline importers must comply with average standards at the 
company level, except that they must aggregate all import facilities 
within a PADD as a single facility to comply with the maximum benzene 
average standard in Sec.  1090.210(b) as specified in Sec.  
1090.1600(b).

Sec.  1090.710   Downstream oxygenate accounting.

    The requirements of this section apply to BOB for which a gasoline 
manufacturer is accounting for the effects of the oxygenate blending 
that occurs downstream of the fuel manufacturing facility in the 
gasoline manufacturer's average standard compliance calculations of 
this subpart. This section includes requirements on distributors to 
ensure that oxygenate is

[[Page 29123]]

added in accordance with the blending instructions specified by the 
gasoline manufacturer in order to ensure fuel quality standards are 
met.
    (a) Provisions for gasoline manufacturers. In order to account for 
the effects of oxygenate blending downstream, a gasoline manufacturer 
must meet all the following requirements:
    (1) Produce or import BOB such that the gasoline continues to meet 
the applicable gasoline standards in subpart C of this part after the 
addition of the specified type and amount of oxygenate.
    (2) Conduct tests on each batch of BOB produced or imported that 
represents the gasoline after each specified type and amount of 
oxygenate is added to the batch of BOB by creating a hand blend in 
accordance with Sec.  1090.1340 and determining the properties of the 
hand blend using the methods specified in subpart M of this part. When 
creating the hand blend, gasoline manufacturers must not add any more 
oxygenate to the BOB than the amount of oxygenate specified on the PTD 
for the BOB under paragraph (a)(5) of this section.
    (3) Participate in the national sampling oversight program 
specified in Sec.  1090.1440 or have an approved in-line blending 
waiver under Sec.  1090.1315.
    (4) Transfer ownership of the BOB only to an oxygenate blender that 
is registered with EPA under subpart I of this part or to an 
intermediate owner with the restriction that it only be transferred to 
a registered oxygenate blender.
    (5) Specify each oxygenate type and amount (or range of amounts) 
that the gasoline manufacturer certified for compliance of the hand 
blend on the PTD for the BOB, as specified in Sec.  1090.1160(b)(1).
    (6) Participate in the national fuels survey program under subpart 
N of this part.
    (b) Requirements for oxygenate blenders. Oxygenate blenders must 
add oxygenate of each type and amount (or within the range of amounts) 
as specified on the PTD for all BOB received, except as specified in 
paragraph (c)(2) of this section.
    (c) Limitations. (1) Only the gasoline manufacturer that first 
certifies the BOB may account for the downstream addition of oxygenate 
under this section. On any occasion where any person downstream of the 
fuel manufacturing facility gate of the gasoline manufacturer that 
produced or imported gasoline or BOB adds oxygenate to such product, 
the person may not include the volume and sulfur and benzene content of 
the oxygenate in any compliance calculations for demonstrating 
compliance with the average standards specified in subpart C of this 
part or for credit generation under this subpart. All applicable per-
gallon standards specified in subpart C of this part continue to apply.
    (2) A person downstream of the fuel manufacturing facility gate may 
redesignate BOB for use as gasoline without the addition of the 
specified type and amount of oxygenate if the provisions of Sec.  
1090.740 are met. Parties that redesignate BOB for use as gasoline 
without the addition of the specified type and amount of oxygenate are 
gasoline manufacturers and must meet all applicable requirements for 
gasoline manufacturers specified in this part.

Sec.  1090.715   Deficit carryforward.

    (a) A gasoline manufacturer incurs a compliance deficit if they 
exceed the average standard specified in subpart C of this part for a 
given compliance period. The deficit incurred must be determined as 
specified in paragraph (a)(1) of this section for sulfur and paragraph 
(b)(2) of this section for benzene.
    (1) The sulfur deficit incurred is determined as follows:
    [GRAPHIC] [TIFF OMITTED] TP14MY20.011
    
Where:

DS,y = Sulfur deficit incurred for compliance period y, 
in ppm-gallons.
CSVy = Compliance sulfur value for compliance period y, 
per Sec.  1090.700(a)(1), in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.

    (2) The benzene deficit incurred is determined as follows:
    [GRAPHIC] [TIFF OMITTED] TP14MY20.012
    
Where:

DBz,y = Benzene deficit incurred for compliance period y, 
in benzene gallons.
CBVy = Compliance benzene value for compliance period y, 
per Sec.  1090.700(b)(1), in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.

    (b) Gasoline manufacturers must use all sulfur or benzene credits 
previously generated or obtained at any of their facilities to achieve 
compliance with an average standard specified in subpart C of this part 
before carrying forward a sulfur or benzene deficit at any of their 
facilities.
    (c) Gasoline manufacturers that incur a deficit under this section 
must satisfy that deficit during the next compliance period regardless 
of whether the gasoline manufacturer produces gasoline during next 
compliance period.

Sec.  1090.720   Credit use.

    (a) General credit use provisions. Only gasoline manufacturers may 
generate, use, transfer, or own credits generated under this subpart, 
as specified in Sec.  1090.725(a)(1). Credits may be used by a gasoline 
manufacturer to comply with the average standards specified in subpart 
C of this part. Gasoline manufacturers may also bank credits for future 
use, transfer credits to another facility within a company (i.e., 
intracompany trading), or transfer credits to another gasoline 
manufacturer, if all applicable requirements of this subpart are met.
    (b) Credit life. Credits are valid for use for 5 years after the 
compliance period for which they are generated.
    (c) Limitations on credit use. (1) Credits that have expired may 
not be used for demonstrating compliance with the average standards 
specified in subpart C of this part or be used to replace invalid 
credits under Sec.  1090.735.
    (2) A gasoline manufacturer possessing credits must use all credits 
prior to falling into compliance deficit under Sec.  1090.715.
    (3) Credits may not be used to meet per-gallon standards.
    (4) Credits may not be used to meet the maximum benzene average 
standard in Sec.  1090.210(b).
    (d) Credit use limitation. Credits may only be used if the gasoline 
manufacturer owns them at the time of use.

[[Page 29124]]

    (e) Credit reporting. Gasoline manufacturers that generate, 
transact, or use credits under this subpart must report to EPA as 
specified in Sec.  1090.905 using forms and procedures specified by 
EPA.
    (f) Part 80 credit use. Valid credits generated under 40 CFR 
80.1615 and 80.1290 may be used by gasoline manufacturers to comply 
with the average standards in subpart C of this part, subject to the 
provisions of this subpart.

Sec.  1090.725   Credit generation.

    (a) Parties that may generate credits. (1) Only gasoline 
manufacturers may generate credits for use towards an average standard 
specified in subpart C of this part. No person other than a gasoline 
manufacturer may generate credits.
    (2) No credits may be generated for gasoline produced by the 
following activities: Transmix processing, transmix blending, oxygenate 
blending, certified butane blending, certified pentane blending, or 
importation of gasoline by rail and truck using the alternative 
sampling and testing requirements in Sec.  1090.1610.
    (3) No sulfur credits may be generated at a facility if that 
facility used sulfur credits in that same compliance period.
    (4) No benzene credits may be generated at a facility if that 
facility used benzene credits in that same compliance period.
    (b) Credit year. Credits generated under this section must be 
identified by the compliance period of generation. For example, credits 
generated on gasoline produced in 2021 must be identified as 2021 
credits.
    (c) Sulfur credit generation. (1) The number of sulfur credits 
generated is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.013

Where:

CS,y = Sulfur credits generated for compliance period y, 
in ppm-gallons.
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.
CSVy = Compliance sulfur value for compliance period y, 
per Sec.  1090.700(a)(1), in ppm-gallons.

    (2) The value of CS,y must be positive to generate 
credits.
    (3) Sulfur credits calculated under paragraph (c)(1) of this 
section must be expressed to the nearest ppm-gallon. Fractional values 
must be rounded in accordance with Sec.  1090.50.
    (d) Benzene credit generation. (1) The number of benzene credits 
generated is determined as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.014

Where:

CBz,y = Benzene credits generated for compliance period 
y, in benzene gallons.
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.
CBVy = Compliance benzene value for compliance period y, 
per Sec.  1090.700(b)(1), in benzene gallons.

    (2) The value of CBz,y must be positive to generate 
credits.
    (3) Benzene credits calculated under paragraph (d)(1) of this 
section must be expressed to the nearest benzene gallon. Fractional 
values must be rounded in accordance with Sec.  1090.50.
    (e) Credit generation limitation. Gasoline manufacturers may only 
generate credits after they have finished producing or importing 
gasoline for the compliance period.
    (f) Credit reporting. Gasoline manufacturers that generate credits 
under this section must report to EPA all information regarding the 
generation transaction as specified in Sec.  1090.905 using forms and 
procedures specified by EPA.

Sec.  1090.730   Credit transfers.

    Gasoline manufacturers may only obtain credits from another 
gasoline manufacturer to meet an average standard specified in subpart 
C of this part if all applicable requirements of this section are met.
    (a) The credits are generated as specified in Sec.  1090.725 and 
reported as specified in Sec.  1090.905.
    (b) The credits are used for compliance with the limitations 
regarding the appropriate periods for credit use in Sec.  1090.720.
    (c) Any credit transfer must take place no later than the 
compliance deadline specified in Sec.  1090.900(d) following the 
compliance period when the credits are obtained.
    (d) The credit has not been transferred between EPA registered 
companies more than twice. The first transfer by the gasoline 
manufacturer that generated the credit (``transferor'') may only be 
made to a gasoline manufacturer that intends to use the credit 
(``transferee''). If the transferee is unable to use the credit, it may 
make the second, and final, transfer only to a gasoline manufacturer 
that intends to use the credit. Intracompany credit transfers are 
unlimited.
    (e) The transferor must apply any credits necessary to meet the 
transferor's applicable average standard before transferring credits to 
any other gasoline manufacturer.
    (f) No person may transfer credits if the transfer would cause them 
to incur a deficit.
    (g) Unless the transferor and transferee are the same party (i.e., 
intracompany transfers), the transferor must supply to the transferee 
records as specified in Sec.  1090.1210(g) indicating the years the 
credits were generated, the identity of the gasoline manufacturer that 
generated the credits, and the identity of the transferring party.
    (h) The transferor and the transferee report to EPA all information 
regarding the transaction as specified in Sec.  1090.905 using forms 
and procedures specified by EPA.

Sec.  1090.735  Invalid credits and remedial actions.

    For credits that have been calculated or generated improperly, or 
are otherwise determined to be invalid, all the following provisions 
apply:
    (a) Invalid credits may not be used to achieve compliance with an 
average standard, regardless of the good faith belief that the credits 
were validly generated.
    (b) Any validly generated credits existing in the transferring 
gasoline manufacturer's credit balance after correcting the credit 
balance, and after the transferor applies credits as needed to meet the 
average standard at the end of the compliance period, must first be 
applied to correct the invalid transfers before the transferring 
gasoline manufacturer trades or banks the credits.
    (c) The gasoline manufacturer that used the credits, and any 
transferor of the credits, must adjust their credit

[[Page 29125]]

records, reports, and average standard compliance calculations as 
necessary to reflect the use of valid credits only. Updates to any 
reports must be done in accordance with subpart J of this part using 
forms and procedures specified by EPA.

Sec.  1090.740  Downstream BOB recertification.

    (a)(1) Gasoline manufacturers may recertify a BOB that another 
gasoline manufacturer has specified blending instructions for 
oxygenate(s) under Sec.  1090.710(a)(5) for a different type or amount 
of oxygenate (including gasoline recertification to contain no 
oxygenate) if the recertifying gasoline manufacturer meets all the 
requirements of this section.
    (2) Gasoline manufacturers must comply with applicable requirements 
of this part and incur deficits to be included in the compliance 
calculations in Sec.  1090.700.
    (3) Unless otherwise required under this part, gasoline 
manufacturers that recertify 200,000 or less gallons of BOB under this 
section do not need to arrange for an auditor to conduct audits under 
subpart R of this part.
    (b) Gasoline manufacturers that recertify a BOB under this section 
must calculate sulfur and benzene deficits for each batch and the total 
deficits for sulfur and benzene as follows:
    (1) Sulfur deficits from downstream BOB recertification. Calculate 
the sulfur deficit from BOB recertification for each individual batch 
of BOB recertified as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.015

Where:

DS_Oxy_Batch = Sulfur deficit resulting from recertifying 
the batch of BOB, in ppm-gallons.
VBase = The volume of BOB in the batch being recertified, 
in gallons.
PTDOxy = The volume fraction of oxygenate that would have 
been added to the BOB as specified on PTDs.

    (2) Total sulfur deficit from downstream BOB recertification. 
Calculate the total sulfur deficit from downstream BOB recertification 
as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.016

Where:

DS_Oxy_Total,y = The total sulfur deficit from downstream 
BOB recertification for compliance period y, in ppm-gallons.
DS_Oxy_Batch_i = The sulfur deficit for batch i of 
recertified BOB, per paragraph (b)(1) of this section, in ppm-
gallons.
n = The number of batches of BOB recertified during compliance 
period y.
i = Individual batch of BOB recertified during compliance period y.

    (3) Benzene deficits from downstream BOB recertification. Calculate 
the benzene deficit from BOB recertification for each individual batch 
of BOB recertified as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.017

Where:

DBz_Oxy_Batch = Benzene deficit resulting from 
recertifying the batch of BOB, in benzene gallons.
VBase = The volume of BOB in the batch being recertified, 
in gallons.
PTDOxy = The volume fraction of oxygenate that would have 
been added to the BOB as specified on PTDs.

    (4) Total benzene deficit from downstream BOB recertification. 
Calculate the total benzene deficit from downstream BOB recertification 
as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.018

Where:

DBz_Oxy_Total,y = The total benzene deficit from 
downstream BOB recertification for compliance period y, in benzene 
gallons.
DBz_Oxy_Batch_i = The benzene deficit for batch i of 
recertified BOB, per paragraph (b)(3) of this section, in benzene 
gallons.
n = The number of batches of BOB recertified during compliance 
period y.
i = Individual batch of BOB recertified during compliance period y.

    (5) Deficit rounding. The deficits calculated in paragraphs (b)(1) 
through (4) of this section must be rounded and reported to the nearest 
sulfur ppm-gallon or benzene gallon in accordance with Sec.  1090.50, 
as applicable.
    (c) Gasoline manufacturers do not incur a deficit, nor may they 
generate credits, for negative values from the equations in paragraph 
(b) of this section.
    (d) Deficits incurred under this section must be fulfilled in the 
compliance period in which they occur and may not be carried forward 
under Sec.  1090.715.

Sec.  1090.745  Informational annual average calculations.

    (a) Gasoline manufacturers must calculate and report annual average 
sulfur and benzene levels for each of their facilities as described in 
this section. The values calculated and reported under this section are 
not used

[[Page 29126]]

to demonstrate compliance with average standards under this part.
    (b) Gasoline manufacturers must calculate and report the unadjusted 
average sulfur level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.019

Where:

Sa,y = The facility unadjusted average sulfur level for 
compliance period y, in ppm. Report Sa,y to two decimal 
places.
Vi = The volume of gasoline produced or imported in batch 
i, in gallons.
Si = The sulfur content of batch i, in ppm.
n = The number of batches of gasoline produced or imported during 
the compliance period.
i = Individual batch of gasoline produced or imported during the 
compliance period.

    (c) Gasoline manufacturers must calculate and report the net 
average sulfur level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.020

Where:

SNET,y = The facility net average sulfur level for 
compliance period y, in ppm. Report SNET,y to two decimal 
places.
CSVy = The compliance sulfur value for compliance period 
y, per Sec.  1090.700(a)(1).

    (d) Gasoline manufacturers must calculate and report the net 
average benzene level as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.021

Where:

BNET,y = The facility net average benzene level for 
compliance period y, in volume percent benzene. Report 
BNET,y to two decimal places.
CBVy = The compliance benzene value for compliance period 
y, per Sec.  1090.700(b)(1).

Subpart I--Registration

Sec.  1090.800  General provisions.

    (a) Who must register. The following parties must register with EPA 
prior to engaging in any activity under this part:
    (1) Fuel manufacturers, including:
    (i) Gasoline manufacturers.
    (ii) Diesel fuel manufacturers.
    (iii) ECA marine fuel manufacturers.
    (iv) Certified butane blenders.
    (v) Certified pentane blenders.
    (vi) Transmix processors.
    (2) Oxygenate blenders.
    (3) Oxygenate producers, including DFE producers.
    (4) Certified pentane producers.
    (5) Certified ethanol denaturant producers.
    (6) Distributors, carriers, and pipeline operators who are part of 
the 500 ppm LM fuel distribution chain under a compliance plan 
submitted under Sec.  1090.520(g).
    (7) Independent surveyors.
    (8) Auditors.
    (9) Third parties that submit reports on behalf of any regulated 
party under this part. Such parties must register and associate their 
registration with the regulated party for whom they are reporting.
    (b) Dates for registration. The deadlines for registration are as 
follows:
    (1) New registrants. Except as specified in paragraph (b)(2) of 
this section, parties not currently registered with EPA must register 
with EPA no later than 60 days in advance of the first date that such 
person engages in any activity under this part requiring registration 
under paragraph (a) of this section.
    (2) Existing registrants. Parties that are already registered with 
EPA under 40 CFR part 80 as of January 1, 2021, are deemed to be 
registered for purposes of this part, except that such parties are 
responsible for reviewing and updating their registration information 
consistent with the requirements of this part, as specified in 
paragraph (c) of this section.
    (c) Updates to registration. A registered party must submit updated 
registration information to EPA within 30 days of any occasion when the 
registration information previously supplied becomes incomplete or 
inaccurate.
    (d) Forms and procedures for registration. All registrants must use 
forms and procedures specified by EPA.
    (e) Company and facility identification. EPA will provide 
registrants with company and facility identifiers to be used for 
recordkeeping and reporting under this part.
    (f) English language. Registration information submitted to EPA 
must be in English.

Sec.  1090.805  Contents of registration.

    (a) General information required for all registrants. The following 
general information must be submitted to EPA by all entities required 
to register:
    (1) Company information. For the company of the party, all the 
following information:
    (i) The company name.
    (ii) Company address, which must be the physical address of the 
business (i.e., not a post office box).
    (iii) Mailing address, if different from company address.
    (iv) Name, title, telephone number, and email address of an RCO. 
The RCO may delegate responsibility to a person who is familiar with 
the requirements of this part and who is no lower in the organization 
than a fuel manufacturing facility manager, or equivalent.
    (2) Facility information. For each separate facility, all the 
following information:
    (i) The facility name.
    (ii) The physical location of the facility.
    (iii) A contact name and telephone number for the facility.
    (iv) The type of facility.
    (3) Location of records. For each separate facility, or for each 
importer's operations in a single PADD, all the following information:
    (i) Whether records are kept on-site or off-site of the facility, 
or for importers, the registered address.
    (ii) If records are kept off-site, the primary off-site storage 
name, physical location, contact name, and telephone number.
    (4) Activities. A description of the activities that are engaged in 
by the company and its facilities (e.g., refining, importing, etc.).
    (b) Additional information required for certified pentane 
producers. In addition to the information in paragraph (a) of this 
section, certified pentane producers must also submit the following 
information:
    (1) A description of the production facility that demonstrates that 
the facility is capable of producing certified pentane that is 
compliant with the requirements of this part without significant 
modifications to the existing facility.
    (2) A description of how the certified pentane will be shipped from 
the production facility to the certified pentane blender(s) and the 
associated quality assurance practices that demonstrate that 
contamination during distribution can be adequately controlled so as 
not to cause the certified pentane to be in violation of the standards 
in this part.

Sec.  1090.810  Voluntary cancellation of company or facility 
registration.

    (a) Criteria for voluntary cancellation. A party may request 
cancellation of the registration of the company or any of its 
facilities at any time. Such request must use forms and procedures 
specified by EPA.
    (b) Effect of voluntary cancellation. A party whose registration is 
canceled:
    (1) Will still be liable for violation of any requirements under 
this part.
    (2) Will not be listed on any public list of actively registered 
companies that is maintained by EPA.
    (3) Will not have access to any of the electronic reporting systems 
associated with this part.

[[Page 29127]]

    (4) Will still be required to meet any applicable requirements 
under this part (e.g., the recordkeeping provisions under subpart L of 
this part).
    (c) Re-registration. If a party whose registration has been 
voluntarily cancelled wants to re-register, they must do all the 
following:
    (1) Notify EPA of their intent to re-register.
    (2) Provide any required information and correct any identified 
deficiencies.
    (3) Refrain from initiating a new registration unless directed to 
do so by EPA.
    (4) Submit updated information as needed.

Sec.  1090.815  Deactivation (involuntary cancellation) of 
registration.

    (a) Criteria for deactivation. EPA may deactivate the registration 
of any party required to register under this part, using the process 
specified in paragraph (b) of this section, if any of the following 
criteria are met:
    (1) The party has not accessed their account or engaged in any 
registration or reporting activity within the most recent 24 months.
    (2) The party has failed to comply with the registration 
requirements of this subpart.
    (3) The party has failed to submit any required notification or 
report within 30 days of the required submission date.
    (4) Any required attest engagement has not been received within 30 
days of the required submission date.
    (5) The party fails to pay a penalty or to perform any requirement 
under the terms of a court order, administrative order, consent decree, 
or administrative settlement between the party and EPA.
    (6) The party submits false or incomplete information.
    (7) The party denies EPA access or prevents EPA from completing 
authorized activities under section 114 or 208 of the Clean Air Act 
despite presenting a warrant or court order. This includes a failure to 
provide reasonable assistance.
    (8) The party fails to keep or provide the records required by 
subpart L of this part.
    (9) The party otherwise circumvents the intent of the Clean Air Act 
or of this part.
    (b) Process for deactivation. Except as specified in paragraph (c) 
of this section, EPA will use the following process whenever it decides 
to deactivate the registration of a party:
    (1) EPA will provide written notification to the RCO identifying 
the reasons or deficiencies for which EPA intends to deactivate the 
party's registration. The party will have 30 calendar days from the 
date of the notification to correct the deficiencies identified or 
explain why there is no need for corrective action.
    (2) If the basis for EPA's notice of intent to deactivate 
registration is the absence of activity under paragraph (a)(1) of this 
section, a stated intent to engage in activity will be sufficient to 
avoid deactivation of registration.
    (3) If the party does not correct identified deficiencies under 
paragraphs (a)(2) through (9) of this section, EPA may deactivate the 
party's registration without further notice to the party.
    (c) Immediate deactivation. In instances in which public health, 
public interest, or safety requires otherwise, EPA may deactivate the 
registration of the party without any notice to the party. EPA will 
provide written notification to the RCO identifying the reasons EPA 
deactivated the registration of the party.
    (d) Effect of deactivation. A party whose registration is 
deactivated:
    (1) Will still be liable for violation of any requirement under 
this part.
    (2) Will not be listed on any public list of actively registered 
companies that is maintained by EPA.
    (3) Will not have access to any of the electronic reporting systems 
associated with this part.
    (4) Will still be required to meet any applicable requirements 
under this part (e.g., the recordkeeping provisions under subpart L of 
this part).
    (e) Re-registration. If a party whose registration has been 
deactivated wishes to re-register, they must do all the following:
    (1) Notify EPA of their intent to re-register.
    (2) Provide any required information and correct any identified 
deficiencies.
    (3) Refrain from initiating a new registration unless directed to 
do so by EPA.
    (4) Remedy the circumstances that caused the party to be 
deactivated in the first place.
    (5) Submit updated information as needed.

Sec.  1090.820  Changes of ownership.

    (a) When a company or any of its facilities will change ownership, 
the company must notify EPA within 30 days after the date of sale or 
change in ownership.
    (b) The notification required under paragraph (a) of this section 
must include all the following:
    (1) The effective date of the transfer of ownership of the facility 
and a summary of any changes to the registration information for the 
affected companies and facilities.
    (2) Documents that demonstrate the sale or change in ownership of 
the facility.
    (3) A letter, signed by an RCO from the company that currently owns 
or will own the company or facility and, if possible, an RCO from the 
company that previously registered the company or facility that details 
the effective date of the transfer of ownership of the company or 
facility and summarizes any changes to the registration information.
    (4) Any additional information requested by EPA to complete the 
change in registration.

Subpart J--Reporting

Sec.  1090.900  General provisions.

    (a) Forms and procedures for reporting. (1) All reporting, 
including all transacting of credits under this part, must be submitted 
electronically using forms and procedures specified by EPA.
    (2) Values must be reported in the units (e.g., gallons, ppm, etc.) 
and to the number of decimal places specified in this part or in 
reporting formats and procedures, whichever is more precise.
    (b) English language. All reports submitted under this subpart must 
be submitted in English.
    (c) Rounding. All values measured, calculated, or reported under 
this subpart must be rounded in accordance with Sec.  1090.50.
    (d) Report submission. All annual reports required under this 
subpart, except attest engagement reports, must be submitted by March 
31 for the preceding compliance period (e.g., reports covering the 
calendar year 2021 must be submitted to EPA by no later than March 31, 
2022). Attest engagement reports must be submitted by June 1 for the 
preceding compliance period (e.g., attest engagement reports covering 
calendar year 2021 must be submitted to EPA by no later than June 1, 
2022). Independent survey quarterly reports must be submitted by the 
deadlines in Table 1 to Sec.  1090.925(a).

Sec.  1090.905  Annual, batch, and credit transaction reporting for 
gasoline manufacturers.

    (a) Annual compliance demonstration for sulfur. Gasoline 
manufacturers, for each of their facilities, must submit a report for 
each compliance period that includes all the following information:
    (1) Company-level reporting. For the company, as applicable:
    (i) The EPA-issued company and facility identifiers.
    (ii) Provide information for sulfur credits, and separately by 
compliance period of creation, as follows:

[[Page 29128]]

    (A) The number of sulfur credits owned at the beginning of the 
compliance period.
    (B) The number of sulfur credits that expired at the end of the 
compliance period.
    (C) The number of sulfur credits that will be carried over into the 
next compliance period.
    (D) Any other information as EPA may require.
    (2) Facility-level reporting. For each refinery or importer, as 
applicable:
    (i) The EPA-issued company and facility identifiers.
    (ii) The compliance sulfur value, per Sec.  1090.700(a)(1), in ppm-
gallons.
    (iii) The total volume of gasoline produced or imported, in 
gallons.
    (iv) Provide information for sulfur credits, and separately by 
compliance period of creation, as follows:
    (A) The number of sulfur credits generated during the compliance 
period.
    (B) The number of sulfur credits retired during the compliance 
period.
    (C) The sulfur credit deficit that was carried over from the 
previous compliance period.
    (D) The sulfur credit deficit that will be carried over into the 
next compliance period.
    (E) The total sulfur deficit from downstream BOB recertification, 
per Sec.  1090.740(b)(2).
    (v) The unadjusted average sulfur concentration, per Sec.  
1090.745(b), in ppm.
    (vi) The net average sulfur level, per Sec.  1090.745(c), in ppm.
    (vii) Any other information as EPA may require.
    (b) Annual compliance demonstration for benzene. Gasoline 
manufacturers, for each of their facilities, must submit a report for 
each compliance period that includes all the following information:
    (1) Company-level reporting. For the company, as applicable:
    (i) The EPA-issued company and facility identifiers and compliance 
level.
    (ii) Provide information for benzene credits, and separately by 
compliance period of creation, as follows:
    (A) The number of benzene credits owned at the beginning of the 
compliance period.
    (B) The number of benzene credits that expired at the end of the 
compliance period.
    (C) The number of benzene credits that will be carried over into 
the next compliance period.
    (D) Any other information as EPA may require.
    (2) Facility-level reporting. For each refinery or importer, as 
applicable:
    (i) The EPA-issued company and facility identifiers.
    (ii) The compliance benzene value, per Sec.  1090.700(b)(1), in 
benzene gallons.
    (iii) The total volume of gasoline produced or imported, in 
gallons.
    (iv) The average benzene concentration, per Sec.  1090.700(b)(3), 
in percent volume.
    (v) The net average benzene level, per Sec.  1090.745(d), in 
percent volume.
    (vi) Provide information for benzene credits, and separately by 
compliance period of creation, as follows:
    (A) The number of benzene credits generated during the compliance 
period.
    (B) The number of benzene credits retired during the compliance 
period.
    (C) The benzene credit deficit that was carried over from the 
previous compliance period
    (D) The benzene credit deficit that will be carried over into the 
next compliance period.
    (E) The total benzene deficit from downstream BOB recertification, 
per Sec.  1090.740(b)(4).
    (vii) Any other information as EPA may require.
    (c) Batch reporting. Gasoline manufacturers, for each of their 
facilities, must report the following information on a per-batch basis 
for gasoline and gasoline regulated blendstocks:
    (1) For gasoline, and BOB for which the fuel manufacturer does not 
include the addition of downstream oxygenate in their compliance 
calculations as specified in Sec.  1090.710:
    (i) The EPA-issued company and facility identifiers.
    (ii) The batch number.
    (iii) The date the batch was produced or imported.
    (iv) The batch volume, in gallons.
    (v) The designation of the gasoline or BOB as RFG, CG, RBOB, or 
CBOB.
    (vi) The tested sulfur content of the batch, in ppm, and the test 
method used to measure the sulfur content.
    (vii) The tested benzene content of the batch, as a volume 
percentage, and the test method used to measure the benzene content. 
Gasoline produced by a transmix processor using only TGP or both TGP 
and PCG under Sec.  1090.510 is exempt from this requirement under 
Sec.  1090.1325. Transmix processors that use this exemption must 
report whether the batch was produced using TGP or both TGP and PCG.
    (viii) For all batches of summer gasoline or BOB:
    (A) The applicable RVP standard, as specified in Sec.  1090.215.
    (B) The tested RVP of the batch, in psi, and the test method used 
to measure the RVP.
    (ix) If the gasoline contains oxygenate, the type and tested 
content of each oxygenate, as a volume percentage, and the test method 
used to measure the content of each oxygenate.
    (2) For BOB in which the oxygenate to be blended with the BOB is 
reported by, and included in, the compliance calculations of the 
gasoline manufacturer that produced the BOB:
    (i) The EPA-issued company and facility identifiers.
    (ii) The batch identification.
    (iii) The date the batch of BOB was produced or imported.
    (iv) The batch volume, in gallons. This volume is the sum of the 
produced or imported BOB volume plus the anticipated volume from the 
addition of oxygenate downstream that the gasoline manufacturer 
specified to be blended with the BOB.
    (v) The designation of the BOB (CBOB or RBOB) used to prepare the 
hand blend of BOB and oxygenate under Sec.  1090.1340.
    (vi) The tested sulfur content for both the BOB and the hand blend 
of BOB and oxygenate prepared under Sec.  1090.1340, and the test 
method used to measure the sulfur content.
    (vii) The tested benzene content for the hand blend of BOB and 
oxygenate prepared under Sec.  1090.1340, and the test method used to 
measure the benzene content.
    (viii) For all batches of summer BOB:
    (A) The applicable RVP standard, as specified in Sec.  1090.215, 
for the neat CBOB, or hand blend of RBOB and oxygenate prepared under 
Sec.  1090.1340.
    (B) The tested RVP for the neat CBOB or hand blend of RBOB and 
oxygenate prepared under Sec.  1090.1340, in psi, and the test method 
used to measure the RVP.
    (ix) The type and content of each oxygenate, as a volume 
percentage, in the hand blend of BOB and oxygenate prepared under Sec.  
1090.1340, and, if measured, the test method used for each oxygenate.
    (3) For blendstock added to PCG by gasoline manufacturers complying 
by subtraction under Sec.  1090.1320(a)(1):
    (i) For the PCG prior to the addition of blendstock:
    (A) The EPA-issued company and facility identifiers for the 
facility at which the PCG is blended to produce a new batch.
    (B) The batch number assigned by the facility at which the PCG is 
blended to produce a new batch.
    (C) The date the batch was received or, for PCG that was not 
received from another company, the date the PCG was designated to be 
used to produce a new batch of gasoline.
    (D) The batch volume, including the volume of any oxygenate that 
would

[[Page 29129]]

have been added to the PCG, as a negative number in gallons.
    (E) The designation of the PCG.
    (F) The tested sulfur content of the batch, in ppm, and the test 
method used to measure the sulfur content.
    (G) The tested benzene content of the batch, as a volume 
percentage, and the test method used to measure the benzene content.
    (H) For all batches of summer gasoline or BOB:
    (1) The applicable RVP standard, as specified in Sec.  1090.215.
    (2) The tested RVP of the batch, in psi, and the test method used 
to measure the RVP.
    (I) If the PCG contains oxygenate, the type and tested content of 
each oxygenate, as a volume percentage, and the test method used to 
measure the content of each oxygenate.
    (J) Identification of the batch as PCG.
    (ii) For the batch of gasoline or BOB produced using PCG and 
blendstock:
    (A) For batches of finished gasoline or neat BOB, all the 
information specified in paragraph (c)(1) of this section.
    (B) For batches of BOB in which the oxygenate to be blended with 
the BOB is included in the gasoline manufacturer's compliance 
calculations, all the information specified in paragraph (c)(2) of this 
section.
    (4) For blendstock added by gasoline manufacturers to PCG and 
complying by addition per Sec.  1090.1320(a)(2) (i.e., treat the 
blendstock as a separate batch):
    (i) For the blendstock, the sulfur content, benzene content, and 
each oxygenate type and content of the batch, and for summer gasoline, 
the RVP of the batch.
    (ii) For batches produced by adding blendstock to PCG, the sulfur 
content of the batch, and for summer gasoline, the RVP of the batch.
    (5) For certified butane blended by certified butane blenders and 
certified pentane blended by certified pentane blenders:
    (i) For the certified butane or certified pentane batch:
    (A) The batch number.
    (B) The date the batch was received by the blender.
    (C) The batch volume, in gallons.
    (D) The designation of the batch (certified butane or certified 
pentane).
    (E) The volume percentage of butane in butane batches, or pentane 
in pentane batches, provided by the butane or pentane supplier.
    (F) The sulfur content of the batch, in ppm, provided by the butane 
or pentane supplier.
    (G) The benzene content of the batch, in volume percent, provided 
by the butane or pentane supplier.
    (H) The RVP of the batch, in psi, provided by the butane or pentane 
supplier for butane or pentane blended into PCG from May 1 through 
September 15.
    (ii) For the batch of blended product (i.e., PCG plus butane or PCG 
plus pentane):
    (A) The batch number.
    (B) The date the batch was produced.
    (C) The batch volume, in gallons.
    (D) The designation of the blended product.
    (E) The tested RVP of the batch, in psi, and the test method used 
to measure the RVP.
    (6) For manufacturers of TGP and any blendstocks added to TGP:
    (i) For the TGP, the sulfur content of the batch, and for summer 
gasoline, the RVP of the batch.
    (ii) For blendstocks added to TGP, where the TGP is treated like 
PCG, one of the following:
    (A) The information specified in paragraph (c)(3) of this section.
    (B) The information specified in paragraph (c)(4) of this section.
    (7) For GTAB:
    (i) The EPA-issued company and facility identifiers.
    (ii) The batch number.
    (iii) The date the batch was imported.
    (iv) The batch volume, in gallons.
    (v) The designation of the product as GTAB.
    (8) Any other information as EPA may require.
    (d) Credit transactions. Any party that is required to demonstrate 
annual compliance under paragraph (a) or (b) of this section must 
submit information related to individual transactions involving sulfur 
and benzene credits, including all the following:
    (1) The generation, purchase, sale, or retirement of such credits.
    (2) If any credits were obtained from or transferred to other fuel 
manufacturers, and for each other party, their name and EPA-issued 
company identifier, the number of credits obtained from or transferred 
to the other party, and the year the credits were generated.
    (3) Any other information as EPA may require.

Sec.  1090.910  Reporting for gasoline manufacturers that recertify BOB 
to gasoline.

    Any person that recertifies BOB under Sec.  1090.740 must report 
the information of this section, as applicable.
    (a) Batch reporting. (1) Any person that recertifies a BOB under 
Sec.  1090.740 with less oxygenate than specified by the fuel 
manufacturer of the BOB must report the following for each batch:
    (i) The EPA-issued company and facility identifiers for the 
recertifying gasoline manufacturer.
    (ii) The batch number assigned by the recertifying gasoline 
manufacturer.
    (iii) The date the batch was recertified.
    (iv) The batch volume, as a negative number in gallons. The volume 
is the amount of oxygenate that the recertifying gasoline manufacturer 
did not blend with the BOB.
    (v) The designation of the batch.
    (vi) A sulfur content of 11 ppm.
    (vii) A benzene content of 0.068 volume percent.
    (viii) The type and content of each oxygenate, as a volume 
percentage.
    (ix) The sulfur deficit for the batch calculated under Sec.  
1090.740(b)(1).
    (x) The benzene deficit for the batch calculated under Sec.  
1090.740(b)(3).
    (2) Any person that recertifies a BOB under Sec.  1090.740 with 
more oxygenate than specified by the fuel manufacturer of the BOB does 
not need to report the batch.
    (b) Annual sulfur and benzene compliance reporting. Any person that 
recertifies a BOB under Sec.  1090.740 must include any deficits 
incurred from recertification in reports under Sec.  1090.905(a) and 
(b).
    (c) Credit transactions. Any person that recertifies a BOB under 
Sec.  1090.740 must report any credit transactions under Sec.  
1090.905(d).

Sec.  1090.915  Batch reporting for oxygenate producers and importers.

    Any oxygenate producer, for each of their production facilities, 
and any importer for the oxygenate they import, must submit a report 
for each compliance period that includes all the following information:
    (a) The EPA-issued company and facility identifiers.
    (b) The total volume of oxygenate produced or imported.
    (c) For each batch of oxygenate produced or imported during the 
compliance period, all the following:
    (1) The batch number.
    (2) The date the batch was produced or imported.
    (3) One of the following product types:
    (i) Denatured ethanol using certified ethanol denaturant complying 
with Sec.  1090.235(b).
    (ii) Denatured ethanol from non-certified ethanol denaturant.
    (iii) A specified oxygenate other than ethanol (e.g., isobutanol).
    (4) The volume of the batch, in gallons.
    (5) The tested sulfur content of the batch, in ppm, and the test 
method used to measure the sulfur content.

[[Page 29130]]

    (d) Any other information as EPA may require.

Sec.  1090.920  Reports by certified pentane producers.

    Any producer of certified pentane for use by certified pentane 
blenders must submit a report for each facility at which certified 
pentane was produced or imported that contains all the following 
information:
    (a) The EPA-issued company and facility identifiers.
    (b) For each batch of certified pentane produced or imported during 
the compliance period, all the following:
    (1) The batch number.
    (2) The date the batch was produced or imported.
    (3) The batch volume, in gallons.
    (4) The tested pentane content of the batch, as a volume 
percentage, and the test method used to measure the pentane content.
    (5) The tested sulfur content of the batch, in ppm, and the test 
method used to measure the sulfur content.
    (6) The tested benzene of the batch, as a volume percentage, and 
the test method used to measure the benzene content.
    (7) The tested RVP of the batch, in psi, and the test method used 
to measure the RVP.
    (c) Any other information as EPA may require.

Sec.  1090.925  Reports by independent surveyors.

    (a) General procedures. (1) Independent surveyors must 
electronically submit any plans, notifications, or reports required 
under this subpart using forms and procedures specified by EPA.
    (2) For each report required under this section, the independent 
surveyor must affirm that the survey was conducted in accordance with 
an EPA-approved survey plan and that the survey results are accurate.
    (3) The independent surveyor must include EPA-issued company 
identifiers on each report required under this section.
    (4) Independent surveyors must submit quarterly reports required 
under paragraph (b) of this section by the following deadlines:

                          Table 1 to Sec.   1090.925(a)--Quarterly Reporting Deadlines
----------------------------------------------------------------------------------------------------------------
             Calendar quarter                     Time period covered             Quarterly report deadline
----------------------------------------------------------------------------------------------------------------
Quarter 1................................  January1-March 31...............  June 1.
Quarter 2................................  April 1-June 30.................  September 1.
Quarter 3................................  July 1-September 30.............  December 1.
Quarter 4................................  October 1-December 31...........  March 31.
----------------------------------------------------------------------------------------------------------------

    (b) Quarterly reporting. Independent surveyors must submit the 
following information quarterly, as applicable:
    (1) For each retail outlet or gasoline manufacturing facility 
sampled by the independent surveyor:
    (i) The identification information for the retail outlet or 
gasoline manufacturing facility, as assigned by the surveyor in a 
consistent manner and as described in the survey plan.
    (ii) The displayed fuel manufacturer brand name at the retail 
outlet, if any.
    (iii) The physical location (i.e., address) of the retail outlet or 
gasoline manufacturing facility.
    (2) For each gasoline sample collected by the independent surveyor:
    (i) A description of the labeling of the fuel dispenser(s) (e.g., 
``E0'', ``E10'', ``E15'', etc.) from which the independent surveyor 
collected the sample.
    (ii) The date and time the independent surveyor collected the 
sample.
    (iii) The test results for the sample, and the test methods used, 
as determined by the independent surveyor, including the following 
parameters:
    (A) The oxygen content, in weight percent.
    (B) The type and amount of each oxygenate, by weight and volume 
percent.
    (C) The sulfur content, in ppm.
    (D) The benzene content, in volume percent.
    (E) The specific gravity.
    (F) The RVP in psi, if tested.
    (G) The aromatic content in volume percent, if tested.
    (H) The olefin content in volume percent, if tested.
    (I) The distillation parameters (i.e., E200, E300, T50, T90), if 
tested.
    (3) For each diesel sample collected at a retail outlet by the 
independent surveyor:
    (i) A description of the labeling of the fuel dispenser(s) (e.g., 
``ULSD'') from which the independent surveyor collected the sample.
    (ii) The date and time the independent surveyor collected the 
sample.
    (iii) The tested sulfur content of the sample, and the test method 
used, as determined by the independent surveyor, in ppm.
    (4) Any other information as EPA may require.
    (c) Annual reporting. Independent surveyors must submit the 
following information annually by March 31.
    (1) An identification of the parties that participated in the 
survey during the compliance period.
    (2) An identification of each geographic area included in a survey.
    (3) Summary statistics for each identified geographic area, 
including the following:
    (i) The number of samples collected and tested.
    (ii) The mean, median, and range expressed in appropriate units for 
each measured gasoline and diesel parameter.
    (iii) The standard deviation for each measured gasoline and diesel 
parameter.
    (iv) The estimated compliance rate for each measured gasoline and 
diesel parameter subject to a per-gallon standard in subpart C or D of 
this part.
    (v) A summary of potential non-compliance issues.
    (4) Any other information as EPA may require.

Sec.  1090.930  Reports by auditors.

    (a) Attest engagement reports required under subpart R of this part 
must be submitted by independent auditors who are registered with EPA 
and associated with a company, or companies, via registration under 
subpart I of this part. Each attest engagement must clearly identify 
the company and compliance level (e.g., facility), time period, and 
scope covered by the report. Attest engagement reports covered by this 
section include those required under this part, and under 40 CFR part 
80, subpart M, beginning with the report due June 1, 2022.
    (b) An attest engagement report must be submitted to EPA covering 
each compliance period by June 1 of the following calendar year. The 
auditor must make the attest engagement

[[Page 29131]]

available to the company for which it was performed.
    (c) The attest engagement must comply with subpart R of this part 
and the attest engagement report must clearly identify the 
methodologies followed and any findings, exceptions, etc.
    (d) A single attest engagement submission by the auditor may 
include procedures performed under this part and under 40 CFR part 80, 
subpart M. If a single submission method is used, the auditor must 
clearly and separately describe the procedures and findings for each 
program.
    (e) If the attest engagement reveals discrepancies or instances of 
noncompliance requiring corrective action, then the RCO must submit a 
statement acknowledging them and stating that they are undertaking 
corrective action.

Sec.  1090.935  Reports by diesel manufacturers.

    (a) Batch reporting. (1) For each compliance period, manufacturers 
of ULSD must submit the following information:
    (i) The EPA-issued company and facility identifiers for the 
manufacturer of ULSD.
    (ii) The highest sulfur content level observed for a batch of ULSD 
produced during the compliance period on a company level, in ppm.
    (iii) The average sulfur content level of all batches produced 
during the compliance period on a company level, in ppm.
    (iv) A list of all batches of ULSD that exceeded the sulfur 
standard in Sec.  1090.305(b) by facility. For each such batch, report 
the following:
    (A) The batch number.
    (B) The date the batch was produced.
    (C) The volume of the batch, in gallons.
    (D) The sulfur content of the batch, in ppm.
    (E) The corrective action taken, if any.
    (b) [Reserved]

Subpart K--Batch Certification, Designation, and Product Transfer 
Documents

Batch Certification and Designation

Sec.  1090.1100  Batch certification requirements.

    (a) General provisions. (1) Fuel manufacturers, fuel additive 
manufacturers, and regulated blendstock producers must certify batches 
of fuels, fuel additives, and regulated blendstocks as specified in 
this section.
    (2) Fuel manufacturers, fuel additive manufacturers, and regulated 
blendstock producers do not need to certify fuel, fuel additive, or 
regulated blendstock that is exempt under subpart G of this part.
    (3) For purposes of this part, the volume of a batch is the sum of 
all shipments or transfers of fuel, fuel additive, or regulated 
blendstock out of the tank or vessel in which the fuel, fuel additive, 
or regulated blendstock was certified. If a volume of fuel, fuel 
additive, or regulated blendstock is placed in a tank, certified (if 
not previously certified), and is not changed in some way, it is 
considered to be the same batch even if several shipments or transfers 
are made out of that tank.
    (4) For fuel produced at a facility that has an in-line blending 
waiver under Sec.  1090.1315, the volume of the batch is the volume of 
product that is homogeneous under the requirements of Sec.  1090.1337 
and is produced during a period not to exceed 3 days.
    (5) No person may introduce into commerce gasoline, diesel fuel, or 
ECA marine fuel that is not certified under this section.
    (b) Gasoline. (1) Gasoline manufacturers must certify gasoline as 
specified in paragraph (b)(2) of this section prior to introducing the 
fuel into commerce.
    (2) To certify batches of gasoline, gasoline manufacturers must do 
all the following:
    (i) Register with EPA as a refiner, blending manufacturer, 
importer, transmix processor, certified butane blender, or certified 
pentane blender under subpart I of this part, as applicable, prior to 
producing gasoline.
    (ii) Ensure that each batch of gasoline meets the applicable 
requirements of subpart C of this part using the applicable procedures 
specified in subpart M of this part. Transmix processors and transmix 
blenders must also meet all applicable requirements in subpart F of 
this part to ensure that each batch of gasoline meets the applicable 
requirements in subpart C of this part.
    (iii) Assign batch numbers as specified in Sec.  1090.1120.
    (iv) Designate batches of gasoline as specified in Sec.  1090.1110.
    (3) PCG may be mixed with other PCG without re-certification if the 
resulting mixture complies with the applicable standards in subpart C 
of this part and is designated appropriately under Sec.  1090.1110. 
Resulting mixtures of PCG are not new batches and should not be 
assigned new batch numbers.
    (4) Any person that mixes summer gasoline with summer or winter 
gasoline that has a different designation must do one of the following:
    (i) Designate the resulting mixture as meeting the least stringent 
RVP designation of any batch that is mixed. For example, a distributor 
who mixes Summer RFG with 7.8 psi Summer CG must designate the mixture 
as 7.8 psi Summer CG.
    (ii) Determine the RVP of the mixture using the procedures 
specified in subpart M of this part and designate the new batch under 
Sec.  1090.1110 to reflect the RVP of the resulting mixture.
    (5) Any person that mixes summer gasoline with winter gasoline to 
transition any storage tank from winter to summer gasoline is exempt 
from the requirement in paragraph (b)(4)(ii) of this section but must 
ensure that the gasoline meets the applicable RVP standard in Sec.  
1090.215.
    (c) Diesel fuel and ECA marine fuel. (1) Diesel fuel and ECA marine 
fuel manufacturers must certify diesel fuel as specified in paragraph 
(c)(2) of this section prior to introducing the fuel into commerce.
    (2) To certify batches of diesel fuel and ECA marine fuel, diesel 
fuel and ECA marine fuel manufacturers must do all the following:
    (i) Register with EPA as a refiner, blending manufacturer, 
importer, or transmix processor under subpart I of this part, as 
applicable, prior to producing diesel fuel or ECA marine fuel.
    (ii) Ensure that each batch of diesel fuel or ECA marine fuel meets 
the applicable requirements of subpart D of this part using the 
applicable procedures specified in subpart M of this part. Transmix 
processors must also meet all applicable requirements specified in 
subpart F of this part to ensure that each batch of diesel fuel or ECA 
marine fuel meets the applicable requirements in subpart D of this 
part.
    (iii) Assign batch numbers as specified in Sec.  1090.1120.
    (iv) Designate batches of diesel fuel as specified in Sec.  
1090.1115.
    (d) Oxygenates. (1) Oxygenate producers must certify oxygenates 
intended to be blended into gasoline as specified in paragraph (d)(2) 
of this section.
    (2) To certify batches of oxygenates, oxygenate producers and 
importers must do all the following:
    (i) Register with EPA as an oxygenate producer under subpart I of 
this part prior to producing or importing oxygenate intended for 
blending into gasoline.
    (ii) Ensure that each batch of oxygenate meets the requirements in 
Sec.  1090.230 by using the applicable procedures specified in subpart 
M of this part.

[[Page 29132]]

    (iii) Assign batch numbers as specified in Sec.  1090.1120.
    (iv) Designate batches of oxygenate as intended for blending with 
gasoline as specified in Sec.  1090.1110(c).
    (e) Certified butane. (1) Certified butane producers must certify 
butane intended to be blended by a blending manufacturer under Sec.  
1090.1320 as specified in paragraph (e)(2) of this section.
    (2) To certify batches of certified butane, certified butane 
producers must do all the following:
    (i) Ensure that each batch of certified butane meets the 
requirements in Sec.  1090.220 by using the applicable procedures 
specified in subpart M of this part.
    (A) Testing must occur after the most recent delivery into the 
certified butane producer's storage tank, and prior to transferring the 
certified butane batch for delivery.
    (B) The certified butane producer must provide documentation of the 
test results for each batch of certified butane to the certified butane 
blender.
    (ii) Designate batches of certified butane as intended for blending 
with gasoline as specified in Sec.  1090.1110(d).
    (f) Certified pentane. (1) Certified pentane producers must certify 
pentane intended to be blended by a blending manufacturer under Sec.  
1090.1320 as specified in paragraph (f)(2) of this section.
    (2) To certify batches of certified pentane, certified pentane 
producers must do all the following:
    (i) Register with EPA as a certified pentane producer under subpart 
I of this part prior to producing certified pentane.
    (ii) Ensure that each batch of certified pentane meets the 
requirements in Sec.  1090.225 by using the applicable procedures 
specified in subpart M of this part.
    (A) Testing must occur after the most recent delivery into the 
certified pentane producer's storage tank, before transferring the 
certified pentane batch for delivery.
    (B) The certified pentane producer must provide documentation of 
the test results for each batch of certified pentane to the certified 
pentane blender.
    (iii) Assign batch numbers as specified in Sec.  1090.1120.
    (iv) Designate batches of certified pentane as intended for 
blending with gasoline as specified in Sec.  1090.1110(d).
    (g) Certified ethanol denaturant. (1) Certified ethanol denaturant 
producers must certify certified ethanol denaturant intended to be used 
to make DFE that meets the requirements in Sec.  1090.235 as specified 
in paragraph (g)(2) of this section.
    (2) To certify batches of certified ethanol denaturant, certified 
ethanol denaturant producers must do all the following:
    (i) Register with EPA as a certified ethanol denaturant producer 
under subpart I of this part prior to producing certified ethanol 
denaturant.
    (ii) Ensure that each batch of certified ethanol denaturant meets 
the requirements in Sec.  1090.235 by using the applicable procedures 
specified in subpart M of this part.
    (iii) Assign batch numbers as specified in Sec.  1090.1120.
    (iv) Designate batches of certified ethanol denaturant as intended 
for blending with gasoline as specified in Sec.  1090.1110(e).

Sec.  1090.1105  Designation of batches of fuels, fuel additives, and 
regulated blendstocks.

    (a) Fuel manufacturers, fuel additive manufacturers, and regulated 
blendstock producers must designate batches of fuel, fuel additive, and 
regulated blendstock as specified in this subpart.
    (b) Fuel manufacturers, fuel additive manufacturers, and regulated 
blendstock producers must include designations on PTDs as specified in 
this subpart and must make the designation prior to the batch leaving 
the facility where it was produced.
    (c) By designating a batch of fuel, fuel additive, or regulated 
blendstock under this subpart, the designating party is acknowledging 
that the batch is subject to all applicable standards under this part.
    (d) A person must comply with all provisions of this part even if 
they fail to designate or improperly designate a batch of fuel, fuel 
additive, or regulated blendstock.
    (e) No person may use the designation provisions of this subpart to 
circumvent any standard or requirement in this part.

Sec.  1090.1110  Designation requirements for gasoline.

    (a) Designation requirements for gasoline manufacturers. Gasoline 
manufacturers must accurately and clearly designate each batch of 
gasoline as follows:
    (1) Gasoline manufacturers must designate each batch of gasoline as 
one of the following fuel types:
    (i) Winter RFG or RBOB.
    (ii) Summer RFG or RBOB.
    (iii) Winter CG or CBOB.
    (iv) Summer CG or CBOB.
    (v) Exempt gasoline under subpart G of this part (including 
additional identifying information).
    (vi) California gasoline.
    (2) Gasoline manufacturers must further designate gasoline 
designated as Summer CG or Summer CBOB as follows:
    (i) 7.8 psi Summer CG or CBOB.
    (ii) 9.0 psi Summer CG or CBOB.
    (iii) SIP-controlled Summer CG or CBOB.
    (3) CBOB and RBOB manufacturers must further designate the CBOB or 
RBOB with the type(s) and amount(s) of oxygenate specified to be 
blended with the CBOB or RBOB as specified in Sec.  1090.710.
    (b) Designation requirements for gasoline distributors. Gasoline 
distributors must accurately and clearly designate each batch or 
portion of a batch of gasoline for which they transfer custody to 
another facility as follows:
    (1) Distributors must accurately and clearly classify each batch or 
portion of each batch of gasoline as specified by the gasoline 
manufacturer in paragraph (a) of this section.
    (2) Distributors may redesignate batches or portions of batches of 
gasoline for which they transfer custody to another facility without 
recertifying the batch or portion of the batch as follows:
    (i) Winter RFG or RBOB may be redesignated as Winter CG or CBOB.
    (ii) Winter CG or CBOB may be redesignated as Winter RFG or RBOB.
    (iii) Summer RFG or RBOB and Summer CG or CBOB may be redesignated 
to a less stringent RVP designation. For example, a distributor could 
redesignate without recertification a portion of a batch of Summer RFG 
to 7.8 psi Summer CG or 9.0 psi Summer CG.
    (iv) Summer RFG or RBOB and Summer CG or CBOB may be redesignated 
as Winter RFG or RBOB or Winter CG or CBOB.
    (v)(A) California gasoline may be redesignated as RFG or CG, with 
appropriate season designation and RVP designation under paragraph (a) 
of this section, if the requirements specified in Sec.  1090.625(d) are 
met.
    (B) California gasoline that is not redesignated under paragraph 
(b)(2)(v)(A) of this section may instead be recertified as gasoline 
under Sec.  1090.1100(b).
    (vi) CG and RFG may not be redesignated as BOB.
    (3) Distributors that redesignate batches or portions of gasoline 
under paragraph (b)(2) of this section must accurately and clearly 
designate the batch or portion of the batch of gasoline as specified in 
paragraph (a) of this section.
    (c) Designation requirements for oxygenate producers. Oxygenate

[[Page 29133]]

producers must accurately and clearly designate each batch of oxygenate 
intended for blending with gasoline as one of the following oxygenate 
types:
    (1) DFE.
    (2) The name of the specific oxygenate (e.g., iso-butanol).
    (d) Designation requirements for certified butane and certified 
pentane. Certified butane and certified pentane producers must 
accurately and clearly designate each batch of certified butane and 
certified pentane as one of the following types:
    (1) Certified butane.
    (2) Certified pentane.
    (e) Designation requirements for certified ethanol denaturant. 
Certified ethanol denaturant producers must accurately and clearly 
designate batches of certified ethanol denaturant as ``certified 
ethanol denaturant''.

Sec.  1090.1115  Designation requirements for diesel and distillate 
fuels.

    (a) Designation requirements for diesel and distillate fuel 
manufacturers. (1) Except as specified in paragraphs (a)(3) and (4) of 
this section, diesel and distillate fuel manufacturers must accurately 
and clearly designate each batch of diesel or distillate fuel as at 
least one of the following fuel types:
    (i) ULSD. Diesel fuel manufacturers may also designate the fuel as 
15 ppm MVNRLM.
    (ii) LM 500 diesel fuel.
    (iii) Heating oil.
    (iv) Jet fuel.
    (v) Kerosene.
    (vi) ECA marine fuel.
    (vii) Distillate global marine fuel.
    (viii) Exempt diesel or distillate fuel under subpart G of this 
part (including additional identifying information).
    (2) Only fuel manufacturers that comply with the requirements in 
Sec.  1090.520 may designate fuel as LM 500 diesel fuel.
    (3) Any batch of diesel or distillate fuel that is certified and 
designated as ULSD may also be designated as heating oil, kerosene, or 
jet fuel if it is also suitable for use as heating oil, kerosene, or 
jet fuel.
    (4) Any batch of diesel or distillate fuel that is certified and 
designated as ULSD may also be designated as ECA marine fuel or 
distillate global marine fuel if the applicable requirements in Sec.  
1090.325 are met.
    (b) Designation requirements for distributors of diesel and 
distillate fuels. Distributors of diesel and distillate fuels must 
accurately and clearly designate each batch of diesel or distillate 
fuel for which they transfer custody as follows:
    (1) Distributors must accurately and clearly designate such diesel 
or distillate fuel by sulfur content while it is in their custody 
(e.g., as 15 ppm or 500 ppm).
    (2) Distributors must accurately and clearly designate such diesel 
or distillate fuel as specified by the diesel or distillate fuel 
manufacturer under paragraph (a) of this section.
    (3) Distributors may redesignate batches or portions of batches of 
diesel or distillate fuel for which they transfer custody to another 
facility without recertifying the batch or portion of the batch as 
follows:
    (i) ULSD that is also suitable for use as kerosene or jet fuel 
(commonly referred to as dual use kerosene) may be designated as ULSD, 
kerosene, or jet fuel (as applicable).
    (ii) ULSD may be redesignated as LM 500 diesel fuel, heating oil, 
jet fuel, kerosene, ECA marine fuel, or distillate global marine fuel 
without recertification if all applicable requirements under this part 
are met for the new fuel designation.
    (iii) California diesel may be redesignated as ULSD if the 
requirements specified in Sec.  1090.625(e) are met.
    (iv) Heating oil, kerosene, or jet fuel may be redesignated as ULSD 
if the requirements specified in Sec.  1090.315 are met.
    (v) 500 ppm LM diesel fuel may be redesignated as ECA marine fuel, 
distillate global marine fuel, heating oil, or blendstock. Any person 
that redesignates 500 ppm LM diesel fuel to ECA marine fuel or 
distillate global marine fuel must maintain records from the producer 
of the 500 ppm LM diesel fuel (i.e., PTDs accompanying the fuel under 
Sec.  1090.1165) to demonstrate compliance with the 500 ppm sulfur 
standard in Sec.  1090.320(b).
    (c) No person may designate distillate fuel with a sulfur content 
greater than the sulfur standard in Sec.  1090.305(b) as ULSD.

Sec.  1090.1120  Batch numbering.

    (a) Fuel manufacturers, fuel additive manufacturers, and regulated 
blendstock producers must assign a number (the ``batch number'') to 
each batch of gasoline, diesel fuel, oxygenate, certified pentane, or 
certified ethanol denaturant either produced or imported. The batch 
number must, if available, consist of the EPA-assigned company 
registration number of the party that either produced or imported the 
fuel, fuel additive, or regulated blendstock, the EPA-assigned facility 
registration number where the fuel, fuel additive, or regulated 
blendstock was produced or imported, the last two digits of the year 
that the batch was either produced or imported, and a unique number for 
the batch, beginning with the number one (1) for the first batch 
produced or imported each calendar year and each subsequent batch 
during the calendar year being assigned the next sequential number 
(e.g., 4321-54321-20-000001, 4321-54321-20-000002, etc.). EPA assigns 
company and facility registration numbers as specified in subpart I of 
this part.
    (b) Certified butane or certified pentane blended with PCG during a 
period of up to one month may be included in a single batch for 
purposes of reporting to EPA. However, certified butane and certified 
pentane must be reported as separate batches.
    (c) Gasoline manufacturers that recertify BOBs under Sec.  1090.740 
may include up to a single month's volume as a single batch for 
purposes of reporting to EPA.

Product Transfer Documents

Sec.  1090.1150  General PTD provisions.

    (a) General. (1) On each occasion when any person transfers custody 
or title to any product covered under this part other than when fuel is 
sold or dispensed for use in motor vehicles at a retail outlet or WPC 
facility, the transferor must provide to the transferee PTDs that 
include all the following information:
    (i) The name and address of the transferor.
    (ii) The name and address of the transferee.
    (iii) The volume of the product being transferred, in gallons.
    (iv) The location of the product at the time of the transfer.
    (v) The date of the transfer.
    (2) The specific designations required for gasoline-related 
products specified in Sec.  1090.1110 or distillate-related products 
specified in Sec.  1090.1115.
    (b) Use of codes. Except for transfers to truck carriers, 
retailers, or WPCs, product codes may be used to convey the information 
required under this subpart, if such codes are clearly understood by 
each transferee.

Sec.  1090.1155  PTD requirements for exempted fuels.

    (a) In addition to the information required under Sec.  1090.1150, 
on each occasion when any person transfers custody or title to any 
exempted fuel under subpart G of this part, the transferor must provide 
to the transferee PTDs that include the following statements, as 
applicable:
    (1) National security exemption language. For fuels with a national 
security exemption specified in Sec.  1090.605: ``This fuel is for use 
in

[[Page 29134]]

vehicles, engines, or equipment under an EPA-approved national security 
exemption only.''
    (2) R&D exemption language. For fuels used for an R&D purpose 
specified in Sec.  1090.610: ``For use in research, development, and 
test programs only.''
    (3) Racing fuel language. For fuels used for racing purposes 
specified in Sec.  1090.615: ``This fuel is for racing purposes only.''
    (4) Aviation fuel language. For fuels used in aircraft specified in 
Sec.  1090.615: ``This fuel is for aviation use only.''
    (5) Territory fuel exemption language. For fuels for use in 
American Samoa, Guam, or the Commonwealth of the Northern Mariana 
Islands specified in Sec.  1090.620: ``This fuel is for use only in 
Guam, American Samoa, or the Northern Mariana Islands.''
    (6) California gasoline language. For California gasoline specified 
in Sec.  1090.625: ``California gasoline''.
    (7) California diesel language. For California diesel specified in 
Sec.  1090.625: ``California diesel''.
    (8) Alaska, Hawaii, Puerto Rico, and U.S. Virgin Islands summer 
gasoline language. For summer gasoline for use in Alaska, Hawaii, 
Puerto Rico, or the U.S. Virgin Islands specified in Sec.  1090.630: 
``This summer gasoline is for use only in Alaska, Hawaii, Puerto Rico, 
or the U.S. Virgin Islands.''
    (9) Exported fuel language. For exported fuels specified in Sec.  
1090.645: ``This fuel is for export from the United States only.''
    (b) In statements required by paragraph (a) of this section, where 
``fuel'' is designated in a statement, the specific fuel type (for 
example, ``diesel fuel'' or ``gasoline'') may be used in place of the 
word ``fuel''.

Sec.  1090.1160  Gasoline, gasoline additive, and gasoline regulated 
blendstock PTD provisions.

    (a) General requirements. For each occasion that any person 
transfers custody of any gasoline, gasoline additive, or gasoline 
regulated blendstock, the transferor must provide the transferee PTDs 
that include the following information:
    (1) All applicable information required under Sec.  1090.1150 and 
this section.
    (2) An accurate and clear statement of the applicable designation 
of the gasoline, gasoline additive, or gasoline regulated blendstock 
under Sec.  1090.1110.
    (b) BOB language requirements. For batches of BOB, in addition to 
the information required under paragraph (a) of this section, the 
following information must be included on the PTD:
    (1) Oxygenate type(s) and amount(s). Statements specifying each 
oxygenate type and amount (or range of amounts) that the fuel 
manufacturer certified a hand blend under Sec.  1090.710 for the BOB.
    (2) Summer BOB language requirements. Except as specified in 
paragraph (b)(2)(iv) of this section, for batches of summer BOB, 
identification of the product with one of the following statements 
indicating the applicable RVP standard in Sec.  1090.215.
    (i) ``9.0 psi CBOB. This product does not meet the requirements for 
summer reformulated gasoline.''
    (ii) ``7.8 psi CBOB. This product does not meet the requirements 
for summer reformulated gasoline.''
    (iii) ``RBOB. This product meets the requirements for summer 
reformulated or conventional gasoline.''
    (iv) For BOBs designed to produce a finished gasoline that must 
meet an RVP per-gallon standard required by any SIP approved or 
promulgated under 42 U.S.C. Sec.  7410 or Sec.  7502, additional or 
substitute language to satisfy the state program may be used as 
necessary but must include at a minimum the applicable RVP standard 
established under the SIP.
    (c) RFG and CG requirements. For batches of RFG and CG, in addition 
to the information required under paragraph (a) of this section, the 
following information must be included on the PTD:
    (1) Summer gasoline language requirements. (i) Except as specified 
in paragraph (c)(1)(ii) of this section, for summer gasoline, 
identification of the product with one of the following statements 
indicating the applicable RVP standard:
    (A) For gasoline that meets the 9.0 psi RVP standard in Sec.  
1090.215(a): ``9.0 psi Gasoline.''
    (B) For gasoline that meets the 7.8 psi RVP standard in Sec.  
1090.215(a)(1): ``7.8 psi Gasoline.''
    (C) For gasoline that meets the RFG 7.4 psi RVP standard in Sec.  
1090.215(a)(2): ``Reformulated Gasoline.''
    (ii) For finished gasoline that meets an RVP per-gallon standard 
required by any SIP approved or promulgated under 42 U.S.C. Sec.  7410 
or 7502, additional or substitute language to satisfy the state program 
may be used as necessary.
    (2) Ethanol content language requirements. (i) For gasoline-ethanol 
blends, one of the following statements that accurately describes the 
gasoline:
    (A) For gasoline containing no ethanol (``E0''), the following 
statement: ``E0: Contains no ethanol.''
    (B) For finished gasoline containing less than 9 volume percent 
ethanol, the following statement: ``EX--Contains up to X% ethanol.'' 
The term X refers to the maximum volume percent ethanol present in the 
gasoline-ethanol blend.
    (C) For E10, the following statement: ``E10: Contains between 9 and 
10 vol % ethanol.''
    (D) For E15, the following statement: ``E15: Contains up to 15 vol 
% ethanol.''
    (E) For gasoline-ethanol blends containing more than 15 volume 
percent ethanol, the following statement: ``EXX: Contains up to XX vol 
% ethanol.'' The term XX refers to the maximum volume percent ethanol 
present in the gasoline-ethanol blend.
    (ii) No person may designate a fuel as E10 if the fuel is produced 
by blending ethanol and gasoline in a manner designed to contain less 
than 9.0 or more than 10.0 volume percent ethanol.
    (iii) No person may designate a fuel as E15 if the fuel is produced 
by blending ethanol and gasoline in a manner designed to contain less 
than 10.0 or more than 15.0 volume percent ethanol.
    (d) Oxygenate language requirements. In addition to any other PTD 
requirements of this subpart, on each occasion when any person 
transfers custody or title to any oxygenate upstream of any oxygenate 
blending facility, the transferor must provide to the transferee PTDs 
that include the following information, as applicable:
    (1) For DFE: ``Denatured fuel ethanol, maximum 10 ppm sulfur.''
    (2) For other oxygenates, the name of the specific oxygenate must 
be identified on the PTD, followed by ``maximum 10 ppm sulfur.'' For 
example, for isobutanol, the following statement on the PTD would be 
required, ``Isobutanol, maximum 10 ppm sulfur.''
    (e) Gasoline detergent language requirements. In addition to any 
other PTD requirements of this subpart, on each occasion when any 
person transfers custody or title to any gasoline detergent, the 
transferor must provide to the transferee PTDs that include the 
following information:
    (1) The identity of the product being transferred as detergent, 
detergent-additized gasoline, or non-additized detergent gasoline.
    (2) The name of the registered detergent must be used to identify 
the detergent additive package on its PTD and the LAC on the PTD must 
be consistent with the requirements in Sec.  1090.240.
    (f) Gasoline additives language requirements. In addition to any 
other PTD requirements of this subpart, on each occasion when any 
person transfers custody or title to any gasoline additive that meets 
the requirements of

[[Page 29135]]

Sec.  1090.255(a), the transferor must provide to the transferee PTDs 
that include all the following information:
    (1) The maximum allowed treatment rate of the additive so that the 
additive will contribute no more than 3 ppm sulfur to the finished 
gasoline.
    (2) [Reserved].
    (g) Certified ethanol denaturant language requirements. In addition 
to any other PTD requirements of this subpart, on each occasion when 
any person transfers custody or title to any certified ethanol 
denaturant that meets the requirements of Sec.  1090.235(b), the 
transferor must provide to the transferee PTDs that include all the 
following information:
    (1) The following statement: ``Certified Ethanol Denaturant 
suitable for use in the manufacture of denatured fuel ethanol meeting 
EPA standards.''
    (2) The PTD must state that the sulfur content is 330 ppm or less. 
If the certified ethanol denaturant manufacturer represents a batch of 
denaturant as having a maximum sulfur content lower than 330 ppm, the 
PTD must instead state that lower sulfur maximum (e.g., has a sulfur 
content of 120 ppm or less).
    (h) Butane and pentane language requirements. (1) In addition to 
any other PTD requirements of this subpart, on each occasion when any 
person transfers custody or title to any certified butane or certified 
pentane, the transferor must provide to the transferee PTDs that 
include the following information:
    (i) The certified butane or certified pentane producer company name 
and facility registration number issued by EPA.
    (ii) One of the following statements, as applicable:
    (A) ``Certified pentane for use by certified pentane blenders''.
    (B) ``Certified butane for use by certified butane blenders''.
    (2) PTDs that are compliant with the requirements of paragraph 
(h)(1) of this section must be transferred from each party transferring 
certified butane or certified pentane for use by certified butane or 
certified pentane blenders to each party that receives the certified 
butane or certified pentane through to the certified butane or 
certified pentane blender, respectively.

Sec.  1090.1165   PTD requirements for distillate and residual fuels.

    (a) General requirements. For each occasion that any person 
transfers custody of any distillate or residual fuel, the transferor 
must provide the transferee PTDs that include the following 
information:
    (1) The sulfur per-gallon standard that the transferor represents 
the fuel to meet under subpart D of this part (e.g., 15 ppm sulfur for 
ULSD or 1,000 ppm sulfur for ECA marine fuel).
    (2) An accurate and clear statement of the applicable 
designation(s) of the fuel under Sec.  1090.1115 (e.g., ``ULSD'', ``500 
ppm LM diesel fuel'', or ``ECA marine fuel'').
    (3) If the fuel does not meet the ULSD sulfur standard in Sec.  
1090.305(b), the following statement: ``Not for use in highway vehicles 
or engines or nonroad, locomotive, or marine engines.''
    (b) 500 ppm LM diesel fuel language requirements. For batches of 
500 ppm LM diesel fuel, in addition to the information required under 
paragraph (a) of this section, the following information must be 
included on the PTD:
    (1) The following statement: ``500 ppm sulfur (maximum) LM diesel 
fuel. For use only in accordance with a compliance plan under 40 CFR 
1090.520(g). Not for use in highway vehicles or other nonroad vehicles 
and engines.''
    (2) [Reserved]
    (c) ECA marine fuel language requirements. For batches of ECA 
marine fuel, in addition to the information required under paragraph 
(a) of this section, the following information must be included on the 
PTD:
    (1) The following statement: ``1,000 ppm sulfur (maximum) ECA 
marine fuel. For use in Category 3 marine vessels only. Not for use in 
Category 1 or Category 2 marine vessels.''
    (2) Parties may replace the required statement in paragraph (c)(1) 
of this section with the following statement for qualifying vessels 
under 40 CFR part 1043: ``High sulfur fuel. For use only in ships as 
allowed by MARPOL Annex VI, Regulation 3 or Regulation 4.''
    (3) Under 40 CFR 1043.80, fuel suppliers (i.e., ECA marine fuel 
distributors, retailers, and WPCs) must provide bunker delivery notes 
to vessel operators in addition to any applicable PTD requirements 
under this subpart.
    (d) Distillate global marine fuel language requirements. For 
batches of distillate global marine fuel, in addition to the 
information required under paragraph (a) of this section, the following 
information must be included on the PTD:
    (1) The following statement: ``For use only in steamships or 
Category 3 marine vessels outside of an Emission Control Area (ECA), 
consistent with MARPOL Annex VI.''
    (2) [Reserved]

Sec.  1090.1170   Diesel fuel additives language requirements.

    In addition to any other PTD requirements in this subpart, on each 
occasion that any person transfers custody or title to a diesel fuel 
additive that is subject to the provisions of Sec.  1090.310 to a party 
in the additive distribution system or in the diesel fuel distribution 
system for use downstream of the diesel fuel manufacturing facility, 
the transferor must provide to the transferee PTDs that include the 
following information:
    (a) For diesel fuel additives that comply with the sulfur standard 
in Sec.  1090.310(a), include the following statement: ``The sulfur 
content of this diesel fuel additive does not exceed 15 ppm.''
    (b) For diesel fuel additives that meet the requirements of Sec.  
1090.310(b), the transferor must provide to the transferee documents 
that identify the additive as such, and do all the following:
    (1) Indicate the high sulfur potential of the diesel fuel additive 
by including the following statement: ``This diesel fuel additive may 
exceed the federal 15 ppm sulfur standard. Improper use of this 
additive may result in non-compliant diesel fuel.''
    (2) If the diesel fuel additive package contains a static 
dissipater additive or red dye having a sulfur content greater than 15 
ppm, one of the following statements must be included that accurately 
describes the contents of the additive package:
    (i) ``This diesel fuel additive contains a static dissipater 
additive having a sulfur content greater than 15 ppm.''
    (ii) ``This diesel fuel additive contains red dye having a sulfur 
content greater than 15 ppm.''
    (iii) ``This diesel fuel additive contains a static dissipater 
additive and red dye having a sulfur content greater than 15 ppm.''
    (3) Include the following information:
    (i) The diesel fuel additive package's maximum sulfur 
concentration.
    (ii) The maximum recommended concentration for use of the diesel 
fuel additive package in diesel fuel, in volume percent.
    (iii) The contribution to the sulfur level of the fuel (in ppm) 
that would result if the diesel fuel additive package is used at the 
maximum recommended concentration.
    (c) For diesel fuel additives that are sold in containers for use 
by the ultimate consumer of diesel fuel, each transferor must display 
on the additive container, in a legible and conspicuous manner, one of 
the following statements, as applicable:

[[Page 29136]]

    (1) For diesel fuel additives that comply with the sulfur standard 
in Sec.  1090.310(a), ``This diesel fuel additive complies with the 
federal low sulfur content requirements for use in diesel motor 
vehicles and nonroad engines.''
    (2) For diesel fuel additives that do not comply with the sulfur 
standard in Sec.  1090.310(a), the following statement: ``This diesel 
fuel additive does not comply with federal ultra-low sulfur content 
requirements.''

Sec.  1090.1175  Alternative PTD language provisions.

    (a) Alternative PTD language to the language specified in this 
subpart may be used if approved by EPA in advance. Such language must 
contain all the applicable informational elements specified in this 
subpart.
    (b) Requests for alternative PTD language must be submitted as 
specified in Sec.  1090.10.

Subpart L--Recordkeeping

Sec.  1090.1200   General recordkeeping requirements.

    (a) Length of time records must be kept. Records required by this 
part must be kept for 5 years from the date they were created, except 
that records relating to credit transfers must be kept by the 
transferor for 5 years from the date the credits were transferred and 
must be kept by the transferee for 5 years from the date the credits 
were transferred, used, or terminated, whichever is later.
    (b) Make records available to EPA. On request by EPA, the records 
specified in this part must be provided to EPA. For records that are 
electronically generated or maintained, the equipment and software 
necessary to read the records must be made available, or upon approval 
by EPA, electronic records must be converted to paper documents that 
must be provided to EPA.

Sec.  1090.1205   Recordkeeping requirements for all regulated parties.

    (a) Overview. Any party subject to the requirements and provisions 
of this part must keep records containing the information specified in 
this section.
    (b) Records related to PTDs. Any party that transfers title or 
custody of any fuel, fuel additive, or regulated blendstock must 
maintain the PTDs for which the party is the transferor or transferee.
    (c) Records related to sampling and testing. Any party required to 
perform any sampling and testing on any fuel, fuel additive, or 
regulated blendstock must keep records of the following:
    (1) The location, date, time, and storage tank or truck, rail car, 
or vessel identification for each sample collected.
    (2) The identification of the person(s) who collected the sample 
and the person(s) who performed the testing.
    (3) The results of all tests as originally printed by the testing 
apparatus, or where no printed result is produced, the results as 
originally recorded by the person or apparatus that performed the test. 
Where more than one test is performed, keep all the results.
    (4) The methodology used to test any parameter under this part.
    (5) Records related to performance-based measurement and 
statistical quality control under Sec. Sec.  1090.1360 through 
1090.1375.
    (6) Records related to gasoline deposit control testing under Sec.  
1090.1395.
    (7) The actions taken to stop the sale of any fuel, fuel additive, 
or regulated blendstock found not to be in compliance with applicable 
standards under this part, and the actions taken to identify the cause 
of any noncompliance and prevent future instances of noncompliance.
    (d) Records related to registration. For parties required to 
register under subpart I of this part, the party must maintain records 
supporting the information required to complete and maintain the 
registration for the party's company and each registered facility. The 
party must also maintain copies of any confirmation received from the 
submission of such registration information to EPA.
    (e) Records related to reporting. For parties required to submit 
reports under subpart J of this part, the party must maintain copies of 
all reports submitted to EPA. The party must also maintain copies of 
any confirmation received from the submission of such reports to EPA.
    (f) Records related to exemptions. Anyone that produces or 
distributes exempt fuel, fuel additive, or regulated blendstock under 
subpart G of this part must keep the following records:
    (1) Designation of the fuel, fuel additive, or regulated blendstock 
under subparts G and K of this part.
    (2) Copies of PTDs generated or accompanying the exempted fuel, 
fuel additive, or regulated blendstock.
    (3) Records demonstrating that the exempt fuel, fuel additive, or 
regulated blendstock was actually used in accordance with the 
requirements of the applicable exemption(s) under subpart G of this 
part.

Sec.  1090.1210   Recordkeeping requirements for gasoline 
manufacturers.

    (a) Overview. In addition to the requirements in Sec.  1090.1205, 
gasoline manufacturers must keep records for each of their facilities 
that include the information in this section.
    (b) Batch records. For each batch of gasoline, gasoline 
manufacturers must keep records of the following information:
    (1) The results of tests, including any calculations necessary to 
transcribe or correlate test results into reported values under subpart 
J of this part, performed to determine gasoline properties and 
characteristics as specified in subpart M of this part.
    (2) The batch volume.
    (3) The batch number.
    (4) The date the batch was produced or imported.
    (5) The designation of the batch under Sec.  1090.1110.
    (6) The PTDs for any gasoline produced or imported.
    (7) The PTDs for any gasoline received.
    (c) Downstream oxygenate accounting records. For BOB certified for 
including in downstream oxygenate accounting under Sec.  1090.710, 
gasoline manufacturers must keep records of the following information:
    (1) The test results for hand blends prepared under Sec.  
1090.1340.
    (2) Records that demonstrate that the gasoline manufacturer 
participates in the national fuels survey program under subpart N of 
this part.
    (3) Records that demonstrate that the gasoline manufacturer 
participates in the national sampling oversight program under Sec.  
1090.1440.
    (4) Compliance calculations specified in Sec.  1090.700 based on an 
assumed addition of oxygenate.
    (d) Records for PCG. For new batches of gasoline produced by adding 
blendstock to PCG, gasoline manufacturers must keep records of the 
following information:
    (1) Records that reflect the storage and movement of the PCG and 
blendstock within the fuel manufacturing facility to the point such PCG 
is used to produce gasoline or BOB.
    (2) For new batches of gasoline produced by adding blendstock to 
PCG under Sec.  1090.1320(a)(1), keep records of the following 
additional information:
    (i) The results of tests to determine the sulfur content, benzene 
content, RVP in the summer, and oxygenate(s) content for the PCG and 
volume of the PCG when received at the fuel manufacturing facility.
    (ii) Records demonstrating which batches of PCG were used in each 
new batch of gasoline.
    (iii) Records demonstrating which, if any, blendstocks were used in 
each new batch of gasoline.

[[Page 29137]]

    (iv) Records of the test results for sulfur content, benzene 
content, RVP in the summer, oxygenate(s) content, and distillation 
parameters for each new batch of gasoline.
    (3) For new batches of gasoline produced by adding blendstock to 
PCG under Sec.  1090.1320(a)(2), keep records of the following 
additional information:
    (i) Records of the test results for sulfur content, benzene 
content, RVP in the summer, and oxygenate(s) content of each blendstock 
used to produce the new batch of gasoline.
    (ii) Records of the test results for sulfur content and RVP in the 
summer of each new batch of gasoline.
    (iii) Records demonstrating which, if any, blendstocks were used in 
each new batch of gasoline.
    (e) Records for certified butane and certified pentane blenders. 
For certified butane or certified pentane blended into gasoline or BOB 
under Sec.  1090.1320, certified butane and certified pentane blenders 
must keep records of the following information:
    (1) The volume of certified butane or certified pentane added.
    (2) The volume of gasoline prior to and after the certified butane 
or certified pentane blending.
    (3) The purity and properties of the certified butane or certified 
pentane specified in Sec.  1090.220 or Sec.  1090.225, respectively.
    (f) Records for the importation of gasoline treated as blendstock. 
For any imported GTAB, importers must keep records of documents that 
reflect the storage and physical movement of the GTAB from the point of 
importation to the point of blending to produce gasoline.
    (g) Records related to ABT. Gasoline manufacturers must keep 
records of the following information related to their ABT activities 
under subpart H of this part, as applicable:
    (1) Compliance sulfur values and compliance benzene values under 
Sec.  1090.700, and the calculations used to determine those values.
    (2) The number of valid credits in possession of the gasoline 
manufacturer at the beginning of each compliance period, separately by 
facility and compliance period of generation.
    (3) The number of credits generated by the gasoline manufacturer 
under Sec.  1090.725, separately by facility and compliance period of 
generation.
    (4) If any credits were obtained from or transferred to other 
parties, all the following for each other party:
    (i) The party's name.
    (ii) The party's EPA company and facility registration numbers.
    (iii) The number of credits obtained from or transferred to the 
party.
    (5) The number of credits that expired at the end of each 
compliance period, separately by facility and compliance period of 
generation.
    (6) The number of credits that will be carried over into the next 
compliance period, separately by facility and compliance period of 
generation.
    (7) The number of credits used, separately by facility and 
compliance period of generation.
    (8) Contracts or other commercial documents that establish each 
transfer of credits from the transferor to the transferee.
    (9) Documentation that supports the number of credits transferred 
between facilities within the same company (i.e., intracompany 
transfers).

Sec.  1090.1215   Recordkeeping requirements for diesel fuel and ECA 
marine fuel manufacturers.

    (a) Overview. In addition to the requirements in Sec.  1090.1205, 
diesel fuel and ECA marine fuel manufacturers must keep records for 
each of their facilities that include the information in this section.
    (b) Batch records. For each batch of ULSD, 500 ppm LM diesel fuel, 
or ECA marine fuel, diesel fuel and ECA marine fuel manufacturers must 
keep records of the following information:
    (1) The batch volume.
    (2) The batch number.
    (3) The date the batch was produced or imported.
    (4) The designation of the batch under Sec.  1090.1115.
    (5) All documents and information created or used for the purpose 
of batch designation under Sec.  1090.1115, including PTDs for the 
batch.
    (c) Distillate global marine fuel. For each batch of distillate 
global marine fuel, distillate global marine fuel manufacturers must 
keep records of the following information:
    (1) The designation of the batch as distillate global marine fuel.
    (2) The PTD for the batch.

Sec.  1090.1220   Recordkeeping requirements for oxygenate blenders.

    (a) In addition to the requirements in Sec.  1090.1205, oxygenate 
blenders that blend oxygenate into gasoline must keep records that 
include the information in this section.
    (b) For each occasion that an oxygenate blender blends oxygenate 
into gasoline, oxygenate blenders must keep records of the following 
information:
    (1) The date, time, location, and identification of the blending 
tank or truck in which the blending occurred.
    (2) The volume and oxygenate requirement of the gasoline to which 
oxygenate was added.
    (3) The volume, type, and purity of the oxygenate that was added, 
and documents that show the supplier(s) of the oxygenate used.

Sec.  1090.1225   Recordkeeping requirements for gasoline additives.

    (a) Gasoline additive producers and importers. In addition to the 
requirements in Sec.  1090.1205, gasoline additive manufacturers must 
keep records of the following information for each batch of additive 
produced or imported:
    (1) The batch volume.
    (2) The date the batch was produced or imported.
    (3) The PTD for the batch.
    (4) The maximum recommended treatment rate.
    (5) The gasoline additive manufacturer's control practices that 
demonstrate that the additive will contribute no more than 3 ppm on a 
per-gallon basis to the sulfur content of gasoline when used at the 
maximum recommended treatment rate.
    (b) Records that parties that take custody of gasoline additives in 
the gasoline additive distribution system must keep. Except for 
gasoline additives packaged for addition to gasoline in the vehicle 
fuel tank, all parties that take custody of gasoline additives for bulk 
addition to gasoline--from the producer through to the party that adds 
the additive to gasoline--must keep records of the following 
information:
    (1) The PTD for each batch of gasoline additive.
    (2) The treatment rate at which the additive was added to gasoline, 
as applicable.
    (3) The volume of gasoline that was treated with the additive, as 
applicable. A new record must be initiated in cases where a new batch 
of additive is mixed into a storage tank from which the additive is 
drawn to be injected into gasoline.

Sec.  1090.1230   Recordkeeping requirements for oxygenate producers.

    (a) Oxygenate producers. In addition to the requirements in Sec.  
1090.1205, oxygenate producers must keep records of the following 
information for each batch of oxygenate:
    (1) The batch volume.
    (2) The batch number.
    (3) The date the batch was produced or imported.
    (4) The PTD for the batch.
    (5) The sulfur content of the batch.
    (6) The sampling and testing records specified in Sec.  
1090.1205(c), if the sulfur

[[Page 29138]]

content of the batch was determined by analytical testing.
    (b) DFE producers. In addition to the requirements in paragraph (a) 
of this section, DFE producers must keep records of the following 
information for each batch of DFE if the sulfur content of the batch 
was determined under Sec.  1090.1330:
    (1) The name and title of the person who calculated the sulfur 
content of the batch.
    (2) The date the calculation was performed.
    (3) The calculated sulfur content.
    (4) The sulfur content of the neat (un-denatured) ethanol.
    (5) The date each batch of neat ethanol was produced.
    (6) The neat ethanol batch number.
    (7) The neat ethanol batch volume.
    (8) As applicable, the neat ethanol production quality control 
records, or the test results on the neat ethanol, including all the 
following:
    (i) The location, date, time, and storage tank or truck 
identification for each sample collected.
    (ii) The name and title of the person who collected the sample and 
the person who performed the test.
    (iii) The results of the test as originally printed by the testing 
apparatus, or where no printed result is produced, the results as 
originally recorded by the person who performed the test.
    (iv) Any record that contains a test result for the sample that is 
not identical to the result recorded in paragraph (b)(8)(iii) of this 
section.
    (v) The test methodology used.
    (9) The sulfur content of each batch of denaturant used, and the 
volume percent at which the denaturant was added to neat (un-denatured) 
ethanol to produce DFE.
    (10) The PTD for each batch of denaturant used.
    (c) Records that parties that take custody of oxygenate in the 
oxygenate distribution system must keep. All parties that take custody 
of oxygenate--from the oxygenate producer through to the oxygenate 
blender--must keep records of the PTD for each batch of oxygenate.

Sec.  1090.1235   Recordkeeping requirements for ethanol denaturant.

    (a) Certified ethanol denaturant producers. In addition to the 
requirements in Sec.  1090.1205, certified ethanol denaturant producers 
must keep records of the following information for each batch of 
certified ethanol denaturant:
    (1) The batch volume.
    (2) The batch number.
    (3) The date the batch was produced or imported.
    (4) The PTD for the batch.
    (5) The sulfur content of the batch.
    (b) Parties that take custody of ethanol denaturants. All parties 
that take custody of denaturant designated as suitable for use in the 
production of DFE under Sec.  1090.230(b) must keep records of the 
following information:
    (1) The PTD for each batch of denaturant.
    (2) The volume percent at which the denaturant was added to 
ethanol, as applicable.

Sec.  1090.1240  Recordkeeping requirements for gasoline detergent 
blenders.

    (a) Overview. In addition to the requirements in Sec.  1090.1205, 
gasoline detergent blenders must keep records that include the 
information in this section.
    (b) Gasoline detergent blenders. Gasoline detergent blenders must 
keep records of the following information:
    (1) The PTD for each detergent used.
    (2) For automated detergent blending facilities, keep records of 
the following information:
    (i) The dates of the VAR Period.
    (ii) The total volume of detergent blended into gasoline, as 
determined using one of the following methods, as applicable:
    (A) For facilities that use in-line meters to measure the amount of 
detergent blended, the total volume of detergent measured, together 
with supporting data that includes one of the following:
    (1) The beginning and ending meter readings for each meter being 
measured.
    (2) Other comparable metered measurements.
    (B) For facilities that use a gauge to measure the inventory of the 
detergent storage tank, the total volume of detergent must be 
calculated as follows:

VD = DIi -DIf + DIa -
DIw

Where:

VD = Volume of detergent.
DIi = Initial detergent inventory of the tank.
DIf = Final detergent inventory of the tank.
DIa = Sum of any additions to detergent inventory.
DIw = Sum of any withdrawals from detergent inventory for 
purposes other than the additization of gasoline.

    (C) The value of each variable in the equation in paragraph 
(b)(2)(ii)(B) of this section must be separately recorded. Recorded 
volumes of detergent must be expressed to the nearest gallon (or 
smaller units), except that detergent volumes of five gallons or less 
must be expressed to the nearest tenth of a gallon (or smaller units). 
However, if the blender's equipment is unable to accurately measure to 
the nearest tenth of a gallon, then such volumes must be rounded 
downward to the next lower gallon.
    (iii) The total volume of gasoline to which detergent has been 
added, together with supporting data that includes one of the 
following:
    (A) The beginning and ending meter measurements for each meter 
being measured.
    (B) The metered batch volume measurements for each meter being 
measured.
    (C) Other comparable metered measurements.
    (iv) The actual detergent concentration, calculated as the total 
volume of the detergent added (as determined under paragraph (b)(2)(ii) 
of this section) divided by the total volume of gasoline (as determined 
under paragraph (b)(2)(iii) of this section). The concentration must be 
calculated and recorded to four digits and rounded as specified in 
Sec.  1090.50.
    (v) The initial detergent concentration rate, together with the 
date and description of each adjustment to any initially set 
concentration.
    (vi) If the detergent injector is set below the applicable LAC, or 
adjusted by more than 10 percent above the concentration initially set 
in the VAR Period, documentation establishing that the purpose of the 
change is to correct a batch misadditization prior to the end of the 
VAR Period and prior to the transfer of the batch to another party or 
to correct an equipment malfunction and the date and adjustments of the 
correction.
    (vii) Documentation reflecting the performance and results of the 
calibration of detergent equipment under Sec.  1090.1390.
    (3) For non-automated detergent blending facilities, keep records 
of the following information:
    (i) The date of additization.
    (ii) The volume of added detergent.
    (iii) The volume of gasoline to which the detergent was added.
    (iv) The actual detergent concentration, calculated as the volume 
of added detergent (as determined under paragraph (b)(3)(ii) of this 
section) divided by the volume of gasoline (as determined under 
paragraph (b)(3)(iii) of this section). The concentration must be 
calculated and recorded to four digits and rounded as specified in 
Sec.  1090.50.

Sec.  1090.1245   Recordkeeping requirements for independent surveyors.

    (a) In addition to the requirements in Sec.  1090.1205, independent 
surveyors must keep records that include the information in this 
section.

[[Page 29139]]

    (b) Independent surveyors must keep records of the following 
information, as applicable:
    (1) Records related to the national fuels survey program under 
Sec.  1090.1405.
    (2) Records related to a geographically-focused E15 survey program 
under Sec.  1090.1420(b).
    (3) Records related to the national sampling oversight program 
under Sec.  1090.1440.

Sec.  1090.1250   Recordkeeping requirements for auditors.

    (a) In addition to the requirements in Sec.  1090.1205, auditors 
must keep records that include the information in this section.
    (b) Auditors must keep records of the following information:
    (1) Documents pertaining to the performance of each audit performed 
under subpart R of this part.
    (2) Copies of each attestation report prepared and all related 
records developed to prepare the attestation report.
    (c) Auditors must keep the records specified in paragraph (b) of 
this section for 5 years after issuing each attestation report.

Sec.  1090.1255   Recordkeeping requirements for transmix processors, 
transmix blenders, transmix distributors, and pipeline operators.

    (a) In addition to the requirements in Sec.  1090.1205, transmix 
processors, transmix blenders, transmix distributors, and pipeline 
operators must keep records that include the information in this 
section.
    (b) Transmix processors and transmix distributors must keep records 
that reflect the results of any sampling and testing required under 
subpart F or M of this part.
    (c) Pipeline operators must keep records that demonstrate 
compliance with the interface handling practices in Sec.  1090.525.
    (d) Transmix processors must keep records showing the volumes of 
TGP recovered from transmix and the type and amount of any blendstock 
or PCG added to make gasoline from TGP under Sec.  1090.510.
    (e) Transmix blenders must keep records showing compliance with the 
quality assurance program and/or sampling and testing requirements in 
Sec.  1090.505, and for each batch of gasoline with which transmix is 
blended, the volume of the batch, and the volume of transmix blended 
into the batch.
    (f) Manufacturers and distributors of 500 ppm LM diesel fuel using 
transmix must keep records of the following information, as applicable:
    (1) Copies of the compliance plan required under Sec.  1090.520(g).
    (2) Documents demonstrating how the party complies with each 
applicable element of the compliance plan under Sec.  1090.520(g).
    (3) Documents and copies of calculations used to determine 
compliance with the 500 ppm LM diesel fuel volume requirements under 
Sec.  1090.520(c).
    (4) Documents or information that demonstrates that the 500 ppm LM 
diesel fuel was only used in locomotive and marine engines that are not 
required to use ULSD under 40 CFR 1033.815 and 40 CFR 1042.660, 
respectively.

Subpart M--Sampling, Testing, and Retention

Sec.  1090.1300   General provisions.

    (a) This subpart is organized as follows:
    (1) Sections 1090.1310 through 1090.1330 specify the scope of 
required testing, including special provisions that apply in several 
unique circumstances.
    (2) Sections 1090.1335 through 1090.1345 specify handling 
procedures for collecting and retaining samples. Sections 1090.1350 
through 1090.1375 specify the procedures for measuring the specified 
parameters. These procedures apply to anyone who performs testing under 
this subpart.
    (3) Section 1090.1390 specifies the requirements for calibrating 
automated detergent blending equipment.
    (4) Section 1090.1395 specifies the procedures for testing related 
to gasoline deposit control test procedure.
    (b) If you need to meet requirements for a quality assurance 
program at some minimum frequency, your first batch of product triggers 
the testing requirement. The specified frequency serves as a deadline 
for performing the required testing, and as a starting point for the 
next testing period. The following examples illustrate the requirements 
for testing based on sampling the more frequent of every 90 days or 
500,000 gallons of certified butane you received from a supplier:
    (1) If your testing period starts on March 1 and you use less than 
500,000 gallons of butane from March 1 through May 29 (90 days), you 
must perform testing under a quality assurance program sometime between 
March 1 and May 29. Your next test period starts with the use of butane 
on May 30 and again ends after 90 days or after you use 500,000 gallons 
of butane, whichever occurs first.
    (2) If your testing period starts on March 1 and you use 500,000 
gallons of butane for the testing period on April 29 (60 days), you 
must perform testing under a quality assurance program sometime between 
March 1 and April 29. Your next testing period starts with the use of 
butane on April 30 and again ends after 90 days or after you use 
500,000 gallons of butane, whichever occurs first.
    (c) Anyone performing tests on behalf of a manufacturer to 
demonstrate compliance with standards or other requirements under this 
part must meet the requirements of this subpart in the same way that 
the manufacturer needs to meet requirements for its own testing.
    (d) Anyone performing tests under this subpart must apply good 
laboratory practices for all sampling, measurement, and calculations 
related to testing required under this part. This requires performing 
these procedures in a way that is consistent with generally accepted 
scientific and engineering principles and properly accounting for all 
available relevant information.
    (e) Subpart P of this part has provisions related to importation, 
including provisions that describe how to meet the sampling and testing 
requirements of this subpart.
    (f) The following general provisions apply:
    (1) A crosscheck program is an arrangement for laboratories to 
perform measurements from test samples prepared from a single 
homogeneous fuel batch to establish an accepted reference value for 
evaluating precision and accuracy. This subpart relies on inter-
laboratory crosscheck programs sponsored by ASTM International or 
another voluntary consensus standards body, or on crosscheck programs 
conducted separately by one or more companies.
    (2) A voluntary consensus standards body (VCSB) is an organization 
that follows consistent protocols to adopt standards reflecting a wide 
range of input from interested parties. ASTM International and the 
International Organization for Standardization are examples of VCSB 
organizations.

Scope of Testing

Sec.  1090.1310   Testing to demonstrate compliance with standards.

    (a) Perform testing as needed to submit the reports specified in 
subpart J of this part. This section specifies additional test 
requirements.
    (b) Fuel manufacturers must perform the following measurements 
before the fuel, fuel additive, or regulated blendstock from a given 
batch leaves the fuel manufacturing facility, except as specified in 
Sec.  1090.1315:

[[Page 29140]]

    (1) Diesel fuel. Perform testing for each batch of ULSD, 500 ppm LM 
diesel fuel, and ECA marine fuel to demonstrate compliance with sulfur 
standards.
    (2) Gasoline. Perform testing for each batch of gasoline to 
demonstrate compliance with sulfur and benzene standards and perform 
testing for each batch of summer gasoline to demonstrate compliance 
with RVP standards.
    (c) The following testing provisions apply for gasoline and 
gasoline regulated blendstock:
    (1) Gasoline manufacturers producing BOB must prepare a hand blend 
as specified in Sec.  1090.1340 and perform the following measurements:
    (i) For Summer CG, measure RVP in the BOB.
    (ii) For Summer RFG, measure RVP in the hand blend.
    (iii) Measure the sulfur content of both the BOB and the hand 
blend.
    (iv) Measure the benzene content of the hand blend.
    (2) Oxygenate producers must measure the sulfur content of each 
batch of oxygenate, except that DFE producers may meet the alternative 
requirements in Sec.  1090.1330.
    (3) Ethanol denaturant producers that certify denaturant under 
Sec.  1090.1330 must measure the sulfur content of each batch of 
denaturant.
    (4) Certified butane and certified pentane producers must perform 
sampling and testing to demonstrate compliance with purity 
specifications and sulfur and benzene standards as specified in Sec.  
1090.1320.
    (5) Transmix processors producing gasoline from TGP must test each 
batch of gasoline for parameters required to demonstrate compliance 
with Sec.  1090.510 as specified in Sec.  1090.1325.
    (d) Blending manufacturers producing gasoline by adding blendstock 
to PCG must comply with Sec.  1090.1320.
    (e) For gasoline produced at a fuel blending facility or a transmix 
processing facility, gasoline manufacturers must measure such gasoline 
for oxygenate and for distillation parameters (i.e., T10, T50, T90, 
final boiling point, and percent residue) in addition to other 
measurements to demonstrate compliance with applicable standards.

Sec.  1090.1315   In-line blending.

    Fuel manufacturers using in-line blending equipment may qualify for 
a waiver from the requirement in Sec.  1090.1310(b) to test every batch 
of fuel before the fuel leaves the fuel manufacturing facility as 
follows:
    (a) The waiver in this section applies if you use or intend to use 
in-line blending equipment to supply fuel directly into a pipeline, 
marine vessel, or other type of distribution that does not involve 
collecting fuel in a tank or other type of storage for creating a batch 
of fuel. It also applies for fuel manufacturers that produce batches of 
fuel that are too large to contain in available storage tanks.
    (b) Waivers granted under 40 CFR part 80 are no longer valid. Any 
party who received an in-line blending waiver granted under 40 CFR part 
80 may continue to operate under the waiver until January 1, 2022. To 
obtain a waiver under this part, submit a request signed by the RCO to 
EPA with the following information:
    (1) Describe the location of your in-line blending operation, how 
long it has been in operation, and how much of each type and grade of 
fuel you have blended over the preceding 3 years (or since starting the 
in-line blending operation if that is less than 3 years). Describe the 
physical layout of the blending operation and how you move the blended 
fuel into distribution. Also describe how your automated system 
monitors and controls blending proportions and the properties of the 
blended fuel. For new installations, describe these as a planned 
operation with projected volumes by type and grade.
    (2) Describe how you collect and test composite fuel samples in a 
way that is equivalent to measuring the fuel properties of a batch of 
blended fuel as specified in this subpart. Your procedures need to 
conform to the sampling specifications in ASTM D4177 and the composite 
calculations in ASTM D5854 (both incorporated by reference in Sec.  
1090.95).
    (3) Describe any expectation or plan for you or another party to 
perform additional downstream testing for the same fuel parameters.
    (4) Describe your quality assurance procedures. Describe any 
experiences from the previous 3 years where these quality assurance 
procedures led you to make corrections to your in-line blending 
operation.
    (5) Describe any times from the previous 3 years that you modified 
fuel after it came out of your blending operation. Describe how you 
modified the fuel and why that was necessary.
    (6) Describe how you will meet the auditing requirements of 
paragraph (c) of this section.
    (c) You must arrange for an audit of your blending operation each 
calendar year that reviews procedures and documents to determine 
whether measured and calculated values properly represent the aggregate 
fuel properties for the blended fuel.
    (d) You must update your in-line blending waiver request 60 days 
prior to making any material change to your in-line blending process.
    (e) If EPA approves your request for a waiver under this section, 
you may need to update your procedures for more effective control and 
documentation of measured fuel parameters based on audit results, 
development of improved practices, or other information.

Sec.  1090.1320   Adding blendstock to PCG.

    The requirements of this section apply for refiners and blending 
manufacturers that add blendstock to PCG to produce a new batch of 
gasoline. Paragraph (c) of this section specifies an alternative 
approach for certified butane and certified pentane blenders. Section 
1090.1325 describes additional provisions that apply to transmix 
processors.
    (a) Sample and test using one of the following methods to exclude 
PCG from the compliance demonstration for sulfur and benzene:
    (1) Compliance by subtraction. (i) Sample and test the sulfur and 
benzene content of each batch of PCG before blending blendstocks to 
produce a new batch of gasoline.
    (ii) Determine the volume of PCG that was blended with blendstock 
to produce a new batch of gasoline. Report the PCG as a negative batch 
as specified in Sec.  1090.905(c)(3)(i).
    (iii) After adding blendstock to PCG, sample and test the sulfur 
and benzene content of the new batch of gasoline.
    (iv) Determine the volume of the new batch of gasoline. Report the 
new batch of gasoline as a positive batch as specified in Sec.  
1090.905(c)(3)(ii).
    (v) Include the PCG batch and the new batch of gasoline in 
compliance calculations as specified in Sec.  1090.700(d)(4)(i).
    (vi) The sample retention requirements in Sec.  1090.1345 apply for 
both the new batch of gasoline and the associated PCG.
    (2) Compliance by addition. (i) Sample and test the sulfur and 
benzene content of each batch of blendstock used to produce a new batch 
of gasoline from PCG.
    (ii) Determine the volume of each batch of blendstock used to 
produce the new batch of gasoline.
    (iii) Report each batch of blendstock as specified in Sec.  
1090.905(c)(4).
    (iv) Include each batch of blendstock in compliance calculations as 
specified in Sec.  1090.700(d)(4)(ii).

[[Page 29141]]

    (v) The sample retention requirements in Sec.  1090.1345 apply for 
the new batch of gasoline and for each blendstock.
    (b) Regardless of the approach used under paragraph (a) of this 
section, fuel manufacturers must determine the volume of each blended 
batch of gasoline, and perform the following measurements for each 
blended batch of gasoline using the procedures specified in Sec.  
1090.1350:
    (1) Measure the sulfur content, benzene content, oxygenate content, 
and for summer gasoline, RVP.
    (2) Determine the following distillation parameters: T10, T50, T90, 
final boiling point, and distillation residue.
    (c) Certified butane or certified pentane blenders that blend 
certified butane or certified pentane into PCG to make a new batch of 
gasoline may comply with the following requirements instead of the 
requirements of paragraphs (a) and (b) of this section:
    (1) For summer gasoline, measure RVP of the blended fuel. The fuel 
manufacturer may rely on sulfur and benzene test results from the 
certified butane or certified pentane producer. Note that Sec.  
1090.245(e) disallows adding certified butane and certified pentane to 
RFG.
    (2) Before blending the certified butane or certified pentane with 
PCG, obtain a copy of the producer's test results indicating that the 
certified butane or certified pentane meets the standards in Sec.  
1090.220 or Sec.  1090.225, respectively.
    (3) The certified pentane blender must enter into a contract with 
the certified pentane producer to verify that the certified pentane 
producer has an adequate quality assurance program to ensure that the 
certified pentane received will not be contaminated in transit.
    (4) The certified butane or certified pentane blender must conduct 
a quality assurance program to demonstrate that the certified butane or 
certified pentane meets the standards specified in Sec.  1090.220 or 
Sec.  1090.225, respectively. The quality assurance program must be 
based on sampling the more frequent of every 90 days or 500,000 gallons 
of certified butane or certified pentane received from each producer. 
The certified butane or certified pentane blender may rely on a third 
party to perform the testing.

Sec.  1090.1325   Adding blendstock to TGP.

    The following provisions apply to transmix processors producing 
gasoline by adding blendstock to TGP:
    (a) Perform testing for each batch of summer gasoline to 
demonstrate compliance with the applicable RVP standard in Sec.  
1090.215.
    (b) Measure the distillation endpoint for gasoline produced from 
TGP as specified in Sec.  1090.1350.
    (c) Determine the volume, sulfur content, and benzene content of 
each blendstock batch used to produce gasoline for reporting and 
compliance calculations by following the sampling and testing 
requirements in Sec.  1090.1320 and treating the TGP used to produce 
the gasoline as PCG.
    (d) Sample and test the gasoline made from TGP and blendstock to 
demonstrate compliance with the sulfur per-gallon standard in Sec.  
1090.205(b) and the applicable RVP standard in Sec.  1090.215.
    (e) Transmix processors producing gasoline by only adding TGP to 
PCG do not have to measure the benzene content of the finished 
gasoline. Such transmix processors also do not have to measure the 
oxygenate content of the finished gasoline if the records for each 
blendstock show no oxygenate content.

Sec.  1090.1330   Preparing denatured fuel ethanol.

    Instead of measuring every batch, DFE producers and importers may 
calculate the sulfur content of a batch of DFE as follows:
    (a) Determine the sulfur content of ethanol before adding 
denaturant by measuring it as specified in Sec.  1090.1310 or by 
estimating it based on your production quality control procedures.
    (b) Use the ppm sulfur content of certified ethanol denaturant 
specified on the PTD for the batch. If the sulfur content is specified 
as a range, use the maximum specified value.
    (c) Calculate the weighted sulfur content of the DFE using the 
values determined under paragraphs (a) and (b) of this section.

Handling and Preparing Samples

Sec.  1090.1335   Collecting and preparing samples for testing.

    (a) General provisions. Use good laboratory practice to collect 
samples to represent the batch you are testing. For example, take steps 
to ensure that a batch is always well mixed before sampling. Also, 
always take steps to prevent sample contamination, such as completely 
flushing sampling taps and piping and pre-rinsing sample containers 
with the product being sampled. Follow the procedures in paragraph (b) 
of this section for manual sampling. Follow the procedures paragraph 
(c) of this section for automatic sampling. Additional requirements for 
measuring RVP are specified in paragraph (d) of this section.
    (b) Manual sampling. Perform manual sampling using one of the 
methods specified in ASTM D4057 (incorporated by reference in Sec.  
1090.95) as follows:
    (1) Use tap sampling or spot sampling to collect upper, middle, and 
lower samples. Adjust spot sampling for partially filled tanks as shown 
in Table 1 or Table 5 of ASTM D4057 as applicable. For tap sampling, 
collect samples that most closely match the recommendations in Table 5 
of ASTM D4057. If you test more than one sample for a given fuel 
parameter, calculate the arithmetic average of the test results to 
represent the batch and use the average result for determining 
compliance with the standards under this part. Each measured sample 
must meet all applicable per-gallon standards. If you test only one 
sample for a given parameter, you must use that test result to 
represent the batch. You may not use the results from a composite 
sample to determine compliance with the standards under this part.
    (2) Collect a ``running'' or ``all-levels'' sample from the top of 
the tank. Drawing a sample from a standpipe is acceptable only if it is 
slotted or perforated to ensure that the drawn sample properly 
represents the whole batch of fuel.
    (3) If the procedures in paragraphs (b)(1) and (2) of this section 
are impractical for a given storage configuration, you may use 
alternative sampling procedures as specified in ASTM D4057. This 
applies primarily for sampling with trucks, railcars, retail stations, 
and other downstream locations.
    (4) Test results with manual sampling are valid only after you 
demonstrate homogeneity as specified in Sec.  1090.1337, except that 
the homogeneity testing requirement does not apply in the following 
cases:
    (i) There is only a single sample using the procedures specified in 
paragraph (b)(1) of this section.
    (ii) Upright cylindrical tanks that have a liquid depth (from the 
tank outlet) less than 10 feet.
    (iii) You draw spot or tap samples as specified in paragraph (b)(1) 
of this section and test each sample for every parameter subject to a 
testing requirement and use the worst-case test result for each 
parameter for purposes of reporting, meeting per-gallon and average 
standards, and all other aspects of compliance.
    (iv) Sampling at a downstream location where it is not possible to 
collect separate samples and you take

[[Page 29142]]

steps to ensure that the batch is well mixed.
    (c) Automatic sampling. Perform automatic sampling as specified in 
ASTM D4177 (incorporated by reference in Sec.  1090.95). Configure the 
system to ensure a well-mixed stream at the sampling point. The default 
sampling frequency should follow the recommended approach of at least 
9,604 samples to represent a batch. EPA may approve a less frequent 
sampling strategy under Sec.  1090.1315(b)(2) if it is appropriate for 
a given facility or for a small-volume batch. Take steps to align the 
start and end of sampling with the start and end of creating the batch.
    (d) Sampling provisions related to measuring RVP of summer 
gasoline. The following additional provisions apply for preparing 
samples to measure RVP of summer gasoline:
    (1) Meet the additional specifications for manual and automatic 
sampling in ASTM D5842 (incorporated by reference in Sec.  1090.95).
    (2) If you measure RVP for multiple test samples to demonstrate 
compliance, do not calculate an average result. Rather, each tested 
sample must meet the applicable RVP standard.
    (3) If you measure other fuel parameters for a given sample in 
addition to RVP testing, always measure RVP first.

Sec.  1090.1337   Demonstrating homogeneity.

    (a) Use the procedures in this section as specified in Sec.  
1090.1335 to determine whether a batch is homogeneous and suitable for 
parameter measurements under this subpart. If the batch is not 
homogeneous, increase mixing or take other appropriate steps and repeat 
the procedure.
    (b) Draw a sample representing different levels of stored fuel, 
fuel additive, or regulated blendstock in the tank as specified in 
Sec.  1090.1335(b)(1).
    (c) For testing to meet the gasoline standards in subpart C of this 
part, demonstrate homogeneity using two of the procedures specified in 
paragraph (c)(1) through (4) of this section. For summer gasoline, the 
homogeneity demonstration must include RVP measurements.
    (1) Measure API gravity from each sample using ASTM D287, ASTM 
D1298, or ASTM D4052 (incorporated by reference in Sec.  1090.95).
    (2) Measure the sulfur content of each sample as specified in this 
subpart.
    (3) Measure the benzene content of each sample as specified in this 
subpart.
    (4) Measure the RVP of each sample as specified in this subpart.
    (d) For testing to meet the diesel fuel standards in subpart D of 
this part, demonstrate homogeneity using one of the procedures 
specified in paragraph (c)(1) or (2) of this section.
    (e) Consider the batch to be homogeneous for a given parameter if 
the measured values for all tested samples vary by less than the 
published repeatability of the test method. If repeatability is a 
function of measured values, calculate repeatability using the average 
value of the measured parameter representing all tested samples. 
Calculate using all meaningful significant figures as specified for the 
test method, even if Sec.  1090.1350(c) describes a different 
precision. For cases that do not require a homogeneity demonstration 
under Sec.  1090.1335(b)(4), the lack of homogeneity demonstration does 
not prevent a quantity of fuel, fuel additive, or regulated blendstock 
from being considered a batch for demonstrating compliance with the 
requirements of this part.

Sec.  1090.1340   Preparing a hand blend from BOB.

    (a) If you produce or import BOB and instruct downstream blenders 
to add oxygenate, you must meet the sampling requirements of this 
subpart by blending oxygenate into a BOB sample to represent the final 
blended fuel. To do this, prepare each fuel sample by adding oxygenate 
to the BOB sample in a way that corresponds to your instructions to 
downstream blenders for the sampled batch of fuel. Prepare a hand blend 
representing a worst case for oxygenate as follows:
    (1) Take steps to avoid introducing high or low bias in sulfur 
content when selecting from available samples to create the hand blend. 
For example, if there are three samples with discrete sulfur 
measurements, select the sample with the mid-range sulfur content. In 
other cases, randomly select the sample.
    (2) If your instructions allow for downstream blenders to add more 
than one type or concentration of oxygenate, prepare a hand blend for 
summer gasoline intended for blending with ethanol using the lowest 
specified ethanol blend. For summer gasoline intended for blending only 
with oxygenate other than ethanol, and for all winter gasoline, blend 
at the lowest specified oxygenate concentration, regardless of the type 
of oxygenate. For example, if you give instructions for a given batch 
of BOB to perform downstream blending to make E10, E15, and an 8 
percent blend with butanol, prepare a hand blend for testing winter 
gasoline with 8 percent butanol, and prepare an E10 hand blend for 
testing summer gasoline.
    (b) Blend the fuel using the procedures specified in ASTM D7717 
(incorporated by reference in Sec.  1090.95). The blended fuel must 
have an amount of oxygenate that does not exceed the oxygenate 
concentration specified on the PTD for the BOB under Sec.  
1090.1160(b)(1).
    (c) If you produce or import BOB and you blend in oxygenate before 
selling or transporting the fuel, you must instead draw samples from 
your blended fuel.

Sec.  1090.1345  Retaining samples.

    (a) Fuel manufacturers, regulated blendstock producers, and 
independent surveyors must retain samples of fuel and oxygenate tested 
under this subpart as follows:
    (1) If you test gasoline, diesel fuel, or oxygenate to measure any 
parameter as required under this subpart, you must keep a 
representative fuel sample for at least 30 days after testing is 
complete, except that a longer sample retention of 120 days applies for 
blending manufacturers that produce gasoline.
    (2) The nominal volume of retained samples must be at least 330 ml. 
If you have only a single sample for testing, keep that sample after 
testing is complete. If you collect multiple samples from a single 
batch or you create a hand blend, select a representative sample as 
follows:
    (i) If you test a hand blend under Sec.  1090.1340, keep a sample 
of the BOB.
    (ii) For summer gasoline, keep an untested (or less tested) sample 
that is most like the tested sample, as applicable. In all other cases, 
keep the tested (or most tested) sample.
    (b) Oxygenate producers and importers must keep oxygenate samples 
as follows:
    (1) Keep a representative sample of any tested oxygenate. Also keep 
a representative sample of DFE if you used the provisions of Sec.  
1090.1330 to calculate its sulfur content. The nominal volume of 
retained samples must be at least 330 ml.
    (2) Keep all the samples you collect over the previous 21 days. If 
you have fewer than 20 samples from the previous 21 days, continue 
keeping the most recent 20 samples collected up to a maximum of 90 days 
for any given sample.
    (c) Keep records of all calculations, test results, and test 
methods for the batch associated with each stored sample.
    (d) If EPA requests a test sample, you must follow EPA's 
instructions and send it to EPA by a courier service (or equivalent). 
The instructions will describe where and when to send the sample. For 
each test sample, you must

[[Page 29143]]

identify the test results and test methods used.
    (e) You are responsible for meeting the requirements of this 
section even if a third party performs testing and stores the fuel 
samples for you.

Measurement Procedures

Sec.  1090.1350  Overview of test procedures.

    Fuel manufacturers meet the requirements of this subpart based on 
laboratory measurements of the specified fuel parameters. Test 
procedures for these measurements apply as follows:
    (a) Except as specified in paragraph (b) of this section, the 
Performance-based Measurement System specified in Sec. Sec.  1090.1360 
through 1090.1375 applies for all testing specified in this subpart for 
the following fuels and fuel parameters:
    (1) Sulfur content of diesel fuel.
    (2) Sulfur content of ECA marine fuel.
    (3) RVP, sulfur content, benzene content, and oxygenate content of 
gasoline. The procedures for measuring sulfur in gasoline in this 
subpart also apply for testing sulfur in certified ethanol denaturant; 
however, demonstrating compliance for alternative procedures in Sec.  
1090.1365 and statistical quality control in Sec.  1090.1375 do not 
apply for sulfur concentration above 80 ppm.
    (4) Sulfur content of butane.
    (b) Specific test procedures apply for measuring other fuel 
parameters, as follows:
    (1) Determine the cetane index of diesel fuel as specified in ASTM 
D976 or ASTM D4737 (incorporated by reference in Sec.  1090.95). There 
is no cetane-related test requirement for biodiesel.
    (2) Measure aromatic content of diesel fuel as specified in ASTM 
D1319 or ASTM D5186 (incorporated by reference in Sec.  1090.95). You 
may use an alternative procedure if you correlate your test results 
with ASTM D1319 or ASTM D5186.
    (3) Measure the purity of butane and pentane as specified in ASTM 
D2163 (incorporated by reference in Sec.  1090.95).
    (4) Measure the benzene content of butane and pentane as specified 
in ASTM D5134 (incorporated by reference in Sec.  1090.95).
    (5) Measure the sulfur content of pentane as specified in ASTM 
D6667 (incorporated by reference in Sec.  1090.95).
    (6) Measure distillation parameters of gasoline as specified in 
ASTM D86 (incorporated by reference in Sec.  1090.95). You may use an 
alternative procedure if you correlate your test results with ASTM D86.
    (7) Measure the sulfur content of neat ethanol as specified in ASTM 
D5453 (incorporated by reference in Sec.  1090.95). You may use an 
alternative procedure if you correlate your test results with ASTM 
D5453.
    (8) Measure the phosphorus content of gasoline as specified in ASTM 
D3231 (incorporated by reference in Sec.  1090.95).
    (9) Measure the lead content of gasoline as specified in ASTM D3237 
(incorporated by reference in Sec.  1090.95).
    (10) Measure the sulfur content of gasoline additives and diesel 
fuel additives as specified in ASTM D2622 (incorporated by reference in 
Sec.  1090.95).
    (11) Use referee procedures specified in Sec.  1090.1360(d) and the 
following additional methods to measure gasoline fuel parameters to 
meet the survey requirements of subpart N of this part:

                      Table 1 to Paragraph (b)(11)
------------------------------------------------------------------------
        Fuel parameter                Units           Test method \1\
------------------------------------------------------------------------
Distillation (T50 and T90)....  [deg]C...........  ASTM D86.
Aromatic content..............  volume percent...  ASTM D5769.
Olefin content................  volume percent...  ASTM D6550.
------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec.   1090.95.

    (12) Updated versions of the test procedures specified in this 
section are acceptable as alternative procedures if both repeatability 
and reproducibility are at least as precise as the values specified in 
the earlier version.
    (c) Record measured values with the following precision, with 
rounding in accordance with Sec.  1090.50:
    (1) Record sulfur content to the nearest whole ppm.
    (2) Record benzene to the nearest 0.01 volume percent.
    (3) Record RVP to the nearest 0.01 psi.
    (4) Record oxygenate content to the nearest 0.01 mass percent for 
each calibrated oxygenate.
    (5) Record diesel aromatic content to the nearest 0.1 volume 
percent, or record cetane index to the nearest whole number.
    (6) Record gasoline aromatic and olefin content to the nearest 0.1 
volume percent.
    (7) Record distillation parameters to the nearest whole degree.
    (d) For any measurement or calculation that depends on the volume 
of the test sample, correct the volume of the sample to a reference 
temperature of 15.5 [deg]C (288.65 K). Use a correction equation that 
is appropriate for each tested compound. This applies for all fuels, 
blendstocks, and additives, except butane.

Sec.  1090.1355  Calculation adjustments and corrections.

    Adjust measured values for special circumstances as follows:

    (a) Adjust measured values for total vapor pressure as follows:
RVP (psi) = 0.956  Ptotal - 0.347

Where:

Ptotal = Measured total vapor pressure, in psi.

    (b) For measuring the sulfur and benzene content of gasoline, 
adjust a given test result upward in certain circumstances, as follows:
    (1) If your measurement method involves a published procedure with 
a Pooled Limit of Quantitation (PLOQ), treat the PLOQ as your final 
result if your measured result is below the PLOQ.
    (2) If your measurement method involves a published procedure with 
a limited scope but no PLOQ, treat the lower bound of the scope as your 
final result if your measured result is less than that value.
    (3) If you establish a Laboratory Limit of Quantitation (LLOQ) 
below the lower bound of the scope of the procedure as specified in 
ASTM D6259 (incorporated by reference in Sec.  1090.95), treat the LLOQ 
as your final result if your measured result is less than the LLOQ. 
Note that this option is meaningful only if the LLOQ is less than a 
published PLOQ, or if there is no published PLOQ.
    (c) For measuring the benzene content of butane and pentane, report 
a zero value if the test result is at or below the PLOQ or Limit of 
Detection (LOD) that applies for the test method.
    (d) If measured content of any oxygenate compound is less than 0.1 
percent by mass, record the result as ``None detected.''

[[Page 29144]]

Sec.  1090.1360  Performance-based Measurement System.

    (a) The Performance-based Measurement System (PBMS) is an approach 
that allows for laboratory testing with any procedure that meets 
specified performance criteria. This subpart specifies the performance 
criteria for measuring certain fuel parameters to demonstrate 
compliance with the standards and other specifications of this part. 
These provisions do not apply to process stream analyzers used with in-
line blending.
    (b) Different requirements apply for absolute fuel parameters and 
method-defined fuel parameters.
    (1) Absolute fuel parameters are those for which it is possible to 
evaluate measurement accuracy by comparing measured values of a test 
sample to a reference sample with a known value for the measured 
parameter. The following are absolute fuel parameters:
    (i) Sulfur. This applies for measuring sulfur in any fuel, fuel 
additive, or regulated blendstock.
    (ii) [Reserved]
    (2) Method-defined fuel parameters are all those that are not 
absolute fuel parameters. Additional test provisions apply for method-
defined fuel parameters under this section because there is no 
reference sample for evaluating measurement accuracy.
    (c) The performance criteria of this section apply as follows:
    (1) Section 1090.1365 specifies the initial qualifying criteria for 
all measurement procedures. You may use an alternative procedure only 
if testing shows that you meet the initial qualifying criteria
    (2) Section 1090.1375 specifies ongoing quality testing 
requirements that apply for laboratories that use either referee 
procedures or alternative procedures.
    (3) Streamlined requirements for alternative procedures apply for 
procedures adopted by a voluntary consensus standards body (VCSB). 
Compliance testing with non-VCSB procedures requires advance approval 
by EPA. Procedures are considered non-VCSB testing as follows:
    (i) Procedures developed by individual companies or other parties 
are considered non-VCSB procedures.
    (ii) Draft procedures under development by a VCSB organization are 
considered non-VCSB procedures until they are approved for publication.
    (iii) A published procedure is considered non-VCSB for testing with 
fuel parameters that fall outside the range of values covered in the 
research report of the ASTM D6708 (incorporated by reference in Sec.  
1090.95) assessment comparing candidate alternative procedures to the 
referee procedure specified in paragraph (d) of this section.
    (4) You may qualify updated versions of the referee procedures as 
alternative procedures under Sec.  1090.1365. You may ask EPA for 
approval to use an updated version of the referee procedure for 
qualifying other alternative procedures if the updated referee 
procedure has the same or better accuracy and precision compared to the 
version specified in Sec.  1090.95. If the updated procedure has worse 
accuracy and precision compared to the earlier version, you must 
complete the required testing specified in Sec.  1090.1365 using the 
older, referenced version of the referee procedure.
    (5) Any laboratory may use the specified referee procedure without 
qualification testing. To use alternative procedures at a given 
facility, you must perform the specified testing to demonstrate 
compliance with precision and accuracy requirements, with the following 
exceptions:
    (i) Testing you performed to qualify alternative procedures under 
40 CFR part 80 continues to be valid for making the demonstrations 
required in this part.
    (ii) Qualification testing is not required for laboratories that 
measure the benzene content of gasoline using Procedure B of ASTM D3606 
(incorporated by reference in Sec.  1090.95). However, qualification 
testing may be necessary for updated versions of this procedure as 
specified in Sec.  1090.1365(a)(2).
    (d) Referee procedures are presumed to meet the initial qualifying 
criteria in this section. You may use alternative procedures if you 
qualify them using the referee procedures as a benchmark as specified 
in Sec.  1090.1365. The following are the referee procedures:

                        Table 1 to Paragraph (d)
------------------------------------------------------------------------
                                                       Referee procedure
         Tested product                Parameter              \1\
------------------------------------------------------------------------
ULSD, 500 ppm diesel fuel, ECA    Sulfur............  ASTM D2622.
 marine fuel, gasoline.
Butane..........................  Sulfur............  ASTM D6667.
Gasoline........................  oxygenate content.  ASTM D5599.
Gasoline........................  RVP...............  ASTM D5191, except
                                                       as specified in
                                                       Sec.
                                                       1090.1355(a).
Gasoline........................  benzene...........  ASTM D5769.
------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec.   1090.95.

Sec.  1090.1365  Qualifying criteria for alternative measurement 
procedures.

    This section specifies how to qualify alternative procedures for 
measuring absolute and method-defined fuel parameters under the 
Performance-based Analytical Test Method specified in Sec.  1090.1360.
    (a) The following general provisions apply for qualifying 
alternative procedures:
    (1) Alternative procedures must have appropriate precision to allow 
for reporting to the number of decimal places specified in Sec.  
1090.1350(c).
    (2) Testing to qualify an alternative procedure applies for the 
specified version of the procedure you use for making the necessary 
measurements. Once an alternative procedure for a method-defined fuel 
parameter is qualified for your laboratory, updated versions of that 
same procedure are qualified without further testing, as long as the 
procedure's specified reproducibility is the same as or better than the 
values specified in the earlier version. For absolute fuel parameters, 
updated versions are qualified without testing if both repeatability 
and reproducibility are the same as or better than the values specified 
in the earlier version.
    (3) Except as specified in paragraph (d) of this section, testing 
to demonstrate compliance with the precision and accuracy 
specifications in this section apply only for the test facility where 
the testing occurred.
    (4) If a procedure for measuring benzene or sulfur in gasoline has 
no specified PLOQ and no specified scope with a lower bound, you must 
establish a LLOQ for your facility.

[[Page 29145]]

    (5) Testing for method-defined fuel parameters must take place at a 
reference installation as specified in Sec.  1090.1370.
    (b) All alternative procedures must meet precision criteria based 
on a calculated maximum allowable standard deviation for a given fuel 
parameter as specified in this paragraph. The precision criteria apply 
for measuring the parameters and fuels specified in paragraph (b)(3) of 
this section. Take the following steps to qualify the measurement 
procedure for measuring a given fuel parameter:
    (1) The fuel must meet the parameter specifications in Table 1 to 
paragraph (b)(3) of this section. This may require that you modify the 
fuel you typically produce to be within the specified range. Absent a 
specification (maximum or minimum), select a fuel representing values 
that are typical for your testing. Store and mix the fuel to maintain a 
homogenous mixture throughout the measurement period to ensure that 
each fuel sample drawn from the batch has the same properties.
    (2) Measure the fuel parameter from a homogeneous fuel batch at 
least 20 times. Record each result in sequence. Do not omit any valid 
results unless you use good engineering judgment to determine that the 
omission is necessary and you document those results and the reason for 
excluding them. Perform this analysis over a 20-day period. You may 
make up to 4 separate measurements in a 24-hour period, as long as the 
interval between measurements is at least 4 hours. Do not measure RVP 
more than once from a single sample.
    (3) Calculate the maximum allowable standard deviation as follows:
    [GRAPHIC] [TIFF OMITTED] TP14MY20.022
    
Where:

[sigma]max = Maximum allowable standard deviation.
x1, x2, and x3 have the values from 
the following table:

                                  Table 1 to Paragraph (b)(3)--Precision Criteria for Qualifying Alternative Procedures
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                  x2 =
                                                                              Repeatability            Fixed  values
    Fuel, fuel additive, or      Fuel  parameter        Range         x1         (r) or         x3     of [sigma]max              Source \2\
     regulated blendstock                                                    reproducibility
                                                                                 (R) \1\
--------------------------------------------------------------------------------------------------------------------------------------------------------
ULSD..........................  Sulfur..........  5 ppm minimum...     1.5  r=1.33..........    2.77          0.72    ASTM D3120-08 (2019).
500 ppm LM diesel fuel........  Sulfur..........  350 ppm minimum.     1.5  r=21.3..........    2.77          11.5    ASTM D2622-16.
ECA marine fuel...............  Sulfur..........  700 ppm minimum.     1.5  37.1............    2.77          20.1    ASTM D2622-16.
Butane........................  Sulfur..........  ................     1.5  r =                 2.77  ..............  ASTM D6667-14 (2019).
                                                                             0.1152[middot]x.
Gasoline......................  Sulfur..........  ................     1.5  r =                 2.77  ..............  ASTM D7039-15a.
                                                                             0.4998[middot]x
                                                                             0.54.
Gasoline......................  oxygenate.......  ................     0.3  R =                    1  ..............  ASTM D5599-18.
                                                                             0.13[middot]x0.
                                                                             83.
Gasoline......................  RVP \3\.........  ................     0.3  R=0.40..........       1          0.12    ASTM D5191-19.
Gasoline......................  Benzene.........  ................    0.15  R=0.221[middot]x       1  ..............  ASTM D5769-15.
                                                                             0.67.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Calculate repeatability and reproducibility using the average value determined from testing. Use units as specified in Sec.   1090.1350(c).
\2\ ASTM publications are incorporated by reference in Sec.   1090.95. Note that the listed procedure may be different than the referee procedure
  identified in Sec.   1090.1360(d), or it may be an older version of the referee procedure.
\3\ Use only 1-liter containers for testing to qualify alternative methods.

    (c) Alternative VCSB procedures for measuring absolute fuel 
parameters (sulfur) must meet accuracy criteria based on the following 
measurement procedure:
    (1) Obtain gravimetric sulfur standards to serve as representative 
reference samples. The samples must have known sulfur content within 
the ranges specified in paragraph (c)(3) of this section. The known 
sulfur content is the accepted reference value (ARV) for the fuel 
sample.
    (2) Measure the sulfur content of the fuel sample at your 
laboratory at least 10 times, without interruption. Use good laboratory 
practice to compensate for any known chemical interferences; however, 
you must apply that same compensation for all tests to measure the 
sulfur content of a test fuel. Calculate the arithmetic average of all 
the measured values, including any compensation.
    (3) The measurement procedure meets the accuracy requirement as 
follows:
    (i) Demonstrate accuracy for measuring sulfur in gasoline, gasoline 
regulated blendstock, and gasoline additive using test fuels to 
represent sulfur values from 1 to 10 ppm, 11 to 20 ppm, and 21 to 95 
ppm. You may omit any of these ranges if you do not perform testing 
with fuel in that range. Calculate the maximum allowable difference 
between the average measured value and ARV for each applicable range as 
follows:

[Delta]max = 0.75[middot] [sigma]max

Where:

[Delta]max = Maximum allowable difference.
[sigma]max = the maximum allowable standard deviation 
from paragraph (b)(3) of this section using the sulfur content 
represented by ARV.

    (ii) Demonstrate accuracy for measuring sulfur in diesel fuel using 
test fuels meeting the specifications in Table 2 to this section. For 
testing diesel-related blendstocks and additives, use representative 
test samples meeting the appropriate sulfur specification. Table 2 to 
paragraph (c)(3)(ii) of this section also identifies the maximum 
allowable difference between average measured values and ARV 
corresponding to ARV at the upper end of the specified ranges. These 
values are based on calculations with the equation in paragraph 
(c)(3)(i) of this section, with parameter values set to be equal to the 
standard.

    Table 2 to Paragraph (c)(3)(ii)--Accuracy Criteria for Qualifying
 Alternative Procedures with Diesel Fuel and Diesel-Related Blendstocks
                              and Additives
------------------------------------------------------------------------
                                                     Illustrated maximum
            Fuel              Sulfur content (ppm)        allowable
                                                         differences
------------------------------------------------------------------------
ULSD........................  10-20...............                  0.54
500 ppm LM diesel fuel......  450-500.............                  8.65
ECA marine fuel.............  900-1,000...........                  15.1
------------------------------------------------------------------------

[[Page 29146]]

    (d) Alternative VCSB procedures for measuring method-defined fuel 
parameters must meet accuracy criteria as follows:
    (1) You may use the alternative procedure only if you follow all 
the statistical protocols and meet all the criteria specified in 
Section 6 of ASTM D6708 (incorporated by reference in Sec.  1090.95) 
when comparing your measurements using the alternative procedure to 
measurements at a reference installation using the appropriate referee 
test method identified in Sec.  1090.1360(d).
    (2) For qualifying alternative procedures, determine whether the 
alternative procedure needs a correlation equation to correct bias 
relative to the reference test method. Create such a correlation 
equation as specified in Section 7 of ASTM D6708. For all testing, 
apply the correlation equation to adjust measured values to be 
statistically consistent to measuring with the reference test method.
    (3) If an alternative VCSB procedure states that the procedure has 
a successful assessment relative to the referee procedures in this 
section under ASTM D6708, that finding applies for all test facilities 
using that procedure.
    (e) Alternative non-VCSB procedures for measuring absolute fuel 
parameters (sulfur) must meet accuracy criteria as follows:
    (1) Demonstrate whether the procedure meets statistical criteria 
and whether it needs a correlation equation as specified in paragraphs 
(d)(1) and (2) of this section. Apply the correlation equation for all 
testing with the alternative procedure.
    (2) Demonstrate at your laboratory that the alternative procedure 
meets the accuracy criteria specified in paragraph (c) of this section.
    (3) Send EPA a written request to use the alternative procedure. In 
your request, fully describe the procedure to show how it functions for 
achieving accurate measurements and include detailed information 
related to your assessment under paragraph (d)(1) and (2) of this 
section.
    (f) Alternative non-VCSB procedures for measuring method-defined 
fuel parameters must meet accuracy and precision criteria as follows:
    (1) Demonstrate whether the procedure meets statistical criteria 
and whether it needs a correlation equation as specified in paragraphs 
(d)(1) and (2) of this section. Apply the correlation equation for all 
testing with the alternative procedure.
    (2) Test with a range of fuels that are typical of those you will 
analyze at your laboratory. Use either consensus-named fuels or 
locally-named reference materials. Consensus-named fuels are 
homogeneous fuel quantities sent around to different laboratories for 
analysis, which results in a ``consensus name'' representing the 
average value of the parameter for all participating laboratories. 
Locally named reference materials are fuel samples analyzed using the 
reference test method, either at your laboratory or at a reference 
installation, to establish an estimated value for the fuel parameter; 
locally named reference materials usually come from the fuel you 
produce.
    (3) You may qualify your procedure as meeting the variability 
requirements of paragraph (f)(1) of this section only for a narrower, 
defined range of fuels. If this is the case, identify the appropriate 
range of fuels in your request for approval and describe how you will 
screen fuel samples accordingly.
    (4) Qualify the precision of the alternative procedure by comparing 
results to testing with the referee procedure based on ``between 
methods reproducibility,'' Rxy, as specified in ASTM D6708. The Rxy 
must be at or below 75 percent of the reproducibility of the referee 
procedure from Sec.  1090.1360(d).
    (5) Perform testing at your laboratory as specified in paragraph 
(b) of this section to establish the repeatability of the alternative 
procedure. The repeatability must be as good as or better than that 
specified in paragraph (b)(3) of this section.
    (6) Fully describe the procedure to show how it functions for 
achieving accurate measurements. Describe the technology, test 
instruments, and testing method so a competent person lacking 
experience with the procedure and test instruments would be able to 
replicate the results.
    (7) Engage a third-party auditor to review and verify your 
information as follows:
    (i) The auditor must qualify as an independent third party and meet 
the specifications for technical ability as specified in Sec.  1090.55.
    (ii) The auditor must send you a report describing their inspection 
of your facilities and their review of the information supporting your 
request to use the alternative procedure. The report must describe how 
the auditor performed the review, identify any errors or discrepancies, 
and state whether the information supports a conclusion that the 
alternative procedure should be approved.
    (iii) The auditor must keep records related to the review for at 
least 5 years after sending you the report and provide those records to 
EPA upon request.
    (8) Send EPA a written request to use the alternative procedure. 
Include the specified information and any additional information EPA 
needs to evaluate your request.
    (g) Keep fuel samples from any qualification testing under this 
section for at least 180 days after you have taken all steps to qualify 
an alternative procedure under this section. This applies for testing 
at your laboratory and at any reference installation you use for 
demonstrating the accuracy of an alternative procedure.

Sec.  1090.1370   Qualifying criteria for reference installations.

    (a) A reference installation refers to a test facility that uses 
the referee test method specified in Sec.  1090.1360(d) to evaluate the 
accuracy of alternative procedures for method-defined parameters, by 
comparing measured values to companion tests using one of the referee 
procedures in Sec.  1090.1360(d). This evaluation may result in an 
equation to correlate results between the two procedures. Once a 
facility qualifies as a reference installation, that qualification is 
valid for five years from the qualifying date, consistent with good 
laboratory practices.
    (b) Qualify a reference installation for VCSB procedures by 
participating in an interlaboratory crosscheck program with at least 16 
separate measurements that are not identified as outliers. This 
presumes that the results for the candidate reference installation are 
not outliers.
    (c) Qualify a reference installation for non-VCSB procedures based 
on the following measurement protocol:
    (1) Use the precision testing procedure specified in Sec.  
1090.1365(b) to show that your standard deviation for tests using the 
reference test method is at or below 0.3 times the reproducibility for 
a given fuel parameter.
    (2) You must correlate your test results for a given fuel parameter 
against the accepted reference values from a monthly crosscheck program 
based on Section 6.2.2.1 and Note 7 of ASTM D6299 (incorporated by 
reference in Sec.  1090.95) as follows:
    (i) If there are multiple fuels available from the crosscheck 
program, select the fuel that has the closest value to the standard. If 
there is no standard for a given fuel parameter, select the fuel with 
values for the fuel parameter that best represent typical values for 
fuels you test.
    (ii) Measure the fuel parameter for the crosscheck fuel at your 
facility using the appropriate referee procedure. Calculate

[[Page 29147]]

a mean value that includes all your repeat measurements.
    (iii) Determine the mean value from the crosscheck program and 
calculate the difference between this value and the mean value from 
your testing. Express this difference as a certain number of standard 
deviations relative to the data set from the crosscheck program.
    (iv) The calculated monthly difference between the mean values from 
Sec.  1090.1365(c)(3)(ii) for 5 consecutive months must fall within the 
central 50 percent of the distribution of data at least 3 times. The 
central 50 percent of the distribution corresponds to 0.68 standard 
deviations.
    (v) Calculate the mean value of the differences from Sec.  
1090.1365(c)(3)(ii) for all 5 months. This mean value must fall within 
the central 50 percent of the distribution of data from the crosscheck 
program. For example, if the difference was 0.5 standard deviations for 
two months, 0.6 for one month, and 0.7 for two months, the mean value 
of the difference is 0.6 standards deviations, and the reference 
installation meets the requirements of this paragraph.
    (3) You must demonstrate that the reference installation is in 
statistical quality control for at least 5 months with the designated 
procedure as specified in ASTM D6299 (incorporated by reference in 
Sec.  1090.95). If at any point the reference installation is not in 
statistical quality control, you must make any necessary changes and 
restart testing toward meeting the requirement to achieve statistical 
quality control for at least 5 months, except as follows:
    (i) Do not consider measurements you perform as part of regular 
maintenance or recalibration for evaluating statistical quality 
control.
    (ii) If you find that the reference installation is not in 
statistical quality control during an initial 5-month period and you 
are able to identify the problem and make the necessary changes to 
again achieve statistical quality control before the end of the 5-month 
demonstration period, you may consider the reference installation as 
meeting the requirement to be in statistical quality control for at 
least 5 months.

Sec.  1090.1375  Quality control procedures.

    This section specifies ongoing quality testing requirements as part 
of the Performance-based Measurement System specified in Sec.  
1090.1360.
    (a) General provisions. You must perform testing to show that your 
test facility meets specified precision and accuracy criteria as 
follows:
    (1) The testing requirement applies for the referee procedures in 
Sec.  1090.1360(d) and for alternate procedures that are qualified or 
approved under Sec.  1090.1365. The testing requirements apply 
separately for each test instrument at each test facility.
    (2) If you fail to conduct specified testing, your test facility is 
not qualified for measuring fuel parameters to demonstrate compliance 
with the standards and other specifications of this part until you 
perform this testing. Similarly, if your test facility fails to meet 
the specified criteria, it is not qualified for measuring fuel 
parameters to demonstrate compliance with the standards and other 
specifications of this part until you make the necessary changes to 
your test facility and perform testing to show that the test facility 
again meets the specified criteria.
    (3) If you perform major maintenance such as overhauling an 
instrument, confirm that the instrument still meets precision and 
accuracy criteria before you start testing again based on the 
procedures specified in ASTM D6299 (incorporated by reference in Sec.  
1090.95).
    (4) Keep records to document your testing under this section for 5 
years.
    (b) Precision demonstration. Show that you meet precision criteria 
as follows:
    (1) Meeting the precision criteria of this paragraph (b) qualifies 
your test facility for performing up to 20 production tests or 7 days, 
whichever is less.
    (2) Perform precision testing using the control-chart procedures in 
ASTM D6299. If you opt to use the Q-procedure, validate the first run 
on the new QC batch by either an overlap in-control result of the old 
batch, or by a single execution of an accompanying standard reference 
material. The new QC material result would be considered validated if 
the single result of the standard reference material is within the 
established site precision (R') of the ARV of the standard reference 
material, as determined by ASTM D6792 (incorporated by reference in 
Sec.  1090.95).
    (3) Use I charts and MR charts as specified in ASTM D6299 to show 
that the long-term standard deviation for the test facility meets the 
precision criteria specified in Sec.  1090.1365(b).
    (c) Accuracy demonstration. For absolute fuel parameters (VCSB and 
non-VCSB) and for method-defined fuel parameters using non-VCSB 
methods, you must show that you meet accuracy criteria as specified in 
this paragraph. For method-defined VCSB procedures, you may meet 
accuracy requirements as specified in this paragraph or by comparing 
your results to the accepted reference value in an inter-laboratory 
crosscheck program sponsored by ASTM International or another VCSB at 
least 3 times per year.
    (1) Meeting the accuracy criteria of this paragraph (c) qualifies 
your test facility for 130 days.
    (2) Except as specified in paragraph (c)(3) of this section, test 
every instrument using a check standard meeting the specifications of 
ASTM D6299. Select a fuel sample with an ARV that is at or slightly 
below the standard that applies. If there are both average and batch 
standards, use the average standard. If there is no standard, select a 
fuel sample representing fuel that is typical for your testing.
    (3) The following provisions apply for method-defined non-VCSB 
alternative procedures with high sensitivity to sample-specific bias:
    (i) Procedures have high sensitivity if the closeness sum of 
squares (CSS) statistic exceeds the 95th percentile value, as specified 
in ASTM D6708 (incorporated by reference in Sec.  1090.95).
    (ii) Create a check standard from production fuel representing the 
fuel you will routinely analyze. Determine the ARV of your check 
standard using the protocol in ASTM D6299 at a reference installation 
as specified in Sec.  1090.1370.
    (iii) You must send EPA a fuel sample from every twentieth batch of 
gasoline or diesel fuel and identify the procedures and corresponding 
test results from your testing. EPA may return one of your samples to 
you for further testing; if this occurs, you must repeat your 
measurement and report your results within 180 days of receiving the 
fuel sample.
    (4) You meet accuracy requirements under this section if the 
difference between your measured value for the check standard and the 
ARV is less than the value from the following equation:
[GRAPHIC] [TIFF OMITTED] TP14MY20.023

Where:

[Delta]max = Maximum allowable difference.
R = Reproducibility of the referee procedure identified in Sec.  
1090.1360(d), as noted in Table 1 to paragraph (b)(3) of Sec.  
1090.1365 or in the following table:

[[Page 29148]]

                                           Table 1 to Paragraph (c)(3)
----------------------------------------------------------------------------------------------------------------
             Tested product                     Referee  procedure \1\             Reproducibility  (R) \2\
----------------------------------------------------------------------------------------------------------------
ULSD, 500 ppm diesel fuel, ECA marine    ASTM D2622.........................  R= 0.4273[middot]x 0.8015
 fuel, diesel fuel additive, gasoline,
 gasoline regulated blendstock, and
 gasoline additive.
Butane.................................  ASTM D6667.........................  R= 0.3130[middot]x
----------------------------------------------------------------------------------------------------------------
\1\ ASTM specifications are incorporated by reference in Sec.   1090.95.
\2\ Calculate reproducibility using the average value determined from testing. Use units as specified in Sec.
  1090.1350(c).

L = the total number of test results used to determine the ARV of a 
consensus-named fuel. For testing locally named fuels for which no 
consensus-based ARV applies, use L = [infin].

Testing Related to Gasoline Deposit Control

Sec.  1090.1390  Requirement for Automated Detergent Blending Equipment 
Calibration.

    (a) Automated detergent blending facilities must calibrate their 
automated detergent blending equipment once in each calendar half-year, 
with the acceptable calibrations being no less than 120 days apart.
    (b) Equipment recalibration is also required each time the 
detergent package is changed, unless written documentation indicates 
that the new detergent package has the same viscosity as the previous 
detergent package. Calibrating after changing the detergent package may 
be used to satisfy the semiannual recalibration requirement in 
paragraph (a) of this section, provided that the calibrations occur in 
the appropriate calendar half-year and are no less than 120 days apart.

Sec.  1090.1395  Gasoline deposit control test procedures.

    Gasoline detergent manufacturers must perform testing as specified 
in paragraph (a), (b), or (c) of this section to establish the lowest 
additive concentration (LAC) for the detergent.
    (a) Top Tier-Based Test Method. Use the procedures specified in 
ASTM D6201 (incorporated by reference in Sec.  1090.95), as follows:
    (1) Use a base fuel that conforms to the specifications for 
gasoline-alcohol blends in ASTM D4814 (incorporated by reference in 
Sec.  1090.95). Blendstocks used to formulate the test fuel must be 
derived from conversion units downstream of distillation, with all 
processes representing normal fuel manufacturing facility operations. 
Blendstocks may not come from chemical grade streams. Butane and 
pentane may be added to adjust vapor pressure. The base fuel should 
include any nondetergent additives typical of commercially available 
fuel if they may positively or negatively affect deposit formation. In 
addition, the base fuel must have the following properties:
    (i) 8.0-10.0 Volume percent DFE that meets the requirements in 
Sec.  1090.230 and conforms to the specifications of ASTM D4806 
(incorporated by reference in Sec.  1090.95).
    (ii) At least 8.0 volume percent olefins.
    (iii) At least 15 volume percent aromatics.
    (iv) No more than 80 ppm sulfur.
    (v) T90 distillation temperature at or above 143 [deg]C.
    (vi) No detergent-active substance. A base fuel with typical 
nondetergent additives, such as antioxidants, corrosion inhibitors, and 
metal deactivators, may be used.
    (2) Perform the 100-hour test for intake valve deposits with the 
base fuel to demonstrate that the intake valves accumulate at least 500 
mg on average. If the test engine fails to accumulate enough deposits, 
make any necessary adjustments and repeat the test. This demonstration 
is valid for any further detergent testing with the same base fuel.
    (3) Repeat the test on the same engine with a specific 
concentration of detergent added to the base fuel. If the test results 
in less than 50 mg average per intake valve, the tested detergent 
concentration is the LAC for the detergent.
    (b) CARB-Based Test Method. Use the procedures specified by CARB in 
Title 13, California Code of Regulations, section 2257.
    (1) A detergent tested under this option or certified under 40 CFR 
80.163(d) prior to January 21, 2021, may be used at the LAC specified 
for use in the state of California in any gasoline in the United 
States.
    (2) The gasoline detergent manufacturer must cease selling a 
detergent immediately upon being notified by CARB that the CARB 
certification for this detergent has been invalidated and must notify 
EPA under 40 CFR 79.21.
    (c) Alternative test methods. (1) An EPA-approved alternative test 
method may be used if the alternative test method can be correlated to 
any one of the following methods.
    (i) The Top Tier-Based Test Method specified in paragraph (a) of 
this section.
    (ii) The CARB-Based Test Method in paragraph (b) of this section.
    (iii) The retired EPA BMW Test Method as follows:
    (A) Prepare the test fuel with the following specification:
    (1) Sulfur--minimum 340 ppm.
    (2) T-90--minimum 339 degrees Fahrenheit.
    (3) Olefins--minimum 11.4 volume percent.
    (4) Aromatics--minimum 31.1 volume percent.
    (5) Ethanol--minimum 10 volume percent.
    (6) Sulfur, T-90, olefins, and aromatics specifications must be met 
prior to the addition of ethanol.
    (7) Di-tert-butyl disulfide may be added to the test fuel to help 
meet the sulfur specification.
    (B) Using the test fuel meeting the requirements of paragraphs 
(c)(1)(iii)(A) of this section, test the test fuel with and without 
detergent in accordance with ASTM D5500 (incorporated by reference in 
Sec.  1090.95) and under the following conditions:
    (1) The unadditized fuel's test results must meet or exceed 290 mg 
per valve on average.
    (2) The required test fuel, including detergent additives, must 
produce the accumulation of less than 100 mg of intake valve deposits 
on average.
    (3) The duration of the demonstration tests under ASTM D5500 may be 
less than the specified 10,000 miles, provided the results satisfy the 
standards of this paragraph.
    (C) If the demonstration test results do not meet the criteria in 
paragraph (c)(1)(iii)(B) of this section, then the formulated fuel may 
not be used for detergent deposit control testing.
    (2) Alternative test methods for detergent additives must be 
correlated to one of the methods specified in paragraph (c)(1) of this 
section in the submission.
    (3) Information describing the alternative test method and analysis 
demonstrating correlation must be submitted for EPA approval as 
specified in Sec.  1090.10.

[[Page 29149]]

Subpart N--Survey Provisions

Sec.  1090.1400   National fuels survey program participation.

    (a) Gasoline manufacturers that elect to account for the addition 
of oxygenate added downstream under Sec.  1090.710 must participate in 
the national fuel survey program specified in this subpart.
    (b) Parties required to participate in an E15 survey under Sec.  
1090.1420(a) must participate in the national fuels survey specified in 
this subpart or a survey approved by EPA under Sec.  1090.1420(b) or 
(c).
    (c) Other parties may elect to participate in the national fuel 
survey program for purposes of establishing an affirmative defense 
against violations of requirements and provisions under this part as 
specified in Sec.  1090.1720.

Sec.  1090.1405   National fuels survey program requirements.

    The national fuels survey program must meet all the following 
requirements:
    (a) The survey program must be planned and conducted by an 
independent surveyor that meets the independence requirements in Sec.  
1090.55 and the requirements specified in Sec.  1090.1410.
    (b) The survey program must be conducted at a representative sample 
of gasoline and diesel retail outlets in the United States as specified 
in Sec.  1090.1415.

Sec.  1090.1410   Independent surveyor requirements.

    The independent surveyor conducting the national fuels survey 
program must meet all the following requirements:
    (a) Submit a proposed survey program plan under Sec.  1090.1415 to 
EPA for approval for each calendar year.
    (b)(1) Obtain samples representative of the gasoline and diesel 
fuel (including diesel fuel made available at retail to nonroad 
vehicles, engines, and equipment) offered for sale separately from all 
gasoline and diesel retail outlets in accordance with the survey 
program plan approved by EPA, or immediately notify EPA of any refusal 
of a retailer to allow samples to be taken.
    (2) Obtain the number of samples representative of the number of 
gasoline retail outlets offering E15.
    (3) Collect samples of gasoline produced at blender pump using 
``method 1'' specified in NIST Handbook 158 (incorporated by reference, 
see Sec.  1090.95). All other samples of gasoline and diesel fuel must 
be collected using the methods specified in subpart M of this part.
    (4) Samples must be shipped via ground service to an EPA-approved 
laboratory within 2 business days of being collected.
    (c) Test, or arrange to be tested, the collected samples, as 
follows:
    (1) Gasoline samples must be analyzed for oxygenate content, sulfur 
content, and benzene content. Gasoline samples collected from June 1 
through September 15 must also be analyzed for RVP.
    (2) A subset of gasoline samples, as determined by Sec.  
1090.1415(e)(3), must also be analyzed for aromatics content, olefins 
content, and distillation parameters (i.e., T50 and T90).
    (3) Diesel samples must be analyzed for sulfur content.
    (4) All samples must be tested by an EPA-approved laboratory using 
the test methods specified in subpart M of this part.
    (5) All testing must be completed by the EPA-approved laboratory 
within 10 business days after receipt of the sample.
    (d) Verify E15 labeling requirements at gasoline retail outlets 
that offer E15 for sale.
    (e) Using procedures specified in an EPA-approved plan under Sec.  
1090.1415, notify EPA, the retailer, and the branded fuel manufacturer 
(if applicable) within 24 hours after the EPA-approved laboratory has 
completed analysis when any of the following occur:
    (1) A test result for a gasoline sample yields a sulfur content 
result that exceeds the sulfur standard in Sec.  1090.205(c).
    (2) A test result for a gasoline sample yields an RVP result that 
exceeds the applicable RVP standard in Sec.  1090.215.
    (3) A test result for a diesel sample yields a sulfur content 
result that exceeds the sulfur standard in Sec.  1090.305(b).
    (4) A test result for a gasoline sample identified as ``E15'' 
yields an ethanol content result that exceeds 15 volume percent.
    (5) A test result for a gasoline sample not identified as ``E15'' 
yields an ethanol content of more than 10 volume percent ethanol.
    (f) Provide to EPA quarterly and annual summary reports that 
include the information specified in Sec.  1090.925.
    (g) Keep records related to the national fuels survey program as 
specified in Sec.  1090.1245(b)(1).
    (h) Submit contracts to EPA as specified in Sec.  1090.1430.
    (i) Permit any representative of EPA to monitor at any time the 
conducting of the survey, including sample collection, transportation, 
storage, and analysis.

Sec.  1090.1415   Survey plan design requirements.

    The national fuels survey program plan must include all the 
following:
    (a) Number of surveys. The survey program plan must include 4 
surveys each calendar year that occur during the following time 
periods:
    (1) One survey during the period of January 1 through March 31.
    (2) One survey during the period of April 1 through June 30.
    (3) One survey during the period of July 1 through September 30.
    (4) One survey during the period of October 1 through December 31.
    (b) Sampling areas. The survey program plan must include sampling 
in all sampling strata during each survey. These sampling strata must 
be further divided into discrete sampling areas or clusters. Each 
survey must include sampling in at least 40 sampling areas in each 
stratum that are randomly selected.
    (c) No advance notice of surveys. The survey program plan must 
include procedures to keep the identification of the sampling areas 
that are included in the plan confidential from any participating party 
prior to the beginning of a survey in an area. However, this 
information must not be kept confidential from EPA.
    (d) Gasoline and diesel retail outlet selection. (1) Gasoline and 
diesel retail outlets to be sampled in a sampling area must be selected 
from among all gasoline retail outlets in the United States that sell 
gasoline with the probability of selection proportionate to the volume 
of gasoline sold at the retail outlet. The sample of retail outlets 
must also include gasoline retail outlets with different brand names as 
well as those gasoline retail outlets that are unbranded.
    (2) For any gasoline or diesel retail outlet from which a sample of 
gasoline or diesel was collected during a survey was reported to EPA 
under Sec.  1090.1410(e), that gasoline or diesel retail outlet must be 
included in the subsequent survey.
    (3) At least one sample of a product dispensed as E15 must be 
collected at each gasoline retail outlet when E15 is present, and 
separate samples must be taken that represent the gasoline contained in 
each storage tank at the gasoline retail outlet unless collection of 
separate samples is not practicable.
    (4) At least one sample of a product dispensed as diesel fuel must 
be collected at each diesel fuel retail outlet when diesel fuel is 
present. Samples of diesel fuel may be collected at retail outlets that 
sell gasoline.

[[Page 29150]]

    (e) Number of samples. (1) The number of retail outlets to be 
sampled must be independently calculated for the total number of 
gasoline retail outlets and the total number of diesel fuel retail 
outlets. The same retail outlet may represent both a gasoline retail 
outlet and a diesel fuel retail outlet for purposes of determining the 
number of samples.
    (2) The minimum number of samples to be included in the survey plan 
for each calendar year is calculated as follows:
[GRAPHIC] [TIFF OMITTED] TP14MY20.024

Where:

n = Minimum number of samples in a year-long survey series. However, 
n must be greater than or equal to 2,000 for the number of diesel 
samples or 5,000 for the number of gasoline samples.
Z[alpha] = Upper percentile point from the normal 
distribution to achieve a one-tailed 95% confidence level (5% 
[alpha]-level). For purposes of this survey program, 
Z[alpha] equals 1.645.
Z[beta] = Upper percentile point to achieve 95% power. 
For purposes of this survey program, Z[beta] equals 
1.645.
[phiv]1 = The maximum proportion of non-compliant outlets 
for a region to be deemed compliant. This parameter needs to be 5% 
or greater (i.e., 5% or more of the outlets, within a stratum such 
that the region is considered non-compliant).
[phiv]0 = The underlying proportion of non-compliant 
outlets in a sample. For the first survey plan, [phiv]0 
will be 2.3%. For subsequent survey plans, [phiv]0 will 
be the average of the proportion of outlets found to be non-
compliant over the previous 4 surveys.
Fa = Adjustment factor for the number of extra samples 
required to compensate for samples that could not be included in the 
survey (e.g., due to technical or logistical considerations), based 
on the number of additional samples required during the previous 4 
surveys. Fa must be greater than or equal to 1.1.
Fb = Adjustment factor for the number of samples required 
to resample each retail outlet with test results reported to EPA 
under Sec.  1090.1410(e), based on the rate of resampling required 
during the previous 4 surveys. Fb must be greater than or 
equal to 1.1.
Sun = Number of surveys per year. For purposes of this 
survey program, Sun equals 4.
Stn = Number of sampling strata. For purposes of this 
survey program, Stn equals 3.

    (3) The number of gasoline samples that also need to be tested for 
aromatics, olefins, and distillation parameters under Sec.  
1090.1410(c)(2) must be calculated using the methodology specified in 
paragraph (e)(2) of this section without the Fa, 
Fb, and Sun parameters.
    (4) The number of samples determined under paragraphs (e)(2) and 
(3) of this section must be distributed approximately equally among the 
4 surveys conducted during the calendar year.
    (f) Laboratory designation. Any laboratory that the independent 
surveyor intends to use to test samples collected as part of the 
national fuels survey program must be approved annually as part of the 
national fuels survey program plan approval process in Sec.  1090.1425. 
In the survey program plan submitted to EPA, the independent surveyor 
must include the following information regarding any laboratory they 
intend to use to test samples:
    (1) The name of the laboratory.
    (2) The address of the laboratory.
    (3) The test methods for each fuel parameter measured at the 
laboratory.
    (4) Reports demonstrating the laboratory's performance in a 
laboratory cross-check program for the most recent 12 months prior to 
submission of the plan.
    (g) Submission. Plans submitted under this section must be approved 
annually under Sec.  1090.1425.

Sec.  1090.1420   Additional requirements for E15 misfueling mitigation 
surveying.

    (a) E15 misfueling mitigation survey requirement. (1) Any gasoline 
manufacturer, oxygenate blender, or oxygenate producer that produces, 
introduces into commerce, sells, or offers for sale E15, gasoline, BOB, 
DFE, or gasoline-ethanol blended fuel that is intended for use in or as 
E15 must comply with either survey program Option 1 (as specified in 
paragraph (b) of this section) or Option 2 (as specified in paragraph 
(c) of this section).
    (2) For oxygenate producers that produce or import DFE, the DFE is 
deemed as intended for use in E15 unless an oxygenate producer 
demonstrates that it was not intended for such use. Oxygenate producers 
may demonstrate, at a minimum, that DFE is not intended for use in E15 
by including language on PTDs stating that the DFE is not intended for 
use in E15, entering into contracts with oxygenate blenders to limit 
the use of their DFE to gasoline-ethanol blended fuels of no more than 
10 volume percent, and limiting the concentration of their DFE to no 
more than 10 volume percent in their fuel additive registration under 
40 CFR part 79.
    (b) Survey Option 1. To comply with the E15 misfueling mitigation 
survey requirement specified in paragraph (a) of this section, the 
gasoline manufacturer, oxygenate blender, or oxygenate producer must 
properly conduct a survey program in accordance with a survey program 
plan that has been approved by EPA in all areas that may be reasonably 
expected to be supplied with their gasoline, BOB, DFE, or gasoline-
ethanol blended fuel. Such approval must be based on a survey program 
plan meeting all the following requirements:
    (1) The survey program must consist of at least quarterly surveys 
that occur during the following time periods in every year during which 
the gasoline manufacturer, oxygenate blender, or oxygenate producer 
introduces E15 into commerce:
    (i) One survey during the period of January 1 through March 31.
    (ii) One survey during the period of April 1 through June 30.
    (iii) One survey during the period of July 1 through September 30.
    (iv) One survey during the period of October 1 through December 31.
    (2) The survey program plan must meet all the requirements of this 
subpart, except for Sec. Sec.  1090.1400, 1090.1405(b), 1090.1410(c)(2) 
and (3), and 1090.1415(b), (d)(1), (2), and (4), and (e). In lieu of 
meeting these exempted sections, the survey program plan must specify 
the sampling strata, clusters, and area(s) to be surveyed, and the 
number of samples to be included in the survey.
    (c) Survey Option 2. To comply with the E15 misfueling mitigation 
survey requirement specified in paragraph (a) of this section, the 
gasoline manufacturer, oxygenate blender, or oxygenate producer must 
participate in the survey program specified in Sec.  1090.1405.

[[Page 29151]]

Sec.  1090.1425   Program plan approval process.

    (a) A program plan that complies with the requirements in Sec.  
1090.1415 or Sec.  1090.1440 must be submitted to EPA no later than 
October 15 of the year preceding the calendar year in which the program 
will be conducted.
    (b) The program plan must be signed by an RCO of the independent 
surveyor conducting the program.
    (c) The program plan must be submitted as specified in Sec.  
1090.10.
    (d) EPA will send a letter to the party submitting the program plan 
that indicates whether EPA approves or disapproves the plan.

Sec.  1090.1430   Independent surveyor contract.

    (a) No later than December 15 of the year preceding the year in 
which the survey will be conducted, the contract with the independent 
surveyor must be in effect, and the amount of compensation necessary to 
carry out the entire survey plan must either be paid to the independent 
surveyor or placed into an escrow account with instructions to the 
escrow agent to remit the compensation to the independent surveyor 
during the course of the survey plan.
    (b) No later than December 31 of the year preceding the year in 
which the survey will be conducted, EPA must receive a copy of the 
contract with the independent surveyor and proof that the compensation 
necessary to carry out the survey plan has either been paid to the 
independent surveyor or placed into an escrow account. If placed into 
an escrow account, a copy of the escrow agreement must be sent to EPA.

Sec.  1090.1440   National sampling oversight program requirements.

    (a) National sampling oversight program participation. (1) Except 
for gasoline manufacturers that have an approved in-line blending 
waiver under Sec.  1090.1315, any gasoline manufacturer that elects to 
account for the addition of oxygenate added downstream under Sec.  
1090.710 must participate in the national sampling oversight program in 
this section.
    (2) Other gasoline manufacturers may elect to participate in the 
national sampling oversight program for purposes of establishing an 
affirmative defense to a violation under Sec.  1090.1720.
    (3) Gasoline manufacturers that elect to participate in the 
national sampling oversight program must test, or arrange to be tested, 
samples collected from their gasoline manufacturing facilities as 
specified in paragraph (c)(2) of this section and report results to the 
independent surveyor within 10 business days of the date the sample was 
collected.
    (b) National sampling oversight program requirements. The national 
oversight sampling program must meet all the following requirements:
    (1) The national oversight sampling program must be planned and 
conducted by an independent surveyor that meets the independence 
requirements in Sec.  1090.55 and the requirements of paragraph (c) of 
this section.
    (2) The national sampling oversight program must be conducted at 
each gasoline manufacturing facility from all participating gasoline 
manufacturers.
    (c) Independent surveyor requirements. The independent surveyor 
conducting the national sampling oversight program must meet all the 
following requirements:
    (1) Submit a proposed national sampling oversight program plan that 
meets the requirements of paragraph (d) of this section to EPA for 
approval each calendar year.
    (2)(i) Obtain at least one sample representing summer gasoline and 
one sample representing winter gasoline for each participating gasoline 
manufacturing facility.
    (ii) Observe the gasoline manufacturer collect at least one sample 
representing summer gasoline and one sample representing winter 
gasoline for each participating gasoline manufacturing facility. The 
independent surveyor must also obtain a portion of the sample collected 
by the gasoline manufacturer and ship the sample as specified in 
paragraph (c)(2)(v) of this section. The observed sample does not need 
to represent a batch of certified gasoline (i.e., the independent 
surveyor may observe the collection of a simulated sample if the 
gasoline manufacturer does not have a batch of certified gasoline 
available).
    (iii) The independent surveyor must immediately notify EPA of any 
refusal of a gasoline manufacturer to allow samples to be taken. 
Gasoline manufacturers that refuse to allow the independent surveyor to 
take portions of collected samples are no longer considered by EPA to 
participate in the national sampling oversight program and may not 
account for the addition of oxygenate added downstream under Sec.  
1090.710.
    (iv) Samples must be retained by the independent surveyor as 
specified in Sec.  1090.1345(a).
    (v) Samples collected must be shipped via ground service within 2 
business days from when the samples are collected to an EPA-approved 
laboratory as established in an approved plan under this section. A 
random subset of collected samples must also be shipped to the EPA 
National Vehicle and Fuel Emissions Laboratory as established in an 
approved plan under this section.
    (3) Test, or arrange to be tested, samples collected under 
paragraph (c)(2) of this section as follows:
    (i) Winter gasoline samples must be analyzed for oxygenate content, 
sulfur content, benzene content, distillation parameters, aromatics, 
and olefins.
    (ii) Summer gasoline samples must be analyzed for oxygenate 
content, sulfur content, benzene content, distillation parameters, 
aromatics, olefins, and RVP.
    (iii) All samples must be tested by an EPA-approved laboratory 
using test methods specified in subpart M of this part.
    (iv) All analyses must be completed by the EPA-approved laboratory 
within 10 business days after receipt of the sample.
    (v) Gasoline manufacturers must analyze gasoline samples for sulfur 
and benzene content, and for summer gasoline, RVP.
    (4) Using procedures specified in the EPA-approved plan under this 
section, notify EPA and the gasoline manufacturer within 24 hours after 
the EPA-approved laboratory has completed analysis when any of the 
following occur:
    (i) A test result for a gasoline sample yields a sulfur content 
result that exceeds the sulfur standard in Sec.  1090.205(b).
    (ii) A test result for a gasoline sample yields an RVP result that 
exceeds the applicable RVP standard in Sec.  1090.215.
    (5) Make the test results available to EPA and the gasoline 
manufacturer for all analyses specified in paragraph (c)(3) of this 
section within 5 business days of completion of the analysis.
    (6) Compare test results of all samples collected under paragraph 
(c)(2) of this section and all test results obtained from the gasoline 
manufacturer from the same samples as specified in paragraph (a)(3) of 
this section and inform EPA and the gasoline manufacturer if the test 
result for any parameter tested under paragraph (c)(3) of this section 
is greater than the reproducibility of the applicable method specified 
in subpart M of this part.
    (7) Provide to EPA quarterly and annual summary reports that 
include the information specified in subpart J of this part.
    (8) Keep records related to the national sampling oversight program 
as specified in Sec.  1090.1245(b)(3).

[[Page 29152]]

    (9) Submit contracts to EPA as specified in Sec.  1090.1430.
    (10) Review the test performance index and precision ratio for each 
method and instrument the laboratory used to test the gasoline samples 
collected under this section as follows:
    (i) For each test method and instrument, the surveyor must obtain 
the relevant records from the gasoline manufacturer to determine the 
site precision, either from an inter-laboratory crosscheck program or 
from ASTM D6299 (incorporated by reference in Sec.  1090.95).
    (ii) Using relevant information obtained from the gasoline 
manufacturers, the surveyor must determine the appropriate Test 
Performance Index (TPI) and Precision Ration (PR) from ASTM D6792 Table 
2 Guidelines for Action Based on TPI (incorporated by reference in 
Sec.  1090.95).
    (iii) Report as part of the quarterly and annual reporting 
requirements in Sec.  1090.925 the determined site precision under 
paragraph (c)(10)(i) of this section and the test performance index 
under paragraph (c)(10)(ii) of this section.
    (iv) Gasoline manufacturers must supply copies of the necessary 
information to the independent surveyor to review the TPI and PR for 
each method and instrument used to test the gasoline samples collected 
under this section.
    (11) Permit any representative of EPA to monitor at any time the 
conducting of the national sampling oversight program, including sample 
collection, transportation, storage, and analysis.
    (d) National sampling oversight program plan requirements. The 
national sampling oversight program plan specified in paragraph (c)(1) 
of this section must include, at a minimum, all the following:
    (1) Advance notice of sampling. The program plan must include 
procedures on how to keep the identification of the gasoline 
manufacturing facilities included in the program plan confidential with 
minimal advanced notification from any participating gasoline 
manufacturer prior to collecting a sample. However, this information 
must not be kept confidential from EPA.
    (2) Gasoline manufacturing facility selection. (i) Each 
participating gasoline manufacturing facility must be sampled at least 
once during the summer season and once during the winter season. The 
plan must demonstrate how these facilities will be randomly selected 
within the summer and winter seasons.
    (ii) In addition to the summer and winter sample collected at each 
participating gasoline manufacturing facility, additional oversight 
samples are required under paragraph (d)(3)(ii) of this section. The 
independent surveyor must identify how these samples will be randomly 
distributed among participating gasoline manufacturing facilities.
    (3) Number of samples. (i) The number of gasoline manufacturing 
facilities to be sampled must be calculated for the total number of 
samples to be collected for the next calendar year as part of the 
program plan.
    (ii) The minimum number of samples to be included in the program 
plan for each calendar year is calculated as follows:

n = R * Fa * Fb * Sun

Where:

n = Minimum number of samples in a year.
R = The number of participating gasoline manufacturing facilities.
Fa = Adjustment factor for the number of extra samples 
required to compensate for samples that could not be included in the 
national sampling oversight program (e.g., due to technical or 
logistical considerations), based on the number of additional 
samples required during the previous 2 calendar years. Fa 
must be greater than or equal to 1.1.
Fb = Adjustment factor for the number of samples required 
to ensure oversight. For purposes of this program, Fb 
equals 1.25.
Sun = Number of samples required per participating 
facility per year. For purposes of this program, Sun 
equals 2.

    (4) Laboratory designation. Any laboratory that the independent 
surveyor intends to use to test samples collected as part of the 
national sampling oversight program specified in this subpart must be 
approved annually as part of the sampling oversight program plan 
approval process in Sec.  1090.1425. The independent surveyor must 
include the following information regarding any laboratory it intends 
to use to test samples:
    (i) The name of the laboratory.
    (ii) The address of the laboratory.
    (iii) The test methods for each fuel parameter measured at the 
laboratory.
    (iv) Reports demonstrating the laboratory's performance in a 
laboratory cross-check program for the most recent 12 months prior to 
submission of the plan.
    (5) Sampling procedure. The plan must include a detailed 
description of the sampling procedures used to collect samples at 
participating gasoline manufacturing facilities.
    (6) Notification of test results. The plan must include a 
description of how the independent surveyor will notify EPA and 
gasoline manufacturers of test results under paragraph (c)(4) of this 
section.
    (7) Submission. Plans submitted under this section must be approved 
annually under Sec.  1090.1425.

Subpart O--Retailer and Wholesale Purchaser-Consumer Provisions

Sec.  1090.1500   Overview.

    (a) Retailers and WPCs must meet the labeling requirements in 
Sec. Sec.  1090.1510 and 1090.1515, as applicable, and the refueling 
hardware requirements in Sec. Sec.  1090.1550 through 1090.1565, as 
applicable.
    (b) An alternative label design to those specified in this subpart 
may be used if the design is approved by EPA prior to use and meets all 
the following requirements:
    (1) The alternative label must be similar in substance and 
appearance to the EPA-required label.
    (2) The alternative label must contain the same informational 
elements.
    (3) The alternative label must be submitted as specified in Sec.  
1090.10.

Labeling

Sec.  1090.1510   E15 labeling provisions.

    Any retailer or WPC dispensing E15 must apply a label to the fuel 
dispenser as follows:
    (a) Position the label to clearly identify which control the 
consumer will use to select E15. If the dispenser is set up to dispense 
E15 without the consumer taking action to select the fuel, position the 
label on a vertical surface in a prominent place, approximately at eye 
level.
    (b) Figure 1 of this section shows the required content and 
formatting. Use black letters on an orange background for the lower 
portion and the diagonal ``Attention'' field and use orange letters on 
a black background for the rest of the upper portion. Font size is 
shown in Figure 1. Set vertical position and line spacing as 
appropriate for each field. Dimensions are nominal values.

[[Page 29153]]

[GRAPHIC] [TIFF OMITTED] TP14MY20.025

Sec.  1090.1515   Diesel sulfur labeling provisions.

    Any retailer or WPC dispensing heating oil, 500 ppm LM diesel fuel, 
or ECA marine fuel must apply labels to fuel dispensers as follows:
    (a) Labels must be in a prominent location where the consumer will 
select or dispense either the corresponding fuel or heating oil. The 
label content must be in block letters of no less than 24-point bold 
type, printed in a color contrasting with the background.
    (b) Labels must include the following statements, or equivalent 
alternative statements approved by EPA:
    (1) For dispensing heating oil along with any kind of diesel fuel 
for any kind of engine, vehicle, or equipment, apply the following 
label:

HEATING OIL

WARNING

    Federal law prohibits use in highway vehicles or engines, or in 
nonroad, locomotive, or marine diesel engines.
    Its use may damage these diesel engines.
    (2) For dispensing 500 ppm LM diesel fuel, apply the following 
label:

LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur Maximum)

WARNING

    Federal law prohibits use in nonroad engines or in highway vehicles 
or engines.
    (3) For dispensing ECA marine fuel, apply the following label:

ECA MARINE FUEL (1,000 ppm Sulfur Maximum).

For use in Category 3 (C3) marine vessels only.

WARNING

    Federal law prohibits use in any engine that is not installed in a 
C3 marine vessel; use of fuel oil with a sulfur content greater than 
1,000 ppm in an ECA is prohibited except as allowed by 40 CFR part 
1043.
    Note: If a pump dispensing 500 ppm LM diesel fuel is labeled with 
the ``LOW SULFUR LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur 
Maximum)'' label, the retailer or WPC does not need to replace this 
label.

Refueling Hardware

Sec.  1090.1550   Requirements for gasoline dispensing nozzles used 
with motor vehicles.

    (a) The following refueling hardware specifications apply for any 
nozzle installation used for dispensing gasoline into motor vehicles:
    (1) The outside diameter of the terminal end must not be greater 
than 21.3 mm.
    (2) The terminal end must have a straight section of at least 63 
mm.
    (3) The retaining spring must terminate at least 76 mm from the 
terminal end.
    (b) For nozzles that dispense gasoline into motor vehicles, the 
dispensing flow rate may not exceed a maximum value of 10 gallons per 
minute. The flow rate may be controlled through any means in the pump/
dispenser system, as long as it does not exceed the specified maximum 
value. Any dispensing pump dedicated to heavy-duty vehicles or 
airplanes is exempt from this flow-rate requirement. Dispensing pumps 
primarily used with marine vessels must instead meet the requirements 
in Sec.  1090.1555.

Sec.  1090.1555   Requirements for gasoline dispensing nozzles used 
primarily with marine vessels.

    The refueling hardware specifications of this section apply for any 
nozzle installation used primarily for dispensing gasoline into marine 
vessels. Note that nozzles meeting these specifications also meet the 
specifications of Sec.  1090.1550(a).
    (a) The outside diameter of the terminal end must have a diameter 
of 20.93  00.43 mm.
    (b) The spout must include an aspirator hole for automatic shutoff 
positioned with a center that is 17.0  01.3 mm from the 
terminal end of the spout.
    (c) The terminal end must have a straight section of at least 63.4 
mm with no holes or grooves other than the aspirator hole.

[[Page 29154]]

    (d) The retaining spring (if applicable) must terminate at least 76 
mm from the terminal end.

Sec.  1090.1560   Requirements related to dispensing natural gas.

    (a) Except for pumps dedicated to heavy-duty vehicles, any pump 
installation used for dispensing natural gas into motor vehicles must 
have a nozzle and hose configuration that vents no more than 1.2 grams 
of natural gas during a complete refueling event for a vehicle meeting 
the requirements of 40 CFR 86.1813-17(f)(1).
    (b) Determine the vented volume using calculations based on the 
geometric shape of the nozzle and hose.

Sec.  1090.1565   Requirements related to dispensing liquefied 
petroleum gas.

    (a) Except for pumps dedicated to heavy-duty vehicles, any pump 
installation used for dispensing liquefied petroleum gas into motor 
vehicles must have a nozzle that has no greater than 2.0 cm\3\ dead 
space from which liquefied petroleum gas will be released when the 
nozzle disconnects from the vehicle.
    (b) Determine the volume of the nozzle cavity using calculations 
based on the geometric shape of the nozzle, with an assumed flat 
surface where the nozzle face seals against the vehicle.

Subpart P--Importer and Exporter Provisions

Sec.  1090.1600   General provisions for importers.

    (a) This subpart contains provisions that apply to any person who 
imports fuel, fuel additive, or regulated blendstock.
    (b) Importers that import fuel at multiple import facilities must 
comply with the gasoline average standards as specified in Sec.  
1090.705(b) unless the importer elects to comply with the alternative 
per-gallon standards for rail and truck imports specified in Sec. Sec.  
1090.205(d) and 1090.210(c).
    (c) Importers must separately comply with any applicable 
certification or other requirements for U.S. Customs.
    (d) Alternative testing requirements for importers that import 
gasoline or diesel fuel by rail or truck are specified in Sec.  
1090.1610.

Sec.  1090.1605  Importation by marine vessel.

    Importers that import fuel, fuel additive, or regulated blendstock 
using a marine vessel must comply with the requirements of this 
section.
    (a) Importers must certify each fuel, fuel additive, or regulated 
blendstock imported at each port, even if it is transported by the same 
vessel making multiple stops.
    (b)(1) Except as specified in paragraph (d) of this section, 
importers must certify each fuel, fuel additive, or regulated 
blendstock while it is onboard the vessel used to transport it to the 
United States, and certification sampling must be performed after the 
vessel's arrival at the port where the fuel, fuel additive, or 
regulated blendstock will be offloaded.
    (2) Importers must sample each compartment of the vessel and treat 
each compartment as a separate batch unless the importer collects and 
combines samples from separate compartments into a single, volume-
weight composite sample using ASTM D4057 (incorporated by reference in 
Sec.  1090.95) and demonstrates that the fuel, fuel additive, or 
regulated blendstock is homogeneous across the compartments under Sec.  
1090.1337.
    (3) Importers must ensure that all applicable per-gallon standards 
are met before offloading the fuel, fuel additive, or regulated 
blendstock.
    (4) Importers must not rely on testing conducted by a foreign 
supplier.
    (c) Once the fuel, fuel additive, or regulated blendstock on a 
vessel has been certified under paragraph (b) of this section, it may 
be transferred to shore tanks using smaller vessels or barges 
(lightered) as a certified fuel, fuel additive, or regulated 
blendstock. These lightering transfers may be to terminals located in 
any harbor and are not restricted to terminals located in the harbor 
where the vessel is anchored. For example, certified gasoline could be 
transferred from an import vessel anchored in New York harbor to a 
lightering vessel and transported to Albany, New York or Providence, 
Rhode Island without separately certifying the gasoline upon arrival in 
Albany or Providence. In this lightering scenario, transfers of 
certified gasoline to a lightering vessel must be accompanied by PTDs 
that meet the PTD requirements of subpart K of this part.
    (d) As an alternative to paragraphs (b) and (c) of this section, 
importers may offload fuel, fuel additive, or regulated blendstock into 
shore tanks containing the same fuel, fuel additive, or regulated 
blendstock if the importer meets the following requirements:
    (1) For gasoline, importers must offload gasoline into one or more 
empty shore tanks or tanks containing PCG that the importer owns.
    (i) If importers offload gasoline into one or more empty shore 
tanks, they must sample and test the sulfur and benzene content, and 
for summer gasoline, RVP, of each shore tank into which the gasoline 
was offloaded.
    (ii) If importers offload gasoline into one or more shore tanks 
containing PCG, they must sample the PCG already in the shore tank 
prior to offloading gasoline from the marine vessel, test the sulfur 
and benzene content, and report this PCG as a batch with a negative 
volume. After offloading the gasoline into the shore tanks, the 
importer must sample and test the sulfur and benzene content, and RVP 
for summer gasoline, of each shore tank into which the gasoline was 
offloaded and report the volume and sulfur and benzene content as a 
positive batch.
    (2) For all other fuel, fuel additive, or regulated blendstock, 
importers must sample and test the fuel, fuel additive, or regulated 
blendstock in each shore tank into which it was offloaded. Importers 
must ensure that all applicable per-gallon standards are met before the 
fuel, fuel additive, or regulated blendstock is shipped from the shore 
tank.

Sec.  1090.1610   Importation by rail or truck.

    Importers that import fuel, fuel additive, or regulated blendstock 
by rail or truck may meet the sampling and testing requirements of 
subpart M of this part based on test results from the supplier if they 
meet all the following requirements:
    (a) The importer must get documentation of test results from the 
supplier for each batch of fuel, fuel additive, or regulated blendstock 
in accordance with the following requirements:
    (1) The testing must include measurements for all the fuel 
parameters specified in Sec.  1090.1310 using the measurement 
procedures specified in Sec.  1090.1350.
    (2) Testing for a given batch must occur after the most recent 
delivery into the supplier's storage tank and before transferring the 
fuel, fuel additive, or regulated blendstock to the railcar or truck.
    (b) The importer must conduct testing to verify test results from 
each supplier as follows:
    (1) Collect a sample at least once every 30 days or every 50 rail 
or truckloads from a given supplier, whichever is more frequent. Test 
such samples as specified in paragraphs (a)(1) and (2) of this section.
    (2) Treat importation of each fuel, fuel additive, or regulated 
blendstock separately, but treat railcars and truckloads together if 
the fuel, fuel additive, or regulated blendstock is imported from a 
given supplier by rail and truck.

[[Page 29155]]

    (c) If the importer fails to meet the requirements of paragraphs 
(a) and (b) of this section, they must perform testing as specified in 
Sec.  1090.1310 until EPA determines that the importer has adequately 
addressed the cause of the failure.

Sec.  1090.1615   Gasoline treated as a blendstock.

    (a) Importers may exclude GTAB from their compliance calculations 
if they meet all the following requirements:
    (1) The importer reports such GTAB to EPA under Sec.  
1090.905(c)(7).
    (2) Such GTAB is treated as blendstock at a related gasoline 
manufacturing facility that produces gasoline using the GTAB.
    (3) The related gasoline manufacturing facility must report the 
gasoline produced using such GTAB and must include the gasoline 
produced using such GTAB in their compliance calculations.
    (b) After importation, the title of the GTAB may not be transferred 
to another party until the GTAB has been blended to produce gasoline 
and all applicable standards and requirements have been met for the 
gasoline produced.
    (c) The facility at which the GTAB is used to produce gasoline must 
be physically located at either the same terminal at which the GTAB 
first arrives in the United States, the import facility, or at a 
facility to which the GTAB is directly transported from the import 
facility.
    (d)(1) The importer must treat the GTAB as if were imported 
gasoline and complete all requirements for gasoline manufacturers under 
Sec.  1090.105(a) (except for the sampling, testing, and sample 
retention requirements in Sec.  1090.105(a)(5)) for the GTAB at the 
time it is imported.
    (2) Any GTAB that ultimately is not used to produce gasoline (e.g., 
a tank bottom of GTAB) must be treated as newly imported gasoline and 
must meet all applicable requirements for imported gasoline.

Sec.  1090.1650   General provisions for exporters.

    Except as specified in this section and in subpart G of this part, 
gasoline and diesel fuel produced, imported, distributed, or offered 
for sale in the United States is subject to the standards and 
requirements of this part.
    (a) Fuels designated for export by a fuel manufacturer are not 
subject to the standards in this part, provided they are ultimately 
exported to a foreign country. However, such fuels must be designated 
at the fuel manufacturing facility and must be accompanied by PTDs 
stating that the fuel is for ``export only'' under subpart K of this 
part. Fuel manufacturers must keep records to demonstrate that the fuel 
was exported. Fuel designated for export must be segregated from all 
fuel intended for use in the United States.
    (b) Fuel not designated for export may be exported without 
restriction. However, the fuel remains subject to the provisions of 
this part while in the United States. For example, fuel designated as 
ULSD must meet the applicable sulfur standards under this part even if 
it will later be exported.
    (c) Fuel that has been classified as American Goods Returned to the 
U.S. by the U.S. Customs Service is not considered to be imported for 
purposes of this part, provided all the following requirements are met:
    (1) Such fuel was produced at a fuel manufacturing facility located 
within the United States and has not been mixed with fuel produced at a 
fuel manufacturing facility located outside the United States.
    (2) Such fuel must be included in compliance calculations by the 
producing fuel manufacturer.
    (3) All the fuel that was exported must ultimately be classified as 
American Goods Returned to the U.S. and none may be used in a foreign 
country.
    (4) No fuel classified as American Goods Returned to the U.S. may 
be combined with any fuel produced at a foreign fuel manufacturing 
facility prior to importation into the United States.

Subpart Q--Compliance and Enforcement Provisions

Sec.  1090.1700   Prohibited acts.

    (a) No person may violate any prohibited act in this part or fail 
to meet a requirement that applies to that person under this part.
    (b) No person may cause another person to commit an act in 
violation of this part.

Sec.  1090.1705   Evidence related to violations.

    (a)(1) EPA may use results from any testing required by this part 
to determine whether a given fuel, fuel additive, or regulated 
blendstock meets any applicable standard. However, EPA may also use any 
other evidence or information to make this determination if the 
evidence or information supports the conclusion that the fuel, fuel 
additive, or regulated blendstock would fail to meet one or more of the 
parameter specifications in this part if the appropriate sampling and 
testing methodology had been correctly performed. Examples of other 
relevant information include business records, commercial documents, 
and measurements with alternative procedures.
    (2) Testing to determine noncompliance with this part may occur at 
any location and be performed by any party.
    (b) Determinations of compliance with the requirements of this part 
other than the fuel, fuel additive, or regulated blendstock standards, 
and determinations of liability for any violation of this part, may be 
based on information from any source or location. Such information may 
include, but is not limited to, business records and commercial 
documents.

Sec.  1090.1710   Penalties.

    (a) Any person liable for a violation under this part is subject to 
civil penalties as specified in 42 U.S.C. 7524 and 7545 for every day 
of such violation and the amount of economic benefit or savings 
resulting from each violation.
    (b)(1) Any person liable for the violation of an average standard 
under this part is subject to a separate day of violation for each and 
every day in the compliance period.
    (2) Any person liable under this part for a failure to fulfill any 
requirement for credit generation, transfer, use, banking, or deficit 
correction is subject to a separate day of violation for each and every 
day in the compliance period in which invalid credits are generated or 
used.
    (c)(1) Any person liable under this part for a violation of a per-
gallon standard, or of causing another party to violate a per-gallon 
standard, is subject to a separate day of violation for each and every 
day the non-complying fuel, fuel additive, or regulated blendstock 
remains any place in the distribution system.
    (2) For the purposes of paragraph (c)(1) of this section, the 
length of time the fuel, fuel additive, or regulated blendstock that 
violates a per-gallon standard remained in the distribution system is 
deemed to be 25 days, unless a person subject to liability or EPA 
demonstrates by reasonably specific showings, by direct or 
circumstantial evidence, that the non-complying fuel, fuel additive, or 
regulated blendstock remained in the distribution system for fewer than 
or more than 25 days.
    (d) Any person liable for failure to meet, or causing a failure to 
meet, any other provision of this part is liable for a separate day of 
violation for each and every day such provision remains unfulfilled.

[[Page 29156]]

    (e) For any person that fails to meet separate parameter 
requirements of this part, these count as separate violations.
    (f) Violation of any misfueling prohibition under this part counts 
as a separate violation for each and every day the noncompliant fuel, 
fuel additive, or regulated blendstock remains in any engine, vehicle, 
or equipment.
    (g) The presumed values of fuel parameters in paragraphs (g)(1) 
through (6) of this section apply for cases in which any person fails 
to perform required testing and must be reported, unless EPA, in its 
sole discretion, approves a different value in writing. EPA may 
consider any relevant information to determine whether a different 
value is appropriate.
    (1) For gasoline: 970 ppm sulfur, 5 volume percent benzene, and 11 
psi RVP.
    (2) For diesel fuel: 1,000 ppm sulfur.
    (3) For ECA marine fuel: 5,000 ppm sulfur.
    (4) For the PCG portion for PCG by subtraction under Sec.  
1090.1320(a)(1): 0 ppm sulfur and 0 volume percent benzene.
    (5) For fuel additives: 970 ppm sulfur.
    (6) For regulated blendstocks: 970 ppm sulfur and 5 volume percent 
benzene.

Sec.  1090.1715   Liability provisions.

    (a) Any person who violates any requirement in this part is liable 
for the violation.
    (b) Any person who causes someone to commit a prohibited act under 
this subpart is liable for violating that prohibition.
    (c) Any parent corporation is liable for any violation committed by 
any of its wholly-owned subsidiaries.
    (d) Each partner to a joint venture, or each owner of a facility 
owned by two or more owners, is jointly and severally liable for any 
violation of this subpart that occurs at the joint venture facility or 
facility owned by the joint owners, or is committed by the joint 
venture operation or any of the joint owners of the facility.
    (e)(1) Any person that produced, imported, sold, offered for sale, 
dispensed, supplied, offered for supply, stored, transported, caused 
the transportation or storage of, or introduced into commerce fuel, 
fuel additive, or regulated blendstock that is in the storage tank 
containing fuel, fuel additive, or regulated blendstock that is found 
to be in violation of a per-gallon standard is liable for the 
violation.
    (2) In order for a carrier to be liable under paragraph (e)(1) of 
this section, EPA must demonstrate by reasonably specific showing, by 
direct or circumstantial evidence, that the carrier caused the 
violation.
    (f) If a fuel manufacturer's corporate, trade, or brand name is 
displayed at a facility where a violation occurs, the fuel manufacturer 
is liable for the violation. This also applies where the displayed 
corporate, trade, or brand name is from the fuel manufacturer's 
marketing subsidiary.

Sec.  1090.1720   Affirmative defense provisions related to 
noncompliant fuel, fuel additive, or regulated blendstock.

    (a) Any person liable for a violation under Sec.  1090.1715(e) or 
(f) will not be deemed in violation if the person demonstrates all the 
following:
    (1) The violation was not caused by the person or the person's 
employee or agent.
    (2) In cases where PTD requirements of this part apply, the PTDs 
account for the fuel, fuel additive, or regulated blendstock found to 
be in violation and indicate that the violating fuel, fuel additive, or 
regulated blendstock was in compliance with the applicable requirements 
while in that person's control.
    (3) The person conducted a quality assurance program, as specified 
in paragraph (d) of this section.
    (i) A carrier may rely on the quality assurance program carried out 
by another party, including the party that owns the fuel in question, 
provided that the quality assurance program is carried out properly.
    (ii) Retailers and WPCs are not required to conduct sampling and 
testing of fuel as part of their quality assurance program.
    (b) For a violation found at a facility operating under the 
corporate, trade, or brand name of a fuel manufacturer, or a fuel 
manufacturer's marketing subsidiary, the fuel manufacturer must show, 
in addition to the defense elements required under paragraph (a) of 
this section, that the violation was caused by one of the following:
    (1) An act in violation of law (other than the Clean Air Act or 
this part), or an act of sabotage or vandalism.
    (2) The action of any retailer, distributor, reseller, oxygenate 
blender, carrier, retailer, or WPC in violation of a contractual 
agreement between the branded fuel manufacturer and the person designed 
to prevent such action, and despite periodic sampling and testing by 
the branded fuel manufacturer to ensure compliance with such 
contractual obligation.
    (3) The action of any carrier or other distributor not subject to a 
contract with the fuel manufacturer, but engaged for transportation of 
fuel, fuel additive, or regulated blendstock despite specifications or 
inspections of procedures and equipment that are reasonably calculated 
to prevent such action.
    (c) For any person to show under paragraph (a) of this section that 
a violation was not caused by that person, or to show under paragraph 
(b) of this section that a violation was caused by any of the specified 
actions, the person must demonstrate by reasonably specific showings, 
through direct or circumstantial evidence, that the violation was 
caused or must have been caused by another person and that the person 
asserting the defense did not contribute to that other person's 
causation.
    (d) To demonstrate an acceptable quality assurance program under 
paragraph (a)(3) of this section, a person must present evidence of all 
the following:
    (1)(i) A periodic sampling and testing program adequately designed 
to ensure the fuel, fuel additive, or regulated blendstock the person 
sold, dispensed, supplied, stored, or transported meets the applicable 
per-gallon standard. A person may meet this requirement by 
participating in a survey program under subpart N of this part that was 
in effect at the time of the violation.
    (ii) In addition to the requirements in paragraph (d)(1)(i) of this 
section, gasoline manufacturers must also participate in the national 
sampling oversight program specified in Sec.  1090.1440 at the time of 
the violation.
    (2) On each occasion when a fuel, fuel additive, or regulated 
blendstock is found to be in noncompliance with the applicable per-
gallon standard, the person does all the following:
    (i) Immediately ceases selling, offering for sale, dispensing, 
supplying, offering for supply, storing, or transporting the non-
complying fuel, fuel additive, or regulated blendstock.
    (ii) Promptly remedies the violation and the factors that caused 
the violation (e.g., by removing the non-complying fuel, fuel additive, 
or regulated blendstock from the distribution system until the 
applicable standard is achieved and taking steps to prevent future 
violations of a similar nature from occurring).
    (3) For any carrier that transports a fuel, fuel additive, or 
regulated blendstock in a tank truck, the quality assurance program 
required under paragraph (d)(1) of this section does not need to 
include periodic sampling and testing of gasoline in the tank truck. In 
lieu of such tank truck sampling and testing, the carrier must 
demonstrate

[[Page 29157]]

evidence of an oversight program for monitoring compliance with the 
requirements of this part relating to the transport or storage of fuel, 
fuel additive, or regulated blendstock by tank truck, such as 
appropriate guidance to drivers regarding compliance with the 
applicable per-gallon standards and PTD requirements, and the periodic 
review of records received in the ordinary course of business 
concerning gasoline quality and delivery.
    (e) In addition to the defenses provided in paragraphs (a) through 
(d) of this section, in any case in which an ethanol blender, 
distributor, reseller, carrier, retailer, or WPC would be in violation 
under Sec.  1090.1715 as a result of gasoline that contains between 9 
and 15 percent ethanol (by volume) but exceeds the applicable standard 
by more than 1.0 psi, the ethanol blender, distributor, reseller, 
carrier, retailer or wholesale purchaser-consumer will not be deemed in 
violation if such person can demonstrate, by showing receipt of a 
certification from the facility from which the gasoline was received or 
other evidence acceptable to EPA, all the following:
    (1) The gasoline portion of the blend complies with the applicable 
RVP standard in Sec.  1090.215.
    (2) The ethanol portion of the blend does not exceed 15 percent (by 
volume).
    (3) No additional alcohol or other additive has been added to 
increase the RVP of the ethanol portion of the blend.
    (4) In the case of a violation alleged against an ethanol blender, 
distributor, reseller, or carrier, if the demonstration required by 
paragraphs (e)(1) through (3) of this section is made by a 
certification, it must be supported by evidence that the criteria in 
paragraphs (e)(1) through (3) of this section have been met, such as an 
oversight program conducted by or on behalf of the ethanol blender, 
distributor, reseller, or carrier alleged to be in violation, which 
includes periodic sampling and testing of the gasoline or monitoring 
the volatility and ethanol content of the gasoline. Such certification 
will be deemed sufficient evidence of compliance provided it is not 
contradicted by specific evidence, such as testing results, and 
provided that the party has no other reasonable basis to believe that 
the facts stated in the certification are inaccurate. In the case of a 
violation alleged against a retail outlet or WPC facility, such 
certification will be deemed an adequate defense for the retailer or 
WPC, provided that the retailer or WPC is able to show certificates for 
all the gasoline contained in the storage tank found in violation, and, 
provided that the retailer or WPC has no reasonable basis to believe 
that the facts stated in the certifications are inaccurate.

Subpart R--Attestation Engagements

Sec.  1090.1800   General provisions.

    (a) The following parties must arrange for attestation engagement 
using agreed-upon procedures as specified in this subpart:
    (1) Gasoline manufacturers that produce or import gasoline subject 
to the requirements of subpart C of this part.
    (2) Gasoline manufacturers that perform testing as specified in 
subpart M of this part, and gasoline manufacturers that rely on testing 
from independent laboratories.
    (b) Auditors performing attestation engagements must meet the 
following requirements:
    (1) Auditors must meet one of the following professional 
qualifications:
    (i) The auditor may be an internal auditor that is employed by the 
fuel manufacturer and certified by the Institute of Internal Auditors. 
Internal auditors must perform the attestation engagement in accordance 
with the International Standards for the Professional Practice of 
Internal Auditing (Standards) (incorporated by reference in Sec.  
1090.95).
    (ii) The auditor may be a certified public accountant, or firm of 
such accountants, that is independent of the gasoline manufacturer. 
Such auditors must comply with the AICPA Code of Professional Conduct, 
including its independence requirements, the AICPA Statements on 
Quality Control Standards (both incorporated by reference in Sec.  
1090.95), and applicable rules of state boards of public accountancy. 
Such auditors must also perform the attestation engagement in 
accordance with the AICPA Statements on Standards for Attestation 
Engagements (SSAE) No. 18, Attestation Standards: Clarification and 
Recodification, especially as noted in sections AT-C 105, 215, and 315 
(incorporated by reference in Sec.  1090.95).
    (2) The auditor must meet the independence requirements in Sec.  
1090.55.
    (3) The auditor must be registered with EPA under subpart I of this 
part.
    (4) Any auditor suspended or debarred under 2 CFR part 1532 or 48 
CFR part 9, subpart 9.4, is not qualified to perform attestation 
engagements under this subpart.
    (c) Auditors must perform attestation engagements separately for 
each gasoline manufacturing facility for which the gasoline 
manufacturer submitted reports to EPA under subpart J of this part for 
the compliance period.
    (d) The following provisions apply to each attestation engagement 
performed under this subpart:
    (1) The auditor must prepare a report identifying the applicable 
procedures specified in this subpart along with the auditor's 
corresponding findings for each procedure. The auditor must submit the 
report electronically to EPA by June 1 of the year following the 
compliance period.
    (2) The auditor must identify any instances where compared values 
do not agree or where specified values do not meet applicable 
requirements under this part.
    (3) Laboratory analysis refers to the original test result for each 
analysis of a product's properties. The following provisions apply in 
special cases:
    (i) For laboratories using test methods that must be correlated to 
the standard test method, the laboratory analysis must include the 
correlation factors along with the corresponding test results.
    (ii) For gasoline manufacturers that rely on third-party 
laboratories for all testing, the laboratory analysis consists of the 
results provided by the third-party laboratory.

Sec.  1090.1805   Representative samples.

    (a) If the specified procedures require evaluation of a 
representative sample from the overall population for a given data set, 
determine the number of results for evaluation using one of the 
following methods:
    (1) Determine sample size using the following table:

                       Table 1 to Paragraph (a)(1)
------------------------------------------------------------------------
              Population                          Sample size
------------------------------------------------------------------------
1-25.................................  The smaller of the population or
                                        19.
26-40................................  20.
41-65................................  25.
66 or more...........................  29.
------------------------------------------------------------------------

    (2) Determine sample size corresponding to a confidence level of 95 
percent, an expected error rate of 0 percent, and a maximum tolerable 
error rate of 10 percent, using conventional statistical principles and 
methods.
    (3) Determine sample size using an alternate method that is 
equivalent to or better than the methods specified in paragraphs (a)(1) 
and (2) of this section with respect to strength of inference and 
freedom from bias. Auditors that determine a sample size using an 
alternate method must describe and justify the alternate method in the 
attestation report.
    (b) Select specific data points for evaluation over the course of 
the

[[Page 29158]]

compliance period in a way that leads to a simple random sample that 
properly represents the overall population for the data set.

Sec.  1090.1810   General procedures--gasoline manufacturers.

    The procedures specified in this section apply to refiners, 
blending manufacturers, and transmix processers that produce gasoline.
    (a) Registration and EPA reports. Auditors must review registration 
and EPA reports as follows:
    (1) Obtain copies of the gasoline manufacturer's registration 
information submitted under subpart I of this part and all reports 
(except batch reports) submitted to EPA under subpart J of this part.
    (2) For each gasoline manufacturing facility, confirm that the 
facility's registration is accurate based on the activities reported 
during the compliance period, including that the registration for the 
facility and any related updates were completed prior to conducting 
regulated activities at the facility, reporting any discrepancies.
    (3) Confirm that the gasoline manufacturer submitted all the 
reports required under subpart J of this part for activities they 
performed during the compliance period, reporting any exceptions.
    (4) Obtain a written statement from the gasoline manufacturer's RCO 
that the submitted reports are complete and accurate.
    (5) Report in the attestation report the name of any commercial 
computer program used to track the data required under this part, if 
any.
    (b) Inventory reconciliation analysis. Auditors must perform an 
inventory reconciliation analysis as follows:
    (1) Obtain an inventory reconciliation analysis from the gasoline 
manufacturer for each product type produced at each facility (e.g., 
RFG, CG, RBOB, CBOB), including the inventory at the beginning and end 
of the compliance period, receipts, production, shipments, transfers, 
and gain/loss.
    (2) Foot and cross-foot the volumes.
    (3) Compare the beginning and ending inventory to the 
manufacturer's inventory records for each product type, reporting any 
variances.
    (4) Report in the attestation report the volume totals for each 
product type on the basis of which gasoline batches are reported.
    (c) Listing of tenders. Auditors must review a listing of tenders 
as follows:
    (1) Obtain detailed listings of gasoline tenders from the gasoline 
manufacturer, by product type.
    (2) Foot the listings of gasoline tenders.
    (3) Compare the total volume from the gasoline tenders to the total 
volume shipped in the inventory reconciliation analysis for each 
product type, reporting any variances.
    (d) Listing of batches. Auditors must review listings of batches as 
follows:
    (1) Obtain the batch reports submitted under subpart J of this 
part.
    (2) Foot the batch volumes by product type.
    (3) Compare the total volume from the batch reports to the total 
production or shipment volume from the inventory reconciliation 
analysis specified in paragraph (b)(4) of this section for each product 
type, reporting any variances.
    (4) Report as a finding in the attestation report any gasoline 
batch with reported values that do not meet a per-gallon standard in 
subpart C of this part.
    (e) Test methods. Auditors must follow the procedures specified in 
Sec.  1090.1845 to determine whether the gasoline manufacturer complies 
with the applicable quality control requirements specified in Sec.  
1090.1375.
    (f) Review of BOB tenders. Auditors must review a detailed listing 
of BOB tenders as follows:
    (1) Select a representative sample of PTDs from the listing of BOB 
tenders.
    (2) For each sample, obtain the associated PTDs.
    (3) Using a unique identifier, confirm that the correct PTDs are 
obtained for the samples and compare the volume on the listing of each 
selected BOB tender to the associated PTD, reporting any exceptions.
    (4) Confirm that the PTD associated with each selected BOB tender 
contains all the applicable language requirements under subpart K of 
this part, reporting any exceptions.
    (g) Detailed testing of BOB batches. Auditors must review a 
detailed listing of BOB batches as follows:
    (1) Select a representative sample from the BOB batch reports 
submitted to EPA under subpart J of this part and obtain the volume 
documentation and laboratory analysis for each sample.
    (2) Compare the reported volume for each selected sample to the 
volume documentation, reporting any exceptions.
    (3) Compare the reported properties for each selected sample BOB 
batch to the laboratory analysis, reporting any exceptions.
    (4) Compare the reported test methods used for each selected BOB 
batch to the laboratory analysis, reporting any exceptions.
    (5) Determine each oxygenate type and amount that is required for 
blending with the BOB.
    (6) Confirm that each oxygenate type and amount included in the BOB 
hand blend agrees within an acceptable range to each selected BOB 
batch, reporting any exceptions.
    (7) Confirm that the manufacturer participates in the national 
fuels survey program under subpart N of this part, if applicable.
    (8) For blending manufacturers, confirm that the laboratory 
analysis includes test results for oxygenate and distillation 
parameters (i.e., T10, T50, T90, final boiling point, and percent 
residue).
    (h) Detailed testing of finished gasoline tenders. Auditors must 
review a detailed listing of finished gasoline tenders as follows:
    (1) Select a representative sample from the listing of finished 
gasoline tenders and obtain the associated PTD for each selected 
tender.
    (2) Using a unique identifier, confirm that the correct PTDs are 
obtained for the samples and compare the volume on the listing for each 
finished gasoline tender to the associated PTD.
    (3) Confirm that the PTD associated with each selected finished 
gasoline tender contains all the applicable language requirements under 
subpart K of this part, reporting any exceptions.
    (4) Report as a finding in the attestation report any tenders where 
the PTD did not contain all applicable PTD language requirements under 
subpart K of this part, reporting any exceptions.
    (i) Detailed testing of finished gasoline batches. Auditors must 
review a detailed listing of finished gasoline batches as follows:
    (1) Select a representative sample of finished gasoline batches 
from the batch reports submitted to EPA under subpart J of this part 
and obtain the volume documentation and laboratory analysis for each 
selected finished gasoline batch.
    (2) Compare the reported volume for each selected finished gasoline 
batch to the volume documentation, reporting any exceptions.
    (3) Compare the reported properties for each selected finished 
gasoline batch to the laboratory analysis, reporting any exceptions.
    (4) Compare the reported test methods used for each selected 
finished gasoline batch to the laboratory analysis, reporting any 
exceptions.
    (5) For blending manufacturers, confirm that the laboratory 
analysis includes test results for oxygenate and distillation 
parameters (i.e., T10, T50, T90, final boiling point, and percent 
residue).

[[Page 29159]]

Sec.  1090.1815   General procedures--gasoline importers.

    The procedures of this section apply to gasoline manufacturers that 
import gasoline:
    (a) Registration and EPA reports. Auditors must review registration 
and EPA reports for gasoline importers as specified in Sec.  
1090.1810(a).
    (b) Listing of imports. Auditors must review a listing of imports 
as follows:
    (1) Obtain detailed listings of gasoline imports from the importer, 
by product type.
    (2) Foot the listings of gasoline imports from the importer.
    (3) Obtain listings of gasoline imports directly from the third-
party customs broker, by product type.
    (4) Foot the listings of gasoline imports from the third-party 
customs broker.
    (5) Compare the total volume from the importer's listings of 
gasoline imports to the listings from the third-party customs broker 
for each product type, reporting any variances.
    (6) Report in the attestation report the total imported volume for 
each product type.
    (c) Listing of batches. Auditors must review listings of batches as 
follows:
    (1) Obtain the batch reports submitted under subpart J of this 
part.
    (2) Foot the batch volumes by product type.
    (3) Compare the total volume from the batch reports to the total 
volume per the listings of gasoline imports from the importer specified 
in paragraph (b)(1) of this section for each product type, reporting 
any variances.
    (4) Report as a finding in the attestation report any gasoline 
batches with parameter results that do not meet the per-gallon 
standards in subpart C of this part.
    (d) Test methods. Auditors must follow the procedures specified in 
Sec.  1090.1845 to determine whether the importer complies with the 
quality control requirements specified in Sec.  1090.1375 for gasoline, 
gasoline additives, and gasoline regulated blendstocks.
    (e) Detailed testing of BOB imports. Auditors must review a 
detailed listing of BOB imports as follows:
    (1) Select a representative sample from the listing of BOB imports 
from the importer and obtain the associated U.S. Customs Entry Summary 
and PTD for each selected BOB import.
    (2) Using a unique identifier, confirm that the correct U.S. 
Customs Entry Summaries are obtained for the samples and compare the 
location that each selected BOB import arrived in the United States and 
volume on the listing of BOB imports from the importer to the U.S. 
Customs Entry Summary, reporting any exceptions.
    (3) Using a unique identifier, confirm that the correct PTDs are 
obtained for the samples. Confirm that the PTD contains all the 
applicable language requirements under subpart K of this part, 
reporting any exceptions.
    (f) Detailed testing of BOB batches. Auditors must review a 
detailed listing of BOB batches as follows:
    (1) Select a representative sample of BOB batches from the batch 
reports submitted under subpart J of this part and obtain the volume 
inspection report and laboratory analysis for each selected BOB batch.
    (2) Compare the reported volume for each selected BOB batch to the 
volume inspection report, reporting any exceptions.
    (3) Compare the reported properties for each selected BOB batch to 
the laboratory analysis, reporting any exceptions.
    (4) Compare the reported test methods used for each selected BOB 
batch to the laboratory analysis, reporting any exceptions.
    (5) Determine each oxygenate type and amount that is required for 
blending with each selected BOB batch.
    (6) Confirm that each oxygenate type and amount included in the BOB 
hand blend agrees within an acceptable range to each selected BOB 
batch, reporting any exceptions.
    (7) Confirm that the importer participates in the national fuels 
survey program under subpart N of this part, if applicable.
    (g) Detailed testing of finished gasoline imports. Auditors must 
review a detailed listing of finished gasoline imports as follows:
    (1) Select a representative sample from the listing of finished 
gasoline imports from the importer and obtain the associated U.S. 
Customs Entry Summary and PTD for each selected finished gasoline 
import.
    (2) Using a unique identifier, confirm that the correct U.S. 
Customs Entry Summaries are obtained for the samples and compare the 
location that each selected finished gasoline import arrived in the 
United States and volume on the listing of finished gasoline imports 
from the importer to the U.S. Customs Entry Summary, reporting any 
exceptions.
    (3) Using a unique identifier, confirm that the correct PTDs are 
obtained for the samples. Confirm that the PTD contain all the 
applicable language requirements under subpart K of this part, 
reporting any exceptions.
    (h) Detailed testing of finished gasoline batches. Auditors must 
review a detailed listing of finished gasoline batches as follows:
    (1) Select a representative sample of finished gasoline batches 
from the batch reports submitted under subpart J of this part and 
obtain the volume inspection report and laboratory analysis for each 
selected finished gasoline batch.
    (2) Compare the reported volume for each selected finished gasoline 
batch to the volume inspection report, reporting any exceptions.
    (3) Compare the reported properties for each selected finished 
gasoline batch to the laboratory analysis, reporting any exceptions.
    (4) Compare the reported test methods used for each selected 
finished gasoline batch to the laboratory analysis, reporting any 
exceptions.
    (i) Additional procedures for certain gasoline imported by rail or 
truck. Auditors must perform the following additional procedures for 
importers that import gasoline into the United States by rail or truck 
under Sec.  1090.1610:
    (1) Select a representative sample from the listing of batches 
obtained under paragraph (c) of this section and perform the following 
for each selected batch:
    (i) Identify the point of sampling and testing associated with each 
selected batch in the tank activity records from the supplier.
    (ii) Confirm that the sampling and testing occurred after the most 
recent delivery into the supplier's storage tank and before 
transferring product to the railcar or truck.
    (2)(i) Obtain a detailed listing of the importer's quality 
assurance program sampling and testing results.
    (ii) Determine whether the frequency of the sampling and testing 
meets the requirements in Sec.  1090.1610(b).
    (iii) Select a representative sample from the importer's sampling 
and testing records under the quality assurance program and perform the 
following for each selected batch:
    (A) Obtain the corresponding laboratory analysis.
    (B) Determine whether the importer analyzed the test sample, and 
whether they performed the analysis using the methods specified in 
subpart M of this part.
    (C) Review the terminal test results corresponding to the time of 
collecting the quality assurance test samples. Compare the terminal 
test results with the test results from the quality assurance program, 
noting any parameters with differences that are greater than the 
reproducibility of the

[[Page 29160]]

applicable method specified in subpart M of this part.

Sec.  1090.1820   Additional procedures for gasoline treated as 
blendstock.

    In addition to any applicable procedures required under Sec. Sec.  
1090.1810 and 1090.1815, auditors must perform the procedures in this 
section for gasoline manufacturers that import GTAB under Sec.  
1090.1615.
    (a) Listing of GTAB imports. Auditors must review a listing of GTAB 
imports as follows:
    (1) Obtain a detailed listing of GTAB imports from the GTAB 
importer.
    (2) Foot the listing of GTAB imports from the GTAB importer.
    (3) Obtain a listing of GTAB imports directly from the third-party 
customs broker.
    (4) Foot the listing of GTAB imports from the third-party customs 
broker, reporting any variances.
    (5) Compare the total volume from the GTAB importer's listing of 
GTAB imports to the listing from the third-party customs broker.
    (6) Report in the attestation report the total imported volume of 
GTAB and the corresponding facilities at which the GTAB was blended.
    (b) Listing of GTAB batches. Auditors must review a listing of GTAB 
batches as follows:
    (1) Obtain the GTAB batch reports submitted under subpart J of this 
part.
    (2) Foot the batch volumes.
    (3) Compare the total volume from the GTAB batch reports to the 
total volume from the importer's listing of GTAB imports in paragraph 
(a)(1) of this section, reporting any variances.
    (c) Detailed testing of GTAB imports. Auditors must review a 
detailed listing of GTAB imports as follows:
    (1) Select a representative sample from the listing of GTAB imports 
obtained in paragraph (a)(1) of this section.
    (2) For each selected GTAB batch, obtain the U.S. Customs Entry 
Summaries.
    (3) Using a unique identifier, confirm that the correct U.S. 
Customs Entry Summaries are obtained for the samples. Compare the 
volumes and locations that each selected GTAB batch arrived in the 
United States to the U.S. Customs Entry Summary, reporting any 
exceptions.
    (d) Detailed testing of GTAB batches. Auditors must review a 
detailed listing of GTAB batches as follows:
    (1) Select a representative sample from the batch reports obtained 
under paragraph (b)(1) of this section.
    (2) For each selected GTAB batch sample, obtain the volume 
inspection report.
    (3) Compare the reported volume for each selected GTAB batch to the 
volume inspection report, reporting any exceptions.
    (4) Compare the reported properties for the selected GTAB batches 
to the laboratory analysis, reporting any exceptions.
    (5) Compare the reported test methods used for the selected GTAB 
batches to the laboratory analysis, reporting any exceptions.
    (e) GTAB tracing. Auditors must trace and review the movement of 
GTAB from importation to use to produce gasoline as follows:
    (1) Compare the volume total on each GTAB batch report obtained 
under paragraph (b)(1) of this section to the GTAB volume total in the 
gasoline manufacturer's inventory reconciliation analysis under Sec.  
1090.1810(b).
    (2) For each selected GTAB batch under paragraph (d)(1) of this 
section:
    (i) Obtain tank activity records that describe the movement of the 
selected GTAB batch from importation to use to produce gasoline.
    (ii) Identify each selected GTAB batch in the tank activity records 
and trace each selected GTAB batch to subsequent reported batches of 
BOB or finished gasoline.
    (iii) Agree the location of the facility where gasoline was 
produced from each selected GTAB batch to the location that the GTAB 
batch arrived in the United States, or to the facility directly 
receiving the GTAB batch from the import facility.
    (iv) Determine the status of the tank(s) before receiving each 
selected GTAB batch (e.g., empty tank, tank containing blendstock, tank 
containing GTAB, tank containing PCG).
    (v) If the tank(s) contained PCG before receiving the selected GTAB 
batch, take the following additional steps:
    (A) Obtain and review a copy of the documented tank mixing 
procedures.
    (B) Determine the volume and properties of the tank bottom that was 
PCG before adding GTAB.
    (C) Confirm that the gasoline manufacturer determined the volume 
and properties of the BOB or finished gasoline produced using GTAB by 
excluding the volume and properties of any PCG, and that the gasoline 
manufacturer separately reported the PCG volume and properties under 
subpart J of this part, reporting any discrepancies.

Sec.  1090.1825   Additional procedures for PCG used to produce 
gasoline.

    In addition to any applicable procedures required under Sec.  
1090.1810, auditors must perform the procedures in this section for 
gasoline manufacturers that produce gasoline from PCG under Sec.  
1090.1320.
    (a) Listing of PCG batches. Auditors must review a listing of PCG 
batches as follows:
    (1) Obtain the PCG batch reports submitted under subpart J of this 
part.
    (2) Foot the batch volumes.
    (3) Compare the volume total for each PCG batch report to the 
receipt volume total in the inventory reconciliation analysis specified 
in Sec.  1090.1810(b), reporting any variances.
    (b) Detailed testing of PCG batches. Auditors must review a 
detailed listing of PCG batches as follows:
    (1) Select a representative sample from the PCG batch reports 
obtained under paragraph (a) of this section.
    (2) Obtain the volume documentation, laboratory analysis, 
associated PTDs, and tank activity records for each selected PCG batch.
    (3) Identify each selected PCG batch in the tank activity records 
and trace each selected PCG batch to subsequent reported batches of BOB 
or finished gasoline, reporting any exceptions.
    (4) Report as a finding in the attestation report any instances 
where the reported PCG batch volume was adjusted from the original 
receipt volume, such as for exported PCG.
    (5) Compare the volume for each selected PCG batch to the volume 
documentation, reporting any exceptions.
    (6) Compare the product type and grade for each selected PCG batch 
to the associated PTDs, reporting any exceptions.
    (7) Compare the reported properties for each selected PCG batch to 
the laboratory analysis, reporting any exceptions.
    (8) Compare the reported test methods used for each selected PCG 
batch to the laboratory analysis, reporting any exceptions.

Sec.  1090.1830  Alternative procedures for certified butane blenders.

    Auditors must use the procedures of this section instead of or in 
addition to the procedures in Sec.  1090.1810 for certified butane 
blenders that blend certified butane into PCG under the provisions of 
Sec.  1090.1320.
    (a) Registration and EPA reports. Auditors must review registration 
and EPA reports as follows:
    (1) Obtain copies of the certified butane blender's registration 
information submitted under subpart I of this part and all reports 
submitted under subpart J of this part, including the batch reports for 
the butane received and blended.

[[Page 29161]]

    (2) For each certified butane blending facility, confirm that the 
facility's registration is accurate based on activities reported during 
the compliance period, including that the registration for the facility 
and any related updates were completed prior to conducting regulated 
activities at the facility, reporting any discrepancies.
    (3) Confirm that the certified butane blender submitted the reports 
required under subpart J of this part for activities they performed 
during the compliance period, reporting any exceptions.
    (4) Obtain a written statement from the certified butane blender's 
RCO that the submitted reports are complete and accurate.
    (5) Report in the attestation report the name of any commercial 
computer program used to track the data required under this part, if 
any.
    (b) Inventory reconciliation analysis. Auditors must complete an 
inventory reconciliation analysis review as follows:
    (1) Obtain an inventory reconciliation analysis from the certified 
butane blender for each blending facility related to all certified 
butane movements, including the inventory at the beginning and end of 
the compliance period, receipts, blending/production volumes, 
shipments, transfers, and gain/loss.
    (2) Foot and cross-foot the volumes.
    (3) Compare the beginning and ending inventory to the certified 
butane blender's inventory records, reporting any variances.
    (4) Compare the total volume of certified butane received from the 
batch reports obtained under paragraph (a) of this section to the 
inventory reconciliation analysis, reporting any variances.
    (5) Compare the total volume of certified butane blended from the 
batch reports to the inventory reconciliation analysis, reporting any 
variances.
    (6) Report in the attestation report the total volume of certified 
butane received and blended.
    (c) Listing of certified butane receipts. Auditors must review a 
listing of certified butane receipts as follows:
    (1) Obtain a detailed listing of all certified butane batches 
received at the blending facility from the certified butane blender.
    (2) Foot the listing of certified butane batches received.
    (3) Compare the total volume from batch reports for certified 
butane received at the butane blending facility to the certified butane 
blender's listing of certified butane batches received, reporting any 
variances.
    (d) Detailed testing of certified butane batches. Auditors must 
review a detailed listing of certified butane batches as follows:
    (1) Select a representative sample from the certified butane batch 
reports submitted under subpart J of this part.
    (2) Obtain the volume documentation and laboratory analysis for 
each selected certified butane batch.
    (3) Compare the reported volume for each selected certified butane 
batch to the volume documentation, reporting any exceptions.
    (4) Compare the reported properties for each selected certified 
butane batch to the laboratory analysis, reporting any exceptions.
    (5) Compare the reported test methods used for each selected 
certified butane batch to the laboratory analysis, reporting any 
exceptions.
    (6) Confirm that the butane meets the standards for certified 
butane under subpart C of this part, reporting any exceptions.
    (e) Quality control review. Auditors must obtain the certified 
butane blender's sampling and testing results for certified butane 
received and determine if the frequency of the sampling and testing 
meets the requirements in Sec.  1090.1320(c)(4), reporting any 
discrepancies.

Sec.  1090.1835   Alternative procedures for certified pentane 
blenders.

    (a) Auditors must use the procedures of this section instead of or 
in addition to the procedures in Sec. Sec.  1090.1810 and 1090.1815, as 
applicable, for certified pentane blenders that blend certified pentane 
into PCG under the provisions of Sec.  1090.1320.
    (b) Auditors must apply the procedures in Sec.  1090.1830 by 
substituting ``pentane'' for ``butane'' in all cases.

Sec.  1090.1840  Additional procedures related to compliance with 
gasoline average standards.

    Auditors must perform the procedures of this section for gasoline 
manufacturers that comply with the standards in subpart C of this part 
using the procedures specified in subpart H of this part.
    (a) Annual compliance demonstration review. Auditors must review 
annual compliance demonstrations as follows:
    (1) Obtain the annual compliance reports for sulfur and benzene and 
associated batch reports submitted under subpart J of this part.
    (2)(i) For gasoline refiners and blending manufacturers, compare 
the gasoline production volume from the annual compliance report to the 
inventory reconciliation analysis under Sec.  1090.1810(b), reporting 
any variances.
    (ii) For gasoline importers, compare the gasoline import volume 
from the annual compliance report to the corresponding volume from the 
listing of imports under Sec.  1090.1815(b), reporting any variances.
    (3) For each facility, recalculate the following and report in the 
attestation report the recalculated values:
    (i) Compliance sulfur value, per Sec.  1090.700(a)(1), and 
compliance benzene value, per Sec.  1090.700(b)(1).
    (ii) Average benzene concentration, per Sec.  1090.700(b)(3).
    (iii) Number of credits generated during the compliance period, or 
number of banked or traded credits needed to meet standards for the 
compliance period.
    (iv) Number of credits from the preceding compliance period that 
are expired or otherwise no longer available for the compliance period 
being reviewed.
    (4) Compare the recalculated values in paragraph (a)(3) of this 
section to the reported values in the annual compliance reports, 
reporting any exceptions.
    (5) Report in the attestation report whether the gasoline 
manufacturer had a deficit for both the compliance period being 
reviewed and the preceding compliance period.
    (b) Credit transaction review. Auditors must review credit 
transactions as follows:
    (1) Obtain the gasoline manufacturer's credit transaction reports 
submitted under subpart J of this part and contracts or other 
information that documents all credit transfers. Also obtain records 
that support intracompany transfers.
    (2) For each reported transaction, compare the supporting 
documentation with the credit transaction reports for the following 
elements, reporting any exceptions:
    (i) Compliance period of creation.
    (ii) Credit type (i.e., sulfur or benzene) and number of times 
traded.
    (iii) Quantity.
    (iv) The name of the other company participating in the credit 
transfer.
    (v) Transaction type.
    (c) Facility-level credit reconciliation. Auditors must perform a 
facility-level credit reconciliation separately for each gasoline 
manufacturing facility as follows:
    (1) Obtain the credits remaining or the credit deficit from the 
previous compliance period from the gasoline manufacturer's credit 
transaction information for the previous compliance period.

[[Page 29162]]

    (2) Compute and report as a finding the net credits remaining at 
the end of the compliance period.
    (3) Compare the ending balance of credits or credit deficit 
recalculated in paragraph (c)(2) of this section to the corresponding 
value from the annual compliance report, reporting any variances.
    (4) For importers, the procedures of this paragraph (c) apply at 
the company level.
    (d) Company-level credit reconciliation. Auditors must perform a 
company-level credit reconciliation as follows:
    (1) Obtain a credit reconciliation listing company-wide credits 
aggregated by facility for the compliance period.
    (2) Foot and cross-foot the credit quantities.
    (3) Compare and report the beginning balance of credits, the ending 
balance of credits, the associated credit activity at the company level 
in accordance with the credit reconciliation listing, and the 
corresponding credit balances and activity submitted under subpart J of 
this part.
    (e) Procedures for gasoline manufacturers that recertify BOB. 
Auditors must perform the following procedures for any gasoline 
manufacturer that recertifies a BOB under Sec.  1090.740 and incurs a 
deficit:
    (1) Auditors must perform the procedures specified in Sec.  
1090.1810(a) to review registration and EPA reports.
    (2) Obtain the batch reports for recertified BOB submitted under 
subpart J of this part.
    (3) Select a representative sample of recertified BOB batches from 
the batch reports.
    (4) For each sample, obtain supporting documentation.
    (5) Confirm the accuracy of the information reported, reporting any 
exceptions.
    (6) Recalculate the deficits in accordance with the provisions of 
Sec.  1090.740, reporting any discrepancies.
    (7) Confirm that the deficits are included in the annual compliance 
demonstration calculations, reporting any exceptions.

Sec.  1090.1845   Procedures related to meeting performance-based 
measurement and statistical quality control for test methods.

    (a) General provisions. (1) Auditors must conduct the procedures 
specified in this section for gasoline manufacturers.
    (2) Auditors performing the procedures specified in this section 
must meet the laboratory experience requirements specified in Sec.  
1090.55(b)(2).
    (3) In cases where the auditor needs to involve an external 
specialist, all the requirements of Sec.  1090.55 apply to the external 
specialist. The auditor is responsible for overseeing the work of the 
specialist, consistent with applicable professional standards specified 
in Sec.  1090.1800.
    (4) In the case of quality control testing at a third-party 
laboratory, the auditor may perform a single attestation engagement on 
the third-party laboratory for multiple gasoline manufacturers if the 
auditor directly reviewed the information from the third-party 
laboratory.
    (b) Non-referee method review. For each test method used to measure 
a parameter for gasoline as specified in a report submitted under 
subpart J of this part that is not one of the referee methods listed in 
Sec.  1090.1360(d), the auditor must:
    (1) Obtain supporting documentation showing that the laboratory has 
qualified the test method by meeting the precision and accuracy 
criteria specified under Sec.  1090.1365.
    (2) Report in the attestation report a list of the alternative 
methods used.
    (3) Report as a finding in the attestation report any of these test 
methods that have not been qualified by the facility.
    (4) If an auditor has previously reviewed supporting documentation 
under this paragraph for an alternative method at the facility, the 
auditor does not have to review the supporting document again.
    (c) Reference installation review. For each reference installation 
used by the gasoline manufacturer during the compliance period, the 
auditor must review the following:
    (1) Obtain supporting documentation demonstrating that the 
reference installation followed the qualification procedures specified 
in Sec.  1090.1370(c)(1) and (2) and the quality control procedures 
specified in Sec.  1090.1370(c)(3).
    (2) Report as a finding in the attestation report any of the 
qualification procedures that were not completed by the facility.
    (d) Instrument control review. For each test instrument used to 
test gasoline parameters for batches selected as part of a 
representative sample under Sec.  1090.1810, the auditor must review 
whether test instruments were in control as follows:
    (1) Obtain statistical quality assurance data and control charts 
demonstrating ongoing quality testing to meet the accuracy and 
precision requirements specified in Sec.  1090.1375.
    (2) Report as a finding in the attestation report any instruments 
for which the facility failed to perform statistical qualtiy assurance 
monitoring under Sec.  1090.1375.
    (3) Report as a finding in the attestation report the instrument 
list obtained under paragraph (b)(1) of this section and the compliance 
period when the instrument control review was completed.

Sec.  1090.1850   Procedures related to in-line blending waivers.

    In addition to any other procedure required under this subpart, 
auditors must perform the procedures specified in this section for 
gasoline refiners that rely on an in-line blending waiver under Sec.  
1090.1315.
    (a) Obtain a copy of the refiner's in-line blending waiver 
submission and EPA's approval letter.
    (b) Confirm that the refiner uses the in-line blending waiver only 
for qualified operations as specified in Sec.  1090.1315(a).
    (c) Confirm that the sampling procedures and composite calculations 
conform to specifications as specified in Sec.  1090.1315(b)(2).
    (d) Review the refiner's procedure for defining a batch for 
compliance purposes. Review available test data demonstrating that the 
test results from in-line blending correctly characterize the fuel 
parameters for the designated batch.
    (e) Confirm that the refiner corrected their operations because of 
previous audits, if applicable.
    (f) Confirm that the equipment and procedures are not materially 
changed from the refiner's in-line blending waiver. Report in the 
attestation report whether the refiner has failed to update their in-
line blending waiver based on a material change in equipment or 
procedure.
    (g) Report in the attestation report whether the refiner has 
complied with all provisions related to their in-line blending waiver.

[FR Doc. 2020-09337 Filed 5-13-20; 8:45 am]
 BILLING CODE 6560-50-P