2020-23164. Fuels Regulatory Streamlining

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Final rule.

SUMMARY:

This action updates many of EPA's existing gasoline, diesel, and other fuel quality programs to improve overall compliance assurance and maintain environmental performance, while reducing compliance costs for industry and EPA. EPA is streamlining existing fuel quality regulations by removing expired provisions, eliminating redundant compliance provisions (e.g., duplicative registration requirements that are required by every EPA fuels program), removing unnecessary and out-of-date requirements, and replacing them with a single set of provisions and definitions that applies to all gasoline, diesel, and other fuel quality programs. This action does not change the stringency of the existing fuel quality standards.

DATES:

This rule is effective on January 1, 2021, except for amendatory instructions 48, 51, and 52, which are effective on December 4, 2020, and amendatory instructions 16, 18, and 19, which are effective on January 1, 2022. The incorporation by reference of certain publications listed in this regulation is approved by the Director of the Federal Register as of December 4, 2020. The incorporation by reference of ASTM D86-12, D93-13, D445-12, D613-13, D4052-11, and D5186-03 (R2009) in part 1065 was approved by the Director of the Federal Register as of June 27, 2014.

ADDRESSES:

EPA has established a docket for this action under Docket ID No. EPA-HQ-OAR-2018-0227. All documents in the docket are listed on the https://www.regulations.gov website. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material is not available on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available electronically through https://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT:

Nick Parsons, Office of Transportation and Air Quality, Assessment and Standards Division, Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 48105; telephone number: 734-214-4479; email address: [e-mail].

SUPPLEMENTARY INFORMATION:

Does this action apply to me?

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

Category	NAICS 1 code	Examples of potentially affected entities
Industry	211130	Natural gas liquids extraction and fractionation.
Industry	221210	Natural gas production and distribution.
Industry	324110	Petroleum refineries (including importers).
Industry	325110	Butane and pentane manufacturers.
Industry	325193	Ethyl alcohol manufacturing.
Industry	325199	Manufacturers of gasoline additives.
Industry	424710	Petroleum bulk stations and terminals.
Industry	424720	Petroleum and petroleum products wholesalers.
Industry	447110, 447190	Fuel retailers.
Industry	454310	Other fuel dealers.
Industry	486910	Natural gas liquids pipelines, refined petroleum products pipelines.
Industry	493190	Other warehousing and storage—bulk petroleum storage.
1 North American Industry Classification System (NAICS).

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be affected by this action. This table lists the types of entities that EPA is now aware could potentially be affected by this action. Other types of entities not listed in the table could also be affected. To determine whether your entity would be affected by this action, you should carefully examine the applicability criteria in 40 CFR part 1090. If you have any questions regarding the applicability of this action to a particular entity, consult the person listed in the FOR FURTHER INFORMATION CONTACT section.

Table of Contents

I. Executive Summary

A. Overview of Fuels Regulatory Streamlining

B. Summary of Stakeholder Involvement and Rule Development

C. Timing

D. Costs and Benefits

II. Changes to Other Parts of Title 40

III. Structure of Regulations and General Provisions

A. Structure of the Regulations

B. Implementation Dates

C. Prior Approvals

D. Definitions

IV. General Requirements for Regulated Parties

V. Standards

A. Gasoline Standards

B. Diesel Fuel

VI. Exemptions, Hardships, and Special Provisions

A. Exemptions

B. Exports

C. Extreme, Unusual, and Unforeseen Hardships

VII. Averaging, Banking, and Trading Provisions

A. Overview

B. Compliance on Average

C. Deficit Carryforward

D. Credit Generation, Use, and Transfer

E. Invalid Credits

F. Downstream Oxygenate Accounting

G. Downstream BOB Recertification

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

A. Overview

B. Registration

C. Reporting

D. Product Transfer Documents (PTDs)

E. Recordkeeping

F. Rounding

G. Certification and Designation of Batches

IX. Sampling, Testing, and Retention Requirements

A. Overview and Scope of Testing

B. Handling and Testing Samples

C. Measurement Procedures

X. Third-Party Survey Provisions

A. National Survey Program

B. National Sampling and Testing Oversight Program

XI. Import of Fuels, Fuel Additives, and Blendstocks

A. Importation

B. Special Provisions for Importation by Rail or Truck

C. Special Provisions for Importation by Marine Vessel

D. Gasoline Treated as Blendstocks

XII. Compliance and Enforcement Provisions and Attest Engagements

A. Compliance and Enforcement Provisions

B. Attest Engagements

C. RVP Test Enforcement Tolerance

XIII. Other Requirements and Provisions

A. Requirements for Independent Parties

B. Labeling

C. Refueling Hardware Requirements for Dispensing Facilities and Motor Vehicles

D. Previously Certified Gasoline (PCG)

E. Transmix and Pipeline Interface Provisions

F. Gasoline Deposit Control

G. In-Line Blending Waivers

H. Confidential Business Information

XIV. Costs and Benefits

A. Overview

B. Reduced Fuel Costs to Consumers From Improved Fuel Fungibility

C. Costs and Benefits for Regulated Parties

D. Environmental Impacts

XV. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review

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

C. Paperwork Reduction Act (PRA)

D. Regulatory Flexibility Act (RFA)

E. Unfunded Mandates Reform Act (UMRA)

F. Executive Order 13132: Federalism

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

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

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

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

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

L. Congressional Review Act (CRA)

XVI. Statutory Authority

I. Executive Summary

A. Overview of Fuels Regulatory Streamlining

1. Why EPA Is Taking This Action

In this action, we are streamlining and modernizing our 40 CFR part 80 (“part 80”) fuel quality regulations to minimize the implementation burden associated with them while still ensuring that the fuel quality standards previously established under the Clean Air Act (CAA) continue to be met in real-world use. We are doing so by transferring the relevant part 80 provisions into a new set of regulations in 40 CFR part 1090 (“part 1090”). After taking a detailed look at the many different and overlapping requirements in the part 80 regulations, it became apparent that a holistic update to the regulations was better accomplished by redrafting them into an entirely new part. The new part 1090 regulations will also better reflect how fuels, fuel additives, and regulated blendstocks are produced, distributed, and sold in today's marketplace and help regulated parties more easily identify regulatory requirements.

2. What Is and Is Not Covered in This Action

This action focuses primarily on streamlining and consolidating the gasoline and diesel fuel programs that reside in part 80.^[1] To accomplish this, we are removing expired provisions and consolidating the remaining provisions from multiple fuel quality programs into a single set of provisions. This action covers almost all fuel programs and related provisions currently in part 80. These programs include, but are not limited to, the reformulated gasoline (RFG) program, the anti-dumping program, the diesel sulfur program, the gasoline benzene program, the gasoline sulfur programs, the E15 misfueling mitigation program, and the national fuel detergent program. This streamlining action combines these separate, now fully-implemented programs, all of which affect the same regulated parties, into a single, national fuel quality program.

The majority of this action's changes focus on consolidating and streamlining compliance provisions currently in part 80, not on adding new compliance requirements for regulated parties. This action also does not impose any new standards on fuels. As such, this action is mostly a compilation of numerous, relatively minor changes to the existing provisions under part 80. Many of these changes may appear disconnected from one another, as they are addressing a specific technical area that needs consolidation, streamlining, and/or updating. Together, however, these changes will lead to a more effective, efficient EPA fuel quality program.

While this action changes many aspects of our fuel quality programs, there are several areas of the part 80 regulations that remain unchanged even as those regulations are transposed into part 1090. Most importantly, this action does not change the stringency of the existing fuel quality standards. We are simply streamlining and consolidating the part 80 fuel quality programs into a single streamlined fuel quality program that will make compliance with the existing fuel quality standards established under part 80 more straightforward to implement and comply with. As a result, in addition to reducing costs, it may also enable improved fuel quality through increased compliance with our fuel quality standards. This action transfers the part 80 fuel quality standards mostly unchanged to part 1090, though in some cases we are modifying the form of a standard to translate it into a format more conducive to streamlining the regulations and ensuring in-use compliance.

With minor exceptions, this action also does not change the provisions of the RFS program, which will remain in subpart M of part 80, The subpart M regulations are mostly unique to the RFS program. However, since the RFS program uses similar, if not the same, reporting systems and compliance mechanisms for parties to demonstrate compliance, we are finalizing some parallel changes to help ensure that this consistency is maintained or enhanced as a result of this action. This will help ensure consistency in how parties comply with our regulatory requirements and report information to EPA. We received a number of comments asking for more substantive changes to the RFS program; we consider these comments outside the scope of this rulemaking.^[2]

Finally, this action does not remove any statutory requirement for fuels specified by the CAA. For example, this action does not remove limits on lead levels in gasoline under CAA section 211(n), remove the requirement that all gasoline be additized with detergents under CAA section 211(l), or remove cetane index limits for diesel fuel under CAA section 211(g) and (i). While this action does update some of the provisions put in place to implement many provisions of the CAA, and in some cases substantially streamline the implementing regulations, we are not eliminating any requirement under the CAA for fuels and parties that make, distribute, and sell such fuels.

We recognize that while we are not changing the standards, in some cases, the consolidation of certain provisions may slightly, indirectly affect in-use fuel quality. For example, changes to how parties record and report test results that fall below the test method's lower limits of detection might cause parties to have to report slightly higher sulfur and benzene levels in gasoline, effectively improving in-use fuel quality by slightly decreasing the national annual average sulfur level. On the other hand, the provisions that make it easier for fuel manufacturers of conventional gasoline (CG) to account for oxygenates (e.g., ethanol) added downstream of the manufacturing facility, thereby allowing for a slightly lower reported level of gasoline benzene and sulfur levels, might be perceived as slightly decreasing in-use fuel quality. There are many such minor impacts of changes in part 1090 and we believe that on balance the streamlined fuels program will maintain the same overall level of fuel quality as the part 80 regulations. We discuss the cumulative costs and benefits of these changes in more detail in Section XIV.

3. Program Design

The new part 1090 is designed to reduce compliance burdens for both industry and EPA, potentially lower fuel costs for consumers, and maintain fuel quality. To accomplish these goals, we have taken action on three key elements that are included in part 1090:

• A simplification of the RFG summer volatile organic compound (VOC) standards.^[3]

• A consolidation of the regulatory requirements across the part 80 fuel quality programs.
• Improving oversight through the leveraging of third parties to ensure in-use fuel quality.

First, we are simplifying the RFG standards by translating the part 80 summer RFG VOC standard into an RVP per-gallon cap of 7.4 psi. This change allows us to remove the use of the Complex Model ^[4] as a requirement to certify batches of gasoline and remove all the provisions associated with demonstrating compliance on average. This change also allows for us to minimize the restrictions on the commingling of RFG and CG, allowing for a more fungible and efficient gasoline distribution system.

Under part 80, the main remaining difference between RFG and CG is the summer volatility. Under part 80, RFG's volatility is functionally controlled through a summer VOC performance standard determined with the Complex Model pursuant to CAA section 211(k). In contrast, CG volatility is controlled through the RVP per-gallon maximum standards established under CAA section 211(h). EPA has previously aligned the treatment of RFG and CG for NO_X performance through the Tier 2 gasoline sulfur program and toxics performance through the national gasoline benzene program.^[5] This action aligns treatment for RFG and CG by translating the existing RFG VOC performance standard into a maximum RVP per-gallon standard, as is the case for CG in the summer. In Section V.A.2, we describe how the summer RVP per-gallon cap of 7.4 psi equates to the existing RFG summer VOC standards. This change alone allows for the removal of the sampling, testing, and reporting requirements associated with several Complex Model parameters, greatly simplifying compliance with our fuel quality standards. With this translation of the RFG summer VOC performance standards into a summer RFG maximum RVP per-gallon standard, the required controls on RFG fuel properties will be identical to the control of CG fuel properties, even though the RVP standards themselves will remain different.

Second, since the standards for volatility, benzene, and sulfur will be treated similarly for both RFG and CG, this will allow for the streamlining and consolidation of the compliance and enforcement provisions of the various part 80 gasoline quality programs into a single fuel quality program in part 1090. This consolidation will improve consistency, remove duplication, and ultimately reduce compliance burden on both regulated parties and EPA. For example, under part 80, we require quarterly batch reports for RFG, versus annual reports for CG. We also require separate batch reports for the gasoline benzene and gasoline sulfur programs. In part 1090, we are consolidating the various gasoline reporting requirements into a single, unified annual reporting requirement.

Third, the streamlined fuel quality program aims to improve oversight of our fuel quality programs while reducing its cost. We hope to accomplish this by updating and improving the third-party oversight programs we already use in part 80. In part 1090, we are consolidating the four existing in-use survey programs into a single national in-use fuel quality survey. This program will help ensure that all fuels nationwide continue to meet EPA fuel quality standards when dispensed into vehicles and engines, not just at the fuel manufacturing facility gate. We are also replacing the RFG independent lab testing requirement with a voluntary national sampling and testing oversight program (NSTOP). The NSTOP will impose substantially lower costs across industry than the current regulations while helping to ensure the consistency of sampling and testing across industry. Finally, we are updating and modernizing the annual attest engagement program. These updated procedures will help ensure the quality and consistency of reported information. Taken together, we believe these provisions will help improve oversight of our streamlined fuel quality program.

B. Summary of Stakeholder Involvement and Rule Development

We actively engaged stakeholders throughout the development of this action to help maximize its potential effectiveness. Due to the number of affected stakeholders, the complexity surrounding the production and distribution of fuels, and the broad scope of this action, active stakeholder involvement was necessary to help ensure that the fuels regulatory streamlining program achieved its goals and that the final regulations were ready for a smooth implementation. This included making available four discussion drafts of the proposed regulations on our Fuels Regulatory Streamlining website.^[6] We also held a three-day public workshop on a variety of topics in Chicago on May 21-23, 2018.^[7] During this workshop, EPA staff discussed a variety of issues related to the development of this action to an audience of over 120 affected stakeholders. The streamlined fuel quality program in this action reflects the valuable input of all those who provided feedback to EPA both before and after the proposal.

C. Timing

As discussed in more detail in Section III.B, most of the part 1090 regulations will replace the existing part 80 regulations on January 1, 2021. We believe that having an implementation date at the beginning of a new compliance period will provide for a smooth transition to the new regulatory requirements. This is supported by commenters who have had to prepare for this transition. However, we also received a number of comments requesting that certain provisions begin implementation at a later date due to the short lead time available. As discussed in Section III.B, we are allowing certain provisions to begin implementation at a later date.

D. Costs and Benefits

We do not anticipate changes in air quality as a result of this action. This is largely due to the fact that we are not making changes to the existing fuel quality standards. As such, we do not expect that regulated parties will need to make significant changes to how fuels are made, distributed, and sold, which are the factors EPA typically considers when determining the costs associated with imposing or changing fuel quality standards.

We believe that this action will result in savings to regulated parties and EPA by simplifying compliance with our fuel quality standards and by allowing greater flexibility in the manufacture and distribution of fuels. These savings largely arise from the reduction of the administrative costs on both regulated parties and EPA in complying with and implementing the existing fuel quality standards. We estimate the annualized total costs savings in administrative cost savings to industry to be $40.4 million per year ($2019). Other savings associated with improving the fungibility of fuel and providing greater flexibility could potentially be even more significant but we have been unable to quantify these savings. Section XIV discusses in more detail the potential costs and benefits of this action.

II. Changes to Other Parts of Title 40

We are transferring several provisions in part 80 that are currently in effect to part 1090. These provisions are all discussed in the subsequent sections of this preamble and are now presented in a manner that makes them easier to understand. Within part 80, we are also removing subparts D, E, F, G, H, I, J, K, L, N, and O and appendices A and B to part 80 in their entirety, along with most of subpart B. Some of these subparts have either expired (e.g., designate and track provisions for diesel fuel) or have been replaced by newer subparts (e.g., subpart K (RFS1) was superseded by subpart M (RFS2), subpart H (Tier 2 Sulfur) was superseded by subpart O (Tier 3 Sulfur), and subpart J (MSAT1) was supplanted by subpart L (MSAT2)). However, in order to help enable the transition from part 80 to part 1090 and since a number of 2020 compliance demonstration requirements have deadlines in 2021 (e.g., reporting, attest engagements), these part 80 provisions will remain in the CFR until the end of 2021.

We are not transferring some provisions from part 80 to part 1090. First, we are retaining the current RFS provisions in subpart M. We are making minor edits to subpart M that are intended to ensure consistency with the new language used in part 1090. These edits will not affect any of the actual requirements in subpart M, but rather will homogenize the language used across all of our fuels programs.

Second, because we are retaining the RFS program in part 80, we need to maintain certain general provisions contained in subpart A that will continue to apply to the RFS program. We are also revising several sections within subpart A to remove requirements, such as definitions that would no longer be applicable to part 80. In addition, we are reorganizing and consolidating the definitions in 40 CFR 80.2 to place them in alphabetical order, as this will make it consistent with part 1090 and much easier to find terms.

Third, we are also retaining the Oxygenated Gasoline provisions in subpart C in part 80. This subpart contains a single section related to a requirement for labeling of oxygenated gasoline at retail pumps, as mandated by CAA section 211(m)(4). We are maintaining this requirement in part 80 because some state oxygenated fuel programs may reference the labeling requirements in part 80 and we want to minimize the amount of changes needed by states to revise regulations and update state implementation plans.

Finally, we received a comment concerning how to adapt or apply the filler-neck requirements for current and future vehicle designs. The commenter suggested that it would be inappropriate for EPA to carry-forward these provisions without significant changes to address issues related to current and future vehicle designs and that such an effort should be taken in a future rulemaking that specifically addresses these issues. We agree with commenter's suggestion to address these issues in a later rulemaking as such modifications to the filler-neck requirements were not proposed and thus, are outside the scope of this rulemaking. As a result, we are not finalizing the movement of the filler-neck provisions of 40 CFR 80.24 to part 1090. Those provisions in part 80 will continue to apply.

In addition, several commenters identified cross-references to part 80 in other parts of Title 40 that need to be revised to instead reference part 1090. We have made the revisions identified by the commenters and have updated cross-references in 40 CFR parts 60, 63, and 1043. We similarly determined that there were references to part 80 in 40 CFR parts 1042 and 1065. Most of these updated cross-references simply correct citations. These changes are discussed in more detail in Section 2 of the RTC document.

III. Structure of Regulations and General Provisions

This section describes the general structure of part 1090 (i.e., the modified structure of the regulations to make them more accessible to users and readers of the regulations). This section also describes implementation dates, how we will treat prior approvals made under part 80, and our approach to consolidating the existing definitions in part 80. Finally, this section discusses key provisions (e.g., the definition of fuels) in more detail, as these provisions are fundamental to the streamlined fuel quality program.

A. Structure of the Regulations

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

Under part 1090, subpart A contains general requirements that apply throughout the rest of the part. Subpart A includes regulatory language that generally outlines the applicability and scope of the regulation, defines key terms, and outlines when the part 1090 requirements come into effect. Subpart A also describes how requirements under part 1090 interact with other parts of the regulations that affect fuels—parts 79 and 80. Many of these provisions are described elsewhere in this preamble; for example, rounding of data is discussed Section VIII.F and batch numbering is discussed in Section VIII.G.

We are also including a list of general regulatory requirements for parties in subpart B. This subpart lays out the general regulatory requirements for regulated parties. This will help inform the regulated community of what is generally expected of them in a succinct manner and provides references to the specific requirements in the appropriate places in the regulations. While the roadmap in subpart B does not remove or modify any of the regulatory obligations required throughout the rest of part 1090, we believe it will serve as a helpful guide. We received feedback from several stakeholders that such a roadmap would be helpful for them to find and follow the regulatory requirements in part 1090 and would be especially helpful to those new to the regulations.

We also placed the standards for different fuels in separate subparts so as to make it easier for parties to identify the specific standards that apply to each fuel, regulated blendstock, and additive. We placed the gasoline-related standards and the diesel-related (plus IMO marine fuel) standards separately in subparts C and D, respectively. We are leaving subpart E reserved, as we may need to use that subpart for future standards and this will enable us to maintain subsequent subparts to avoid unnecessary confusion within regulated community.

The next block of subparts (F through Q) involve the provisions and requirements that regulated parties are expected to follow to demonstrate compliance with the applicable standards. We have consolidated the specific types of compliance activities where possible (e.g., we have consolidated all the registration sections of part 80 into subpart I). For these subparts, we have included general provisions that apply to all regulated parties, with sections devoted to specific requirements for individual groups of regulated parties (e.g., gasoline manufacturer or oxygenate blenders).

Subpart R includes the liability, compliance, and violation provisions that EPA will use to enforce the program. This subpart consolidates the similar sections from across part 80 into a single streamlined subpart.

Finally, subpart S includes the attest engagement procedures that auditors will use to conduct annual auditing of reports and records for gasoline manufacturers. These procedures are updated versions of the those previously included in part 80.

We believe that this new structure will make the fuel quality regulations more accessible to all stakeholders, help ensure compliance by making requirements more easily identifiable by activity and help future participants in this regulated space understand our fuel quality regulations in the future. In general, comments received on the structure were supportive of the ease and clarity with which regulatory requirements were laid out. Therefore, we are finalizing the regulatory structure in part 1090 as proposed.

B. Implementation Dates

We are finalizing the implementation date for most provisions of part 1090 on January 1, 2021. This implementation date will result in the first compliance reports under the new part 1090 regulations being due March 31, 2022, for the 2021 compliance period, and the first attest engagement reports being due June 1, 2022.

We believe that this schedule minimizes the need for immediate changes to how regulated parties comply with our fuel quality regulations, and therefore will allow sufficient time for regulated parties to modify their current business practices whenever it makes the most business sense for the individual regulated party's situation. In general, we have tried to minimize changes to existing requirements for regulated parties so as to avoid unnecessary burden. However, to consolidate the RFG program with the other fuel quality programs and maximize fuel fungibility, some changes to the program design will result from consolidating the programs into a single national program. Where possible, we wrote the requirements to allow flexibility for regulated parties to adjust as needed. We also believe that this schedule honors the significant effort and commitment that those impacted by the regulations have already put into their plans to transition from part 80 to part 1090 compliance.

In the NPRM, we sought comment on whether regulated parties needed more lead time to comply with any of the proposed regulatory provisions. While we received strong support for most provisions beginning on January 1, 2021, we received many comments suggesting that certain provisions of part 1090 be implemented at a later date to provide sufficient lead time but without impacting the overall implementation schedule. In particular, commenters highlighted the product transfer document (PTD) requirements and the NSTOP provisions as two areas where more lead time is needed.

For PTDs, several commenters suggested that it will take several months to modify computer systems to print the appropriate language on PTDs and work with pipelines and other distributors of fuels to develop the necessary product codes to comply with the part 1090 PTD requirements. They expressed concern that the time between when this action is finalized and its implementation on January 1, 2021, may not allow sufficient lead time, and suggested that we allow regulated parties to begin complying with the PTD provisions no later than May 1, 2021. This would then coincide with the next natural change in the marketplace with the onset of the summer RVP requirements in gasoline. Since the need for PTD changes is also less important prior to May 1, 2021, as RFG and CG are fungible in the winter under part 1090, we are delaying the PTD implementation date until May 1, 2021, as requested. However, parties may opt to comply with the part 1090 PTD requirements earlier than May 1, 2021.

Regarding the NSTOP, parties noted that the mechanics of signing up with an independent surveyor, having EPA approve a plan, and then to begin having the independent surveyor obtain samples from fuel manufacturing facilities would require several months. Commenters also noted that since the program was new, there were several details that would need to be worked out in advance prior to the NSTOP being able to be implemented. Commenters also requested that if EPA did grant more lead time for the NSTOP, that the number of visits under the NSTOP should be adjusted to account for the fact that the program would not run for the entire 2021 compliance period. We believe it is both reasonable to provide more lead time for the NSTOP and that the number of visits under the NSTOP should be adjusted accordingly. Therefore, we are allowing the NSTOP to begin no later than June 1, 2021, as suggested by the commenters. We believe that this will provide enough lead time for fuel manufacturers to register with the program, the independent surveyor to have a plan approved by EPA, and for the independent surveyor to begin visiting fuel manufacturing facilities. We are also only requiring the independent surveyor to visit participating fuel manufacturing facilities one time during the 2021 compliance period instead of the typical two visits. Since our goal is to maximize participation in this voluntary program, we believe providing more lead time and reducing the number of required visits in 2021 will help incentivize fuel manufacturers to participate in the program.

We address other comments related to implementation dates and lead times in Section 4 of the response to comments (RTC) document.

C. Prior Approvals

We are allowing regulated parties with existing approvals under part 80 to maintain those approvals under part 1090. For example, parties registered under part 80 will not need to re-register under part 1090. We believe that making regulated parties resubmit information already reviewed and approved by EPA would be duplicative and burdensome on both the regulated parties and EPA staff, and also not be consistent with the purposes of regulatory streamlining. However, this action requires that any new requests or updates to approvals currently necessary under part 80 will have to meet the new regulatory requirements of part 1090.

For existing approvals under part 80, regulated parties do not need to update any previously approved submission under part 1090. For example, we have approved alternative E15 labels under part 80. Parties do not need to have these labels reapproved in order to use them under part 1090. One notable exception is for in-line blending waivers for gasoline. As discussed more in Section XIII.G, we are making significant changes to the in-line blending waiver provisions for RFG (mostly to remove provisions related to parameters that will no longer need to be reported) and for CG to make them consistent with the RFG in-line blending waiver provisions. As such, we are requiring resubmission of all in-line blending waiver requests to ensure that they meet the new requirements under part 1090.

Commenters were supportive of our proposed treatment of prior approvals from part 80 under part 1090 and we are finalizing as proposed. We address these comments in Section 4 of the RTC document.

D. Definitions

In part 1090, we are streamlining and updating the definitions contained throughout part 80, as well as adding and removing terms as needed to write the part 1090 regulations. How we define key terms in the regulations has a significant effect on how regulated parties comply with the regulations. As our fuel quality programs have expanded in scope, definitions in part 80 have expanded as well. Additionally, as we have added additional subparts to part 80 for each new fuels program, we have added subpart-specific definitions. We have also defined terms in the context of specific sections of the regulations. This has created situations where sometimes there are differences in definitions of the same term for the different standards, making it more difficult for parties to comprehend and comply with the regulations. In part 1090, we have consolidated all the applicable definitions into a single section. Generally, we have tried to avoid having a definition section within individual subparts; however, some infrequently-used terms may still be defined in the context of the regulatory text. We believe this approach helps the regulated community and the public at large to more easily comprehend the regulations.

For the most part, we are simply transferring the existing part 80 definitions into part 1090 with minor changes to specific terms for consistency. However, in some cases, we are redefining or reclassifying key terms in part 1090. Specifically, these areas include the defined terms for the types of regulated products (discussed in Section III.D.1) and the descriptions of regulated parties (discussed in Section III.D.2). We are also revising the definition of fuels (e.g. “gasoline” and “diesel fuel”), which is discussed in Section III.D.3.

For most proposed definitions, commenters were supportive or provided suggestions or requests for clarification regarding specific terms. We address these comments in Section 4 of the RTC document.

1. Fuels, Fuel Additives, and Regulated Blendstocks

In order to improve the clarity and consistency of our regulations, we are changing how we classify products regulated under our fuel quality regulations in part 1090. In part 80, most fuel programs were written as a separate fuel program rather than a single, consolidated fuel quality program. For example, under part 80, subpart I almost exclusively deals with distillate fuels and subpart N deals with gasoline-ethanol blended fuels. Since part 1090 consolidates all fuel quality programs from part 80 (excluding the RFS program) into a single, consolidated fuel quality program, a consistent nomenclature for regulated products is needed.

This action describes requirements for fuel quality on three categories of products: Fuels, regulated blendstocks, and fuel additives. We further classify these products into bins based on the type of vehicle or engine that the fuel is used in (i.e., gasoline-fueled, diesel-fueled, or in a vessel subject to Annex VI to the International Convention for the Prevention of Pollution from Ships (“MARPOL Annex VI”) requirements (e.g., vessels that must use Emission Control Area (ECA) or IMO marine fuel)). For gasoline-fueled engines, we not only define the term gasoline (discussed in Section III.D.2), but we also define and place requirements on specific types of gasoline based on its ethanol content (e.g., E0, E10, and E15), whether the gasoline is intended for use or used as summer or winter gasoline, and in the summer, what RVP standard the fuel is subject to (i.e., 9.0 psi, 7.8 psi, or the RFG 7.4 psi standard). For diesel-fueled engines, since the requirement to use 15 ppm diesel fuel (or ultra-low-sulfur diesel (ULSD)) is now required in almost all motor vehicle, non-road, locomotive, and marine applications (called MVNRLM diesel fuel in part 80), we are defining this fuel simply as ULSD, as it is more commonly known in the market. 500 ppm diesel fuel produced from transmix continues to be allowed in limited circumstances for certain locomotive and marine applications.

Regarding regulated blendstocks, we have historically not imposed quality specifications on such blendstocks, choosing instead to focus compliance requirements on fuels that are ultimately used in vehicles and engines. However, as the fuels marketplace has continued to evolve, using this structure has become increasingly difficult to accommodate the complexity of fuel manufacturing and distribution practices today. Therefore, we are including alternative provisions, which are currently allowed in part 80, for gasoline manufacturers to demonstrate compliance with our fuel quality requirements by imposing requirements on certain blendstocks that are added to previously certified gasoline (PCG) if certain conditions are met. We are referring to blendstocks for which we have imposed standards collectively as “regulated blendstocks.” For example, under both part 80 and part 1090, we allow gasoline manufacturers to blend butane into gasoline and to rely on test results from the producers of the butane if the butane meets more stringent sulfur and benzene per-gallon standards (referred to as “certified butane”).^[8] These certified butane blenders can use these provisions instead of certifying the finished gasoline and having to meet sulfur and benzene annual standards as these provisions are designed to ensure that the amount of sulfur and benzene in the national gasoline pool does not increase as a result of blending these feedstocks. Under part 1090, we are including similar flexibilities as under part 80 for gasoline manufacturers that wish to blend butane that has been certified to meet specifications (differences regarding butane blending between part 80 and part 1090 are discussed in Section V.A.3).

This action also includes the current part 80 specifications for gasoline and diesel additives, mostly unchanged. Except for oxygenates in gasoline, under part 80 and part 1090 additives are added to fuels in low amounts (less than 1.0 volume percent of the fuel total) and often serve to help improve fuel performance (e.g., to control deposits on intake valves). All diesel fuel additives are subject to sulfur limitations. Under both part 80 and part 1090, gasoline additives are also subject to sulfur limitations. Also, under both part 80 and part 1090, gasoline detergents and oxygenates (including denatured fuel ethanol or DFE) have specific requirements that apply in addition to the sulfur requirements that apply for all gasoline additives.

We received a comment suggesting that our proposed definition of fuel additive was unnecessarily restrictive on gasoline-ethanol blends. In response, we have revised the part 1090 definition of fuel additive to have the same meaning as “additive” under part 79. We further address this comment in Section 6 of the RTC document.

2. Fuel Manufacturers, Regulated Blendstock Producers, and Fuel Additive Manufacturers

We are finalizing the definitions related to parties described as fuel manufacturers, regulated blendstock producers, and fuel additive manufacturers as proposed. In part 80, a refinery is broadly defined as “any facility, including but not limited to, a plant, tanker truck, or vessel where gasoline or diesel fuel is produced, including any facility at which blendstocks are combined to produce gasoline or diesel fuel, or at which blendstock is added to gasoline or diesel fuel.” ^[9] A refiner is “any person who owns, leases, operates, controls, or supervises a refinery.” ^[10] When these terms were first defined, virtually all finished fuels were produced at a crude oil refinery. As we have permitted greater flexibility in the production of fuels through the blending of regulated blendstocks to make new fuels and the market has moved to allowing fuels to be produced downstream of crude oil refineries, the use of the term “refiner” to encompass all parties that make fuels has become less appropriate. Additionally, the differences in terminology between part 79 and part 80 have caused confusion among those required to or potentially required to comply with the requirements of both parts. Refiners and importers of on-highway motor vehicle gasoline and diesel fuel are fuel manufacturers under part 79 and required to register under EPA's fuel and fuel additive registration (FFARs) requirements. Under part 79, parties that make gasoline or diesel fuel through the blending of blendstocks or blending of blendstocks into PCG are also considered fuel manufacturers and must registered under part 79. Part 79 also includes importers of on-highway motor vehicle gasoline and diesel fuel as fuel manufacturers for purposes of FFARs. Part 80 generally requires that importers of gasoline and diesel fuel meet the same requirements as refiners, with some additional requirements on importers depending on the situation.

Under part 1090, the term fuel manufacturer describes any party that owns, leases, operates, controls, or supervises a facility where fuel is produced, imported, or recertified, whether through a refining process (e.g., through the distillation of crude oil), through blending of blendstocks to make fuel or blending blendstocks into a previously certified fuel to make a new batch of fuel, or through the recertification of products not subject to our fuel quality standards to fuels that are subject to our fuel quality standards (e.g., redesignating heating oil to ULSD). Importers of fuels would continue to be fuel manufacturers consistent with part 79 and the CAA. Under part 1090, we also distinguish further between parties that refine feedstocks to make fuels (more commonly known as “crude refiners” or simply “refiners”) and blending manufacturers who make fuels through blending blendstocks together to make a fuel or into an existing fuel to make a new fuel.^[11] Part 1090 includes requirements specific to the type of fuel manufacturer, and this nomenclature makes it easier for us to describe the specific requirements for each type of fuel manufacturer and for parties to understand what requirements apply specifically to whom. However, while we are modifying the terminology used in part 1090 for these parties, these parties will generally have the same obligations and responsibilities as currently required under part 80.

We are defining producers of regulated blendstocks as regulated blendstock producers. For example, these parties would include certified butane/pentane producers.

As is the case currently under part 79 and part 80, parties that only blend fuel additives into fuels are not fuel manufacturers. Any party that adds a compound (other than oxygenate or transmix) that is 1.0 percent or more of the finished fuel is a blending manufacturer, as the compound added is considered a blendstock and parties that add blendstocks into fuel are considered fuel manufacturers and need to meet all the applicable regulatory requirements. Consistent with part 79, oxygenate blenders that only add oxygenates at levels permissible under CAA section 211(f) continue to be considered oxygenate blenders and not fuel manufacturers.

3. Definition of Fuels

We are finalizing our proposed definitions for fuels (e.g., gasoline, diesel fuel, ECA marine fuel, etc.), largely as proposed. In the NPRM, we outlined a consistent framework for how we would define fuels to help ensure that compliant fuel is ultimately used in vehicles, engines, and equipment. To achieve this goal, we believe that the definition of fuels needs to reflect changes in the fuels marketplace that have occurred over the last 40 years, as well as potential changes on the horizon. While crude oil refineries still have the most direct impact on fuel quality by volume, every party downstream of the refinery can affect fuel quality, and in today's marketplace many of these downstream parties are now a key determinant of the quality of the fuel that actually goes into the vehicle. For example, downstream parties add oxygenates to gasoline (primarily ethanol) and often augment the volume of gasoline through the blending of various blendstocks into PCG to produce new fuels.

To ensure that fuels meet fuel quality standards from the crude oil refinery until they are dispensed into vehicles or engines, in light of the changing fuels marketplace, we believe that any definition of a fuel should contain three elements. First, when a party represents a fuel as meeting EPA's fuel quality standards, such fuel is subject to EPA standards regardless of whether the fuel actually meets the standards. Were this not the case, then anytime a fuel failed to meet EPA standards, we could not hold anyone accountable for failing to meet the standards. In part 1090, we define regulated fuels as anything commonly and commercially known as that particular fuel. This portion of the definition is consistent with the existing definitions of gasoline, diesel fuel, and ECA marine fuel in part 79 and part 80.

The second element of the definition of a fuel is whether a product is used or intended for use as a fuel in a vehicle or engine covered by EPA regulations (e.g., a product that is used or intended for use in vehicles and engines that are designed to use gasoline is gasoline). Since the ultimate purpose of EPA's fuel quality standards is to ensure that compliant fuel is used in vehicles and engines, if a person uses or makes a product available for use by designating it as gasoline or placing it in the fuel distribution system, or if the product is used in a gasoline-fueled vehicle or engine, the product is gasoline (i.e., a fuel) and is subject to EPA's gasoline standards. The same holds true for diesel fuel or any other regulated fuel. We have used this terminology previously when describing other fuels under part 80, notably in definitions related to motor vehicle diesel fuel ^[12] and ECA marine fuel.^[13]

The third element of the definition of a fuel relates to the physical and chemical characteristics of the fuel. Whether a product is a fuel and therefore subject to our standards and regulatory requirements cannot be solely based on whether a regulated party calls or labels it as a particular fuel. This would create an incentive for parties to simply label products intended for use as fuels by another name to avoid having to meet EPA's fuel quality standards and regulatory requirements. Therefore, when a manufacturer produces a product that is chemically and physically similar to a fuel, the product is a fuel and is subject to EPA's fuel quality standards and regulatory requirements. To address this element, we are specifying that gasoline is any product that meets the voluntary consensus standards body (VCSB) industry specifications for gasoline (ASTM D4814) and diesel fuel is any product that meets industry specifications for diesel fuel (ASTM D975).

In the NPRM, we proposed that certain blendstocks that met ASTM D4814 could be excluded from the definition of gasoline if those blendstocks were not made available as gasoline even though they may otherwise meet the definition of gasoline by meeting ASTM D4814 specifications. We also proposed to apply this same “made available” provision to diesel fuel and other fuels covered by part 1090. We explained that “[s]ince the ultimate purpose of our fuel standards is to ensure that compliant fuel is used in vehicles and engines, if a person makes a product available for use by designating it as gasoline or placing it in the fuel distribution system, or if the product is used in a gasoline-fueled vehicle or engine, the product should be subject to EPA standards. We have used this terminology when describing other fuels under part 80, notably in definitions related to motor vehicle diesel fuel and ECA marine fuel.” ^[14]

We received several comments asking for compliance assistance regarding how a company can make sure that EPA will not consider a blendstock that has the same chemical and physical characteristics as a fuel to be a fuel subject to part 1090 standards. In general, we consider any fuel that is stored, sold, or placed into a fuel distribution system that supplies fuel for use in gasoline-fueled vehicles, diesel-fueled vehicles, or marine vessels as being “made available for use” in these vehicles or vessels unless the party who produces or distributes the fuel can demonstrate that the fuel was not used, intended for use, or made available for use in these vehicles or vessels.

For example, if a person mixes two distillate blends in a tank and identifies the product as a distillate blend when it loads the product onto a barge that will transfer the fuel to a ECA marine fuel propulsion tank in a marine vessel, we would consider the product to be ECA marine fuel that has been made available for use in a marine vessel and the person would be subject to all of the requirements that apply to fuel manufacturers and distributors under part 1090, including sampling, testing, recordkeeping, and PTD requirements and marine fuel standards. On the other hand, if a person loads a product identified as a distillate blend onto a rail car and has commercial documents showing that the product was sold to a heating oil distributor who only distributes heating oil and the fuel is specifically identified to be used for the sole purpose of heating oil, we would not consider the fuel to be made available for use in a marine vessel.

There are certain products currently in the fuel distribution system that were previously not designated as “ECA Marine Fuel” or “Global Marine Fuel.” Instead, fuel suppliers have designated these products in accordance with other naming conventions and commonly using terms identified in the International Organization for Standardization (ISO) Petroleum products—Fuels (class F)—Specification of marine fuels (ISO 8217). Examples of these fuel designations include DMX, DMA, DMZ, and DMB (generally referred to by industry as “marine gas oil” or “MGO”) and RMA, RMB, RMD, RME, RMG, and RMK. If a fuel is designated by one of these terms or as a product that is commonly or commercially known to be made available fuel use in marine vessels, we will consider the product to be IMO marine fuel as the fuel has been made available for use in a marine vessel and is subject to all of the requirements for IMO marine fuel in part 1090 (as well as the applicable regulations in part 1043). We also note that intentionally mis-designating a fuel to avoid regulatory requirements does not mean those requirements are not applicable nor does it insulate a fuel supplier from potential civil or criminal enforcement.

Since there are many different and complex fuel distribution systems and channels in the U.S., we will evaluate whether a fuel is made available for use in a gasoline-fueled vehicle, diesel-fueled vehicle, or marine vessel on a case-by-case basis.

IV. General Requirements for Regulated Parties

We are including a subpart dedicated to outlining the general regulatory requirements for each regulated party in part 1090 (subpart B). The regulations in part 80 are almost 1,000 pages long, and many regulated parties currently spend a substantial amount of time and resources to comprehend and interpret them or ask EPA staff to identify applicable regulatory requirements.

To make the streamlined regulations more accessible, we are making subpart B a roadmap for regulated parties, directing them to those subparts that are most likely to affect them and their business. We first outline the general requirements applicable to all parties that make and distribute fuels, fuel additives, and regulated blendstocks. These requirements include keeping records and being subject to regulatory requirements under part 1090 if a party makes and distributes fuels, fuel additives, and regulated blendstocks.

We then describe the requirements that apply to each group of regulated parties based on their business activities. Examples of these categories are fuel manufacturers, detergent blenders, oxygenate blenders, and retailers. We believe this will help these parties more easily identify regulatory provisions that apply to their specific activities. For example, retailers are typically small businesses that have greater difficulty hiring consultants to help them understand their regulatory requirements. Retailers also have a relatively small number of regulatory requirements under part 80 and part 1090. By identifying the generally applicable requirements that apply to all retailers, these small businesses could more easily identify those requirements that apply to them, helping them to more easily comply with EPA's fuel quality regulations.

It is important to note that parties may have more than one regulated activity, and, as is the case today, these parties would be required to satisfy all regulatory requirements for each regulated activity. Regulated parties will still need to comply with all applicable requirements contained in part 1090, regardless of whether they are identified for them in subpart B. We cannot predict every possible situation a party may be in within the marketplace now or in the future. Accordingly, regulated parties, as always, should pay careful attention to all the applicable regulatory requirements to ensure compliance.

Commenters were generally supportive of the proposed structure of subpart B and found it helpful to regulated parties in general. We also received comments that included suggested edits to subpart B. We address these comments in Section 5 of the RTC document.

V. Standards

A. Gasoline Standards

1. Overview and Streamlining of Gasoline Program

We are consolidating the various gasoline standards from part 80 into a single subpart in part 1090 (subpart C). We are neither changing the gasoline lead, phosphorous, sulfur, benzene or RVP standards, nor modifying the standards for oxygenates (including DFE), certified ethanol denaturant, gasoline additives, and standards for certified butane and certified pentane. These standards are simply being moved and consolidated into subpart C.

To further streamline the gasoline program, we are altering the form of the RFG VOC performance standards. These changes are not expected to change the stringency of the gasoline standards. We do, however, expect that these changes will greatly simplify the gasoline program, resulting in: (1) Reduced burden associated with demonstrating compliance with the gasoline standards; (2) improved fungibility of gasoline, allowing the market to operate more efficiently; and (3) reduced costs to consumers.

First, we are translating the RFG standard from the demonstration of the VOC performance standard via the Complex Model into an equivalent maximum RVP per-gallon standard, which allows us to greatly simplify the compliance demonstration requirements for RFG. Of all the provisions being finalized, this is the key provision enabling considerable streamlining of the existing gasoline regulations.

Second, we are consolidating the two grades of butane and two grades of pentane specified in part 80 for use by butane and pentane blenders into a single grade each of certified butane and certified pentane. This greatly simplifies the registration and reporting of activities related to blending certified butane and certified pentane.

Finally, we are establishing certain regulations related to summer gasoline, as well as procedures for states to relax the federal 7.8 psi RVP standard. These changes are discussed more thoroughly in the following sections.^[15]

2. RFG Volatility Standard

The RFG program was created by EPA in the 1990s in response to a directive from Congress in the CAA Amendments of 1990 with the express purpose of providing cleaner burning gasoline to the most polluted metropolitan areas of the country. The program was very successful in that regard. However, since that time, a series of additional fuel quality standards and other market changes have resulted in CG meeting or exceeding most of the performance requirements for RFG, with the primary difference between CG and RFG now being only the lower volatility of RFG during the summer months. At the same time, the extensive RFG regulations remain, constraining gasoline fungibility, increasing costs, complicating compliance oversight, and limiting the sale of certain biofuel blends. Consequently, we are: (1) Replacing the existing compliance mechanism used for RFG batch certification—the Complex Model—with a summer maximum RVP per-gallon standard (“RVP standard”); (2) applying that same single RVP standard to all RFG nationwide; (3) provide greater flexibility for blending of oxygenates (e.g., ethanol and isobutanol) and E0 in RFG areas; and (4) removing several other restrictions that currently create a distinction without a difference between RFG and CG.

We intend these changes to maintain the stringency of all standards associated with RFG while alleviating unnecessary compliance burden. We acknowledge that the CAA requires the existence of RFG in specified nonattainment areas ^[16] and certification procedures to certify RFG as complying with the requirements.^[17] This action will simplify and translate the previously established requirements while still maintaining the same level of VOC emissions reductions as currently required. This will be accomplished by translating the current VOC emissions reductions demonstrated through the Complex Model into an RVP standard that will be used to demonstrate RFG VOC compliance in lieu of the Complex Model.^[18]

CAA section 211(k)(3)(B) provides that during the high ozone season, “the aggregate emissions of ozone forming volatile organic compounds from baseline vehicles when using the reformulated gasoline shall be 15 percent below the aggregate emissions of ozone forming [VOCs] from such vehicles when using baseline gasoline.” This section also provides for increasing stringency beginning in 2000 of at least 25 percent, based on technological feasibility and costs. We are achieving that demonstration largely through the use of an RVP standard in combination with the previously established sulfur standard.

The RFG RVP standard of 7.4 psi was specifically chosen in order to maintain the summer VOC performance required by the statute,^[19] and this RVP is currently observed in the RFG pool. This approach also aligns the RFG compliance provisions with the much simpler and more easily enforced provisions currently in place for CG. In doing so, we are also acting on the Energy Policy Act of 2005 (EPAct) directive to consolidate the RFG VOC Regions into a single set of RFG standards by applying the southern RFG requirements (VOC control region 1) to all RFG areas, as discussed further in Section V.A.2.b. This consolidation of RFG VOC Regions, along with other changes in this action, will provide greater fungibility in the RFG pool and eliminate antiquated restrictions in order to provide greater flexibility to fuel manufacturers and distributors, reduce cost for those parties, and reduce compliance and enforcement oversight costs.

Additional benefits from this action are potentially wide reaching as it could create opportunities for broader availability of fuels and reduced consumer costs. By having a single RVP standard for RFG, in situations of fuel shortage in RFG areas during the summer, gasoline from other RFG areas or from state low-RVP fuel programs could now be moved to affected areas without recertification so long as the RFG RVP standard is observed. This increase in gasoline fungibility should serve to reduce scarcity and promote lower prices for consumers in affected areas. Additionally, the desire for ethanol-free gasoline (e.g., E0 or isobutanol blends) for marine use in RFG areas has regularly been expressed by both citizens and elected officials of areas where RFG is required. Under the current RFG compliance provisions in part 80, it is difficult for distributors to provide ethanol-free gasoline to consumers in RFG areas. Under part 1090, using the downstream gasoline before oxygenate blending (BOB) recertification provisions discussed in Section VII.G, it will be easier for distributors to provide ethanol-free gasoline to consumers in these areas.

a. RVP Standard for VOC Performance Determination

With the importance of RVP in the Complex Model for VOC emissions performance and the combination of MSAT2 and Tier 2/3 for reducing benzene and sulfur, respectively, RFG compliance is now almost completely determined by the RVP of the fuel. Consequently, we proposed that, under part 1090, any summer RFG batch meeting an RVP standard of 7.4 psi would be deemed compliant with the RFG VOC emission performance reduction standard. Many commenters were supportive of this approach, and we are finalizing these regulations as proposed.^[20 21] Along with RVP, benzene concentration for MSAT2 compliance, and sulfur content for Tier 3 compliance will also be reported to EPA. Thus, all three of the emission reduction standards for RFG will be covered by just three parameters: RVP, benzene, and sulfur. This will reduce the compliance and reporting burden for gasoline manufacturers by reducing the number of parameters they need to test and report from 11 to as few as 3 in the summer.^[22 23]

Our intent in translating the VOC performance standards into a maximum RVP per-gallon standard is to both ensure that the emission reduction targets for RFG and the current emissions performance will continue to be achieved. In determining the RFG RVP standard, we operated under the statutory constraints that were, and remain, present for the formulation of the Complex Model—namely, the 1990 baselines for both fuel composition and vehicle technology. Thus, the 7.4 psi RVP standard for RFG will maintain the gasoline quality and its associated emission performance as calculated consistent with the statutory requirements and the Complex Model.

Although it will no longer be required for demonstration of RFG batch compliance, the Complex Model will be retained by EPA for compliance oversite purposes in conjunction with the national fuels survey program (NFSP). Continued adherence to the RFG VOC emission performance reduction standard will be monitored through samples collected from RFG areas as part of the NFSP. This oversite function will help ensure that the emission reductions the Complex Model was intended to certify at the fuel manufacturing facility gate are being maintained in use.

b. Consolidation of RFG VOC Control Regions

Translating the VOC emissions performance standard into a summer RVP standard enables EPA to simplify the RFG program significantly. Additionally, the creation of a single summer RVP standard for all RFG areas further simplifies the RFG program and automatically consolidates the VOC regions as required under section 1504(c) of EPAct, which directs EPA to revise the RFG regulations to consolidate the regulations for the VOC-Control Regions by eliminating the less stringent requirements.^[24]

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

c. Additional Changes Related to RFG

We are also finalizing regulations intended to allow for greater compliance flexibility and increased gasoline fungibility for the RFG program. Specifically, as discussed in Section VIII.G, we are finalizing several provisions regarding fuel certification and recertification that are now commonplace due to the gasoline quality standards implemented since the onset of the RFG program. For instance, RFG is statutorily required to be used in certain ozone nonattainment or maintenance areas in both summer and winter. The differences between RFG and CG that require the respective fuels to be segregated in the summer (i.e., RFG and CG must meet different standards in the summer) are not present during the winter season, where RFG and CG must meet identical standards under part 80. However, a similar prohibition on comingling RFG and CG in the winter exists.

To address this situation, we are finalizing provisions to allow all winter gasoline to be used in RFG areas without recertification. Distributors of gasoline will be allowed to designate winter gasolines without recertification as RFG or CG to comport with state or pipeline specifications, which may require those distinctions.

All comments received on the proposed RFG RVP standard of 7.4 psi, consolidation of the VOC control regions, and improved fungibility provisions for RFG were supportive. We did, however, we receive comments asking for minor edits to and clarifications of the regulatory requirements for RFG under part 1090. We address these comments in Section 6 of the RTC document.

3. Certified Butane and Pentane

We are streamlining the provisions for gasoline blending manufacturers that blend butane and pentane of certified quality (certified butane and certified pentane, respectively) into PCG.^[25] Under part 80, these flexibilities allow gasoline blending manufacturers to rely on test results by the butane or pentane producer rather than testing each batch of butane or pentane received as would otherwise be required of a gasoline blender manufacturer to demonstrate compliance with EPA standards. This basic approach is maintained in part 1090.

Part 80 has two grades of butane and pentane (commercial and noncommercial) that can be used by gasoline blender manufacturers under these provisions. We are combining these grades into single grades of “certified butane” and “certified pentane.” Consolidating the grades of butane and pentane allows for streamlined compliance demonstrations for certified butane and certified pentane blenders to produce gasoline using certified butane and certified pentane.

The part 80 standards for commercial and noncommercial grades of butane and pentane contain specifications on the maximum sulfur, benzene, olefin, and aromatics content. Consistent with the changes to RFG certification discussed in Section V.A.2, we are removing the maximum olefin and aromatics standards from the specifications for certified butane and certified pentane. Under part 1090, both certified butane and certified pentane will continue to be subject to a maximum 10 ppm sulfur standard and maximum 0.03 volume percent benzene standard, as are the commercial and noncommercial grades of butane and pentane under part 80. The sulfur and benzene specifications are still needed to ensure that certified butane and certified pentane blenders do not increase the amount of sulfur and benzene in the national gasoline pool.

Under part 80, commercial grade pentane is subject to both 95 volume percent pentane purity specification and a maximum 5 volume percent C6 and higher carbon number hydrocarbons specification.^[26] Non-commercial grade pentane is subject to 95 volume percent pentane purity specification but is not subject to specifications on the amount of C6 and higher carbon number hydrocarbons that may be present. In part 1090, we are removing the standard on C6 and higher hydrocarbon content for certified pentane given that compliance with the 95 volume percent pentane purity specification ensures that no more than 5 volume percent C6 and higher hydrocarbons are present. We did not receive any adverse comments to this proposal for certified pentane standards, and so we are finalizing the certified pentane standards as proposed.

Unlike the part 80 standard for non-commercial grade pentane, the current standards for commercial and non-commercial grade butane do not include a specification on minimum butane purity. With the removal of the maximum olefin and aromatics specifications for certified butane, it is appropriate to impose controls on the purity of certified butane that are consistent with the purity specification for certified pentane. In the NPRM, we proposed a 92 volume percent purity specification for certified butane. While slightly lower than the 95 volume percent purity specification for certified pentane, we argued that the slightly lower standard would not result in increased emissions from the use of certified butane compared to a 95 volume percent purity specification and would allow necessary flexibility to industry. We received several comments suggesting that we should impose a lower certified butane purity standard. Commenters suggested a range of options from 80 volume percent to 90 volume percent. Most commenters suggested that a purity specification of 85 volume percent would allow for a high-quality product without disrupting existing butane blending practices. We agree with these comments and are therefore finalizing an 85 volume percent purity specification for certified butane.

We are also simplifying the quality assurance requirements for certified butane and certified pentane blenders. Under part 80, butane and pentane blenders are required to conduct periodic quality assurance testing of the batches of butane or pentane they receive. The sampling and testing frequency for butane received from each butane supplier under part 80 is one sample for every 500,000 gallons, or one sample every three months, whichever is more frequent. The sampling and testing frequency for commercial grade pentane received from each pentane supplier under part 80 is once for every 350,000 gallons of pentane received, or one sample every three months, whichever is more frequent. Under Part 80, noncommercial-grade pentane is subject to a more frequent sampling and testing frequency of once every 250,000 gallons or one sample every three months, whichever is more frequent.

To simplify these quality assurance requirements, under part 1090 we are requiring the same sampling and testing frequency for certified butane and certified pentane to be once every 500,000 gallons of butane or pentane received, or one sample every three months, whichever is more frequent. More frequent sampling and testing is not needed for certified pentane versus certified butane, given that they are subject to similar standards. Existing registration requirements for certified pentane producers will help to mitigate concerns that pentane manufacturing processes may increase concentration of high boiling range hydrocarbons (such as C7-C20 hydrocarbons).^[27] We received no adverse comments on this aspect of the proposal, and so we are finalizing these provisions as proposed.

4. State and Local Fuel Standards

a. Overview

As proposed, we have transferred and consolidated the part 80 regulations that relate to RVP and RFG requirements in part 1090. For example, we are removing outdated provisions and making it easier to identify the RVP standard that applies in a given location. We are also finalizing changes that are intended to update and simplify existing regulations and reflect our experience in implementing these provisions in partnership with states and industry. For example, we are finalizing procedures for states that request a relaxation of the federal RVP standard of 7.8 psi. These procedures are similar to the existing procedures used for RFG opt-out by states. We are not finalizing any regulatory revisions for current fuel programs that apply in several states. The following sections detail the changes we are finalizing.

We are also announcing that an updated boutique fuel list is currently posted on our website.^[28] Section 1541(b) of EPAct requires EPA to remove any fuel from the published list if the fuel either ceases to be included in a state implementation plan (SIP) or is identical to a federal fuel.^[29] Several fuels have ceased to be included in SIPs since the boutique fuel list was originally published in 2006.^[30] The boutique fuel list on our website, however, provides up-to-date information on where such fuels are currently used.

b. Consolidating Gasoline Volatility Standards

As proposed, we have transferred summer gasoline requirements related to RVP standards that are currently in part 80 to part 1090. Summer gasoline for use in the continental U.S. must comply with either the federal RVP standard of 9.0 psi or the more stringent RVP standard of 7.8 psi, unless it is either for use in a RFG covered area, is subject to California's gasoline regulations, or EPA has waived preemption and approved a state request to adopt a more stringent RVP standard into a SIP.^{[31 32 33]} Part 1090 simplifies and clarifies the regulatory text previously located in 40 CFR 80.27(a) and 80.70, and does not change the current RFG and summer gasoline standards nationwide, and requires all gasoline designated as summer gasoline or located at any location in the U.S. during the summer season to meet applicable RVP per-gallon standards. The regulations include a limited exception to facilitate the movement and storage of gasoline that does not meet the applicable RVP standards if it is locked down and is not delivered to any retail station or wholesale purchase consumer. This exception is primarily designed to accommodate the transition from summer to winter gasoline and allow the transportation and storage of higher RVP fuel through areas that are subject to more stringent standards. The exception places the burden on the regulated community to demonstrate that the gasoline is properly designated and isolated and is not delivered to any retail station or wholesale purchaser consumers during a time or place prohibited by the regulations.

c. Reformatting the List of Areas Where the Federal 7.8 psi RVP Standard Applies

As proposed, we have transferred to part 1090 the current RVP standards in 40 CFR 80.27(a)(2), which previously set out the current federal RVP standards. Areas subject to the federal 7.8 psi RVP standard are listed in a table in 40 CFR 1090.215(a)(1), describing the geographic areas subject to the 7.8 psi RVP standard. Part 1090 specifies that any gasoline that is not subject to a lower RVP standard is subject to the federal 9.0 psi RVP standard. We did not propose and therefore are not finalizing any changes or revisions to applicable RVP standards. Specifically, we:

• Removed the regulatory text in 40 CFR 80.27(a)(1) because it was outdated and has not applied since 1991.
• Replaced the regulatory text, table, and footnotes that were in 40 CFR 80.27(a)(2) with a reformatted table in part 1090 that lists the areas where the federal 7.8 psi RVP standard for summer gasoline currently applies.

The table in 40 CFR 80.27(a)(2) dates back to the initial one-hour ozone NAAQS and is overly complex and has caused confusion among states and industry. The new table in 40 CFR 1090.215(a)(1) includes the name of the nonattainment area and the county or counties in the area where the federal 7.8 psi RVP standard applies. The new table under part 1090 also includes a description of the boundaries for areas that include partial counties where RVP standards are currently in effect. Under 40 CFR 80.27(a)(2), interested parties had to search 40 CFR part 81 in order to identify these specific boundaries of the area where the 7.8 psi RVP standard applies. As previously noted, this action does not change any existing requirements.

d. Reformatting RFG Applicability and Covered Areas

As proposed, we have transferred part 80 requirements relating to RFG to part 1090, and we have reformatted how the information on RFG covered areas is presented. Specifically, in 40 CFR 1090.285 we present the description of RFG covered areas in a table format and have grouped the covered areas by the statutory provision under which the area became a covered area. The following are four requirements under which an area could have become an RFG area:

• It was included in the original RFG covered areas under CAA section 211(k)(10)(D) because its 1987-1989 ozone design value was among the nation's nine highest design values and its 1980 population was greater than 250,000;
• It was subsequently reclassified to Severe for an ozone NAAQS;
• It was a classified ozone nonattainment area that opted into the RFG program; or
• It was an attainment area in the ozone transport region that opted into the RFG program.

The tables in part 1090 list the areas in each of these groups. As previously explained, we are not changing the geographic applicability of RFG.

We have also transferred the existing regulatory processes by which an area may become an RFG covered area in the future to part 1090. These processes apply if: (1) An area is reclassified to Severe nonattainment for an ozone NAAQS; (2) a governor requests that a classified ozone nonattainment area become a covered area; or (3) a governor requests that an attainment area in the ozone transport region be included as an RFG covered area.

We also now include two additional California areas on the list of RFG covered areas in part 1090 because the areas became RFG covered areas when they were reclassified as Severe ozone nonattainment areas.^[34] The two areas are the Sacramento Metro area and the San Joaquin Valley area.^[35] We have provided information on these RFG covered areas on our website but had not previously included them in the list of covered areas in 40 CFR 80.70. This does not impact continued applicability of California's regulations that require the sale of California gasoline in these areas, but should California's regulations no longer apply in the future, EPA's RFG regulations would likely still apply in keeping with the CAA.

e. Continuation of RFG Requirements in Covered Areas When Revised Ozone NAAQS Are Implemented

In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we stated that areas that became RFG covered areas pursuant to CAA section 211(k)(10)(D) would remain RFG covered areas at least until they were redesignated to attainment for the 1997 ozone NAAQS. We also stated that areas that became covered areas because they opted into RFG would remain covered areas until they opt out of RFG pursuant to EPA's opt-out regulations. We also included regulatory text in 40 CFR 80.70(m),^[36] parts of which have become outdated and unnecessary because they were specific to the transition from the 1-hour ozone NAAQS to the 1997 ozone NAAQS, both of which have since been revoked.

As proposed, in part 1090 we are maintaining and clarifying our intention and existing practice with regard to applicable RFG requirements. Specifically, RFG will continue to apply in all covered areas (i.e., both areas that opted into RFG under CAA section 211(k)(6) and covered areas under CAA section 211(k)(10)(D)). Requiring the continued implementation of RFG in all covered areas is consistent with how the RFG program has been implemented during the transitions to the 1997, 2008, and 2015 ozone NAAQS. Part 1090 includes procedures for either removing a prohibition on or opting out of RFG, consistent with CAA requirements; thus, part 1090 continues to allow states to revise RFG requirements under certain circumstances.

f. Clarifying When Mandatory RFG Covered Nonattainment Areas Can Be Removed From the List of Covered Areas

In the Phase 2 Implementation Rule for the 1997 Ozone NAAQS, we reserved for future consideration the continued applicability of RFG requirements in areas where RFG use was mandated pursuant to CAA section 211(k)(10)(D) (i.e., the areas with the nine highest 1-hour ozone design values from 1987-1989 or areas reclassified to Severe for an ozone NAAQS).^[37]

As proposed, we are finalizing a new provision in part 1090 that will allow a mandatory RFG covered area pursuant to CAA section 211(k)(10)(D) to remove the applicability of the RFG program if certain requirements are met. Under 40 CFR 1090.290(d), a state could request the removal of its RFG program if the RFG area was either redesignated to attainment for the most stringent ozone NAAQS in effect at the time of the request or initially designated as attainment for the most stringent ozone NAAQS in effect. For example, the 2015 ozone NAAQS of 70 ppb is currently the most stringent ozone NAAQS. Therefore, in order for a mandatory RFG area to remove its RFG program, it would have to either be redesignated to attainment for the 2015 ozone NAAQS (if it had been designated as nonattainment for that NAAQS) or be designated as an attainment area for the 2015 ozone NAAQS. On the other hand, if the area is designated as an attainment area for the most stringent ozone NAAQS in effect, the area would have to be redesignated to attainment for the prior ozone NAAQS before the RFG program could be removed. For example, an area would either have been designated as an attainment area for the 2015 ozone NAAQS with an approved maintenance plan for the 2008 ozone NAAQS or be a nonattainment area that has been redesignated to attainment for the 2015 NAAQS to be eligible for consideration for removal of the RFG program. In either case, we are requiring that any request to remove the RFG requirements must include an approved maintenance plan that demonstrates maintenance of the ozone NAAQS throughout the period addressed by the maintenance plan without the emission reductions from the RFG program. Additionally, we are requiring that a state must also demonstrate that the removal of the requirement for the RFG program would not interfere with reasonable further progress requirements or attainment or maintenance of any other NAAQS or interfere with any other CAA requirement.^[38]

States with current mandatory RFG covered areas may seek to remove the requirement for RFG in the future when all ozone NAAQS are attained and maintained. Although the CAA requires RFG in certain ozone nonattainment areas, it is important that states have the ability to use their limited resources for programs that are necessary for attainment, rather than require the implementation of RFG indefinitely simply because such a covered area had the highest ozone design values over 30 years ago or were reclassified as Severe for a prior ozone NAAQS. This approach is premised on our view that once a covered area attains the most stringent ozone NAAQS, states should be able to determine whether an emission reduction strategy (in this case RFG) should either continue or be removed as long the state can demonstrate maintenance of the ozone NAAQS without the emissions reductions attributable to RFG in the approved CAA section 175A maintenance plan for the area. Requiring that an area attain the most stringent ozone NAAQS and demonstrate maintenance of the ozone NAAQS without the emissions reductions from RFG provides adequate safeguards with respect to protecting air quality improvements and public health, while providing states with the flexibility to determine the best course for maintaining the ozone NAAQS.

This provision is in addition to the current RFG opt-out procedures that apply to areas that opted-in to RFG under CAA section 211(k)(6)(A) or (B). The opt-out procedures, which were established in 1996 and 1997, are not being revised in this action except for transferring them to part 1090, removing obsolete regulatory text (e.g., removing requirements that applied for specific periods of time that are now in the past), and making minor clarifications.

A commenter stated that Congress created mandatory RFG covered areas, and it is up to Congress to eliminate this provision. This commenter believed that EPA does not have the authority to remove the RFG program for a mandatory RFG area created by Congress and the statute is unambiguous regarding this matter. We disagree and have concluded that there is legal authority to support removal of RFG requirements in mandatory RFG areas as long as the criteria established in part 1090 are met. This comment is addressed in more detail in Section 6 of the RTC document.

Another commenter asked whether the RFG opt-out procedures apply to both opt-in and mandatory areas because the proposed regulations could be read to allow only opt-in areas to request removal of an RFG program from a portion of the covered area. The commenter also sought clarification on whether a mandatory RFG area must be in attainment for all prior ozone NAAQS, or only the immediately prior ozone NAAQS (in addition to the most stringent NAAQS) in order to request removal of the RFG requirement.

As proposed, the RFG opt-out regulations could be read to draw a distinction between opt-in areas and mandatory areas under CAA section 211(k)(10)(D). We intended that these opt-out regulations would apply to both opt-in areas and mandatory areas in the same way. In response to this comment, we have revised the RFG opt-out procedures to clarify that the provisions apply to both opt-in areas and mandatory areas in the same manner. Specifically, both opt-in areas and mandatory areas can have the RFG requirement removed from either the entire area or from a portion of the area, provided that the relevant criteria and procedures are followed.

With respect to the request for clarification regarding whether a mandatory RFG area must be in attainment for all prior ozone NAAQS, mandatory RFG areas will remain RFG covered areas until the criteria in part 1090 are met, and the state follows the procedures to have the requirements to sell RFG removed, the EPA Regional Office approves the state's SIP revision and CAA section 110(l) demonstration, and EPA establishes an effective date for the removal of the area. Such an area would have to attain the most stringent ozone NAAQS in effect at the time. The state would have to revise any relevant CAA section 175A maintenance plan and comply with CAA section 110(l) non-interference requirements. Two examples are provided in the following paragraphs.

One example is for a state seeking removal of the RFG program from a mandatory RFG area that was initially designated as nonattainment for the most stringent ozone NAAQS in effect at the time of the request for the removal (e.g., currently the 2015 ozone NAAQS) and the area has been redesignated to attainment with an approved CAA section 175A maintenance plan for that NAAQS. In this case, the state need only address that most stringent ozone NAAQS by revising the approved CAA section 175A maintenance plan for that ozone NAAQS to show continued maintenance of that ozone NAAQS without the emissions reductions from RFG and comply with CAA section 110(l) non-interference requirements.

Another example is if a state is seeking removal of the RFG program from a mandatory RFG area that was initially designated as an attainment area for the most stringent ozone NAAQS in effect. In this case, it needs to address the prior ozone NAAQS by revising the CAA section 175A maintenance plan for that area for the prior ozone NAAQS (i.e., currently the 2008 ozone NAAQS) to show continued maintenance of that ozone NAAQS without the emissions reductions from RFG and comply with CAA section 110(l) non-interference requirements. We also expect a state seeking the removal of the RFG requirement in a mandatory area to briefly discuss its air quality status with respect to the 1-hour ozone NAAQS (i.e., the area's current design value) because all mandatory areas under CAA section 211(k)(10)(D) became mandatory areas due the severity of the 1-hour ozone NAAQS problem in these areas.

g. Providing Streamlined Procedures for Areas Relaxing the Federal 7.8 psi RVP Standard

As proposed, we are finalizing a new streamlined process for state requests to relax the federal 7.8 psi RVP standard for gasoline sold between June 1st and September 15th of each year. Part 1090 provides procedures similar to those that are currently used when states opt out of the RFG program.^[39]

The current federal 7.8 psi RVP standard took effect in 1992 and was initially required in certain 1-hour ozone NAAQS nonattainment areas. States have had the ability to request relaxation of this RVP standard provided that all CAA requirements are fulfilled (e.g., revising approved SIPs as necessary and EPA's approval of those SIP revisions and approval of a CAA section 110(l) non-interference demonstration). Since 2014, we have approved relaxations of the federal 7.8 psi RVP standard for 12 areas in the states of Alabama, Florida, Georgia, Louisiana, North Carolina, and Tennessee.^[40] As discussed in Section V.A.4.c, we are providing a new table in part 1090 that sets out where the federal 7.8 psi RVP standard continues to apply.

Under our previous regulations, the process for accomplishing a 7.8 psi RVP relaxation required two EPA approval actions before a state's request could become effective. First, the EPA Regional Office needed to approve a state's revision to an area's SIP, such as a maintenance plan, for the relevant ozone NAAQS and a CAA section 110(l) non-interference demonstration. After the EPA Regional Office rulemaking was completed, a second rulemaking by EPA Headquarters was necessary to remove the subject area(s) from the federal 7.8 psi RVP regulations in 40 CFR 80.27(a)(2).^[41] The process involving both of these approval actions before a state's request could become effective was cumbersome and time consuming given the number of linear steps involved. There was also an element of confusion and uncertainty to states, local businesses, industry, and the public concerning the effective date of an RVP relaxation.

Based on our experience since 2014, we proposed that the current RFG opt-out regulatory procedures would provide a better model for considering and approving state requests to relax the federal 7.8 psi RVP standard. Thus, the part 1090 regulations for relaxing the federal 7.8 psi RVP standard mirror the RFG opt-out procedures, and are as follows:

• The governor of the state, or the governor's designee, requests in writing that EPA relax the federal 7.8 psi RVP standard.
• The state is required to revise its approved SIP for the area (e.g., the ozone maintenance plan for the area) to appropriately account for the change in emissions due to the increase in the RVP standard and to address the CAA section 110(l) non-interference requirements.
• The EPA Regional Office would have to approve that SIP revision and CAA section 110(l) demonstration.
• Once the EPA Regional Office's action is complete, EPA Headquarters would establish an effective date for the relaxation, which would be no less than 90 days after the effective date of the EPA Regional Office's approval. We then notify the governor in writing, typically through a letter, of the effective date and publish a notice in the Federal Register. Gasoline meeting the 7.8 psi RVP standard would not be required to be sold after that effective date.
• Subsequently, we would publish a separate final rule to remove the area from the list of areas where the 7.8 psi RVP standard continues to apply (i.e., from the list of areas in part 1090). We have concluded that notice-and-comment rulemaking to revise the list of areas in part 1090 is not necessary for relaxation actions to become effective because it merely codifies a change that has been made through a process that is included in our regulations and is thus, merely administrative in nature.

This process will eliminate the need for EPA to complete a notice-and-comment rulemaking to update the list of areas in part 1090 each time we act on a request to relax a federal 7.8 psi RVP standard to remove the subject area from the list of areas subject to that standard. Under the process in part 1090, which is similar to the RFG opt-out procedures, the effective date of the federal 7.8 psi RVP relaxation would be known shortly after the EPA Regional Office's rulemaking on the state's SIP revision and CAA section 110(l) non-interference demonstration becomes effective. Using similar procedures for acting on state requests to change either federal 7.8 psi RVP or RFG programs will also avoid unnecessary confusion and still continue to provide the same level of environmental protection. Under both the former part 80 regulations and the current part 1090 regulations, the state's SIP revision must include revisions to the on-road and nonroad mobile source NO_X and VOC inventories to reflect the removal of the federal 7.8 psi RVP fuel and comply with the CAA's non-interference requirements.^[42] Further, we will continue to act on such SIP revisions and CAA section 110(l) non-interference demonstrations through notice-and-comment rulemaking. Finally, this process, which streamlines the RVP relaxation program, results in the conservation of limited government resources and brings certainty for states, the public, and gasoline suppliers as to when a state's request to relax RVP would take effect.

h. Transitioning From RFG or a Boutique Fuel Program to the Federal 9.0 psi RVP Standard in Certain States

In this action we are providing information for states that decide to either opt out of RFG or remove a state SIP fuel rule that regulates gasoline RVP (i.e., a boutique fuel). Specifically, a state in its SIP revision (e.g., maintenance plan revision) may request that EPA apply the federal 9.0 psi RVP standard rather than the federal 7.8 psi RVP standard.^[43] The SIP revision will have to document that increasing the summer RVP standard to 9.0 psi will not interfere with attainment or maintenance of the relevant ozone NAAQS or with requirements for reasonable further progress, attainment, or maintenance of any other NAAQS.^[44] This reflects our experience in working with states that have decided to change their fuel programs in areas where the federal 9.0 psi RVP standard could be applied.

In such cases, the ultimate goal of these states has been to allow the sale of gasoline that meets the federal 9.0 psi RVP standard in lieu of a more restrictive standard. States have previously accomplished this goal by first submitting a SIP revision (e.g., a maintenance plan revision) that removes the state fuel RVP standard or opts out of the RFG program and applies the federal 7.8 psi RVP standard and addresses CAA section 110(l) non-interference demonstration requirements. Later, such states would submit a second SIP revision to initiate the process to relax the federal 7.8 psi RVP standard to 9.0 psi. We are providing this information in this action to ensure that states are aware that they can accomplish the goal of relaxing the federal RVP standard to 9.0 psi through one SIP revision as long as the associated SIP revision meets the CAA section 110(l) non-interference requirements for the relevant ozone NAAQS and all other pollutants. Accomplishing the goal of allowing the sale of gasoline that meets the federal 9.0 psi RVP standard with one SIP revision, EPA approval of that SIP revision, and one EPA action to update the lists areas subject to the specific gasoline standards will conserve state and federal resources.

Allowing the transition to the federal 9.0 psi RVP standard through one SIP revision continues to protect air quality and public health because the state must demonstrate through its SIP revision and CAA section 110(l) non-interference demonstration that air quality goals are met when gasoline that complies with the federal 9.0 psi RVP standard is sold in the area. This approach also provides fuel suppliers with certainty and stability. Transitioning directly to the 9.0 psi RVP standard through one SIP revision, rather than accomplishing this through two SIP revisions as has occurred in the past, avoids the need for fuel suppliers to supply the area with 7.8 psi RVP gasoline for a short period of time, only to ultimately switch to supplying gasoline that meets the 9.0 psi RVP standard.

We note, however, that if such a state wants EPA to apply the federal 7.8 psi RVP standard, that state could document this intention in its SIP revision, and the associated emissions modeling should be based on application of the federal 7.8 psi RVP standard. In such a case, we would also complete a rulemaking to revise the list of areas where the federal 7.8 psi RVP standard applies (i.e., add such an area to the list in part 1090).

i. Announcing Updates to the Boutique Fuels List

We are also using this action to announce that an updated boutique fuel list is currently posted on our State Fuels website.^[45] Section 1541(b) of EPAct required EPA, in consultation with the Department of Energy (DOE), to determine the total number of fuels approved into all SIPs as of September 1, 2004, under section 211(c)(4)(C), and publish a list of such fuels, including the state and Petroleum Administration for Defense District (PADD) in which they are used for public review and comment. EPA originally published the required list on December 28, 2006.^[46]

We are required to remove any fuels from the published list if the fuel either ceases to be included in a SIP or is identical to a federal fuel.^[47] Since the original list was published, several fuels have been removed from approved SIPs and have thus ceased to exist in SIPs.^[48] In addition to our aforementioned website, we are providing an updated list of boutique fuels that includes all of the boutique fuels that are currently in approved SIPs in Table V.4.h-1 below. We will continue to update that website as changes to boutique fuels occur and periodically announce updates in the Federal Register for fuels that are either removed or added.

Table V.4.h-1—Total Number of Fuels Approved in SIPs Under CAA Section 211(c)(4)(C)

Type of fuel control	PADD	Region—state
RVP of 7.8 psi	2 3	5—Indiana. 6—Texas (May 1-October 1) *.
RVP of 7.0 psi	2 2 2 3 3	7—Kansas. 5—Michigan. 7—Missouri. 4—Alabama 49. 6—Texas.
Low Emission Diesel	3	6—Texas.
Cleaner Burning Gasoline (Summer)	5	9—Arizona (May 1-September 30) *.
Cleaner Burning Gasoline (Non-Summer)	5	9—Arizona (October 1-April 30).
Winter Gasoline (aromatics & sulfur)	5	9—Nevada 50.
* 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

CAA section 211(f)(1)(B) prohibits the introduction into commerce of “any fuel or fuel additive for use by any person in motor vehicles manufactured after model year 1974 which is not substantially similar to any fuel or fuel additive utilized in the certification of any model year 1975, or subsequent model year vehicle, or engine.” While this provision has always applied to fuel and fuel additive manufacturers by virtue of it being a statutory requirement, it was not listed in part 80 among the requirements for fuel.^[51] As part of our effort to consolidate fuels compliance requirements and make it easier for regulated parties to understand their obligations, we are finalizing a requirement in part 1090 that all gasoline, BOBs, and gasoline fuel additives must be substantially similar under CAA section 211(f)(1)(B) or have a waiver under CAA section 211(f)(4).^[52]

EPA has issued two coexisting definitions of substantially similar for gasoline, one in 2008 ^[53] and one in 2019,^[54] and several CAA section 211(f)(4) waivers. The part 1090 regulations refer to the statutory provisions (CAA section 211(f)(1) and (4)). EPA has issued interpretative rules on the meaning of “substantially similar” under this provision.^[55] EPA has also issued many CAA section 211(f)(4) waivers from the substantially similar provision, including, but not limited to the E10 (“gasohol”) waiver and the Octamix waiver.^[56] Fuel and fuel additive manufacturers are expected to comply with the parameters associated with the definitions of “substantially similar” when introducing gasoline or gasoline additives into commerce under CAA section 211(f)(1). Fuel and fuel additive manufacturers are expected to comply with any conditions associated with a CAA section 211(f)(4) waiver when introducing gasoline or gasoline additives into commerce under a waiver.

We have made some modifications to the “substantially similar” requirement in response to comments received by stakeholders. We have also added the “substantially similar” requirement to the diesel standards in this final rule in order to comprehensively cover the requirements imposed by CAA section 211(f)(1) and (f)(4) as they pertain to gasoline and diesel fuels. We further address these comments in Section 6 of the RTC document.

B. Diesel Fuel

1. Overview and Streamlining of Diesel Fuel Program

Similar to our approach for the gasoline standards, we are consolidating the diesel fuel standards into a single subpart in part 1090 (subpart D). We are not making any changes to the sulfur or cetane/aromatics standards for diesel fuel, the sulfur standards for diesel fuel additives, or the ECA marine fuel standards. However, we are removing expired provisions that were needed to support the phase-in of the current diesel fuel sulfur program. The phase-in period was completed in 2014; however, these now expired phase-in provisions are imbedded throughout the diesel fuel program regulations in part 80, adding burden to regulated parties in identifying their compliance duties and confusing other stakeholders. As part of the transfer of current part 80 regulations to part 1090, we are also consolidating identical provisions for highway and other diesel fuels into a single regulatory requirement to improve clarity.

We are also making revisions to the part 80 regulations in moving them to part 1090 as discussed in the following sections. First, we are removing the requirement that motor vehicle diesel fuel be free of red dye because we believe this requirement is no longer necessary to evaluate compliance with the diesel sulfur standards. Second, we are streamlining the requirements that pertain to importation of diesel fuel that does not meet EPA standards. Third, we are removing the requirement for ECA marine fuel distributors and associated requirements to include a registration number on PTDs. Finally, we are streamlining the means for downstream parties to redesignate heating oil, kerosene, or jet fuel as ULSD.

We expect that these changes will simplify the diesel fuel programs, resulting in reduced burden associated with demonstrating compliance with the sulfur standards and maximize the fungibility of diesel fuel, allowing the market to operate more efficiently. These changes are not expected to change the stringency of the diesel fuel and IMO marine fuel standards.

2. Removing the Red Dye Requirement

Under the Internal Revenue Code, non-road, locomotive, and marine (NRLM) diesel fuel, heating oil, and exempt highway diesel fuel ^[57] must contain red dye before leaving a fuel distribution terminal to indicate its tax-exempt status. When the sulfur standards for off-highway diesel fuel were less stringent than those for motor vehicle diesel fuel, the presence of red dye was a useful screening tool for EPA to identify potential noncompliance with the sulfur standards for highway diesel fuel. Consequently, part 80 currently requires that motor vehicle diesel fuel must be free of visible evidence of dye solvent red 164 (which has a characteristic red color in diesel fuel), except for motor vehicle diesel fuel that is used in a manner that is tax exempt under section 4082 of the Internal Revenue Code.^[58]

However, as other distillate fuels have become subject to the same 15 ppm sulfur standard that applies to highway diesel fuel, the presence of red dye has ceased to be a useful indicator of sulfur noncompliance. With the completion of the phase-in of EPA's diesel fuel sulfur program in 2014, all highway, nonroad, locomotive, and marine diesel fuel must meet a 15 ppm sulfur standard except for a limited volume of locomotive and marine (LM) diesel fuel produced by transmix processors, which is subject to a 500 ppm sulfur standard. The distribution of 500 ppm LM diesel fuel is subject to separate compliance provisions to ensure that is not misdirected for use in highway, nonroad, locomotive, or marine engines that require the use of 15 ppm diesel fuel (ULSD).

The other potential source of red-dyed high-sulfur diesel fuel that might inappropriately be diverted as highway diesel has been heating oil. However, the vast majority of heating is also currently subject to a 15 ppm standard.^[59] Therefore, we believe that the requirement that red dye should not be present in motor vehicle diesel fuel no longer provides any meaningful added assurance of compliance with ULSD standards. Rather, the existence of this requirement now just complicates the process of providing alternate sources of diesel fuel when supplies of highway diesel fuel are constricted due to extreme and unusual supply circumstances as specified under CAA section 211(c)(4)(C)(ii). State authorities are currently required to request a waiver from both EPA and the Internal Revenue Service (IRS) from the respective agency's red dye requirements to enable the use of 15 ppm NRLM diesel fuel on highway during such circumstances.

Commenters were generally supportive of removing the red-dye requirement. Consequently, we are removing the EPA requirement that motor vehicle diesel fuel must be free from visual evidence of red dye as proposed.^[60] This change does not alter the Internal Revenue Code requirement that NRLM diesel fuel, heating oil, and exempt motor vehicle diesel fuel must contain red dye before leaving a fuel distribution terminal to indicate its tax-exempt status. However, EPA will continue to coordinate with IRS staff in cases where supply issues arise if needed.

3. Importation of Off Spec Diesel Fuel

We are replacing the provisions for the importation of diesel fuel treated as blendstock (DTAB) under part 80 ^[61] with a streamlined procedure to handle imported off-spec diesel fuel. The part 80 provisions require importers to include DTAB in compliance calculations that are no longer applicable, to keep DTAB segregated from other diesel fuel, and limit the importer's ability to transfer title of DTAB. Under part 1090, importers may import diesel fuel that does not comply with EPA standards if certain provisions (which are a subset of those currently required under part 80) are met. Under part 1090, the importer is required to offload the imported diesel fuel into one or more shore tanks containing diesel fuel, sample and test the blended fuel to confirm that it meets all applicable per-gallon standards before introduction into commerce, and keep all applicable records. We believe that this simplification provides the needed flexibility for importers while providing improved clarity.

We received no adverse comments to our proposed streamlining of the DTAB provisions and therefore we are finalizing these provisions as proposed.

4. MARPOL Annex VI Marine Fuel Standards

In this action, we are mostly transposing without change the regulations in subpart I of part 80 for distillate diesel fuel that complies with the 0.10 percent (1,000 ppm) and 0.50 percent (5,000 ppm) sulfur standards contained in MARPOL Annex VI. The U.S. ratified MARPOL Annex VI and became a Party to this Protocol effective January 2009. MARPOL Annex VI requires marine vessels operating globally to use fuel that meets the 0.50 percent sulfur standard starting January 1, 2020 (“global marine fuel”). The MARPOL Annex VI standard is 0.10 percent sulfur for fuel used in vessels operating in designated ECAs.^[62]

In a separate action, we modified the diesel fuel regulations in part 80 to allow fuel manufacturers and distributors to sell distillate diesel fuel meeting the 2020 global marine fuel standard instead of the ULSD or ECA marine standards.^[63] We are incorporating those provisions into part 1090 with minor changes to be consistent with the new part 1090 structure.

Regarding ECA marine fuel, we are including the provisions from part 80 in part 1090 without change save one major exception. Under part 80, distributors of ECA marine fuel from the manufacturer to the point of transfer to a vessel were required to register with EPA and include this registration number on PTDs.^[64] Distributors of other distillate and residual fuels had similar “designate and track” requirements during the phase-in of the ULSD standards for highway and nonroad diesel fuel to allow the temporary use of limited volumes of 500 ppm highway and nonroad diesel fuel under the program's small refiner and credit provisions.^[65] The majority of these requirements gradually expired with the phase-out of the ULSD program's small refiner and early credit provisions that ended in 2014, which had allowed the production of limited volumes of 500 ppm highway diesel fuel. Beginning in 2014, the only fuel distributors still required to register with EPA were those that handle ECA marine fuel and 500 ppm LM diesel fuel produced by transmix processors.^[66]

We believe that the benefit associated with having ECA marine fuel distributors register with EPA does not outweigh the burdens associated with this requirement. All comments received on this issue supported the elimination of the registration requirement for ECA marine fuel distributors, and we are finalizing its removal as proposed.

5. Heating Oil, Kerosene, and Jet Fuel

When we first established the diesel fuel sulfur program under part 80, it required only on-highway or motor vehicle diesel fuel to meet the 15 ppm sulfur standard. In order to implement and enforce this standard and avoid the contamination of ULSD with higher sulfur distillate fuels (which at the time were non-road diesel, heating oil, kerosene, and jet fuel), it required that we include a number of regulatory provision to designate, segregate, and label distillate fuels. Now the 15 ppm sulfur standard to all diesel fuel (motor vehicle, non-road, locomotive, and marine diesel fuel) and, as discussed in Section V.B.2, a state or local 15 ppm sulfur standard applies to most of the heating oil used in the U.S. The provisions designed to avoid contamination of ULSD with higher sulfur distillate fuels are no longer serving any purpose. However, the provisions have remained in place under part 80 despite this change in the distillate fuel market. These obsolete provisions contribute to inefficiency in the distribution system leading to higher costs, and barriers to the free movement of fuel during times of unforeseen supply disruptions (e.g., refinery fires, hurricanes, etc.).

In the NPRM, we proposed to allow heating oil, kerosene, and jet fuel certified to ULSD standards to be redesignated downstream as ULSD for use in motor vehicles and NRLM engines without recertification by the downstream party if certain conditions are met. Under these provisions, downstream parties may rely on documentation from pipelines or fuel manufacturers that the heating oil, kerosene, or jet fuel was certified to meet the 15 ppm sulfur standard and cetane/aromatics specifications to fungibly transport, store, and dispense all 15 ppm sulfur distillate fuels downstream. We also proposed to allow ULSD to be used as heating oil, kerosene, jet fuel, or ECA marine fuel without recertification as long as records are kept demonstrating that the ULSD had been redesignated.

Comments were supportive of the proposed provisions for the redesignation of distillate fuels certified to meet the ULSD standards and we are finalizing these provisions as proposed. We believe that these provisions will maximize the fungibility of distillate fuels, resulting in substantially reduced distributional costs and greater efficiency in the fuels market.

6. Downstream Testing Adjustment for ULSD

In part 80 there is a 2-ppm sulfur downstream testing tolerance for ULSD.^[67] This was not carried over into the proposed part 1090 regulations as diesel sulfur levels are typically much lower than the 15 ppm standard and the opportunities for contamination in the distribution system have been reduced with the establishment of sulfur limits on all gasoline, diesel fuel, and most heating oil. We received a number of comments highlighting that this adjustment remains necessary to account for test variability in the measurement of sulfur in ULSD. Based on these comments, we are including the 2-ppm sulfur downstream testing adjustment for ULSD in part 1090. We believe that the variability in the most commonly used test methods for measuring sulfur in ULSD appears to continue to necessitate the adjustment. In the future, as improvements are made to the measurement of sulfur in ULSD, we may revisit the need for this testing adjustment.

VI. Exemptions, Hardships, and Special Provisions

A. Exemptions

We are transferring provisions that exempt fuels from applicable standards that are currently contained in part 80 to part 1090. We are making minor revisions for purposes of modernizing these exemptions, as well as removing obsolete exemption provisions. Any exemptions that were granted under part 80 will remain in effect with their original conditions as applicable under part 1090. As a result of moving these provisions to part 1090, instead of being scattered through various subparts as is the current practice in part 80, they will be consolidated into a single subpart (subpart G) for all exemptions. This includes those exemptions that require a petition (such as the hardship exemption) and those that do not (such as the export exemption). This structure is designed to increase their accessibility and usability. Consistent with current provisions, exempted fuels, fuel additives, and regulated blendstocks do not need to comply with the standards of part 1090, but remain subject to other requirements (e.g., registration, reporting, and recordkeeping) under part 1090.

We are not making any revisions to exemptions nor the related requirements that apply to fuels used for national security and military purposes, temporary research and development (R&D), racing, and aviation. Similarly, we are not changing the exemption that applies to fuels for use in Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands. Summer gasoline in Alaska, Hawaii, Puerto Rico, and the U.S. Virgin Islands will also continue to be exempt from the federal volatility regulations.

We are, however, making minor revisions to these exemptions for consistency and as a result of consolidating the various part 80 exemptions, and to modernize the exemption provisions. First, we are including language that imposes conditions on parties operating under an R&D test program to prevent the inadvertent use of test fuels exempted under a temporary R&D exemption by participants not included in the test program. Recently, we have received requests for R&D exemptions that focus on the effects of a certain fuel's use in more real-world operation conditions (as opposed to a contained laboratory type situation). This often requires the test fuel be made available in a way that could result in vehicles or engines not included as part of the R&D program inappropriately using the test fuel. We believe it is appropriate for applicants requesting such an R&D exemption to take reasonable precautions to prevent consumers not participating in the test program from fueling with the test fuel. We requested comment on procedures that could be applied to fuels being tested under an R&D exemption when the test includes consumer participation that could result in the aforementioned misfueling. However, we received no comments on this topic and therefore are finalizing the R&D exemption provisions as proposed. We address comments related to the R&D exemption in Section 9 of the RTC document.

Second, we are allowing certain exemptions for fuel additives and regulated blendstocks. Under part 80, it was unclear whether some exemptions applied to fuel additives and regulated blendstocks under certain programs, such as the gasoline sulfur program. Under part 1090, fuel additives and regulated blendstocks will now be exempt from applicable requirements if certain conditions are met. For example, the military use exemption now explicitly exempts fuels, fuel additives and regulated blendstocks used in either military vehicles or in support of military operations.

Third, we are finalizing as proposed the regulatory provision to prevent contamination of motor vehicle fuels by exempt fuels, such as racing and aviation gasoline containing lead additives, at 40 CFR 1090.615(c) (which is carried over from part 80). This regulatory provision requires the segregation of exempt fuels from production through consumption. We had also proposed a new provision at 40 CFR 1090.615(e) that was also designed to shore up protection against contamination of motor vehicle fuels during distribution by tanker trucks. For example, when a tanker truck carrying exempt racing gasoline or aviation gasoline is later used to transport non-exempt gasoline, residual exempt gasoline could remain in the tanker truck and contaminate the non-exempt gasoline. We referred regulated parties to follow established voluntary consensus-based standards for managing the transportation of both exempt and non-exempt fuels in the same transportation vessel.^[68]

A commenter requested that we remove the proposed examples that referenced industry guidance from the regulations because these standards can change over time. In response to those comments, we considered incorporating these API and EI/JIG standards by reference, or drafting and including appropriate portions of these standards into part 1090. However, in reviewing the regulations we realized that the new provision proposed at 40 CFR 1090.615(e) may be superfluous with the existing requirement for product segregation throughout the entire distribution system now under 40 CFR 1090.615(c). The intent of proposed 40 CFR 1090.615(e) had been to enhance the prevention of product contamination in cases when both exempt and non-exempt fuels are being transported in the same transportation vessel. However, in some cases, this provision could have been interpreted as relaxing product segregation requirements when exempt fuels are being transported using transportation vessels totally dedicated to that fuel. This was not our intent. For this reason, we will continue to rely on the existing regulatory language at 40 CFR 1090.615(c).

Finally, California gasoline and diesel fuel used in California are currently exempt from the part 80 standards in separate provisions under the various subparts. We are consolidating these existing exemptions for California fuels into a single comprehensive section. This reorganization eliminates the redundancy that resulted as new programs were implemented with California exemptions and old programs sunsetted but remained in the regulations with their original California fuels exemption. Additionally, housing all the provisions for the California fuels exemption in one section facilitates compliance with its requirements, as regulated parties need not scour part 1090 for hidden exemption provisions.

We are also creating provisions that clarify how California gasoline and diesel fuels may be used in states other than California. Under part 80, fuel manufacturers that make California gasoline and diesel fuel must recertify those fuels in order to sell them outside the state of California.^[69] Under part 1090, we are providing California fuel manufacturers and distributors the choice of whether to recertify the California fuel, as currently required under part 80, or redesignate the California fuel without recertification if certain conditions are met. In order for a fuel manufacturer or distributor of California gasoline to redesignate without recertification such fuel for use outside of California, the fuel must meet all applicable requirements for California reformulated gasoline under Title 13 of the California Code of Regulations and the manufacturer or distributor must meet applicable designation and recordkeeping requirements.^[70] Under part 1090, parties that redesignate California gasoline without recertification for use outside of California would not be permitted to generate sulfur or benzene credits from the redesignated fuel. Similarly, California diesel fuel used outside of California would be deemed in compliance with the standards of this part if it meets all the requirements Title 13 of the California Code of Regulations and the manufacturer or distributor meets applicable designation and recordkeeping requirements.^[71]

B. Exports

We are transferring the current part 80 exemption from applicable standards for fuels, fuel additives, and regulated blendstocks that are designated for export to part 1090. Additionally, we are transferring requirements for designation, PTDs, and gasoline segregation for fuels designated for export that currently apply under part 80 to part 1090.

In the NPRM, we proposed that in order for a fuel, fuel additive, or regulated blendstock to receive an export exemption, it would have to be segregated from the point of production to the point of exportation from the U.S. Commenters suggested that the inclusion of fuel additives and regulated blendstocks in the segregation requirement for exports was unnecessary, as exported fuel additives and regulated blendstocks do not need to be segregated and are unlikely to cause fuel quality issues if commingled. As such, we are not finalizing a segregation requirement for exported fuel additives and regulated blendstocks.

Regarding exported fuels, commenters suggested that we should only require that exempt fuels for export be segregated from non-exempt fuels from the point that the fuel was designated as for export until the fuel is exported. Commenters stated that the proposed segregation requirement could create challenges, as often times fuels for export are produced simultaneously with fuels for domestic use. To avoid unintended increases in the burden of producing domestic and exported fuels, we have revised the segregation requirement for fuels to begin at the point of designation.

Commenters also asked for more clarity on how diesel fuel export segregation requirements would work under part 1090. Under part 80, diesel fuel not designated for export can be exported without restriction as long as it meets the applicable fuel quality standards. However, the fuel remains subject to the provisions of this part while in the U.S. For example, diesel fuel designated as ULSD must meet the applicable sulfur standards even if it will later be exported. Such diesel fuel that meets ULSD standards would not need to be segregated and may be redesignated for export by a distributor. On the other hand, diesel fuel that does not meet the ULSD standards would need to be designated for export and segregated from the point of designation until it is exported, as currently required under part 80.

We address other comments related to exports in Section 9 of the RTC document.

C. Extreme, Unusual, and Unforeseen Hardships

Under part 80, the various subparts associated with each standard include separate provisions for receiving an exemption from that subpart's fuel quality standards due to extreme, unusual, and unforeseeable hardship. We are consolidating these exemptions into one hardship provision for extreme, unusual, and unforeseeable circumstances (e.g., a natural disaster or refinery fire excluding financial and supply chain hardship) that a refinery cannot avoid with prudent planning.^[72] The part 1090 organization is intended to make the hardship provision easier to find and does not change either the opportunity for a hardship or the regulated party's burden to demonstrate that its circumstances satisfy the requirements for applicable hardship exemptions. This change applies only to the standards in part 1090; the parallel provision for the RFS program requirements remains in part 80. Accordingly, any exemptions available under the RFS program would similarly remain unaffected.

Commenters on the proposed extreme, unusual, and unforeseen hardship provision objecting to the explicit exclusion of financial and supplier difficulties from the grounds for hardship relief. The commenter described this language as a change from the extreme, unusual, and unforeseen hardship provisions of part 80. We believe that this is a clarification of the kinds of extreme, unusual, and unforeseen events that qualify for relief under this hardship provision under part 80. As such, we are finalizing the extreme, unusual, and unforeseen hardship provision as proposed and have addressed the comment in Section 9 of the RTC document.

VII. Averaging, Banking, and Trading Provisions

A. Overview

We have often used averaging, banking, and trading (ABT) provisions as a means to both meet our environmental objectives and provide regulated parties with the ability to comply with our fuel standards in the most efficient and lowest cost manner. As such, they are integral to our standards and we are transferring the currently applicable ABT provisions for gasoline sulfur and benzene from part 80 to part 1090.^[73] In doing so, we are making modifications that will facilitate consolidation of these various ABT regulatory provisions in part 80 into a single set of ABT provisions in part 1090. In particular, this includes changes to how gasoline manufacturers can account for oxygenate added to gasoline downstream of fuel manufacturing facilities in compliance calculations. It also includes a new mechanism that allows downstream parties that recertify batches of gasoline to use different types and amounts of oxygenate downstream of a manufacturing facility. We are not transferring expired part 80 ABT provisions that were temporary provisions associated with initial implementation of the standards, such as the separate ABT provisions for small refiners and small volume refineries that expired at the end of 2019.

B. Compliance on Average

We are finalizing minor changes to the format of the average compliance calculations to align the sulfur and benzene compliance calculations more closely with each other and accommodate consolidating annual compliance reporting into a single reporting format. Under part 80, compliance with the benzene and sulfur average standards is demonstrated in separate forms and use a slightly different nomenclature. These changes to the compliance calculations will not affect how gasoline manufacturers currently comply with the average standards or their stringency; however, the streamlined equations appear slightly different compared to the similar equations in part 80. We are also adding to the compliance calculation the deficits incurred on an annual basis due to the recertification of BOBs downstream to use a different type(s) and amount(s) of oxygenate. We discuss this change in detail in Section VII.G.

As previously noted, part 80 regulations had separate ABT provisions for small refiners and small volume refineries associated with the initial implementation of the gasoline sulfur and benzene standards that have expired. The last such provisions related to the Tier 3 gasoline sulfur program, which expired on December 31, 2019, resulting in small refiners and small volume refineries being required to comply with the same part 80 fuel quality standards and use the same ABT provisions as other refiners. As a result, part 1090 does not include separate ABT provisions for small refiners and small volume refineries.

C. Deficit Carryforward

Under part 80 we allow gasoline manufacturers to carryforward deficits for the gasoline and sulfur benzene standards, whereby an individual fuel manufacturing facility that does not meet either the sulfur or benzene standard in each compliance period may carry a credit deficit forward into the next compliance period. Under this deficit carryforward allowance, the manufacturer for the facility must make up the credit deficit and come into compliance with the applicable standard(s) in the next compliance period. In part 1090, we are consolidating the separate gasoline sulfur and benzene deficit carryforward provisions from part 80 into a single provision and slightly modifying the language simply to accommodate the consolidation. We do not believe that the modifications will substantively affect how gasoline manufacturers are permitted to carry forward deficits.

Commenters requested additional flexibilities related to the deficit carryforward provisions. However, we are not finalizing any additional flexibility related to deficit carryforward. These comments are addressed in Section 10 of the RTC document.

D. Credit Generation, Use, and Transfer

We are also transferring the part 80 credit generation, use, and transfer provisions for gasoline manufacturers to part 1090. We are making minor changes to the language largely to ensure consistency between the sulfur and benzene credit trading programs.

We are not making any changes to the lifespan of generated credits (i.e., credits generated under part 1090 have the same lifespan as afforded them under part 80). Additionally, credits generated under part 80 are still usable to comply with average standards under part 1090. To facilitate the use of part 80 credits under part 1090, we are including language to make it clear that credits generated under part 80 are still valid for compliance under part 1090 for the specified life of the credits under part 80. For example, credits generated for the 2020 compliance period could be used through the 2025 compliance period.

In general, we are finalizing the credit generation, use, and transfer provisions of part 1090 as proposed. We did, however, receive several comments that suggested clarifying edits to the regulations. These comments are addressed in Section 10 of the RTC document.

E. Invalid Credits

We are transferring the part 80 provisions for treatment of invalid credits to part 1090 without modification. Since the establishment of the sulfur and benzene ABT programs, we migrated tracking of credit transactions into the EPA Moderated Transaction System (EMTS). We did not receive substantive adverse comments related to the treatment of invalid credits under part 1090 and we are finalizing the provisions related to invalid credits under part 1090 as proposed. We did however receive a comment asking about published guidance for remedial actions to address issues related to invalid credits in EPA electronic reporting systems. We address this comment in Section 10 of the RTC document.

F. Downstream Oxygenate Accounting

Under part 80, we provided several mechanisms, depending on the gasoline program, for refiners and importers to account for oxygenate added downstream. Under the current part 80 RFG provisions for oxygenate blending and accounting, refiners and importers create a hand blend, test the hand blend for reported parameters, and include these values in their compliance calculations to demonstrate compliance with the sulfur and benzene average standards and the RFG performance standards. The refiner or importer then specifies the type(s) and amount(s) of oxygenate on PTDs to be added by the oxygenate blender, who must then follow the blending instructions by the refiner or importer. Further, refiners and importers must contract with an independent surveyor to verify that an oxygenate is added downstream at levels reported to EPA in batch reports.

While there are provisions in part 80 for refiners and importers of CG to also account for downstream oxygenate addition, they are much more limited and difficult to utilize given the fungible nature of most CG and conventional gasoline before oxygenate blending (CBOB) and the requirements imposed. CG/CBOB refiners and importers can only account for oxygenate if the refiner or importer can establish that the oxygenate was in fact added to the CG/CBOB. This regulatory disparate treatment of CG and CBOB compared to RFG and reformulated gasoline before oxygenate blending (RBOB) has created a scenario where it is more difficult for CG/CBOB refiners and importers to account for the benefits of the addition of downstream oxygenates at a time when virtually all gasoline now has ethanol added downstream.

In order to remedy this disparity, we are finalizing a single method for gasoline manufacturers to account for oxygenate added downstream of a fuel manufacturing facility to comply with the average sulfur and benzene standards, as proposed. In part 1090, we are requiring gasoline manufacturers to use “hand blends” when accounting for oxygenate added downstream. We are also requiring that oxygenate blenders follow instructions for the type(s) and amount(s) of oxygenate from the BOB manufacturer. These requirements for gasoline manufacturers and oxygenate blenders under part 1090 largely mirror the requirements for oxygenate blending and accounting found in the RFG program under part 80.

The main differences between the part 1090 hand blend approach and the part 80 RFG program is that the accompanying in-use survey under part 1090 will be national in scope (instead of just a survey of RFG areas), and the BOB manufacturer must participate in NSTOP.^[74] Additionally, since we are broadening the scope of the oxygenate accounting process from RBOB to all BOB, we are also requiring that gasoline manufacturers prepare samples using the hand blend procedures in ASTM D7717 and that commercially available oxygenate (e.g., DFE) be used to make hand blends. The oxygenate used should reflect the anticipated sulfur and benzene levels of the oxygenate that will ultimately be blended with the BOB. All other part 1090 requirements are the same as currently specified for the RFG program under part 80.

In the NPRM, we sought comment on whether to allow for alternative mechanisms for downstream oxygenate accounting. We received comments suggesting that we include provisions to allow fuel manufacturers to use a set of specified assumptions for benzene, sulfur, and oxygenate content values to account for oxygenate added downstream. For reasons discussed in detail in Section 10 of the RTC document, we are only finalizing the proposed hand blend approach.

We also received other comments with suggestions or requests for clarification regarding the downstream oxygenate accounting provisions, which we have reflected in the final regulations as appropriate. We address these comments in Section 10 of the RTC document.

G. Downstream BOB Recertification

We are finalizing provisions that will allow parties to recertify BOBs downstream for different type(s) and amount(s) of oxygenate (including E0) if certain requirements are met. Under the part 80 RFG program, oxygenate blenders must add the type(s) and amount(s) of oxygenate to RBOB as specified by refiners.^[75] Refiners must specify blending instructions for all RBOB, most of which is to be made into E10. An oxygenate blender that recertifies a batch of RBOB under part 80 is a gasoline refiner and must comply with all the applicable requirements for a gasoline refiner. These requirements include registration under part 79 as a fuel manufacturer, registering under part 80 as a refiner, complying with sulfur and benzene average standards, and batch sampling and testing. As a result of the cost associated with recertifying batches of RBOB downstream in keeping with these requirements under the part 80 RFG program, oxygenate blenders have not typically opted to assume the role of a gasoline refiner. This has all but precluded the availability of E0, E15, and the use of isobutanol in RFG areas. The batch sizes are relatively small (typically the volume of a single tanker truck) and do not support the added cost.

These restrictions, currently limited to RFG areas under part 80, would have been compounded by the expansion of the downstream oxygenate accounting flexibility to all gasoline under part 1090 discussed in Section VII.F. As such, we are including a downstream certification mechanism to allow for oxygenate blenders to recertify batches of BOB for different types and amounts of oxygenates as the market demands to make sure that consumers can still have E0, E15, or isobutanol-blended gasoline available as needed. In other words, under part 1090, oxygenate blenders must follow the blending instructions on PTDs by gasoline manufacturers unless they recertify the batch for a different type and/or amount of oxygenate.

Under part 1090, we are requiring that parties that wish to recertify BOBs must determine the number of sulfur and benzene credits lost by any lack of downstream oxygenate dilution in cases where the party added less oxygenate than was specified by the gasoline manufacturer. For example, if a party takes a premium BOB intended for blending with ethanol at 10 volume percent and wishes to use it as E0 for recreational vehicles, they would need to make up for the lost dilution of the sulfur and benzene in the national gasoline pool. We have included additional compliance calculations that such parties would need to use to determine the number of sulfur and benzene credits needed. In this calculation, we use default assumed values for the amount of sulfur and benzene from the BOB and are setting default values of 11 ppm sulfur and 0.68 volume percent benzene. These values are reflective of the national sulfur and benzene average values adjusted for the absence of DFE added at 10 volume percent ethanol.^[76] The goal of these values is to avoid requiring additional sampling and testing from the recertifying party. We believe that due to the small batch volume for recertified product, typically the size of a tanker truck, the amount of credits needed for any given batch of recertified gasoline will be low and small changes from actual benzene and sulfur content will likely be offset by improved compliance oversight in other areas of the program, as discussed in Section XIV.

We received comments on the proposed compliance calculations for downstream BOB recertification and have made some minor modifications based on suggestions from commenters. These changes are discussed in more detail in Section 10 of the RTC document.

In cases where a party adds the same volume of oxygenate or more, these credit makeup regulations do not apply, as more than enough sulfur and benzene dilution will have occurred (e.g., adding 15 volume percent ethanol into a BOB intended for the addition of 10 volume percent ethanol or adding 12 volume percent isobutanol to a batch of BOB intended for the addition of 10 volume percent ethanol). All other applicable requirements under the CAA and EPA regulations would apply to the recertified fuel. For example, the recertified gasoline would need to meet RVP requirements in the summer, meet per-gallon sulfur requirements, and be substantially similar under CAA section 211(f) or meet all waiver conditions under CAA section 211(f)(4). Part 80 currently does not allow oxygenate blenders to generate credits in cases where additional oxygenate is added to RBOB or CBOB and part 1090 does not change this. The challenges associated with implementing and enforcing such a credit provision with so many entities on such small volumes has historically created considerable difficulties, and there does not appear to be any compelling reason here to change from the current regulations.

We received several comments asking for clarity on how the downstream BOB recertification requirements apply to parties that add the same or more oxygenate to a BOB. We have added language to the regulations that clarify that these parties do not incur deficits and are not expected to submit additional reports as fuel manufacturers. We address these comments in Section 10 of the RTC document.

In order to ensure that parties that recertify BOBs downstream adhere to the provisions for downstream oxygenate recertification, we are requiring that these parties register with EPA, transact for any needed sulfur and benzene credits, submit annual compliance reports, and keep records documenting the blending activities and reports submitted to EPA. In lieu of requiring the burden of sampling and testing each batch, we are also requiring that these parties simply undergo an annual attest engagement audit and submit an attest report similar to the report required for gasoline manufacturers. These requirements would only apply to parties that incur a deficit by recertifying BOBs with less oxygenate than specified on the PTD. If a party is already registered with EPA and complies with sulfur and benzene averaging requirements, they must include the total number of credits needed as a result of downstream oxygenate recertification in their annual compliance calculations as a deficit.

In the NPRM, we proposed to exempt parties that blended 200,000 gallons or less per year from the annual attestation audit for purposes of reducing the potential costs for small volume blenders that recertify BOBs. We sought comment on both the 200,000-gallon threshold and whether additional flexibility was needed to control costs for small volume blenders. Several commenters requested an increase of the annual threshold, ranging from 1,000,000 to 2,000,000 gallons per year. We also received several comments suggesting that we exempt these small volume blenders from not only the annual attestation engagement, but also the deficits themselves or from having any compliance burden whatsoever. Commenters argued that without either increasing the threshold or reducing the compliance burden, BOB recertification would still be prohibitively expensive and limit the availability of E0 and isobutanol blends for vehicles and engines where their use is recommended (e.g., marine engines).

Based on these comments, we believe it is appropriate to both increase the exemption threshold and provide additional flexibility for small volume blenders to avoid unnecessarily increasing the costs of such blends. Therefore, we are increasing the annual threshold to 1,000,000 gallons per year. We are also exempting parties that blend 1,000,000 gallons or less per year from incurring sulfur and benzene deficits related to downstream BOB recertification. In combination, we believe these changes will provide adequate flexibility for parties that recertify BOBs to supply E0 and isobutanol blends while also ensuring that large volume blenders do not significantly increase the national average sulfur and benzene levels. These small volume blenders are still required to register, report, and keep records under part 1090. We believe these requirements are necessary to help ensure oversight of the program and do not anticipate that this will substantially increase burdens on such blenders, as many of these parties already are registered with EPA and submit reports under part 80.

Because the downstream BOB recertifications were a new flexibility under part 1090, we sought comment on several issues, including whether there were alternative mechanisms to allow for downstream BOB recertification that would be less burdensome. While several commenters suggested that the proposed downstream BOB recertification provisions were unnecessary, we did not receive any comments suggesting an alternative mechanism to allow parties to recertify BOBs downstream. We address comments suggesting that the downstream BOB recertification provisions are unnecessary in Section 13 of the RTC document.

We did not propose a deficit carryforward for deficits incurred from downstream BOB recertification, as we believed that the amount of credits needed to satisfy such deficits would be relatively small, parties may fail to satisfy those deficits, and enforcement would be impractical. Nevertheless, we sought comment on whether to allow for a deficit carryforward for deficits incurred under the proposed downstream BOB recertification provisions. Several commenters suggested that we should provide such deficit carryforward provisions. However, in light of the exemption provided for volumes up to 1,000,000 gallons per year as discussed earlier, and for reasons explained in more detail in Section 13 of the RTC document, we are not providing deficit carryforward provisions for deficits incurred from downstream BOB recertification.

Several other commenters suggested modifications to the downstream BOB recertification provisions. We address these comments in Section 13 of the RTC document.

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

A. Overview

This rule transfers and consolidates many of the existing part 80 registration, reporting, PTD, and recordkeeping provisions in new part 1090. As discussed in the NPRM, we have sought to reduce the impacts on regulated parties and reduce the burden associated with maintaining and submitting information, an approach generally supported by commenters. In certain cases, we have simplified and better aligned reporting requirements with current industry practice, which is particularly true of the batch reporting requirements described in greater detail in Section VIII.C.

Except for certain information discussed in Section XIII.H, information submitted under part 1090 may be claimed as confidential business information (CBI) by the submitter, including certain information submitted via registration and reporting systems. EPA will treat such information from public release in accordance with the provisions of 40 CFR part 2, subpart B. Our public release of EPA enforcement-related determinations and EPA actions, together with basic information regarding the party or parties involved and the parameter(s) or credits affected, does not involve the release of information that is entitled to treatment as CBI. Information that may be publicly released may include the company name and company identification number, the facility name and facility identification number, the total quantity of fuel and parameter, and the time period when the violation occurred. Enforcement-related determinations and actions within the scope of this release of information include notices of violation, administrative complaints, civil complaints, criminal information, and criminal indictments. We did not propose a comprehensive CBI determination and, therefore, are not finalizing one here.

B. Registration

1. Purpose of Registration

Registration is necessary to: (1) Identify parties engaged in regulated activities under EPA regulations; (2) allow regulated parties access to systems to submit information required under EPA's fuel quality regulations; and (3) provide regulated parties with company and compliance-level identification numbers for producing PTDs and other records. Part 1090 makes modest changes to the existing registration system, including modernizing certain terminology and updates that make registration easier to understand and implement.

A number of commenters sought clarification on the proposed registration requirements under part 1090 and we have incorporated them to the extent appropriate. We address these comments in detail in Section 11 of the RTC document.

2. Who Must Register

The registration regulations update terminology to better reflect current roles and activities in the fuel production and distribution system. This rule includes registration requirements for certain third parties, such as auditors. These are explained in greater detail below. The following parties must register with EPA prior to engaging in any activity under part 1090:

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

Nearly all parties who are subject to registration under part 1090 are already registered under part 80. We did not propose to require parties who are already registered under part 80 to go through the effort to re-register their company or their facilities under part 1090. Some commenters specifically stated that they believe parties should not have to re-register and we agree.

Part 1090 includes specific provisions that ensure such parties do not need to re-register. For example, although we do not currently register parties under part 80 as “gasoline manufacturers,” parties who are currently registered as “refiners” are covered under this new term and do not have to re-register. We do not believe that migration of part 80 requirements to part 1090 will result in a significant number of new registrants, and existing registrants will only need to make the type of routine registration updates they already are required to make (e.g., to add or delete activities they engage in or to change an address). Existing registrants may also need to access the registration system in order to associate with auditors or other third parties who will submit reports on their behalf. Association is a step within the existing registration system and is designed to ensure that the company for which the reports are submitted by a third party agrees to that arrangement. Association is designed to be a simple step that would still prevent an unauthorized party from submitting reports on another's behalf without their consent or knowledge.

Part 1090 removes the registration requirement for independent laboratories that existed in part 80. As a result, independent laboratories are no longer required to register unless they submit information directly on behalf of another party, such as a gasoline manufacturer. In such cases, they will need to update their registration to reflect that they are submitting reports on behalf of a regulated party and will have to associate with the company or companies for which they will submit reports.

We are finalizing registration requirements for independent surveyors and auditors under part 1090. These parties were not subject to registration requirements under part 80, but either submit survey plans and periodic reports to EPA under various provisions or perform attest engagements for regulated parties. Independent surveyors perform the compliance surveys and the voluntary sampling oversight program (discussed in more detail in Section X). At present, there is only one known independent surveyor, performing four types of surveys under part 80. As previously noted, independent surveyors already submit survey reports to EPA, in a variety of ways. As discussed in Section VIII.C.9, independent surveyors have to register with EPA so that they may submit reports via EPA's reporting systems. Although this would create a small, new class of registrants (currently only one new submitter), we believe the burden of registering is outweighed by the simplicity and reliability of having surveyors utilizing the electronic reporting system to submit their information. Having the independent surveyor register and be able to submit reports via EPA's established reporting system will allow us to more quickly publicly post in-use survey results.

As also previously noted, auditors already performed attest engagements on behalf of parties who are required to demonstrate compliance via reporting. Under part 80, the regulated party (e.g., a gasoline manufacturer) is required to engage an auditor to perform the attest engagement, and the auditor gives the attest engagement to the party who then must submit it to EPA. Some parties have found this process cumbersome. In order to streamline the reporting process, we proposed to establish a means by which auditors may submit the attest engagement directly to EPA and in a manner that ensures the party for whom it was performed is aware of the submission. To implement this change, auditors will register and associate with the regulated party; then, the auditor will submit reports directly to EPA. This will ensure that they are submitting reports on behalf of a regulated party and that the attest engagement is properly submitted. This will also help EPA to contact the company and the auditor regarding any difficulty with the submission.

3. What Is Included in Registration

Like the existing provisions in part 80, registration under part 1090 entails submitting general information about the company and its compliance-level activities (e.g., facilities), including the address, activities engaged in, name of a responsible corporate officer (RCO), contact information, and location of records. Parties who submit reports to EPA must complete the steps required to set up an account with EPA's Central Data Exchange (CDX) and/or with OTAQ Registration (OTAQReg). Most regulated parties affected by this action have already registered and set up the necessary accounts. Part 1090 updates the terminology for companies to more modern usage; it does not change the fundamental activity or purpose of registration.

4. Deadlines for Registration

Under part 80 new registrants have to register 60 days prior to engaging in regulated activity. This timeframe remains a useful guideline, as we must be allowed an appropriate amount of time to process and activate registration-related requests. Part 1090 requires that registration occur 60 days prior to a party engaging in any activity that requires registration. We are retaining the requirements from part 80 that updates to existing registration must occur within 30 days of the event requiring the change. As previously discussed, we do not expect many new registrants under part 1090, as existing registrants under part 80 will continue to be registered under part 1090. Company and compliance-level (e.g., facility) identification numbers issued under part 80 will remain valid under part 1090. We do, however, anticipate newly registering up to 100 auditors, one surveyor, and 50 third parties.

5. Changes in Ownership

As explained in the NPRM, we have received feedback over the years from registrants that changes in ownership should be addressed more clearly in the regulations. Consequently, we proposed provisions to clarify how a company may initiate a change in ownership for registration purposes. The provisions on updating registrations for ownership change largely codify existing guidance provided to companies under part 80.

Part 1090 clarifies that companies will have to notify EPA of a change in ownership and, in cases requiring registration of a new company, complete registration prior to engaging in any activity requiring registration. In the case of a change in ownership requiring an update to an existing registration, a company will need to complete the registration update within 30 days of the change. For any party that is a fuel or fuel additive manufacturer, the new owner will need to be in full compliance with any applicable part 79 registration requirements.

Since part 1090 registration is needed in order to report and engage in credit transactions and comply with the fuel quality regulations, parties have great incentive to submit ownership change information to EPA as soon as it is available. We have received feedback from stakeholders who have told us that having a requirement that they submit ownership change information by a specific, advance deadline (e.g., 60 days before the change in ownership occurs as currently required under part 80) is not workable due to how ownership changes are effectuated in the business world. Although we did not propose, and are not finalizing, a specific, advance deadline, we note that it may take several days or weeks for EPA to process a new registration and urge companies to attempt to submit materials as soon as possible and to consider that 60 days prior to ownership change as a good guideline. Based on our experience with ownership changes under part 80, companies will want EPA to activate registration changes for ownership changes in a timely manner to ensure that registrations are up-to-date and that the company can engage in credit generation, trading, and use as soon as practical. Often, these companies request a specific date for the ownership change to be reflected with respect to their registration. Because many ownership changes in the fuel quality programs are complicated and involve many facilities, for EPA to reasonably act on this type of registration update, we need adequate time to process registration changes.

We believe common ownership changes may include companies and/or facilities that are bought in their entirety by another party; companies and/or facilities whose majority owner changes; or a merger resulting in creation of a new company and/or facility. We are not finalizing a specific list of documentation that parties may have to submit to support a change in ownership affecting their registration. What documentation, if any, is needed is highly situational. However, we do have experience with typical documentation submitted by parties that may be appropriate, and that may include: sale documentation or contract (portions of which may be claimed as CBI and redacted); Articles of Incorporation, Certificate of Incorporation, or Corporate Charter issued by a state; and/or other legal documents showing ownership (e.g., deeds). Parties anticipating the need to update registration due to a change in ownership should contact EPA as soon as possible in order to discuss their unique situation.

6. Cancellation of Registration

We are finalizing new provisions for voluntary and involuntary cancellation of registration under part 1090. Similar provisions exist for the RFS program in 40 CFR part 80, subpart M, and we believe they work well for both compliance and compliance assistance purposes under part 1090.

Voluntary cancellation is initiated by the registered party (e.g., if the party's business changes and it no longer engages in an activity that requires registration). We are including voluntary cancellation language in part 1090 because registered parties often ask for clarification of the procedure involved.

Involuntary cancellation is initiated by EPA, typically in cases where the party has failed to submit required reports or attest engagements, or for a prolonged period of inactivity. Specifically, involuntary cancellation may occur where:

• The party has not accessed its account or engaged in any registration or reporting activity within 24 months.
• The party has failed to comply with any registration requirements, such as updating needed information.
• The party has failed to submit any required notification or report within 30 days of the required submission date.
• The attest engagement has not been received within 30 days of the required submission date.
• The party fails to pay a penalty or to perform any requirements under the terms of a court order, administrative order, consent decree, or administrative settlement between the party and EPA.
• The party submits false or incomplete information.
• The party denies EPA access or prevents EPA from completing authorized activities under sections 114 or 208 of the CAA despite presenting a warrant or court order. This includes a failure to provide reasonable assistance.
• The party fails to keep or provide the records required by part 1090.
• The party otherwise circumvents the intent of the CAA or part 1090.

We will provide notification of our intention to cancel the party's registration and the registrant will have an opportunity to address any deficiencies identified in the notice (e.g., to submit required reports) or to explain why no deficiency exists. If we do not receive missing reports within 30 days of notification, then the registration may be canceled without further notice. We believe it is important to have a procedure to keep registrations up-to-date and to ensure that parties perform activities required to maintain active registration. Several commenters noted that there was a discrepancy in the NPRM between the preamble and the regulations regarding the period by which missing reports must be received. The NPRM preamble said 14 days, but the regulatory text said 30 days. We are clarifying that we intended the longer response time (i.e., 30 days).

In instances of willfulness or where public health, interest, or safety requires, EPA may deactivate the registration of the party without any notice to the party. In such cases, EPA will provide written notification to the RCO identifying the reason(s) EPA deactivated the registration of the party. We expect such situations to be extremely rare.

C. Reporting

1. Purpose of Reporting

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

A number of commenters sought clarification on the proposed reporting requirements under part 1090 and we have incorporated them to the extent appropriate. We address these comments in detail in Section 12 of the RTC document.

2. Who Must Report

The following parties would have to report under part 1090:

• Gasoline manufacturers
• Diesel manufacturers and ECA marine manufacturers
• Transmix Processors
• Oxygenate producers
• Certified butane blenders
• Certified pentane producers
• Certified pentane blenders
• Independent surveyors
• Auditors

As discussed in Section VIII.B, certain parties are required to register to receive company and compliance-level identification numbers for use on PTDs and for recordkeeping, although they do not have reporting requirements under part 1090. For example, parties involved in the manufacture and distribution of 500 ppm LM diesel fuel are required to register and receive company and compliance-level identification numbers to use on PTDs and records but do not submit reports under part 1090.

3. Key Differences Between Part 1090 and Part 80

We are eliminating reporting of the following gasoline parameters that are currently collected under part 80 and no longer necessary under part 1090 to certify batches and demonstrate compliance with the RFG standards (discussed in more detail in Section V.A.2):

• Aromatics and the associated test method
• Olefins and the associated test method
• Methanol and the associated test method
• MTBE and the associated test method
• Ethanol and the associated test method
• ETBE and the associated test method
• TAME and the associated test method
• T-Butanol and the associated test method
• T50 and the associated test method
• T90 and the associated test method
• E200 and the associated test method
• E300 and the associated test method
• Toxics (as a percent reduction from baseline)
• VOCs (as a percent reduction from baseline)
• Exhaust Toxics Emission
• Other identifying information (i.e., Batch Grade, lab waiver, independent lab analysis requirement)

We are retaining the four main parameters for gasoline reporting: Sulfur, benzene, RVP, and oxygenate type/content.^[77] The parameters being eliminated from reporting, although once useful, are no longer needed in reports, as discussed in Section V.A.2. Removing these parameters reduces compliance costs related to reporting, sampling, and testing, without sacrificing our goal of protecting human health and the environment. Under part 1090, we are also simplifying the annual, batch, and credit transactions reporting, which results in many fewer forms and data elements for respondents.

Under part 80, there are numerous reporting forms in use; these reporting forms are now simplified and reduced under part 1090. Reporting forms and format are available in the docket for this action and have also been included in the information collection request (ICR) described in Section XV.C.

4. Reporting Requirements for Gasoline Manufacturers

As previously discussed, we are transferring the current part 80 requirements for annual, batch, and credit transaction reporting for gasoline manufacturers to part 1090. In doing this, we are also eliminating collection of information that is no longer necessary, reducing the number of parameters and test methods reported, simplifying the type and number of reports to be filed, and, in many cases, reducing the frequency of reporting (e.g., going from quarterly to annual).

The reporting requirements for gasoline manufacturers include the following:

• Annual compliance demonstration for sulfur, to include information about the total volume of gasoline produced or imported, the compliance sulfur value, summary information about sulfur credits owned, generated, retired, etc., and information about credit deficits.
• Annual compliance demonstration for benzene, to include information about the total volume of gasoline produced or imported, the compliance benzene value, summary information benzene credits owned, generated, retired, etc., and information about credit deficits.
• Batch reporting, including information about individual batches of gasoline, to include information about the date of production or import, the volume, the designation of the gasoline or BOB, the tested sulfur and benzene content of the batch, and the tested RVP for summer gasoline or BOB. The regulations address reporting for gasoline, oxygenates, and regulated blendstocks and explain reporting for specific scenarios, such as the reporting for blendstocks added by gasoline manufacturers to PCG by either the compliance by addition or compliance by subtraction method and reporting for blending of certified butane or pentane. We have prepared a detailed color-coded batch reporting summary table as part of the reporting form instructions and this table reflects the information to be submitted for a variety of products. This information is available in the docket for this action and has been provided as an addendum to the ICR described in Section XV.C.
• Credit transaction reporting, including information about the generation, purchase, sale, retirement, etc. of sulfur and benzene credits.
• Attest engagements. Under part 1090, we have changed the method of submission of annual attest engagements. Under part 80, refiners and importers submit attest engagement reports themselves. Under part 1090, the attest engagement report will be submitted on the fuel manufacturer's behalf by the auditor. Fuel manufacturers remain responsible for engaging an auditor to conduct the attest engagement, and for ensuring that a proper attest engagement is submitted to EPA. To do this, as explained in Section X.A.2.d, the auditor will register with EPA and be associated with a registered company. To ensure that the auditor and the company for whom they are preparing the report agree, these parties must associate with each other within the registration system. This action aligns the submission of the attest engagements under part 1090 with the requirements of the RFS program. We had proposed that the attest engagement submission would require a description of the findings and the steps the regulated party would take to address remedial actions, but did not require that all the remedial action steps occur before submission. We are finalizing the requirement that the submission include a description of the findings. We are not finalizing the requirement that the submission by the auditor address remedial actions related to the attest engagement, as we agree with commenters that this report item may be beyond the normal scope of the auditor. Some commenters expressed a desire to receive the attest engagement report prior to submission to EPA by the auditor; we believe that this is within the ability of the party to arrange with the auditor and need not be specified in the regulations. The auditor and the party with whom they are associated (and for whom the attest engagement was prepared) will be able to download the report submitted to EPA. Attest engagements are discussed in detail in Section XII.B.

5. Reporting Requirements for Gasoline Manufacturers That Recertify BOB for Different Type(s) and Amount(s) of Oxygenate

In order to implement the optional provisions discussed in Section VII.G with respect to treatment of BOBs, we are finalizing reporting requirements for gasoline manufacturers that recertify BOB for different types and amounts of oxygenate. When a person recertifies a BOB with less oxygenate than specified by the BOB manufacturer, they will be required to submit information about recertification activity on a batch level report and include any deficits incurred in their annual sulfur and benzene compliance report.^[78] Credit transactions associated with re-certification of the BOB will also be reported. Parties that recertify BOBs may include all volumes and deficits in a single reported batch of up to 30 days. (Allowing this reduces the reporting burden.)

6. Reporting for Oxygenate Producers and Importers

Similar to part 80, oxygenate producers and importers must submit batch reports providing information about the oxygenate they produce or import. Reporting for oxygenate producers is on a compliance-level (e.g., facility) basis. The information to be submitted includes information about the oxygenate produced or imported, including the sulfur content of the batch and the test method used. For DFE, the reported information will specify whether the denaturant is certified ethanol denaturant or non-certified.

7. Reporting for Certified Pentane Producers and Importers

Similar to part 80, certified pentane producers and importers must submit batch reports that provide information about the certified pentane produced or imported, including the pentane, sulfur, and benzene content of each batch and the test methods used.

8. Reporting by Diesel Manufacturers

We are finalizing limited batch reporting for manufacturers of diesel fuel. Specifically, manufacturers of diesel fuel (excluding 500 LM diesel fuel from transmix) that test any batch found to exceed the applicable 15 ppm sulfur standard must report information about that batch. Batches that do not exceed the applicable 15 ppm sulfur standard will not be reported to EPA. The specific information to be reported includes the company and facility identifier, the batch identifier, and the tested sulfur content in ppm and test method used. Since diesel manufacturers are required to test their product for sulfur content and must retain information related to sampling and test results already, the burden of reporting a relatively small number of batches found to exceed the applicable 15 ppm is small. This limited batch reporting will assist us in our compliance oversight efforts and in ensuring that the human health and environmental benefits of the program are realized. This action also transitions the diesel fuel property reporting from part 79 to part 1090 in a simplified form, which includes reporting total volume and max/average sulfur results (using ppm as the unit of measure) by company ID and five-digit reporting ID (i.e., facility ID).^[79] We believe that the simplified property reporting for diesel fuel will help us better oversee the fuel quality requirements or diesel fuel under part 79 and part 1090.

9. Reporting by Independent Surveyors

Independent surveyors are required to register and report. The registration requirement for independent surveyors are discussed in greater detail in Section X.A.2.d. For reporting purposes, an independent surveyor must submit plans, notifications, and quarterly survey reports to EPA electronically. The quarterly reports include information about retail outlets visited by the independent surveyor and the characteristics of the fuels samples and tested (e.g., oxygenate type and amount, sulfur content, benzene content, etc.). Independent surveyors are also expected to comply with an annual reporting requirement that addresses summary statistics and describes compliance rates and non-compliance issues. Independent surveyors must also submit similar reports under NSTOP. The independent survey program and NSTOP are discussed in Section X.

10. Deadlines for Reporting

The following reporting deadlines apply to part 1090:

• Annual compliance reports for sulfur and benzene must be submitted by March 31 for the preceding compliance period (e.g., reports covering the calendar year 2021 must be submitted to EPA by March 31, 2022).
• Batch reports must be submitted by March 31 for the preceding compliance period.
• Attest engagements must be submitted by auditors by June 1 for the preceding compliance period.
• Reports by independent surveyors will continue to be submitted quarterly on June 1 (covering January 1-March 31), September 1 (covering April 1-June 30), December 1 (covering July 1-September 30), and March 31 (covering October 1-December 31). Annual reports by independent surveyors must be submitted by March 31.

Part 1090 reporting deadlines are the same as part 80 with one exception. Under part 80, RFG refiners and importers had to submit quarterly batch reports compared to CG refiners and importers who only had to submit annual batch reports. Under part 1090, we are requiring that all batch reports must be submitted annually for all gasoline manufacturers.

Some commenters had suggested that aligning the compliance reporting and the attest engagement due date of June 1 might lead to fewer report resubmissions, and that the auditor would be able to perform the attest engagement using the batch reports that were due on March 31. Although we agree that reducing resubmissions of reports is a consideration, we must balance this against the compliance need to be able to process and utilize ABT and credit reports in a timely manner and against the data transparency purpose of making information about the program available to the public in a timely manner. Therefore, we are finalizing the reporting deadlines as proposed.

11. Reporting Forms

We have docketed the reporting forms and have submitted them to OMB for review with the ICR for this rule. We received several comments related to the content and structure of the forms and have amended several forms in response to these comments. We address these comments in detail in Section 12 of the RTC document.

D. Product Transfer Documents (PTDs)

The general purpose and requirements for PTDs under part 1090 do not differ from the existing requirements in part 80. PTDs are documents generated in the normal course of business that provided a clear description of the product being transferred. Part 1090 mostly consolidates the various PTD language requirements throughout part 80 into a single, consistent section to help bring uniformity to the PTD language across fuels, fuel additives, and regulated parties. This action removes PTD language that is no longer needed and provides standard, updated language to address a variety of common products and situations. We are, however, making some minor modifications from the part 80 requirements.

The PTD requirements apply on each occasion when any person transfers custody or title of IMO marine fuel except when the IMO marine fuel is dispensed for use in marine vessels. Part 1090 incorporates the Bunker Delivery Note (BDN) requirements from 40 CFR 1043.80 to address the transfer of IMO marine fuel by a fuel supplier onto a vessel.^[80] Each fuel supplier is independently responsible for meeting the BDN requirements. However, the BDN requirements must be met only once for each delivery of fuel onto a vessel. As a result, if the BDN requirements are properly met by the fuel supplier that transfers custody or the fuels supplier who transfers title of the fuel onto a vessel, EPA will consider the requirements to have been met by each fuel supplier. This approach provides parties with the flexibility to contractually allocate the BDN responsibilities as they see fit among themselves and ensures that the BDN requirements will be met. Pursuant to 40 CFR 1043.80, each fuel supplier must keep copies of the BDNs.

As proposed, we are including language to identify fuel covered by all known, specific exemptions (e.g., R&D exemption, racing fuel exemption, etc.) in a more consistent manner. Part 80 only requires that exempt fuels be identified on PTDs as exempt and is inconsistent in its language requirements across the various part 80 fuel quality programs. To make our PTD requirements more consistent, we are requiring a more prescriptive format for exempt fuels.

Under some programs in part 80, we have allowed parties to petition for alternative PTD language for some PTD requirements, but not for other PTD requirements. During the rule development process, several stakeholders highlighted that instances exist where our PTD requirements may conflict with other federal, state, or local PTD or identification requirements. In such cases, fuels, fuel additives, or regulated blendstocks could be identified with contradictory language that makes it difficult for parties in the fuel distribution system to comply with all requirements. To address these potential issues, we are adding flexibilities for parties to seek approval for alternative PTD language for all PTD language requirements. Based on experience implementing part 80, we do not anticipate that many parties will request alternative PTD language.

We received several comments suggesting clarifying edits to the PTD requirements to help the part 1090 regulations address common situations that arise in the production and distribution of fuels. We address these comments in Section 13 of the RTC document and have reflected these suggestions where appropriate in the part 1090 regulations.

E. Recordkeeping

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

In general, we received few comments on the proposed recordkeeping requirements. These comments suggested edits to the regulations for clarity. We made slight modifications to the regulations in response to these comments. These comments are addressed in Section 14 of the RTC document.

F. Rounding

The standards and compliance requirements under part 1090 require extensive use of numbers to quantify fuel parameters and fuel volumes, along with numerous calculations of new quantities to properly document compliance. A rigorous compliance demonstration depends on properly managing precision and significant figures in recorded values and calculations. Part 80 addresses rounding and precision by simply instructing regulated parties to round test results to the nearest unit of significant digits specified in the applicable fuel standard as described in ASTM E29. As proposed, we are finalizing a much broader and consistent approach in part 1090 using the standard approach to rounding in 40 CFR 1065.20 that is consistent with ASTM E29. We are requiring this rounding protocol for all recorded values under part 1090.

Part 1090 includes additional specifications for calculating and recording numerical values. First, we are specifying that rounding intermediate values in a calculation is not appropriate. This principle is intended to preserve the accuracy and precision until the calculations reach a final result, at which point the final result can be rounded to the appropriate number of decimal places or significant figures. We recognize that intermediate values must sometimes be transcribed (such as from an analyzer to a spreadsheet), which cannot be done with infinite precision. We are therefore requiring that intermediate values should be recorded and used with full precision, except that rounding is permissible if the value retains at least six significant digits. This does not require six significant digits for all recorded values. Rather, if an intermediate quantity with more than six significant digits needs to be transcribed, parties may use the specified rounding protocol to eliminate the additional digits. Also note that we generally allow for using measurement devices that incorporate proper internal rounding protocols to report test results.

Second, multiplying a value by a percentage must keep the precision of the original value. This is equivalent to considering the specified percentage to be infinitely precise. For example, calculating 1 percent or 1.0 percent of 1,234 would result in a value of 12.34. This is relevant for calculating an averaging standard for benzene. Fuel volume is multiplied by exactly 0.62 percent, rather than using a value of 0.624 (which rounds down to 0.62) before multiplying by fuel volume.

We did not receive any comments on the rounding provisions and we are finalizing the rounding provisions as proposed with one exception. In order to avoid confusion associated with the rounding of batch volumes for small batches of fuel that might be produced in standard-size tanker truck volumes, we are changing the batch size threshold for rounding to the nearest 10 gallons from 10,000 to 11,000 gallons.

G. Certification and Designation of Batches

We are finalizing the batch certification and designation provisions largely as proposed. The certification and designation of batches of fuels, fuel additives, and regulated blendstocks are crucial elements to ensuring that fuels, fuel additives, and regulated blendstocks meet our fuel quality standards and aid in the distribution of such products. Certification is the process where a manufacturer or producer demonstrates that their product meets EPA's standards. Designation is the identification of a batch (typically on PTDs) as meeting specific requirements for a category of fuel (e.g., summer RFG), fuel additive (e.g., diesel fuel additives), or regulated blendstocks (e.g., certified butane or certified pentane). Parties throughout the fuel distribution system rely on designations to appropriately transport, store, dispense, and sell fuels. Part 80 generally has provisions for certification and designation of products separately for each program. Part 1090 consolidates these various certification and designation procedures into a single set of provisions.

Regarding certification, most of the certification procedures for fuels, fuel additives, and regulated blendstocks for part 80 are currently outlined in guidance. We are incorporating such guidance into part 1090 and establishing a clear process to certify batches. The part 1090 regulations include the following four steps:

• Registration prior to the production of fuel, fuel additive, or regulated blendstock (if required).
• Sampling and testing the fuel, fuel additive, or regulated blendstock to demonstrate that the product meets applicable quality standards.
• Assignment of a batch identification number (if required).
• Designation of the batch as appropriate.

We believe these four steps are consistent with how parties certify products under part 80. These requirements also satisfy CAA section 211(k)(4) describing certification procedures for RFG.

Regarding designation, for gasoline and gasoline-related additives and regulated blendstocks, we are modifying the designation requirements for these products. Most of these changes reflect the removal of the Complex Model for use in the certification of batches of RFG and the harmonization of the RFG and CG programs. Many of the prior designations to segregate RFG and CG are no longer necessary, so we are removing those designations. Additionally, we are providing flexible redesignation provisions for distributors of gasoline. These proposed provisions largely reflect the streamlining of the RFG program and the more fungible nature that results.

Under part 1090, distributors of gasoline are allowed to redesignate winter RFG/RBOB to winter CG/CBOB (and vice versa) and summer gasoline from a more stringent RVP standard to a less stringent RVP standard without recertification (e.g., from summer RFG meeting the 7.4 psi RVP standard to 9.0 psi RVP summer CG). Any person that mixes summer gasoline with summer or winter gasoline that has a different RVP designation must either designate the resulting mixture as meeting the least stringent RVP designation of any batch in the blend or determine the RVP of the resultant mixture and designate the new batch accurately to reflect the RVP of the gasoline as described under this section. When transitioning tanks from winter to summer gasoline, parties are not required to test the RVP but must be able to assure that the gasoline meets the applicable RVP standard.

We are also making it clear in part 1090 that parties can redesignate California gasoline that meets CARB standards without recertification, as explained in more detail in Section VI.A. We believe these flexibilities will help maximize the fungibility of gasoline.

For diesel fuel, diesel additives, and diesel regulated blendstocks, we are largely maintaining the part 80 designation requirements. We are, however, making two notable changes. First, we are providing for a more flexible ULSD designation for distillate fuels certified to meet ULSD standards. The intent of this flexibility is to ensure that fuels that meet the ULSD standards could be designated as necessary to be used as home heating oil, MVNLRM diesel fuel, or IMO marine fuel. This change will allow parties to make sure that fuels are designated appropriately throughout the distribution system.^[81] Second, similarly to gasoline, we are allowing parties to redesignate California diesel fuel that meets the ULSD standards without recertification. We believe the designation changes for diesel fuel would help maximize the fungibility of distillate fuels that meet the ULSD standards.

We received several suggestions and requests for clarification regarding the certification and designation provisions under part 1090 from commenters and have made slight modifications to the regulations in response to these comments. We address these comments in Section 13 of the RTC document.

IX. Sampling, Testing, and Retention Requirements

Our fuel quality programs consist of performance standards and compliance provisions that require measurement of various fuel parameters. These measurements in turn rely on specified procedures contained in part 80. We are transferring these test procedures essentially unchanged from part 80 into part 1090 and updating them in the process as proposed. We are also reorganizing the testing provisions in part 1090 and codifying several clarifications to reflect current best practices. We are further consolidating test procedures for gasoline and diesel fuel in some cases. This section highlights the changes relative to what currently applies under part 80.^[82]

A. Overview and Scope of Testing

Part 80 requires gasoline manufacturers to measure 11 complex model parameters. As proposed, and in keeping with the discussion in Section V.A.2, for part 1090 we have reduced this to just three parameters: Sulfur, benzene, and RVP (in summer) for all gasoline, except for some unique situations discussed in more detail below. Diesel fuel manufacturers will continue to have to test for the sulfur content.

Similar to part 80, under part 1090, gasoline manufacturers will also be required to sample and test finished fuels for oxygenates unless the gasoline manufacturer is making gasoline without oxygenates. For gasoline produced at a blending manufacturing facility or a transmix processing facility, we are retaining the part 80 requirement to test gasoline for distillation parameters. This will provide some confirmation that the blended product has a distillation profile that is generally consistent with gasoline meeting the substantially-similar requirements of the CAA. The results of the distillation testing is not required to be reported, but instead would be retained at the facility to provide additional data that can be reviewed in the event of complaints about potential compliance or performance issues. We understand that distillation parameters are effectively a condition of merchantability of gasoline in the U.S., so such testing is already being performed by gasoline manufacturers.

Under part 1090, CG refiners and diesel fuel manufacturers must measure sulfur content in gasoline and diesel fuel prior to introduction into commerce. Requiring measurement before shipping from the refinery provides assurance of compliance prior to the fuel being mixed and commingled in the fungible distribution system. Unlike many regulatory situations where it is possible to go back after the fact and correct the noncompliance, this is difficult if not impossible in most situations for fuel once it has left the refinery.

Similar to part 80, we are requiring under part 1090 that all gasoline manufacturers obtain test results for sulfur and RVP (during the summer months) before shipping gasoline from the fuel manufacturing facility. Part 80 also requires refiners to obtain test results for benzene before shipping RFG, but does not require refiners to first obtain these results for CG. Under part 1090, we are not requiring gasoline manufacturers to test for benzene before shipping gasoline from the fuel manufacturing facility.

We are maintaining part 80 exceptions to testing under current waivers that do not require measurement of fuel properties prior to shipment. Currently 40 CFR 80.65, 80.581, and 80.1630 describe separate programs for in-line blending configurations to qualify for a waiver from the test-before-ship requirements as part of an approved process with annual quality audits. We proposed to allow for the in-line blending waiver only for certain shipment configurations that do not allow for conventional batch testing. We received comments requesting that we clarify whether storage tanks prior to pipeline injection, typically used to accommodate cases where gasoline needs to be held prior to pipeline injection, could be included in an in-line blending waiver request. Under part 80, we have allowed such storage tanks to serve as an extension to the pipeline system as these tanks are typically not suitable for use as a certification tank. Based on these comments, we have revised the final rule to continue allowing the approach from part 80 in which refiners may apply for the in-line blending waiver for shipment configurations that include storage tanks that act as an extension of the pipeline system.

B. Handling and Testing Samples

1. Collecting and Preparing Samples for Testing

Accurate test results are dependent on the sample being representative of the fuel batch. We are transferring the part 80 sampling procedures and demonstration of homogeneity of fuel samples that are currently specified in 40 CFR 80.8 to part 1090 as proposed. This provision generally specifies procedures for manual sampling as described in ASTM D4057 or automated in-line sampling as described in ASTM D4177. The additional procedures for sampling related to gasoline RVP as described in ASTM D5842 are also being transferred to part 1090.

Some of the current regulations in part 80 relating to sample collection, however, do not adequately address sampling procedures because they do not provide the necessary specifications for testing. We have addressed some of those omissions through guidance documents published over the years.^[83] We are reflecting that guidance in part 1090 by adding numerous minor clarifications and adjustments to the regulatory text to reflect current best sampling practices. Several commenters suggested edits to the proposed regulations, as well as sought clarification of the various sampling procedures for fuels. We have reflected these comments in the final regulations as appropriate, and address these comments in Section 15 of the RTC document.

2. Sample Preparation for BOB Testing

Section VII.F describes the “hand blend” approach for gasoline that would allow gasoline manufacturers to account for the impacts of downstream blending of oxygenate into BOB in their sulfur and benzene compliance calculations.^[84] The hand blend procedure involves preparing each fuel sample by adding oxygenates to the BOB sample in a way that corresponds to instructions to downstream blenders for the sampled batch of fuel. Preparing the hand blend sample involves decisions about which samples to use for blending. For example, as a result of homogeneity testing, three tested BOB samples are commonly available to prepare the hand blend. Also, a single hand blend might represent different types and amounts of oxygenate, as reflected in the blending instructions for downstream parties. We are addressing these examples of discretion in the specified procedures by requiring that the hand blend represent a worst-case test condition with respect to oxygenate content. In the case of sulfur measurements from multiple samples to represent a batch of BOB, the regulation requires taking steps to avoid introducing high or low bias in sulfur content when selecting from available samples to create the hand blend.

Under part 1090, winter gasoline must be blended with the lowest specified percentage of any oxygenate type given in the instructions for downstream blending. For example, if blending instructions specify an 8 percent isobutanol blend in addition to E10 and E15, the hand blend would need to be an 8 percent isobutanol blend. This reflects the fact that dilution is the primary effect of blending on fuel parameters other than RVP. A different approach is necessary to properly select the type and amount of oxygenate for hand blending in summer gasoline to properly account for the impacts on RVP. Summer gasoline will need to be blended with the lowest specified percentage of oxygenate given in the instructions for downstream blending (i.e., blend for E10 if the instructions identify E10 and E15 for downstream blending, even if the blending instructions include an option to blend with a lower percentage of a different oxygenate).

3. Sample Retention

Part 80 currently describes sample-retention requirements in multiple provisions. Stakeholders have pointed out that there is ambiguity about whether the part 80 regulations requires sample retention for 30 or 90 days. We are requiring all fuel manufacturers to keep fuel samples used to demonstrate compliance with all applicable standards for 30 days, except for blending manufacturers.

A longer retention time applies for blending manufacturers since these manufacturers typically have less control over the quality of the blendstocks they use to produce gasoline, which can cause decreased fuel quality without robust controls. Crude oil refineries typically distribute fuels through a distribution network with multiple levels of control to ensure fuel quality (e.g., through pipelines that have strict product specifications prior to injection) while blending manufacturers can make fuels on a more ad hoc basis (e.g., in a leased terminal tanks). We therefore believe it is appropriate to require a longer retention period for blending manufacturers to help trace potential issues with fuel quality. We proposed a minimum retention period of 120 days for fuel samples that blending manufacturers use for testing to demonstrate compliance with gasoline or diesel fuel standards. We received several comments suggesting that the proposed 120-day retention period was too long. Commenters contended that such a long retention period would result in the need to develop new capacity to retain fuel samples which would be quite burdensome. Commenters suggested a range of different retention periods from 30 days, as proposed for other fuel manufacturers, to 90 days. In response to these comments, we now believe that a 90-day retention window is the most appropriate balance to ensure robust controls on fuel quality from fuels made by a blending manufacturer. We address this issue in more detail in Section 15 of the RTC document.

For testing BOB and hand blended samples of oxygenated gasoline as described in Section IX.C, the sample-retention requirements apply for only for the BOB sample. Gasoline manufacturers producing BOB have expressed a concern that space limitations would make it difficult to store both the BOB sample and the hand-blended sample used to demonstrate compliance. For any testing, with the retained sample, EPA or the fuel manufacturer would use any standard supply of DFE or other oxygenate to re-create the hand blend.

C. Measurement Procedures

Demonstrating compliance with fuel quality standards requires a wide range of measurement procedures. Our fuel quality regulations rely heavily on standardized test methods published by voluntary consensus standards bodies such as ASTM International. As described below, the regulations in part 1090 reference certain measurement procedures, in most cases with provisions allowing for using alternative procedures, including updated versions of referenced procedures in some instances.

1. Procedures for Gasoline Surveys

Testing for gasoline surveys is intended to provide a consistent indication of in-use fuel parameters over time. As discussed in Section X.A.2, the independent surveyor will test for the full suite of Complex Model gasoline parameters, and testing will be performed by an EPA-approved test lab on fuels intended to represent the range of fuels in distribution over time.

Survey measurements must rely on the referee procedures identified under PBMS, where applicable. The following procedures apply for additional parameters:

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

We received comments asking for minor clarification on the test procedures that independent surveyors would use under part 1090. We have reflected these comments on the final regulations as appropriate, and address these comments in Section 15 of the RTC document.

2. Procedures To Determine Cetane Index for Diesel Fuel

Part 80 and the CAA establishes a cetane index standard at or above 40 for diesel fuel used with motor vehicles and nonroad equipment.^[85] Part 80 also references ASTM D976 as the procedure for determining cetane index in diesel fuel. During the development of this action, industry stakeholders advocated for ASTM D4737 as a more robust method that relies on additional fuel parameters for calculating cetane index. We proposed to allow the use of both ASTM D976 and ASTM D4737 in determining cetane index and received comments in support. As such, the final rule specifies that either of the referenced ASTM procedures are acceptable for determining cetane index for diesel fuel.

Both of the referenced ASTM procedures are valid for the full range of distillate fuels qualifying as diesel fuel. However, these procedures rely on fuel characteristics for distillate fuel and they are therefore not appropriate for biodiesel. The chemical make-up of pure biodiesel causes it to inherently have higher cetane values and no aromatic content. With no suitable measurement procedure for cetane index in biodiesel, and no concern that biodiesel will fail to meet the cetane index standard or have greater than 35 percent aromatics, we are exempting biodiesel from testing to verify compliance with the cetane index or aromatic content requirement for diesel fuel.

Several commenters suggested that we should modify our proposed definition for biodiesel to tie it to industry specifications under ASTM D6751. These comments noted that the proposed definition only required that biodiesel contain a minimum 80 volume percent mono-alkyl esters and asked EPA to clarify what the other 20 volume percent of the biodiesel could be.

While we do not believe that we should limit biodiesel covered under part 1090 to only biodiesel that meets ASTM D6751 (this issue is addressed in more detail in Section 4 of the RTC document), we appreciate the need for clarification regarding which biodiesel fuels are exempt from cetane index/aromatics testing. We believe, based on suggestions from commenters, that exempting all biodiesel from cetane index and aromatics testing, while allowing biodiesel to contain 20 volume percent of substances other than mono-alkyl esters, would not be appropriate. We also believe that ASTM D6751 provides sufficient limitations on the concentrations of impurities in biodiesel to ensure that the biodiesel would not have any aromatics content, thereby meeting the cetane index/aromatics diesel fuel requirements. Therefore, we are finalizing that biodiesel that meets ASTM D6751 is exempt from cetane index and aromatics testing under part 1090. Conversely, biodiesel or biodiesel blends that do not meet ASTM D6751 are not exempt from cetane index and aromatics testing.

3. Performance-Based Measurement System

Part 80 contains the Performance-Based Measurement System (PBMS) that establishes objective criteria for qualifying laboratories and measurement procedures.^[86] Our fuel quality regulations specify referee test methods for several fuel parameters and define precision and accuracy criteria so laboratories can demonstrate that they qualify their equipment for using the referee procedure, or for using alternative procedures. Precision and accuracy criteria apply for initial qualification, and for ongoing quality checks.

Part 80 includes a specified date for laboratories to omit initial qualification testing if they have been using the specified referee procedure for a given parameter. We are broadening this approach in part 1090 by allowing laboratories to omit initial qualification testing if they are using the specified referee test procedure. This approach treats all laboratories the same. Since the ongoing quality checks apply for laboratories using these procedures, the laboratories will still be demonstrating that they are properly performing these measurement procedures.

a. Scope

We have received questions on the applicability of PBMS requirements beyond the predominant scenario of testing fuel at a refinery. The PBMS provisions for measuring specified fuel parameters apply to all parties and at all points in the fuel distribution system. PBMS provisions also apply for quality audits such as what is required for in-line blending waivers, for truck and rail imports where the importer has elected to comply with the alternative per-gallon standards, and for blending certified butane and pentane into PCG. Any other application would be inconsistent with PBMS and would create an unlevel playing field for different market participants.

b. Referee Procedures

We are transferring the same referee procedures to part 1090 that currently apply under part 80, subject to the following exceptions and clarifications.

First, we are changing the designated referee procedure for measuring benzene in gasoline from ASTM D3606 to ASTM D5769. We believe ASTM D5769 is a superior procedure because measurements involve little or no interference from ethanol blended into gasoline. In contrast, ASTM D3606 has interference effects from ethanol that require careful work to adjust for that interference and the prevalence of ethanol in gasoline now makes its use more challenging. Since ASTM D3606 is the referee procedure for measuring benzene in gasoline under part 80, we are waiving requirements to initially qualify testing with ASTM D3606 as an alternative procedure. We believe the ongoing PBMS quality demonstrations are sufficient to demonstrate proper precision and accuracy using ASTM D3606. We received several comments suggesting that we should not update the referee procedures for benzene from ASTM D3606 to ASTM D5769. These commenters mostly highlighted potential logistical issues with converting to a new designated referee method but not with the method itself. As such, we continue to believe that ASTM D5769 should be the referee method, as it does not suffer from matrix effects when testing gasoline-oxygenate blended fuels, which are predominant in the marketplace today. We address this issue in more detail in Section 15 of the RTC document.

Second, we are removing measurement of aromatic content in diesel fuel from the PBMS protocol since, consistent with part 80, we are not requiring aromatics testing for every batch of diesel fuel under part 1090. As a result, we believe the PBMS protocols for referee procedures, qualifying alternative procedures, and ongoing quality testing are no longer appropriate. We are instead specifying ASTM D1319 and ASTM D5186 as acceptable procedures for measuring aromatic content in diesel fuel and allowing for alternative procedures that correlate with either of these specified procedures.

We proposed to specify ASTM D6667 as the procedure for measuring sulfur in pentane. Based on comments, we have revised the final rule to instead specify ASTM D5453 as the appropriate method as discussed in Section 15 of the RTC document.

We have also received questions on the applicability of PBMS to oxygenates used in gasoline. We have always intended for the PBMS requirements to apply for testing oxygenates in the same way that test requirements apply for testing gasoline. Accordingly, we are clarifying in part 1090 that oxygenates, including DFE, are subject to PBMS requirements for all testing under part 1090 in the same way that these requirements apply for testing gasoline. This includes the protocol for qualifying alternative test procedures and the requirements for ongoing quality testing. We did not receive any comments on subjecting oxygenates to the PBMS requirements and are finalizing these provisions as proposed.

c. Updated Versions of Referenced Procedures

EPA fuel regulations rely on specific published versions of the various test procedures for measuring fuel parameters. These specific references do not automatically change with periodic updates to those procedures from the publishing organization, which makes it difficult for us to keep the regulations current as the industry continues to improve measurement procedures. To maintain the integrity of the PBMS protocol while allowing for the regulations to remain current with evolving industry practices, part 1090 allows laboratories to use updated versions of referee procedures or qualified alternative procedures without prior approval from EPA, as long as the updated version has published repeatability and reproducibility that is the same as or better than the version referenced in part 1090.

Laboratories wanting to use an updated method of a referee procedure to qualify alternative procedures must first get EPA approval because using an updated referee method to qualify an alternative method could potentially change the baseline for which other previously approved alternative methods were compared. This could create disparities in how alternative methods are qualified, and we would like the ability to ensure that such disparities do not result in inappropriate qualification of new alternative methods. We would expect to approve such requests based on a demonstration that the repeatability and reproducibility are the same as or better than the referenced procedure. This interaction will also help us identify instances where we should consider updating the regulation to rely on the latest available procedures.

d. Criteria and Methods for Qualifying Procedures

The precision and accuracy criteria from part 80 are migrating to part 1090 unchanged with two exceptions. First, we specify precision and accuracy criteria based on the most recently published repeatability values from ASTM D2622 for measuring sulfur in 500 ppm LM diesel fuel and ECA marine fuel. Second, we specify precision and accuracy criteria for gasoline benzene based on the most recently published reproducibility values from ASTM D5769 instead of ASTM D3606 in keeping with the change in the designated referee method described in Section IX.C.3.b. The published reproducibility for ASTM D5769 is slightly higher than for ASTM D3606, which means that it allows for a slightly more accommodating approach for qualifying alternative procedures.

We require calculating precision and accuracy criteria for diesel sulfur based on calculated values for sulfur concentrations at fixed values to represent compliance at the standard. This allows for a fixed criterion for testing all fuel samples. Selecting a test fuel with very low sulfur would not be meaningful, since it is not reasonable to compare such small quantities of measured sulfur to precision and accuracy criteria that are keyed to the standard. As a result, we are simply transferring the same specified minimum sulfur values for measuring sulfur in all the different types of diesel fuel. This is difficult for measuring sulfur in neat biodiesel, since it has inherently low sulfur concentrations. We expect testing to qualify methods or to perform ongoing quality checks with neat biodiesel to include doping the fuel with enough diesel fuel to meet the minimum sulfur specification.

Part 1090 requires the between-methods-repeatability, R_xy, for qualifying alternative procedures for method-defined parameters using non-VCSB methods to be at or below 75 percent of the reproducibility of the designated referee procedure. This is an increase from the 70 percent value specified in 40 CFR 80.47. The increase in the specified value for the R_xy criterion is based on the observation that it may be mathematically impossible to achieve a 30 percent improvement over the repeatability of the designated referee procedure. We are not aware of anyone seeking to use a non-VCSB method for fuel-defined procedures, but we want to continue to allow this as a viable option.

e. Ongoing Testing for Statistical Quality Control

Further, we are transferring the statistical quality control procedures (SQC) established under 40 CFR 80.47 to part 1090. By rewriting these procedures in their own section, the provisions in part 1090 will likely clarify some points that were previously subject to differing interpretations. We have also updated the SQC procedures to the latest version of ASTM D6299. This should provide additional flexibility to meet ongoing SQC requirements. We address other comments related to ongoing SQC requirements in Section 15 of the RTC document.

X. Third-Party Survey Provisions

Third-party verification plays an important role in overseeing compliance with EPA's fuel quality programs under part 80. One key element to the existing third-party oversight regime is in-use retail level surveys. An advantage of retail survey programs is that they target fuel quality at the point where the fuel is dispensed from a retail outlet. Under part 80, we have four in-use survey programs that primarily focus on RFG and RFG ethanol content, which are tracked in RFG areas, and E15 labeling and ULSD sulfur levels, which are tracked nationally. For the most part, however, we have little or no other retail level information under part 80 for CG, which constitutes about 70 percent of the national gasoline pool. We are finalizing provisions for a national survey program in part 1090 that will consolidate the four programs under part 80 into a single national in-use retail survey program, thereby reducing overall costs, while at the same time expanding the benefits of the survey program nationwide. The part 1090 survey builds upon the part 80 in-use survey provisions, leveraging independent third-parties to a greater extent to ensure that compliant fuels are used in vehicles and engines in exchange for allowing fuel manufacturers greater flexibility to account for oxygenates added downstream in their annual compliance demonstrations,^[87] and reducing the number of fuel parameters that fuel manufacturers need to test and report.

Part 1090 includes two survey programs: (1) A national survey program of retail outlets that offer gasoline and diesel to ensure that in-use standards are met; and (2) a voluntary national sampling and testing oversight program (NSTOP) that is intended to help ensure that gasoline manufacturers collect samples for testing in a consistent manner for purposes of compliance with applicable standards and thus, maintain the integrity of EPA's fuel quality program. This section discusses both programs in detail.

A. National Survey Program

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

Table X.A-1—Existing Survey Programs in Part 80

Program	Regulation citation	Geographic scope	Who participates	Minimum sample
RFG Survey	§ 80.68	RFG Areas	RFG Refiners	4,500
RFG Ethanol Survey	§ 80.69(a)(11)	RFG Areas	RFG Refiners	4,500
ULSD Survey	§ 80.613(e)	Nationwide, on-highway diesel stations	Anyone	1,800
E15 Survey	§ 80.1502	Nationwide gasoline stations	E15 fuel and fuel additive manufacturers	7,500

1. Background

We have historically used survey programs to provide flexibilities in fuel quality programs that we administer, which allows regulated parties to more efficiently meet EPA's fuel quality standards. For example, we provided RFG refiners with the option of complying with RFG requirements on an average basis by demonstrating that RFG meets the applicable in-use oxygen content and NO_X, toxics, and summertime VOC performance at retail stations. By relying on an in-use survey at the retail level to verify overall compliance, the regulations thus allow RFG refiners considerable flexibility in their day-to-day operations to produce fuel at the lowest cost. The norm for over 20 years has thus been that RFG refiners and importers produce a sub-octane, oxygenate-free RBOB that is distributed throughout the distribution system to which ethanol is added at downstream terminals. The retail survey then allows for verification that the RFG standards are met in-use. Since most RFG areas are supplied by multiple refiners, we allowed RFG refiners and importers to consolidate resources to establish a survey to demonstrate that RFG standards were met for RFG areas on average.

Additionally, in order to discourage misfueling of vehicles and engines, we have historically imposed pump labeling requirements at the retail level. In order to provide oversight of the thousands of retail stations, we also currently have provisions for a retail outlet survey to ensure that fuel dispensers are labeled appropriately (e.g., E15). A statistically representative sample of retail outlet fuel dispensers gathered through a survey helps inform responsible parties and EPA whether labeling requirements are being met without having to impose direct costs on the retail outlet to demonstrate compliance.

The focus of much of part 80 compliance oversight has been on refiners that manufacture fuels at crude oil refineries with provisions that then attempt to ensure that the fuel quality as measured at the refinery is maintained all the way to retail. What happens at the refinery has historically been and continues to be the greatest factor as to whether a fuel is ultimately compliant. However, as the transportation fuel market has continued to evolve and parties at all locations downstream of refineries (e.g., pipeline, terminal, retail) are now increasingly engaged in the process of producing finished fuels (i.e., adding ethanol or gasoline blendstocks into PCG, or adding biodiesel into diesel fuel), it has likewise become more important to not only receive information from the manufacturers of gasoline and diesel fuel at the start of the process, but also from the end of the process—at retail level—to ensure fuel quality standards are met. In the past this was mostly necessary just for RFG to ensure that the oxygenate was in fact added to the refinery-certified RBOB downstream and the RFG standards were met. However, now that essentially all gasoline has ethanol added downstream to a refinery-produced and/or certified CBOB and many parties are taking actions that can impact fuel quality downstream of the refinery, all in-use gasoline could benefit from a retail survey. Without it we could not implement the changes discussed in Section VII.F to allow refiners and importers to account for the downstream addition of ethanol in their compliance calculations. Consequently, we are extending the retail survey that has been applicable for over 20 years in RFG areas to all gasoline nationwide. The national in-use gasoline survey will provide EPA with the data necessary to ensure that in-use gasoline is in fact blended with ethanol as claimed by the gasoline manufacturer, meets our gasoline standards, and continues to meet RFG and anti-dumping statutory requirements. An in-use survey will also enable EPA to provide compliance flexibility to CG refiners and importers similar to RFG refiners and importers.

2. National Fuels Survey Program

a. Consolidation and Scope

We are finalizing the consolidation of the four in-use survey programs outlined in Table X.A-1 into a single national fuels survey program (NFSP). We believe the expanded scope of gasoline samples tested nationwide will help us ensure fuel quality oversight and compliance with EPA's applicable fuel quality standards in-use. This will also provide compliance flexibility for CG manufacturers to account for oxygenate (as discussed in Section VII.F). As previously explained, the ULSD and E15 survey programs under part 80 are national surveys of retail stations but only test for sulfur in diesel fuel and ethanol content and RVP of gasoline in the summer. On the other hand, the RFG survey and RFG ethanol survey are limited to RFG areas but test for the full suite of Complex Model fuel parameters. We believe there is technical support for allowing a survey program to collect a sample that satisfies multiple survey requirements (i.e., as long as retail stations are identified using sound selection procedures, there is no reason an independent surveyor could not obtain both a gasoline and a diesel fuel sample to satisfy all applicable survey program requirements).

The main benefit to stakeholders of consolidation of the current four survey programs into a single program is a substantial reduction in sample size. Under part 80, the four survey programs require industry participants to contract for over 18,000 fuel samples collected nationwide (see Table X.A-1 above). As further discussed in Section X.A.2.c, the required sample size of the NFSP under part 1090 could be reduced to less than 7,000 retail outlets sampled. Since the largest expense in retail surveying is the cost to collect and ship a sample from a retail station, reducing the sample size from more than 18,000 to less than 7,000 will substantially decrease the costs of the program.

The main benefit to EPA and the public is the expanded scope of testing for regulated fuel parameters to all fuel nationwide. Under the part 80 programs, the RFG survey programs test approximately 30 percent of the national gasoline pool for the entire set of Complex Model fuel parameters, while in the nationwide E15 survey, only ethanol content year-round and RVP for E15 samples in the summer are tested.

In addition to consolidating the four survey programs into a single, nationwide program, the gasoline properties tested for will also be consolidated. Sulfur, benzene, RVP (in the summer), and oxygenates will be tested for all the samples. A statistically determined subset of the national gasoline sample will be tested for the rest of the Complex Model fuel parameters to allow us to verify that gasoline continues to meet CAA section 211(k) requirements. The NFSP will also continue to ensure E15 pump labeling compliance at retail stations. For diesel samples, the survey will continue to test for sulfur.

We received several comments that supported this consolidation and most of those comments appreciated the reduced burden associated with the sample size reduction. We also received comments suggesting the removal of the verification of E15 compliance from the NFSP. We did not propose and are not removing the existing survey requirement for fuel and fuel additive manufacturers that make E15 or ethanol for use in making E15. Participation in this survey is mandatory under CAA section 211(f) and was established under CAA section 211(c) to ensure that E15 fuel dispensers are labeled correctly. We consider these comments outside the scope of this action.

b. Survey Participation

Gasoline manufacturers only need to participate in the NFSP if they choose to account for oxygenate added downstream in their compliance calculations. Under part 80, the RFG regulations imposed a similar survey requirement on RFG refiners and importers that accounted for oxygenate added downstream ^[88] and since we are now allowing this flexibility for manufacturers of CG, we are imposing a similar survey requirement. We believe that monitoring in-use sulfur, benzene, and oxygenate content is necessary to allow this flexibility for all gasoline manufacturers because without in-use verification from a national survey, there would be no oversight on whether gasoline manufacturers claimed credit for oxygenate that was ultimately not blended.

Under part 1090, parties that participate in the NFSP will satisfy one of the elements of an affirmative defense for downstream violations of our applicable fuel quality standards. Under part 80, we provide an affirmative defense for upstream parties that participate in survey programs to ensure downstream compliance for the ULSD survey. We are extending this affirmative defense for any party that participates in the NFSP to help establish a defense against downstream diesel sulfur, gasoline sulfur, gasoline RVP, and E15 misfueling violations in part 1090. We believe that parties that are part of the ULSD distribution system that participate in the part 80 ULSD survey program will continue to participate in the NFSP as well as other parties in the gasoline distribution system that wish to use the survey to help establish affirmative defenses against downstream violations.

Under the E15 partial waivers and E15 substantially similar determination, fuel and fuel additive manufacturers that make E15 or ethanol for use in making E15 must participate in a compliance survey that ensures that E15 pump dispensers are labeled appropriately.^[89] The E15 partial waiver conditions provide fuel and fuel additive manufacturers two options to satisfy the compliance survey condition: (1) A geographically-focused survey; or (2) a national survey. Under part 1090, we are finalizing as proposed that participation in the NFSP would satisfy the national survey option for purposes of compliance with the E15 waiver conditions or E15 substantially similar determination. The E15 waiver conditions and E15 substantially similar determination allow E15 fuel and fuel additive manufacturers to continue to use a geographically-focused option instead if they so desired, and part 1090 includes provisions to facilitate such a program. However, we expect that fuel and fuel additive manufacturers will continue to elect to participate in the NFSP due to its significant cost savings.

c. Sample Sizes

For the NFSP, we are finalizing the proposed minimum sample size of 5,000 gasoline retail outlets and 2,000 diesel outlets. As outlined in the NPRM, we selected the number of retail outlets for gasoline and diesel based on the recent sample size determinations of the existing part 80 survey programs and proposed the same sample size determination methodology that is used for those programs. This resulted in approximately 5,000 retail outlets since the existing survey program for E15 misfueling mitigation is national in scope. We also highlighted that since most retail outlets offer both gasoline and diesel fuel, the total number of retail outlets sampled could be closer to 5,000 retail outlets rather than 7,000 outlets. This is significantly lower than the 18,000 retail outlets required under part 80. We believe that it will maintain the statistical rigor of the existing part 80 programs while reducing costs. We received several supportive comments in the burden reduction associated with the consolidation of the part 80 survey programs into a single program. We did not receive any comments suggesting that we use a different sample size or sample size selection methodology.

For the subset of gasoline samples that would continue to be tested for the full suite of Complex Model fuel parameters, we proposed that the sample size would be determined using a standard calculation to estimate national fuel parameters. We estimated that around 1,200 gasoline samples would need to be analyzed for the full suite of Complex Model fuel parameters using this methodology. We received no comment suggesting an alternative methodology to calculate the number of gasoline samples that would be tested for the full suite of Complex Model fuel parameters, therefore, we are finalizing as proposed the requirement to test a subset of gasoline samples for all fuel parameters of the Complex Model and the methodology to determine the sample size of such gasoline samples.

d. Requirements for Independent Surveyors

We are retaining and transferring certain existing requirements for independent surveyors in part 80 to part 1090. These include the requirement that an independent surveyor must conduct the NFSP and meet similar independence requirements from parties that hire the surveyor to conduct the program. The independent surveyor is not allowed to have financial interest in companies that hire the independent surveyor to conduct the survey, nor are companies that hire the independent surveyor allowed to have a financial interest in the independent surveyor's organization. Like the part 80 survey programs, the surveyor must submit an annual plan for surveys conducted under part 1090 to EPA for approval. The plan must identify how the independent surveyor intends to meet the survey regulatory requirements and is subject to EPA approval prior to conducting the survey. Additionally, the independent surveyor must submit annually to EPA proof that the NFSP has been fully funded for the next compliance period by December 15. Except for comments that suggested that the employment criteria for independence should be shortened from three years to one year (discussed in more detail in Section XIII.A, we received no comments on the proposed requirements for the independent surveyor. Therefore, we are otherwise finalizing these provisions as proposed.

As part of our effort to modernize the fuel quality programs, we are requiring under part 1090 that independent surveyors register with EPA and submit periodic reports electronically to EPA, which is not currently required under the part 80 survey programs. This will help EPA more quickly provide information collected as part of the NFSP and promote greater transparency in the fuel quality program. The proposed reporting requirements for independent surveyors are similar to those currently specified in part 80, and the independent surveyor will need to keep records in a similar manner. We received no comments on our proposal to require independent surveyors to register with EPA and submit reports electronically and therefore are finalizing these provisions as proposed.

B. National Sampling and Testing Oversight Program

The RFG regulations in part 80 require that each refiner have an independent laboratory sample and test batches of RFG (unless the RFG refiner has an in-line blending waiver). Refiners have the choice of having an independent lab sample and test 100 percent of their batches or 10 percent of their batches randomly selected. Since arranging to have an independent laboratory collect a sample is the most expensive part of the process, commenters argued that this requirement is unnecessarily burdensome. Part 80 also requires that every 33rd batch of RFG collected by an independent lab must be sent to EPA for analysis.^[90] As part of consolidating the compliance provisions across the various gasoline and diesel fuel to create a single fuel quality program, and in light of the retirement of the Complex Model for batch certification and removal of various restrictions on the production and use of RFG, we considered how best to ensure proper EPA oversight of the sampling and testing for fuels compliance.

In lieu of the existing RFG requirements, we are finalizing the more flexible and less burdensome NSTOP as proposed. The purpose of this proposed program is to help ensure that fuel manufacturers are sampling and testing in a manner consistent with the required procedures discussed in more detail in Section IX.

As part of the NSTOP, we are requiring that the independent surveyor review appropriate PBMS qualification and SQC data for the samples collected and tested from gasoline manufacturers. We believe that this will help ensure that labs that test gasoline for compliance under our fuel quality programs are complying with EPA quality control provisions for labs.

Like the NFSP described in Section X.A, we believe there is an opportunity to reduce the overall cost of sampling oversight while expanding the scope from just RFG to all gasoline nationwide. Taken together, we are requiring an estimated 500-750 samples to be collected as part of NSTOP annually. This compares to the several thousand samples currently collected from RFG refiners each year under the part 80 independent laboratory requirements. These samples would be spread across all gasoline manufacturers instead of just RFG refiners. This provides a substantial reduction in associated burden with independent sampling while still providing the necessary oversight.

We are finalizing the requirement that gasoline manufacturers that elect to account for oxygenate added downstream must participate in NSTOP. We believe this requirement will help ensure that fuel manufacturers are sampling, testing, and reporting results of gasoline that is representative of gasoline (i.e., BOB) leaving the fuel manufacturing facility gate. We are also exempting refineries that have in-line blending waivers from NSTOP as proposed since these refineries must meet the annual audit requirement using an auditor.

Gasoline manufacturers that participate in the program will need to arrange for a sample to be overseen by an independent surveyor for each season (winter and summer). This would mean that, as long as a gasoline manufacturer has product available for testing, the gasoline manufacturer would have at least two samples collected per year. We are requiring that an additional number of random samples be collected to ensure an effective deterrent against complacency for parties that have samples collected early in a season. For example, if we only required sampling once per season and a gasoline manufacturer had a winter sample surveyed in January of a compliance period, that gasoline manufacturer would not be surveyed in the winter for the rest of the compliance period. Additional random sampling will help ensure that gasoline manufacturers are following appropriate sampling and testing procedures year-round, even if sampled early in the season.

Historically, EPA's National Vehicle and Fuel Emissions Laboratory (NVFEL) has played a role in the development and quality control of analytical test methods used to determine compliance with our fuel quality standards. Under part 80, as part of the RFG program, NVFEL receives several hundred oversight samples from RFG refiners and independent laboratories. NVFEL analyzes these samples and compares the results to results from RFG refiners and independent labs, which totals between 300-400 RFG samples per year.^[91] Under part 1090, we will no longer collect these oversight samples from RFG refiners and independent labs, as proposed. However, as part of the NSTOP, we are requiring that the independent surveyor send a random selection of samples collected to NVFEL for comparison to the results obtained from the independent surveyor and fuel manufacturer's lab. This will allow NVFEL to continue to serve as a reference installation and maintain EPA oversight of the NSTOP. We intend to collect a similar amount of gasoline samples, around 300 per year, as we currently receive under the RFG program. We received one comment noting that having NSTOP samples shipped to NVFEL would unnecessarily add costs to the NSTOP for little value. For reasons discussed in more detail in Section 16 of the RTC document, we are finalizing as proposed that some NSTOP samples be shipped to NVFEL.

Like the NFSP, we are requiring that an independent surveyor conduct the NSTOP. We envision that these parties would function similar to the way that independent surveyors operate under the part 80 survey programs. Therefore, we are requiring the same independence and plan approval process as those used for independent surveyors under the NFSP, which is similar to the part 80 survey requirements. The only difference would be a change in the reported elements as samples are collected from gasoline manufacturing facilities instead of retail stations. We did not receive any comments on this aspect of the NSTOP and are finalizing the requirements for independent surveyors conducting the NSTOP as proposed.

In the proposal, we also sought comment on whether to maintain the existing RFG independent laboratory testing requirement or whether to require that third-party laboratories that perform testing for fuel manufacturers under the NSTOP also register and associate. We received several comments suggesting that the RFG independent laboratory testing requirement was no longer necessary and that associated burdens with requiring all third-party laboratories to register and associate with fuel manufacturers would be cost prohibitive. We also received comments, mostly from third-party laboratories, noting that we should maintain the RFG independent testing requirement or require the registration of third-party labs as a means to help ensure the integrity of sampling and testing performed by third-parties for fuel manufacturers. For reasons discussed in more detail in Section 13 of the RTC document, we are finalizing as proposed the removal of the RFG independent lab testing requirement and are not finalizing a requirement that all third-party laboratories register and associate with fuel manufacturers.

A number of commenters included suggestions and requests for clarification regarding the NSTOP and we have reflected them in the final regulations as appropriate. We address these comments in Section 13 of the RTC document.

XI. Import of Fuels, Fuel Additives, and Blendstocks

We are transferring most of the current provisions in part 80 that address the importation and exportation of fuels, fuel additives, and blendstocks to part 1090 (subpart Q). As described in this section, importers will continue to be subject to the same requirements as refiners, while exporters will continue to be subject to certain fuel designation and recordkeeping provisions. Overall, we are making several changes to how imported and exported fuel products are treated relative to the provisions of part 80, although we are significantly updating the regulatory text. Many of the modified part 1090 provisions are merely codification of existing implementation policies summarized in a 2003 question and answer (Q&A) document (“2003 Q&A document”).^[92]

A. Importation

With few exceptions, we are finalizing the proposed requirements under part 1090 for importers that largely mirror what we require under part 80. However, we are updating some provisions for imports in part 1090. First, importers that import fuel at multiple import facilities within a single PADD must aggregate the facilities within that PADD for purposes of complying with the maximum benzene average standard. For compliance with other average standards, importers will continue to comply at the company level. Batches of imported fuel that are subject to certification requirements must be certified separately for U.S. Customs Service purposes at each U.S. port of entry.^[93]

Second, under part 80, current guidance allows gasoline classified as “American Goods Returned” to the United States by the U.S. Customs Service to not count as imported gasoline.^[94] As proposed, we are finalizing language consistent with that guidance in part 1090, provided all the following conditions are met:

• The gasoline was produced at a fuel manufacturing facility located within the U.S. and has not been mixed with gasoline produced at a fuel manufacturing facility located outside the U.S.
• The gasoline must be included in compliance calculations by the producing manufacturer.
• All the gasoline that was exported must ultimately be classified as American Goods Returned to the United States and none may be used in a foreign country.
• No gasoline classified as American Goods Returned to the United States may be combined with any gasoline produced at a foreign fuel manufacturing facility prior to being imported into the U.S.

We are not changing how importers are defined in part 1090 compared with part 80.^[95] The importer under part 1090 would generally be the importer of record under the Bureau of Customs and Border Protection regulations. This would typically be the entity that owns 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.

B. Special Provisions for Importation by Rail or Truck

We are finalizing as proposed the compliance options for meeting testing requirements when importing fuels by either rail or truck. These provisions allow importers via rail or truck to meet the sampling and testing requirements based on test results from the supplier instead of testing each batch after the fuel is imported, under certain conditions.

First, for gasoline, the truck or rail importer electing to use supplier test results must meet 0.62 volume percent benzene content and 10 ppm sulfur content per-gallon maximum standards. This requirement is identical to what is currently required under part 80.^[96]

Second, the importer must get documentation of test results from the supplier for each batch of fuel. Testing for a given batch must occur after the most recent delivery into the supplier's storage tank and before transferring product to the railcar or truck.

Third, the importer must conduct testing to verify test results from each supplier, by collecting samples either once every 30 days or every 50 rail or truckloads of fuel from a given supplier, whichever is most frequent.

We received several comments that suggested that our proposal to allow added flexibility was forcing importers via truck and rail to comply with more stringent per-gallon standards. This was not our intent and we have revised the regulations to clarify that importers that import via truck or rail have the option to sample and test each batch of imported gasoline and comply with average benzene and sulfur standards or rely on test results from the gasoline supplier and meet a per-gallon standard. We address other comments related to imports by truck and rail in Section 18 of the RTC document.

C. Special Provisions for Importation by Marine Vessel

We are finalizing as proposed the provisions that specifically address importation of fuels by marine vessels. These provisions are generally the same as those addressed in the 2003 Q&A document.^[97] Under part 1090, separate certification is required at each import facility, unless the fuel is transported by the same vessel making multiple stops but does not pick up additional fuel. Consistent with the current part 80 requirements, we are not allowing importers who import by marine vessels to rely on testing from a foreign source given our lack of jurisdiction generally. Additionally, testing may not be based on samples collected after the fuel is off-loaded, unless certain conditions are met that are designed to make sure the imported gasoline meets all per-gallon standards and that compliance reports accurately reflect the sulfur and benzene content of the imported fuel.

Under these provisions, different ship compartments would generally be considered different batches of fuel. However, we are allowing for the following exceptions. First, importers may treat the fuel in different compartments of a ship as a single batch if they demonstrate that the fuel is homogeneous across the compartments as required for all composite samples. As is the case under part 80, importers must demonstrate that results for homogeneity testing fall within the specified range for the test method used(s) used to determine homogeneity. Under the updated homogeneity testing procedures in part 1090, this should result in a decrease in the amount of analytical testing needed to establish homogeneity for combining marine vessel compartments compared to part 80. This decrease in testing is mostly a result of the decrease in the number of fuel parameters for homogeneity testing from as many as 11 under part 80 to two under part 1090. This change would result in a substantial decrease in testing burden.

Second, we will also accept the analysis of samples collected from different ship compartments that are combined into a single volume-weighted composite sample if the compartments are off-loaded into a single shore tank, or if each individual vessel compartment is shown, through sampling and testing, to meet all applicable standards.

We received several comments suggesting edits and requesting clarifications to the part 1090 marine vessel import provisions that we have reflected in the final regulations as appropriate. We address these comments in Section 18 of the RTC document.

D. Gasoline Treated as Blendstocks

We are transferring part 80 provisions for gasoline treated as blendstock (GTAB) to part 1090 largely unchanged. We are also substantially reducing the number of parameters that are tested and reported to EPA for GTAB. Our primary concern with GTAB has been to ensure that off-spec gasoline imported into the U.S. is properly blended to produce gasoline that meets applicable fuel quality standards. When initially established under the RFG and Anti-dumping programs, the GTAB provisions focused on the entire set of parameters needed to run the Complex Model. Since compliance with EPA's fuel quality standards is based on sampling and testing the finished fuel and part 1090 no longer requires certification of batches of gasoline using the Complex Model, we believe that the testing and reporting of fuel parameters for GTAB is no longer necessary. However, volumes for batches of GTAB must continue to be reported. Other provisions related to GTAB are consistent with current part 80 requirements and published guidance.

In general, comments were supportive of this proposal. However, we received some suggestions for clarification of the GTAB provisions that we have reflected in the final regulations as appropriate. We address these comments in Section 18 of the RTC document.

XII. Compliance and Enforcement Provisions and Attest Engagements

A. Compliance and Enforcement Provisions

We are finalizing the compliance and enforcement provisions as proposed with one exception. We are also finalizing lower sulfur and benzene default values that will apply to sampling and testing requirements violations for fuel content standards.

As explained in the NPRM, the requirements for regulated parties to accurately sample and test fuels are one of the lynchpins of our fuel quality regulations. If regulated parties fail to properly sample and test fuel, it makes it difficult for EPA and the public to know if the fuel meets the applicable standards. Several commenters suggested that the proposed levels, which were identical to the levels in part 80, were too high. The commenters suggested that the default values had not been updated in over 25 years and were not reflective of modern fuel manufacturing. Several commenters suggested default levels that were at or below EPA's regulatorily specified levels. We believe that it would be inappropriate and counterproductive to assume that fuels, fuel additives, and regulated blendstocks met EPA's fuel quality standards if a party failed to appropriately sample and test for compliance. Such levels would provide a strong incentive for parties to forgo compliance sampling and testing altogether, which would jeopardize fuel quality. Other commenters suggested more modest reductions in the default values, but no commenter provided compelling data to support alternative default values.

However, we acknowledge that fuels are made and distributed differently today than they were when we promulgated the part 80 default values in the 1990s. Therefore, we have chosen to use the sulfur and benzene levels specified in CAA section 211(k)(10)(B) for summer (339 ppm sulfur) and winter (1.64 volume percent benzene) baseline fuel, respectively.^[98] We believe these values represent fuels prior to the promulgation of current EPA fuel quality standards, which have controlled sulfur and benzene contents to their current regulatory levels (10.00 ppm and 0.62 volume percent, respectively).

The final rule provides that if a fuel, fuel additive or regulated blendstock manufacturer fails to comply with the sampling and testing requirements, the gasoline will be deemed to have the parameters in Table XII.A-1 below, unless EPA, in its sole discretion, approves a different value in writing. EPA may consider any relevant information to determine whether a different value is appropriate.

Table XII.A-1—Default Values for Fuel, Fuel Additive, and Regulated Blendstock Parameters

Product	Sulfur value (ppm)	Benzene value (volume percent)	RVP value (psi)
Gasoline	339	1.64	11
PCG (by subtraction)	0	0	n/a
Diesel Fuel	1,000	n/a	n/a
ECA Marine Fuel	5,000	n/a	n/a
Fuel Additives	339	n/a	n/a
Regulated Blendstocks	339	1.64	n/a

As mentioned above, the default values approximate uncontrolled levels prior to promulgation of current EPA fuel quality standards and create an additional incentive for fuel, fuel additive and regulated blendstock producers to properly sample and test gasoline and ensure that they will not benefit by underreporting the sulfur, benzene, or RVP of gasoline that is not properly sampled or tested. For fuel manufacturers that produce gasoline using the PCG by subtraction approach, the default values for sulfur is 0 ppm and the default value for benzene is 0 volume percent. This approach attributes all sulfur and benzene to the added blendstock and provides incentives for a blending manufacturer to appropriately sample and test the PCG.

In addition to the comments received on default values, one commenter asked for additional detail regarding how to inform EPA about a failure to comply with the sampling and testing requirements and what type of information EPA will consider when determining whether to approve a value that is different than the default values. Regulated parties should inform EPA of a failure to comply with the sampling and testing requirements through EPA's eDisclosure portal.^[99]

The determination about whether to approve a request to use an alternative value will be made on a case-by-case basis. EPA will consider all relevant information in making this determination, including but not limited to engineering analyses and results from tests that do not meet the regulatory standards.

We address comments related to the compliance and enforcement provisions in more detail in Section 19 of the RTC document.

B. Attest Engagements

Part 80 includes a requirement for gasoline refiners and importers to engage auditors to review information reported to EPA. These annual attest engagements allow EPA to more effectively ensure compliance with regulatory requirements.

We are transferring the various existing attest requirements in part 80 to a single subpart in part 1090 (subpart S). We are removing obsolete material, updating the language for improved clarity, and making some minor adjustments and clarifications to improve the quality and consistency of reported information.

For instance, we have added a requirement for auditors to review the fuel manufacturer's calculations showing that they comply with the sulfur and benzene average standards. We note that EPA's Office of Inspector General made certain findings and recommendations regarding compliance with these standards as part of their review of the auditing requirements under part 80.^[100] One recommendation was to modify the attest engagement regulations to require that auditors verify compliance calculations for gasoline manufacturers to help ensure that the benzene average standard was met. We believe the revised attest engagement provisions are consistent with this recommendation and will provide better oversight of the gasoline sulfur and benzene average standards.

We are also codifying the existing attest requirements spelled out in the 2003 Q&A document.^[101] We are adopting these requirements for both CG and RFG. The most significant new provision is the requirement for auditors to review PBMS qualification and SQC records related to the sampling and testing requirements for gasoline on an annual basis. We require a relatively straightforward review by auditors of whether labs used to test gasoline for compliance have records demonstrating that their methods have been qualified under the PBMS qualification requirements and that the lab is maintaining SQC records. It is worth noting that we are not requiring auditors to interpret this information as auditors may lack the appropriate technical expertise to interpret lab data for conformance with PBMS and SQC requirements. (Instead, as discussed in Section X.B, we require that the independent surveyor review this type of information under the NSTOP.) We do not believe that this simple review will greatly increase the burden associated with the annual attest audits. We believe this laboratory record review will help ensure that labs used for testing fuels for compliance are doing so consistent with EPA's quality control requirements helping to ensure a level playing field and program integrity.

We received several comments that suggested edits to the proposed regulations and asked for clarification on the various attest engagement provisions that we have reflected in the final regulations as appropriate. We address these comments in Section 20 of the RTC document.

C. RVP Test Enforcement Tolerance

Under part 80, EPA recognizes and allows a 0.3 psi downstream enforcement test tolerance over applicable RVP standards for RVP test results.^[102] This test tolerance was based on RVP testing variability and the reproducibility of the test methods at the time the RVP standards were established. Under this approach, we rely on test results from locations downstream of fuel manufacturing facilities to bring enforcement actions against downstream parties only if the downstream test results are more than 0.3 psi above the applicable standard. Although any sample that is over the standard is a violation, we generally do not bring enforcement actions against a downstream party if the sample it collects is over the standard but within the 0.3 psi enforcement test tolerance, as long as there is no reason to believe that the downstream party caused the gasoline to exceed the standard. Gasoline manufacturers may not use the tolerance to effectively raise the applicable standard. If the gasoline manufacturer's test results show the gasoline exceeds the RVP standard, then the gasoline is in violation regardless of whether or not the RVP test result is within the tolerance.

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

XIII. Other Requirements and Provisions

A. Requirements for Independent Parties

We are finalizing requirements for third parties performing actions authorized under part 1090 regarding their independence from the regulated parties who engage them and their technical qualifications. These requirements are consistent with part 80 independence and technical competency requirements for independent third-parties. We believe the requirements will preserve and strengthen the integrity of our independent third-party verification programs.

We remain concerned about the potential for conflicts of interest between the independent third-parties that monitor compliance on behalf of EPA and the regulated entities who engage them. Therefore, we are maintaining the same independence requirements for third-parties as currently used in part 80. In addition, since proposing the original independence requirements for third-parties under the RFG and Anti-dumping programs in the 1990s, we have seen that third-parties often employ contractors or subcontractors to fulfill third-party oversight requirements. These contractors or subcontractors should also be free from conflicts of interest from regulated parties for whom services are performed. Therefore, we are clarifying that independence requirements apply not only for the third parties and their employees, but also for any contractors and subcontractors.

Similar to part 80, we are imposing restrictions on both employment history and financial interest. We proposed that independent third parties would be required to ensure that their employees, contractors, and subcontractors had not worked for the regulated party that hired that third party for any amount of time over the previous three years.

We are also finalizing a limitation imposed on the independent third party's firm or organization as to the proportion of revenue it can generate from any single regulated party. We believe this furthers our goal of independent third-party oversight and increases the trustworthiness of the program's results. We requested comment on these independence requirements and their impacts on the independent third parties, as well as the anticipated effectiveness of these provisions to increase reliability in our third-party oversight program. We have adopted some of the suggested changes and have addressed these comments in Section 4 of the RTC document.

Part 1090 also includes requirements on the technical qualifications of the independent third parties. We have employed similar requirements under part 80 and have used these requirements in other cases where technical competency is important to conduct regulated activities for a regulated party.^[103] These provisions ensure that program oversight is being conducted by parties with the requisite technical capabilities. However, we do not currently require this demonstration under part 80 for in-use surveys. Under part 1090, we are requiring that the independent surveyors employ personnel with expertise in the areas of petroleum marketing, sampling and testing fuels at retail stations, and survey design. Technical competency requirements for attest engagement auditors and independent laboratories that qualify alternative test procedures under PBMS are unchanged in part 1090.

Several commenters suggested that the technical qualification requirements were too restrictive. First, commenters suggested that the requirement that independent parties could not provide services that require independence until 3 years after the point when the independent party was last employed by the regulated party was too long and would result in a significant constraint on the availability of technically competent auditors and surveyors. Based on these comments, we reduced the 3-year period to a 1-year period as commenters suggested. Second, one commenter suggested that the technical competency requirement for a lab to qualify non-VCSB methods was too strict and could not be fulfilled by a single person. We are finalizing these provisions as proposed since we believe that a laboratory that is going to qualify non-VCSB methods must have appropriate personnel to evaluate the new method. We have addressed these comments in Section 4 of the RTC document.

B. Labeling

Part 1090 includes provisions that apply specifically to retailers and WPCs, consolidating the various provisions formerly scattered throughout part 80 (including the whole set of fuel dispenser labeling requirements) into one subpart (subpart P) with only minor changes (including removing several obsolete provisions from part 80). We are finalizing, as proposed, the description of the E15 label by replacing descriptive paragraphs with a graphic example of the E15 pump label. We believe these changes will make the regulations easier to identify and follow for retailers and WPCs.

We are finalizing minor modifications to the existing label language for heating oil by removing the now obsolete label language identifying that the heating oil contains greater than 500 ppm sulfur.^[104] Most heating oil sold today meets state 15 ppm sulfur standards, and we believe that it is now misleading and inappropriate to require that heating oil dispensers label their product as having greater than 500 ppm sulfur. To minimize burden on retailers, we are allowing retailers to continue to use existing labels to satisfy the part 1090 labeling requirements until such time as the existing part 80 label needs replacement.

During the rule development process, we received feedback from stakeholders suggesting that the ECA marine fuel labels were no longer necessary due to the way that ECA marine fuel is sold and dispensed for use in Category 3 marine vessels. However, if there were situations where ECA marine fuel is co-dispensed with other fuels, a label might still help avoid the misfueling of diesel engines that require the use of ULSD with ECA marine fuel. We proposed to maintain the existing part 80 label requirement but requested comment on whether maintaining these labels is necessary or whether we could limit the use of the label to only situations where ECA marine fuel is co-dispensed with other fuels. We received no comments on this question, so we are maintaining the ECA marine fuel labels that are currently required under part 80.

C. Refueling Hardware Requirements for Dispensing Facilities and Motor Vehicles

As described in the preceding section, part 1090 includes a subpart devoted to requirements for retailers and WPCs. This subpart also describes requirements related to refueling hardware.

The updated nozzle requirements for refueling motor vehicles are aligned with the requirements adopted under part 80. There is one noteworthy adjustment. We identify nozzle specifications only in millimeters. The parallel metric and English units in part 80 are nearly identical, but this nevertheless creates two separate sets of requirements, which is contrary to the objective of standardizing hardware. The specifications in part 80 also include a level of precision that is greater than is needed to properly identify a standard configuration. The single set of updated specifications, including rounding, are consistent with the specifications in part 80, so the updated nozzle specifications should not cause any existing hardware to be noncompliant, and any existing blueprints for producing nozzles do not need to be modified.

Similar nozzle requirements apply for dispensing gasoline into marine vessels. We are similarly adopting a singular set of nozzle-geometry specifications in millimeters in a way that is aligned with the specifications as originally adopted. We are also concluding the allowed phase-in of these nozzle-geometry specifications. As originally adopted, the nozzle requirements applied as of January 1, 2009, to new installations and to new nozzles used to repair or replace damaged dispensing equipment. Based on industry feedback, the market has now transitioned, so there is no need for our regulations to continue to allow non-standard nozzles. If there are any remaining nozzles for marine refueling that do not meet specifications, we now require that they be replaced with a nozzle that meets the standardized configuration. This requirement applies January 1, 2021, when part 1090 becomes effective.

Part 80 additionally specifies a standardized geometry for filler necks in light-duty and heavy-duty motor vehicles to correspond with the nozzle geometry specifications. We proposed to move these vehicle-based requirements to 40 CFR parts 86 and 1037, which describe standards and other requirements for light-duty and heavy-duty motor vehicles. However, based on a comment received, we are deferring action on this item. As we are not taking any final action on that provision in this action, the regulations at 40 CFR 80.24 remain unchanged. We intend to revisit this issue in a future rulemaking related to vehicle standards.

D. Previously Certified Gasoline (PCG)

We are largely maintaining the existing part 80 provisions for how blending manufacturers may make new batches of gasoline from PCG and blendstocks.^[105] In the Tier 3 rule, we finalized changes to improve the consistency of the PCG provisions across part 80 programs; ^[106] however, we maintained separate PCG provisions for each part 80 gasoline program. In part 1090 we are consolidating these provisions into a single set of PCG provisions that maintain both options used in part 80: (1) PCG by subtraction; and (2) PCG by addition.^[107] Other changes are minor and designed to improve clarity and consistency of the PCG provisions in part 1090. Other provisions related to blending certified butane or certified pentane are discussed in Section V.A.3.

We received several comments related mostly to how to address various scenarios where blendstocks are added into PCG that has been identified for oxygenate blending by the original PCG manufacturer. For example, commenters requested clarification on whether a party that adds blendstock to PCG must account for the fact that the PCG was intended to have oxygenate added to it. In response to these comments, we are modifying the PCG provisions to ensure that oxygenate is accounted for properly.

Several commenters also suggested edits and clarifications to the part 1090 regulations and have made edits to the regulations where appropriate to address these comments. We address these comments in Section 21 of the RTC document.

E. Transmix and Pipeline Interface Provisions

With few exceptions, we are finalizing the proposed requirements under part 1090 for transmix processors that largely mirror what we require under part 80. In part 1090 we are consolidating and simplifying the flexibilities provided to fuel manufacturers that use transmix to produce gasoline and diesel fuel, and are aligning the requirements applicable to these parties to the requirements applicable to other fuel manufacturers under part 1090.^[108] Some of the part 80 regulations characterize the requirements for transmix processors and transmix blenders as alternative compliance mechanisms. For instance, the gasoline sulfur regulations state that “[t]ransmix processors and transmix blenders may comply with [specified] sampling and testing requirements and standards instead of the sampling and testing requirements and standards otherwise applicable to a refiner under this subpart O.” ^[109] The part 1090 regulations set forth specific requirements for transmix processors and transmix blenders because we believe that virtually all transmix processors and blenders are using the alternative approaches set forth in part 80, and because we believe that it would be overly complex for transmix processors and blenders to comply with the requirements that apply to other fuel manufacturers.

1. Clarifying and Consolidating Requirements Relating to Transmix and Pipeline Interface

Provisions related to the treatment of transmix are currently located in various sections in part 80.^[110] To improve clarity, we have consolidated most of the special provisions related to the treatment of transmix into a single subpart in part 1090 (subpart F). We also incorporated the definitions of transmix and pipeline interface into the definitions section of part 1090. These definitions are currently imbedded in part 80 in a regulatory section that pertains to the treatment of interface and transmix.^[111]

2. Blending Transmix Into Previously Certified Gasoline

In part 1090 we made a minor change to the requirements that apply to parties that blend transmix into PCG.^[112] When the quality assurance program required of a transmix blender indicates that the gasoline does not comply with EPA standards, blenders that use a computer controlled in-line blending system were temporarily required under part 80 to conduct more frequent sampling and testing. We changed this requirement so that no more than one sample per day may be used to demonstrate compliance with this increased testing requirement. This change in part 1090 will ensure that the required increase in sampling and testing frequency fulfills the intended purpose of verifying that the issue(s) that caused the violation have been resolved.

3. Gasoline Produced From Transmix Gasoline Product

As proposed, we are consolidating the different RFG and CG provisions that apply to transmix processors into one set of provisions that largely mirrors the part 80 transmix provisions. Transmix gasoline product, or TGP, is the gasoline blendstock that is produced when transmix is separated into blendstocks at a transmix processing facility. The part 1090 regulations require transmix processors and blending manufacturers that produce gasoline with TGP to exclude the volume of TGP and PCG used to produce gasoline from their annual compliance calculations for the sulfur and benzene average standards. Parties that produce gasoline with TGP and other blendstocks must follow the PCG procedures to account for the sulfur and benzene levels of the added blendstocks for demonstrating compliance with annual average sulfur and benzene standards. Transmix processors and blending manufacturers that only produce gasoline from TGP or TGP and PCG are deemed to be in compliance with the sulfur and benzene average standards. In all cases, fuel manufacturers that produce gasoline using TGP must meet per-gallon sulfur and RVP (in the summer) standards for the resultant gasoline and make sure that the gasoline they produce meets the substantially similar requirements of the CAA. If transmix processors can demonstrate that the transmix and any blendstock they use to produce gasoline contain no oxygenate, they are not be required to test the gasoline they produce for oxygenate content.

Based on suggestions from commenters, we are also finalizing provisions that will allow for TGP to be transferred from a transmix processor to another fuel manufacturer to be used to produce gasoline. The transmix processor will use a PTD that designates the product as TGP and note that it is not suitable for use as gasoline. In such cases where TGP is blended to produce gasoline, the TGP is treated as PCG (i.e., the blending manufacturer must take steps to ensure that the sulfur and benzene content from the TGP is excluded from their average standard compliance demonstrations).

4. 500 ppm LM Diesel Fuel Produced From Transmix

We are finalizing as proposed the minor modifications to the regulatory provisions that allow transmix processors to produce 500 ppm LM diesel fuel for use in locomotive and marine engines that do not require the use of ULSD, with one exception. One commenter pointed out that since part 1090 requires all volume measurements to be temperature adjusted, thermal expansion should not result in differences between the volume of 500 ppm LM diesel fuel received versus the volume delivered and used on a compliance period basis. We agree with this comment and removed this as an allowable justification for volume differences.

5. Streamlining the Requirements for Pipeline Interface That Is Not Transmix

We are finalizing the regulatory provisions that allow pipeline operators to cut pipeline interface from batches of RFG and CG that are shipped adjacent to each other by pipeline into either or both these gasoline batches, with fewer limitations than were imposed under part 80. During the winter months there are no restrictions relating to how operators cut pipeline gasoline interface. During the summer season pipeline operators may not cut pipeline interface from two batches of gasoline subject to different RVP standards that are shipped adjacent to each other by pipeline into the gasoline batch that is subject to the more stringent RVP standard. For example, pipeline operators may not cut pipeline interface from a batch of RFG shipped adjacent to a batch of CG into the batch of RFG.

F. Gasoline Deposit Control

1. Overview

We are finalizing streamlined and updated regulations for gasoline deposit control. Section 211(l) of the CAA requires EPA to establish specifications for additives to prevent the accumulation of deposits in engines and fuel supply systems and that all gasoline contain such additives. In response to this requirement, EPA's gasoline deposit control (detergent) program was finalized in July 1996 and became effective in July 1997.^[113] The detergent program requires that all gasoline, including the gasoline blend component of E85, contain a detergent that satisfies EPA deposit control requirements before being distributed from a petroleum terminal. Terminal operators are required to prepare and keep volumetric accounting reconciliation (VAR) records to demonstrate that a sufficient volume of detergent was added to the gasoline they distribute for each accounting period.^[114]

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 NO_X emissions, and a 0.06 percent improvement in fuel economy on average from the gasoline vehicle fleet at the time.^[115] Given the considerable changes to vehicle technology and to gasoline composition since 1990 that may affect both deposit formation and its impact on emissions, and given the lack of emissions test data on the effects of deposits on emissions from modern vehicles, we are unable to quantify the emissions benefits of different levels of deposit control stringency provided by the detergent program today.

At the same time, there is considerable cost and effort associated with continuing to implement the detergent program. Consequently, we are streamlining the program to the extent possible to minimize its cost. Specifically, we are: (1) Eliminating the requirement that a detergent that is demonstrated to control intake valve deposits must also be tested to demonstrate the ability to control fuel injector deposits; (2) easing the adoption of updated deposit control test procedures when they become available; (3) simplifying the process for registration and certification of detergents and the demonstration of compliance by detergent blenders; (4) removing expired and unused provisions; and (5) removing the requirement that the gasoline portion of E85 must contain a certified detergent. In response to several comments, we are finalizing testing requirements for new detergents consistent with part 80 requirements that will maintain the specifications for detergents, while updating them to accommodate new circumstances discussed in this section. The following sections detail the changes we are finalizing.

2. Eliminating the Port Fuel Injector Deposit Control Testing Requirement

We are finalizing our proposal to eliminate the requirement that detergents be tested to demonstrate the ability to control port fuel injector deposits. We received several comments in support of this proposal. This change will substantially decrease the burden of introducing new detergents while maintaining the benefits of the detergent program.

Under part 80, we required separate tests to demonstrate the ability of a detergent to control port fuel injector deposits and intake valve deposits. Input from stakeholders during the rule development process and from comments supports the conclusion that detergents that are capable of controlling intake valve deposits are inherently capable of controlling port fuel injector deposits.^[116] This conclusion is also supported by the elimination of a port fuel injector testing requirement in the industry-based Top Tier detergency program. The Top Tier program was established by industry based on the premise that a superior level of deposit control was needed for today's vehicles than that provided by EPA requirements. Further support is evidenced by the lack of industry activity to have a separate test for port fuel injector deposits. The port fuel injector deposit control test required by EPA is based on the ASTM D5598 fuel injector deposit control test procedure that used a 1985-1987 Chrysler 2.2L vehicle.^[117] The fuel injector technology used in these old test vehicles is no longer representative of technology used in the current vehicle fleet. Current industry efforts are focused on developing an updated intake valve deposit (IVD) control test procedure (discussed in the next section) and the evaluation of deposit control in gasoline direct injection engines that represent an increasing share of the new vehicle fleet.

3. Amending the Intake Valve Deposit Control Test Procedures

Like the port fuel injector test procedure, the intake valve test procedure in our regulations is antiquated and of questionable relevance to the in-use fleet today. New detergents under part 80 are tested using the EPA ASTM D5500 BMW-based deposit control test procedure (“EPA ASTM D5500 procedure”), which uses a 1985 BMW 318i vehicle. This vehicle was accepted as representative of technology in the vehicle fleet when the detergent program was finalized in 1996. However, this 35-year-old vehicle is no longer representative of the technology used in modern vehicles.^[118] It is also increasingly difficult for emissions laboratories to perform the EPA ASTM D5500 procedure due to the deterioration of the aged test vehicles and the lack of replacement parts. Consequently, CRC is currently developing an updated deposit control test procedure.^[119]

In addition, the test fuel specified by EPA for use in the ASTM D5500 procedure is no longer representative of current gasoline. The composition of the requisite test fuel is specified to assure a 65th percentile concentration of gasoline parameters that affect deposit formation based on 1990 gasoline survey data.^[120] The composition of gasoline in the U.S. has changed significantly since 1990 due to EPA fuel quality requirements and changes in refinery operations due to market shifts. These changes to gasoline composition have resulted in current in-use gasoline having a different deposit-forming tendency compared to the 1990 gasoline on which the test fuel specifications are based. Parties that formulate detergent test fuels stated that the more stringent gasoline sulfur requirements were making it impossible to make the sufficiently stringent test fuels using only normal refinery blendstocks or finished gasoline.^[121] As a result, we issued guidance that a sulfur doping compound could be used to meet the minimum test fuel sulfur specification for test purposes, even though such fuels no longer exist in-use.^[122]

Consequently, we proposed to disallow new detergents that had established a lowest additive concentration (LAC) through the EPA ASTM D5500 procedure. We proposed that new detergent deposit control testing could be conducted using the Top Tier program or California's deposit control program.^[123] We also proposed that existing detergent certifications based on the EPA ASTM D5500 procedure would remain valid indefinitely while new testing procedures could be adopted with EPA-approval.

Several commenters suggested that the proposal to disallow new additives tested on the EPA ASTM D5500 procedure would constitute a de facto change in the stringency of the part 80 deposit control standards, which would result in a substantial increase in costs to industry. While we believe that the commenters may have overstated the expected costs, especially considering that we proposed that previously tested detergents under EPA ASTM D5500 would remain valid indefinitely, we agree that the removal of the option to test new detergents using the EPA ASTM D5500 procedure could result in a slight increase in the stringency and cost for new deposit control formulations. As such, we will continue to allow the EPA ASTM D5500 procedure to be used to certify new detergent formulations.

4. Expanding the Applicability of Detergent Certifications Based on Compliance With the California Deposit Control Regulations

Under the part 80 regulations, a detergent certification based on compliance with the California's deposit control regulations may be used to demonstrate compliance with EPA's deposit control requirements only for gasoline that meets the California's compositional requirements and if the detergent is added in a terminal located in the California. This limitation was based on concerns that detergents certified using test fuels representative of California gasoline might not be capable of controlling deposits in gasoline that does not meet California requirements. When EPA's detergent program was finalized in 1996, the composition of gasoline that complies with California standards differed substantially from gasoline that met EPA's requirements.^[124] Through subsequent rulemakings, expansion of E10 nationwide, and other market changes, the composition of gasoline made for use outside of California is much closer to that required by California. Therefore, we believe that detergents certified under California's requirements should be capable of controlling deposits in gasoline that meets EPA's standards. Further support for this assessment is that California requires that a detergent limit the accumulation of intake valve deposits to less than 50 mg per valve whereas EPA's program allows the accumulation of up to 100 mg per valve using the EPA ASTM D5500 procedure. Consequently, we proposed that a detergent certified under California's program could be used to meet EPA's deposit control requirements in all gasoline. Comments received were supportive, as long as we continued to allow for new detergent testing to be done on the EPA ASTM D5500 procedure. As such, we are finalizing the proposal to allow California detergent testing to be used to satisfy EPA detergent testing requirements.

5. Easing the Adoption of Future Updates To Deposit Control Test Procedures

We are finalizing provisions that allow for an administrative process to approve new deposit control test protocols in a streamlined manner. In the proposal, we co-proposed two approaches regarding the process of updating deposit control test procedures for the future and how regulated parties would reference the specifications for these procedures. The primary approach would be through an administrative process, and the alternative approach would be through a traditional rulemaking process.

We are finalizing the primary approach, which allows for deposit control test procedures accepted by EPA to be specified in a publicly available document that could be updated as EPA accepts new procedures.^[125] The use of this streamlined process will greatly facilitate keeping the requirements consistent with current industry practice. For example, the current need for a notice-and-comment rulemaking to amend test procedures specified in the CFR has caused the detergent program to lag far behind in reflecting current industry practice regarding the test fuels used for the ASTM D6201 procedure. Such noncontroversial changes could be made much more been readily through a streamlined administrative process.

Under this approach, stakeholders may petition EPA to adopt changes to the deposit control test procedures previously accepted by EPA (e.g., when an update to an existing test procedure is incorporated into an existing test method). We will then conduct outreach with stakeholders to assess whether there is sufficiently broad support for the proposed change. If we determine that this is the case and the suggested change meets applicable regulatory requirements, we will publish on our web page and by direct communications with stakeholders that we have accepted the change. We may also periodically update the detergent regulations in the CFR to reflect accepted alternatives.

Comments received were supportive of EPA providing added flexibility to approve new detergent testing protocols via an administrative process. Therefore, we are finalizing the primary approach as proposed.

6. Removing Expired and Unused Provisions

We are finalizing the removal of expired and unused provisions in the detergent program to make the detergent regulations more accessible, understandable, and to eliminate the ongoing costs of maintaining these provisions.

The detergent program in part 80 includes provisions allowing a detergent to be certified for use in different gasoline pools using test fuels that have specifications representative of the deposit-forming characteristics of the discrete pools. Under the “national-generic” certification option, a detergent can be certified for use in all gasoline containing any approved oxygenate. Other options allow a detergent to be certified for use only within one of the five Petroleum Administration for Defense Districts (PADDs), in regular or premium gasoline, in oxygenated or nonoxygenated gasoline, in gasoline containing a specific oxygenate other than ethanol, or in a segregated gasoline pool defined by the certification applicant.^[126] We also accept detergent certifications under the California program in lieu of meeting our requirements. Since all applications for detergent certification to date other than those based on the California program have been under the national-generic option we are removing the other options. We believe that it is reasonable to conclude that these options do not provide a meaningful flexibility to industry given that they have remained unused since the detergent program's inception in 1996. Under part 1090, the detergent program will allow all detergents to be used in all gasoline containing any approved oxygenate, as is the case today under the national-generic detergent certification option. Detergent certifications under California's program will also remain valid.^[127]

We are also removing regulatory provisions associated with the interim detergent program that were superseded by the detergent program in 1996.^[128] Comments received on this aspect of the proposal were supportive, and we are therefore finalizing the removal of expired and unused provisions as proposed.

7. Streamlining the Detergent Registration Process

Detergent manufacturers are currently required under part 80 to submit detergent certification test data and detergent composition information for evaluation and approval by EPA prior to the detergent being used to comply with EPA's deposit control requirements. To speed up the introduction of new detergents and to reduce the burden of detergent certification, we are allowing detergent manufacturers to begin marketing a detergent once the manufacturer has satisfied EPA testing requirements without the need for a prior submission of the data to EPA and approval by EPA. Under this approach, detergent manufacturers will still be required to submit data that demonstrates compliance with the deposit control testing requirements upon request by EPA.

Composition information is required for all additives that are registered for use in gasoline under part 79. Additional composition information is also required for detergents to be evaluated for deposit control efficacy under part 80, including the LAC established by detergent deposit control testing. In lieu of requiring a separate submission of this additional information under part 1090, we are requiring it to be submitted with a detergent's part 79 additive registration. Comments on this aspect of the proposal were supportive and we are finalizing the provisions as proposed.

8. Simplifying the Detergent Volumetric Accounting Reconciliation Requirements

Under parts 80, detergent blenders must maintain periodic VAR records to demonstrate that they added a volume of detergent to the gasoline they distribute at least as great as the LAC associated with the certification for the detergent that is used; this is not changing under part 1090. However, under part 80, the VAR provisions require that detergent blenders compile a separate record for each monthly VAR period in a standard format. During the rule development process, detergent blenders stated that the necessary VAR records are kept in electronic form as standard business practice, but that compiling such information into a standard format as required by EPA for each VAR period represented a significant burden. To reduce the burden, we proposed to remove the requirement that a VAR report be prepared for each accounting period. This would also eliminate the burden on industry of requesting and on EPA of issuing a waiver from this requirement during emergency situations to ensure the availability of gasoline. We also proposed to require that detergent blenders keep the necessary records to demonstrate compliance with detergent LAC requirements for each blending facility in whatever form that is their common practice. The same one calendar month or lesser accounting period would still apply. All comments received on the proposal to simplify VAR requirements were supportive, and we are finalizing these provisions as proposed.

9. Removing the Requirement That the Gasoline Portion of E85 Contain Detergent

We are finalizing an exemption to the deposit control requirement for the gasoline portion of E85. The part 80 deposit control regulations require that the gasoline portion of E85 must contain a detergent additive at or above the LAC.^[129] The addition of ethanol to gasoline, with detergent at the LAC, to produce E85 results in a detergent concentration that is lower than the LAC due to the increased dilution from the additional ethanol. We proposed to remove this requirement in the 2016 Renewables Enhancement and Growth Support (REGS) rule.^[130]

In the REGS rule, we noted that we were not aware of data on the deposit control needs of flex-fuel vehicles (FFVs) that operate on E85. We also related input from stakeholders that as additive concentration diminishes due to dilution with ethanol in making E85, there is a point where the presence of a detergent ceases to be beneficial and can instead contribute to deposit formation. We also noted that certain detergents may not be completely soluble in high ethanol content blends. Comments on the REGS rule were supportive of removing the requirement that the gasoline portion of E85 contain detergents.

In the NPRM, we explained that this action is allowable because CAA section 211(l) only refers to deposit control additives for gasoline. E85 is not gasoline because only fuels composed of at least 50 volume percent clear gasoline are included in the gasoline family under part 79 and E85 contains at least 51 volume percent ethanol.^[131] All comments received on this aspect of the proposal were supportive and we are finalizing these provisions as proposed.

G. In-Line Blending Waivers

Under part 1090, we will continue the policy of approving in-line blending waivers. These waivers allow refiners to certify batches using in-line blending equipment instead of the more typical batch certification procedures. Under part 80, we have two different sets of requirements for in-line blending for RFG and CG that we have consolidated into a single set of requirements for in-line blending in part 1090. For RFG manufacturers, the in-line blending requirements remain largely unchanged except that RFG manufacturers' in-line blending waivers need not cover parameters no longer required for certifying batches of gasoline (discussed in more detail in Section V.A.2). RFG manufacturers will still need to arrange for an annual audit to ensure that the terms of the in-line blending waiver are being implemented appropriately. For CG manufacturers, we will allow in-line blending waivers to cover all regulated gasoline parameters instead of just sulfur. CG refiners will also have to undergo the same annual audit procedure that currently exists for RFG refiners under part 80. The flexibility to cover additional parameters for CG refiners through the in-line blending waiver should far exceed any costs associated with the additional audit.

Due to the substantial changes in part 1090 to the requirements for in-line blending waivers, we are requiring all gasoline manufacturers with existing in-line blending waivers to resubmit their in-line blending waiver requests. This will help to ensure that in-line blending waivers appropriately cover the new requirements. Gasoline manufacturers must have EPA-approved updated waiver requests by January 1, 2022. This allows time for refiners to prepare new submissions and for EPA to review and approve those submissions. Note that diesel fuel manufacturers with an existing in-line blending waiver do not need to submit new requests for diesel fuel under part 1090 and may continue to operate under their part 80 in-line blending waiver.

Several commenters expressed concern regarding in-line blending waivers for locations that are blending into tanks. We did not intend to disallow in-line blending into tankage and the part 1090 regulations have been updated to address this concern. We further address these comments in Section 21 of the RTC document.

H. Confidential Business Information

We are finalizing regulations that will streamline our processing of claims that requests for exemptions or flexibilities should be withheld from public disclosure under Exemption 4 of the Freedom of Information Act (FOIA), 5 U.S.C. 552(b)(4), as CBI. The regulations identify certain types of information collected by EPA under part 1090 that EPA will consider as not entitled to confidential treatment pursuant to Exemption 4 of the FOIA and which EPA will release without further notice.

Exemption 4 of the FOIA exempts from disclosure “trade secrets and commercial or financial information obtained from a person [that is] privileged or confidential.” ^[132] In order for information to meet the requirements of Exemption 4, EPA must find that the information is either: (1) A trade secret, or (2) commercial or financial information that is: (a) Obtained from a person, and (b) privileged or confidential. Information meeting these criteria is commonly referred to as CBI.^[133]

In June 2019, the U.S. Supreme Court issued its decision in Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356, 2366 (2019) (Argus Leader). Argus Leader addressed the meaning of “confidential” within the context of FOIA Exemption 4. The Court held that “[a]t least where commercial or financial information is both customarily and actually treated as private by its owner and provided to the government under an assurance of privacy, the information is `confidential' within the meaning of Exemption 4.” ^[134] The Court identified two conditions “that might be required for information communicated to another to be considered confidential.” ^[135] Under the first condition, “information communicated to another remains confidential whenever it is customarily kept private, or at least closely held, by the person imparting it.” (internal citations omitted). The second condition provides that “information might be considered confidential only if the party receiving it provides some assurance that it will remain secret.” (internal citations omitted). The Court found the first condition necessary for information to be considered confidential within the meaning of Exemption 4, but did not address whether the second condition must also be met.

Following issuance of the Court's opinion, the U.S. Department of Justice (DOJ) issued guidance concerning the confidentiality prong of Exemption 4, articulating “the newly defined contours of Exemption 4” post-Argus Leader.^[136] Where the government provides an express or implied indication to the submitter prior to or at the time the information is submitted to the government that the government would publicly disclose the information, then the submitter cannot reasonably expect confidentiality of the information upon submission, and the information is not entitled to confidential treatment under Exemption 4.^[137]

Here, EPA is providing an express indication that we may release certain basic information incorporated into EPA actions on petitions and submissions, as well as information contained in submissions to EPA under part 1090 without further notice, and that such information will not be entitled to confidential treatment. In particular, this decision applies to requests under the following processes: R&D testing exemptions under 40 CFR 1090.610, hardship exemptions under 40 CFR 1090.635, alternative quality assurance programs under 40 CFR 1090.500, alternative PTD language under 40 CFR 1090.1125, in-line blending waivers under 40 CFR 1090.1315, alternative measurement procedures under 40 CFR 1090.1365, survey plans under 40 CFR 1090.1400, and alternative labels under 40 CFR 1090.1500. Accordingly, such information may be released without further notice to the submitter and without following EPA's procedures set forth in 40 CFR part 2, subpart B. Thus, to improve processing of information requests and increase transparency related to EPA determinations, we are clarifying in the regulations that a clearly delineated set of basic information related to our decisions on exemptions, waivers, and alternative procedures under part 1090 will not be treated as confidential.

In this action, we are, by rulemaking, providing potential submitters notice of our intent to release particular information related to future submissions. Upon receipt of submissions, we may release the following information: Submitter's name; the name and location of the facility for which relief is requested, if applicable; the general nature of the request; and the relevant time period for the request, if applicable. Additionally, once we have adjudicated submissions, we may release the following additional information: The extent to which EPA either granted or denied the request, and any relevant conditions.^[138] For information submitted under part 1090 claimed as confidential that is outside the categories described above, and not specified in the regulations at 40 CFR 1090.15(b) or (c), EPA will evaluate such confidentiality claims in accordance with Argus Leader and our regulations at 40 CFR part 2, subpart B.

We find that it is appropriate to release the information described above in the interest of transparency and to provide the public with information about entities seeking exemptions or requests for alternative compliance procedures under part 1090. Given the fungible fuel supply, and the resulting impacts of fuel quality specifications on emissions and emissions control systems when fuels are used in vehicles and engines, the regulations we are finalizing in this action will better inform the public about exemptions to EPA's fuel quality regulations under part 1090 and will allow for the timely release of basic information relating to the requests. In particular, exemptions granted under part 1090 could result in higher levels of sulfur, benzene, or RVP in fuel, as well as changes in other fuel properties, which can have direct impacts on human health and the environment or on the functioning of vehicles, engines, and their emissions control systems. This approach will also provide certainty to submitters regarding the release of information under part 1090. With this advance notice, each potential submitter will have the discretion to decide whether to make such a request with the understanding that EPA may release certain information about the request without further notice.

We received comments suggesting that our treatment of this basic information should be maintained as CBI if so claimed by submitters. Commenters suggested that refineries would have to choose between regulatory relief and release of information that may harm the refinery's reputation or finances. Commenters also suggested that the regulatory relief was specifically promulgated to help entities, and that disclosing information about the refinery would instead result in harm. We find that establishing the potential release of this basic information through regulation appropriately balances the interest in transparency for the public and the protection of information that could harm a refinery's reputation or finances. As noted above, providing the public with information about exemptions and flexibilities will maintain confidence in EPA's regulatory programs assuring fuel quality and expedite the process for the release of this information. It will also better inform the public about the use of these exemptions and flexibilities given the wide use of fuel and its impacts on air quality and engines and equipment. We note that post-Argus Leader substantial competitive harm is no longer the standard for evaluating whether information is confidential within the meaning of Exemption 4, and we are prospectively, via rulemaking, providing that we will not provide this specific information with confidential treatment. Additionally, we disagree with commenters that the disclosure of this information would necessarily result in harm. For many of the flexibilities mentioned above, the mere fact of a request is not often claimed as CBI (e.g., alternative labels or PTD language), and commenters have provided no explanation as to why the disclosure of the fact of a request for these non-hardship regulatory flexibilities and EPA's response could result in harm. For extreme, unusual, and unforeseen hardship exemptions, as discussed in Section VI.A, the conditions under which a refinery can request extreme, unusual, and unforeseen hardship relief going forward are limited (e.g., for natural disasters or refinery fires), and would very likely be known to the public such that the release of the fact of a request and EPA's decision would not result in reputational or financial harm to the refinery. Additionally, the public interest in the release of information relating to fuel quality is high, particularly when, as discussed above, increases in sulfur, benzene, and RVP, or changes in other fuel properties, have direct impacts on human health, the environment, and the functioning of vehicles, engines, and their emissions control systems. Commenters suggested, without any further explanation as to why, that the mere fact of a petition for relief would have “tremendously negative effects on the submitter's competitive petition” and that “[c]ompetitors could seize upon the company's identified vulnerabilities to gain a competitive advantage through any number of methods.” ^[139] In addition to failing to clearly articulate why or how the release of the fact of a petition would result in harm, commenters have not articulated why the basis for relief would not already be known in light of the remaining justifications available for hardship relief under part 1090 (i.e., extreme, unusual and unforeseen hardship relief).

Commenters suggested that this action contradicts Congress's intent in providing provisions for hardship relief and that Congress must amend the CAA to allow for the release of this information. However, the opportunities for regulatory relief under part 1090 are not statutorily prescribed, nor is the confidential nature of the fact of a petition for relief or EPA's decision on it provided in the CAA. Commenters pointed to no CAA text that would suggest otherwise.

Commenters suggested that EPA has treated requests for regulatory relief as confidential for many years. While EPA has treated some requests as confidential, particularly some small refinery hardship exemptions under the RFS program,^[140] historically EPA has also disclosed other types of hardship exemption decisions and names of parties who have received exemptions and other regulatory flexibilities.^[141] Regardless of our past treatment of submissions, future submissions under part 1090 will be subject to the provisions laid out in this rulemaking, and will result in the potential disclosure of the information described above.

As stated above, EPA will continue to evaluate other information submitted to EPA and claimed as CBI and not articulated in 40 CFR 1090.15(b) and (c) in accordance with Argus Leader and our regulations at 40 CFR part 2, subpart B.

XIV. Costs and Benefits

A. Overview

In general, we expect that this action will reduce the cost of fuel distribution by improving fuel fungibility, reducing the costs for regulated parties to comply with our fuel quality regulations, and reducing the costs for EPA to implement these regulations. We do not expect a measurable effect on regulated emissions or air quality as this rule does not change the stringency of EPA's fuel quality standards. This section lays out the general areas of potential cost savings for producing fuels that we believe will result from this action.^[142]

B. Reduced Fuel Costs to Consumers From Improved Fuel Fungibility

A number of the provisions being finalized in part 1090 are expected to improve fuel fungibility. This should result in decreased costs associated with the distribution and sale of such fuels. Some examples of ways that this should result in potential cost savings are the decreased need for separate tanks at terminals, the shipment of larger batches of fuels through pipelines with less interface downgrade, and fewer constraints on distribution and use of certain fuels in various markets (e.g., winter RFG in CG areas). While we believe that these types of savings could be significant, especially when applied to the national gasoline and diesel fuel pools, we are unable to quantify these types of costs savings. In the proposal, we sought comment on these potential areas of savings and information that might enable quantification. While commenters generally supported the provisions that allowed for improved fungibility, we did not receive any comments that provided any additional information or analysis to support the quantification of benefits from improved fungibility. Therefore, we have not quantified the savings from the improved fungibility of fuels as a result of this action.

C. Costs and Benefits for Regulated Parties

We anticipate that the streamlined fuels provisions in part 1090 will significantly reduce the administrative burden for regulated parties to comply with EPA's fuel quality standards. The opportunities to reduce such administrative burden have been discussed throughout this action. Some examples of areas where savings will result are the decrease in the number of fuel parameters needed to be tested to certify gasoline (discussed in Section V.A.2), the reduction in the number and frequency of reports submitted to EPA to demonstrate compliance with our gasoline requirements (discussed in Section VIII.C), and cost savings associated with consolidating the current four in-use survey programs into a single, national in-use survey program (discussed in Section X.A).

In general, estimates in administrative burden reduction are captured in the supporting statement for the proposed information collection request (ICR) required under the Paperwork Reduction Act (PRA) and discussed in more detail in Section XV.C.^[143] As part of this action, we are replacing the multiple existing ICRs for part 80 into a single ICR for all fuel quality programs that are now in part 1090. As part of that process, we are comparing the administrative burden from the existing ICRs to the estimated administrative burden in the new ICR. This results in a burden reduction of about $10.7 million per year. Furthermore, there are additional areas of potential administrative savings for industry that may not be captured in ICRs.^[144] We estimate these savings to be about $29.7 million per year. Including the $10.7 million cost reductions estimated under the ICR, the total estimated savings in administrative costs to industry is $40.4 million per year. Table XIV.C-1 outlines the categories identified for savings.^[145]

Table XIV.C-1—Estimated Annual Cost Savings by Savings Category ^a

Savings category	Savings (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	15.2
Information Collection Request	10.7
Total Savings	40.4
a Cost savings in 2019 dollars.

In addition, there are other potential savings for all stakeholders that are more difficult to quantify. For example, an expected consequence of making the regulations clearer and less complex will be less time and effort for staff to understand and be trained on EPA's regulations and fewer inquiries to EPA or to hired consultants to untangle regulatory ambiguity.

Aspects of this action that are expected to increase costs are expected to be small and offset by a large margin by savings in provisions they replace. Since we are not making changes to the stringency of the fuel quality standards, we do not expect fuel manufacturers to have to alter their production processes in order to comply with part 1090. In prior fuels rulemakings, retooling crude oil refineries often serves as the most significant costs associated with changes in fuel quality standards. Similarly, other parties in the fuel distribution system are not expected to have to make any costly adjustments to how they produce, distribute, and sell fuels, fuel additives, and regulated blendstocks. We do expect there may be some small one-time costs associated with updating recordkeeping and reporting systems and practices associated with the modified regulations. For example, parties will most likely need to change PTDs to reflect the proposed streamlined language. These costs are expected to be small and are reflected in the ICR supporting statement.^[146]

Overall, we expect the savings from increased fungibility of fuels, the decrease in administrative costs, and other indirect cost savings resulting from the modified regulations to far exceed any one-time administrative costs needed to begin compliance with part 1090. These cost savings are expected to be passed along to consumers in the form of lower fuel prices, given the highly competitive fuels marketplace.^[147] We also estimated the total new present value cost savings if the total savings are carried out over 30 years at a 3 percent and 7 percent discounted rate, which are presented in Table XIV.C-2.^[148]

Table XIV.C-2—Estimated Net Present Value Cost Savings ^a

Three percent discount rate (in millions)	Seven percent discount rate (in millions)
$715	$479
a Cost savings in 2019 dollars.

D. Environmental Impacts

Since we are not making changes to the stringency of the existing fuel quality standards, we do not expect any measurable impact on regulated emissions or air quality. However, as discussed in more detail throughout this action, there are certain areas where changes to compliance requirements could be viewed as marginally affecting in-use fuel quality.^[149] These marginal changes could then have a ripple effect on regulated emissions. In general, such changes are very small, typically well below the levels that we have historically attempted to quantify in rulemakings where we establish fuel quality standards. Given the relative size of such changes, it would be difficult if not impossible to make an estimate with any level of confidence on the overall air quality effects that will result from this action.

We sought comment on the potential effect of this action on fuel quality and we did not receive any adverse comments on potential fuel quality issues. We believe the streamlining of the fuel quality programs will on balance ensure greater compliance with our regulatory requirements by making the requirements more intuitive to the regulated community to comply with. We also believe the improved oversight mechanisms will allow us to better oversee compliance with the current fuel standards and take appropriate action when issues are identified. The net result of this may be a slight improvement in fuel quality across the national fuel pool; however, such an effect is difficult to quantify.

XV. Statutory and Executive Order Reviews

Additional information about these statutes and Executive Orders can be found at http://www.epa.gov/​laws-regulations/​laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review

This action is a significant regulatory action that was submitted to the Office of Management and Budget (OMB) for review. Any changes made in response to OMB recommendations have been documented in the docket. EPA prepared an economic analysis of the potential costs and benefits associated with this action. This analysis, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” is available in the docket.

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

This action is considered an Executive Order 13771 deregulatory action. Details on the estimated cost savings of this final rule can be found in EPA's analysis of the potential costs and benefits associated with this action. This analysis, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” is available in the docket.

C. Paperwork Reduction Act (PRA)

The information collection activities in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the PRA. The Information Collection Request (ICR) document that EPA prepared has been assigned OMB ICR number 2060-NEW; EPA ICR number 2607.02. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here. The information collection requirements are not enforceable until OMB approves them.

The information collection activities include requirements for respondents to register, report, sample, and test gasoline for four parameters (i.e., sulfur, benzene, seasonal RVP, and oxygenate/oxygen content in the case of gasoline; and sulfur in the case of diesel), keep records in the normal course of business (e.g., PTDs and test results, as applicable), participate in surveys, conduct attest engagements, and apply fuel dispenser labels.

The information collection for part 1090 will not result in duplication of requirements under existing part 80, as this action will replace nearly all non-RFS provisions under part 80. Part 1090 represents a change from part 80 that will significantly reduce many recordkeeping and reporting burdens associated with complying with EPA's fuel quality standards, including:

• A reduction in the number of unique fuels compliance reporting forms from 30 to six;
• A change in the frequency of batch reporting from quarterly to annual;
• A reduction in the parameters or properties required to be tested and reported, from 13 to four;
• Improvements to forms and procedures to make them more intuitive and remove duplication; and
• A consolidation and updating of PTD and attest engagement requirements.

Most respondents are already registered under part 80 and will not have to re-register under part 1090. The exact information collection requirements in this final rule are tied directly to the party's control over the quality and type of fuel. For example, a refiner of gasoline has great control over the quality and type of fuel and has registration, reporting, sampling, testing, recordkeeping, survey, and attest engagement responsibilities; whereas, a party who owns a retail station has limited information collection requirements involving the retention of customary business records (e.g., PTDs) or affixing labels.

This information collection will result in the replacement of the following existing and approved information collections under part 80: 2060-0178 (Reid Vapor Pressure), 2060-0275 (Detergent Additives), 2060-0277 (Reformulated Gasoline and Anti-Dumping), 2060-0308 (Diesel Sulfur), 2060-0692 (Performance-Based Test Methods), 2060-0675 (E15), and 2060-0437 (“Tier 3”) Gasoline Sulfur. These collections currently total $64,375,590. This collection totals $53,704,290, which represents a cost savings of $10,671,300.

Respondents/affected entities: The respondents to this information collection are parties involved in the manufacture, blending, distribution, sale, or dispensing of regulated fuels and fuel blendstocks. These include refiners, importers, blenders, terminals and pipelines, truck facilities, fuel retailers, and wholesale purchaser-consumers.

Respondent's obligation to respond: Mandatory, under 40 CFR part 1090.

Estimated number of respondents: 134,668.

Frequency of response: Annual, quarterly, and occasionally.

Total estimated burden: 608,992 hours (per year). Burden is defined at 5 CFR 1320.3(b).

Total estimated cost: $53,704,290 (per year), of which $36,787,434 represents capital/overhead and maintenance cost ($5,744,016) and purchased services ($31,043,418). The estimated labor costs are $19,722,363.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves this ICR, EPA will announce that approval in the Federal Register and publish a technical amendment to 40 CFR part 9 to display the OMB control number for the approved information collection activities contained in this final rule.

D. Regulatory Flexibility Act (RFA)

I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. In making this determination, the impact of concern is any significant adverse economic impact on small entities. An agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, has no net burden, or otherwise has a positive economic effect on the small entities subject to the rule. This action consolidates EPA's existing fuel quality regulations into the new 40 CFR part 1090, and the requirements on small entities are largely the same as those already included in the existing 40 CFR part 80 fuel quality regulations. While this action makes relatively minor corrections and modifications to those regulations, we do not anticipate that there will be any significant cost increases associated with these changes. To the contrary, we have quantified overall cost savings from this action.^[150] Even in those areas where we are imposing provisions with new costs for some entities, they are either offset by other larger cost savings or far below having any significant economic impact on a substantial number of small entities. We have therefore concluded that this action will have no net regulatory burden for all directly regulated small entities.

E. Unfunded Mandates Reform Act (UMRA)

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

F. Executive Order 13132: Federalism

This action does not have federalism implications. EPA believes, however, that this rule may be of significant interest to state and local governments. To the extent that states have adopted fuel regulations based on EPA's regulatory provisions that we are changing, they may need to make corresponding changes to their regulations to maintain their effectiveness. Consistent with the EPA's policy to promote communications between EPA and state and local governments, EPA consulted with representatives of various state and local governments early in the process of developing this rule to permit them to have meaningful and timely input into its development. EPA has also consulted with representatives from the National Association of Clean Air Agencies (NACAA, representing state and local air pollution officials), Association of Air Pollution Control Agencies (AAPCA, representing state and local air pollution officials), and Northeast States for Coordinated Air Use Management (NESCAUM, the Clean Air Association of the Northeast States).

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

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

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

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

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

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

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

This action involves technical standards. EPA is updating a number of regulations that already contain voluntary consensus standards (VCS), practices, and specifications to more recent versions of these standards. In accordance with the requirements of 1 CFR 51.5, EPA is incorporating by reference the use of test methods and standards from American Institute of Certified Public Accountants, American Society for Testing and Materials International (ASTM International), National Institute of Standards and Technology (NIST), and The Institute of Internal Auditors. A detailed discussion of these test methods and standards can be found in Sections III.D.3, VII.F, VIII.F, IX, and XIII.F. The standards and test methods may be obtained through the American Institute of Certified Public Accountants website (www.aicpa.org) or by calling [phone], ASTM International website (www.astm.org) or by calling ASTM at [phone], the National Institute of Standards and Technology website (www.nist.gov) or by calling NIST at [phone], and The Institute of Internal Auditors website (www.theiia.org) or by calling [phone].

EPA continues to reference the following standards, previously approved for incorporation by reference, without change in part 1065: ASTM D86-12, D93-13, D445-12, D613-13, D4052-11, D5186-03 (R2009).

This rulemaking involves environmental monitoring or measurement. Consistent with EPA's Performance Based Measurement System (PBMS), for those fuel parameters that fall under PBMS (e.g., sulfur, benzene, Reid Vapor Pressure, and oxygenate content), EPA has decided not to require the use of specific, prescribed analytic methods. Rather, EPA will allow the use of any method that meets the prescribed performance criteria. The PBMS approach is intended to be more flexible and cost-effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified. EPA will also allow the use of specific standard practices or test methods for situations when PBMS would not be applicable, such as gasoline detergency certification test methods or references to gasoline specification ASTM D4814 or ethanol specification ASTM D4806.

Table XV.J-1—Standards and Test Methods To Be Incorporated by Reference

Organization and standard or test method	Description
American Institute of Certified Public Accountants—AICPA Code of Professional Conduct, updated through June 2020	Document describes principles to establish a code of professional conduct for external auditors.
American Institute of Certified Public Accountants—Statements on Quality Control Standards (SQCS) No. 8, QC Section 10: A Firm's System of Quality Control, current as of July 1, 2019	Document describes an external auditor's CPA firm's responsibilities for its system of quality control for its accounting and auditing practices.
American Institute of Certified Public Accountants—Statement on Standards for Attestation Engagements No. 18, Attestation Standards: Clarification and Recodification, Issued April 2016	Document describes standard practices for external auditors to perform attestation engagements using agreed-upon procedures.
ASTM D86-20a, Standard Test Method for Distillation of Petroleum Products and Liquid Fuels at Atmospheric Pressure, approved July 1, 2020	Test method describes how to perform distillation measurements for gasoline and other petroleum products.
ASTM D287-12b (Reapproved 2019), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), approved December 1, 2019	Test method describes how to measure the density of fuels and other petroleum products, expressed in terms of API gravity.
ASTM D975-20a, Standard Specification for Diesel Fuel, approved June 1, 2020	Specification describes the characteristic values for several parameters to be considered suitable as diesel fuel.
ASTM D976-06 (Reapproved 2016), Standard Test Method for Calculated Cetane Index of Distillate Fuels, approved April 1, 2016	Test method describes how to calculate cetane index for a sample of diesel fuel and other distillate fuels.
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	Test method describes how to measure the density of fuels and other petroleum products, which can be expressed in terms of API gravity.
ASTM D1319-19, Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption, approved August 1, 2019	Test method describes how to measure the aromatic content and other hydrocarbon types in diesel fuel and other petroleum products.
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	Test method describes how to determine the content of various types of hydrocarbons in light-end petroleum products, which is used for determining the purity of butane and propane.
ASTM D2622-16, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, approved January 1, 2016	Test method describes how to measure the sulfur content in gasoline, diesel fuel, and other petroleum products.
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	Test method describes how to measure the sulfur content in diesel fuel and other petroleum products.
ASTM D3231-18, Standard Test Method for Phosphorus in Gasoline, approved April 1, 2018	Test method describes how to measure the phosphorus content of gasoline.
ASTM D3237-17, Standard Test Method for Lead in Gasoline by Atomic Absorption Spectroscopy, approved June 1, 2017	Test method describes how to measure the lead content of gasoline.
ASTM D3606-20e1, Standard Test Method for Determination of Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography, approved July 1, 2020	Test method describes how to measure the benzene content of gasoline and similar fuels.
ASTM D4052-18a, Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter, approved December 15, 2018	Test method describes how to measure the density of fuel samples, which can be expressed in terms of API gravity.
ASTM D4057-19, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, approved July 1, 2019	Document establishes proper procedures for drawing samples of fuel and other petroleum products from storage tanks and other containers using manual procedures.
ASTM D4177-16e1, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, approved October 1, 2016	Document establishes proper procedures for using automated procedures to draw fuel samples for testing.
ASTM D4737-10 (Reapproved 2016), Standard Test Method for Calculated Cetane Index by Four Variable Equation, approved July 1, 2016	Test method describes how to calculate cetane index for a sample of diesel fuel and other distillate fuels.
ASTM D4806-20, Standard Specification for Denatured Fuel Ethanol for Blending with Gasolines for Use as Automotive Spark-Ignition Engine Fuel, approved May 1, 2020	Specification describes the characteristic values for several parameters to be considered suitable as denatured fuel ethanol for blending with gasoline.
ASTM D4814-20a, Standard Specification for Automotive Spark-Ignition Engine Fuel, approved April 1, 2020	Specification describes the characteristic values for several parameters to be considered suitable as gasoline.
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	Test method describes how to measure benzene in butane, pentane, and other light-end petroleum compounds.
ASTM D5186-20, Standard Test Method for Determination of the Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By Supercritical Fluid Chromatography, approved July 1, 2020	Test method describes how to determine the aromatic content in diesel fuel.
ASTM D5191-20, Standard Test Method for Vapor Pressure of Petroleum Products and Liquid Fuels (Mini Method), approved May 1, 2020	Test method describes how to determine the vapor pressure of gasoline and other petroleum products.
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	Test method describes how to measure the sulfur content of neat ethanol and other petroleum products.
ASTM D5500-20a, Standard Test Method for Vehicle Evaluation of Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit Formation, approved June 1, 2020	Test method describes a vehicle test procedure to evaluate intake valve deposit formation of gasoline.
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	Test method describes how to measure the oxygenate content of gasoline.
ASTM D5769-20, Standard Test Method for Determination of Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry, approved June 1, 2020	Test method describes how to determine the benzene content and other types of hydrocarbons in gasoline.
ASTM D5842-19, Standard Practice for Sampling and Handling of Fuels for Volatility Measurement, approved November 1, 2019	Document establishes proper procedures for drawing samples of gasoline and other fuels from storage tanks and other containers using manual procedures to prepare samples for measuring vapor pressure.
ASTM D5854-19a, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products, approved May 1, 2019	Document establishes proper procedures for handling, mixing, and conditioning procedures to prepare representative composite samples.
ASTM D6201-19a, Standard Test Method for Dynamometer Evaluation of Unleaded Spark-Ignition Engine Fuel for Intake Valve Deposit Formation, approved December 1, 2019	Test method describes an engine test procedure to evaluate intake valve deposit formation of gasoline.
ASTM D6259-15 (Reapproved 2019), Standard Practice for Determination of a Pooled Limit of Quantitation for a Test Method, approved May 1, 2019	Document establishes procedures to determine how to evaluate parameter measurements at very low levels, including a laboratory limit of quantitation that applies for a given facility.
ASTM D6299-20, Standard Practice for Applying Statistical Quality Assurance and Control Charting Techniques to Evaluate Analytical Measurement System Performance, approved May 1, 2020	Document establishes procedures to evaluate measurement system performance relative to statistical criteria for ensuring reliable measurements.
ASTM D6550-20, Standard Test Method for Determination of Olefin Content of Gasolines by Supercritical-Fluid Chromatography, approved July 1, 2020	Test method describes how to determine the olefin content of gasoline.
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	Test method describes how to determine the sulfur content of butane, liquefied petroleum gases, and other gaseous hydrocarbons.
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	Document establishes statistical criteria to evaluate whether an alternative test method provides results that are consistent with a reference procedure.
ASTM D6729-14, Standard Test Method for Determination of Individual Components in Spark Ignition Engine Fuels by 100 Metre Capillary High Resolution Gas Chromatography, approved October 1, 2014	Test method describes how to determine the benzene content of butane and pentane.
ASTM D6730-19, Standard Test Method for Determination of Individual Components in Spark Ignition Engine Fuels by 100-Metre Capillary (with Precolumn) High-Resolution Gas Chromatography, approved July 1, 2019	Test method describes how to determine the benzene content of butane and pentane.
ASTM D6751-20, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, approved January 1, 2020	Document establishes specifications for neat biodiesel to be blended into diesel fuel.
ASTM D6792-17, Standard Practice for Quality Management Systems in Petroleum Products, Liquid Fuels, and Lubricants Testing Laboratories, approved May 1, 2017	Document establishes principles for ensuring quality for laboratories involved in parameter measurements for fuels and other petroleum products.
ASTM D7039-15a (Reapproved 2020), Standard Test Method for Sulfur in Gasoline, Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray Fluorescence Spectrometry, approved May 1, 2020	Test method describes how to measure sulfur in gasoline and other petroleum products.
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	Document establishes procedures for blending denatured fuel ethanol with gasoline to prepare a sample for testing.
ASTM D7777-13 (Reapproved 2018)e1, Standard Test Method for Density, Relative Density, or API Gravity of Liquid Petroleum by Portable Digital Density Meter, approved October 1, 2018	Test method describes how to measure the density of fuels and other petroleum products, expressed in terms of API gravity.
CARB Test Method, 13 CA ADC § 2257; California Code of Regulations Title 13. Motor Vehicles, Division 3. Air Resources Board, Chapter 5. Standards for Motor Vehicle Fuels, Article 1. Standards for Gasoline, Subarticle 1. Gasoline Standards that Became Applicable Before 1996, § 2257. Required Additives in Gasoline; amendment filed May 17, 1999	Test method describes a vehicle test procedure to evaluate intake valve deposit formation of gasoline.
The Institute of Internal Auditors—International Standards for the Professional Practice of Internal Auditing (Standards), Revised October 2016	Document describes standard practices for internal auditors to perform auditing services.
NIST Handbook 158, Field Sampling Procedures for Fuel and Motor Oil Quality Testing—A Handbook for Use by Fuel and Oil Quality Regulatory Officials, 2016 Edition, April 2016	Document describes procedures for drawing fuel samples from blender pumps and other in-field installations for testing to measure fuel parameters.

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

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

L. Congressional Review Act (CRA)

This action is subject to the CRA, and EPA will submit a rule report to each House of the Congress and to the Comptroller General of the United States. This action is not a “major rule” as defined by 5 U.S.C. 804(2).

XVI. Statutory Authority

Statutory authority for this action comes from sections 202, 203-209, 211, 213, 216, and 301 of the Clean Air Act, 42 U.S.C. 7414, 7521, 7522-7525, 7541, 7542, 7543, 7545, 7547, 7550, and 7601 as well as Public Law 109-58. Additional support for the procedural and compliance related aspects of this action comes from sections 114, 208, and 301(a) of the Clean Air Act, 42 U.S.C. 7414, 7521, 7542, and 7601(a).

List of Subjects

40 CFR Parts 60, 63, 1042, and 1043

• Administrative practice and procedure
• Air pollution control

40 CFR Part 79

• Fuel additives
• Gasoline
• Motor vehicle pollution
• Penalties
• Reporting and recordkeeping requirements

40 CFR Part 80

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

40 CFR Part 1065

• Administrative practice and procedure
• Air pollution control
• Incorporation by reference

40 CFR Part 1090

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

Dated: October 15, 2020.

Andrew Wheeler,

Administrator.

For the reasons set forth in the preamble, EPA amends 40 CFR parts 60, 63, 79, 80, 1042, 1043, and 1065 and adds 40 CFR part 1090 as follows:

PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

1. The authority citation for part 60 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart IIII—Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

2. Amend § 60.4207 by:

a. Removing and reserving paragraph (a);

b. In paragraph (b), removing “ 40 CFR 80.510(b)” and adding “40 CFR 1090.305” in its place; and

c. Revising paragraph (d).

The revision reads as follows:

§ 60.4207

What fuel requirements must I meet if I am an owner or operator of a stationary CI internal combustion engine subject to this subpart?

* * * * *

(d) Beginning June 1, 2012, owners and operators of stationary CI ICE subject to this subpart with a displacement of greater than or equal to 30 liters per cylinder must use diesel fuel that meets a maximum per-gallon sulfur content of 1,000 parts per million (ppm).

* * * * *

Subpart JJJJ—Standards of Performance for Stationary Spark Ignition Internal Combustion Engines

§ 60.4235

[Amended]

3. Amend § 60.4235 by removing “ 40 CFR 80.195” and adding “40 CFR 1090.205” in its place.

PART 63—NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FOR SOURCE CATEGORIES

4. The authority citation for part 63 continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart R—National Emission Standards for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)

5. Amend § 63.421 by revising the definitions for “Oxygenated gasoline” and “Reformulated gasoline” to read as follows:

§ 63.421

Definitions.

* * * * *

Oxygenated gasoline means the same as defined in 40 CFR 80.2.

* * * * *

Reformulated gasoline means the same as defined in 40 CFR 80.2.

* * * * *

Subpart ZZZZ—National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines

§ 63.6604

[Amended]

6. In § 63.6604, amend paragraphs (a), (b), and (c) by removing “ 40 CFR 80.510(b)” and adding “40 CFR 1090.305” in its place.

PART 79—REGISTRATION OF FUEL AND FUEL ADDITIVES

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

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

Subpart A—General Provisions

8. Amend § 79.5 by revising paragraph (a)(1) to read as follows:

§ 79.5

Periodic reporting requirements.

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

* * * * *

Subpart C—Additive Registration Procedures

9. Amend § 79.21 by:

a. Revising paragraphs (f) and (g); and

b. Adding paragraph (j).

The revisions and addition read as follows:

§ 79.21

Information and assurances to be provided by the additive manufacturer.

* * * * *

(f) Assurances that any change in information submitted pursuant to:

(1) Paragraphs (a), (b), (c), (d), and (j) of this section will be provided to the Administrator in writing within 30 days of such change; and

(2) Paragraph (e) of this section as provided in § 79.5(b).

(g)(1) Assurances that the additive manufacturer will not represent, directly or indirectly, in any notice, circular, letter, or other written communication or any written, oral, or pictorial notice or other announcement in any publication or by radio or television, that registration of the additive constitutes endorsement, certification, or approval by any agency of the United States, except as specified in paragraph (g)(2) of this section.

(2) In the case of an additive that has its purpose-in-use identified as a deposit control additive for use in gasoline pursuant to the requirements of paragraph (d) of this section, the additive manufacturer may publicly represent that the additive meets the EPA's gasoline deposit control requirements, provided that the additive manufacturer is in compliance with the requirements of 40 CFR 1090.260.

* * * * *

(j) If the purpose-in-use of the additive identified pursuant to the requirements of paragraph (d) of this section is a deposit control additive for use in gasoline, the manufacturer must submit the following in addition to the other information specified in this section:

(1) The lowest additive concentration (LAC) that is compliant with the gasoline deposit control requirements of 40 CFR 1090.260.

(2) The deposit control test method in 40 CFR 1090.1395 that the additive is compliant with.

(3) A complete listing of the additive's components and the weight or volume percent (as applicable) of each component.

(i) Nomenclature. When possible, standard chemical nomenclature must be used or the chemical structure of the component must be given. Polymeric components may be reported as the product of other chemical reactants, provided that the supporting data specified in paragraph (j)(3) of this section is also reported.

(ii) Designation. Each detergent-active component of the package must be classified into one of the following designations:

(A) Polyalkyl amine.

(B) Polyether amine.

(C) Polyalkylsuccinimide.

(D) Polyalkylaminophenol.

(E) Detergent-active petroleum-based carrier oil.

(F) Detergent-active synthetic carrier oil.

(G) Other detergent-active component (identify category, if feasible).

(iii) Composition variability. (A) The composition of a detergent additive reported in a single additive registration (and the detergent additive product sold under a single additive registration) may not include the following:

(1) Detergent-active components that differ in identity from those contained in the detergent additive package at the time of deposit control testing.

(2) A range of concentrations for any detergent-active component such that, if the component were present in the detergent additive package at the lower bound of the reported range, the deposit control effectiveness of the additive package would be reduced as compared with the level of effectiveness demonstrated pursuant to the requirements of 40 CFR 1090.260. Subject to the foregoing constraint, a gasoline detergent additive sold under a particular additive registration may contain a higher concentration of the detergent-active component(s) than the concentration(s) of such component(s) reported in the registration for the additive.

(B) The identity or concentration of non-detergent-active components of the detergent additive package may vary under a single registration provided that such variability does not reduce the deposit control effectiveness of the additive package as compared with the level of effectiveness demonstrated pursuant to the requirements of 40 CFR 1090.260.

(C) Unless the additive manufacturer provides EPA with data to substantiate that a carrier oil does not act to enhance the detergent additive's ability to control deposits, any carrier oil contained in the detergent additive, whether petroleum-based or synthetic, must be treated as a detergent-active component in accordance with the requirements in paragraph (j)(3)(ii) of this section.

(D) Except as provided in paragraph (j)(3)(iii)(E) of this section, detergent additive packages that do not satisfy the requirements in paragraphs (j)(3)(iii)(A) through (C) must be separately registered. EPA may disqualify an additive for use in satisfying the requirements of this subpart if EPA determines that the variability included within a given detergent additive registration may reduce the deposit control effectiveness of the detergent package such that it may invalidate the lowest additive concentration reported in accordance with the requirements of paragraph (j)(1) of this section and 40 CFR 1090.260.

(E) A change in minimum concentration requirements resulting from a modification of detergent additive composition does not require a new detergent additive registration or a change in existing registration if the modification is affected by a detergent blender pursuant to the requirements of 40 CFR 1090.1240.

(4) For detergent-active polymers and detergent-active carrier oils that are reported as the product of other chemical reactants:

(i) Identification of the reactant materials and the manufacturer's acceptance criteria for determining that these materials are suitable for use in synthesizing detergent components. The manufacturer must maintain documentation, and submit it to EPA upon request, demonstrating that the acceptance criteria reported to EPA are the same criteria which the manufacturer specifies to the suppliers of the reactant materials.

(ii) A Gel Permeation Chromatograph (GPC), providing the molecular weight distribution of the polymer or detergent-active carrier oil components and the concentration of each chromatographic peak representing more than one percent of the total mass. For these results to be acceptable, the GPC test procedure must include equipment calibration with a polystyrene standard or other readily attainable and generally accepted calibration standard. The identity of the calibration standard must be provided, together with the GPC characterization of the standard.

(5) For non-detergent-active carrier oils, the following parameters:

(i) T10, T50, and T90 distillation points, and end boiling point, measured according to applicable test procedures cited in 40 CFR 1090.1350.

(ii) API gravity and viscosity.

(iii) Concentration of oxygen, sulfur, and nitrogen, if greater than or equal to 0.5 percent (by weight) of the carrier oil.

(6) Description of an FTIR-based method appropriate for identifying the detergent additive package and its detergent-active components (polymers, carrier oils, and others) both qualitatively and quantitatively, together with the actual infrared spectra of the detergent additive package and each detergent-active component obtained by this test method. The FTIR 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.

10. Revise § 79.24 to read as follows:

§ 79.24

Termination of registration of additives.

(a) Registration may be terminated by the Administrator if the additive manufacturer requests such termination in writing.

(b) Registration for an additive that has its purpose-in-use identified as a deposit control additive for use in gasoline pursuant to the requirements of § 79.21(d) may be terminated by the Administrator if the EPA determines that the detergent additive is not compliant with the gasoline deposit control requirements of 40 CFR 1090.260.

Subpart D—Designation of Fuels and Additives

11. Amend § 79.32 by revising paragraph (c) to read as follows:

§ 79.32

Motor vehicle gasoline.

* * * * *

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

* * * * *

12. Amend § 79.33 by revising paragraph (c) to read as follows:

§ 79.33

Motor vehicle diesel.

* * * * *

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

* * * * *

PART 80—REGISTRATION OF FUELS AND FUEL ADDITIVES

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

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

Subpart A—General Provisions

14. Revise § 80.1 to read as follows:

§ 80.1

Scope.

(a) This part prescribes regulations for the renewable fuel program under the Clean Air Act section 211(o) (42 U.S.C. 7545(o)).

(b) This part also prescribes regulations for the labeling of fuel dispensing systems for oxygenated gasoline at retail under the Clean Air Act section 211(m)(4) (42 U.S.C. 7545(m)(4)).

(c) Nothing in this part is intended to preempt the ability of state or local governments to control or prohibit any fuel or fuel additive for use in motor vehicles and motor vehicle engines which is not explicitly regulated by this part.

15. Revise § 80.2 to read as follows:

§ 80.2

Definitions.

Definitions apply in this part as described in this section.

Administrator means the Administrator of the Environmental Protection Agency.

Carrier means any distributor who transports or stores or causes the transportation or storage of gasoline or diesel fuel without taking title to or otherwise having any ownership of the gasoline or diesel fuel, and without altering either the quality or quantity of the gasoline or diesel fuel.

Category 3 (C3) marine vessels, for the purposes of this part 80, are vessels that are propelled by engines meeting the definition of “Category 3” in 40 CFR 1042.901.

CBOB means gasoline blendstock that could become conventional gasoline solely upon the addition of oxygenate.

Control area means a geographic area in which only oxygenated gasoline under the oxygenated gasoline program may be sold or dispensed, with boundaries determined by Clean Air Act section 211(m) (42 U.S.C. 7545(m)).

Control period means the period during which oxygenated gasoline must be sold or dispensed in any control area, pursuant to Clean Air Act section 211(m)(2) (42 U.S.C. 7545(m)(2)).

Conventional gasoline or CG means any gasoline that has been certified under 40 CFR 1090.1000(b) and is not RFG.

Diesel fuel means any fuel sold in any State or Territory of the United States and suitable for use in diesel engines, and that is one of the following:

(1) A distillate fuel commonly or commercially known or sold as No. 1 diesel fuel or No. 2 diesel fuel;

(2) A non-distillate fuel other than residual fuel with comparable physical and chemical properties (e.g., biodiesel fuel); or

(3) A mixture of fuels meeting the criteria of paragraphs (1) and (2) of this definition.

Distillate fuel means diesel fuel and other petroleum fuels that can be used in engines that are designed for diesel fuel. For example, jet fuel, heating oil, kerosene, No. 4 fuel, DMX, DMA, DMB, and DMC are distillate fuels; and natural gas, LPG, gasoline, and residual fuel are not distillate fuels. Blends containing residual fuel may be distillate fuels.

Distributor means any person who transports or stores or causes the transportation or storage of gasoline or diesel fuel at any point between any gasoline or diesel fuel refinery or importer's facility and any retail outlet or wholesale purchaser-consumer's facility.

ECA marine fuel is diesel, distillate, or residual fuel that meets the criteria of paragraph (1) of this definition, but not the criteria of paragraph (2) of this definition.

(1) All diesel, distillate, or residual fuel used, intended for use, or made available for use in Category 3 marine vessels while the vessels are operating within an Emission Control Area (ECA), or an ECA associated area, is ECA marine fuel, unless it meets the criteria of paragraph (2) of this definition.

(2) ECA marine fuel does not include any of the following fuel:

(i) Fuel used by exempted or excluded vessels (such as exempted steamships), or fuel used by vessels allowed by the U.S. government pursuant to MARPOL Annex VI Regulation 3 or Regulation 4 to exceed the fuel sulfur limits while operating in an ECA or an ECA associated area (see 33 U.S.C. 1903).

(ii) Fuel that conforms fully to the requirements of this part for MVNRLM diesel fuel (including being designated as MVNRLM).

(iii) Fuel used, or made available for use, in any diesel engines not installed on a Category 3 marine vessel.

Gasoline means any fuel sold in any State ¹ for use in motor vehicles and motor vehicle engines, and commonly or commercially known or sold as gasoline.

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

Gasoline blendstock or component means any liquid compound that is blended with other liquid compounds to produce gasoline.

Gasoline blendstock for oxygenate blending or BOB has the meaning given in 40 CFR 1090.80.

Gasoline treated as blendstock or GTAB means imported gasoline that is excluded from an import facility's compliance calculations, but is treated as blendstock in a related refinery that includes the GTAB in its refinery compliance calculations.

Heating oil means any No. 1, No. 2, or non-petroleum diesel blend that is sold for use in furnaces, boilers, and similar applications and which is commonly or commercially known or sold as heating oil, fuel oil, and similar trade names, and that is not jet fuel, kerosene, or MVNRLM diesel fuel.

Importer means a person who imports gasoline, gasoline blendstocks or components, or diesel fuel from a foreign country into the United States (including the Commonwealth of Puerto Rico, the Virgin Islands, Guam, American Samoa, and the Northern Mariana Islands).

Jet fuel means any distillate fuel used, intended for use, or made available for use in aircraft.

Kerosene means any No.1 distillate fuel commonly or commercially sold as kerosene.

Liquefied petroleum gas or LPG means a liquid hydrocarbon fuel that is stored under pressure and is composed primarily of species that are gases at atmospheric conditions (temperature = 25 °C and pressure = 1 atm), excluding natural gas.

Locomotive engine means an engine used in a locomotive as defined under 40 CFR 92.2.

Marine engine has the meaning given in 40 CFR 1042.901.

MVNRLM diesel fuel means any diesel fuel or other distillate fuel that is used, intended for use, or made available for use in motor vehicles or motor vehicle engines, or as a fuel in any nonroad diesel engines, including locomotive and marine diesel engines, except the following: Distillate fuel with a T90 at or above 700 °F that is used only in Category 2 and 3 marine engines is not MVNRLM diesel fuel, and ECA marine fuel is not MVNRLM diesel fuel (note that fuel that conforms to the requirements of MVNRLM diesel fuel is excluded from the definition of “ECA marine fuel” in this section without regard to its actual use). Use the distillation test method specified in 40 CFR 1065.1010 to determine the T90 of the fuel.

(1) Any diesel fuel that is sold for use in stationary engines that are required to meet the requirements of 40 CFR 1090.300, when such provisions are applicable to nonroad engines, is considered MVNRLM diesel fuel.

(2) [Reserved]

Natural gas means a fuel whose primary constituent is methane.

Non-petroleum diesel means a diesel fuel that contains at least 80 percent mono-alkyl esters of long chain fatty acids derived from vegetable oils or animal fats.

Nonroad diesel engine means an engine that is designed to operate with diesel fuel that meets the definition of nonroad engine in 40 CFR 1068.30, including locomotive and marine diesel engines.

Oxygenate means any substance which, when added to gasoline, increases the oxygen content of that gasoline. Lawful use of any of the substances or any combination of these substances requires that they be “substantially similar” under section 211(f)(1) of the Clean Air Act (42 U.S.C. 7545(f)(1)), or be permitted under a waiver granted by the Administrator under the authority of section 211(f)(4) of the Clean Air Act (42 U.S.C. 7545(f)(4)).

Oxygenated gasoline means gasoline which contains a measurable amount of oxygenate.

Refiner means any person who owns, leases, operates, controls, or supervises a refinery.

Refinery means any facility, including but not limited to, a plant, tanker truck, or vessel where gasoline or diesel fuel is produced, including any facility at which blendstocks are combined to produce gasoline or diesel fuel, or at which blendstock is added to gasoline or diesel fuel.

Reformulated gasoline or RFG means any gasoline whose formulation has been certified under 40 CFR 1090.1000(b), and which meets each of the standards and requirements prescribed under 40 CFR 1090.220.

Reformulated gasoline blendstock for oxygenate blending, or RBOB means a petroleum product that, when blended with a specified type and percentage of oxygenate, meets the definition of reformulated gasoline, and to which the specified type and percentage of oxygenate is added other than by the refiner or importer of the RBOB at the refinery or import facility where the RBOB is produced or imported.

Residual fuel means a petroleum fuel that can only be used in diesel engines if it is preheated before injection. For example, No. 5 fuels, No. 6 fuels, and RM grade marine fuels are residual fuels. Note: Residual fuels do not necessarily require heating for storage or pumping.

Retail outlet means any establishment at which gasoline, diesel fuel, natural gas or liquefied petroleum gas is sold or offered for sale for use in motor vehicles or nonroad engines, including locomotive or marine engines.

Retailer means any person who owns, leases, operates, controls, or supervises a retail outlet.

Wholesale purchaser-consumer means any person that is an ultimate consumer of gasoline, diesel fuel, natural gas, or liquefied petroleum gas and which purchases or obtains gasoline, diesel fuel, natural gas or liquefied petroleum gas from a supplier for use in motor vehicles or nonroad engines, including locomotive or marine engines and, in the case of gasoline, diesel fuel, or liquefied petroleum gas, receives delivery of that product into a storage tank of at least 550-gallon capacity substantially under the control of that person.

§ 80.3

[Removed and reserved]

16. Effective January 1, 2022, remove and reserve § 80.3.

§ 80.7

[Amended]

17. In § 80.7, amend paragraph (c) by removing “§ 80.22” and adding “ 40 CFR 1090.1550” in its place.

Subpart B—Controls and Prohibitions

§ § 80.22, 80.23, and 80.26 through 80.33

[Removed and reserved]

18. Effective January 1, 2022, remove and reserve §§ 80.22, 80.23, and 80.26 through 80.33.

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

19. Effective January 1, 2022, remove and reserve subparts D through L, N, and O and appendices A and B to Part 80.

Subpart M—Renewable Fuel Standard

§ 80.1400

[Amended]

20. Amend § 80.1400 by removing the second sentence of the introductory text.

21. Amend § 80.1401 by:

a. Revising the definition of “Certified non-transportation 15 ppm distillate fuel”;

b. In paragraph (2) in the definition of “Fuel for use in an ocean-going vessel”, removing “§§ 80.2(ttt) and 80.510(k)” and adding “§ 80.2 and 40 CFR 1090.80” in its place;

c. In paragraph (1) in the definition of “Heating oil”, removing “§ 80.2(ccc)” and adding “§ 80.2” in its place;

d. In the definition of “Renewable gasoline”, removing “§ 80.2(c)” and adding “§ 80.2” in its place; and

e. In the definition of “Renewable gasoline blendstock”, removing “§ 80.2(s)” and adding “§ 80.2” in its place. The revision reads as follows:

§ 80.1401

Definitions.

* * * * *

Certified non-transportation 15 ppm distillate fuel or certified NTDF means distillate fuel that meets all the following:

(1) The fuel has been certified under 40 CFR 1090.1000 as meeting the ULSD standards in 40 CFR 1090.305.

(2) The fuel has been designated under 40 CFR 1090.1015 as certified NTDF.

(3) The fuel has also been designated under 40 CFR 1090.1015 as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non-transportation fuel (e.g., jet fuel, kerosene, or distillate global marine fuel).

(4) The fuel has not been designated under 40 CFR 1090.1015 as ULSD or 15 ppm MVNRLM diesel fuel.

(5) The PTD for the fuel meets the requirements in § 80.1453(e).

* * * * *

22. Amend § 80.1407 by:

a. In paragraph (e), removing “§ 80.2(qqq)” and adding “§ 80.2” in its place; and

b. Revising paragraph (f)(7).

The revision reads as follows:

§ 80.1407

How are the Renewable Volume Obligations calculated?

* * * * *

(f) * * *

(7) Transmix gasoline product (as defined in 40 CFR 1090.80) and transmix distillate product (as defined in 40 CFR 1090.80) produced by a transmix processor, and transmix blended into gasoline or diesel fuel by a transmix blender under 40 CFR 1090.500.

* * * * *

§ 80.1416

[Amended]

23. In § 80.1416, amend paragraph (b)(1)(i) by removing “§ 80.76” and adding “ 40 CFR 1090.805” in its place.

§ 80.1427

[Amended]

24. Amend § 80.1427 by:

a. In paragraph (a)(2) introductory text, removing “Except as described in paragraph (a)(4) of this section,”; and

b. Removing and reserving paragraph (a)(4).

§ 80.1429

[Amended]

25. Amend § 80.1429 by:

a. In paragraph (b)(9) introductory text, removing “RBOB, or CBOB” and adding “or BOB” in its place; and

b. Removing paragraphs (f) and (g).

§ 80.1440

[Amended]

26. In § 80.1440, amend paragraph (a)(2) by removing “any other subpart of 40 CFR part 80 (e.g., §§ 80.606, 80.1655)” and adding “40 CFR 1090.605” in its place.

§ 80.1441

[Amended]

27. Amend § 80.1441 by removing paragraphs (a)(6) and (b)(4).

§ 80.1442

[Amended]

28. Amend § 80.1442 by removing paragraphs (a)(3) and (b)(6).

§ 80.1450

[Amended]

29. Amend § 80.1450 by:

a. In paragraphs (a), (b) introductory text, and (c), removing “§ 80.76” and adding “ 40 CFR 1090.805” in its place;

b. In paragraph (d)(3)(iii), removing “§ 80.127” and adding “ 40 CFR 1090.1805” in its place; and

c. In paragraphs (e) and (g)(1), removing “§ 80.76” and adding “ 40 CFR 1090.805” in its place.

§ 80.1453

[Amended]

30. In § 80.1453, amend paragraph (e)(1) by removing “§ 80.590” and adding “ 40 CFR 1090.1115” in its place.

§ 80.1454

[Amended]

31. In § 80.1454, amend paragraph (h)(2)(i) by removing “§ 80.68(c)(13)(i)” and adding “ 40 CFR 1090.55” in its place.

§ 80.1464

[Amended]

32. Amend § 80.1464 by:

a. In the introductory text, removing “§§ 80.125 through 80.127, and 80.130,” and adding “ 40 CFR 1090.1800” in its place;

b. In paragraph (a)(1)(iii), removing “§ 80.133” and adding “ 40 CFR 1090.1810” in its place; and

c. In paragraphs (a)(1)(iv)(D), (a)(2)(i), (b)(1)(iv), (b)(1)(v)(A), (b)(2)(i), and (c)(1)(i), removing “§ 80.127” and adding “ 40 CFR 1090.1805” in its place.

§ 80.1465

[Removed and reserved]

33. Remove and reserve § 80.1465.

§ 80.1466

[Amended]

34. Amend § 80.1466 by:

a. In paragraph (d)(3)(ii), removing “§ 80.65(f)(2)(iii)” and adding “ 40 CFR 1090.1805” in its place;

b. In paragraphs (m)(3) introductory text, (m)(4) introductory text, and (m)(5), removing “§ 80.127” and adding “ 40 CFR 1090.1805” in its place; and

c. In paragraphs (m)(6)(ii) and (iii), removing “§§ 80.125 through 80.127, 80.130” and adding “ 40 CFR 1090.1800” in its place.

§ 80.1467

[Amended]

35. In § 80.1467, amend paragraphs (h)(2) and (3) by removing “§§ 80.125 through 80.127, 80.130,” and adding “ 40 CFR 1090.1800” in its place.

* * * * *

§ 80.1469

[Amended]

36. In § 80.1469, amend paragraph (c)(5) by removing “§ 80.127” and adding “ 40 CFR 1090.1805” in its place.

§ 80.1475

[Amended]

37. In § 80.1475, amend paragraph (d)(4)(ii) by removing “§ 80.590” and adding “ 40 CFR 1090.1115” in its place.

PART 1042—CONTROL OF EMISSIONS FROM NEW AND IN-USE MARINE COMPRESSION-IGNITION ENGINES AND VESSELS

38. The authority citation for part 1042 continues to read as follows:

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

Subpart G—Special Compliance Provisions

§ 1042.660

[Amended]

39. In § 1042.660, amend paragraph (a) by removing “ 40 CFR part 80” and adding “40 CFR part 1090” in its place.

Subpart J—Definitions and Other Reference Information

§ 1042.901

[Amended]

40. In § 1042.901, amend the definition of “Diesel fuel” by removing “ 40 CFR 80.2” and adding “40 CFR 1090.80” in its place.

PART 1043— CONTROL OF NOX, SOX, AND PM EMISSIONS FROM MARINE ENGINES AND VESSELS SUBJECT TO THE MARPOL PROTOCOL

41. The authority citation for part 1043 continues to read as follows:

Authority: 33 U.S.C. 1901-1912.

§ 1043.1

[Amended]

42. In § 1043.1, amend paragraph (f) by removing “ 40 CFR part 80” and adding “40 CFR part 1090” in its place.

§ 1043.60

[Amended]

43. In § 1043.60, amend paragraphs (d) and (e) by removing “ 40 CFR part 80” and adding “40 CFR part 1090” in its place.

§ 1043.70

[Amended]

44. In § 1043.70, amend paragraphs (c) and (d) by removing “ 40 CFR part 80” and adding “40 CFR part 1090” in its place.

§ 1043.80

[Amended]

45. In § 1043.80, amend paragraph (b)(5) by removing “ 40 CFR part 80” and adding “40 CFR part 1090” in its place.

PART 1065—ENGINE-TESTING PROCEDURES

46. The authority citation for part 1065 continues to read as follows:

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

Subpart H—Engine Fluids, Test Fuels, Analytical Gases and Other Calibration Standards

47. Amend § 1065.701 by revising paragraph (d)(2) to read as follows:

§ 1065.701

General requirements for test fuels.

* * * * *

(d) * * *

(2) The fuel parameters specified in this subpart depend on measurement procedures that are incorporated by reference. For any of these procedures, you may instead rely upon the procedures identified in 40 CFR part 1090 for measuring the same parameter. For example, we may identify different reference procedures for measuring gasoline parameters in 40 CFR 1090.1360.

* * * * *

48. Effective December 4, 2020, amend § 1065.703 by revising Table 1 of § 1065.703 to read as follows:

§ 1065.703

Distillate diesel fuel.

* * * * *

Table 1 of § 1065.703—Test Fuel Specifications for Distillate Diesel Fuel

Property	Unit	Ultra low sulfur	Low sulfur	High sulfur	Reference procedure a
Cetane Number		40-50	40-50	40-50	ASTM D613
Distillation range:
Initial boiling point 10 pct. point 50 pct. point 90 pct. point Endpoint	°C	171-204 204-238 243-282 293-332 321-366	171-204 204-238 243-282 293-332 321-366	171-204 204-238 243-282 293-332 321-366	ASTM D86
Gravity	°API	32-37	32-37	32-37	ASTM D4052
Total sulfur	mg/kg	7-15	300-500	800-2500	ASTM D2622, ASTM D5453, or ASTM D7039
Aromatics, min. (Remainder shall be paraffins, naphthenes, and olefins)	g/kg	100	100	100	ASTM D5186
Flashpoint, min.	°C	54	54	54	ASTM D93
Kinematic Viscosity	mm2/s	2.0-3.2	2.0-3.2	2.0-3.2	ASTM D445
a Incorporated by reference, see § 1065.1010. See § 1065.701(d) for other allowed procedures.

* * * * *

§ 1065.705

[Amended]

49. In § 1065.705, amend the introductory text by removing “ 40 CFR 80.2” and adding “40 CFR 1090.80” in its place.

§ 1065.725

[Amended]

50. In § 1065.725, amend paragraph (c) by removing “denatured ethanol meeting the specifications in 40 CFR 80.1610” and adding “denatured fuel ethanol meeting the specifications in 40 CFR 1090.270” in its place.

Subpart K—Definitions and Other Reference Information

51. Effective December 4, 2020, amend § 1065.1010 by revising the last sentence of paragraph (a) and paragraphs (b)(19), (35), and (46) to read as follows:

§ 1065.1010

Incorporation by reference.

(a) * * * For information on the availability of this material at NARA, email [e-mail] or go to www.archives.gov/​federal-register/​cfr/​ibr-locations.html.

(b) * * *

(19) ASTM D2622-16, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, approved January 1, 2016 (“ASTM D2622”), IBR approved for §§ 1065.703(b) and 1065.710(b) and (c).

* * * * *

(35) ASTM D5453-19a, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved July 1, 2019 (“ASTM D5453”), IBR approved for §§ 1065.703(b) and 1065.710(b).

* * * * *

(46) ASTM D7039-15a (Reapproved 2020), Standard Test Method for Sulfur in Gasoline, Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray Fluorescence Spectrometry, approved May 1, 2020 (“ASTM D7039”), IBR approved for §§ 1065.703(b) and 1065.710(b).

* * * * *

52. Effective December 4, 2020, add part 1090 to read as follows:

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

Subpart A—General Provisions

1090.1

Applicability and relationship to other parts.

1090.5

Implementation dates.

1090.10

Contacting EPA.

1090.15

Confidential business information.

1090.20

Approval of submissions under this part.

1090.50

Rounding.

1090.55

Requirements for independent parties.

1090.80

Definitions.

1090.85

Explanatory terms.

1090.90

Acronyms and abbreviations.

1090.95

Incorporation by reference.

Subpart B—General Requirements and Provisions for Regulated Parties

1090.100

General provisions.

1090.105

Fuel manufacturers.

1090.110

Detergent blenders.

1090.115

Oxygenate blenders.

1090.120

Oxygenate producers.

1090.125

Certified butane producers.

1090.130

Certified butane blenders.

1090.135

Certified pentane producers.

1090.140

Certified pentane blenders.

1090.145

Transmix processors.

1090.150

Transmix blenders.

1090.155

Fuel additive manufacturers.

1090.160

Distributors, carriers, and resellers.

1090.165

Retailers and WPCs.

1090.170

Independent surveyors.

1090.175

Auditors.

1090.180

Pipeline operators.

Subpart C—Gasoline Standards

1090.200

Overview and general requirements.

1090.205

Sulfur standards.

1090.210

Benzene standards.

1090.215

Gasoline RVP standards.

1090.220

RFG standards.

1090.225

Anti-dumping standards.

1090.230

Limitation on use of gasoline-ethanol blends.

1090.250

Certified butane standards.

1090.255

Certified pentane standards.

1090.260

Gasoline deposit control standards.

1090.265

Gasoline additive standards.

1090.270

Gasoline oxygenate standards.

1090.275

Ethanol denaturant standards.

1090.285

RFG covered areas.

1090.290

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

1090.295

Procedures for relaxing the federal 7.8 psi RVP standard.

Subpart D—Diesel Fuel and ECA Marine Fuel Standards

1090.300

Overview and general requirements.

1090.305

ULSD standards.

1090.310

Diesel fuel additives standards.

1090.315

Heating oil, kerosene, ECA marine fuel, and jet fuel provisions.

1090.320

500 ppm LM diesel fuel standards.

1090.325

ECA marine fuel standards.

Subpart E—Reserved Subpart F—Transmix and Pipeline Interface Provisions

1090.500

Gasoline produced from blending transmix into PCG.

1090.505

Gasoline produced from TGP.

1090.510

Diesel and distillate fuel produced from TDP.

1090.515

500 ppm LM diesel fuel produced from TDP.

1090.520

Handling practices for pipeline interface that is not transmix.

Subpart G—Exemptions, Hardships, and Special Provisions

1090.600

General provisions.

1090.605

National security and military use exemptions.

1090.610

Temporary research, development, and testing exemptions.

1090.615

Racing and aviation exemptions.

1090.620

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

1090.625

Exemptions for California gasoline and diesel fuel.

1090.630

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

1090.635

Refinery extreme unforeseen hardship exemption.

1090.640

Exemptions from the gasoline deposit control requirements.

1090.645

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

1090.650

Distillate global marine fuel exemption.

Subpart H—Averaging, Banking, and Trading Provisions

1090.700

Compliance with average standards.

1090.705

Facility level compliance.

1090.710

Downstream oxygenate accounting.

1090.715

Deficit carryforward.

1090.720

Credit use.

1090.725

Credit generation.

1090.730

Credit transfers.

1090.735

Invalid credits and remedial actions.

1090.740

Downstream BOB recertification.

1090.745

Informational annual average calculations.

Subpart I—Registration

1090.800

General provisions.

1090.805

Contents of registration.

1090.810

Voluntary cancellation of company or facility registration.

1090.815

Deactivation (involuntary cancellation) of registration.

1090.820

Changes of ownership.

Subpart J—Reporting

1090.900

General provisions.

1090.905

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

1090.910

Reporting for gasoline manufacturers that recertify BOB to gasoline.

1090.915

Batch reporting for oxygenate producers and importers.

1090.920

Reports by certified pentane producers.

1090.925

Reports by independent surveyors.

1090.930

Reports by auditors.

1090.935

Reports by diesel fuel manufacturers.

Subpart K—Batch Certification and Designation

1090.1000

Batch certification requirements.

1090.1005

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

1090.1010

Designation requirements for gasoline and regulated blendstocks.

1090.1015

Designation requirements for diesel and distillate fuels.

1090.1020

Batch numbering.

Subpart L—Product Transfer Documents

1090.1100

General requirements.

1090.1105

PTD requirements for exempt fuels.

1090.1110

PTD requirements for gasoline, gasoline additives, and gasoline regulated blendstocks.

1090.1115

PTD requirements for distillate and residual fuels.

1090.1120

PTD requirements for diesel fuel additives.

1090.1125

Alternative PTD language.

Subpart M—Recordkeeping

1090.1200

General recordkeeping requirements.

1090.1205

Recordkeeping requirements for all regulated parties.

1090.1210

Recordkeeping requirements for gasoline manufacturers.

1090.1215

Recordkeeping requirements for diesel fuel, ECA marine fuel, and distillate global marine fuel manufacturers.

1090.1220

Recordkeeping requirements for oxygenate blenders.

1090.1225

Recordkeeping requirements for gasoline additives.

1090.1230

Recordkeeping requirements for oxygenate producers.

1090.1235

Recordkeeping requirements for ethanol denaturant.

1090.1240

Recordkeeping requirements for gasoline detergent blenders.

1090.1245

Recordkeeping requirements for independent surveyors.

1090.1250

Recordkeeping requirements for auditors.

1090.1255

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

Subpart N—Sampling, Testing, and Retention

1090.1300

General provisions.

Scope of Testing

1090.1310

Testing to demonstrate compliance with standards.

1090.1315

In-line blending.

1090.1320

Adding blendstock to PCG.

1090.1325

Adding blendstock or PCG to TGP.

1090.1330

Preparing denatured fuel ethanol.

Handling and Preparing Samples

1090.1335

Collecting, preparing, and testing samples.

1090.1337

Demonstrating homogeneity.

1090.1340

Preparing a hand blend from BOB.

1090.1345

Retaining samples.

Measurement Procedures

1090.1350

Overview of test procedures.

1090.1355

Calculation adjustments and corrections.

1090.1360

Performance-based Measurement System.

1090.1365

Qualifying criteria for alternative measurement procedures.

1090.1370

Qualifying criteria for reference installations.

1090.1375

Quality control procedures.

Testing Related to Gasoline Deposit Control

1090.1390

Requirement for Automated Detergent Blending Equipment Calibration.

1090.1395

Gasoline deposit control test procedures.

Subpart O—Survey Provisions

1090.1400

General provisions.

1090.1405

National fuels survey program.

1090.1410

Independent surveyor requirements.

1090.1415

Survey program plan design requirements.

1090.1420

Additional requirements for E15 misfueling mitigation surveying.

1090.1450

National sampling and testing oversight program.

Subpart P—Retailer and Wholesale Purchaser-Consumer Provisions

1090.1500

Overview.

Labeling

1090.1510

E15 labeling provisions.

1090.1515

Diesel sulfur labeling provisions.

Refueling Hardware

1090.1550

Requirements for gasoline dispensing nozzles used with motor vehicles.

1090.1555

Requirements for gasoline dispensing nozzles used primarily with marine vessels.

1090.1560

Requirements related to dispensing natural gas.

1090.1565

Requirements related to dispensing liquefied petroleum gas.

Subpart Q—Importer and Exporter Provisions

1090.1600

General provisions for importers.

1090.1605

Importation by marine vessel.

1090.1610

Importation by rail or truck.

1090.1615

Gasoline treated as a blendstock.

1090.1650

General provisions for exporters.

Subpart R—Compliance and Enforcement Provisions

1090.1700

Prohibited acts.

1090.1705

Evidence related to violations.

1090.1710

Penalties.

1090.1715

Liability provisions.

1090.1720

Affirmative defense provisions.

Subpart S—Attestation Engagements

1090.1800

General provisions.

1090.1805

Representative samples.

1090.1810

General procedures for gasoline manufacturers.

1090.1815

General procedures for gasoline importers.

1090.1820

Additional procedures for gasoline treated as blendstock.

1090.1825

Additional procedures for PCG used to produce gasoline.

1090.1830

Alternative procedures for certified butane blenders.

1090.1835

Alternative procedures for certified pentane blenders.

1090.1840

Additional procedures related to compliance with gasoline average standards.

1090.1845

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

1090.1850

Procedures related to in-line blending waivers.

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

Subpart A—General Provisions

§ 1090.1

Applicability and relationship to other parts.

(a) This part specifies fuel quality standards for gasoline and diesel fuel introduced into commerce in the United States. Additional requirements apply for fuel used in certain marine applications, as specified in paragraph (b) of this section.

(1) The regulations include standards for fuel parameters that directly or indirectly affect vehicle, engine, and equipment emissions, air quality, and public health. The regulations also include standards and requirements for fuel additives and regulated blendstocks that are components of the fuels regulated under this part.

(2) This part also specifies requirements for any person that engages in activities associated with the production, distribution, storage, and sale of fuels, fuel additives, and regulated blendstocks, such as collecting and testing samples for regulated parameters, reporting information to EPA to demonstrate compliance with fuel quality requirements, and performing other compliance measures to implement the standards. A party that produces and distributes other related products, such as heating oil, may need to meet certain reporting, recordkeeping, labeling, or other requirements of this part.

(b)(1) The International Convention for the Prevention of Pollution from Ships, 1973 as modified by the Protocol of 1978 Annex VI (“MARPOL Annex VI”) is an international treaty that sets maximum sulfur content for fuel used in marine vessels, including separate standards for marine vessels navigating in a designated Emission Control Area (ECA). These standards and related requirements are specified in 40 CFR part 1043. This part also sets corresponding sulfur standards that apply to any person who produces or handles ECA marine fuel.

(2) This part also includes requirements for parties involved in the production and distribution of IMO marine fuel, such as collecting and testing samples of fuels for regulated parameters, reporting information to EPA to demonstrate compliance with fuel quality requirements, and performing other compliance measures to implement the standards.

(c) The requirements for the registration of fuel and fuel additives under 42 U.S.C. 7545(a), (b), and (e) are specified in 40 CFR part 79. A party that must meet the requirements of this part may also need to comply with the requirements for the registration of fuel and fuel additives under 40 CFR part 79.

(d) The requirements for the Renewable Fuel Standard (RFS) are specified in 40 CFR part 80, subpart M. A party that must meet the requirements of this part may also need to comply with the requirements for the RFS program under 40 CFR part 80, subpart M.

(e) Nothing in this part is intended to preempt the ability of state or local governments to control or prohibit any fuel or fuel additive for use in motor vehicles and motor vehicle engines that is not explicitly regulated by this part.

§ 1090.5

Implementation dates.

(a) The provisions of this part apply beginning January 1, 2021, unless otherwise specified.

(b) The following provisions of 40 CFR part 80 are applicable after December 31, 2020:

(1) Gasoline sulfur and benzene credit balances and deficits from the 2020 compliance period carry forward for demonstrating compliance with requirements of this part. Any restrictions that apply to credits and deficits under 40 CFR part 80, such as a maximum credit life of 5 years, continue to apply under this part.

(2) Unless otherwise specified (e.g., in-line blending waivers for gasoline as specified in paragraph (b)(8) of this section), any approval granted under 40 CFR part 80 continues to be in effect under this part. For example, if EPA approved the use of an alternative label under 40 CFR part 80, that approval continues to be valid under this part, subject to any conditions specified for the approval.

(3) Unless otherwise specified, a regulated party must use the provisions of 40 CFR part 80 in 2021 to demonstrate compliance with regulatory requirements for the 2020 calendar year. This applies to calculating credits for the 2020 compliance period, and to any sampling, testing, reporting, and auditing related to fuels, fuel additives, and regulated blendstocks produced or imported in 2020.

(4) Any testing to establish the precision and accuracy of alternative test procedures under 40 CFR part 80 continues to be valid under this part.

(5) Requirements to keep records and retain fuel samples related to actions taken before January 1, 2021, continue to be in effect, as specified in 40 CFR part 80.

(6) A party may comply with the PTD requirements of 40 CFR part 80 instead of the requirements of subpart L of this part until May 1, 2021.

(7) A party may comply with the automatic sampling provisions of 40 CFR 80.8 instead of the requirements in § 1090.1335(c) until January 1, 2022.

(8) A gasoline manufacturer may operate under an in-line blending waiver issued under 40 CFR part 80 until January 1, 2022, or until EPA approves a revised in-line blending waiver under § 1090.1315, whichever is earlier. The following provisions apply:

(i) A gasoline manufacturer operating under an in-line blending waiver under 40 CFR 80.65 must monitor and test for sulfur content, benzene content, and for summer gasoline, RVP, and may discontinue monitoring and testing for other properties that are included in their in-line blending waiver.

(ii) The auditing requirements in § 1090.1850 do not apply to an in-line blending waiver issued under 40 CFR part 80.

(c) The following requirements apply for the 2021 compliance period:

(1) The NSTOP specified in § 1090.1450 must begin no later than June 1, 2021.

(2) A gasoline manufacturer that accounts for oxygenate added downstream under § 1090.710 is deemed compliant with the requirement to participate in the NSTOP specified in § 1090.710(a)(3) until June 1, 2021, if the gasoline manufacturer meets all other applicable requirements specified in § 1090.710.

(3) The independent surveyor conducting the NSTOP must submit the proof of contract required under § 1090.1400(b) no later than April 15, 2021.

(4) The independent surveyor may collect only one summer or winter gasoline sample for each participating fuel manufacturing facility instead of the minimum two samples required under § 1090.1450(c)(2)(i).

§ 1090.10

Contacting EPA.

A party must submit all reports, registrations, and documents for approval required under this part electronically to EPA using forms and procedures specified by EPA via the following website: https://www.epa.gov/​fuels-registration-reporting-and-compliance-help.

§ 1090.15

Confidential business information.

(a) Except as specified in paragraphs (b) and (c) of this section, any information submitted under this part claimed as confidential remains subject to evaluation by EPA under 40 CFR part 2, subpart B.

(b) The following information contained in submissions under this part is not entitled to confidential treatment under 40 CFR part 2, subpart B or 5 U.S.C. 552(b)(4):

(1) Submitter's name.

(2) The name and location of the facility, if applicable.

(3) The general nature of a request.

(4) The relevant time period for a request, if applicable.

(c) The following information incorporated into EPA determinations on submissions under this section is not entitled to confidential treatment under 40 CFR part 2, subpart B or 5 U.S.C. 552(b)(4):

(1) Submitter's name.

(2) The name and location of the facility, if applicable.

(3) The general nature of a request.

(4) The relevant time period for a request, if applicable.

(5) The extent to which EPA either granted or denied the request and any relevant terms and conditions.

(d) EPA may disclose the information specified in paragraphs (b) and (c) of this section on its website, or otherwise make it available to interested parties, without additional notice, notwithstanding any claims that the information is entitled to confidential treatment under 40 CFR part 2, subpart B and 5 U.S.C. 552(b)(4).

§ 1090.20

Approval of submissions under this part.

(a) EPA may approve any submission required or allowed under this part if the request for approval satisfies all specified requirements.

(b) EPA may impose terms and conditions on any approval of any submission required or allowed under this part.

(c) EPA will deny any request for approval if the submission is incomplete, contains inaccurate or misleading information, or does not meet all specified requirements.

(d) EPA may revoke any prior approval under this part for cause. For cause includes, but is not limited to, any of the following:

(1) The approval has proved inadequate in practice.

(2) The party fails to notify EPA if information that the approval was based on substantively changed after the approval was granted.

(e) EPA may also revoke and void any approval under this part effective from the approval date for cause. Cause for voiding an approval includes, but is not limited to, any of the following:

(1) The approval was not fully or diligently implemented.

(2) The approval was based on false, misleading, or inaccurate information.

(3) Failure of a party to fulfill or cause to be fulfilled any term or condition of an approval under this part.

(f) Any person that has an approval revoked or voided under this part is liable for any resulting violation of the requirements of this part.

§ 1090.50

Rounding.

(a) Unless otherwise specified, round values to the number of significant digits necessary to match the number of decimal places of the applicable standard or specification. Perform all rounding as specified in 40 CFR 1065.20(e)(1) through (6). This convention is consistent with ASTM E29 and NIST SP 811.

(b) Do not round intermediate values to transfer data unless the rounded number has at least 6 significant digits.

(c) When calculating a specified percentage of a given value, the specified percentage is understood to have infinite precision. For example, if an allowable limit is specified as a fuel volume representing 1 percent of total volume produced, calculate the allowable volume by multiplying total volume by exactly 0.01.

(d) Measurement devices that incorporate internal rounding may be used, consistent with the following provisions:

(1) Devices may use any rounding convention if they report 6 or more significant digits.

(2) Devices that report fewer than 6 significant digits may be used, consistent with the accuracy and repeatability specifications of the procedures specified in subpart N of this part.

(e) Use one of the following rounding conventions for all batch volumes in a given compliance period, and for all reporting under this part:

(1) Identify batch volume in gallons to the nearest whole gallon.

(2)(i) Round batch volumes between 1,000 and 11,000 gallons to the nearest 10 gallons.

(ii) Round batch volumes above 11,000 gallons to the nearest 100 gallons.

§ 1090.55

Requirements for independent parties.

This section specifies how a third party demonstrates their independence from the regulated party that hires them and their technical ability to perform the specified services.

(a) Independence. The independent third party, their contractors, subcontractors, and their organizations must be independent of the regulated party. All the criteria listed in paragraphs (a)(1) and (2) of this section must be met by each person involved in the specified activities in this part that the independent third party is hired to perform for a regulated party, except that an internal auditor may instead meet the requirements in § 1090.1800(b)(1)(i).

(1) Employment criteria. No person employed by an independent third party, including contractor and subcontractor personnel, who is involved in a specified activity performed by the independent third party under the provisions of this part, may be employed, currently or previously, by the regulated party for any duration within the 12 months preceding the date when the regulated party hired the independent third party to provide services under this part.

(2) Financial criteria. (i) The third-party's personnel, the third-party's organization, or any organization or individual that may be contracted or subcontracted by the third party must meet all the following requirements:

(A) Have received no more than one-quarter of their revenue from the regulated party during the year prior to the date of hire of the third party by the regulated party for any purpose.

(B) Have no interest in the regulated party's business. Income received from the third party to perform specified activities under this part is excepted.

(C) Not receive compensation for any specified activity in this part that is dependent on the outcome of the specified activity.

(ii) The regulated party must be free from any interest in the third-party's business.

(b) Technical ability. The third party must meet all the following requirements in order to demonstrate their technical capability to perform specified activities under this part:

(1) An independent surveyor that conducts a survey under subpart O of this part must have personnel familiar with petroleum marketing, the sampling and testing of gasoline and diesel fuel at retail stations, and the designing of surveys to estimate compliance rates for fuel parameters nationwide. The independent surveyor must demonstrate this technical ability in plans submitted under subpart O of this part.

(2) A laboratory attempting to qualify alternative procedures must contract with an independent third party to verify the accuracy and precision of measured values as specified in § 1090.1365. The independent third party must demonstrate work experience and a good working knowledge of the VCSB methods specified in §§ 1090.1365 and 1090.1370, with training and expertise corresponding to a bachelor's degree in chemical engineering, or combined bachelor's degrees in chemistry and statistics.

(3) Any person auditing in-line blending operations must demonstrate work experience and be proficient in the VCSB methods specified in §§ 1090.1365 and 1090.1370.

(c) Suspension and disbarment. Any person suspended or disbarred under 40 CFR part 32 or 48 CFR part 9, subpart 9.4, is not qualified to perform review functions under this part.

§ 1090.80

Definitions.

500 ppm LM diesel fuel means diesel fuel subject to the alternative sulfur standards in § 1090.320 that is produced by a transmix processor under § 1090.515.

Additization means the addition of detergent to gasoline to create detergent-additized gasoline.

Aggregated import facility means all import facilities within a PADD owned or operated by an importer and treated as a single fuel manufacturing facility in order to comply with the maximum benzene average standards under § 1090.210(b).

Anhydrous ethanol means ethanol that contains no more than 1.0 volume percent water.

Auditor means any person that conducts audits under subpart S of this part.

Automated detergent blending facility means any facility (including, but not limited to, a truck or individual storage tank) at which detergents are blended with gasoline by means of an injector system calibrated to automatically deliver a specified amount of detergent.

Average standard means a fuel standard applicable over a compliance period.

Batch means a quantity of fuel, fuel additive, or regulated blendstock that has a homogeneous set of properties. This also includes fuel, fuel additive, or regulated blendstock for which homogeneity testing is not required under § 1090.1337(a).

Biodiesel means a diesel fuel composed of mono-alkyl esters made from nonpetroleum feedstocks.

Blender pump means any fuel dispenser where PCG is blended with E85 (made only with PCG and DFE) or DFE to produce gasoline that has an ethanol content greater than that of the PCG. A fuel dispenser that produces gasoline with anything other than PCG and DFE (e.g., natural gas liquids) is a fuel blending facility.

Blending manufacturer means any person who owns, leases, operates, controls, or supervises a fuel blending facility in the United States.

Blendstock means any liquid compound or mixture of compounds (not including fuel or fuel additive) that is used or intended for use as a component of a fuel.

Business day means Monday through Friday, except the legal public holidays specified in 5 U.S.C. 6103 or any other day declared to be a holiday by federal statute or executive order.

Butane means an organic compound with the formula C₄ H_10.

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) that meets the definition of “Category 1” in 40 CFR part 1042.901.

Category 2 (C2) marine vessel means a vessel that is propelled by an engine(s) that meets the definition of “Category 2” in 40 CFR part 1042.901.

Category 3 (C3) marine vessel means a vessel that is propelled by an engine(s) that meets the definition of “Category 3” in 40 CFR part 1042.901.

CBOB means a BOB produced or imported for use outside of an RFG covered area.

Certified butane means butane that is certified to meet the requirements in § 1090.250.

Certified butane blender means a blending manufacturer that produces gasoline by blending certified butane into PCG and that uses the provisions of § 1090.1320(b) to meet the applicable sampling and testing requirements.

Certified butane producer means a regulated blendstock producer that certifies butane as meeting the requirements in § 1090.250.

Certified ethanol denaturant means ethanol denaturant that is certified to meet the requirements in § 1090.275.

Certified ethanol denaturant producer means any person that certifies ethanol denaturant as meeting the requirements in § 1090.275.

Certified non-transportation 15 ppm distillate fuel or certified NTDF has the meaning given in 40 CFR 80.1401.

Certified pentane means pentane that is certified to meet the requirements in § 1090.255.

Certified pentane blender means a blending manufacturer that produces gasoline by blending certified pentane into PCG and that uses the provisions of § 1090.1320 to meet the applicable sampling and testing requirements.

Certified pentane producer means a regulated blendstock producer that certifies pentane as meeting the requirements in § 1090.255.

Compliance period means the calendar year (January 1 through December 31).

Conventional gasoline (CG) means gasoline that is not certified to meet the requirements for RFG in § 1090.220.

Crosscheck program means an arrangement for laboratories to perform measurements from test samples prepared from a single homogeneous fuel batch to establish an accepted reference value for evaluating accuracy of individual laboratories and measurement systems.

Days means calendar days, including weekends and holidays.

Denatured fuel ethanol (DFE) means anhydrous ethanol that contains a denaturant to make it unfit for human consumption, that is produced or imported for use in gasoline, and that meets the standards and requirements in § 1090.270.

Detergent means any chemical compound or combination of chemical compounds that is added to gasoline to control deposit formation and meets the requirements in § 1090.260. Detergent may be part of a detergent additive package.

Detergent additive package means an additive package containing detergent and may also contain carrier oils and non-detergent-active components such as corrosion inhibitors, antioxidants, metal deactivators, and handling solvents.

Detergent blender means any person who owns, leases, operates, controls, or supervises the blending operation of a detergent blending facility, or imports detergent-additized gasoline.

Detergent blending facility means any facility (including, but not limited to, a truck or individual storage tank) at which detergent is blended with gasoline.

Detergent manufacturer means any person who owns, leases, operates, controls, or supervises a facility that produces detergent. A detergent manufacturer is a fuel additive manufacturer.

Detergent-additized gasoline or detergent gasoline means any gasoline that contains a detergent.

Diesel fuel means any of the following:

(1) Any fuel commonly or commercially known as diesel fuel.

(2) Any fuel (including NP diesel fuel or a fuel blend that contains NP diesel fuel) that is intended or used to power a vehicle or engine that is designed to operate using diesel fuel.

(3) Any fuel that conforms to the specifications of ASTM D975 (incorporated by reference in § 1090.95) and is made available for use in a vehicle or engine designed to operate using diesel fuel.

Diesel fuel manufacturer means a fuel manufacturer that owns, leases, operates, controls, or supervises a fuel manufacturing facility where diesel fuel is produced or imported.

Distillate fuel means diesel fuel and other petroleum fuels with a T90 temperature below 700 °F that can be used in vehicles or engines that are designed to operate using diesel fuel. For example, diesel fuel, jet fuel, heating oil, No. 1 fuel (kerosene), No. 4 fuel, DMX, DMA, DMB, and DMC are distillate fuels. These specific fuel grades are identified in ASTM D975 and ISO 8217. Natural gas, LPG, and gasoline are not distillate fuels. T90 temperature is based on the distillation test method specified in § 1090.1350.

Distributor means any person who transports, stores, or causes the transportation or storage of fuel, fuel additive, or regulated blendstock at any point between any fuel manufacturing facility, fuel additive manufacturing facility, or regulated blendstock production facility and any retail outlet or WPC facility.

Downstream location means any point in the fuel distribution system other than a fuel manufacturing facility through which the fuel passes after it leaves the fuel manufacturing facility gate at which it was certified (e.g., fuel at facilities of distributors, pipelines, terminals, carriers, retailers, oxygenate blenders, and WPCs).

E0 means gasoline that contains no ethanol. This is also known as neat gasoline.

E10 means gasoline that contains at least 9 and no more than 10 volume percent ethanol.

E15 means gasoline that contains more than 10 and no more than 15 volume percent ethanol.

E85 means a fuel that contains more than 50 volume percent but no more than 83 volume percent ethanol and is used, intended for use, or made available for use in flex-fuel vehicles or flex-fuel engines. E85 is not gasoline.

ECA marine fuel means diesel, distillate, or residual fuel used, intended for use, or made available for use in C3 marine vessels while the vessels are operating within an ECA, or an ECA associated area.

Ethanol means an alcohol of the chemical formula C₂ H₅ OH.

Ethanol denaturant means PCG, gasoline blendstocks, or natural gas liquids that are added to anhydrous ethanol to make the ethanol unfit for human consumption as required and defined in 27 CFR parts 19 through 21.

Facility means any place, or series of places, where any fuel, fuel additive, or regulated blendstock is produced, imported, blended, transported, distributed, stored, or sold.

Flex-fuel engine has the same meaning as flexible-fuel engine in 40 CFR 1054.801.

Flex-fuel vehicle has the same meaning as flexible-fuel vehicle in 40 CFR 86.1803-01.

Fuel means only the fuels regulated under this part.

Fuel additive means has the same meaning as additive in 40 CFR 79.2(e).

Fuel additive blender means any person who blends fuel additive into fuel in the United States, or any person who owns, leases, operates, controls, or supervises such an operation in the United States.

Fuel additive manufacturer means any person who owns, leases, operates, controls, or supervises a facility where fuel additives are produced or imported into the United States.

Fuel blending facility means any facility, other than a refinery or transmix processing facility, where fuel is produced by combining blendstocks or by combining blendstocks with fuel. Types of blending facilities include, but are not limited to, terminals, storage tanks, plants, tanker trucks, retail outlets, and marine vessels.

Fuel dispenser means any apparatus used to dispense fuel into motor vehicles, nonroad vehicles, engines, equipment, or portable fuel containers (as defined in 40 CFR 59.680).

Fuel manufacturer means any person who owns, leases, operates, controls, or supervises a fuel manufacturing facility. Fuel manufacturers include refiners, importers, blending manufacturers, and transmix processors.

Fuel manufacturing facility means any facility where fuels are produced, imported, or recertified. Fuel manufacturing facilities include refineries, fuel blending facilities, transmix processing facilities, import facilities, and any facility where fuel is recertified.

Fuel manufacturing facility gate means the point where the fuel leaves the fuel manufacturing facility at which the fuel manufacturer certified the fuel.

Gasoline means any of the following:

(1) Any fuel commonly or commercially known as gasoline, including BOB.

(2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline.

(3) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in § 1090.95) and is made available for use in a vehicle or engine designed to operate on gasoline.

Gasoline before oxygenate blending (BOB) means gasoline for which a gasoline manufacturer has accounted for oxygenate added downstream under § 1090.710. BOB is subject to all requirements and standards that apply to gasoline, unless subject to a specific alternative standard or requirement under this part.

Gasoline manufacturer means a fuel manufacturer that owns, leases, operates, controls, or supervises a fuel manufacturing facility where gasoline is produced, imported, or recertified.

Gasoline regulated blendstock means a regulated blendstock that is used or intended for use as a component of gasoline.

Gasoline treated as blendstock (GTAB) means a gasoline regulated blendstock that is imported and used to produce gasoline as specified in § 1090.1615.

Global marine fuel means diesel fuel, distillate fuel, or residual fuel used, intended for use, or made available for use in steamships or Category 3 marine vessels while the vessels are operating in international waters or in any waters outside the boundaries of an ECA. Global marine fuel is subject to the provisions of MARPOL Annex VI. (Note: This part regulates global marine fuel only if it qualifies as a distillate fuel.)

Heating oil means a combustible product that is used, intended for use, or made available for use in furnaces, boilers, or similar applications. Kerosene and jet fuel are not heating oil.

IMO marine fuel means fuel that is ECA marine fuel or global marine fuel.

Importer means any person who imports fuel, fuel additive, or regulated blendstock into the United States.

Import facility means any facility where an importer imports fuel, fuel additive, or regulated blendstock.

Independent surveyor means any person who meets the independence requirements in § 1090.55 and conducts a survey under subpart O of this part.

Intake valve deposits (IVD) means the deposits formed on the intake valve(s) of a gasoline-fueled engine during operation.

Jet fuel means any distillate fuel used, intended for use, or made available for use in aircraft.

Kerosene means any No. 1 distillate fuel that is used, intended for use, or made available for use as kerosene.

Liquefied petroleum gas (LPG) means a liquid hydrocarbon fuel that is stored under pressure and is composed primarily of compounds that are gases at atmospheric conditions (temperature = 25 °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 (CH₃ OH) by volume.

Natural gas means a fuel that is primarily composed of methane.

Natural gas liquids (NGLs) means natural gasoline or other mixtures of hydrocarbons (primarily but not limited to propane, butane, pentane, hexane, and heptane) that are separated from the gaseous state of natural gas in the form of liquids at a facility, such as a natural gas production facility, gas processing plant, natural gas pipeline, refinery, or similar facility.

Non-automated detergent blending facility means any facility (including a truck or individual storage tank) at which detergent additive is blended using a hand blending technique or any other non-automated method.

Nonpetroleum (NP) diesel fuel means renewable diesel fuel or biodiesel. NP diesel fuel also includes other renewable fuel under 40 CFR part 80, subpart M, that is used or intended for use to power a vehicle or engine that is designed to operate using diesel fuel or that is made available for use in a vehicle or engine designed to operate using diesel fuel.

Oxygenate means a liquid compound that consists of one or more oxygenated compounds. Examples include DFE and isobutanol.

Oxygenate blender means any person who adds oxygenate to gasoline in the United States, or any person who owns, leases, operates, controls, or supervises such an operation in the United States.

Oxygenate blending facility means any facility (including but not limited to a truck) at which oxygenate is added to gasoline (including BOB), and at which the quality or quantity of gasoline is not altered in any other manner except for the addition of deposit control additives.

Oxygenate import facility means any facility where oxygenate, including DFE, is imported into the United States.

Oxygenate producer means any person who produces or imports oxygenate for gasoline in the United States, or any person who owns, leases, operates, controls, or supervises an oxygenate production or import facility in the United States.

Oxygenate production facility means any facility where oxygenate is produced, including DFE.

Oxygenated compound means an oxygen-containing, ashless organic compound, such as an alcohol or ether, which may be used as a fuel or fuel additive.

PADD means Petroleum Administration for Defense District. These districts are the same as the PADDs used by other federal agencies, except for the addition of PADDs VI and VII. The individual PADDs are identified by region, state, and territory as follows:

PADD	Regional description	State or territory
I	East Coast	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 Territories	American Samoa, Guam, Northern Mariana Islands.

Pentane means an organic compound with the formula C₅ H_12.

Pentane blending facility means a fuel manufacturing facility where pentane is blended into PCG.

Per-gallon standard means the maximum or minimum value for any parameter that applies to every volume unit of a specified fuel, fuel additive, or regulated blendstock.

Person has the meaning given in 42 U.S.C. 7602(e).

Pipeline interface means the mixture between different fuels and products that abut each other during shipment by a refined petroleum products pipeline system.

Pipeline operator means any person who owns, leases, operates, controls, or supervises a pipeline that transports fuel, fuel additive, or regulated blendstock in the United States.

Previously certified gasoline (PCG) means CG, RFG, or BOB that has been certified as a batch by a gasoline manufacturer.

Product transfer documents (PTDs) mean documents that reflect the transfer of title or physical custody of fuel, fuel additive, or regulated blendstock (e.g., invoices, receipts, bills of lading, manifests, pipeline tickets) between a transferor and a transferee.

RBOB means a BOB produced or imported for use in an RFG covered area.

Refiner means any person who owns, leases, operates, controls, or supervises a refinery in the United States.

Refinery means a facility where fuels are produced from feedstocks, including crude oil or renewable feedstocks, through physical or chemical processing equipment.

Reformulated gasoline (RFG) means gasoline that is certified under § 1090.1000(b) and that meets each of the standards and requirements in § 1090.220.

Regulated blendstock means certified butane, certified pentane, TGP, TDP, and GTAB.

Regulated blendstock producer means any person who owns, leases, operates, controls, or supervises a facility where regulated blendstocks are produced or imported.

Renewable diesel fuel means diesel fuel that is made from renewable (nonpetroleum) feedstocks and is not a mono-alkyl ester.

Reseller means any person who purchases fuel identified by the corporate, trade, or brand name of a fuel manufacturer from such manufacturer or a distributor and resells or transfers it to a retailer or WPC, and whose assets or facilities are not substantially owned, leased, or controlled by such manufacturer.

Residual fuel means a petroleum fuel with a T90 temperature at or above 700 °F. For example, No. 5 fuels and No. 6 fuels are residual fuels. Residual fuel grades are specified in ASTM D396 and ISO 8217. T90 temperature is based on the distillation test method specified in § 1090.1350.

Responsible corporate officer (RCO) means a person who is authorized by the regulated party to make representations on behalf of, or obligate the company as ultimately responsible for, any activity regulated under this part (e.g., refining, importing, blending). An example is an officer of a corporation under the laws of incorporation of the state in which the company is incorporated. Examples of positions in non-corporate business structures that qualify are owner, chief executive officer, president, or operations manager.

Retail outlet means any establishment at which fuel is sold or offered for sale for use in motor vehicles, nonroad engines, nonroad vehicles, or nonroad equipment, including locomotive or marine engines.

Retailer means any person who owns, leases, operates, controls, or supervises a retail outlet.

RFG covered area means the geographic areas specified in § 1090.285 in which only RFG may be sold or dispensed to ultimate consumers.

RFG opt-in area means an area that becomes a covered area under 42 U.S.C. 7545(k)(6) as listed in § 1090.285.

Round (rounded, rounding) has the meaning given in § 1090.50.

Sampling strata means the three types of areas sampled during a survey, which include the following:

(1) Densely populated areas.

(2) Transportation corridors.

(3) Rural areas.

State Implementation Plan (SIP) means a plan approved or promulgated under 42 U.S.C. 7410 or 7502.

Summer gasoline means gasoline that is subject to the RVP standards in § 1090.215.

Summer season or high ozone season means the period from June 1 through September 15 for retailers and WPCs, and May 1 through September 15 for all other persons, or an RVP control period specified in a SIP if it is longer.

Tank truck means a truck used for transporting fuel, fuel additive, or regulated blendstock.

Transmix means any of the following mixtures of fuels, which no longer meet the specifications for a fuel that can be used or sold as a fuel without further processing:

(1) Pipeline interface that is not cut into the adjacent products.

(2) Mixtures produced by unintentionally combining gasoline and distillate fuels.

(3) Mixtures of gasoline and distillate fuel produced from normal business operations at terminals or pipelines, such as gasoline or distillate fuel drained from a tank or drained from piping or hoses used to transfer gasoline or distillate fuel to tanks or trucks, or gasoline or distillate fuel discharged from a safety relief valve that are segregated for further processing.

Transmix blender means any person who owns, leases, operates, controls, or supervises a transmix blending facility.

Transmix blending facility means any facility that produces gasoline by blending transmix into PCG under § 1090.500.

Transmix distillate product (TDP) means the diesel fuel blendstock that is produced when transmix is separated into blendstocks at a transmix processing facility.

Transmix gasoline product (TGP) means the gasoline blendstock that is produced when transmix is separated into blendstocks at a transmix processing facility.

Transmix processing facility means any facility that produces TGP or TDP from transmix by distillation or other refining processes, but does not produce gasoline or diesel fuel by processing crude oil or other products.

Transmix processor means any person who owns, leases, operates, controls, or supervises a transmix processing facility. A transmix processor is a fuel manufacturer.

Ultra low-sulfur diesel (ULSD) means diesel fuel that is certified to meet the standards in § 1090.305.

United States means the 50 states, the District of Columbia, the Commonwealth of Puerto Rico, the Commonwealth of the Northern Mariana Islands, Guam, American Samoa, and the U.S. Virgin Islands.

Volume Additive Reconciliation (VAR) Period means the following:

(1) For an automated detergent blending facility, the VAR period is a time period lasting no more than 31 days or until an adjustment to a detergent concentration rate that increases the initial rate by more than 10 percent, whichever occurs first. The concentration setting for a detergent injector may be adjusted by more than 10 percent above the initial rate without terminating the VAR Period, provided the purpose of the change is to correct a batch misadditization prior to the transfer of the batch to another party, or to correct an equipment malfunction and the concentration is immediately returned to no more than 10 percent above the initial rate of concentration after the correction.

(2) For a non-automated detergent blending facility, the VAR Period constitutes the blending of one batch of gasoline.

Voluntary consensus standards body (VCSB) means an organization that follows consistent protocols to adopt standards reflecting a wide range of input from interested parties. ASTM International and the International Organization for Standardization are examples of VCSB organizations.

Wholesale purchaser-consumer (WPC) means any person that is an ultimate consumer of fuels and who purchases or obtains fuels for use in motor vehicles, nonroad vehicles, nonroad engines, or nonroad equipment, including locomotive or marine engines, and, in the case of liquid fuels, receives delivery of that product into a storage tank of at least 550-gallon capacity substantially under the control of that person.

Winter gasoline means gasoline that is not subject to the RVP standards in § 1090.215.

Winter season means any duration outside of the summer season or high ozone season.

§ 1090.85

Explanatory terms.

This section explains how certain phrases and terms are used in this part, especially those used to clarify and explain regulatory provisions. They do not, however, constitute specific regulatory requirements and as such do not impose any compliance obligation on regulated parties.

(a) Types of provisions. The term “provision” includes all aspects of the regulations in this part. As specified in this section, regulatory provisions include standards, requirements, and prohibitions, along with a variety of other types of provisions.

(1) A standard is a limit on the formulation, components, or characteristics of any fuel, fuel additive, or regulated blendstock, established by regulation under this part. Compliance with or conformance to a standard is a specific type of requirement. Thus, a statement about the requirements of a part or section also applies with respect to the standards in the part or section. Examples of standards include the sulfur per-gallon standards for gasoline and diesel fuel.

(2) While requirements state what someone must do, prohibitions state what someone must not do. Failing to meet any requirement that applies to a person under this part is a prohibited act.

(3) The regulations in this part include provisions that are not standards, requirements, or prohibitions, such as definitions.

(b) Subject to. A fuel is considered “subject to” a specific provision if that provision applies, even if it falls within an exemption authorized under a different part of this regulation. For example, gasoline is subject to the provisions of this part even if it is exempt from the standards under subpart G of this part.

(c) Singular and plural. Unless stated otherwise or unless it is clear from the regulatory context, provisions written in singular form include the plural form and provisions written in plural form include the singular form.

(d) Inclusive lists. Lists in the regulations in this part prefaced by “including” or “this includes” are not exhaustive. The terms “including” and “this includes” should be read to mean “including but not limited to” and “this includes but is not limited to.”

(e) Notes. Statements that begin with “Note:” or “Note that” are intended to clarify specific regulatory provisions stated elsewhere in the regulations in this part. By themselves, such statements are not intended to specify regulatory requirements.

(f) Examples. Examples provided in the regulations in this part are typically introduced by either “for example” or “such as.” Specific examples given in the regulations do not necessarily represent the most common examples. The regulations may specify examples conditionally (that is, specifying that they are applicable only if certain criteria or conditions are met). Lists of examples are not exhaustive.

§ 1090.90

Acronyms and abbreviations.

500 ppm LM diesel fuel	As defined in § 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 § 1090.80.
E10	As defined in § 1090.80.
E15	As defined in § 1090.80.
ECA marine fuel	As defined in § 1090.80.
EPA	Environmental Protection Agency.
GTAB	gasoline treated as blendstock.
IMO marine fuel	As defined in § 1090.80.
LAC	lowest additive concentration.
LLOQ	laboratory limit of quantitation.
MARPOL Annex VI	The International Convention for the Prevention of Pollution from Ships, 1973 as modified by the Protocol of 1978 Annex VI.
NAAQS	National Ambient Air Quality Standard.
NARA	National Archives and Records Administration.
NFSP	national fuels survey program.
NGL	natural gas liquids.
NIST	National Institute for Standards and Technology.
NSTOP	national sampling and testing oversight program.
PCG	previously certified gasoline.
PLOQ	published limit of quantitation.
ppm (mg/kg)	parts per million (or milligram per kilogram).
PTD	product transfer document.
R&D	research and development.
RCO	responsible corporate officer.
RFG	reformulated gasoline.
RFS	Renewable Fuel Standard.
RVP	Reid vapor pressure.
SIP	state implementation plan.
SQC	statistical quality control.
T10, T50, T90	temperatures representing the points in a distillation process where 10, 50, and 90 percent of the sample evaporates, respectively.
TDP	transmix distillate product.
TGP	transmix gasoline product.
U.S	United States.
U.S.C	United States Code.
ULSD	ultra-low-sulfur diesel fuel.
VCSB	voluntary consensus standards body.

§ 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, [phone], and is also available from the sources listed in this section. This material is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, email [e-mail], 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, [phone], or www.aicpa.org.

(1) AICPA Code of Professional Conduct, updated through June 2020; IBR approved for § 1090.1800(b).

(2) Statements on Quality Control Standards (SQCS) No. 8, QC Section 10: A Firm's System of Quality Control, current as of July 1, 2019; IBR approved for § 1090.1800(b).

(3) Statement on Standards for Attestation Engagements No. 18, Attestation Standards: Clarification and Recodification, Issued April 2016; IBR approved for § 1090.1800(b).

(c) ASTM International, 100 Barr Harbor Dr., P.O. Box C700, West Conshohocken, PA 19428-2959, [phone], or www.astm.org.

(1) ASTM D86-20a, Standard Test Method for Distillation of Petroleum Products and Liquid Fuels at Atmospheric Pressure, approved July 1, 2020 (“ASTM D86”); IBR approved for § 1090.1350(b).

(2) ASTM D287-12b (Reapproved 2019), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), approved December 1, 2019 (“ASTM D287”); IBR approved for § 1090.1337(d).

(3) ASTM D975-20a, Standard Specification for Diesel Fuel, approved June 1, 2020 (“ASTM D975”); IBR approved for § 1090.80.

(4) ASTM D976-06 (Reapproved 2016), Standard Test Method for Calculated Cetane Index of Distillate Fuels, approved April 1, 2016 (“ASTM D976”); IBR approved for § 1090.1350(b).

(5) ASTM D1298-12b (Reapproved 2017), Standard Test Method for Density, Relative Density, or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, approved July 15, 2017 (“ASTM D1298”); IBR approved for § 1090.1337(d).

(6) ASTM D1319-19, Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption, approved August 1, 2019 (“ASTM D1319”); IBR approved for § 1090.1350(b).

(7) ASTM D2163-14 (Reapproved 2019), Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography, approved May 1, 2019 (“ASTM D2163”); IBR approved for § 1090.1350(b).

(8) ASTM D2622-16, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, approved January 1, 2016 (“ASTM D2622”); IBR approved for §§ 1090.1350(b), 1090.1360(d), 1090.1365(b), and 1090.1375(c).

(9) ASTM D3120-08 (Reapproved 2019), Standard Test Method for Trace Quantities of Sulfur in Light Liquid Petroleum Hydrocarbons by Oxidative Microcoulometry, approved May 1, 2019 (“ASTM D3120”); IBR approved for § 1090.1365(b).

(10) ASTM D3231-18, Standard Test Method for Phosphorus in Gasoline, approved April 1, 2018 (“ASTM D3231”); IBR approved for § 1090.1350(b).

(11) ASTM D3237-17, Standard Test Method for Lead in Gasoline by Atomic Absorption Spectroscopy, approved June 1, 2017 (“ASTM D3237”); IBR approved for § 1090.1350(b).

(12) ASTM D3606-20e1, Standard Test Method for Determination of Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography, approved July 1, 2020 (“ASTM D3606”); IBR approved for § 1090.1360(c).

(13) ASTM D4052-18a, Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter, approved December 15, 2018 (“ASTM D4052”); IBR approved for § 1090.1337(d).

(14) ASTM D4057-19, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, approved July 1, 2019 (“ASTM D4057”); IBR approved for §§ 1090.1335(b) and 1090.1605(b).

(15) ASTM D4177-16e1, Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, approved October 1, 2016 (“ASTM D4177”); IBR approved for §§ 1090.1315(a) and 1090.1335(c).

(16) ASTM D4737-10 (Reapproved 2016), Standard Test Method for Calculated Cetane Index by Four Variable Equation, approved July 1, 2016 (“ASTM D4737”); IBR approved for § 1090.1350(b).

(17) ASTM D4806-20, Standard Specification for Denatured Fuel Ethanol for Blending with Gasolines for Use as Automotive Spark-Ignition Engine Fuel, approved May 1, 2020 (“ASTM D4806”); IBR approved for § 1090.1395(a).

(18) ASTM D4814-20a, Standard Specification for Automotive Spark-Ignition Engine Fuel, approved April 1, 2020 (“ASTM D4814”); IBR approved for §§ 1090.80 and 1090.1395(a).

(19) ASTM D5134-13 (Reapproved 2017), Standard Test Method for Detailed Analysis of Petroleum Naphthas through n-Nonane by Capillary Gas Chromatography, approved October 1, 2017 (“ASTM D5134”); IBR approved for § 1090.1350(b).

(20) ASTM D5186-20, Standard Test Method for Determination of the Aromatic Content and Polynuclear Aromatic Content of Diesel Fuels By Supercritical Fluid Chromatography, approved July 1, 2020 (“ASTM D5186”); IBR approved for § 1090.1350(b).

(21) ASTM D5191-20, Standard Test Method for Vapor Pressure of Petroleum Products and Liquid Fuels (Mini Method), approved May 1, 2020 (“ASTM D5191”); IBR approved for §§ 1090.1360(d) and 1090.1365(b).

(22) ASTM D5453-19a, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, approved July 1, 2019 (“ASTM D5453”); IBR approved for § 1090.1350(b).

(23) ASTM D5500-20a, Standard Test Method for Vehicle Evaluation of Unleaded Automotive Spark-Ignition Engine Fuel for Intake Deposit Formation, approved June 1, 2020 (“ASTM D5500”); IBR approved for § 1090.1395(c).

(24) ASTM D5599-18, Standard Test Method for Determination of Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection, approved June 1, 2018 (“ASTM D5599”); IBR approved for §§ 1090.1360(d) and 1090.1365(b).

(25) ASTM D5769-20, Standard Test Method for Determination of Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry, approved June 1, 2020 (“ASTM D5769”); IBR approved for §§ 1090.1350(b), 1090.1360(d), and 1090.1365(b).

(26) ASTM D5842-19, Standard Practice for Sampling and Handling of Fuels for Volatility Measurement, approved November 1, 2019 (“ASTM D5842”); IBR approved for § 1090.1335(d).

(27) ASTM D5854-19a, Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products, approved May 1, 2019 (“ASTM D5854”); IBR approved for § 1090.1315(a).

(28) ASTM D6201-19a, Standard Test Method for Dynamometer Evaluation of Unleaded Spark-Ignition Engine Fuel for Intake Valve Deposit Formation, approved December 1, 2019 (“ASTM D6201”); IBR approved for § 1090.1395(a).

(29) ASTM D6259-15 (Reapproved 2019), Standard Practice for Determination of a Pooled Limit of Quantitation for a Test Method, approved May 1, 2019 (“ASTM D6259”); IBR approved for § 1090.1355(b).

(30) ASTM D6299-20, Standard Practice for Applying Statistical Quality Assurance and Control Charting Techniques to Evaluate Analytical Measurement System Performance, approved May 1, 2020 (“ASTM D6299”); IBR approved for §§ 1090.1370(c), 1090.1375(a), (b), and (c), and 1090.1450(c).

(31) ASTM D6550-20, Standard Test Method for Determination of Olefin Content of Gasolines by Supercritical-Fluid Chromatography, approved July 1, 2020 (“ASTM D6550”); IBR approved for § 1090.1350(b).

(32) ASTM D6667-14 (Reapproved 2019), Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, approved May 1, 2019 (“ASTM D6667”); IBR approved for §§ 1090.1360(d), 1090.1365(b), and 1090.1375(c).

(33) ASTM D6708-19a, Standard Practice for Statistical Assessment and Improvement of Expected Agreement Between Two Test Methods that Purport to Measure the Same Property of a Material, approved November 1, 2019 (“ASTM D6708”); IBR approved for §§ 1090.1360(c), 1090.1365(d) and (f), and 1090.1375(c).

(34) ASTM D6729-14, Standard Test Method for Determination of Individual Components in Spark Ignition Engine Fuels by 100 Metre Capillary High Resolution Gas Chromatography, approved October 1, 2014 (“ASTM D6729”); IBR approved for § 1090.1350(b).

(35) ASTM D6730-19, Standard Test Method for Determination of Individual Components in Spark Ignition Engine Fuels by 100-Metre Capillary (with Precolumn) High-Resolution Gas Chromatography, approved July 1, 2019 (“ASTM D6730”); IBR approved for § 1090.1350(b).

(36) ASTM D6751-20, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, approved January 1, 2020 (“ASTM D6751”); IBR approved for § 1090.1350(b).

(37) ASTM D6792-17, Standard Practice for Quality Management Systems in Petroleum Products, Liquid Fuels, and Lubricants Testing Laboratories, approved May 1, 2017 (“ASTM D6792”); IBR approved for § 1090.1450(c).

(38) ASTM D7039-15a (Reapproved 2020), Standard Test Method for Sulfur in Gasoline, Diesel Fuel, Jet Fuel, Kerosine, Biodiesel, Biodiesel Blends, and Gasoline-Ethanol Blends by Monochromatic Wavelength Dispersive X-ray Fluorescence Spectrometry, approved May 1, 2020 (“ASTM D7039”); IBR approved for § 1090.1365(b).

(39) ASTM D7717-11 (Reapproved 2017), Standard Practice for Preparing Volumetric Blends of Denatured Fuel Ethanol and Gasoline Blendstocks for Laboratory Analysis, approved May 1, 2017 (“ASTM D7717”); IBR approved for § 1090.1340(b).

(40) ASTM D7777-13 (Reapproved 2018)e1, Standard Test Method for Density, Relative Density, or API Gravity of Liquid Petroleum by Portable Digital Density Meter, approved October 1, 2018 (“ASTM D7777”); IBR approved for § 1090.1337(d).

(d) Environmental Protection Agency, Air and Radiation Docket and Information Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW, Washington, DC 20460, [phone].

(1) CARB Test Method, 13 CA ADC § 2257; California Code of Regulations Title 13. Motor Vehicles, Division 3. Air Resources Board, Chapter 5. Standards for Motor Vehicle Fuels, Article 1. Standards for Gasoline, Subarticle 1. Gasoline Standards that Became Applicable Before 1996, § 2257. Required Additives in Gasoline; amendment filed May 17, 1999.

(2) [Reserved]

(e) The Institute of Internal Auditors, 1035 Greenwood Blvd., Suite 401, Lake Mary, FL 32746, [phone], or www.theiia.org.

(1) International Standards for the Professional Practice of Internal Auditing (Standards), Revised October 2016; IBR approved for § 1090.1800(b).

(2) [Reserved]

(f) National Institute of Standards and Technology, 100 Bureau Dr., Stop 1070, Gaithersburg, MD 20899-1070, [phone], or www.nist.gov.

(1) NIST Handbook 158, Field Sampling Procedures for Fuel and Motor Oil Quality Testing—A Handbook for Use by Fuel and Oil Quality Regulatory Officials, 2016 Edition, April 2016; IBR approved for § 1090.1410(b).

(2) [Reserved]

Subpart B—General Requirements and Provisions for Regulated Parties

§ 1090.100

General provisions.

This subpart provides an overview of the general requirements and provisions applicable to any regulated party under this part. A person who meets the definition of more than one type of regulated party must comply with the requirements applicable to each of those types of regulated parties. For example, a fuel manufacturer that also transports fuel must meet the requirements applicable to a fuel manufacturer and a distributor. A regulated party is required to comply with all applicable requirements of this part, regardless of whether they are identified in this subpart. Any person that produces, sells, transfers, supplies, dispenses, or distributes fuel, fuel additive, or regulated blendstock must comply with all applicable requirements.

(a) Recordkeeping. Any party that engages in activities that are regulated under this part must comply with recordkeeping requirements under subpart M of this part.

(b) Compliance and enforcement. Any party that engages in activities that are regulated under this part is subject to compliance and enforcement provisions under subpart R of this part.

(c) Hardships and exemptions. Some regulated parties under this part may be eligible, or eligible to petition, for a hardship or exemption under subpart G of this part.

(d) In addition to the requirements of paragraphs (a) through (c) of this section and § 1090.105, an importer must also comply with subpart Q of this part.

§ 1090.105

Fuel manufacturers.

This section provides an overview of general requirements applicable to a fuel manufacturer. A gasoline manufacturer must comply with the requirements of paragraph (a) of this section. A diesel fuel or IMO marine fuel manufacturer must comply with the requirements of paragraph (b) of this section.

(a) Gasoline manufacturers. Except as specified otherwise in this subpart, a gasoline manufacturer must comply with the following requirements:

(1) Producing compliant gasoline. A gasoline manufacturer must produce or import gasoline that meets the standards of subpart C of this part and must comply with the ABT requirements in subpart H of this part.

(2) Registration. A gasoline manufacturer must register with EPA under subpart I of this part.

(3) Reporting. A gasoline manufacturer must submit reports to EPA under subpart J of this part.

(4) Certification and designation. A gasoline manufacturer must certify and designate the gasoline they produce under subpart K of this part.

(5) PTDs. On each occasion when a gasoline manufacturer transfers custody of or title to any gasoline, the transferor must provide to the transferee PTDs under subpart L of this part.

(6) Sampling, testing, and sample retention. A gasoline manufacturer must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

(7) Surveys. A gasoline manufacturer may participate in applicable fuel surveys under subpart O of this part.

(8) Annual attest engagement. A gasoline manufacturer must submit annual attest engagement reports to EPA under subpart S of this part.

(b) Diesel fuel and IMO marine fuel manufacturers. A diesel fuel or IMO marine fuel manufacturer must comply with the following requirements, as applicable:

(1) Producing compliant diesel fuel and ECA marine fuel. A diesel fuel or ECA marine fuel manufacturer must produce or import diesel fuel or ECA marine fuel that meets the requirements of subpart D of this part.

(2) Registration. A diesel fuel or ECA marine fuel manufacturer must register with EPA under subpart I of this part.

(3) Reporting. A diesel fuel manufacturer must submit reports to EPA under subpart J of this part.

(4) Certification and designation. A diesel fuel or ECA marine fuel manufacturer must certify and designate the diesel fuel or ECA marine fuel they produce under subpart K of this part. A distillate global marine fuel manufacturer must designate the distillate global marine fuel they produce under subpart K of this part.

(5) PTDs. On each occasion when a diesel fuel or IMO marine fuel manufacturer transfers custody or title to any diesel fuel or IMO marine fuel, the transferor must provide to the transferee PTDs under subpart L of this part.

(6) Sampling, testing, and retention requirements. A diesel fuel or ECA marine fuel manufacturer must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

(7) Surveys. A diesel fuel manufacturer may participate in applicable fuel surveys under subpart O of this part.

(8) Distillate global marine fuel manufacturers. A distillate global marine fuel manufacturer does not need to comply with the requirements of paragraphs (b)(1) through (3), and (6) of this section for global marine fuel that is exempt from the standards in subpart D of this part, as specified in § 1090.650.

§ 1090.110

Detergent blenders.

A detergent blender must comply with the requirements of this section.

(a) Gasoline standards. A detergent blender must comply with the applicable requirements of subpart C of this part.

(b) PTDs. On each occasion when a detergent blender transfers custody of or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(c) Recordkeeping. A detergent blender must demonstrate compliance with the requirements in § 1090.260(a) as specified in § 1090.1240.

(d) Equipment calibration. A detergent blender at an automated detergent blending facility must calibrate their detergent blending equipment in accordance with subpart N of this part.

§ 1090.115

Oxygenate blenders.

An oxygenate blender must comply with the requirements of this section.

(a) Gasoline standards. An oxygenate blender must comply with the applicable requirements of subpart C of this part.

(b) Registration. An oxygenate blender must register with EPA under subpart I of this part.

(c) PTDs. On each occasion when an oxygenate blender transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(d) Oxygenate blending requirements. An oxygenate blender must follow the blending instructions specified by the gasoline manufacturer under § 1090.710(a)(5) unless the oxygenate blender recertifies BOBs under § 1090.740.

§ 1090.120

Oxygenate producers.

This section provides an overview of general requirements applicable to an oxygenate producer (e.g., a DFE or isobutanol producer). A DFE producer must comply with the requirements for an oxygenate producer in paragraph (a) of this section and the additional requirements specified in paragraph (b) of this section.

(a) Oxygenate producers. An oxygenate producer must comply with the following requirements:

(1) Gasoline standards. An oxygenate producer must comply with the applicable requirements of subpart C of this part.

(2) Registration. An oxygenate producer must register with EPA under subpart I of this part.

(3) Reporting. An oxygenate producer must submit reports to EPA under subpart J of this part.

(4) Certification and designation. An oxygenate producer must certify and designate the oxygenate they produce under subpart K of this part.

(5) PTDs. On each occasion when an oxygenate producer transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(6) Sampling, testing, and retention requirements. An oxygenate producer must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

(b) DFE producers. In addition to the requirements specified in paragraph (a) of this section, a DFE producer must meet all the following requirements:

(1) Use denaturant that complies with the requirements specified in §§ 1090.270(b) and 1090.275.

(2) Participate in a survey program conducted by an independent surveyor under subpart O of this part if the DFE producer produces DFE made available for use in the production of E15.

§ 1090.125

Certified butane producers.

A certified butane producer must comply with the requirements of this section.

(a) Gasoline standards. A certified butane producer must comply with the applicable requirements of subpart C of this part.

(b) Certification and designation. A certified butane producer must certify and designate the certified butane they produce under subpart K of this part.

(c) PTDs. On each occasion when a certified butane producer transfers custody of or title to any certified butane, the transferor must provide to the transferee PTDs under subpart L of this part.

(d) Sampling, testing, and retention requirements. A certified butane producer must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

§ 1090.130

Certified butane blenders.

A certified butane blender that blends certified butane into PCG is a gasoline manufacturer that may comply with the requirements of this section in lieu of the requirements in § 1090.105.

(a) Gasoline standards. A certified butane blender must comply with the applicable requirements of subpart C of this part.

(b) Registration. A certified butane blender must register with EPA under subpart I of this part.

(c) Reporting. A certified butane blender must submit reports to EPA under subpart J of this part.

(d) PTDs. When certified butane is blended with PCG, PTDs that accompany the gasoline blended with certified butane must comply with subpart L of this part.

(e) Sampling and testing requirements. A certified butane blender must comply with the alternative sampling and testing approach in § 1090.1320(b).

(f) Survey. A certified butane blender may participate in the applicable fuel surveys of subpart O of this part.

(g) Annual attest engagement. A certified butane blender must submit annual attest engagement reports to EPA under subpart S of this part.

§ 1090.135

Certified pentane producers.

A certified pentane producer must comply with the requirements of this section.

(a) Gasoline standards. A certified pentane producer must comply with the applicable requirements of subpart C of this part.

(b) Registration. A certified pentane producer must register with EPA under subpart I of this part.

(c) Reporting. A certified pentane producer must submit reports to EPA under subpart J of this part.

(d) Certification and designation. A certified pentane producer must certify and designate the certified pentane they produce under subpart K of this part.

(e) PTDs. On each occasion when a certified pentane producer transfers custody of or title to any certified pentane, the transferor must provide to the transferee PTDs under subpart L of this part.

(f) Sampling, testing, and retention requirements. A certified pentane producer must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

§ 1090.140

Certified pentane blenders.

A certified pentane blender that blends certified pentane into PCG is a gasoline manufacturer that may comply with the requirements of this section in lieu of the requirements in § 1090.105.

(a) Gasoline standards. A certified pentane blender must comply with the applicable requirements of subpart C of this part.

(b) Registration. A certified pentane blender must register with EPA under subpart I of this part.

(c) Reporting. A certified pentane blender must submit reports to EPA under subpart J of this part.

(d) PTDs. When certified pentane is blended with PCG, PTDs that accompany the gasoline blended with pentane must comply with subpart L of this part.

(e) Sampling, testing, and retention requirements. A certified pentane blender must comply with the alternative sampling and testing approach in § 1090.1320(b).

(f) Survey. A certified pentane blender may participate in the applicable fuel surveys of subpart O of this part.

(g) Annual attest engagement. A certified pentane blender must submit annual attest engagement reports to EPA under subpart S of this part.

§ 1090.145

Transmix processors.

A transmix processor must comply with the requirements of this section.

(a) Transmix requirements. A transmix processor must comply with the transmix requirements of subpart F of this part.

(b) Registration. A transmix processor must register with EPA under subpart I of this part.

(c) Certification and designation. A transmix processor must certify and designate the fuel they produce under subpart K of this part.

(d) PTDs. On each occasion when a transmix processor produces a batch of fuel or transfers custody of or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(e) Sampling, testing, and retention requirements. A transmix processor must conduct sampling, testing, and sample retention in accordance with subparts F and N of this part.

(f) Reporting. A transmix processor must submit reports to EPA under subpart J of this part.

(g) Annual attest engagement. A transmix processor must submit annual attest engagement reports to EPA under subpart S of this part.

§ 1090.150

Transmix blenders.

A transmix blender must comply with the requirements of this section.

(a) Transmix requirements. A transmix blender must comply with the transmix requirements of subpart F of this part.

(b) PTDs. On each occasion when a transmix blender produces a batch of fuel or transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(c) Sampling, testing, and retention requirements. A transmix blender must conduct sampling, testing, and sample retention in accordance with subparts F and N of this part.

§ 1090.155

Fuel additive manufacturers.

This section provides an overview of general requirements applicable to a fuel additive manufacturer. A gasoline additive manufacturer must comply with the requirements of paragraph (a) of this section. A diesel fuel additive manufacturer must comply with the requirements of paragraph (b) of this section. A certified ethanol denaturant producer must comply with the requirements of paragraph (c) of this section.

(a) Gasoline additive manufacturers. A gasoline additive manufacturer must meet the following requirements:

(1) Gasoline additive standards. A gasoline additive manufacturer must produce gasoline additives that comply with subpart C of this part.

(2) Certification. A gasoline additive manufacturer must certify the gasoline additives they produce under subpart K of this part.

(3) PTDs. On each occasion when a gasoline additive manufacturer transfers custody of or title to any gasoline additive, the transferor must provide to the transferee PTDs under subpart L of this part.

(4) Gasoline detergent manufacturers. A gasoline detergent manufacturer must comply with the following requirements:

(i) Part 79 registration and LAC determination. A gasoline detergent manufacturer must register gasoline detergent(s) under 40 CFR 79.21 at a concentration that is greater than or equal to the LAC reported by the gasoline detergent manufacturer under 40 CFR 79.21(j). Note: EPA provides a list on EPA's website of detergents that have been certified by the gasoline detergent manufacturer as meeting the deposit control requirement (Search for “List of Certified Detergent Additives”).

(ii) Gasoline detergent standards. Report the LAC determined under § 1090.260(b) and provide specific composition information as part of the gasoline detergent manufacturer's registration of the detergent under 40 CFR 79.21(j).

(iii) PTDs. On each occasion when a gasoline detergent manufacturer transfers custody of or title to any gasoline detergent, the transferor must provide to the transferee PTDs under subpart L of this part.

(iv) Sampling, testing, and retention requirements. A gasoline detergent manufacturer that registers detergents must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

(b) Diesel fuel additive manufacturers. A diesel fuel additive manufacturer must meet the following requirements:

(1) Diesel fuel additive standards. A diesel fuel additive manufacturer must produce diesel fuel additives that comply with subpart D of this part.

(2) Certification. A diesel fuel additive manufacturer must certify the diesel fuel additives they produce under subpart K of this part.

(3) PTDs. On each occasion when a diesel fuel additive manufacturer transfers custody of or title to any diesel additive, the transferor must provide to the transferee PTDs under subpart L of this part.

(c) Certified ethanol denaturant producers and importers. A certified ethanol denaturant producer or importer must meet the following requirements:

(1) Certification. A certified ethanol denaturant producer or importer must certify that certified ethanol denaturant meets the requirements in § 1090.275 using the procedures specified at § 1090.1000(g).

(2) Registration. A certified ethanol denaturant producer or importer must register with EPA under subpart I of this part.

(3) PTDs. On each occasion when a certified ethanol denaturant producer transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

§ 1090.160

Distributors, carriers, and resellers.

A distributor, carrier, or reseller must comply with the requirements of this section.

(a) Gasoline and diesel standards. A distributor, carrier, or reseller must comply with the applicable requirements of subparts C and D of this part.

(b) Registration. A distributor or carrier must register with EPA under subpart I of this part if they are part of the 500 ppm LM diesel fuel distribution chain under a compliance plan submitted under § 1090.515(g).

(c) PTDs. On each occasion when a distributor, carrier, or reseller transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

§ 1090.165

Retailers and WPCs.

A retailer or WPC must comply with the requirements of this section.

(a) Gasoline and diesel standards. A retailer or WPC must comply with the applicable requirements of subparts C and D of this part.

(b) Labeling. A retailer or WPC that dispenses fuels requiring a label under this part must display fuel labels under subpart P of this part.

(c) Fuels made through fuel dispensers. A retailer or WPC that produces gasoline (e.g., E15) through a fuel dispenser with anything other than PCG and DFE is also a blending manufacturer and must comply with the applicable requirements in § 1090.105.

§ 1090.170

Independent surveyors.

An independent surveyor that conducts fuel surveys must comply with the requirements of this section.

(a) Survey provisions. An independent surveyor must conduct fuel surveys under subpart O of this part.

(b) Registration. An independent surveyor must register with EPA under subpart I of this part.

(c) Reporting. An independent surveyor must submit reports to EPA under subpart J of this part.

(d) Sampling, testing, and retention requirements. An independent surveyor must conduct sampling, testing, and sample retention in accordance with subpart N of this part.

(e) Independence requirements. In order to perform a survey program under subpart O of this part, an independent surveyor must meet the independence requirements in § 1090.55.

§ 1090.175

Auditors.

An auditor that conducts an audit for a responsible party under this part must comply with the requirements of this section.

(a) Registration. An auditor must register with EPA under subpart I of this part.

(b) Reporting. An auditor must submit reports to EPA under subpart J of this part.

(c) Attest engagement. An auditor must conduct audits under subpart S of this part.

(d) Independence requirements. In order to perform an annual attest engagement under subpart S of this part, an auditor must meet the independence requirements in § 1090.55 unless they are a certified internal auditor under § 1090.1800(b)(1)(i).

§ 1090.180

Pipeline operators.

A pipeline operator must comply with the requirements of this section.

(a) Gasoline and diesel standards. A pipeline operator must comply with the applicable requirements of subparts C and D of this part.

(b) PTDs. On each occasion when a pipeline operator transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart L of this part.

(c) Transmix requirements. A pipeline operator must comply with all applicable requirements in subpart F of this part.

Subpart C—Gasoline Standards

§ 1090.200

Overview and general requirements.

(a) Except as specified in subpart G of this part, gasoline, gasoline additives, and gasoline regulated blendstocks are subject to the standards in this subpart.

(b) Except for the sulfur average standard in § 1090.205(a) and the benzene average standards in § 1090.210(a) and (b), the standards in this part apply to gasoline, gasoline additives, and gasoline regulated blendstocks on a per-gallon basis. A gasoline manufacturer, gasoline additive manufacturer (e.g., an oxygenate or certified ethanol denaturant producer), or gasoline regulated blendstock producer (e.g., a certified butane or certified pentane producer) must demonstrate compliance with the per-gallon standards in this subpart by measuring fuel parameters in accordance with subpart N of this part.

(c)(1) Except as specified in paragraph (c)(2) of this section, the sulfur average standard in § 1090.205(a) and the benzene average standards in § 1090.210(a) and (b) apply to all gasoline produced or imported by a fuel manufacturer during a compliance period. A fuel manufacturer must demonstrate compliance with average standards by measuring fuel parameters in accordance with subpart N of this part and by determining compliance under subpart H of this part.

(2) The sulfur average standard in § 1090.205(a) and the benzene average standards in § 1090.210(a) and (b) do not apply to gasoline produced by the following:

(i) Truck and rail importers using the provisions of § 1090.1610 to meet the alternative per-gallon standards of §§ 1090.205(d) and 1090.210(c).

(ii) Certified butane blenders.

(iii) Certified pentane blenders.

(iv) Transmix blenders.

(v) Transmix processors that produce gasoline from only TGP or both TGP and PCG.

(d) No person may produce, import, sell, offer for sale, distribute, offer to distribute, supply, offer for supply, dispense, store, transport, or introduce into commerce any gasoline, gasoline additive, or gasoline regulated blendstock that does not comply with any per-gallon standard set forth in this subpart.

(e) No person may sell, offer for sale, supply, offer for supply, dispense, transport, or introduce into commerce for use as fuel in any motor vehicle (as defined in Section 216(2) of the Clean Air Act, 42 U.S.C. 7550(2)) any gasoline that is produced with the use of additives containing lead, that contains more than 0.05 gram of lead per gallon, or that contains more than 0.005 grams of phosphorous per gallon.

(f) No fuel or fuel additive manufacturer may introduce into commerce gasoline or gasoline additives (including oxygenates) that are not “substantially similar” under 42 U.S.C. 7545(f)(1) or permitted under a waiver granted under 42 U.S.C. 7545(f)(4).

§ 1090.205

Sulfur standards.

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

(a) Sulfur average standard. A gasoline manufacturer must meet a sulfur average standard of 10.00 ppm for each compliance period.

(b) Fuel manufacturing facility gate sulfur per-gallon standard. Gasoline at any fuel manufacturing facility gate is subject to a maximum sulfur per-gallon standard of 80 ppm. A gasoline manufacturer must not account for the downstream addition of oxygenates in determining compliance with this standard.

(c) Downstream location sulfur per-gallon standard. Gasoline at any downstream location is subject to a maximum sulfur per-gallon standard of 95 ppm.

(d) Sulfur standard for importers that import gasoline by rail or truck. (1) An importer that imports gasoline by rail or truck under § 1090.1610 must comply with a maximum sulfur per-gallon standard of 10 ppm instead of the standards in paragraphs (a) through (c) of this section.

(2) An importer that imports gasoline by rail or truck but does not comply with the alternative sampling and testing requirements in § 1090.1610 must conduct sampling, testing, and sample retention in accordance with subpart N of this part and comply with the sulfur standards in paragraphs (a) and (b) of this section.

§ 1090.210

Benzene standards.

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

(a) Benzene average standard. A gasoline manufacturer must meet a benzene average standard of 0.62 volume percent for each compliance period.

(b) Maximum benzene average standard. A gasoline manufacturer must meet a maximum benzene average standard of 1.30 volume percent without the use of credits for each compliance period.

(c) Benzene standard for importers that import gasoline by rail or truck. (1) An importer that imports gasoline by rail or truck under § 1090.1610 must comply with a 0.62 volume percent benzene per-gallon standard instead of the standards in paragraphs (a) and (b) of this section.

(2) An importer that imports gasoline by rail or truck that does not comply with the alternative sampling and testing requirements in § 1090.1610 must conduct sampling, testing, and sample retention in accordance with subpart N of this part and comply with the benzene standards in paragraphs (a) and (b) of this section.

§ 1090.215

Gasoline RVP standards.

Except as specified in subpart G of this part and paragraph (c) of this section, all gasoline designated as summer gasoline or located at any location in the United States during the summer season is subject to a maximum RVP per-gallon standard in this section.

(a)(1) Federal 9.0 psi maximum RVP per-gallon standard. Gasoline designated as summer gasoline or located at any location in the United States during the summer season must meet a maximum RVP per-gallon standard of 9.0 psi unless the gasoline is subject to one of the lower maximum RVP per-gallon standards specified in paragraphs (a)(2) through (5) of this section.

(2) Federal 7.8 maximum RVP per-gallon standard. Gasoline designated as 7.8 psi summer gasoline, or located in the following areas during the summer season, must meet a maximum RVP per-gallon standard of 7.8 psi:

Table 1 to Paragraph (a)(2)—Federal 7.8 psi RVP Areas

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

(3) RFG maximum RVP per-gallon standard. Gasoline designated as Summer RFG or located in an RFG covered area during the summer season must meet a maximum RVP per-gallon standard of 7.4 psi.

(4) California gasoline. Gasoline designated as California gasoline or used in areas subject to the California reformulated gasoline regulations must comply with those regulations under Title 13, California Code of Regulations, sections 2250-2273.5.

(5) SIP-controlled gasoline. Gasoline designated as SIP-controlled gasoline or used in areas subject to a SIP-approved state fuel rule that requires an RVP of less than 9.0 psi must meet the requirements of the federally approved SIP.

(b) Ethanol 1.0 psi waiver. (1) Except as specified in paragraph (b)(3) of this section, any gasoline subject to a federal 9.0 psi or 7.8 psi maximum RVP per-gallon standard in paragraph (a)(1) or (2) of this section that meets the requirements of paragraph (b)(2) of this section is not in violation of this section if its RVP does not exceed the applicable standard by more than 1.0 psi.

(2) To qualify for the special regulatory treatment specified in paragraph (b)(1) of this section, gasoline must meet the applicable RVP per-gallon standard in paragraph (a)(1) or (2) of this section prior to the addition of ethanol and must contain ethanol at a concentration of at least 9 volume percent and no more than 15 volume percent.

(3) RFG and SIP-controlled gasoline that does not allow for the ethanol 1.0 psi waiver does not qualify for the special regulatory treatment specified in paragraph (b)(1) of this section.

(c) Exceptions. The RVP per-gallon standard in paragraph (a) of this section for the area in which the gasoline is located does not apply to that gasoline if the person(s) who produced, imported, sold, offered for sale, distributed, offered to distribute, supplied, offered for supply, dispensed, stored, transported, or introduced the gasoline into commerce can demonstrate one of the following:

(1) The gasoline is designated as winter gasoline and was not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into commerce for use during the summer season and was not delivered to any retail station or WPC during the summer season.

(2) The gasoline is designated as summer gasoline for use in an area other than the area in which it is located and was not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into commerce in the area in which the gasoline is located. In this case, the standard that applies to the gasoline is the standard applicable to the area for which the gasoline is designated.

§ 1090.220

RFG standards.

The standards in this section apply to gasoline that is designated as RFG or RBOB or that is used in an RFG covered area. Gasoline that meets the requirements of this section is deemed to be in compliance with the requirements of 42 U.S.C. 7545(k).

(a) Sulfur standards. RFG or RBOB must comply with the sulfur average standard in § 1090.205(a) and the sulfur per-gallon standards in § 1090.205(b) and (c).

(b) Benzene standards. RFG or RBOB must comply with the benzene average standards in § 1090.210(a) and (b).

(c) RVP standard. Summer RFG or Summer RBOB must comply with the RFG RVP standard in § 1090.215(a)(3).

(d) Heavy metals standard. RFG or RBOB must not contain any heavy metals, including but not limited to lead or manganese. EPA may waive this prohibition for a heavy metal (other than lead) if EPA determines that addition of the heavy metal to the gasoline will not increase, on an aggregate mass or cancer-risk basis, toxic air pollutant emissions from motor vehicles.

(e) Certified butane and certified pentane blending limitation. Certified butane and certified pentane must not be blended with Summer RFG or Summer RBOB under § 1090.1320.

§ 1090.225

Anti-dumping standards.

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

§ 1090.230

Limitation on use of gasoline-ethanol blends.

(a) No person may sell, introduce, cause or permit the sale or introduction of gasoline containing greater than 10 volume percent ethanol (e.g., E15) into any model year 2000 or older light-duty gasoline motor vehicle, any heavy-duty gasoline motor vehicle or engine, any highway or off-highway motorcycle, or any gasoline-powered nonroad engine, vehicle, or equipment.

(b) Paragraph (a) of this section does not prohibit a person from producing, selling, introducing, or causing or allowing the sale or introduction of gasoline containing greater than 10 volume percent ethanol into any flex-fuel vehicle or flex-fuel engine.

§ 1090.250

Certified butane standards.

Butane designated as certified butane under § 1090.1000(e) for use under the butane blending provisions of § 1090.1320(b) must meet the following per-gallon standards:

(a) Butane content. Minimum 85 volume percent.

(b) Benzene content. Maximum 0.03 volume percent.

(c) Sulfur content. Maximum 10 ppm.

(d) Chemical composition. Be composed solely of carbon, hydrogen, oxygen, nitrogen, and sulfur.

§ 1090.255

Certified pentane standards.

Pentane designated as certified pentane under § 1090.1000(f) for use under the pentane blending provisions of § 1090.1320(b) must meet the following per-gallon standards:

(a) Pentane content. Minimum 95 volume percent.

(b) Benzene content. Maximum 0.03 volume percent.

(c) Sulfur content. Maximum 10 ppm.

(d) Chemical composition. Be composed solely of carbon, hydrogen, oxygen, nitrogen, and sulfur.

§ 1090.260

Gasoline deposit control standards.

(a) Except as specified in subpart G of this part, all gasoline that is sold, offered for sale, dispensed, supplied, offered for supply, or transported to the ultimate consumer for use in motor vehicles or in any off-road engines, or that is transported to a gasoline retailer or WPC must be treated with a detergent that meets the requirements of paragraph (b) of this section at a rate at least as high as the detergent's LAC over the VAR period.

(b) The LAC of the detergent must be determined by the gasoline detergent manufacturer using one of the following methods:

(1) The detergent must comply with one of the deposit control testing methods specified in § 1090.1395.

(2) The detergent must have been certified prior to January 1, 2021, under the intake valve deposit control requirements of 40 CFR 80.165(b) for any of the detergent certification options under 40 CFR 80.163. Di-tertiary butyl disulfide may have been used to meet the test fuel specifications under 40 CFR 80.164 associated with the intake valve deposit control requirements of 40 CFR 80.165(b). A party compliant with this paragraph (b)(2) is exempt from the port fuel injector deposit control requirements of 40 CFR 80.165(a).

(3) A gasoline detergent manufacturer must produce detergents consistent with their detergent certifications for detergents certified prior to January 1, 2021, and with the specific composition information submitted as part of the registration of detergents under 40 CFR 79.21(j) thereafter.

§ 1090.265

Gasoline additive standards.

(a) Any gasoline additive that is added to, intended for adding to, used in, or offered for use in gasoline at any downstream location must meet all the following requirements:

(1) Registration. The gasoline additive must be registered by a gasoline additive manufacturer under 40 CFR part 79.

(2) Sulfur content. The gasoline additive must contribute less than or equal to 3 ppm on a per-gallon basis to the sulfur content of gasoline when used at the maximum recommended concentration.

(3) Treatment rate. Except for oxygenates, the gasoline additive(s) must be used at a maximum treatment rate less than or equal to a combined total of 1.0 volume percent.

(b) Any fuel additive blender that is not otherwise subject to any other requirement in this part and only blends a gasoline additive that meets the requirements of paragraph (a) of this section into gasoline is not subject to any requirement in this part solely due to this gasoline additive blending, except the downstream sulfur per-gallon standard in § 1090.205(c), if all the following conditions are met:

(1) The fuel additive blender blends gasoline additives into gasoline at a concentration less than or equal to a combined total of 1.0 volume percent.

(2) The fuel additive blender does not add any other blendstock into the gasoline except for oxygenates that meet the requirements in § 1090.270.

(c) Any person who blends any fuel additive that does not meet the requirements of paragraphs (a) and (b) of this section is a gasoline manufacturer and must comply with all requirements applicable to a gasoline manufacturer under this part.

(d) Any gasoline additive used or intended for use to comply with the gasoline deposit control requirement in § 1090.260(a) must meet the gasoline deposit control standards under § 1090.260(b).

§ 1090.270

Gasoline oxygenate standards.

(a) All oxygenates designated for blending with gasoline or blended with gasoline must meet the following per-gallon standards:

(1) Sulfur content. Maximum 10 ppm.

(2) Chemical composition. Be composed solely of carbon, hydrogen, oxygen, nitrogen, and sulfur.

(b) DFE designated for blending into gasoline or blended with gasoline must meet the following additional requirements:

(1) Denaturant type. Only PCG, gasoline blendstocks, NGLs, or certified ethanol denaturant that meets the requirements in § 1090.275 may be used as denaturants.

(2) Denaturant concentration. The concentration of all denaturants used in DFE must not exceed 3.0 volume percent.

§ 1090.275

Ethanol denaturant standards.

(a) Standard for all ethanol denaturant. All ethanol denaturant, certified or uncertified, used to produce DFE must be composed solely of carbon, hydrogen, nitrogen, oxygen, and sulfur.

(b) Standards for certified ethanol denaturant. In addition to the requirements of paragraph (a) of this section, certified ethanol denaturant must meet the following requirements:

(1) Sulfur content per-gallon standard. Maximum 330 ppm. If the certified ethanol denaturant producer represents a batch of denaturant as having a maximum sulfur content less than 330 ppm on the PTD (for example, less than or equal to 120 ppm), then the actual sulfur content must be less than or equal to the stated value.

(2) Denaturant type. Only PCG, gasoline blendstocks, or NGLs may be used to produce certified ethanol denaturant.

§ 1090.285

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)—RFG Covered Areas Under 42 U.S.C. 7545(k)(10)(D)

Area designation	State	Counties	Independent cities
Los Angeles-Anaheim-Riverside	California	Los Angeles, Orange, Ventura, San Bernardino,1 Riverside 2
San Diego County	California	San Diego
Greater Connecticut	Connecticut	Hartford, Middlesex, New Haven, New London, Tolland, Windham, Fairfield (only the City of Shelton), Litchfield (all except the towns of Bridgewater and New Milford)
New York-Northern New Jersey-Long Island-Connecticut	Connecticut	Fairfield (all except the 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, Carroll, Harford, Howard	Baltimore.
Houston-Galveston-Brazoria	Texas	Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, Waller
Milwaukee-Racine	Wisconsin	Kenosha, Milwaukee, Ozaukee, Racine, Washington, Waukesha
1 That portion of San Bernardino County, CA that lies south of latitude 35 degrees, 10 minutes north and west of longitude 115 degrees, 45 minutes west.
2 That portion of Riverside County, CA that lies to the west of a line described as follows: Beginning at the northeast corner of Section 4, Township 2 South, Range 5 East, a point on the boundary line common to Riverside and San Bernardino Counties; then southerly along section lines to the centerline of the Colorado River Aqueduct; then southeasterly along the centerline of said Colorado River Aqueduct to the southerly line of Section 36, Township 3 South, Range 7 East; then easterly along the township line to the northeast corner of Section 6, Township 4 South, Range 9 East; then southerly along the easterly line of Section 6 to the southeast corner thereof; then easterly along section lines to the northeast corner of Section 10, Township 4 South, Range 9 East; then southerly along section lines to the southeast corner of Section 15, Township 4 South, Range 9 East; then easterly along the section lines to the northeast corner of Section 21, Township 4 South, Range 10 East; then southerly along the easterly line of Section 21 to the southeast corner thereof; then easterly along the northerly line of Section 27 to the northeast corner thereof; then southerly along section lines to the southeast corner of Section 34, Township 4 South, Range 10 East; then easterly along the township line to the northeast corner of Section 2, Township 5 South, Range 10 East; then southerly along the easterly line of Section 2, to the southeast corner thereof; then easterly along the northerly line of Section 12 to the northeast corner thereof; then southerly along the range line to the southwest corner of Section 18, Township 5 South, Range 11 East; then easterly along section lines to the northeast corner of Section 24, Township 5 South, Range 11 East; and then southerly along the range line to the southeast corner of Section 36, Township 8 South, Range 11 East, a point on the boundary line common to Riverside and San Diego Counties.

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

Table 2 to Paragraph (b)—Additional RFG Covered Areas Under 42 U.S.C. 7545(k)(10)(D)

Area designation	State or district	Counties	Independent cities
Washington, DC-Maryland-Virginia	District of Columbia	Washington
	Maryland	Calvert, Charles, Frederick, Montgomery, Prince George's
	Virginia	Arlington, Fairfax, Loudoun, Prince William, Stafford	Alexandria, Fairfax, Falls Church, 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)—RFG Covered Areas Under 42 U.S.C. 7545(k)(6)(A)(i)

Area designation at the time of opt-in	State	Counties	Independent cities
Sussex County	Delaware	Sussex
St. Louis, Missouri-Illinois	Illinois	Jersey, Madison, Monroe, St. Clair
	Missouri	Franklin, Jefferson, St. Charles, St. Louis	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, Rockingham Counties	New Hampshire	Hillsborough, Merrimack, Rockingham, Strafford
Atlantic City	New Jersey	Atlantic, Cape May
New Jersey portion of Allentown- Bethlehem-Easton	New Jersey	Warren
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 News (Hampton Roads)	Virginia	James City, York	Chesapeake, Hampton, Newport News, Norfolk, Poquoson, Portsmouth, Suffolk, Virginia Beach, Williamsburg.
Richmond	Virginia	Charles City, Chesterfield, Hanover, Henrico	Colonial Heights, Hopewell, Richmond.
1 In Bullitt County, KY, beginning at the intersection of Ky 1020 and the Jefferson-Bullitt County Line proceeding to the east along the county line to the intersection of county road 567 and the Jefferson-Bullitt County Line; proceeding south on county road 567 to the junction with Ky 1116 (also known as Zoneton Road); proceeding to the south on KY 1116 to the junction with Hebron Lane; proceeding to the south on Hebron Lane to Cedar Creek; proceeding south on Cedar Creek to the confluence of Floyds Fork turning southeast along a creek that meets Ky 44 at Stallings Cemetery; proceeding west along Ky 44 to the eastern most point in the Shepherdsville city limits; proceeding south along the Shepherdsville city limits to the Salt River and west to a point across the river from Mooney Lane; proceeding south along Mooney Lane to the junction of Ky 480; proceeding west on Ky 480 to the junction with Ky 2237; proceeding south on Ky 2237 to the junction with Ky 61 and proceeding north on Ky 61 to the junction with Ky 1494; proceeding south on Ky 1494 to the junction with the perimeter of the Fort Knox Military Reservation; proceeding north along the military reservation perimeter to Castleman Branch Road; proceeding north on Castleman Branch Road to Ky 44; proceeding a very short distance west on Ky 44 to a junction with Ky 1020 and proceeding north on Ky 1020 to the beginning.
2 In Oldham County, KY, beginning at the intersection of the Oldham-Jefferson County Line with the southbound lane of Interstate 71; proceeding to the northeast along the southbound lane of Interstate 71 to the intersection of Ky 329 and the southbound lane of Interstate 71; proceeding to the northwest on Ky 329 to the intersection of Zaring Road on Ky 329; proceeding to the east-northeast on Zaring Road to the junction of Cedar Point Road and Zaring Road; proceeding to the north-northeast on Cedar Point Road to the junction of Ky 393 and Cedar Point Road; proceeding to the south-southeast on Ky 393 to the junction of county road 746 (the road on the north side of Reformatory Lake and the Reformatory); proceeding to the east-northeast on county road 746 to the junction with Dawkins Lane (also known as Saddlers Mill Road) and county road 746; Proceeding to follow an electric power line east-northeast across from the junction of county road 746 and Dawkins Lane to the east-northeast across Ky 53 on to the La Grange Water Filtration Plant; proceeding on to the east-southeast along the power line then south across Fort Pickens Road to a power substation on Ky 146; proceeding along the power line south across Ky 146 and the Seaboard System Railroad track to adjoin the incorporated city limits of La Grange; then proceeding east then south along the La Grange city limits to a point abutting the north side of Ky 712; proceeding east-southeast on Ky 712 to the junction of Massie School Road and Ky 712; proceeding to the south-southwest and then north-northwest on Massie School Road to the junction of Ky 53 and Massie School Road; proceeding on Ky 53 to the north-northwest to the junction of Moody Lane and Ky 53; proceeding on Moody Lane to the south-southwest until meeting the city limits of La Grange; then briefly proceeding north following the La Grange city limits to the intersection of the northbound lane of Interstate 71 and the La Grange city limits; proceeding southwest on the northbound lane of Interstate 71 until intersecting with the North Fork of Currys Fork; proceeding south-southwest beyond the confluence of Currys Fork to the south-southwest beyond the confluence of Floyds Fork continuing on to the Oldham-Jefferson County Line and proceeding northwest along the Oldham-Jefferson County Line to the beginning.

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

Table 4 to Paragraph (d)—RFG Covered Areas Under 42 U.S.C. 7545(k)(6)(B)(i)(I)

State	Counties
Maine	Androscoggin, Cumberland, Kennebec, Knox, Lincoln, Sagadahoc, York.

§ 1090.290

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

(a) New RFG covered areas. (1) Effective 1 year after an area has been reclassified as a Severe ozone nonattainment area under 42 U.S.C. 7511(b), such Severe area will become a covered area under the RFG program as required by 42 U.S.C. 7545(k)(10)(D). The geographic extent of each such covered area must be the nonattainment area boundaries as specified in 40 CFR part 81, subpart C, for the ozone NAAQS that was the subject of the reclassification.

(2) Any classified ozone nonattainment area identified in 40 CFR part 81, subpart C, as Marginal, Moderate, Serious, or Severe may be included as a covered area upon the request of the governor of the state in which the area is located. EPA must do all the following:

(i) Publish the governor's request in the Federal Register upon receipt.

(ii) Establish an effective date that is not later than 1 year after the request is received unless EPA determines that there is insufficient capacity to supply RFG as required by 42 U.S.C. 7545(k)(6)(A)(ii).

(3) Any ozone attainment area in the ozone transport region established by 42 U.S.C. 7511c(a) may be included as a covered area upon petition by the governor of the state in which the area is located as required by 42 U.S.C. 7545(k)(6)(B)(i). EPA must do all the following:

(i) Publish the governor's request in the Federal Register as soon as practicable after it is received.

(ii) Establish an effective date that is not later than 180 days after the request is received unless EPA determines that there is insufficient capacity to supply RFG as required by 42 U.S.C. 7545(k)(6)(B)(iii).

(b) Opting out of RFG. Any area that opted into RFG under 42 U.S.C. 7545(k)(6)(A) or (B) and has not subsequently been reclassified as a Severe ozone nonattainment area may opt out of RFG using the opt-out procedure in paragraph (d) of this section.

(c) Eligibility for opting out of RFG. The governor of the state in which a covered area under 42 U.S.C. 7545(k)(10)(D) is located may request that EPA remove the prohibition specified in 42 U.S.C. 7545(k)(5) in such area by following the opt-out procedure specified in paragraph (d) of this section upon one of the following:

(1) Redesignation to attainment for such area for the most stringent ozone NAAQS in effect at the time of redesignation.

(2) Designation as an attainment area for the most stringent ozone NAAQS in effect at the time of the designation. The area must also be redesignated to attainment for the prior ozone NAAQS.

(d) Procedure for opting out of RFG. EPA may approve a request from a state asking for either the removal of an RFG opt-in area (or portion of an RFG opt-in area), or the removal of a covered area (or portion of a covered area) under 42 U.S.C. 7545(k)(10)(D) that meets the criteria in paragraph (c) of this section, from the list of RFG covered areas in § 1090.285 if it meets the requirements of paragraph (d)(1) of this section. If EPA approves such a request, an effective date will be set as specified in paragraph (d)(2) of this section. EPA will notify the state in writing of EPA's action on the request and the effective date of the removal when the request is approved.

(1) An opt-out request must be signed by the governor of a state, or the governor's authorized representative, and must include all the following:

(i) A geographic description of each RFG area (or portion of each RFG area) that is covered by the request.

(ii) A description of all the means in which emissions reductions from RFG are relied upon in any approved SIP or any submitted SIP that has not yet been approved by EPA.

(iii) For an RFG area covered by the request where emissions reductions from RFG are relied upon as specified in paragraph (d)(1)(ii) of this section, the request must include all the following information:

(A) Identify whether the state is withdrawing any submitted SIP that has not yet been approved.

(B)(1) Identify whether the state intends to submit a SIP revision to any approved SIP or any submitted SIP that has not yet been approved, which relies on emissions reductions from RFG, and describe any control measures that the state plans to submit to EPA for approval to replace the emissions reductions from RFG.

(2) A description of the state's plans and schedule for adopting and submitting any revision to any approved SIP or any submitted SIP that has not yet been approved.

(C) If the state is not withdrawing any submitted SIP that has not yet been approved and does not intend to submit a revision to any approved SIP or any submitted SIP that has not yet been approved, describe why no revision is necessary.

(iv) The governor of a state, or the governor's authorized representative, must submit additional information upon request by EPA.

(2)(i) Except as specified in paragraph (d)(2)(ii) of this section, EPA will set an effective date of the RFG opt-out as requested by the governor, or the governor's authorized representative, but no less than 90 days from EPA's written notification to the state approving the RFG opt-out request.

(ii) Where emissions reductions from RFG are included in an approved SIP or any submitted SIP that has not yet been approved, other than as a contingency measure consisting of a future opt-in to RFG, EPA will set an effective date of the RFG opt-out as requested by the governor, or the governor's authorized representative, but no less than 90 days from the effective date of EPA approval of the SIP revision that removes the emissions reductions from RFG, and, if necessary, provides emissions reductions to make up for those from RFG opt-out.

(iii) Notwithstanding the provisions of paragraphs (d)(2)(i) and (ii) of this section, for an area in the ozone transport region that opted into RFG under 42 U.S.C. 7545(k)(6)(B), EPA will not set the effective date for removal of the area earlier than 4 years after the commencement date of opt-in.

(4) EPA will publish a notice in the Federal Register announcing the approval of an RFG opt-out request and its effective date.

(5) Upon the effective date for the removal of an RFG area (or portion of an RFG area) included in an approved request, such geographic area will no longer be considered an RFG covered area.

(e) Revising list of RFG covered areas. EPA will periodically publish a final rule revising the list of RFG covered areas in § 1090.285.

§ 1090.295

Procedures for relaxing the federal 7.8 psi RVP standard.

(a) EPA may approve a request from a state asking for relaxation of the federal 7.8 psi RVP standard for any area (or portion of an area) required to use such gasoline, if it meets the requirements of paragraph (b) of this section. If EPA approves such a request, an effective date will be set as specified in paragraph (c) of this section. EPA will notify the state in writing of EPA's action on the request and the effective date of the relaxation when the request is approved.

(b) The request must be signed by the governor of the state, or the governor's authorized representative, and must include all the following:

(1) A geographic description of each federal 7.8 psi gasoline area (or portion of such area) that is covered by the request.

(2) A description of all the means in which emissions reduction from the federal 7.8 psi gasoline are relied upon in any approved SIP or in any submitted SIP that has not yet been approved by EPA.

(3) For any federal 7.8 psi gasoline area covered by the request where emissions reductions from the federal 7.8 psi gasoline are relied upon as specified in paragraph (b)(2) of this section, the request must include the following information:

(i) Identify whether the state is withdrawing any submitted SIP that has not yet been approved.

(ii)(A) Identify whether the state intends to submit a SIP revision to any approved SIP or any submitted SIP that has not yet been approved, which relies on emissions reductions from federal 7.8 psi gasoline, and describe any control measures that the state plans to submit to EPA for approval to replace the emissions reductions from federal 7.8 psi gasoline.

(B) A description of the state's plans and schedule for adopting and submitting any revision to any approved SIP or any submitted SIP that has not yet been approved.

(iii) If the state is not withdrawing any submitted SIP that has not yet been approved and does not intend to submit a revision to any approved SIP or any submitted SIP that has not yet been approved, describe why no revision is necessary.

(4) The governor of a state, or the governor's authorized representative, must submit additional information upon request by EPA.

(c)(1) Except as specified in paragraph (c)(2) of this section, EPA will set an effective date of the relaxation of the federal 7.8 psi RVP standard as requested by the governor, or the governor's authorized representative, but no less than 90 days from EPA's written notification to the state approving the relaxation request.

(2) Where emissions reductions from the federal 7.8 psi gasoline are included in an approved SIP or any submitted SIP that has not yet been approved, EPA will set an effective date of the relaxation of the federal 7.8 psi RVP standard as requested by the governor, or the governor's authorized representative, but no less than 90 days from the effective date of EPA approval of the SIP revision that removes the emissions reductions from the federal 7.8 psi gasoline, and, if necessary, provides emissions reductions to make up for those from the federal 7.8 psi gasoline relaxation.

(d) EPA will publish a notice in the Federal Register announcing the approval of any federal 7.8 psi gasoline relaxation request and its effective date.

(e) Upon the effective date for the relaxation of the federal 7.8 psi RVP standard in a subject area (or portion of a subject area) included in an approved request, such geographic area will no longer be considered a federal 7.8 psi gasoline area.

(f) EPA will periodically publish a final rule revising the list of areas subject to the federal 7.8 psi RVP standard in § 1090.215(a)(2).

Subpart D—Diesel Fuel and ECA Marine Fuel Standards

§ 1090.300

Overview and general requirements.

(a) Diesel fuel is subject to the ULSD standards in § 1090.305, except as follows:

(1) Alternative sulfur standards apply for 500 ppm LM diesel fuel and ECA marine fuel as specified in §§ 1090.320 and 1090.325, respectively.

(2) Exemption provisions apply as specified in subpart G of this part.

(b) Diesel fuel additives must meet the requirements in § 1090.310.

(c) A diesel fuel manufacturer or diesel fuel additive manufacturer must demonstrate compliance with the standards in this subpart by measuring fuel parameters in accordance with subpart N of this part.

(d) All the standards in this part apply to diesel fuel and diesel fuel additives on a per-gallon basis.

(e)(1) No person may produce, import, sell, offer for sale, distribute, offer to distribute, supply, offer for supply, dispense, store, transport, or introduce into commerce any diesel fuel, ECA marine fuel, or diesel fuel additive that does not meet any standard set forth in this subpart.

(2) Notwithstanding paragraph (e)(1) of this section, an importer may import diesel fuel that does not comply with the standards set forth in this subpart if all the following conditions are met:

(i) The importer offloads the imported diesel fuel into one or more tanks that are physically located at the same import facility at which the imported diesel fuel first arrives in the United States or at a facility to which the imported diesel fuel is directly transported from the import facility at which the imported diesel fuel first arrived in the United States.

(ii) The importer uses the imported diesel fuel to produce one or more new batches of diesel fuel.

(iii) The importer certifies each new batch of diesel fuel under § 1090.1000(c) and demonstrates that it complies with the standards in this subpart by measuring fuel parameters in accordance with subpart N of this part before custody or title to each new batch of diesel fuel is transferred.

(f) No fuel or fuel additive manufacturer may introduce into commerce diesel fuel or diesel fuel additives that are not “substantially similar” under 42 U.S.C. 7545(f)(1) or permitted under a waiver granted under 42 U.S.C. 7545(f)(4).

(g) Distillate global marine fuel that does not qualify for an exemption under § 1090.650 is subject to the standards, requirements, and prohibitions that apply for ULSD under this part.

(h) No person may introduce used motor oil, or used motor oil blended with diesel fuel, into the fuel system of model year 2007 or later diesel motor vehicles or engines or model year 2011 or later nonroad diesel vehicles or engines (not including locomotive or marine diesel engines).

§ 1090.305

ULSD standards.

(a) Overview. Except as specified in § 1090.300(a), diesel fuel must meet the ULSD per-gallon standards of this section.

(b) Sulfur standard. Maximum sulfur content of 15 ppm.

(c) Cetane index or aromatic content. Diesel fuel must meet one of the following standards:

(1) Minimum cetane index of 40.

(2) Maximum aromatic content of 35 volume percent.

§ 1090.310

Diesel fuel additives standards.

(a) Except as specified in paragraph (b) and (c) of this section, diesel fuel additives blended into diesel fuel that is subject to the standards in § 1090.305 must have a sulfur concentration less than or equal to 15 ppm on a per-gallon basis.

(b) Diesel fuel additives do not have to comply with paragraph (a) of this section if all the following conditions are met:

(1) The additive is added to diesel fuel in a quantity less than 1.0 volume percent of the resultant mixture of additive and diesel fuel.

(2) The PTD for the diesel fuel additive complies with the requirements in § 1090.1120(b).

(3) The additive is not commercially available as a retail product for ultimate consumers.

(c) The provisions of this section do not apply to additives used with 500 ppm LM diesel fuel or ECA marine fuel.

§ 1090.315

Heating oil, kerosene, ECA marine fuel, and jet fuel provisions.

Heating oil, kerosene, ECA marine fuel, and jet fuel must not be sold for use in motor vehicles or nonroad equipment and are not subject to the ULSD standards in § 1090.305 unless also designated as ULSD under § 1090.1015(a).

§ 1090.320

500 ppm LM diesel fuel standards.

(a) Overview. 500 ppm LM diesel fuel produced or distributed by a transmix processor or pipeline operator under § 1090.515 must meet the per-gallon standards of this section.

(b) Sulfur standard. Maximum sulfur content of 500 ppm.

(c) Cetane index or aromatic content. The standard for cetane index or aromatic content in § 1090.305(c).

§ 1090.325

ECA marine fuel standards.

(a) Overview. Except as specified in paragraph (c) of this section, ECA marine fuel must meet the per-gallon standards of this section.

(b) Sulfur standard. Maximum sulfur content of 1,000 ppm.

(c) Exceptions. The standards in paragraph (b) of this section do not apply to the following:

(1) Residual fuel made available for use in a steamship or C3 marine vessel if the U.S. government exempts or excludes the vessel from MARPOL Annex VI fuel standards. Diesel fuel and other distillate fuel used in diesel engines operated on such vessels is subject to the standards in this section instead of the standards in § 1090.305 or § 1090.320.

(2) Distillate global marine fuel that is exempt under § 1090.650.

Subpart E—Reserved

Subpart F—Transmix and Pipeline Interface Provisions

§ 1090.500

Gasoline produced from blending transmix into PCG.

(a) Applicability. (1) Except as specified in paragraph (a)(2) of this section, a transmix blender that blends transmix into PCG must comply with the requirements of this section.

(2) Small volumes of fuel that are captured in pipeline sumps or trapped in pipeline pumps or valve manifolds and that are injected back into batches of gasoline or diesel fuel are exempt from the requirements in this section.

(b) Requirements. (1) The distillation end-point of the resultant transmix-blended gasoline must not exceed 437 degrees Fahrenheit.

(2) The resultant transmix-blended gasoline must meet the downstream sulfur per-gallon standard in § 1090.205(c) and the applicable RVP standard in § 1090.215.

(3) The transmix blender must comply with the recordkeeping requirements in § 1090.1255.

(4) The transmix blender must maintain and follow a written quality assurance program that meets the requirements of paragraph (c) of this section.

(5) In the event that the test result for any sample collected under the quality assurance program specified in paragraph (c) of this section indicates that the gasoline does not comply with any of the applicable standards in this part, the transmix blender must do all the following:

(i) Immediately take steps to stop the sale of the gasoline that was sampled.

(ii) Take reasonable steps to determine the cause of the noncompliance and prevent future instances of noncompliance.

(iii) Notify EPA of the noncompliance.

(iv) If the transmix was blended by a computer controlled in-line blending system, increase the rate of sampling and testing to a minimum frequency of once per week and a maximum frequency of once per day and continue the increased frequency of sampling and testing until the results of 10 consecutive samples and tests indicate that the gasoline complies with applicable standards, at which time the sampling and testing may be conducted at the original frequency.

(c) Quality assurance program. (1) The quality assurance program must be designed to assure that the type and amount of transmix blended into PCG will not cause violations of the applicable fuel quality standards.

(2) Except as specified in paragraph (c)(3) of this section, as a part of the quality assurance program, a transmix blender must collect samples of gasoline after blending transmix and test the samples to ensure the end-point temperature of the resultant transmix-blended gasoline does not exceed 437 degrees Fahrenheit, using one of the following sampling methods:

(i) For transmix that is blended in a tank (including a tank on a barge), collect a representative sample of the resultant transmix-blended gasoline following each occasion transmix is blended.

(ii) For transmix that is blended by a computer controlled in-line blending system, the transmix blender must collect composite samples of the resultant transmix-blended gasoline at least twice each calendar month during which transmix is blended.

(3) Any transmix blender may petition EPA for approval of a quality assurance program that does not include the minimum sampling and testing requirements of paragraph (c)(2) of this section. To seek approval for such an alternative quality assurance program, the transmix blender must submit a petition to EPA that includes all the following:

(i) A detailed description of the quality assurance procedures to be carried out at each location where transmix is blended into PCG, including a description of how the transmix blender proposes to determine the ratio of transmix that can be blended with PCG without violating any of the applicable standards in this part, and a description of how the transmix blender proposes to determine that the gasoline produced by the transmix blending operation meets the applicable standards.

(ii) A letter signed by the RCO or their delegate stating that the information contained in the submission is true to the best of their belief must accompany the petition.

(iii) A transmix blender that petitions EPA to use an alternative quality assurance program must comply with any request by EPA for additional information or any other requirements that EPA includes as part of EPA's evaluation of the petition. However, the transmix blender may withdraw their petition or approved use of an alternative quality assurance program at any time, upon notice to EPA.

§ 1090.505

Gasoline produced from TGP.

(a) General provisions. (1) A transmix processor or blending manufacturer that produces gasoline from TGP must meet the requirements of this section.

(2) A transmix processor must not use any feedstock other than transmix to produce TGP.

(3) A transmix processor or blending manufacturer may produce gasoline using only TGP, a combination of TGP and PCG, a combination of TGP and blendstock(s), or a combination TGP, PCG, and blendstock(s) under the provisions of this section. A transmix processor or blending manufacturer may also blend fuel additives into gasoline in accordance with §§ 1090.260 and 1090.265.

(b) Demonstration of compliance with sulfur per-gallon standard. (1) A transmix processor or blending manufacturer that produces gasoline with TGP must meet one of the following sulfur standards for each batch of gasoline they produce, as applicable:

(i) Each batch of gasoline produced from only TGP or both TGP and PCG must comply with the downstream sulfur per-gallon standard in § 1090.205(c).

(ii) Each batch of gasoline produced from a combination of TGP and any blendstock must comply with the fuel manufacturing facility gate sulfur per-gallon standard in § 1090.205(b).

(2) A transmix processor or blending manufacturer that produces gasoline with TGP must demonstrate compliance with the applicable sulfur standard in paragraph (b)(1) of this section by measuring the sulfur content of each batch of gasoline they produce in accordance with subpart N of this part.

(c) Demonstration of compliance with sulfur and benzene average standards. (1) A transmix processor or blending manufacturer that produces gasoline with TGP must exclude TGP and PCG used to produce gasoline under the provisions of this section from their compliance calculations to demonstrate compliance with the sulfur and benzene average standards in §§ 1090.205(a) and 1090.210(a) and (b), respectively. A transmix processor or blending manufacturer that exclusively produces gasoline from only TGP or both TGP and PCG is deemed to be in compliance with the sulfur and benzene average standards in §§ 1090.205(a) and 1090.210(a) and (b), respectively.

(2) A transmix processor or blending manufacturer that produces gasoline with TGP must include all blendstocks other than TGP and PCG in their compliance calculations to demonstrate compliance with the sulfur and benzene average standards in §§ 1090.205(a) and 1090.210(a) and (b), respectively.

(3) A transmix processor or blending manufacturer that produces gasoline by adding blendstock to TGP must comply with § 1090.1325.

(d) Demonstration of compliance with RVP standard. A transmix processor or blending manufacturer that produces gasoline with TGP must demonstrate that each batch of gasoline they produce meets the applicable RVP standard in § 1090.215 by measuring the RVP of each batch in accordance with subpart N of this part.

(e) Distillation point determination. A transmix processor or blending manufacturer that produces gasoline with TGP must determine the following distillation parameters for each batch of gasoline they produce in accordance with subpart N of this part:

(1) T10.

(2) T50.

(3) T90.

(4) End-point.

(5) Distillation residue.

§ 1090.510

Diesel and distillate fuel produced from TDP.

(a) A transmix processor must not use any feedstock other than transmix to produce TDP.

(b) A transmix processor must demonstrate that each batch of diesel fuel or distillate fuel produced from TDP meets the applicable standard in subpart D of this part and must comply with all other requirements applicable to a diesel fuel or distillate fuel manufacturer under this part.

(c) A transmix processor that produces 500 ppm LM diesel fuel from TDP must also comply with the requirements in § 1090.515.

§ 1090.515

500 ppm LM diesel fuel produced from TDP.

(a) Applicability. A transmix processor that produces 500 ppm LM diesel fuel from TDP must comply with the requirements of this section and the standards for 500 ppm LM diesel fuel specified in § 1090.320.

(b) Blending component limitation. A transmix processor may only use the following components to produce 500 ppm LM diesel fuel:

(1) TDP.

(2) ULSD.

(3) Diesel fuel additives that comply with the requirements in § 1090.310.

(c) Volume requirements. A party that handles 500 ppm LM diesel fuel must calculate the volume of 500 ppm LM diesel fuel received versus the volume delivered and used on a compliance period basis. An increase in the volume of 500 ppm LM diesel fuel delivered compared to the volume received must be due solely to one or more of the following:

(1) Normal pipeline interface cutting practices under paragraph (e)(1) of this section.

(2) The addition of ULSD to a retail outlet or WPC 500 ppm LM diesel fuel storage tank under paragraph (e)(2) of this section.

(d) Use restrictions. 500 ppm LM diesel fuel may only be used in locomotive or marine engines that are not required to use ULSD under 40 CFR 1033.815 or 40 CFR 1042.660, respectively. No person may use 500 ppm LM diesel fuel in locomotive or marine engines that are required to use ULSD, in any nonroad vehicle or engine, or in any motor vehicle engine.

(e) Segregation requirement. A transmix processor or distributor must segregate 500 ppm LM diesel fuel from other fuels except as follows:

(1) A pipeline operator may ship 500 ppm LM diesel fuel by pipeline provided that the 500 ppm LM diesel fuel does not come into physical contact in the pipeline with distillate fuels that have a sulfur content greater than 15 ppm. If 500 ppm LM diesel fuel is shipped by pipeline adjacent to ULSD, the pipeline operator must cut ULSD into the 500 ppm LM diesel fuel.

(2) A WPC or retailer of 500 ppm LM diesel fuel may introduce ULSD into a storage tank that contains 500 ppm LM diesel fuel, provided that the other requirements of this section are satisfied. The resultant mixture must be designated as 500 ppm LM diesel fuel.

(f) Party limit. No more than 4 separate parties may handle the 500 ppm LM diesel fuel between the producer and the ultimate consumer.

(g) Compliance plan. For each facility, a transmix processor that produces 500 ppm LM diesel fuel must obtain approval from EPA for a compliance plan at least 60 days prior to producing 500 ppm LM diesel fuel. The compliance plan must detail how the transmix processor intends to meet all the following requirements:

(1) Demonstrate how the 500 ppm LM diesel fuel will be segregated by the producer through to the ultimate consumer from fuel having other designations in order to comply with the segregation requirement in paragraph (e) of this section.

(2) Demonstrate that the end users of 500 ppm LM diesel fuel will also have access to ULSD for use in those engines that require ULSD.

(3) Identify the parties that will handle the 500 ppm LM diesel fuel through to the ultimate consumer.

(4) Identify all ultimate consumers that will be supplied with the 500 ppm LM diesel fuel.

(5) Demonstrate how misfueling of 500 ppm LM diesel fuel into vehicles, engines, or equipment that require the use of ULSD will be prevented.

(6) Include an EPA registration number.

§ 1090.520

Handling practices for pipeline interface that is not transmix.

(a) Subject to the limitations in paragraph (b) of this section, a pipeline operator may cut pipeline interface from two batches of gasoline subject to EPA standards that are shipped adjacent to each other by pipeline into either or both these batches of gasoline provided that this action does not cause or contribute to a violation of the standards in this part.

(b) During the summer season, a pipeline operator must not cut pipeline interface from two batches of gasoline subject to different RVP standards that are shipped adjacent to each other by pipeline into the gasoline batch that is subject to the more stringent RVP standard. For example, during the summer season, a pipeline operator must not cut pipeline interface from a batch of RFG shipped adjacent to a batch of conventional gasoline into the batch of RFG.

Subpart G—Exemptions, Hardships, and Special Provisions

§ 1090.600

General provisions.

(a) Gasoline, diesel fuel, or IMO marine fuel subject to an exemption under this subpart is exempt from the standards and provisions of this part as specified in this subpart.

(b) Fuel that does not meet all the requirements and conditions specified in this subpart for an exemption is subject to all applicable standards and requirements of this part.

§ 1090.605

National security and military use exemptions.

(a) Fuel, fuel additive, and regulated blendstock that is produced, imported, sold, offered for sale, supplied, offered for supply, stored, dispensed, or transported for use in the following tactical military vehicles, engines, or equipment, including locomotive and marine engines, are exempt from the standards specified in this part:

(1) Tactical military vehicles, engines, or equipment, including locomotive or marine engines, that have an EPA national security exemption from the motor vehicle emission standards under 40 CFR parts 85 or 86, or from the nonroad engine emission standards under 40 CFR parts 89, 92, 94, 1042, or 1068.

(2) Tactical military vehicles, engines, or equipment, including locomotive or marine engines, that are not subject to a national security exemption from vehicle or engine emissions standards specified in paragraph (a)(1) of this section but, for national security purposes (e.g., for purposes of readiness, including training, for deployment overseas), need to be fueled on the same fuel as the vehicles, engines, or equipment that EPA has granted such a national security exemption.

(b) The exempt fuel must meet all the following requirements:

(1) It must be accompanied by PTDs that meet the requirements of subpart L of this part.

(2) It must be segregated from non-exempt fuel at all points in the distribution system.

(3) It must be dispensed from a fuel dispenser stand, fueling truck, or tank that is labeled with the appropriate designation of the fuel.

(4) It must not be used in any vehicles, engines, or equipment, including locomotive and marine engines, other than those specified in paragraph (a) of this section.

§ 1090.610

Temporary research, development, and testing exemptions.

(a) Requests for an exemption. (1) Any person may receive an exemption from the provisions of this part for fuel used for research, development, or testing (“R&D”) purposes by submitting the information specified in paragraph (c) of this section as specified in § 1090.10.

(2) Any person that is performing emissions certification testing for a motor vehicle or motor vehicle engine under 42 U.S.C. 7525 or nonroad engine or nonroad vehicle under 42 U.S.C. 7546 is exempt from the provisions of this part for the fuel they are using for emissions certification testing if they have an exemption under 40 CFR parts 85 and 86 to perform such testing.

(b) Criteria for an R&D exemption. For an R&D exemption to be granted, the person requesting an exemption must meet all the following conditions:

(1) Demonstrate that the exemption is for an appropriate R&D purpose.

(2) Demonstrate that an exemption is necessary.

(3) Design an R&D program that is reasonable in scope.

(4) Have a degree of control consistent with the purpose of the program and EPA's monitoring requirements.

(5) Meet the requirements specified in paragraphs (c) and (d) of this section.

(c) Information required to be submitted. To aid in demonstrating each of the elements in paragraph (b) of this section, the person requesting an exemption must include, at a minimum, all the following information:

(1) A concise statement of the purpose of the program demonstrating that the program has an appropriate R&D purpose.

(2) An explanation of why the stated purpose of the program is unable to be achieved in a practicable manner without meeting the requirements of this part.

(3) A demonstration of the reasonableness of the scope of the program, including all the following:

(i) An estimate of the program's duration in time (including beginning and ending dates).

(ii) An estimate of the maximum number of vehicles, engines, and equipment involved in the program, and the number of miles and engine hours that will be accumulated on each.

(iii) The manner in which the information on vehicles, engines, or equipment used in the program will be recorded and made available to EPA upon request.

(iv) The quantity of the fuel that does not comply with the requirements of this part, as applicable.

(v) The specific applicable standard(s) of this part that would apply to the fuel expected to be used in the program.

(4) With regard to control, a demonstration that the program affords EPA a monitoring capability, including all the following:

(i) A description of the technical and operational aspects of the program.

(ii) The site(s) of the program (including facility name, street address, city, county, state, and ZIP code).

(iii) The manner in which information on vehicles, engines, and equipment used in the program will be recorded and made available to EPA upon request.

(iv) The manner in which information on the fuel used in the program (including quantity, fuel properties, name, address, telephone number, and contact person of the supplier, and the date received from the supplier) will be recorded and made available to EPA upon request.

(v) The manner in which the party will ensure that the fuel will be segregated from fuel that meets the requirements of subparts C and D of this part, as applicable, and how fuel dispensers will be labeled to ensure that the fuel is not dispensed for use in motor vehicles or nonroad engines, vehicles, or equipment, including locomotive or marine engines, that are part of the R&D test program.

(vi) The name, business address, telephone number, and title of the person(s) in the organization requesting an exemption from whom further information on the application may be obtained.

(vii) The name, business address, telephone number, and title of the person(s) in the organization requesting an exemption who is responsible for recording and making available the information specified in this paragraph (c), and the location where such information will be maintained.

(viii) Any other information requested by EPA to determine whether the test program satisfies the criteria of paragraph (b) of this section.

(d) Additional requirements. (1) The PTDs associated with fuel must comply with the requirements of subpart L of this part.

(2) The fuel must be designated as exempt fuel by the fuel manufacturer or supplier, as applicable.

(3) The fuel must be kept segregated from non-exempt fuel at all points in the distribution system.

(4) The fuel must not be sold, distributed, offered for sale or distribution, dispensed, supplied, offered for supply, transported to or from, or stored by a retail outlet or WPC facility, unless the WPC facility is associated with the R&D program that uses the fuel.

(5) At the completion of the program, any emission control systems or elements of design that are damaged or rendered inoperative must be replaced on vehicles remaining in service or the responsible person will be liable for a violation of 42 U.S.C. 7522(a)(3), unless sufficient evidence is supplied that the emission controls or elements of design were not damaged.

(e) Approval of exemption. EPA may grant an R&D exemption upon a demonstration that the requirements of this section have been met. The R&D exemption approval may include such terms and conditions as EPA determines necessary to monitor the exemption and to carry out the purposes of this part, including restoration of emission control systems.

(1) The volume of fuel subject to the approval must not exceed the estimated amount in paragraph (c)(3)(iv) of this section, unless EPA grants an approval for a greater amount.

(2) Any exemption granted under this section will expire at the completion of the test program or 1 year from the date of approval, whichever occurs first, and may only be extended upon re-application consistent with the requirements of this section.

(3) If any information required by paragraph (c) of this section changes after approval of the exemption, the responsible person must notify EPA in writing immediately.

(f) Notification of completion. Any person with an approved exemption under this section must notify EPA in writing within 30 days after completion of the R&D program.

§ 1090.615

Racing and aviation exemptions.

(a) Fuel, fuel additive, and regulated blendstock that is used in aircraft, or racing vehicles or racing boats in sanctioned racing events, is exempt from the standards in subparts C and D of this part if all the requirements of this section are met.

(b) The fuel, fuel additive, or regulated blendstock is identified on PTDs and on any fuel dispenser from which the fuel, fuel additive, or regulated blendstock is dispensed as restricted for use either in aircraft or in racing motor vehicles or racing boats that are used only in sanctioned racing events.

(c) The fuel, fuel additive, or regulated blendstock is completely segregated from all other non-exempt fuel, fuel additive, or regulated blendstock throughout production, distribution, and sale to the ultimate consumer.

(d) The fuel, fuel additive, or regulated blendstock is not made available for use as gasoline or diesel fuel subject to the standards in subparts C and D of this part, as applicable, or dispensed for use in motor vehicles or nonroad engines, vehicles, or equipment, including locomotive or marine engines, except for those used only in aircraft or in sanctioned racing events.

§ 1090.620

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

Fuel that is produced, imported, sold, offered for sale, supplied, offered for supply, stored, dispensed, or transported for use in the territories of Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands, is exempt from the standards in subparts C and D of this part if all the following requirements are met:

(a) The fuel is designated by the fuel manufacturer as gasoline, diesel fuel, or ECA marine fuel for use only in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands.

(b) The fuel is used only in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands.

(c) The fuel is accompanied by PTDs that meet the requirements of subpart L of this part.

(d) The fuel is completely segregated from non-exempt fuel at all points from the point the fuel is designated as exempt fuel for use only in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands, while the exempt fuel is in the United States (including an ECA or an ECA associated area under 40 CFR 1043.20) but outside these territories.

§ 1090.625

Exemptions for California gasoline and diesel fuel.

(a) California gasoline and diesel fuel exemption. California gasoline or diesel fuel that complies with all the requirements of this section is exempt from all other provisions of this part.

(b) California gasoline and diesel fuel requirements. (1) Each batch of California gasoline or diesel fuel must be designated as such by its fuel manufacturer.

(2) Designated California gasoline or diesel fuel must be segregated from fuel that is not California gasoline or diesel fuel at all points in the distribution system.

(3) Except for as specified in paragraph (d) or (e) of this section, designated California gasoline or diesel fuel must ultimately be used only in the state of California.

(4) Transferors and transferees of California gasoline or diesel fuel produced outside the state of California must meet the PTD requirements of subpart L of this part.

(5) Each transferor and transferee of California gasoline or diesel fuel produced outside the state of California must maintain copies of the PTDs as specified in subpart M of this part.

(6) California gasoline or diesel fuel must not be used in any part of the United States outside of the state of California unless the manufacturer or distributor recertifies or redesignates the batch of California gasoline or diesel fuel as specified in paragraph (d) or (e) of this section.

(c) Use of California test methods and offsite sampling procedures. For any gasoline or diesel fuel that is not California gasoline or diesel fuel and that is either produced at a facility located in the state of California or is imported from outside the United States into the state of California, the manufacturer must do one of the following:

(1) Comply with the sampling and testing provisions in subpart N of this part, as applicable.

(2) Sample and test using methods approved in Title 13 of the California Code of Regulations.

(3) Sample and test per a current and valid protocol agreement between the fuel manufacturer and the California Air Resources Board or by Executive Order from the California Air Resources Board. Such protocols or Executive Orders must be provided to EPA upon request.

(d) California gasoline used outside of California. California gasoline may be used in any part of the United States outside of the state of California if the manufacturer or distributor of the California gasoline does one of the following:

(1) Recertifies the California gasoline as gasoline under this part and includes the recertified gasoline in their average standard compliance calculations.

(2) Designates the California gasoline as gasoline under this part without recertification and does all the following:

(i) Demonstrates that the fuel meets all applicable requirements for California reformulated gasoline under Title 13 of the California Code of Regulations.

(ii) Properly redesignates the fuel under § 1090.1010(b)(2)(vi).

(iii) Generates PTDs under subpart L of this part.

(iv) Keeps records under subpart M of this part.

(v) Does not include the California gasoline in their average standard compliance calculations.

(e) California diesel used outside of California. California diesel fuel may be used in any part of the United States outside of the state of California and is deemed to meet the standards in subpart D of this part without recertification if the fuel designated as California diesel fuel meets all applicable requirements for diesel fuel under Title 13 of the California Code of Regulations and the manufacturer or distributor of the fuel does all the following:

(1) The manufacturer or distributor properly redesignates the fuel under § 1090.1015(b)(3)(iii).

(2) The manufacturer or distributor generates PTDs under subpart L of this part.

(3) The manufacturer or distributor keeps records under subpart M of this part.

§ 1090.630

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

Summer gasoline that is produced, imported, sold, offered for sale, supplied, offered for supply, stored, dispensed, or transported for use in the Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, is exempt from the RVP standards in § 1090.215 if all the following requirements are met:

(a) The summer gasoline is designated by the fuel manufacturer as summer gasoline for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands.

(b) The summer gasoline is used only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands.

(c) The summer gasoline is accompanied by PTDs that meet the requirements of subpart L of this part.

(d) The summer gasoline is completely segregated from non-exempt gasoline at all points from the point the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these states or territories.

§ 1090.635

Refinery extreme unforeseen hardship exemption.

(a) In appropriate extreme, unusual, and unforeseen circumstances (e.g., circumstances like a natural disaster or refinery fire; not financial or supplier difficulties) that are clearly outside the control of the refiner and that could not have been avoided by the exercise of prudence, diligence, and due care, EPA may permit a refiner, for a brief period, to distribute fuel that is exempt from the standards in subparts C and D of this part if all the following requirements are met:

(1) It is in the public interest to do so (e.g., distribution of the nonconforming fuel will not damage vehicles or engines and is necessary to meet projected temporary shortfalls in the supply of the fuel in a state or region of the United States for which the shortfall is unable to otherwise be compensated for).

(2) The refiner exercised prudent planning and was not able to avoid the violation and has taken all reasonable steps to minimize the extent of the nonconformity.

(3) The refiner shows how compliance will be achieved as expeditiously as possible.

(4) The refiner agrees to make up any air quality detriment associated with the nonconforming fuel, where practicable.

(5) The refiner pays to the U.S. Treasury an amount equal to the economic benefit of the nonconformity minus the amount expended under paragraph (a)(4) of this section, in making up the air quality detriment.

(b) Hardship applications under this section must be submitted to EPA as specified in § 1090.10 and must contain a letter signed by the RCO, or their delegate, stating that the information contained in the application is true and accurate to the best of their knowledge.

§ 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 § 1090.260.

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

§ 1090.645

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

(a) Fuel, fuel additive, and regulated blendstock that is exported for sale outside of the United States is exempt from the standards in subparts C and D of this part if all the following requirements are met:

(1) The fuel, fuel additive, or regulated blendstock is designated for export by the fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer.

(2) The fuel, fuel additive, or regulated blendstock designated for export is accompanied by PTDs that meet the requirements of subpart L of this part.

(3) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps records that demonstrate that the fuel, fuel additive, or regulated blendstock was ultimately exported from the United States.

(4) The fuel, fuel additive, or regulated blendstock is completely segregated from non-exempt fuels, fuel additives, and regulated blendstocks from the point the fuel, fuel additive, or regulated blendstock is designated for export to the point where it is ultimately exported from the United States.

(5) Fuel, fuel additive, or regulated blendstock certified and designated for export may be certified for use in the United States if all the applicable requirements of this part are met.

(b) Any fuel dispensed from a retail outlet within the geographic boundaries of the United States is not exempt under this section.

§ 1090.650

Distillate global marine fuel exemption.

(a) The standards of subpart D of this part do not apply to distillate global marine fuel that is produced, imported, sold, offered for sale, supplied, offered for supply, stored, dispensed, or transported for use in steamships or Category 3 marine vessels when operating outside of ECA boundaries.

(b) Exempt distillate global marine fuel under paragraph (a) of this section must meet all the following requirements:

(1) The fuel must not exceed 0.50 weight percent sulfur (5,000 ppm).

(2) The fuel must be accompanied by PTDs as specified in § 1090.1115.

(3) The fuel must be designated as specified in § 1090.1015.

(4) The fuel must be segregated from non-exempt fuel at all points in the distribution system.

(5) The fuel must not be used in vehicles, engines, or equipment other than those referred to in paragraph (a) of this section.

(c)(1) Fuel that does not meet the requirements specified in paragraph (b) of this section is subject to the standards, requirements, and prohibitions that apply for ULSD under this part.

(2) Any person who produces, imports, sells, offers for sale, supplies, offers for supply, stores, dispenses, or transports distillate global marine fuel without meeting the applicable recordkeeping requirements in subpart M of this part must not claim the fuel is exempt from the standards, requirements, and prohibitions that apply for ULSD under this part.

Subpart H—Averaging, Banking, and Trading Provisions

§ 1090.700

Compliance with average standards.

(a) Compliance with the sulfur average standard. For each of their facilities, a gasoline manufacturer must demonstrate compliance with the sulfur average standard in § 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:

CSV_y = S_tot,y + Ds,_(y−1) + D_{S_Oxy_Total} − C_S

Where:

CSV_y = Compliance sulfur value for compliance period y, in ppm-gallons.

S_tot,y = The total amount of sulfur produced in compliance period y, per paragraph (a)(1)(ii) of this section, in ppm-gallons.

Ds,_(y−1) = Sulfur deficit from the previous compliance period, per § 1090.715(a)(1), in ppm-gallons.

D_{S_Oxy_Total} = The total sulfur deficit from BOB recertification, per § 1090.740(b)(2), in ppm-gallons.

C_S = Sulfur credits used by the gasoline manufacturer, per § 1090.720, in ppm-gallons.

(ii) The total amount of sulfur produced is determined as follows:

Where:

V_i = The volume of gasoline produced or imported in batch i, in gallons.

S_i = 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 S_tot,y results in a negative number, replace it with zero.

(2) Sulfur compliance calculation. (i) Compliance with the sulfur average standard in § 1090.205(a) is achieved if the following equation is true:

(ii) Compliance with the sulfur average standard in § 1090.205(a) is not achieved if a deficit is incurred two or more consecutive years. A gasoline manufacturer incurs a deficit under § 1090.715 if the following equation is true:

(b) Compliance with the benzene average standards. For each of their facilities, a gasoline manufacturer must demonstrate compliance with the benzene average standard in § 1090.210(a) by using the equations in paragraphs (b)(1) and (2) of this section and with the maximum benzene average standard in § 1090.210(b) by using the equations in paragraphs (b)(3) and (4) of this section.

(1) Compliance benzene value calculation. (i) The compliance benzene value is determined as follows:

CBV_y = B_tot,y + D_Bz,(y−1) + D_{Bz_Oxy_Total} − C_Bz

Where:

CBV_y = Compliance benzene value for compliance period y, in benzene gallons.

B_tot,y = The total amount of benzene produced in compliance period y, per paragraph (b)(1)(ii) of this section, in benzene gallons.

D_Bz,(y−1) = Benzene deficit from the previous compliance period, per § 1090.715(a)(2), in benzene gallons.

D_{Bz_Oxy_Total} = The total benzene deficit from BOB recertification, per § 1090.740(b)(4), in benzene gallons.

C_Bz = Benzene credits used by the gasoline manufacturer, per § 1090.720, in benzene gallons.

(ii) The total amount of benzene produced is determined as follows:

V_i = The volume of gasoline produced or imported in batch i, in gallons.

B_i = The benzene content of batch i, in volume percent.

n = The number of batches of gasoline produced or imported during the compliance period.

i = Individual batch of gasoline produced or imported during the compliance period.

If the calculation of B_tot,y results in a negative number, replace it with zero.

(2) Benzene average compliance calculation. (i) Compliance with the benzene average standard in § 1090.210(a) is achieved if the following equation is true:

(ii) Compliance with the benzene average standard in § 1090.210(a) is not achieved if a deficit is incurred two or more consecutive years. A gasoline manufacturer incurs a deficit under § 1090.715 if the following equation is true:

(3) Average benzene concentration calculation. The average benzene concentration is determined as follows:

Where:

B_a,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 § 1090.210(b) is achieved for compliance period y if the following equation is true:

B_a,y ≤ 1.30 vol%

(5) Rounding and reporting benzene values. (i) The total amount of benzene produced, as calculated in paragraph (b)(1)(ii) of this section, must be rounded to the nearest whole benzene gallon in accordance with § 1090.50.

(ii) The average benzene concentration, as calculated in paragraph (b)(3) of this section, must be rounded and reported to two decimal places in accordance with § 1090.50.

(c) Accounting for oxygenate added at a downstream location. A gasoline manufacturer that complies with the requirements in § 1090.710 may include the volume of oxygenate added at a downstream location and the effects of such blending on sulfur content and benzene content in compliance calculations under this subpart.

(d) Inclusions. A gasoline manufacturer must include the following products that they produced or imported during the compliance period in their compliance calculations:

(1) CG.

(2) RFG.

(3) BOB.

(4) Added gasoline volume resulting from the production of gasoline from PCG as follows:

(i) For PCG by subtraction under § 1090.1320(a)(1), include the PCG batch as a batch with a negative volume, positive sulfur content, and positive benzene content and include the new batch of gasoline as a batch with a positive volume, positive sulfur content, and positive benzene content in compliance calculations under this section. Any negative compliance sulfur value or compliance benzene value must be reported as zero and not as a negative result.

(ii) For PCG by addition under § 1090.1320(a)(2), include only the blendstock added to make the new batch of gasoline as a batch with a positive volume, positive sulfur content, and positive benzene content in compliance calculations under this section. Do not include any test results or volumes for the PCG or new batch of gasoline in these calculations.

(5)(i) Inclusion of a particular batch of gasoline for compliance calculations for a compliance period is based on the date the batch is produced, not shipped. For example, a batch produced on December 30, 2021, but shipped on January 2, 2022, would be included in the compliance calculations for the 2021 compliance period. The volume included in the 2021 compliance period for that batch would be the entire batch volume, even though the shipment of all or some of the batch did not occur until 2022.

(ii) For PCG by subtraction under § 1090.1320(a)(1), include PCG in the compliance period in which it was blended with blendstock. This may necessitate reporting a portion of the volume of PCG received in one compliance period as a separate PCG batch in the following compliance period.

(e) Exclusions. A gasoline manufacturer must exclude the following products from their compliance calculations:

(1) Gasoline that was not produced by the gasoline manufacturer.

(2) Blendstock, unless the blendstock is added to PCG or TGP under § 1090.1320 or § 1090.1325, respectively.

(3) PCG, except as specified in paragraph (d)(4)(i) of this section.

(4) Certified butane and certified pentane blended under § 1090.1320(b).

(5) TGP.

(6) GTAB that meets the requirements in § 1090.1615(a).

(7) Gasoline imported by truck or rail using the provisions of § 1090.1610 to meet the alternative per-gallon standards of §§ 1090.205(d) and 1090.210(c).

(8) Gasoline exempt under subpart G of this part from the average standards of subpart C of this part (e.g., California gasoline, racing fuel, etc.).

§ 1090.705

Facility level compliance.

(a) Except as specified in paragraph (b) of this section, a gasoline manufacturer must comply with average standards at the individual facility level.

(b) A gasoline importer must comply with average standards at the company level, except that aggregation of all import facilities within a PADD as a single facility is required for compliance with the maximum benzene average standard in § 1090.210(b).

§ 1090.710

Downstream oxygenate accounting.

The requirements of this section apply to BOB for which a gasoline manufacturer accounts for the effects of the oxygenate blending that occurs downstream of the fuel manufacturing facility in the gasoline manufacturer's average standard compliance calculations under this subpart. This section also includes requirements for oxygenate blenders to ensure that oxygenate is added in accordance with the blending instructions specified by the gasoline manufacturer in order to ensure fuel quality standards are met.

(a) Provisions for gasoline manufacturers. In order to account for the effects of oxygenate blending downstream, a gasoline manufacturer must meet all the following requirements:

(1) Produce or import BOB such that the gasoline continues to meet the applicable gasoline standards in subpart C of this part after the addition of the specified type and amount of oxygenate.

(2) For each batch of BOB produced or imported, create a hand blend in accordance with § 1090.1340 and determine the properties of the hand blend using the methods specified in subpart N of this part.

(3) Participate in the NSTOP specified in § 1090.1450 or have an approved in-line blending waiver under § 1090.1315.

(4) Transfer ownership of the BOB only to an oxygenate blender that is registered with EPA under subpart I of this part or to an intermediate owner with the restriction that it only be transferred to a registered oxygenate blender.

(5) Specify on the PTD for the BOB each oxygenate type and amount (or range of amounts) for which the hand blend was certified for compliance under § 1090.1340.

(6) Participate in the NFSP under subpart O of this part.

(b) Requirements for oxygenate blenders. An oxygenate blender must add oxygenate of each type and amount (or within the range of amounts) as specified on the PTD for all BOB received, except as specified in paragraph (c)(2) of this section.

(c) Limitations. (1) Only the gasoline manufacturer that first certifies the BOB may account for the downstream addition of oxygenate under this section. On any occasion where any person downstream of the fuel manufacturing facility gate of the gasoline manufacturer that produced or imported gasoline or BOB adds oxygenate to such product, the person must not include the volume, sulfur content, and benzene content of the oxygenate in any compliance calculations for demonstrating compliance with the average standards specified in subpart C of this part or for credit generation under this subpart. All applicable per-gallon standards specified in subpart C of this part continue to apply.

(2) A person downstream of the fuel manufacturing facility gate may recertify BOB for use as gasoline without the addition of the specified type and amount of oxygenate if the provisions of § 1090.740 are met. A person who recertifies BOB for use as gasoline without the addition of the specified type and amount of oxygenate is a gasoline manufacturer and must meet all applicable requirements for a gasoline manufacturer specified in this part.

§ 1090.715

Deficit carryforward.

(a) A gasoline manufacturer incurs a compliance deficit if they exceed the average standard specified in subpart C of this part for a given compliance period. The deficit incurred must be determined as specified in paragraph (a)(1) of this section for sulfur and paragraph (a)(2) of this section for benzene.

(1) The sulfur deficit incurred is determined as follows:

Where:

D_S,y = Sulfur deficit incurred for compliance period y, in ppm-gallons.

CSV_y = Compliance sulfur value for compliance period y, per § 1090.700(a)(1), in ppm-gallons.

V_i = 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:

Where:

D_Bz,y = Benzene deficit incurred for compliance period y, in benzene gallons.

CBV_y = Compliance benzene value for compliance period y, per § 1090.700(b)(1)(i), in ppm-gallons.

V_i = The volume of gasoline produced or imported in batch i, in gallons.

n = The number of batches of gasoline produced or imported during the compliance period.

i = Individual batch of gasoline produced or imported during the compliance period.

(b) A gasoline manufacturer must use all sulfur or benzene credits previously generated or obtained at any of their facilities to achieve compliance with an average standard specified in subpart C of this part before carrying forward a sulfur or benzene deficit at any of their facilities.

(c) A gasoline manufacturer that incurs a deficit under this section must satisfy that deficit and demonstrate compliance with the annual average standards during the next compliance period regardless of whether the gasoline manufacturer produces gasoline during next compliance period.

§ 1090.720

Credit use.

(a) General credit use provisions. Only a gasoline manufacturer may generate, use, transfer, or own credits generated under this subpart, as specified in § 1090.725(a)(1). Credits may be used by a gasoline manufacturer to comply with the average standards specified in subpart C of this part. A gasoline manufacturer may also bank credits for future use, transfer credits to another facility within the company (i.e., intracompany trading), or transfer credits to another gasoline manufacturer, if all applicable requirements of this subpart are met.

(b) Credit life. Credits are valid for use for 5 years after the compliance period for which they are generated.

(c) Limitations on credit use. (1) Credits that have expired must not be used for demonstrating compliance with the average standards specified in subpart C of this part or be used to replace invalid credits under § 1090.735.

(2) A gasoline manufacturer possessing credits must use all credits prior to incurring a compliance deficit under § 1090.715.

(3) Credits must not be used to meet per-gallon standards.

(4) Credits must not be used to meet the maximum benzene average standard in § 1090.210(b).

(5) Credits may only be used if the gasoline manufacturer owns them at the time of use.

(d) Credit reporting. A gasoline manufacturer that generates, transacts, or uses credits under this subpart must report to EPA as specified in § 1090.905 using forms and procedures specified by EPA.

(e) Part 80 credit use. Valid credits generated under 40 CFR 80.1615 and 80.1290 may be used by a gasoline manufacturer to comply with the average standards in subpart C of this part, subject to the provisions of this subpart.

§ 1090.725

Credit generation.

(a) Parties that may generate credits. (1) No person other than a gasoline manufacturer may generate credits for use towards an average standard specified in subpart C of this part.

(2) No credits may be generated for gasoline produced by any of the following activities:

(i) Transmix processing.

(ii) Transmix blending.

(iii) Oxygenate blending.

(iv) Certified butane blending.

(v) Certified pentane blending.

(vi) Importation of gasoline by rail and truck using the alternative sampling and testing requirements in § 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:

Where:

C_S,y = Sulfur credits generated for compliance period y, in ppm-gallons.

V_i = 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.

CSV_y = Compliance sulfur value for compliance period y, per § 1090.700(a)(1), in ppm-gallons.

(2) The value of C_S,y must be positive to generate credits.

(3) Sulfur credits calculated under paragraph (c)(1) of this section must be expressed to the nearest ppm-gallon. Fractional values must be rounded in accordance with § 1090.50.

(d) Benzene credit generation. (1) The number of benzene credits generated is determined as follows:

Where:

C_Bz,y = Benzene credits generated for compliance period y, in benzene gallons.

V_i = 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.

CBV_y = Compliance benzene value for compliance period y, per § 1090.700(b)(1)(i), in benzene gallons.

(2) The value of C_Bz,y must be positive to generate credits.

(3) Benzene credits calculated under paragraph (d)(1) of this section must be expressed to the nearest benzene gallon. Fractional values must be rounded in accordance with § 1090.50.

(e) Credit generation limitation. A gasoline manufacturer may only generate credits after they have finished producing or importing gasoline for the compliance period.

(f) Credit generation reporting. A gasoline manufacturer that generates credits under this section must report to EPA all credit generation information as specified in § 1090.905 using forms and procedures specified by EPA.

§ 1090.730

Credit transfers.

A gasoline manufacturer may only transfer or obtain credits from another gasoline manufacturer to meet an average standard specified in subpart C of this part if all applicable requirements of this section are met.

(a) The credits are generated as specified in § 1090.725 and reported as specified in § 1090.905.

(b) The credits are used for compliance in accordance with the limitations on credit use specified in § 1090.720(c).

(c) Any credit transfer must take place no later than the deadline specified in § 1090.900(c) following the compliance period in which the credits are obtained.

(d) The credit has not been transferred between EPA registered companies more than twice. The first transfer by the gasoline manufacturer that generated the credit (“transferor”) must only be made to a gasoline manufacturer that intends to use the credit (“transferee”). If the transferee is unable to use the credit, it may make the second, and final, transfer only to a gasoline manufacturer that intends to use the credit. Intracompany credit transfers are unlimited.

(e) The transferor must apply any credits necessary to meet the transferor's applicable average standard before transferring credits to any other gasoline manufacturer.

(f) No person may transfer credits if the transfer would cause them to incur a deficit.

(g) Unless the transferor and transferee are the same party (i.e., intracompany transfers), the transferor must supply to the transferee records as specified in § 1090.1210(g) indicating the year(s) the credits were generated, the identity of the gasoline manufacturer that generated the credits, and the identity of the transferring party.

(h) The transferor and the transferee must report to EPA all information regarding the transaction as specified in § 1090.905 using forms and procedures specified by EPA.

§ 1090.735

Invalid credits and remedial actions.

For credits that have been calculated or generated improperly, or are otherwise determined to be invalid, all the following provisions apply:

(a) Invalid credits must not be used to achieve compliance with an average standard under this part, regardless of the good faith belief that the credits were validly generated.

(b) Any validly generated credits existing in the transferring gasoline manufacturer's credit balance after correcting the credit balance, and after the transferor applies credits as needed to meet the average standard at the end of the compliance period, must first be applied to correct the invalid transfers before the transferring gasoline manufacturer trades or banks the credits.

(c) The gasoline manufacturer that used the credits, and any transferor of the credits, must adjust their credit records, reports, and average standard compliance calculations as necessary to reflect the use of valid credits only. Updates to any reports must be done in accordance with subpart J of this part using forms and procedures specified by EPA.

§ 1090.740

Downstream BOB recertification.

(a)(1) A gasoline manufacturer may recertify a BOB that another gasoline manufacturer has specified blending instructions for oxygenate(s) under § 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) A gasoline manufacturer must comply with applicable requirements of this part and incur deficits to be included in their compliance calculations in § 1090.700 for each facility at which the gasoline manufacturer recertifies BOB.

(3) Unless otherwise required under this part, a gasoline manufacturer that recertifies 1,000,000 or less gallons of BOB under this section at a facility does not need to obtain credits to satisfy deficits incurred under this section or arrange for an auditor to conduct audits under subpart S of this part for that facility. The gasoline manufacturer must still comply with all other applicable provisions of this part (e.g., register and submit reports under subparts I and J of this part, respectively).

(4) A party that only recertifies BOB that contains a greater amount of a specified oxygenate (e.g., a party adds 15 volume percent DFE instead of 10 volume percent to an E10 BOB) or a different oxygenate at an equal or greater amount (e.g., a party adds 16 volume percent isobutanol instead of 10 volume percent to an E10 BOB) does not incur deficits under this section, does not need to submit reports under subpart J of this part, and does not need to arrange for an auditor to conduct an audit under subpart S of this part. The party must still comply with all other applicable provisions of this part (e.g., register and keep records under subparts I and M of this part, respectively).

(b) A gasoline manufacturer that recertifies a BOB under this section must calculate sulfur and benzene deficits for each batch and the total deficits for sulfur and benzene as follows:

(1) Sulfur deficits from downstream BOB recertification. Calculate the sulfur deficit from BOB recertification for each individual batch of BOB recertified as follows:

Where:

D_{S_Oxy_Batch} = Sulfur deficit resulting from recertifying the batch of BOB, in ppm-gallons.

V_Base = The volume of BOB in the batch being recertified, in gallons.

PTD_Oxy = The volume fraction of oxygenate that would have been added to the BOB as specified on PTDs.

ACTUAL_Oxy = The volume fraction of oxygenate that was actually added to the BOB. If no oxygenate was added to the BOB, then ACTUAL_Oxy = 0.

(2) Total sulfur deficit from downstream BOB recertification. Calculate the total sulfur deficit from downstream BOB recertification for each facility as follows:

Where:

D_{S_Oxy_Total,y} = The total sulfur deficit from downstream BOB recertification for compliance period y, in ppm-gallons.

D_{S_Oxy_Batch_i} = The sulfur deficit for batch i of recertified BOB, per paragraph (b)(1) of this section, in ppm-gallons.

n = The number of batches of BOB recertified during compliance period y.

i = Individual batch of BOB recertified during compliance period y.

(3) Benzene deficits from downstream BOB recertification. Calculate the benzene deficit from BOB recertification for each individual batch of BOB recertified as follows:

Where:

D_{Bz_Oxy_Batch} = Benzene deficit resulting from recertifying the batch of BOB, in benzene gallons.

V_Base = The volume of BOB in the batch being recertified, in gallons.

PTD_Oxy = The volume fraction of oxygenate that would have been added to the BOB as specified on PTDs.

ACTUAL_Oxy = The volume fraction of oxygenate that was actually added to the BOB. If no oxygenate was added to the BOB, then ACTUAL_Oxy = 0.

(4) Total benzene deficit from downstream BOB recertification. Calculate the total benzene deficit from downstream BOB recertification for each facility as follows:

Where:

D_{Bz_Oxy_Total,y} = The total benzene deficit from downstream BOB recertification for compliance period y, in benzene gallons.

D_{Bz_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 § 1090.50, as applicable.

(c) A gasoline manufacturer does 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 must not be carried forward under § 1090.715.

§ 1090.745

Informational annual average calculations.

(a) A gasoline manufacturer must calculate and report annual average sulfur and benzene concentrations for each of their facilities as specified in this section. The values calculated and reported under this section are not used to demonstrate compliance with average standards under this part.

(b) A gasoline manufacturer must calculate and report their unadjusted average sulfur concentration as follows:

Where:

S_a,y = The facility unadjusted average sulfur concentration for compliance period y, in ppm. Round and report S_a,y to two decimal places.

V_i = The volume of gasoline produced or imported in batch i, in gallons.

S_i = The sulfur content of batch i, in ppm.

n = The number of batches of gasoline produced or imported during the compliance period.

i = Individual batch of gasoline produced or imported during the compliance period.

(c) A gasoline manufacturer must calculate and report their net average sulfur concentration as follows:

Where:

S_NET,y = The facility net average sulfur concentration for compliance period y, in ppm. Round and report S_NET,y to two decimal places.

CSV_y = Compliance sulfur value for compliance period y, per § 1090.700(a)(1), in ppm-gallons.

(d) A gasoline manufacturer must calculate and report their net average benzene concentration as follows:

Where:

B_NET,y = The facility net average benzene concentration for compliance period y, in volume percent benzene. Round and report B_NET,y to two decimal places.

CBV_y = Compliance benzene value for compliance period y, per § 1090.700(b)(1)(i), in benzene gallons.

Subpart I—Registration

§ 1090.800

General provisions.

(a) Who must register. The following parties must register with EPA prior to engaging in any activity under this part:

(1) Fuel manufacturers, including:

(i) Gasoline manufacturers.

(ii) Diesel fuel manufacturers.

(iii) ECA marine fuel manufacturers.

(iv) Certified butane blenders.

(v) Certified pentane blenders.

(vi) Transmix processors.

(2) Oxygenate blenders.

(3) Oxygenate producers, including DFE producers.

(4) Certified pentane producers.

(5) Certified ethanol denaturant producers.

(6) Distributors, carriers, and pipeline operators that are part of the 500 ppm LM fuel distribution chain under a compliance plan submitted under § 1090.515(g).

(7) Independent surveyors.

(8) Auditors.

(9) Third parties that submit reports on behalf of any regulated party under this part. Such parties must register and associate their registration with the regulated party for whom they are reporting.

(b) Dates for registration. The deadlines for registration are as follows:

(1) New registrants. Except as specified in paragraph (b)(2) of this section, a party not currently registered with EPA must register with EPA no later than 60 days in advance of the first date that such party engages in any activity under this part requiring registration under paragraph (a) of this section.

(2) Existing registrants. Any party that is already registered with EPA under 40 CFR part 80 as of January 1, 2021, is deemed to be registered for purposes of this part, except that such party is responsible for reviewing and updating their registration information consistent with the requirements of this part, as specified in paragraph (c) of this section.

(c) Updates to registration. A registered party must submit updated registration information to EPA within 30 days of any occasion when the registration information previously supplied becomes incomplete or inaccurate.

(d) RCO submission. Registration information must be submitted by an RCO. The RCO may delegate responsibility to a person who is familiar with the requirements of this part and who is no lower in the organization than a fuel manufacturing facility manager, or equivalent.

(e) Forms and procedures for registration. All registrants must use forms and procedures specified by EPA.

(f) Company and facility identification. EPA will provide registrants with company and facility identifiers to be used for recordkeeping and reporting under this part.

(g) English language. Registration information submitted to EPA must be in English.

§ 1090.805

Contents of registration.

(a) General information required for all registrants. A party required to register under this part must submit all the following general information to EPA:

(1) Company information. For the company of the party, all the following information:

(i) The company name.

(ii) Company address, which must be the physical address of the business (i.e., not a post office box).

(iii) Mailing address, if different from company address.

(iv) Name, title, telephone number, and email address of an RCO.

(2) Facility information. For each separate facility, all the following information:

(i) The facility name.

(ii) The physical location of the facility.

(iii) A contact name, email address, and telephone number for the facility.

(iv) The type of facility.

(3) Location of records. For each separate facility, or for each importer's operations in a single PADD, all the following information:

(i) Whether records are kept on-site or off-site of the facility, or for an importer, the registered address.

(ii) If records are kept off-site, the primary off-site storage name, physical location, contact name, and telephone number.

(4) Activities. A description of the activities that are engaged in by the company and its facilities (e.g., refining, importing, etc.).

(b) Additional information required for certified pentane producers. In addition to the information in paragraph (a) of this section, a certified pentane producer must also submit the following information:

(1) A description of the production facility that demonstrates that the facility is capable of producing certified pentane that is compliant with the requirements of this part without significant modifications to the existing facility.

(2) A description of how certified pentane will be shipped from the production facility to the certified pentane blender(s) and the associated quality assurance practices that demonstrate that contamination during distribution can be adequately controlled so as not to cause certified pentane to be in violation of the standards in this part.

§ 1090.810

Voluntary cancellation of company or facility registration.

(a) Criteria for voluntary cancellation. A party may request cancellation of the registration of the company or any of its facilities at any time. Such request must use forms and procedures specified by EPA.

(b) Effect of voluntary cancellation. A party whose registration is canceled:

(1) Will still be liable for violation of any requirements under this part.

(2) Will not be listed on any public list of actively registered companies that is maintained by EPA.

(3) Will not have access to any of the electronic reporting systems associated with this part.

(4) Will still be required to meet any applicable requirements under this part (e.g., the recordkeeping provisions under subpart M of this part).

(c) Re-registration. If a party whose registration has been voluntarily cancelled wants to re-register, they must do all the following:

(1) Notify EPA of their intent to re-register.

(2) Provide any required information and correct any identified deficiencies.

(3) Refrain from initiating a new registration unless directed to do so by EPA.

(4) Submit updated information as needed.

§ 1090.815

Deactivation (involuntary cancellation) of registration.

(a) Criteria for deactivation. EPA may deactivate the registration of any party, or any of a party's facilities, required to register under this part, using the process specified in paragraph (b) of this section, if any of the following criteria are met:

(1) The party has not accessed their account or engaged in any registration or reporting activity within the most recent 24 months.

(2) The party has failed to comply with the registration requirements of this subpart.

(3) The party has failed to submit any required notification or report within 30 days of the required submission date.

(4) Any required attest engagement has not been received within 30 days of the required submission date.

(5) The party fails to pay a penalty or to perform any requirement under the terms of a court order, administrative order, consent decree, or administrative settlement between the party and EPA.

(6) The party submits false or incomplete information.

(7) The party denies EPA access or prevents EPA from completing authorized activities under section 114 or 208 of the Clean Air Act (42 U.S.C. 7414 or 7542) despite presenting a warrant or court order. This includes a failure to provide reasonable assistance.

(8) The party fails to keep or provide the records required under subpart M of this part.

(9) The party otherwise circumvents the intent of the Clean Air Act or of this part.

(b) Process for deactivation. Except as specified in paragraph (c) of this section, EPA will use the following process whenever it decides to deactivate the registration of a party:

(1) EPA will provide written notification to the RCO identifying the reasons or deficiencies for which EPA intends to deactivate the party's registration. The party will have 30 calendar days from the date of the notification to correct the deficiencies identified or explain why there is no need for corrective action.

(2) If the basis for EPA's notice of intent to deactivate registration is the absence of activity under paragraph (a)(1) of this section, a stated intent to engage in activity will be sufficient to avoid deactivation of registration.

(3) If the party does not correct identified deficiencies under paragraphs (a)(2) through (9) of this section, EPA may deactivate the party's registration without further notice to the party.

(c) Immediate deactivation. In instances in which public health, public interest, or safety requires, EPA may deactivate the registration of the party without any notice to the party. EPA will provide written notification to the RCO identifying the reason(s) EPA deactivated the registration of the party.

(d) Effect of deactivation. A party whose registration is deactivated:

(1) Will still be liable for violation of any requirement under this part.

(2) Will not be listed on any public list of actively registered companies that is maintained by EPA.

(3) Will not have access to any of the electronic reporting systems associated with this part.

(4) Will still be required to meet any applicable requirements under this part (e.g., the recordkeeping provisions under subpart M of this part).

(e) Re-registration. If a party whose registration has been deactivated wishes to re-register, they must do all the following:

(1) Notify EPA of their intent to re-register.

(2) Provide any required information and correct any identified deficiencies.

(3) Refrain from initiating a new registration unless directed to do so by EPA.

(4) Remedy the circumstances that caused the party to be deactivated in the first place.

(5) Submit updated information as needed.

§ 1090.820

Changes of ownership.

(a) When a company or any of its facilities will change ownership, the company must notify EPA within 30 days after the date of the change in ownership.

(b) The notification required under paragraph (a) of this section must include all the following:

(1) The effective date of the transfer of ownership of the company or facility and a summary of any changes to the registration information for the affected companies and facilities.

(2) Documents that demonstrate the sale or change in ownership of the company or facility.

(3) A letter, signed by an RCO from the company that currently owns or will own the company or facility and, if possible, an RCO from the company that previously registered the company or facility that details the effective date of the transfer of ownership of the company or facility and summarizes any changes to the registration information.

(4) Any additional information requested by EPA to complete the change in registration.

Subpart J—Reporting

§ 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.

(3) Reported volumes must be temperature-corrected in accordance with § 1090.1350(d).

(4) Report values as specified in § 1090.1335(e).

(b) English language. All reports submitted under this subpart must be submitted in English.

(c) Report deadlines. All annual, batch, and credit transaction reports required under this subpart, except attest engagement reports, must be submitted by March 31 for the preceding compliance period (e.g., reports covering the calendar year 2021 must be submitted to EPA by no later than March 31, 2022). Attest engagement reports must be submitted by June 1 for the preceding compliance period (e.g., attest engagement reports covering calendar year 2021 must be submitted to EPA by no later than June 1, 2022). Independent survey quarterly reports must be submitted by the deadlines in Table 1 to paragraph (a)(4) in § 1090.925.

(d) RCO submission. Reports must be signed and submitted by an RCO or their delegate of the RCO.

§ 1090.905

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

(a) Annual compliance demonstration for sulfur. For each compliance period, a gasoline manufacturer must submit a report for each of their facilities that includes all the following information:

(1) Company-level reporting. For the company, as applicable:

(i) The EPA-issued company and facility identifiers.

(ii) Provide information for sulfur credits, and separately by compliance period of creation, as follows:

(A) The number of sulfur credits owned at the beginning of the compliance period.

(B) The number of sulfur credits that expired at the end of the compliance period.

(C) The number of sulfur credits that will be carried over into the next compliance period.

(D) Any other information as EPA may require in order to administer reporting systems.

(2) Facility-level reporting. For each refinery or importer, as applicable:

(i) The EPA-issued company and facility identifiers.

(ii) The compliance sulfur value, per § 1090.700(a)(1), in ppm-gallons.

(iii) The total volume of gasoline produced or imported, in gallons.

(iv) Provide information for sulfur credits, and separately by compliance period of creation, as follows:

(A) The number of sulfur credits generated during the compliance period.

(B) The number of sulfur credits retired during the compliance period.

(C) The sulfur credit deficit that was carried over from the previous compliance period.

(D) The sulfur credit deficit that will be carried over into the next compliance period.

(E) The total sulfur deficit from downstream BOB recertification, per § 1090.740(b)(2).

(v) The unadjusted average sulfur concentration, per § 1090.745(b), in ppm.

(vi) The net average sulfur concentration, per § 1090.745(c), in ppm.

(vii) Any other information as EPA may require in order to administer reporting systems.

(b) Annual compliance demonstration for benzene. For each compliance period, a gasoline manufacturer must submit a report for each of their facilities that includes all the following information:

(1) Company-level reporting. For the company, as applicable:

(i) The EPA-issued company and facility identifiers and compliance level.

(ii) Provide information for benzene credits, and separately by compliance period of creation, as follows:

(A) The number of benzene credits owned at the beginning of the compliance period.

(B) The number of benzene credits that expired at the end of the compliance period.

(C) The number of benzene credits that will be carried over into the next compliance period.

(D) Any other information as EPA may require in order to administer reporting systems.

(2) Facility-level reporting. For each fuel manufacturing facility or importer, as applicable:

(i) The EPA-issued company and facility identifiers.

(ii) The compliance benzene value, per § 1090.700(b)(1)(i), in benzene gallons.

(iii) The total volume of gasoline produced or imported, in gallons.

(iv) The average benzene concentration, per § 1090.700(b)(3), in percent volume. For an importer, report the average benzene concentration for each aggregated import facility.

(v) The net average benzene concentration, per § 1090.745(d), in percent volume.

(vi) Provide information for benzene credits, and separately by compliance period of creation, as follows:

(A) The number of benzene credits generated during the compliance period.

(B) The number of benzene credits retired during the compliance period.

(C) The benzene credit deficit that was carried over from the previous compliance period

(D) The benzene credit deficit that will be carried over into the next compliance period.

(E) The total benzene deficit from downstream BOB recertification, per § 1090.740(b)(4).

(vii) Any other information as EPA may require in order to administer reporting systems.

(c) Batch reporting. A gasoline manufacturer must report the following information for each of their facilities on a per-batch basis for gasoline and gasoline regulated blendstocks:

(1) For all gasoline for which the gasoline manufacturer has not accounted for oxygenate added downstream under § 1090.710:

(i) The EPA-issued company and facility identifiers.

(ii) The batch number.

(iii) The date the batch was produced or imported.

(iv) The batch volume, in gallons.

(v) The designation of the gasoline as RFG, CG, RFG “Intended for Oxygenate Blending”, or CG “Intended for Oxygenate Blending”.

(vi) The tested sulfur content of the batch separately for per-gallon and average compliance, in ppm, and the test method used to measure the sulfur content.

(vii) The tested benzene content of the batch, as a volume percentage, and the test method used to measure the benzene content.

(viii) For all batches of summer gasoline:

(A) The applicable RVP standard, as specified in § 1090.215.

(B) The tested RVP of the batch, in psi, and the test method used to measure the RVP. If the gasoline is Summer RFG that is designated as “Intended for Oxygenate Blending” under § 1090.1010(a)(4), report the tested RVP for the hand blend.

(ix) If the gasoline contains oxygenate, the type and tested content of each oxygenate, as a volume percentage, and the test method used to measure the content of each oxygenate.

(2) For BOB for which the gasoline manufacturer has accounted for oxygenate added downstream under § 1090.710:

(i) The EPA-issued company and facility identifiers.

(ii) The batch identification.

(iii) The date the batch of BOB was produced or imported.

(iv) The batch volume, in gallons. This volume is the sum of the produced or imported BOB volume plus the anticipated volume from the addition of oxygenate downstream that the gasoline manufacturer specified to be blended with the BOB.

(v) The designation of the BOB (CBOB or RBOB) used to prepare the hand blend of BOB and oxygenate under § 1090.1340.

(vi) The tested sulfur content for both the BOB and the hand blend of BOB and oxygenate prepared under § 1090.1340, and the test method used to measure the sulfur content.

(vii) The tested benzene content for the hand blend of BOB and oxygenate prepared under § 1090.1340, and the test method used to measure the benzene content.

(viii) For all batches of summer BOB:

(A) The applicable RVP standard, as specified in § 1090.215, for the neat CBOB, or hand blend of RBOB and oxygenate prepared under § 1090.1340.

(B) The tested RVP for the neat CBOB or hand blend of RBOB and oxygenate prepared under § 1090.1340, in psi, and the test method used to measure the RVP.

(ix) The type and content of each oxygenate, as a volume percentage, in the hand blend of BOB and oxygenate prepared under § 1090.1340, and, if measured, the test method used for each oxygenate.

(3) For blendstock added to PCG by a gasoline manufacturer complying by subtraction under § 1090.1320(a)(1):

(i) For the PCG prior to the addition of blendstock:

(A) The EPA-issued company and facility identifiers for the facility at which the PCG is blended to produce a new batch.

(B) The batch number assigned by the facility at which the PCG is blended to produce a new batch.

(C) The date the batch was received or, for PCG that was not received from another company, the date the PCG was designated to be used to produce a new batch of gasoline.

(D) The batch volume, including the volume of any oxygenate that would have been added to the PCG, as a negative number in gallons.

(E) The designation of the PCG.

(F) The tested sulfur content of the batch, in ppm, and the test method used to measure the sulfur content. If the PCG is a BOB, report the tested sulfur content of the hand blend prepared under § 1090.1340.

(G) The tested benzene content of the batch, as a volume percentage, and the test method used to measure the benzene content. If the PCG is a BOB, report the tested benzene content of the hand blend prepared under § 1090.1340.

(H) For all batches of summer gasoline or BOB:

(1) The applicable RVP standard, as specified in § 1090.215.

(2) The tested RVP of the batch, in psi, and the test method used to measure the RVP.

(I) If the PCG contains oxygenate, the type and tested content of each oxygenate, as a volume percentage, and the test method used to measure the content of each oxygenate.

(J) Identification of the batch as PCG.

(ii) For the batch of gasoline or BOB produced using PCG and blendstock:

(A) For batches of finished gasoline or neat BOB, all the information specified in paragraph (c)(1) of this section.

(B) For batches of BOB in which the oxygenate to be blended with the BOB is included in the gasoline manufacturer's compliance calculations, all the information specified in paragraph (c)(2) of this section.

(4) For blendstock(s) added to PCG by a gasoline manufacturer complying by addition under § 1090.1320(a)(2), report each blendstock as a separate batch and all the following:

(i) For the blendstock, the sulfur content and benzene content of the batch.

(ii) For batches produced by adding blendstock to PCG, the sulfur content, oxygenate type and amount (unless not required under § 1090.1310(e)), and for summer gasoline, RVP, of the batch.

(5) For certified butane blended by a certified butane blender or certified pentane blended by a certified pentane blender:

(i) For the certified butane or certified pentane batch:

(A) The batch number.

(B) The date the batch was received by the blender.

(C) The volume of certified butane or certified pentane blended, in gallons.

(D) The designation of the batch (certified butane or certified pentane).

(E) The volume percentage of butane in butane batches, or pentane in pentane batches, provided by the certified butane or certified pentane supplier.

(F) The sulfur content of the batch, in ppm, provided by the certified butane or certified pentane supplier.

(G) The benzene content of the batch, in volume percent, provided by the certified butane or certified pentane supplier.

(ii) For the batch of blended product (i.e., PCG plus butane or PCG plus pentane):

(A) The batch number.

(B) The date the batch was produced.

(C) The batch volume, in gallons.

(D) The designation of the blended product.

(E) For a new batch of gasoline (e.g., a blended gasoline containing certified butane and PCG) that is summer gasoline or summer BOB, the tested RVP of the batch, in psi, and the test method used to measure the RVP.

(6) For gasoline produced by adding any blendstocks to TGP:

(i) For each batch of gasoline produced with TGP, the sulfur content and for summer gasoline, RVP, of the batch.

(ii) For blendstocks added to TGP, a transmix processor or blending manufacturer must treat the TGP like PCG and report one of the following:

(A) The information specified in paragraph (c)(3) of this section.

(B) The information specified in paragraph (c)(4) of this section.

(7) For GTAB:

(i) The EPA-issued company and facility identifiers.

(ii) The batch number.

(iii) The date the batch was imported.

(iv) The batch volume, in gallons.

(v) The designation of the product as GTAB.

(8) For each batch of gasoline produced by a transmix processor or blending manufacturer from only TGP or both TGP and PCG under § 1090.505:

(i) The EPA-issued company and facility identifiers.

(ii) The batch number.

(iii) The date the batch was produced.

(iv) The batch volume, in gallons.

(v) The designation of the gasoline.

(vi) The tested sulfur content of the batch, in ppm, and the test method used to measure the sulfur content.

(vii) For summer gasoline:

(A) The applicable RVP standard in § 1090.215.

(B) The tested RVP of the batch, in psi, and the test method used to measure the RVP.

(9) Any other information as EPA may require in order to administer reporting systems.

(d) Credit transactions. Any party that is required to demonstrate annual compliance under paragraph (a) or (b) of this section must submit information related to individual transactions involving sulfur and benzene credits, including all the following:

(1) The generation, purchase, sale, or retirement of such credits.

(2) If any credits were obtained from or transferred to other fuel manufacturers, and for each other party, their name and EPA-issued company identifier, the number of credits obtained from or transferred to the other party, and the year the credits were generated.

(3) Any other information as EPA may require in order to administer reporting systems.

§ 1090.910

Reporting for gasoline manufacturers that recertify BOB to gasoline.

A party that recertifies BOB under § 1090.740 must report the information of this section, as applicable.

(a) Batch reporting. (1) A party that recertifies a BOB under § 1090.740 with less oxygenate than specified by the BOB manufacturer must report the following for each batch:

(i) The EPA-issued company and facility identifiers for the recertifying party.

(ii) The batch number assigned by the recertifying party.

(iii) The date the batch was recertified.

(iv) The batch volume, as a negative number in gallons. The volume is the amount of oxygenate that the recertifying gasoline manufacturer did not blend with the BOB.

(v) The designation of the batch.

(vi) A sulfur content of 11 ppm.

(vii) A benzene content of 0.68 volume percent.

(viii) The type and content of each oxygenate, as a volume percentage.

(ix) The sulfur deficit for the batch calculated under § 1090.740(b)(1).

(x) The benzene deficit for the batch calculated under § 1090.740(b)(3).

(2) A party that recertifies a BOB under § 1090.740 with more oxygenate than specified by the BOB manufacturer does not need to report the batch.

(b) Annual sulfur and benzene compliance reporting. A party that recertifies a BOB under § 1090.740 must include any deficits incurred from recertification in reports under § 1090.905(a) and (b).

(c) Credit transactions. A party that recertifies a BOB under § 1090.740 must report any credit transactions under § 1090.905(d).

§ 1090.915

Batch reporting for oxygenate producers and importers.

An oxygenate producer, for each of their production facilities, or an importer for the oxygenate they import, must submit a report for each compliance period that includes all the following information:

(a) The EPA-issued company and facility identifiers.

(b) The total volume of oxygenate produced or imported.

(c) For each batch of oxygenate produced or imported during the compliance period, all the following:

(1) The batch number.

(2) The date the batch was produced or imported.

(3) One of the following product types:

(i) Denatured ethanol using certified ethanol denaturant complying with § 1090.275.

(ii) Denatured ethanol from non-certified ethanol denaturant.

(iii) A specified oxygenate other than ethanol (e.g., isobutanol).

(4) The volume of the batch, in gallons.

(5) The tested sulfur content of the batch, in ppm, and the test method used to measure the sulfur content.

(d) Any other information as EPA may require in order to administer reporting systems.

§ 1090.920

Reports by certified pentane producers.

A certified pentane producer must submit a report for each facility at which certified pentane was produced or imported that contains all the following information:

(a) The EPA-issued company and facility identifiers.

(b) For each batch of certified pentane produced or imported during the compliance period, all the following:

(1) The batch number.

(2) The date the batch was produced or imported.

(3) The batch volume, in gallons.

(4) The tested pentane content of the batch, as a volume percentage, and the test method used to measure the pentane content.

(5) The tested sulfur content of the batch, in ppm, and the test method used to measure the sulfur content.

(6) The tested benzene of the batch, as a volume percentage, and the test method used to measure the benzene content.

(7) The tested RVP of the batch, in psi, and the test method used to measure the RVP.

(c) Any other information as EPA may require in order to administer reporting systems.

§ 1090.925

Reports by independent surveyors.

(a) General procedures. An independent surveyor must meet the following requirements:

(1) Electronically submit any plans, notifications, or reports required under this part using forms and procedures specified by EPA.

(2) For each report required under this section, affirm that the survey was conducted in accordance with an EPA-approved survey plan and that the survey results are accurate.

(3) Include EPA-issued company identifiers on each report required under this section.

(4) Submit quarterly reports required under paragraphs (b) and (d) of this section by the following deadlines:

Table 1 to Paragraph (a)(4)—Quarterly Reporting Deadlines

Calendar quarter	Time period covered	Quarterly report deadline
Quarter 1	January 1-March 31	June 1.
Quarter 2	April 1-June 30	September 1.
Quarter 3	July 1-September 30	December 1.
Quarter 4	October 1-December 31	March 31.

(b) NFSP quarterly reporting. An independent surveyor conducting the NFSP under § 1090.1405 must submit the following information quarterly, as applicable:

(1) For each retail outlet sampled by the independent surveyor:

(i) The identification information for the retail outlet, as assigned by the surveyor in a consistent manner and as specified in the survey plan.

(ii) The displayed fuel manufacturer brand name at the retail outlet, if any.

(iii) The physical location (i.e., address) of the retail outlet.

(2) For each gasoline sample collected by the independent surveyor:

(i) A description of the labeling of the fuel dispenser(s) (e.g., “E0”, “E10”, “E15”, etc.) from which the independent surveyor collected the sample.

(ii) The date and time the independent surveyor collected the sample.

(iii) The test results for the sample, and the test methods used, as determined by the independent surveyor, including the following parameters:

(A) The oxygen content, in weight percent.

(B) The type and amount of each oxygenate, by weight and volume percent.

(C) The sulfur content, in ppm.

(D) The benzene content, in volume percent.

(E) The specific gravity.

(F) The RVP in psi, if tested.

(G) The aromatic content in volume percent, if tested.

(H) The olefin content in volume percent, if tested.

(I) The distillation parameters, if tested.

(3) For each diesel sample collected at a retail outlet by the independent surveyor:

(i) A description of the labeling of the fuel dispenser(s) (e.g., “ULSD”) from which the independent surveyor collected the sample.

(ii) The date and time the independent surveyor collected the sample.

(iii) The tested sulfur content of the sample, and the test method used, as determined by the independent surveyor, in ppm.

(4) Any other information as EPA may require in order to administer reporting systems.

(c) NFSP annual reporting. An independent surveyor conducting the NFSP under § 1090.1405 must submit the following information annually by March 31.

(1) An identification of the parties that participated in the survey during the compliance period.

(2) An identification of each geographic area included in a survey.

(3) Summary statistics for each identified geographic area, including the following:

(i) The number of samples collected and tested.

(ii) The mean, median, and range expressed in appropriate units for each measured gasoline and diesel parameter.

(iii) The standard deviation for each measured gasoline and diesel parameter.

(iv) The estimated compliance rate for each measured gasoline and diesel parameter subject to a per-gallon standard in subpart C or D of this part.

(v) A summary of potential non-compliance issues.

(4) Any other information as EPA may require in order to administer reporting systems.

(d) NSTOP quarterly reporting. An independent surveyor conducting the NSTOP under § 1090.1450 must submit the following information quarterly, as applicable:

(1) For each gasoline manufacturing facility sampled by the independent surveyor:

(i) The EPA-issued company and facility identifiers for the gasoline manufacturer and the gasoline manufacturing facility.

(2) For each gasoline sample collected by the independent surveyor:

(i) The designation of the gasoline.

(ii) The date and time the independent surveyor collected the sample.

(iii) The batch number or the sample identification number as assigned by the independent surveyor in a consistent manner and as specified in the survey plan.

(iv) A description of any instance in which the gasoline manufacturer did not follow the applicable sampling procedures.

(v) The test results for the sample, and the test methods used, as determined by the independent surveyor, including the following parameters:

(A) The sulfur content, in ppm.

(B) The benzene content, in volume percent.

(C) The RVP in psi, if tested.

(vi) The test results for the sample, and the test methods used, as determined by the gasoline manufacturer, including the following parameters:

(A) The sulfur content, in ppm.

(B) The benzene content, in volume percent.

(C) The RVP in psi, if tested.

(vii) If available, the test results for the sample, and the test methods used, as determined by EPA's National Vehicle and Fuel Emissions Laboratory, including the following parameters:

(A) The sulfur content, in ppm.

(B) The benzene content, in volume percent.

(C) The RVP in psi, if tested.

(viii) The determined site precision under § 1090.1450(c)(10)(i) and the test performance index under § 1090.1450(c)(10)(ii) for each method and instrument that the gasoline manufacturer used to test the sample.

(ix) The reproducibility of each method that the gasoline manufacturer used to test the sample.

(x) Any applicable correlation equations used to compare the gasoline manufacturer's test results to the independent surveyor's test results.

(3) Any other information as EPA may require in order to administer reporting systems.

§ 1090.930

Reports by auditors.

(a) Attest engagement reports required under subpart S of this part must be submitted by an independent auditor registered with EPA and associated with a company, or companies, through registration under subpart I of this part. Each attest engagement must clearly identify the company and compliance level (e.g., facility), time period, and scope covered by the report. Attest engagement reports covered by this section include those required under this part, and under 40 CFR part 80, subpart M, beginning with the report due June 1, 2022.

(b) An attest engagement report must be submitted to EPA covering each compliance period by June 1 of the following calendar year. The auditor must make the attest engagement available to the company for which it was performed.

(c) The attest engagement must comply with subpart S of this part and the attest engagement report must clearly identify the methodologies followed and any findings, exceptions, and variances.

(d) A single attest engagement submission by the auditor may include procedures performed under this part and under 40 CFR part 80, subpart M. If a single submission method is used, the auditor must clearly and separately describe the procedures and findings for each program.

(e) The auditor must submit written acknowledgement from the RCO that the gasoline manufacturer has reviewed the attest engagement report.

§ 1090.935

Reports by diesel fuel manufacturers.

(a) Batch reporting. (1) For each compliance period, a ULSD manufacturer must submit the following information:

(i) The EPA-issued company and facility identifiers for the ULSD manufacturer.

(ii) The highest sulfur content observed for a batch of ULSD produced during the compliance period on a company level, in ppm.

(iii) The average sulfur concentration of all batches produced during the compliance period on a company level, in ppm.

(iv) A list of all batches of ULSD that exceeded the sulfur standard in § 1090.305(b) by facility. For each such batch, report the following:

(A) The batch number.

(B) The date the batch was produced.

(C) The volume of the batch, in gallons.

(D) The sulfur content of the batch, in ppm.

(E) The corrective action taken, if any.

(b) [Reserved]

Subpart K—Batch Certification and Designation

§ 1090.1000

Batch certification requirements.

(a) General provisions. (1) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer must certify batches of fuel, fuel additive, or regulated blendstock as specified in this section.

(2) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer does not need to certify fuel, fuel additive, or regulated blendstock that is exempt under subpart G of this part.

(3)(i) For purposes of this part, the volume of a batch is one of the following:

(A) The sum of all shipments or transfers of fuel, fuel additive, or regulated blendstock out of the tank or vessel in which the fuel, fuel additive, or regulated blendstock was certified.

(B) The entire volume of a tank or vessel may be certified as a single batch. In such cases, any heel left in the tank or vessel after shipments of the batch becomes PCG.

(ii) If a volume of fuel, fuel additive, or regulated blendstock is placed in a tank, certified (if not previously certified), and is not altered in any manner, then it is considered to be the same batch even if several shipments or transfers are made out of that tank.

(iii) Batch volumes must be temperature-corrected in accordance with § 1090.1350(d).

(4) For fuel produced at a facility that has an in-line blending waiver under § 1090.1315, the volume of the batch is the volume of product that is homogeneous under the requirements in § 1090.1337 and is produced during a period not to exceed 10 days.

(5) A fuel manufacturer must certify each batch of fuel at the facility where the fuel is produced or at a facility that is under the complete control of the fuel manufacturer before they transfer custody or title of the fuel to any other person.

(6) No person may sell, offer for sale, distribute, offer to distribute, supply, offer for supply, dispense, store, transport, or introduce into commerce gasoline, diesel fuel, or ECA marine fuel that is not certified under this section.

(b) Gasoline. (1) A gasoline manufacturer must certify gasoline as specified in paragraph (b)(2) of this section prior to introduction into commerce.

(2) To certify batches of gasoline, a gasoline manufacturer must comply with all the following:

(i) Register with EPA as a refiner, blending manufacturer, importer, transmix processor, certified butane blender, or certified pentane blender under subpart I of this part, as applicable, prior to producing gasoline.

(ii) Ensure that each batch of gasoline meets the applicable requirements of subpart C of this part using the applicable procedures specified in subpart N of this part. A transmix processor must also meet all applicable requirements in subpart F of this part to ensure that each batch of gasoline meets the applicable requirements in subpart C of this part.

(iii) Assign batch numbers as specified in § 1090.1020.

(iv) Designate batches of gasoline as specified in § 1090.1010.

(3) PCG may be mixed with other PCG without re-certification if the resultant mixture complies with the applicable standards in subpart C of this part and is accurately and clearly designated under § 1090.1010. Resultant mixtures of PCG are not new batches and should not be assigned new batch numbers.

(4) Any person that mixes summer gasoline with summer or winter gasoline that has a different designation must comply with one of the following:

(i) Designate the resultant mixture as meeting the least stringent RVP designation of any batch that is mixed. For example, a distributor that mixes Summer RFG with 7.8 psi Summer CG must designate the mixture as 7.8 psi Summer CG.

(ii) Determine the RVP of the mixture using the procedures specified in subpart N of this part and designate the new batch under § 1090.1010 to reflect the RVP of the resultant mixture.

(5) Any person that mixes summer gasoline with winter gasoline to transition any storage tank from winter to summer gasoline is exempt from the requirement in paragraph (b)(4)(ii) of this section but must ensure that the gasoline meets the applicable RVP standard in § 1090.215.

(c) Diesel fuel and ECA marine fuel. (1) A diesel fuel or ECA marine fuel manufacturer must certify diesel fuel or ECA marine fuel as specified in paragraph (c)(2) of this section prior to introducing the fuel into commerce.

(2) To certify batches of diesel fuel or ECA marine fuel, a diesel fuel or ECA marine fuel manufacturer must comply with all the following:

(i) Register with EPA as a refiner, blending manufacturer, importer, or transmix processor under subpart I of this part, as applicable, prior to producing diesel fuel or ECA marine fuel.

(ii) Ensure that each batch of diesel fuel or ECA marine fuel meets the applicable requirements of subpart D of this part using the applicable procedures specified in subpart N of this part. A transmix processor must also meet all applicable requirements specified in subpart F of this part to ensure that each batch of diesel fuel or ECA marine fuel meets the applicable requirements in subpart D of this part.

(iii) Assign batch numbers as specified in § 1090.1020.

(iv) Designate batches of diesel fuel as specified in § 1090.1015.

(d) Oxygenates. (1) An oxygenate producer must certify oxygenates intended to be blended into gasoline as specified in paragraph (d)(2) of this section.

(2) To certify batches of oxygenates, an oxygenate producer must comply with all the following:

(i) Register with EPA as an oxygenate producer under subpart I of this part prior to producing or importing oxygenate intended for blending into gasoline.

(ii) Ensure that each batch of oxygenate meets the requirements in § 1090.270 by using the applicable procedures specified in subpart N of this part.

(iii) Assign batch numbers as specified in § 1090.1020.

(iv) Designate batches of oxygenate as intended for blending with gasoline as specified in § 1090.1010(c).

(e) Certified butane. (1) A certified butane producer must certify butane intended to be blended by a blending manufacturer under § 1090.1320 as specified in paragraph (e)(2) of this section.

(2) To certify batches of certified butane, a certified butane producer must comply with all the following:

(i) Ensure that each batch of certified butane meets the requirements in § 1090.250 by using the applicable procedures specified in subpart N of this part.

(A) Testing must occur after the most recent delivery into the certified butane producer's storage tank.

(B) The certified butane producer must provide documentation of the test results for each batch of certified butane to the certified butane blender.

(ii) Designate batches of certified butane as intended for blending with gasoline as specified in § 1090.1010(d).

(f) Certified pentane. (1) A certified pentane producer must certify pentane intended to be blended by a blending manufacturer under § 1090.1320 as specified in paragraph (f)(2) of this section.

(2) To certify batches of certified pentane, a certified pentane producer must comply with all the following:

(i) Register with EPA as a certified pentane producer under subpart I of this part prior to producing certified pentane.

(ii) Ensure that each batch of certified pentane meets the requirements in § 1090.255 by using the applicable procedures specified in subpart N of this part.

(A) Testing must occur after the most recent delivery into the certified pentane producer's storage tank, before transferring the certified pentane batch for delivery.

(B) The certified pentane producer must provide documentation of the test results for each batch of certified pentane to the certified pentane blender.

(iii) Assign batch numbers as specified in § 1090.1020.

(iv) Designate batches of certified pentane as intended for blending with gasoline as specified in § 1090.1010(d).

(g) Certified ethanol denaturant. (1) A certified ethanol denaturant producer must certify certified ethanol denaturant intended to be used to make DFE that meets the requirements in § 1090.275 as specified in paragraph (g)(2) of this section.

(2) To certify batches of certified ethanol denaturant, a certified ethanol denaturant producer must comply with all the following:

(i) Register with EPA as a certified ethanol denaturant producer under subpart I of this part prior to producing certified ethanol denaturant.

(ii) Ensure that each batch of certified ethanol denaturant meets the requirements in § 1090.275 by using the applicable procedures specified in subpart N of this part.

(iii) Assign batch numbers as specified in § 1090.1020.

(iv) Designate batches of certified ethanol denaturant as intended for blending with gasoline as specified in § 1090.1010(e).

§ 1090.1005

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

(a) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer must designate batches of fuel, fuel additive, or regulated blendstock as specified in this subpart.

(b) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer must designate the fuel, fuel additive, or regulated blendstock prior to the fuel, fuel additive, or regulated blendstock leaving the facility where it was produced and must include the designations on PTDs as specified in this subpart.

(c) By designating a batch of fuel, fuel additive, or regulated blendstock under this subpart, the designating party is acknowledging that the batch is subject to all applicable standards under this part.

(d) A person must comply with all provisions of this part even if they fail to designate or improperly designate a batch of fuel, fuel additive, or regulated blendstock.

(e) No person may use the designation provisions of this subpart to circumvent any standard or requirement in this part.

§ 1090.1010

Designation requirements for gasoline and regulated blendstocks.

(a) Designation requirements for gasoline manufacturers. A gasoline manufacturer must accurately and clearly designate each batch of gasoline as follows:

(1) A gasoline manufacturer must designate each batch of gasoline as one of the following fuel types:

(i) Winter RFG.

(ii) Summer RFG.

(iii) Winter RBOB.

(iv) Summer RBOB.

(v) Winter CG.

(vi) Summer CG.

(vii) Winter CBOB.

(viii) Summer CBOB.

(ix) Exempt gasoline under subpart G of this part (including additional identifying information).

(x) California gasoline.

(2) A gasoline manufacturer must further designate gasoline designated as Summer CG or Summer CBOB as follows:

(i) 7.8 psi Summer CG or Summer CBOB, respectively.

(ii) 9.0 psi Summer CG or Summer CBOB, respectively.

(iii) SIP-controlled Summer CG or Summer CBOB, respectively.

(3) A CBOB or RBOB manufacturer must further designate the CBOB or RBOB with the type(s) and amount(s) of oxygenate specified to be blended with the CBOB or RBOB as specified in § 1090.710(a)(5).

(4) In addition to any other applicable designation in this paragraph (a), gasoline designed for downstream oxygenate blending for which the gasoline manufacturer has not accounted for oxygenate added downstream under § 1090.710 must be designated as “Intended for Oxygenate Blending”, along with a designation indicating the type(s) and amount(s) of oxygenate to be blended with the gasoline.

(b) Designation requirements for gasoline distributors and certain gasoline blending manufacturers. A gasoline distributor, certified butane blender, certified pentane blender, or party that recertifies BOB under § 1090.740 must accurately and clearly designate each batch or portion of a batch of gasoline for which they transfer custody to another facility as follows:

(1) A distributor must accurately and clearly classify each batch or portion of a batch of gasoline as specified by the gasoline manufacturer in paragraph (a) of this section.

(2) Except as specified in paragraph (b)(2)(vii) of this section, a distributor, certified butane blender, certified pentane blender, or party that recertifies BOB under § 1090.740 may redesignate a batch or portion of a batch of gasoline without recertifying the batch or portion of a batch as follows:

(i) Winter RFG or Winter RBOB may be redesignated as either Winter CG or Winter CBOB.

(ii) Winter CG or Winter CBOB may be redesignated as either Winter RFG or Winter RBOB.

(iii) Summer RFG, Summer RBOB, Summer CG, or Summer CBOB may be redesignated without recertification to a less stringent RVP designation. For example, a distributor could redesignate without recertification a portion of a batch of Summer RFG to 7.8 psi Summer CG or 9.0 psi Summer CG.

(iv) Summer RFG, Summer RBOB, Summer CG, or Summer CBOB may be redesignated without recertification as either Winter RFG, Winter RBOB, Winter CG, or Winter CBOB.

(v) Summer CG, Summer CBOB, or any winter gasoline may be redesignated to either Summer RFG or Summer RBOB, provided the RVP is determined using the applicable procedures specified in subpart N of this part and the new batch meets the RFG RVP standard specified in § 1090.215(a)(3).

(vi)(A) California gasoline may be redesignated as RFG or CG, with appropriate season designation and RVP designation under paragraph (a) of this section, if the requirements specified in § 1090.625(d) are met.

(B) California gasoline that is not redesignated under paragraph (b)(2)(vi)(A) of this section may instead be recertified as gasoline under § 1090.1000(b).

(vii) CG or RFG must not be redesignated as BOB.

(3) A distributor, certified butane blender, certified pentane blender, or party that recertifies BOB under § 1090.740 that redesignates a batch or portion of a batch of gasoline under paragraph (b)(2) of this section must accurately and clearly designate the batch or portion of the batch of gasoline as specified in paragraph (a) of this section.

(c) Designation requirements for oxygenate producers. An oxygenate producer must accurately and clearly designate each batch of oxygenate intended for blending with gasoline as one of the following oxygenate types:

(1) DFE.

(2) The name of the specific oxygenate (e.g., iso-butanol).

(d) Designation requirements for certified butane and certified pentane. A certified butane or certified pentane producer must accurately and clearly designate each batch of certified butane or certified pentane as one of the following types:

(1) Certified butane.

(2) Certified pentane.

(e) Designation requirements for certified ethanol denaturant. A certified ethanol denaturant producer must accurately and clearly designate batches of certified ethanol denaturant as “certified ethanol denaturant”.

(f) Designation requirements for TGP. A transmix processor must accurately and clearly designate any TGP that they transfer to any other person as “TGP”.

§ 1090.1015

Designation requirements for diesel and distillate fuels.

(a) Designation requirements for diesel and distillate fuel manufacturers. (1) Except as specified in paragraph (a)(3) of this section, a diesel fuel or distillate fuel manufacturer must accurately and clearly designate each batch of diesel fuel or distillate fuel as at least one of the following fuel types:

(i) ULSD. A diesel fuel manufacturer may also designate ULSD as 15 ppm MVNRLM diesel fuel.

(ii) 500 ppm LM diesel fuel.

(iii) Heating oil.

(iv) Jet fuel.

(v) Kerosene.

(vi) ECA marine fuel.

(vii) Distillate global marine fuel.

(viii) Certified NTDF.

(ix) Exempt diesel fuel or distillate fuel under subpart G of this part (including additional identifying information).

(2) Only a fuel manufacturer that complies with the requirements in § 1090.515 may designate fuel as 500 ppm LM diesel fuel.

(3) Any batch of diesel fuel or distillate fuel that is certified and designated as ULSD may also be designated as heating oil, kerosene, ECA marine fuel, jet fuel, or distillate global marine fuel if it is also suitable for such use.

(b) Designation requirements for distributors of diesel and distillate fuels. A distributor of diesel and distillate fuels must accurately and clearly designate each batch of diesel fuel or distillate fuel for which they transfer custody as follows:

(1) A distributor must accurately and clearly designate such diesel fuel or distillate fuel by sulfur content while it is in their custody (e.g., as 15 ppm or 500 ppm).

(2) A distributor must accurately and clearly designate such diesel fuel or distillate fuel as specified by the diesel fuel or distillate fuel manufacturer under paragraph (a) of this section.

(3) A distributor may redesignate batches or portions of batches of diesel fuel or distillate fuel for which they transfer custody to another facility without recertifying the batch or portion of the batch as follows:

(i) ULSD that is also suitable for use as kerosene or jet fuel (commonly referred to as dual use kerosene) may be designated as ULSD, kerosene, or jet fuel (as applicable).

(ii) ULSD may be redesignated as 500 ppm LM diesel fuel, heating oil, kerosene, ECA marine fuel, jet fuel, or distillate global marine fuel without recertification if all applicable requirements under this part are met for the new fuel designation.

(iii) California diesel may be redesignated as ULSD if the requirements specified in § 1090.625(e) are met.

(iv) Heating oil, kerosene, ECA marine fuel, or jet fuel may be redesignated as ULSD if the fuel meets the ULSD standards in § 1090.305 and was designated as ULSD under paragraph (a) of this section.

(v) 500 ppm LM diesel fuel may be redesignated as ECA marine fuel, distillate global marine fuel, or heating oil. Any person that redesignates 500 ppm LM diesel fuel to ECA marine fuel or distillate global marine fuel must maintain records from the producer of the 500 ppm LM diesel fuel (i.e., PTDs accompanying the fuel under § 1090.1115) to demonstrate compliance with the 500 ppm sulfur standard in § 1090.320(b).

(vi) Fuel designated as certified NTDF may be redesignated as ULSD without recertification if the applicable requirements of 40 CFR 80.1408 are met.

(c) ULSD designation limitation. No person may designate distillate fuel with a sulfur content greater than the sulfur standard in § 1090.305(b) as ULSD.

§ 1090.1020

Batch numbering.

(a) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer must assign a number (the “batch number”) to each batch of gasoline, diesel fuel, oxygenate, certified pentane, or certified ethanol denaturant either produced or imported. The batch number must, if available, consist of the EPA-assigned company registration number of the party that either produced or imported the fuel, fuel additive, or regulated blendstock, the EPA-assigned facility registration number where the fuel, fuel additive, or regulated blendstock was produced or imported, the last two digits of the year that the batch was either produced or imported, and a unique number for the batch, beginning with the number one (1) for the first batch produced or imported each calendar year and each subsequent batch during the calendar year being assigned the next sequential number (e.g., 4321-54321-20-000001, 4321-54321-20-000002, etc.). EPA assigns company and facility registration numbers as specified in subpart I of this part.

(b) Certified butane or certified pentane blended with PCG during a period of up to one month may be included in a single batch for purposes of reporting to EPA.

(c) A gasoline manufacturer that recertifies BOBs under § 1090.740 may include up to a single month's volume as a single batch for purposes of reporting to EPA.

Subpart L—Product Transfer Documents

§ 1090.1100

General requirements.

(a) General provisions. (1) On each occasion when any person transfers custody or title to any product covered under this part, other than when fuel is sold or dispensed to the ultimate end user at a retail outlet or WPC facility, the transferor must provide the transferee PTDs that include the following information:

(i) The name and address of the transferor.

(ii) The name and address of the transferee.

(iii) The volume of the product being transferred.

(iv) The location of the product at the time of the transfer.

(v) The date of the transfer.

(2) The specific designations required for gasoline-related products specified in § 1090.1010 or distillate-related products specified in § 1090.1015.

(b) Use of codes. Except for transfers to a truck carrier, retailer, or WPC, product codes may be used to convey the information required under this subpart, if such codes are clearly understood by each transferee.

(c) Part 80 PTD requirements. For fuel, fuel additive, or regulated blendstock subject to 40 CFR part 80, subpart M, a party must also include the applicable PTD information required under 40 CFR 80.1453.

§ 1090.1105

PTD requirements for exempt fuels.

(a) In addition to the information required under § 1090.1100, on each occasion when any person transfers custody or title to any exempt fuel under subpart G of this part, other than when fuel is sold or dispensed to the ultimate end user at a retail outlet or WPC facility, the transferor must provide the transferee PTDs that include the following statements, as applicable:

(1) National security exemption language. For fuels with a national security exemption specified in § 1090.605: “This fuel is for use in vehicles, engines, or equipment under an EPA-approved national security exemption only.”

(2) R&D exemption language. For fuels used for an R&D purpose specified in § 1090.610: “For use in research, development, and test programs only.”

(3) Racing fuel language. For fuels used for racing purposes specified in § 1090.615: “This fuel is for racing purposes only.”

(4) Aviation fuel language. For fuels used in aircraft specified in § 1090.615: “This fuel is for aviation use only.”

(5) Territory fuel exemption language. For fuels for use in American Samoa, Guam, or the Commonwealth of the Northern Mariana Islands specified in § 1090.620: “This fuel is for use only in Guam, American Samoa, or the Northern Mariana Islands.”

(6) California gasoline language. For California gasoline specified in § 1090.625: “California gasoline”.

(7) California diesel language. For California diesel specified in § 1090.625: “California diesel”.

(8) Alaska, Hawaii, Puerto Rico, and U.S. Virgin Islands summer gasoline language. For summer gasoline for use in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands specified in § 1090.630: “This summer gasoline is for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands.”

(9) Exported fuel language. For exported fuels specified in § 1090.645: “This fuel is for export from the United States only.”

(b) In statements required by paragraph (a) of this section, where “fuel” is designated in a statement, the specific fuel type (for example, “diesel fuel” or “gasoline”) may be used in place of the word “fuel”.

§ 1090.1110

PTD requirements for gasoline, gasoline additives, and gasoline regulated blendstocks.

(a) General requirements. On each occasion when any person transfers custody or title of any gasoline, gasoline additive, or gasoline regulated blendstock, other than when fuel is sold or dispensed to the ultimate end user at a retail outlet or WPC facility, the transferor must provide the transferee PTDs that include the following information:

(1) All applicable information required under § 1090.1100 and this section.

(2) An accurate and clear statement of the applicable designation of the gasoline, gasoline additive, or gasoline regulated blendstock under § 1090.1010.

(b) BOB language requirements. For batches of BOB, in addition to the information required under paragraph (a) of this section, the following information must be included on the PTD:

(1) Oxygenate type(s) and amount(s). Statements specifying each oxygenate type and amount (or range of amounts) for which the BOB was certified under § 1090.710(a)(5).

(2) Summer BOB language requirements. (i) Except as specified in paragraph (b)(2)(ii) of this section, for batches of summer BOB, identification of the product with one of the following statements indicating the applicable RVP standard in § 1090.215:

(A) “9.0 psi CBOB. This product does not meet the requirements for summer reformulated gasoline.”

(B) “7.8 psi CBOB. This product does not meet the requirements for summer reformulated gasoline.”

(C) “RBOB. This product meets the requirements for summer reformulated or conventional gasoline.”

(ii) For BOBs designed to produce a finished gasoline that must meet an RVP standard required by any SIP approved or promulgated under 42 U.S.C. 7410 or 7502, additional or substitute language to satisfy the state program may be used as necessary but must include at a minimum the applicable RVP standard established under the SIP.

(c) RFG and CG requirements. For batches of RFG and CG, in addition to the information required under paragraph (a) of this section, the following information must be included on the PTD:

(1) Summer gasoline language requirements. (i) Except as specified in paragraph (c)(1)(ii) of this section, for summer gasoline, identification of the product with one of the following statements indicating the applicable RVP standard:

(A) For gasoline that meets the 9.0 psi RVP standard in § 1090.215(a)(1): “9.0 psi Gasoline.”

(B) For gasoline that meets the 7.8 psi RVP standard in § 1090.215(a)(2): “7.8 psi Gasoline.”

(C) For gasoline that meets the RFG 7.4 psi RVP standard in § 1090.215(a)(3): “Reformulated Gasoline.”

(ii) For finished gasoline that meets an RVP standard required by any SIP approved or promulgated under 42 U.S.C. 7410 or 7502, additional or substitute language to satisfy the state program may be used as necessary.

(2) Ethanol content language requirements. (i) For gasoline-ethanol blends, one of the following statements that accurately describes the gasoline:

(A) For gasoline containing no ethanol (“E0”), the following statement: “E0: Contains no ethanol.”

(B) For finished gasoline containing less than 9 volume percent ethanol, the following statement: “EX—Contains up to X% ethanol.” The term X refers to the maximum volume percent ethanol present in the gasoline-ethanol blend.

(C) For E10, the following statement: “E10: Contains between 9 and 10 vol % ethanol.”

(D) For E15, the following statement: “E15: Contains between 10 and 15 vol % ethanol.”

(E) For gasoline-ethanol blends containing more than 15 volume percent ethanol, the following statement: “EXX: Contains up to XX vol % ethanol.” The term XX refers to the maximum volume percent ethanol present in the gasoline-ethanol blend.

(ii) No person may designate a fuel as E10 if the fuel is produced by blending ethanol and gasoline in a manner designed to contain less than 9.0 or more than 10.0 volume percent ethanol.

(iii) No person may designate a fuel as E15 if the fuel is produced by blending ethanol and gasoline in a manner designed to contain less than 10.0 or more than 15.0 volume percent ethanol.

(d) Oxygenate language requirements. In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any oxygenate upstream of any oxygenate blending facility, the transferor must provide to the transferee PTDs that include the following information, as applicable:

(1) For DFE: “Denatured fuel ethanol, maximum 10 ppm sulfur.”

(2) For other oxygenates, the name of the specific oxygenate must be identified on the PTD, followed by “maximum 10 ppm sulfur.” For example, for isobutanol, the following statement on the PTD would be required, “Isobutanol, maximum 10 ppm sulfur.”

(e) Gasoline detergent language requirements. In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any gasoline detergent, the transferor must provide to the transferee PTDs that include the following information:

(1) The identity of the product being transferred as detergent, detergent-additized gasoline, or non-additized detergent gasoline.

(2) The name of the registered detergent must be used to identify the detergent additive package on its PTD and the LAC on the PTD must be consistent with the requirements in § 1090.260.

(f) Gasoline additives language requirements. In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any gasoline additive that meets the requirements in § 1090.265(a), the transferor must provide to the transferee PTDs that include the following information:

(1) The maximum allowed treatment rate of the additive so that the additive will contribute no more than 3 ppm sulfur to the finished gasoline.

(2) [Reserved]

(g) Certified ethanol denaturant language requirements. In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any certified ethanol denaturant that meets the requirements in § 1090.275, the transferor must provide to the transferee PTDs that include the following information:

(1) The following statement: “Certified Ethanol Denaturant suitable for use in the manufacture of denatured fuel ethanol meeting EPA standards.”

(2) The PTD must state that the sulfur content is 330 ppm or less. If the certified ethanol denaturant manufacturer represents a batch of denaturant as having a maximum sulfur content lower than 330 ppm, the PTD must instead state that lower sulfur maximum (e.g., has a sulfur content of 120 ppm or less).

(h) Butane and pentane language requirements. (1) In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any certified butane or certified pentane, the transferor must provide to the transferee PTDs that include the following information:

(i) The certified butane or certified pentane producer company name and, for the certified pentane producer, the facility registration number issued by EPA.

(ii) One of the following statements, as applicable:

(A) “Certified pentane for use by certified pentane blenders.”

(B) “Certified butane for use by certified butane blenders.”

(2) PTDs must be transferred from each party transferring certified butane or certified pentane for use by a certified butane or certified pentane blender to each party that receives the certified butane or certified pentane through to the certified butane or certified pentane blender, respectively.

(i) TGP language requirements. In addition to any other PTD requirements of this subpart, on each occasion when any person transfers custody or title to any TGP, the transferor must provide to the transferee PTDs that include the following information:

(1) The following statement: “Transmix Gasoline Product—not for use as gasoline.”

(2) [Reserved]

§ 1090.1115

PTD requirements for distillate and residual fuels.

(a) General requirements. On each occasion when any person transfers custody or title of any distillate or residual fuel, other than when fuel is sold or dispensed to the ultimate end user at a retail outlet or WPC facility, the transferor must provide the transferee PTDs that include the following information:

(1) The sulfur per-gallon standard that the transferor represents the fuel to meet under subpart D of this part (e.g., 15 ppm sulfur for ULSD or 1,000 ppm sulfur for ECA marine fuel).

(2) An accurate and clear statement of the applicable designation(s) of the fuel under § 1090.1015 (e.g., “ULSD”, “500 ppm LM diesel fuel”, or “ECA marine fuel”).

(3) If the fuel does not meet the sulfur standard in § 1090.305(b) for ULSD, the following statement: “Not for use in highway vehicles or engines or nonroad, locomotive, or marine engines.”

(b) 500 ppm LM diesel fuel language requirements. For batches of 500 ppm LM diesel fuel, in addition to the information required under paragraph (a) of this section, PTDs must include the following information:

(1) The following statement: “500 ppm sulfur (maximum) LM diesel fuel. For use only in accordance with a compliance plan under 40 CFR 1090.515(g). Not for use in highway vehicles or other nonroad vehicles and engines.”

(2) [Reserved]

(c) ECA marine fuel language requirements. For batches of ECA marine fuel, in addition to the information required under paragraph (a) of this section, PTDs must include the following information:

(1) The following statement: “1,000 ppm sulfur (maximum) ECA marine fuel. For use in Category 3 marine vessels only. Not for use in Category 1 or Category 2 marine vessels.”

(2) A party may replace the required statement in paragraph (c)(1) of this section with the following statement for qualifying vessels under 40 CFR part 1043: “High sulfur fuel. For use only in ships as allowed by MARPOL Annex VI, Regulation 3 or Regulation 4.”

(3) Under 40 CFR 1043.80, a fuel supplier (i.e., the person who transfers custody or title of marine fuel onto a vessel) must provide bunker delivery notes to vessel operators.

(d) Distillate global marine fuel language requirements. For batches of distillate global marine fuel, in addition to the information required under paragraph (a) of this section, PTDs must include the following information:

(1) The following statement: “5,000 ppm sulfur (maximum) Distillate Global Marine Fuel. For use only in steamships or Category 3 marine vessels outside of an Emission Control Area (ECA), consistent with MARPOL Annex VI.”

(2) [Reserved]

§ 1090.1120

PTD requirements for diesel fuel additives.

In addition to any other PTD requirements in this subpart, on each occasion when any person transfers custody or title to a diesel fuel additive that is subject to the provisions of § 1090.310 to a party in the additive distribution system or in the diesel fuel distribution system for use downstream of the diesel fuel manufacturing facility, the transferor must provide to the transferee PTDs that include the following information:

(a) For diesel fuel additives that comply with the sulfur standard in § 1090.310(a), the following statement: “The sulfur content of this diesel fuel additive does not exceed 15 ppm.”

(b) For diesel fuel additives that meet the requirements in § 1090.310(b), the transferor must provide to the transferee PTDs that identify the additive as such, and comply with all the following:

(1) Indicate the high sulfur potential of the diesel fuel additive by including the following statement: “This diesel fuel additive may exceed the federal 15 ppm sulfur standard. Improper use of this additive may result in non-compliant diesel fuel.”

(2) If the diesel fuel additive package contains a static dissipater additive or red dye having a sulfur content greater than 15 ppm, one of the following statements must be included that accurately describes the contents of the additive package:

(i) “This diesel fuel additive contains a static dissipater additive having a sulfur content greater than 15 ppm.”

(ii) “This diesel fuel additive contains red dye having a sulfur content greater than 15 ppm.”

(iii) “This diesel fuel additive contains a static dissipater additive and red dye having a sulfur content greater than 15 ppm.”

(3) Include the following information:

(i) The diesel fuel additive package's maximum sulfur concentration.

(ii) The maximum recommended concentration for use of the diesel fuel additive package in diesel fuel, in volume percent.

(iii) The contribution to the sulfur content of the fuel (in ppm) that would result if the diesel fuel additive package is used at the maximum recommended concentration.

(c) For diesel fuel additives that are sold in containers for use by the ultimate consumer of diesel fuel, each transferor must display on the additive container, in a legible and conspicuous manner, one of the following statements, as applicable:

(1) For diesel fuel additives that comply with the sulfur standard in § 1090.310(a): “This diesel fuel additive complies with the federal low sulfur content requirements for use in diesel motor vehicles and nonroad engines.”

(2) For diesel fuel additives that do not comply with the sulfur standard in § 1090.310(a), the following statement: “This diesel fuel additive does not comply with federal ultra-low sulfur content requirements.”

§ 1090.1125

Alternative PTD language.

(a) Alternative PTD language to the language specified in this subpart may be used if approved by EPA in advance. Such language must contain all the applicable informational elements specified in this subpart.

(b) Requests for alternative PTD language must be submitted as specified in § 1090.10.

Subpart M—Recordkeeping

§ 1090.1200

General recordkeeping requirements.

(a) Length of time records must be kept. Records required under this part must be kept for 5 years from the date they were created, except that records relating to credit transfers must be kept by the transferor for 5 years from the date the credits were transferred and must be kept by the transferee for 5 years from the date the credits were transferred, used, or terminated, whichever is later.

(b) Make records available to EPA. On request by EPA, the records specified in this part must be provided to EPA. For records that are electronically generated or maintained, the equipment and software necessary to read the records must be made available or, upon approval by EPA, electronic records must be converted to paper documents that must be provided to EPA.

§ 1090.1205

Recordkeeping requirements for all regulated parties.

(a) Overview. Any party subject to the requirements and provisions of this part must keep records containing the information specified in this section.

(b) PTDs. Any party that transfers custody or title of any fuel, fuel additive, or regulated blendstock must maintain the PTDs for which the party is the transferor or transferee.

(c) Sampling and testing. Any party that performs any sampling and testing on any fuel, fuel additive, or regulated blendstock must keep records of the following information:

(1) The location, date, time, and storage tank or truck, rail car, or vessel identification for each sample collected.

(2) The identification of the person(s) who collected the sample and the person(s) who performed the testing.

(3) The results of all tests as originally printed by the testing apparatus, or where no printed result is produced, the results as originally recorded by the person or apparatus that performed the test. Where more than one test is performed, all the results must be retained.

(4) The methodology used for any testing under this part.

(5) Records related to performance-based measurement and statistical quality control under §§ 1090.1360 through 1090.1375.

(6) Records related to gasoline deposit control testing under § 1090.1395.

(7) Records demonstrating the actions taken to stop the sale of any fuel, fuel additive, or regulated blendstock that is found not to be in compliance with applicable standards under this part, and the actions taken to identify the cause of any noncompliance and prevent future instances of noncompliance.

(d) Registration. Any party required to register under subpart I of this part must maintain records supporting the information required to complete and maintain the registration for the party's company and each registered facility. The party must also maintain copies of any confirmation received from the submission of such registration information to EPA.

(e) Reporting. Any party required to submit reports under subpart J of this part must maintain copies of all reports submitted to EPA. The party must also maintain copies of any confirmation received from the submission of such reports to EPA.

(f) Exemptions. Any party that produces or distributes exempt fuel, fuel additive, or regulated blendstock under subpart G of this part must keep the following records:

(1) Records demonstrating the designation of the fuel, fuel additive, or regulated blendstock under subparts G and K of this part.

(2) Copies of PTDs generated or accompanying the exempt fuel, fuel additive, or regulated blendstock.

(3) Records demonstrating that the exempt fuel, fuel additive, or regulated blendstock was actually used in accordance with the requirements of the applicable exemption(s) under subpart G of this part.

§ 1090.1210

Recordkeeping requirements for gasoline manufacturers.

(a) Overview. In addition to the requirements in § 1090.1205, a gasoline manufacturer must keep records for each of their facilities that include the information in this section.

(b) Batch records. For each batch of gasoline, a gasoline manufacturer must keep records of the following information:

(1) The results of tests, including any calculations necessary to transcribe or correlate test results into reported values under subpart J of this part, performed to determine gasoline properties and characteristics as specified in subpart N of this part.

(2) The batch volume.

(3) The batch number.

(4) The date the batch was produced or imported.

(5) The designation of the batch under § 1090.1010.

(6) The PTDs for any gasoline produced or imported.

(7) The PTDs for any gasoline received.

(c) Downstream oxygenate accounting. For BOB for which the gasoline manufacturer has accounted for oxygenate added downstream under § 1090.710, a gasoline manufacturer must keep records of the following information:

(1) The test results for hand blends prepared under § 1090.1340.

(2) Records that demonstrate that the gasoline manufacturer participates in the NFSP under § 1090.1405.

(3) Records that demonstrate that the gasoline manufacturer participates in the NSTOP under § 1090.1450.

(4) Compliance calculations specified in § 1090.700 based on an assumed addition of oxygenate.

(d) PCG and TGP. For new batches of gasoline produced by adding blendstock to PCG or TGP, a gasoline manufacturer must keep records of the following information:

(1) Records that reflect the storage and movement of the PCG or TGP and blendstock within the fuel manufacturing facility to the point such PCG or TGP is used to produce gasoline or BOB.

(2) For new batches of gasoline produced by adding blendstock to PCG or TGP under § 1090.1320(a)(1) or § 1090.1325, respectively, keep records of the following additional information:

(i) The results of tests to determine the sulfur content, benzene content, oxygenate(s) content, and in the summer, RVP, for the PCG or TGP and volume of the PCG or TGP when received at the fuel manufacturing facility.

(ii) Records demonstrating which specific batches of PCG or TGP were used in each new batch of gasoline.

(iii) Records demonstrating which blendstocks were used in each new batch of gasoline.

(iv) Records of the test results for sulfur content, benzene content, oxygenate(s) content, distillation parameters, and in the summer, RVP, for each new batch of gasoline.

(3) For new batches of gasoline produced by adding blendstock to PCG or TGP under § 1090.1320(a)(2), keep records of the following additional information:

(i) Records of the test results for sulfur content, benzene content, oxygenate(s) content, and in the summer, RVP, of each blendstock used to produce the new batch of gasoline.

(ii) Records of the test results for sulfur content and in the summer, RVP, of each new batch of gasoline.

(iii) Records demonstrating which blendstocks were used in each new batch of gasoline.

(e) Certified butane and certified pentane blenders. For certified butane or certified pentane blended into gasoline or BOB under § 1090.1320, a certified butane or certified pentane blender must keep records of the following information:

(1) The volume of certified butane or certified pentane added.

(2) The purity and properties of the certified butane or certified pentane specified in § 1090.250 or § 1090.255, respectively.

(f) Importation of gasoline treated as blendstock. For any imported GTAB, an importer must keep records of documents that reflect the storage and physical movement of the GTAB from the point of importation to the point of blending to produce gasoline or the point at which the GTAB was certified as gasoline.

(g) ABT. A gasoline manufacturer must keep records of the following information related to their ABT activities under subpart H of this part, as applicable:

(1) Compliance sulfur values and compliance benzene values under § 1090.700, and the calculations used to determine those values.

(2) The number of valid credits in possession of the gasoline manufacturer at the beginning of each compliance period, separately by facility and compliance period of generation.

(3) The number of credits generated by the gasoline manufacturer under § 1090.725, separately by facility and compliance period of generation.

(4) If any credits were obtained from or transferred to other parties, all the following for each other party:

(i) The party's name.

(ii) The party's EPA company 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).

§ 1090.1215

Recordkeeping requirements for diesel fuel, ECA marine fuel, and distillate global marine fuel manufacturers.

(a) Overview. In addition to the requirements in § 1090.1205, a diesel fuel or ECA marine fuel manufacturer must keep records for each of their facilities that include the information in this section.

(b) Batch records. For each batch of ULSD, 500 ppm LM diesel fuel, or ECA marine fuel, a diesel fuel or ECA marine fuel manufacturer must keep records of the following information:

(1) The batch volume.

(2) The batch number.

(3) The date the batch was produced or imported.

(4) The designation of the batch under § 1090.1015.

(5) All documents and information created or used for the purpose of batch designation under § 1090.1015, including PTDs for the batch.

(c) Distillate global marine fuel manufacturers. For distillate global marine fuel, a distillate global marine fuel manufacturer must keep records of the following information:

(1) The designation of the fuel as distillate global marine fuel.

(2) The PTD for the distillate global marine fuel.

§ 1090.1220

Recordkeeping requirements for oxygenate blenders.

(a) Overview. In addition to the requirements in § 1090.1205, an oxygenate blender that blends oxygenate into gasoline must keep records that include the information in this section.

(b) Oxygenate blenders. For each occasion that an oxygenate blender blends oxygenate into gasoline, the oxygenate blender must keep records of the following information:

(1) The date, time, location, and identification of the blending tank or truck in which the blending occurred.

(2) The volume and oxygenate requirement of the gasoline to which oxygenate was added.

(3) The volume, type, and purity of the oxygenate that was added, and documents that show the supplier(s) of the oxygenate used.

§ 1090.1225

Recordkeeping requirements for gasoline additives.

(a) Gasoline additive manufacturers. In addition to the requirements in § 1090.1205, a gasoline additive manufacturer must keep records of the following information for each batch of additive produced or imported:

(1) The batch volume.

(2) The date the batch was produced or imported.

(3) The PTD for the batch.

(4) The maximum recommended treatment rate.

(5) The gasoline additive manufacturer's control practices that demonstrate that the additive will contribute no more than 3 ppm on a per-gallon basis to the sulfur content of gasoline when used at the maximum recommended treatment rate.

(b) Parties that take custody of gasoline additives. Except for gasoline additives packaged for addition to gasoline in the vehicle fuel tank, all parties that take custody of gasoline additives for bulk addition to gasoline—from the producer through to the gasoline additive blender that adds the additive to gasoline—must keep records of the following information:

(1) The PTD for each batch of gasoline additive.

(2) The treatment rate at which the additive was added to gasoline, as applicable.

(3) The volume of gasoline that was treated with the additive, as applicable. A new record must be initiated in each case where a new batch of additive is mixed into a storage tank from which the additive is drawn to be injected into gasoline.

§ 1090.1230

Recordkeeping requirements for oxygenate producers.

(a) Oxygenate producers. In addition to the requirements in § 1090.1205, an oxygenate producer must keep records of the following information for each batch of oxygenate:

(1) The batch volume.

(2) The batch number.

(3) The date the batch was produced or imported.

(4) The PTD for the batch.

(5) The sulfur content of the batch.

(6) The sampling and testing records specified in § 1090.1205(c), if the sulfur content of the batch was determined by analytical testing.

(b) DFE producers. In addition to the requirements of paragraph (a) of this section, a DFE producer must keep records of the following information for each batch of DFE if the sulfur content of the batch was determined under § 1090.1330:

(1) The name and title of the person who calculated the sulfur content of the batch.

(2) The date the calculation was performed.

(3) The calculated sulfur content.

(4) The sulfur content of the neat (un-denatured) ethanol.

(5) The date each batch of neat ethanol was produced.

(6) The neat ethanol batch number.

(7) The neat ethanol batch volume.

(8) As applicable, the neat ethanol production quality control records, or the test results on the neat ethanol, including all the following:

(i) The location, date, time, and storage tank or truck identification for each sample collected.

(ii) The name and title of the person who collected the sample and the person who performed the test.

(iii) The results of the test as originally printed by the testing apparatus, or where no printed result is produced, the results as originally recorded by the person who performed the test.

(iv) Any record that contains a test result for the sample that is not identical to the result recorded in paragraph (b)(8)(iii) of this section.

(v) The test methodology used.

(9) The sulfur content of each batch of denaturant used, and the volume percent at which the denaturant was added to neat (un-denatured) ethanol to produce DFE.

(10) The PTD for each batch of denaturant used.

(c) Parties that take custody of oxygenate. All parties that take custody of oxygenate—from the oxygenate producer through to the oxygenate blender—must keep records of the following information:

(1) The PTD for each batch of oxygenate.

(2) [Reserved]

§ 1090.1235

Recordkeeping requirements for ethanol denaturant.

(a) Certified ethanol denaturant producers. In addition to the requirements in § 1090.1205, a certified ethanol denaturant producer must keep records of the following information for each batch of certified ethanol denaturant:

(1) The batch volume.

(2) The batch number.

(3) The date the batch was produced or imported.

(4) The PTD for the batch.

(5) The sulfur content of the batch.

(b) Parties that take custody of ethanol denaturants. All parties that take custody of denaturant designated as suitable for use in the production of DFE under § 1090.270(b) must keep records of the following information:

(1) The PTD for each batch of denaturant.

(2) The volume percent at which the denaturant was added to ethanol, as applicable.

§ 1090.1240

Recordkeeping requirements for gasoline detergent blenders.

(a) Overview. In addition to the requirements in § 1090.1205, a gasoline detergent blender must keep records that include the information in this section.

(b) Gasoline detergent blenders. A gasoline detergent blender must keep records of the following information:

(1) The PTD for each detergent used.

(2) For an automated detergent blending facility, the following information:

(i) The dates of the VAR Period.

(ii) The total volume of detergent blended into gasoline, as determined using one of the following methods, as applicable:

(A) For a facility that uses in-line meters to measure the amount of detergent blended, the total volume of detergent measured, together with supporting data that includes one of the following:

(1) The beginning and ending meter readings for each meter being measured.

(2) Other comparable metered measurements.

(B) For a facility that uses a gauge to measure the inventory of the detergent storage tank, the total volume of detergent must be calculated as follows:

V_D = DI_i− DI_f+ DI_a− DI _w

Where:

V_D = Volume of detergent.

DI_i = Initial detergent inventory of the tank.

DI_f = Final detergent inventory of the tank.

DI_a = Sum of any additions to detergent inventory.

DI_w = Sum of any withdrawals from detergent inventory for purposes other than the additization of gasoline.

(C) The value of each variable in the equation in paragraph (b)(2)(ii)(B) of this section must be separately recorded. Recorded volumes of detergent must be expressed to the nearest gallon (or smaller units), except that detergent volumes of five gallons or less must be expressed to the nearest tenth of a gallon (or smaller units). However, if the blender's equipment is unable to accurately measure to the nearest tenth of a gallon, then such volumes must be rounded downward to the next lower gallon.

(iii) The total volume of gasoline to which detergent has been added, together with supporting data that includes one of the following:

(A) The beginning and ending meter measurements for each meter being measured.

(B) The metered batch volume measurements for each meter being measured.

(C) Other comparable metered measurements.

(iv) The actual detergent concentration, calculated as the total volume of detergent added (as determined under paragraph (b)(2)(ii) of this section) divided by the total volume of gasoline (as determined under paragraph (b)(2)(iii) of this section). The concentration must be calculated and recorded to four digits and rounded as specified in § 1090.50.

(v) The initial detergent concentration rate, together with the date and description of each adjustment to any initially set concentration.

(vi) If the detergent injector is set below the applicable LAC, or adjusted by more than 10 percent above the concentration initially set in the VAR Period, documentation establishing that the purpose of the change is to correct a batch misadditization prior to the end of the VAR Period and prior to the transfer of the batch to another party or to correct an equipment malfunction and the date and adjustments of the correction.

(vii) Documentation reflecting the performance and results of the calibration of detergent equipment under § 1090.1390.

(3) For a non-automated detergent blending facility, keep records of the following information:

(i) The date of additization.

(ii) The volume of detergent added.

(iii) The volume of gasoline to which the detergent was added.

(iv) The actual detergent concentration, calculated as the volume of detergent added (per paragraph (b)(3)(ii) of this section) divided by the volume of gasoline (per paragraph (b)(3)(iii) of this section). The concentration must be calculated and recorded to four digits and rounded as specified in § 1090.50.

§ 1090.1245

Recordkeeping requirements for independent surveyors.

(a) Overview. In addition to the requirements in § 1090.1205, an independent surveyor must keep records that include the information in this section.

(b) Independent surveyors. An independent surveyor must keep records of the following information, as applicable:

(1) Records related to the NFSP under § 1090.1405.

(2) Records related to a geographically-focused E15 survey program under § 1090.1420(b).

(3) Records related to the NSTOP under § 1090.1450.

§ 1090.1250

Recordkeeping requirements for auditors.

(a) Overview. In addition to the requirements in § 1090.1205, an auditor must keep records that include the information in this section.

(b) Auditors. An auditor must keep records of the following information:

(1) Documents pertaining to the performance of each audit performed under subpart S of this part, including all correspondence between the auditor and the fuel manufacturer.

(2) Copies of each attestation report prepared and all related records developed to prepare the attestation report.

§ 1090.1255

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

(a) Overview. In addition to the requirements in § 1090.1205, a transmix processor, transmix blender, transmix distributor, or pipeline operator must keep records that include the information in this section.

(b) Transmix. (1) A transmix processor or transmix distributor must keep records that reflect the results of any sampling and testing required under subpart F or M of this part.

(2) A transmix processor must keep records showing the volumes of TGP recovered from transmix and the type and amount of any blendstock or PCG added to make gasoline from TGP under § 1090.505.

(3) A transmix processor that adds blendstock to TGP or PCG must keep records under § 1090.1210(d).

(4) A transmix blender must keep records showing compliance with the quality assurance program and/or sampling and testing requirements in § 1090.500, and for each batch of gasoline with which transmix is blended, the volume of the batch, and the volume of transmix blended into the batch.

(c) 500 ppm LM diesel fuel. A manufacturer or distributor of 500 ppm LM diesel fuel using transmix must keep records of the following information, as applicable:

(1) Copies of the compliance plan required under § 1090.515(g).

(2) Documents demonstrating how the party complies with each applicable element of the compliance plan under § 1090.515(g).

(3) Documents and copies of calculations used to determine compliance with the 500 ppm LM diesel fuel volume requirements under § 1090.515(c).

(4) Documents or information that demonstrates that the 500 ppm LM diesel fuel was only used in locomotive and marine engines that are not required to use ULSD under 40 CFR 1033.815 and 40 CFR 1042.660, respectively.

(d) Pipeline operators. A pipeline operator must keep records that demonstrate compliance with the interface handling practices in § 1090.520.

Subpart N—Sampling, Testing, and Retention

§ 1090.1300

General provisions.

(a) This subpart is organized as follows:

(1) Sections 1090.1310 through 1090.1330 specify the scope of required testing, including special provisions that apply in several unique circumstances.

(2) Sections 1090.1335 through 1090.1345 specify handling procedures for collecting and retaining samples. Sections 1090.1350 through 1090.1375 specify the procedures for measuring the specified parameters. These procedures apply to anyone who performs testing under this subpart.

(3) Section 1090.1390 specifies the requirements for calibrating automated detergent blending equipment.

(4) Section 1090.1395 specifies the procedures for testing related to gasoline deposit control test procedure.

(b) If you need to meet requirements for a quality assurance program at a minimum frequency, your first batch of product triggers the testing requirement. The specified frequency serves as a deadline for performing the required testing, and as a starting point for the next testing period. The following examples illustrate the requirements for testing based on sampling the more frequent of every 90 days or 500,000 gallons of certified butane you received from a supplier:

(1) If your testing period starts on March 1 and you use less than 500,000 gallons of butane from March 1 through May 29 (90 days), you must perform testing under a quality assurance program sometime between March 1 and May 29. Your next test period starts with the use of butane on May 30 and again ends after 90 days or after you use 500,000 gallons of butane, whichever occurs first.

(2) If your testing period starts on March 1 and you use 500,000 gallons of butane for the testing period on April 29 (60 days), you must perform testing under a quality assurance program sometime between March 1 and April 29. Your next testing period starts with the use of butane on April 30 and again ends after 90 days or after you use 500,000 gallons of butane, whichever occurs first.

(c) Anyone acting on behalf of a regulated party to demonstrate compliance with requirements under this part must meet the requirements of this subpart in the same way that the party needs to meet those requirements for its own testing. The regulated party and the third party will both be liable for any violations arising from the third party's failure to meet the requirements of this subpart.

(d) Anyone performing tests under this subpart must apply good laboratory practices for all sampling, measurement, and calculations related to testing required under this part. This requires performing these procedures in a way that is consistent with generally accepted scientific and engineering principles and properly accounting for all available relevant information.

(e) Subpart Q of this part has provisions related to importation, including additional provisions that specify how to meet the sampling and testing requirements of this subpart.

Scope of Testing

§ 1090.1310

Testing to demonstrate compliance with standards.

(a) Perform testing as needed to certify fuel, fuel additive, or regulated blendstock as specified in subpart K of this part. This section specifies additional test requirements.

(b) A fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer must perform the following measurements before fuel, fuel additive, or regulated blendstock from a given batch leaves the facility, except as specified in § 1090.1315:

(1) Diesel fuel. Perform testing for each batch of ULSD, 500 ppm LM diesel fuel, and ECA marine fuel to demonstrate compliance with sulfur standards.

(2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur standards and perform testing for each batch of summer gasoline to demonstrate compliance with RVP standards.

(c) The following testing provisions apply for gasoline, oxygenate, certified ethanol denaturant, certified butane, and certified pentane:

(1) A gasoline manufacturer producing BOB for which oxygenate added downstream is accounted for under § 1090.710 must prepare a hand blend as specified in § 1090.1340 and perform the following measurements:

(i) Measure the sulfur content of both the BOB and the hand blend.

(ii) Except as specified in § 1090.1325(c), measure the benzene content of the hand blend.

(iii) For Summer CG, measure the RVP of the BOB.

(iv) For Summer RFG, measure the RVP of the hand blend.

(2) A gasoline manufacturer producing gasoline for which oxygenate added downstream is not accounted for under § 1090.710 (e.g., E0 or so-called suboctane gasoline) must perform the following measurements:

(i) Measure the sulfur content of the gasoline.

(ii) Except as specified in § 1090.1325(c), measure the benzene content of the gasoline.

(iii) For Summer CG and Summer RFG, measure the RVP of the gasoline.

(iv) For Summer RFG that is designated as “Intended for Oxygenate Blending” under § 1090.1010(a)(4), create a hand blend as specified in § 1090.1340 and measure the RVP of the hand blend.

(v) For gasoline blended with oxygenate, measure the oxygenate content of the gasoline.

(3) An oxygenate producer must measure the sulfur content of each batch of oxygenate, except that a DFE producer may meet the alternative requirements in § 1090.1330.

(4) An ethanol denaturant producer that certifies denaturant under § 1090.1330 must measure the sulfur content of each batch of denaturant.

(5) A certified butane or certified pentane producer must perform sampling and testing to demonstrate compliance with purity specifications and sulfur and benzene standards as specified in § 1090.1320.

(6) A transmix processor producing gasoline from TGP must test each batch of gasoline for parameters required to demonstrate compliance with § 1090.505 as specified in § 1090.1325.

(d) A blending manufacturer producing gasoline by adding blendstock to PCG must comply with § 1090.1320.

(e) For gasoline produced at a fuel blending facility or a transmix processing facility, a gasoline manufacturer must measure such gasoline for oxygenate and for distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue). However, a fuel manufacturer or transmix processor does not need to measure the oxygenate content of gasoline if PCG, transmix, TGP, and blendstocks used to produce the batch did not contain any oxygenates, based on the following documentation:

(1) For PCG, documentation consists of oxygenate content identified on PTDs.

(2) For transmix, TGP, and blendstocks, documentation consists of affidavits or oxygenate test results from the person providing the transmix or blendstock stating that these products do not contain oxygenate.

§ 1090.1315

In-line blending.

A fuel manufacturer using in-line blending equipment may qualify for a waiver from the requirement in § 1090.1310(b) to test every batch of fuel before the fuel leaves the fuel manufacturing facility as follows:

(a) Submit a request signed by the RCO to EPA with the following information:

(1) Describe the location of your in-line blending operation, how long it has been in operation, and how much of each type and grade of fuel you have blended over the preceding 3 years (or since starting the in-line blending operation if it is less than 3 years). Describe the physical layout of the blending operation and how you move the blended fuel into distribution. Also describe how your automated system monitors and controls blending proportions and the properties of the blended fuel. For new installations, describe these as a planned operation with projected volumes by type and grade. Describe clearly which portions of your blending operation are the subject of your waiver request.

(2) Describe how you collect and test composite fuel samples in a way that is equivalent to measuring the fuel properties of a batch of blended fuel as specified in this subpart. Also describe how your procedures conform to the sampling specifications in ASTM D4177 and the composite calculations in ASTM D5854 (both incorporated by reference in § 1090.95).

(3) Describe any expectation or plan for you or another party to perform additional downstream testing for the same fuel parameters.

(4) Describe your quality assurance procedures. Explain how you will ensure that all fuel will meet all applicable per-gallon standards. Describe any experiences from the previous 3 years where these quality assurance procedures led you to make corrections to your in-line blending operation. Describe how you will deal with release of fuel that fails to meet a per-gallon standard.

(5) Describe any times from the previous 3 years that you modified fuel after it left your facility. Describe how you modified the fuel and why that was necessary.

(6) Describe how you will meet the auditing requirements specified in § 1090.1850 and any additional, facility-specific considerations that relate to those auditing requirements.

(b) You must arrange for an audit of your blending operation each calendar year as specified in § 1090.1850. The audit must review procedures and documents to determine whether measured and calculated values properly represent the aggregate fuel properties for the blended fuel.

(c) You must submit an updated in-line blending waiver request to EPA 60 days before making any material change to your in-line blending process. Examples of material changes include changing analyzer hardware or programming, changing the location of the analyzer, changing the piping configuration, changing the mixing control hardware or programming logic, changing sample compositors or compositor settings, or expanding fuel blending capacity. Changing the name of the company or business unit is an example of a change that is not material.

(d) If EPA approves your request for a waiver under this section, you may need to update your procedures for more effective control and documentation of measured fuel parameters based on audit results, development of improved practices, or other information.

§ 1090.1320

Adding blendstock to PCG.

The requirements of this section apply for a refiner or blending manufacturer that adds blendstock to PCG to produce a new batch of gasoline. Paragraph (b) of this section specifies an alternative approach for a certified butane or certified pentane blender. Section 1090.1325 describes additional provisions that apply to a transmix processor.

(a) Sample and test using one of the following methods to exclude PCG from the compliance demonstration for sulfur and benzene:

(1) Compliance by subtraction. (i) Determine the sulfur content, benzene content, and oxygenate content of the PCG before blending blendstocks to produce a new batch of gasoline as follows:

(A) Sample and test the sulfur content, benzene content, and oxygenate content of each batch of PCG. The blending manufacturer does not need to test PCG for oxygenate content if they can demonstrate that the PCG does not contain oxygenates as specified in paragraph (a)(1)(i)(C) of this section or § 1090.1310(e)(1).

(B) If the PCG is a BOB, prepare a hand blend under § 1090.1340 and test the hand blend for sulfur content and benzene content.

(C) The blending manufacturer may use the PCG manufacturer's certification test results if the PCG was received directly from the PCG manufacturer by an in-tank transfer or tank-to-tank transfer within the same terminal as long as the results are from the PCG that is being transferred.

(ii) Determine the volume of PCG that was blended with blendstock to produce a new batch of gasoline. Report the PCG as a negative batch as specified in § 1090.905(c)(3)(i).

(iii) After adding blendstock to PCG, sample and test the sulfur content, benzene content, and for summer gasoline, RVP, of the new batch of gasoline.

(iv) Determine the volume of the new batch of gasoline. Report the new batch of gasoline as a positive batch as specified in § 1090.905(c)(3)(ii).

(v) Include the PCG batch and the new batch of gasoline in compliance calculations as specified in § 1090.700(d)(4)(i).

(vi) The sample retention requirements in § 1090.1345 apply for both the new batch of gasoline and the associated PCG.

(2) Compliance by addition. (i) Sample and test the sulfur content and benzene content of each batch of blendstock used to produce a new batch of gasoline from PCG using the procedures in § 1090.1350. The homogeneity requirements for gasoline specified in § 1090.1337 apply to blendstock and GTAB collected with manual sampling.

(ii) Determine the volume of each batch of blendstock used to produce the new batch of gasoline.

(iii) Determine the volume of each blended batch of gasoline, and measure the sulfur content and for summer gasoline, RVP, for each blended batch of gasoline using the procedures specified in § 1090.1350. Testing the blended batch of gasoline for sulfur content, however, is not required if the fuel manufacturer tests the added blendstock and determines that both the blendstock and PCG meet the fuel manufacturing facility gate sulfur per-gallon standard in § 1090.205(b).

(iv) Report each batch of blendstock as specified in § 1090.905(c)(4).

(v) Include each batch of blendstock in compliance calculations as specified in § 1090.700(d)(4)(ii).

(vi) The sample retention requirements in § 1090.1345 apply for the new batch of gasoline and for each blendstock.

(b) A certified butane or certified pentane blender that blends certified butane or certified pentane into PCG to make a new batch of gasoline may comply with the following requirements instead of the requirements of paragraph (a) of this section:

(1) For summer gasoline, measure RVP of the blended fuel. The fuel manufacturer may rely on sulfur and benzene test results from the certified butane or certified pentane producer. Note that § 1090.220(e) disallows adding certified butane or certified pentane to Summer RFG or Summer RBOB.

(2) Before blending the certified butane or certified pentane with PCG, obtain a copy of the producer's test results indicating that the certified butane or certified pentane meets the standards in § 1090.250 or § 1090.255, respectively.

(3) The certified pentane blender must enter into a contract with the certified pentane producer to verify that the certified pentane producer has an adequate quality assurance program to ensure that the certified pentane received will not be contaminated in transit.

(4) The certified butane or certified pentane blender must conduct a quality assurance program to demonstrate that the certified butane or certified pentane meets the standards specified in § 1090.250 or § 1090.255, respectively. The quality assurance program must be based on sampling the more frequent of every 90 days or 500,000 gallons of certified butane or certified pentane received from each distributor. The certified butane or certified pentane blender may rely on a third party to perform the testing.

(c) This paragraph describes provisions that apply in cases where PCG is a BOB for which the PCG manufacturer accounted for oxygenate added downstream under § 1090.710 and the blending manufacturer makes a new batch that includes less oxygenate than was specified for the BOB by the PCG manufacturer. A blending manufacturer in this circumstance does not qualify for the small volume blender exemption for BOB recertification under § 1090.740(a)(3) and must comply with all the following.

(1) Calculate and incur sulfur and benzene deficits under the BOB recertification provisions in § 1090.740.

(2) Comply with either the compliance by subtraction requirements of paragraph (a)(1) of this section or the compliance by addition requirements of paragraph (a)(2) of this section. For compliance by subtraction, test the PCG without adding oxygenate (i.e., test the PCG “neat”), and report the PCG volume without adjusting for the volume of oxygenate that the PCG manufacturer specified under § 1090.740.

§ 1090.1325

Adding blendstock or PCG to TGP.

The following provisions apply to a transmix processor or blending manufacturer producing gasoline by adding blendstock or PCG to TGP:

(a) Determine the volume, sulfur content, and benzene content of each blendstock batch used to produce gasoline for reporting and compliance calculations by following the sampling and testing requirements in § 1090.1320 and treating the TGP used to produce the gasoline as PCG.

(b) Sample and test the gasoline made from TGP and PCG or blendstock to demonstrate compliance with the fuel manufacturing facility gate sulfur per-gallon standard in § 1090.205(b) and the applicable RVP standard in § 1090.215.

(c) A transmix processor producing gasoline by only adding TGP to PCG does not have to measure the benzene content of the finished gasoline.

§ 1090.1330

Preparing denatured fuel ethanol.

Instead of measuring every batch, a DFE producer or importer may calculate the sulfur content of a batch of DFE as follows:

(a) Determine the sulfur content of ethanol before adding denaturant by measuring it as specified in § 1090.1310 or by estimating it based on your production quality control procedures.

(b) Use the ppm sulfur content of certified ethanol denaturant specified on the PTD for the batch. If the sulfur content is specified as a range, use the maximum specified value.

(c) Calculate the weighted sulfur content of the DFE using the values determined under paragraphs (a) and (b) of this section.

Handling and Preparing Samples

§ 1090.1335

Collecting, preparing, and testing samples.

(a) General provisions. Use good laboratory practice to collect samples to represent the batch you are testing. For example, take steps to ensure that a batch is always well mixed before sampling. Also, always take steps to prevent sample contamination, such as completely flushing sampling taps and piping and pre-rinsing sample containers with the product being sampled. Follow the procedures in paragraph (b) of this section for manual sampling. Follow the procedures paragraph (c) of this section for automatic sampling. Additional requirements for measuring RVP are specified in paragraph (d) of this section. A description of how to determine compliance based on single or multiple tests on single or multiple samples is specified in paragraph (e) of this section.

(b) Manual sampling. Perform manual sampling using one of the methods specified in ASTM D4057 (incorporated by reference in § 1090.95) to demonstrate compliance with standards as follows:

(1) Collect a “running” or “all-levels” sample from the top of the tank. Drawing a sample from a standpipe is acceptable only if it is slotted or perforated to ensure that the drawn sample properly represents the whole batch of fuel.

(2)(i) Use tap sampling or spot sampling to collect upper, middle, and lower samples if a running or all-levels sample is impractical for a given storage configuration. Collect samples that most closely match the recommendations in Table 5 of ASTM D4057. Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057, as applicable.

(ii) Spot sampling must not be used for certification testing unless the tank contains less than 10 feet of product.

(3) If the procedures in paragraphs (b)(1) and (2) of this section are impractical for a given storage configuration, you may use alternative sampling procedures as specified in ASTM D4057. This applies primarily for sampling with trucks, railcars, retail stations, and other downstream locations.

(4) Test results with manual sampling are valid only after you demonstrate homogeneity as specified in § 1090.1337.

(5) Except as specified for marine vessels in § 1090.1605, you must not do certification testing with a composite sample from manual sampling.

(c) Automatic sampling. (1) For in-line blending waivers under § 1090.1315, follow all specifications for automatic sampling as specified in EPA's approval letter instead of or in addition to the specifications in paragraph (c)(2) of this section. Automatic sampling is also appropriate for a configuration involving a pipeline filling a tank that will be certified as compliant before it leaves the fuel manufacturing facility gate.

(2) Perform automatic sampling as specified in ASTM D4177 (incorporated by reference in § 1090.95), with the following additional specifications:

(i) Configure the system to ensure a well-mixed stream at the sampling point. Align the start and end of sampling with the start and end of creating the batch.

(ii) The default sampling frequency must follow the recommended approach of at least 9,604 samples to represent a batch. Less frequent sampling is acceptable as long as the interval between samples does not exceed 20 seconds throughout the batch.

(iii) Collect three samples for individual measurements in addition to the composite sample. Draw head, middle, and tail samples after flowing 15, 50, and 85 percent of the estimated batch volume, respectively.

(iv) EPA may approve a different sampling strategy under an approved in-line blending waiver under § 1090.1315 if it is appropriate for a given facility or for a small-volume batch.

(d) Sampling provisions related to measuring RVP of summer gasoline. The following additional provisions apply for preparing samples to measure RVP of summer gasoline:

(1) Meet the additional specifications for manual and automatic sampling in ASTM D5842 (incorporated by reference in § 1090.95).

(2) If you measure other fuel parameters for a given sample in addition to RVP testing, always measure RVP first.

(e) Testing to demonstrate compliance with standards. (1) Perform testing as specified in this subpart.

(2) For parameters subject to per-gallon standards, report the highest measured value (or the lowest measured value for testing related to cetane index or other parameters that are subject to a standard representing a minimum value). This applies for repeat tests on a given sample and for testing multiple samples (including head, middle, and tail samples from automatic sampling). A batch is noncompliant if any tested sample does not meet all applicable per-gallon standards.

(3) In the case of automatic sampling for parameters subject to average standards, report the result from the composite sample to represent the batch for demonstrating compliance with the average standard. For any repeat testing with the composite sample, calculate the arithmetic average from all tests to represent the batch.

(4) In the case of manual sampling for parameters subject to average standards, determine the value representing the batch as follows:

(i) For testing with only a single sample, report that value to represent the batch. If there are repeat tests with that sample, report the arithmetic average from all tests to represent the sample.

(ii) For testing with more than one sample, report the arithmetic average from all tested samples to represent the batch. If there are repeat tests for any sample, calculate the arithmetic average of those repeat tests to determine a single value to represent that sample before calculating the average value to represent the batch.

§ 1090.1337

Demonstrating homogeneity.

(a) Certification test results corresponding to manual sampling as specified in § 1090.1335(b) are valid only if collected samples meet the homogeneity specifications in this section, except that the homogeneity testing requirement does not apply in the following cases:

(1) There is only a single sample using the procedure specified in § 1090.1335(b)(2).

(2) Upright cylindrical tanks that have a liquid depth of less than 10 feet.

(3) You draw spot or tap samples as specified in paragraph (c) of this section, test each sample for every parameter subject to a testing requirement, and use the worst-case test result for each parameter for purposes of reporting, meeting per-gallon and average standards, and all other aspects of compliance.

(4) Sampling at a downstream location where it is not possible to collect separate samples and steps are taken to ensure that the batch is well mixed.

(b)(1) Testing performed to establish homogeneity is not considered certification testing, except as specified in paragraph (b)(2) of this section.

(2) Homogeneity testing may be used as certification testing if any of the following criteria are met:

(i) All tested samples meet all applicable per-gallon standards.

(ii) The testing meets the requirement in § 1090.1335(b)(2)(ii).

(iii) The testing follows the procedures specified in paragraph (a)(3) of this section.

(c) Use spot sampling as specified in § 1090.1335(b)(2) for homogeneity testing. Tap sampling is acceptable if spot sampling is impractical for a given facility.

(d) Demonstrate homogeneity for gasoline using two of the procedures specified in this paragraph (d) with each sample. For summer gasoline, the homogeneity demonstration must include RVP measurement.

(1) Measure API gravity using ASTM D287, ASTM D1298, ASTM D4052, or ASTM D7777 (incorporated by reference in § 1090.95).

(2) Measure the sulfur content as specified in § 1090.1360.

(3) Measure the benzene content as specified § 1090.1360.

(4) Measure the RVP as specified in § 1090.1360.

(e) For testing to meet the diesel fuel standards in subpart D of this part, demonstrate homogeneity using one of the procedures specified in paragraph (d)(1) or (2) of this section.

(f) Consider the batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than the published reproducibility of the test method multiplied by 0.75 (R × 0.75). If reproducibility is a function of measured values, calculate reproducibility using the average value of the measured parameter representing all tested samples. Calculate using all meaningful significant figures as specified for the test method, even if § 1090.1350(c) describes a different precision. For cases that do not require a homogeneity demonstration under paragraph (a) of this section, the lack of homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or regulated blendstock from being considered a batch for demonstrating compliance with the requirements of this part.

§ 1090.1340

Preparing a hand blend from BOB.

(a) If you produce or import BOB and instruct downstream blenders to add oxygenate, you must meet the requirements of this subpart by blending oxygenate that reflects the anticipated sulfur content and benzene content of the oxygenate for blending into a BOB sample. To do this, prepare each hand blend by adding oxygenate to the BOB sample in a way that corresponds to your instructions to downstream blenders for the sampled batch of fuel. Prepare a hand blend as follows:

(1) Take steps to avoid introducing high or low bias in sulfur content when selecting from available samples to prepare the hand blend. For example, if there are three samples with discrete sulfur measurements, select the sample with the mid-range sulfur content. In other cases, randomly select the sample.

(2) If your instructions allow for a downstream blender to add more than one type or concentration of oxygenate, prepare the hand blend as follows:

(i) For summer gasoline intended for blending with ethanol, use the lowest specified ethanol blend.

(ii) For all winter gasoline and for summer gasoline intended for blending only with oxygenate other than ethanol, use the lowest specified oxygenate concentration, regardless of the type of oxygenate.

(iii) As an example, if you give instructions for a given batch of BOB to perform downstream blending to make E10, E15, and an 8 percent blend with butanol, prepare a hand blend for testing winter gasoline with 8 percent butanol, and prepare an E10 hand blend for testing summer gasoline.

(b) Prepare the hand blend using the procedures specified in ASTM D7717 (incorporated by reference in § 1090.95). The hand blend must have an amount of oxygenate that does not exceed the oxygenate concentration specified on the PTD for the BOB under § 1090.1110(b)(1).

§ 1090.1345

Retaining samples.

(a) Retain samples as follows:

(1) A fuel manufacturer, regulated blendstock producer, or independent surveyor must keep representative samples of gasoline, diesel fuel, or oxygenate that is subject to certification testing requirements under this subpart for at least 30 days after testing is complete, except that a longer sample retention of 90 days applies for a blending manufacturer that produces gasoline.

(2) A certified pentane producer must keep representative samples of certified pentane for at least 30 days after testing is complete.

(3) A blending manufacturer required to test blendstock under § 1090.1320(a)(2) must keep representative samples of the blendstock and the new batch of gasoline for at least 90 days after testing is complete.

(4) An oxygenate producer or importer must keep oxygenate samples as follows:

(i) Keep a representative sample of any tested oxygenate. Also keep a representative sample of DFE if you used the provisions of § 1090.1330 to calculate its sulfur content.

(ii) Keep all the samples you collect over the previous 21 days. If you have fewer than 20 samples from the previous 21 days, continue keeping the most recent 20 samples collected up to a maximum of 90 days for any given sample.

(5) The nominal volume of retained liquid samples must be at least 330 ml. If you have only a single sample for testing, keep that sample after testing is complete. If you collect multiple samples from a single batch or you create a hand blend, select a representative sample as follows:

(i) If you are required to test a hand blend under § 1090.1340, keep a sample of the BOB and a sample representative of the oxygenate used to prepare the hand blend.

(ii) For summer gasoline, keep an untested (or less tested) sample that is most like the tested sample, as applicable. In all other cases, keep the tested (or most tested) sample.

(c) Keep records of all calculations, test results, and test methods for the batch associated with each stored sample.

(d) If EPA requests a test sample, you must follow EPA's instructions and send it to EPA by a courier service (or equivalent). The instructions will describe where and when to send the sample. For each test sample, you must identify the test results and test methods used.

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

Measurement Procedures

§ 1090.1350

Overview of test procedures.

A fuel manufacturer, fuel additive manufacturer, regulated blendstock producer, or independent surveyor meets the requirements of this subpart based on laboratory measurements of the specified fuel parameters. Test procedures for these measurements apply as follows:

(a) Except as specified in paragraph (b) of this section, the Performance-based Measurement System specified in §§ 1090.1360 through 1090.1375 applies for all testing specified in this subpart for the following fuels and fuel parameters:

(1) Sulfur content of diesel fuel.

(2) Sulfur content of ECA marine fuel.

(3) RVP, sulfur content, benzene content, and oxygenate content of gasoline. The procedures for measuring sulfur in gasoline in this subpart also apply for testing sulfur in certified ethanol denaturant; however, demonstrating compliance for alternative procedures in § 1090.1365 and statistical quality control in § 1090.1375 do not apply for sulfur concentration above 80 ppm.

(4) Sulfur content of butane.

(b) Specific test procedures apply for measuring other fuel parameters, as follows:

(1) Determine the cetane index of diesel fuel as specified in ASTM D976 or ASTM D4737 (incorporated by reference in § 1090.95). There is no cetane-related test requirement for biodiesel that meets ASTM D6751 (incorporated by reference in § 1090.95).

(2) Measure aromatic content of diesel fuel as specified in ASTM D1319 or ASTM D5186 (incorporated by reference in § 1090.95). You may use an alternative procedure if you correlate your test results with ASTM D1319 or ASTM D5186. There is no aromatics-related test requirement for biodiesel that meets ASTM D6751.

(3) Measure the purity of butane as specified in ASTM D2163 (incorporated by reference in § 1090.95). Measure the purity of pentane as specified in ASTM D2163 or ASTM D5134 (incorporated by reference in § 1090.95).

(4) Measure the benzene content of butane and pentane as specified in ASTM D2163, ASTM D5134, ASTM D6729, or ASTM D6730 (incorporated by reference in § 1090.95).

(5) Measure the sulfur content of pentane as specified in ASTM D5453 (incorporated by reference in § 1090.95).

(6) Measure distillation parameters as specified in ASTM D86 (incorporated by reference in § 1090.95). You may use an alternative procedure if you correlate your test results with ASTM D86.

(7) Measure the sulfur content of neat ethanol as specified in ASTM D5453. You may use an alternative procedure if you adequately correlate your test results with ASTM D5453.

(8) Measure the phosphorus content of gasoline as specified in ASTM D3231 (incorporated by reference in § 1090.95).

(9) Measure the lead content of gasoline as specified in ASTM D3237 (incorporated by reference in § 1090.95).

(10) Measure the sulfur content of gasoline additives and diesel fuel additives as specified in ASTM D2622 (incorporated by reference in § 1090.95).

(11) Use referee procedures specified in § 1090.1360(d) and the following additional methods to measure gasoline fuel parameters to meet the survey requirements of subpart O of this part:

Table 1 to Paragraph (b)(11)—Additional Survey Test Methods

Fuel parameter	Units	Test method 1
Distillation	°C	ASTM D86.
Aromatic content	volume percent	ASTM D5769.
Olefin content	volume percent	ASTM D6550.
1 ASTM specifications are incorporated by reference, see § 1090.95.

(12) Updated versions of the test procedures specified in this section are acceptable as alternative procedures if both repeatability and reproducibility are the same or better than the values specified in the earlier version.

(c) Record measured values with the following precision, with rounding in accordance with § 1090.50:

(1) Record sulfur content to the nearest whole ppm.

(2) Record benzene to the nearest 0.01 volume percent.

(3) Record RVP to the nearest 0.01 psi.

(4) Record oxygenate content to the nearest 0.01 mass percent for each calibrated oxygenate.

(5) Record diesel aromatic content to the nearest 0.1 volume percent, or record cetane index to the nearest whole number.

(6) Record gasoline aromatic and olefin content to the nearest 0.1 volume percent.

(7) Record distillation parameters to the nearest whole degree.

(d) For any measurement or calculation that depends on the volume of the test sample, correct the volume of the sample to a reference temperature of 15.56 °C. Use a correction equation that is appropriate for each tested compound. This applies for all fuels, blendstocks, and additives, except butane.

§ 1090.1355

Calculation adjustments and corrections.

Adjust measured values as follows:

(a) Adjust measured values for total vapor pressure as follows:

RVP (psi) = 0.956 · P_total − 0.347

Where:

P_total = Measured total vapor pressure, in psi.

(b) For measuring the sulfur content and benzene content of gasoline, adjust a given test result upward in certain circumstances, as follows:

(1) If your measurement method involves a published procedure with a Pooled Limit of Quantitation (PLOQ), treat the PLOQ as your final result if your measured result is below the PLOQ.

(2) If your measurement method involves a published procedure with a limited scope but no PLOQ, treat the lower bound of the scope as your final result if your measured result is less than that value.

(3) If you establish a Laboratory Limit of Quantitation (LLOQ) below the lower bound of the scope of the procedure as specified in ASTM D6259 (incorporated by reference in § 1090.95), treat the LLOQ as your final result if your measured result is less than the LLOQ. Note that this option is meaningful only if the LLOQ is less than a published PLOQ, or if there is no published PLOQ.

(c) For measuring the sulfur content of ULSD at a downstream location, subtract 2 ppm from the result.

(d) For measuring the benzene content of butane and pentane, report a zero value if the test result is at or below the PLOQ or Limit of Detection (LOD) that applies for the test method.

(e) If measured content of any oxygenate compound is less than 0.20 percent by mass, record the result as “None detected.”

§ 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 a laboratory that uses either referee procedures or alternative procedures.

(3) Streamlined requirements for alternative procedures apply for procedures adopted by a voluntary consensus standards body (VCSB). Certification testing with non-VCSB procedures requires advance approval by EPA. Procedures are considered non-VCSB testing as follows:

(i) Procedures developed by individual companies or other parties are considered non-VCSB procedures.

(ii) Draft procedures under development by a VCSB organization are considered non-VCSB procedures until they are approved for publication.

(iii) A published procedure is considered non-VCSB for testing with fuel parameters that fall outside the range of values covered in the research report of the ASTM D6708 (incorporated by reference in § 1090.95) assessment comparing candidate alternative procedures to the referee procedure specified in paragraph (d) of this section.

(4) You may use updated versions of the referee procedures as alternative procedures subject to the limitations of § 1090.1365(a)(2). You may ask EPA for approval to use an updated version of the referee procedure for qualifying other alternative procedures if the updated referee procedure has the same or better repeatability and reproducibility compared to the version specified in § 1090.95. If the updated procedure has worse repeatability or reproducibility compared to the earlier version, you must complete the required testing specified in § 1090.1365 using the older, referenced version of the referee procedure.

(5) Any laboratory may use the specified referee procedure without qualification testing. To use alternative procedures at a given laboratory, you must perform the specified testing to demonstrate compliance with precision and accuracy requirements, with the following exceptions:

(i) Testing you performed to qualify alternative procedures under 40 CFR part 80 continues to be valid for making the demonstrations required in this part.

(ii) Qualification testing is not required for a laboratory that measures the benzene content of gasoline using Procedure B of ASTM D3606 (incorporated by reference in § 1090.95). However, qualification testing may be necessary for updated versions of this procedure as specified in § 1090.1365(a)(2).

(d) Referee procedures are presumed to meet the initial qualifying criteria in this section. You may use alternative procedures if you qualify them using the referee procedures as a benchmark as specified in § 1090.1365. The following are the referee procedures:

Table 1 to Paragraph (d)—Referee Procedures for Qualifying Alternative Procedures

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

§ 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 § 1090.1360.

(a) The following general provisions apply for qualifying alternative procedures:

(1) Alternative procedures must have appropriate precision to allow for reporting to the number of decimal places specified in § 1090.1350(c).

(2) Testing to qualify an alternative procedure applies for the specified version of the procedure you use for making the necessary measurements. For referee procedures and for alternative procedures for method-defined fuel parameters that you have qualified for your laboratory, updated versions of those same procedures are qualified without further testing, as long as the specified reproducibility is the same as or better than the values specified in the earlier version. For absolute fuel parameters, updated versions are qualified without testing if both repeatability and reproducibility are the same as or better than the values specified in the earlier version.

(3) Except as specified in paragraph (d) of this section, testing to demonstrate compliance with the precision and accuracy specifications in this section apply only for the laboratory where the testing occurred.

(4) If a procedure for measuring benzene or sulfur in gasoline has no specified PLOQ and no specified scope with a lower bound, you must establish a LLOQ for your laboratory.

(5) Testing for method-defined fuel parameters must take place at a reference installation as specified in § 1090.1370.

(b) All alternative procedures must meet precision criteria based on a calculated maximum allowable standard deviation for a given fuel parameter as specified in this paragraph (b). The precision criteria apply for measuring the parameters and fuels specified in paragraph (b)(3) of this section. Take the following steps to qualify the measurement procedure for measuring a given fuel parameter:

(1) The fuel must meet the parameter specifications in Table 1 to paragraph (b)(3) of this section. This may require that you modify the fuel you typically produce to be within the specified range. Absent a specification (maximum or minimum), select a fuel representing values that are typical for your testing. Store and mix the fuel to maintain a homogenous mixture throughout the measurement period to ensure that each fuel sample drawn from the batch has the same properties.

(2) Measure the fuel parameter from a homogeneous fuel batch at least 20 times. Record each result in sequence. Do not omit any valid results unless you use good engineering judgment to determine that the omission is necessary and you document those results and the reason for excluding them. Perform this analysis over a 20-day period. You may make up to 4 separate measurements in a 24-hour period, as long as the interval between measurements is at least 4 hours. Do not measure RVP more than once from a single sample.

(3) Calculate the maximum allowable standard deviation as follows:

Where:

σ_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

Fuel, fuel additive, or regulated blendstock	Fuel parameter	Range	x1	x2 = Repeatability (r) or reproducibility (R) 1	x3	Fixed values of σmax	Source 2
ULSD	Sulfur	5 ppm minimum	1.5	r = 1.33	2.77	0.72	ASTM D3120-08 (R2019).
500 ppm LM diesel fuel	Sulfur	350 ppm minimum	1.5	r = 21.3	2.77	11.5	ASTM D2622-16.
ECA marine fuel	Sulfur	700 ppm minimum	1.5	37.1	2.77	20.1	ASTM D2622-16.
Butane	Sulfur		1.5	r = 0.1152. x	2.77		ASTM D6667-14 (R2019).
Gasoline	Sulfur		1.5	r = 0.4998. x 0.54	2.77		ASTM D7039-15a (R2020).
Gasoline	oxygenate		0.3	R = 0.13. x 0.83	1		ASTM D5599-18.
Gasoline	RVP 3		0.3	R = 0.40	1	0.12	ASTM D5191-20.
Gasoline	Benzene		0.15	R = 0.221. x 0.67	1		ASTM D5769-20.
1 Calculate repeatability and reproducibility using the average value determined from testing. Use units as specified in § 1090.1350(c).
2 ASTM publications are incorporated by reference, see § 1090.95. Note that the listed procedure may be different than the referee procedure identified in § 1090.1360(d), or it may be an older version of the referee procedure.
3 Use only 1-liter containers for testing to qualify alternative methods.

(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:

Δ_max = 0.75 · σ_max

Where:

Δ_max = Maximum allowable difference.

σ_max = the maximum allowable standard deviation from paragraph (b)(3) of this section using the sulfur content represented by ARV.

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

Table 2 to Paragraph (c)(3)(ii)—Accuracy Criteria for Qualifying Alternative Procedures With Diesel Fuel and Diesel-Related Blendstocks and Additives

Fuel	Sulfur content (ppm)	Illustrated maximum allowable differences
ULSD	10-20	0.54
500 ppm LM diesel fuel	450-500	8.65
ECA marine fuel	900-1,000	15.1

(d) Alternative VCSB procedures for measuring method-defined fuel parameters must meet accuracy criteria as follows:

(1) You may use the alternative procedure only if you follow all the statistical protocols and meet all the criteria specified in Section 6 of ASTM D6708 (incorporated by reference in § 1090.95) when comparing your measurements using the alternative procedure to measurements at a reference installation using the appropriate referee procedure identified in § 1090.1360(d).

(2) For qualifying alternative procedures, determine whether the alternative procedure needs a correlation equation to correct bias relative to the reference test method. Create such a correlation equation as specified in Section 7 of ASTM D6708. For all testing, apply the correlation equation to adjust measured values to be statistically consistent to measuring with the reference test method.

(3) If an alternative VCSB procedure states that the procedure has a successful assessment relative to the referee procedures in this section under ASTM D6708, that finding applies for all laboratories using that procedure.

(e) Alternative non-VCSB procedures for measuring absolute fuel parameters (sulfur) must meet accuracy criteria as follows:

(1) Demonstrate whether the procedure meets statistical criteria and whether it needs a correlation equation as specified in paragraphs (d)(1) and (2) of this section. Apply the correlation equation for all testing with the alternative procedure.

(2) Demonstrate at your laboratory that the alternative procedure meets the accuracy criteria specified in paragraph (c) of this section.

(3) Send EPA a written request to use the alternative procedure. In your request, fully describe the procedure to show how it functions for achieving accurate measurements and include detailed information related to your assessment under paragraph (e)(1) and (2) of this section.

(f) Alternative non-VCSB procedures for measuring method-defined fuel parameters must meet accuracy and precision criteria as follows:

(1) Demonstrate whether the procedure meets statistical criteria and whether it needs a correlation equation as specified in paragraphs (e)(1) and (2) of this section. Apply the correlation equation for all testing with the alternative procedure.

(2) Test with a range of fuels that are typical of those you will analyze at your laboratory. Use either consensus-named fuels or locally-named reference materials. Consensus-named fuels are homogeneous fuel quantities sent around to different laboratories for analysis, which results in a “consensus name” representing the average value of the parameter for all participating laboratories. Locally named reference materials are fuel samples analyzed using the reference test method, either at your laboratory or at a reference installation, to establish an estimated value for the fuel parameter; locally named reference materials usually come from the fuel you produce.

(3) You may qualify your procedure as meeting the requirements of paragraph (f)(1) of this section only for a narrower, defined range of fuels. If this is the case, identify the appropriate range of fuels in your request for approval and describe how you will screen fuel samples accordingly.

(4) Qualify the precision of the alternative procedure by comparing results to testing with the referee procedure based on “between methods reproducibility,” Rxy, as specified in ASTM D6708. The Rxy must be at or below 75 percent of the reproducibility of the referee procedure in § 1090.1360(d).

(5) Perform testing at your laboratory as specified in paragraph (b) of this section to establish the repeatability of the alternative procedure. The repeatability must be as good as or better than that specified in paragraph (b)(3) of this section.

(6) Fully describe the procedure to show how it functions for achieving accurate measurements. Describe the technology, test instruments, and testing method so a competent person lacking experience with the procedure and test instruments would be able to replicate the results.

(7) Engage a third-party auditor to review and verify your information as follows:

(i) The auditor must qualify as an independent third party and meet the specifications for technical ability as specified in § 1090.55.

(ii) The auditor must send you a report describing their inspection of your laboratories and their review of the information supporting your request to use the alternative procedure. The report must describe how the auditor performed the review, identify any errors or discrepancies, and state whether the information supports a conclusion that the alternative procedure should be approved.

(iii) The auditor must keep records related to the review for at least 5 years after sending you the report and provide those records to EPA upon request.

(8) Send EPA a written request to use the alternative procedure. Include the specified information and any additional information EPA needs to evaluate your request.

(g) Keep fuel samples from any qualification testing under this section for at least 180 days after you have taken all steps to qualify an alternative procedure under this section. This applies for testing at your laboratory and at any reference installation you use for demonstrating the accuracy of an alternative procedure.

§ 1090.1370

Qualifying criteria for reference installations.

(a) A reference installation refers to a laboratory that uses the referee procedure specified in § 1090.1360(d) to evaluate the accuracy of alternative procedures for method-defined parameters, by comparing measured values to companion tests using one of the referee procedures in § 1090.1360(d). This evaluation may result in an equation to correlate results between the two procedures. Once a laboratory qualifies as a reference installation, that qualification is valid for five years from the qualifying date, consistent with good laboratory practices.

(b) You may qualify a reference installation for VCSB procedures by participating in an interlaboratory crosscheck program with at least 16 separate measurements that are not identified as outliers. This presumes that the results for the candidate reference installation are not outliers.

(c) You may qualify a reference installation for VCSB or non-VCSB procedures based on the following measurement protocol:

(1) Use the precision testing procedure specified in § 1090.1365(b) to show that your standard deviation for tests using the reference test method is at or below 0.3 times the reproducibility for a given fuel parameter.

(2) You must correlate your test results for a given fuel parameter against the accepted reference values from a monthly crosscheck program based on Section 6.2.2.1 and Note 7 of ASTM D6299 (incorporated by reference in § 1090.95) as follows:

(i) If there are multiple fuels available from the crosscheck program, select the fuel that has the closest value to the standard. If there is no standard for a given fuel parameter, select the fuel with values for the fuel parameter that best represent typical values for fuels you test.

(ii) Measure the fuel parameter for the crosscheck fuel at your laboratory using the appropriate referee procedure. Calculate a mean value that includes all your repeat measurements.

(iii) Determine the mean value from the crosscheck program and calculate the difference between this value and the mean value from your testing. Express this difference as a certain number of standard deviations relative to the data set from the crosscheck program.

(iv) The calculated monthly difference between the mean values from § 1090.1365(c)(3)(ii) for 5 consecutive months must fall within the central 50 percent of the distribution of data at least 3 times. The central 50 percent of the distribution corresponds to 0.68 standard deviations.

(v) Calculate the mean value of the differences from § 1090.1365(c)(3)(ii) for all 5 months. This mean value must fall within the central 50 percent of the distribution of data from the crosscheck program. For example, if the difference was 0.5 standard deviations for two months, 0.6 for one month, and 0.7 for two months, the mean value of the difference is 0.6 standards deviations, and the reference installation meets the requirements of this paragraph.

(3) You must demonstrate that the reference installation is in statistical quality control for at least 5 months with the designated procedure as specified in ASTM D6299. 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.

§ 1090.1375

Quality control procedures.

This section specifies ongoing quality testing requirements as part of the Performance-based Measurement System specified in § 1090.1360.

(a) General provisions. You must perform testing to show that your laboratory meets specified precision and accuracy criteria as follows:

(1) The testing requirement applies for the referee procedures in § 1090.1360(d) and for alternate procedures that are qualified or approved under § 1090.1365. The testing requirements apply separately for each test instrument at each laboratory.

(2) If you fail to conduct specified testing, your test instrument is not qualified for measuring fuel parameters to demonstrate compliance with the standards and other specifications of this part until you perform this testing. Similarly, if your test instrument fails to meet the specified criteria, it is not qualified for measuring fuel parameters to demonstrate compliance with the standards and other specifications of this part until you make the necessary changes to your test instrument and perform testing to show that the test instrument again meets the specified criteria.

(3) If you perform major maintenance such as overhauling an instrument, confirm that the instrument still meets precision and accuracy criteria before you start testing again based on the procedures specified in ASTM D6299 (incorporated by reference in § 1090.95).

(4) Keep records to document your testing under this section for 5 years.

(b) Precision demonstration. Show that you meet precision criteria as follows:

(1) Meeting the precision criteria of this paragraph (b) qualifies your test instrument for performing up to 20 tests or 7 days, whichever is less. Include all tests except for testing to meet precision or accuracy requirements.

(2) Perform precision testing using the control-chart procedures in ASTM D6299. If you opt to use procedure 2A (Q-Procedure) or 2B (dynamically updated exponentially weighted moving average), validate the first run on the new QC batch by either an overlap in-control result of the old batch, or by a single execution of an accompanying standard reference material. The new QC material result would be considered validated if the single result of the standard reference material is within the established site precision (R') of the ARV of the standard reference material.

(3) Use I charts and MR charts as specified in ASTM D6299 to show that the standard deviation for the test instrument meets the precision criteria specified in § 1090.1365(b).

(c) Accuracy demonstration. For absolute fuel parameters (VCSB and non-VCSB) and for method-defined fuel parameters using non-VCSB methods, you must show that you meet accuracy criteria as specified in this paragraph (c). For method-defined VCSB procedures, you may meet accuracy requirements as specified in this paragraph (c) or by comparing your results to the accepted reference value in an inter-laboratory crosscheck program sponsored by ASTM International or another VCSB at least 3 times per year.

(1) Meeting the accuracy criteria of this paragraph (c) qualifies your test instrument for 130 days.

(2) Except as specified in paragraph (c)(3) of this section, test every instrument using a check standard meeting the specifications of ASTM D6299. Select a fuel sample with an ARV that is at or slightly below the standard that applies. If there are both average and batch standards, use the average standard. If there is no standard, select a fuel sample representing fuel that is typical for your testing.

(3) The following provisions apply for method-defined non-VCSB alternative procedures with high sensitivity to sample-specific bias:

(i) Procedures have high sensitivity if the closeness sum of squares (CSS) statistic exceeds the 95th percentile value, as specified in ASTM D6708 (incorporated by reference in § 1090.95).

(ii) Create a check standard from production fuel representing the fuel you will routinely analyze. Determine the ARV of your check standard using the protocol in ASTM D6299 at a reference installation as specified in § 1090.1370.

(iii) You must send EPA a fuel sample from every twentieth batch of gasoline or diesel fuel and identify the procedures and corresponding test results from your testing. EPA may return one of your samples to you for further testing; if this occurs, you must repeat your measurement and report your results within 180 days of receiving the fuel sample.

(4) You meet accuracy requirements under this section if the difference between your measured value for the check standard and the ARV is less than the value from the following equation:

Where:

Δ_max = Maximum allowable difference.

R = Reproducibility of the referee procedure identified in § 1090.1360(d), as noted in Table 1 to paragraph (b)(3) of § 1090.1365 or in the following table:

Table 1 to Paragraph (c)(4)—Criteria for Qualifying Alternative Procedures

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

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

Testing Related to Gasoline Deposit Control

§ 1090.1390

Requirement for Automated Detergent Blending Equipment Calibration.

(a) An automated detergent blending facility must calibrate their automated detergent blending equipment once in each calendar half-year, with the acceptable calibrations being no less than 120 days apart.

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

§ 1090.1395

Gasoline deposit control test procedures.

A gasoline detergent manufacturer must perform testing using one of the methods specified in this section to establish the lowest additive concentration (LAC) for the detergent.

(a) Top Tier-Based Test Method. Use the procedures specified in ASTM D6201 (incorporated by reference in § 1090.95), as follows:

(1) Use a base fuel that conforms to the specifications for gasoline-alcohol blends in ASTM D4814 (incorporated by reference in § 1090.95). Blendstocks used to formulate the test fuel must be derived from conversion units downstream of distillation, with all processes representing normal fuel manufacturing facility operations. Blendstocks must not come from chemical grade streams. Butane and pentane may be added to adjust vapor pressure. The base fuel should include any nondetergent additives typical of commercially available fuel if they may positively or negatively affect deposit formation. In addition, the base fuel must have the following properties:

(i) 8.0-10.0 volume percent DFE that meets the requirements in § 1090.270 and conforms to the specifications of ASTM D4806 (incorporated by reference in § 1090.95).

(ii) At least 8.0 volume percent olefins.

(iii) At least 15 volume percent aromatics.

(iv) No more than 80 ppm sulfur.

(v) T90 distillation temperature at or above 143 °C.

(vi) No detergent-active substance. A base fuel with typical nondetergent additives, such as antioxidants, corrosion inhibitors, and metal deactivators, may be used.

(2) Perform the 100-hour test for intake valve deposits with the base fuel to demonstrate that the intake valves accumulate at least 500 mg on average. If the test engine fails to accumulate enough deposits, make any necessary adjustments and repeat the test. This demonstration is valid for any further detergent testing with the same base fuel.

(3) Repeat the test on the same engine with a specific concentration of detergent added to the base fuel. If the test results in less than 50 mg average per intake valve, the tested detergent concentration is the LAC for the detergent.

(b) CARB Test Method. Use the procedures specified by CARB in Title 13, California Code of Regulations, section 2257 (incorporated by reference in § 1090.95).

(1) A detergent tested under this option or certified under 40 CFR 80.163(d) prior to January 21, 2021, may be used at the LAC specified for use in the state of California in any gasoline in the United States.

(2) The gasoline detergent manufacturer must cease selling a detergent immediately upon being notified by CARB that the CARB certification for this detergent has been invalidated and must notify EPA under 40 CFR 79.21.

(c) EPA BMW method. Use the procedures specified in ASTM D5500 (incorporated by reference in § 1090.95), as follows:

(1) Prepare the test fuel with the following specification:

(i) Sulfur—minimum 340 ppm.

(ii) T90—minimum 171 °C.

(iii) Olefins—minimum 11.4 volume percent.

(iv) Aromatics—minimum 31.1 volume percent.

(v) Ethanol—minimum 10 volume percent.

(vi) Sulfur, T90, olefins, and aromatics specifications must be met before adding ethanol.

(vii) Di-tert-butyl disulfide may be added to the test fuel.

(2) The duration of testing may be less than 10,000 miles. Measured deposits must meet the following specified values to qualify the test fuel and establish a detergent's LAC:

(i) Measured deposits for the fuel without detergent must be at least 290 mg per valve on average.

(ii) Measured deposits for the fuel with detergent must be less than 100 mg per valve on average.

(d) Alternative test methods. (1) An EPA-approved alternative test method may be used if the alternative test method can be correlated to any of the methods specified in paragraphs (a) through (c) of this section.

(2) Information describing the alternative test method and analysis demonstrating correlation must be submitted for EPA approval as specified in § 1090.10.

Subpart O—Survey Provisions

§ 1090.1400

General provisions.

(a) Program plan approval process. (1) A program plan that complies with the requirements in § 1090.1415 or § 1090.1450 must be submitted to EPA no later than October 15 of the year preceding the calendar year in which the program will be conducted.

(2) The program plan must be signed by an RCO of the independent surveyor conducting the program.

(3) The program plan must be submitted as specified in § 1090.10.

(4) EPA will send a letter to the party submitting the program plan that indicates whether EPA approves or disapproves the plan.

(b) Independent surveyor contract. (1) No later than December 15 of the year preceding the year in which the survey will be conducted, the contract with the independent surveyor must be in effect, and the amount of compensation necessary to carry out the entire survey plan must either be paid to the independent surveyor or placed into an escrow account with instructions to the escrow agent to remit the compensation to the independent surveyor during the course of the survey plan.

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

§ 1090.1405

National fuels survey program.

(a) Program participation. (1) A gasoline manufacturer that elects to account for oxygenate added downstream under § 1090.710 must participate in the national fuels survey program (NFSP) specified in this paragraph (b) of this section.

(2) A party required to participate in an E15 survey under § 1090.1420(a) must participate in the NFSP specified in paragraph (b) of this section or a survey program approved by EPA under § 1090.1420(b) or (c).

(3) Other parties may elect to participate in the NFSP for purposes of establishing an affirmative defense against violations of requirements and provisions under this part as specified in § 1090.1720.

(b) Program requirements. The NFSP must meet all the following requirements:

(1) The survey program must be planned and conducted by an independent surveyor that meets the independence requirements in § 1090.55 and the requirements specified in § 1090.1410.

(2) The survey program must be conducted by collecting samples representative of gasoline and diesel retail outlets in the United States as specified in § 1090.1415.

§ 1090.1410

Independent surveyor requirements.

The independent surveyor conducting the NFSP must meet all the following requirements:

(a) Submit a proposed survey program plan under § 1090.1415 to EPA for approval for each calendar year.

(b)(1) Obtain samples representative of the gasoline and diesel fuel (including diesel fuel made available at retail to nonroad vehicles, engines, and equipment) offered for sale separately from all gasoline and diesel retail outlets in accordance with the survey program plan approved by EPA, or immediately notify EPA of any refusal of a retailer to allow samples to be taken.

(2) Obtain the number of samples representative of the number of gasoline retail outlets offering E15.

(3) Collect samples of gasoline produced at blender pump using “method 1” specified in NIST Handbook 158 (incorporated by reference, see § 1090.95). All other samples of gasoline and diesel fuel must be collected using the methods specified in subpart N of this part.

(4) Samples must be shipped via ground service to an EPA-approved laboratory within 2 business days of being collected.

(c) Test, or arrange to be tested, the collected samples, as follows:

(1) Gasoline samples must be analyzed for oxygenate content, sulfur content, and benzene content. Gasoline samples collected from June 1 through September 15 must also be analyzed for RVP.

(2) A subset of gasoline samples, as determined under § 1090.1415(e)(3), must also be analyzed for aromatics content, olefins content, and distillation parameters.

(3) Diesel samples must be analyzed for sulfur content.

(4) All samples must be tested by an EPA-approved laboratory using the test methods specified in subpart N of this part.

(5) All testing must be completed by the EPA-approved laboratory within 10 business days after receipt of the sample.

(d) Verify E15 labeling requirements at gasoline retail outlets that offer E15 for sale.

(e) Using procedures specified in an EPA-approved plan under § 1090.1415, notify EPA, the retailer, and the branded fuel manufacturer (if applicable) within 24 hours after the EPA-approved laboratory has completed analysis when any of the following occur:

(1) A test result for a gasoline sample yields a sulfur content result that exceeds the downstream sulfur per-gallon standard in § 1090.205(c).

(2) A test result for a gasoline sample yields an RVP result that exceeds the applicable RVP standard in § 1090.215.

(3) A test result for a diesel sample yields a sulfur content result that exceeds the sulfur standard in § 1090.305(b).

(4) A test result for a gasoline sample identified as “E15” yields an ethanol content result that exceeds 15 volume percent.

(5) A test result for a gasoline sample not identified as “E15” yields an ethanol content of more than 10 volume percent ethanol.

(f) Provide quarterly and annual summary reports that include the information specified in § 1090.925(b) and (c), respectively.

(g) Keep records related to the NFSP as specified in § 1090.1245(b)(1).

(h) Submit contracts to EPA as specified in § 1090.1400(b).

(i) Permit any representative of EPA to monitor at any time the conducting of the survey, including sample collection, transportation, storage, and analysis.

§ 1090.1415

Survey program plan design requirements.

The survey program plan must include all the following:

(a) Number of surveys. The survey program plan must include 4 surveys each calendar year that occur during the following time periods:

(1) One survey during the period of January 1 through March 31.

(2) One survey during the period of April 1 through June 30.

(3) One survey during the period of July 1 through September 30.

(4) One survey during the period of October 1 through December 31.

(b) Sampling areas. The survey program plan must include sampling in all sampling strata during each survey. These sampling strata must be further divided into discrete sampling areas or clusters. Each survey must include sampling in at least 40 sampling areas in each stratum that are randomly selected.

(c) No advance notice of surveys. The survey program plan must include procedures to keep the identification of the sampling areas that are included in the plan confidential from any participating party prior to the beginning of a survey in an area. However, this information must not be kept confidential from EPA.

(d) Gasoline and diesel retail outlet selection. (1) Gasoline and diesel retail outlets to be sampled in a sampling area must be selected from among all gasoline retail outlets in the United States that sell gasoline with the probability of selection proportionate to the volume of gasoline sold at the retail outlet. The sample of retail outlets must also include gasoline retail outlets with different brand names as well as those gasoline retail outlets that are unbranded.

(2) For any gasoline or diesel retail outlet from which a sample of gasoline or diesel was collected during a survey and was reported to EPA under § 1090.1410(e), that gasoline or diesel retail outlet must be included in the subsequent survey.

(3) At least one sample of a product dispensed as E15 must be collected at each gasoline retail outlet when E15 is present, and separate samples must be taken that represent the gasoline contained in each storage tank at the gasoline retail outlet unless collection of separate samples is not practicable.

(4) At least one sample of a product dispensed as diesel fuel must be collected at each diesel fuel retail outlet when diesel fuel is present. Samples of diesel fuel may be collected at retail outlets that sell gasoline.

(e) Number of samples. (1) The number of retail outlets to be sampled must be independently calculated for the total number of gasoline retail outlets and the total number of diesel fuel retail outlets. The same retail outlet may represent both a gasoline retail outlet and a diesel fuel retail outlet for purposes of determining the number of samples.

(2) The minimum number of samples to be included in the survey program plan for each calendar year is calculated as follows:

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_α = Upper percentile point from the normal distribution to achieve a one-tailed 95% confidence level (5% α-level). For purposes of this survey program, Z_α equals 1.645.

Z_β = Upper percentile point to achieve 95% power. For purposes of this survey program, Z_β equals 1.645.

ϕ₁ = 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).

ϕ₀ = The underlying proportion of non-compliant outlets in a sample. For the first survey program plan, ϕ₀ will be 2.3%. For subsequent survey program plans, ϕ₀ will be the average of the proportion of outlets found to be non-compliant over the previous 4 surveys.

F_a = 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. F_a must be greater than or equal to 1.1.

F_b = Adjustment factor for the number of samples required to resample each retail outlet with test results reported to EPA under § 1090.1410(e), based on the rate of resampling required during the previous 4 surveys. F_b must be greater than or equal to 1.1.

Su_n = Number of surveys per year. For purposes of this survey program, Su_n equals 4.

St_n = Number of sampling strata. For purposes of this survey program, St_n equals 3.

(3) The number of gasoline samples that also need to be tested for aromatics, olefins, and distillation parameters under § 1090.1410(c)(2) must be calculated using the methodology specified in paragraph (e)(2) of this section without the F_a, F_b, and Su_n parameters.

(4) The number of samples determined under paragraphs (e)(2) and (3) of this section must be distributed approximately equally among the 4 surveys conducted during the calendar year.

(f) Laboratory designation. Any laboratory that the independent surveyor intends to use to test samples collected as part of the NFSP must be approved annually as part of the survey program plan approval process in § 1090.1400(a). In the survey program plan submitted to EPA, the independent surveyor must include the following information regarding any laboratory they intend to use to test samples:

(1) The name of the laboratory.

(2) The address of the laboratory.

(3) The test methods for each fuel parameter measured at the laboratory.

(4) Reports demonstrating the laboratory's performance in a laboratory crosscheck program for the most recent 12 months prior to submission of the survey program plan.

(g) Submission. Survey program plans submitted under this section must be approved annually under § 1090.1400(a).

§ 1090.1420

Additional requirements for E15 misfueling mitigation surveying.

(a) E15 misfueling mitigation survey requirement. (1) Any gasoline manufacturer, oxygenate blender, or oxygenate producer that produces, introduces into commerce, sells, or offers for sale E15, gasoline, BOB, DFE, or gasoline-ethanol blended fuel that is intended for use in or as E15 must comply with either survey program Option 1 (as specified in paragraph (b) of this section) or Option 2 (as specified in paragraph (c) of this section).

(2) For an oxygenate producer that produces or imports DFE, the DFE is deemed as intended for use in E15 unless the oxygenate producer demonstrates that it was not intended for such use. The oxygenate producer may demonstrate, at a minimum, that DFE is not intended for use in E15 by including language on PTDs stating that the DFE is not intended for use in E15, entering into contracts with oxygenate blenders to limit the use of their DFE to gasoline-ethanol blended fuels of no more than 10 volume percent, and limiting the concentration of their DFE to no more than 10 volume percent in their fuel additive registration under 40 CFR part 79.

(b) Survey Option 1. The gasoline manufacturer, oxygenate blender, or oxygenate producer must properly conduct a survey program in accordance with a survey program plan that has been approved by EPA in all areas that may be reasonably expected to be supplied with their gasoline, BOB, DFE, or gasoline-ethanol blended fuel. Such approval must be based on a survey program plan that meets all the following requirements:

(1) The survey program must consist of at least quarterly surveys that occur during the following time periods in every year during which the gasoline manufacturer, oxygenate blender, or oxygenate producer introduces E15 into commerce:

(i) One survey during the period of January 1 through March 31.

(ii) One survey during the period of April 1 through June 30.

(iii) One survey during the period of July 1 through September 30.

(iv) One survey during the period of October 1 through December 31.

(2) The survey program plan must meet all the requirements of this subpart, except for §§ 1090.1405(a) and (b)(2), 1090.1410(c)(2) and (3), and 1090.1415(b), (d)(1), (2), and (4), and (e). In lieu of meeting these sections, the survey program plan must specify the sampling strata, clusters, and area(s) to be surveyed, and the number of samples to be included in the survey.

(c) Survey Option 2. The gasoline manufacturer, oxygenate blender, or oxygenate producer must participate in the NFSP under § 1090.1405.

§ 1090.1450

National sampling and testing oversight program.

(a) Program participation. (1) Except for a gasoline manufacturer that has an approved in-line blending waiver under § 1090.1315 that covers all gasoline produced at their facility, a gasoline manufacturer that elects to account for oxygenate added downstream under § 1090.710 must participate in the national sampling and testing oversight program (NSTOP) in this section.

(2) Other gasoline manufacturers may elect to participate in the NSTOP for purposes of establishing an affirmative defense to a violation under § 1090.1720. A gasoline manufacturer that has an approved in-line blending waiver under § 1090.1315 does not need to participate in the NSTOP in order to establish an affirmative defense to a violation under § 1090.1720.

(3) A gasoline manufacturer that elects to participate in the NSTOP must test, or arrange to be tested, samples collected from their gasoline manufacturing facilities as specified in paragraph (c)(2) of this section and report results to the independent surveyor within 10 business days of the date that the sample was collected.

(b) Program requirements. The NSTOP must meet all the following requirements:

(1) The NSTOP must be planned and conducted by an independent surveyor that meets the independence requirements in § 1090.55 and the requirements of paragraph (c) of this section.

(2) The NSTOP must be conducted at each gasoline manufacturing facility from all participating gasoline manufacturers.

(c) Independent surveyor requirements. The independent surveyor conducting the NSTOP must meet all the following requirements:

(1) Submit a proposed NSTOP plan that meets the requirements of paragraph (d) of this section to EPA for approval each calendar year.

(2)(i) Obtain at least one sample representing summer gasoline and one sample representing winter gasoline for each participating gasoline manufacturing facility. If the fuel manufacturer only produces fuel during either the summer or winter season, obtain at least one sample during the season that the fuel manufacturer produces fuel.

(ii)(A) Observe the gasoline manufacturer collect at least one sample representing each gasoline required under paragraph (c)(2)(i) of this section for each participating gasoline manufacturing facility and evaluate whether the gasoline manufacturer collected representative sample(s) in accordance with applicable sampling procedures specified in § 1090.1335. Immediately notify EPA and the gasoline manufacturer if the applicable sampling procedures are not followed.

(B) The independent surveyor must also obtain a portion of the sample collected by the gasoline manufacturer and ship the sample as specified in paragraph (c)(2)(v) of this section.

(C) The observed sample does not need to represent a batch of certified gasoline (i.e., the independent surveyor may observe the collection of a simulated sample if the gasoline manufacturer does not have a batch of certified gasoline available).

(iii) The independent surveyor must immediately notify EPA of any refusal of a gasoline manufacturer to allow samples to be taken. A gasoline manufacturer that refuses to allow the independent surveyor to take portions of collected samples is no longer considered by EPA to be participating in the NSTOP and must not account for oxygenate added downstream under § 1090.710.

(iv) Samples must be retained by the independent surveyor as specified in § 1090.1345(a)(1).

(v) Samples collected must be shipped via ground service within 2 business days from when the samples are collected to an EPA-approved laboratory as established in an approved plan under this section. A random subset of collected samples must also be shipped to the EPA National Vehicle and Fuel Emissions Laboratory as established in an approved plan under this section.

(3) Test, or arrange to be tested, samples collected under paragraph (c)(2) of this section as follows:

(i) Winter gasoline samples must be analyzed for oxygenate content, sulfur content, benzene content, distillation parameters, aromatics, and olefins.

(ii) Summer gasoline samples must be analyzed for oxygenate content, sulfur content, benzene content, distillation parameters, aromatics, olefins, and RVP.

(iii) All samples must be tested by an EPA-approved laboratory using test methods specified in subpart N of this part.

(iv) All analyses must be completed by the EPA-approved laboratory within 10 business days after receipt of the sample.

(v) A gasoline manufacturer must analyze gasoline samples for sulfur content, benzene content, and for summer gasoline, RVP.

(4) Using procedures specified in the EPA-approved plan under this section, notify EPA and the gasoline manufacturer within 24 hours after the EPA-approved laboratory has completed analysis when any of the following occur:

(i) A test result for a gasoline sample yields a sulfur content that exceeds the fuel manufacturing facility gate sulfur per-gallon standard in § 1090.205(b).

(ii) A test result for a gasoline sample yields an RVP that exceeds the applicable RVP standard in § 1090.215.

(5) Make the test results available to EPA and the gasoline manufacturer for all analyses specified in paragraph (c)(3) of this section within 5 business days of completion of the analysis.

(6) Compare test results of all samples collected under paragraph (c)(2) of this section and all test results obtained from the gasoline manufacturer from the same samples as specified in paragraph (a)(3) of this section and notify EPA and the gasoline manufacturer if the test result for any parameter tested under paragraph (c)(3) of this section is greater than the reproducibility of the applicable method specified in subpart N of this part.

(7) Provide quarterly reports to EPA that include the information specified in § 1090.925(d).

(8) Keep records related to the NSTOP as specified in § 1090.1245(b)(3).

(9) Submit contracts to EPA as specified in § 1090.1400(b).

(10) Review the test performance index and precision ratio for each method and instrument the laboratory used to test the gasoline samples collected under this section as follows:

(i) For each test method and instrument, the surveyor must obtain the relevant records from the gasoline manufacturer to determine the site precision, either from an inter-laboratory crosscheck program or from ASTM D6299 (incorporated by reference in § 1090.95).

(ii) Using relevant information obtained from the gasoline manufacturers, the surveyor must determine the appropriate Test Performance Index (TPI) and Precision Ratio (PR) from Table 2 Guidelines for Action Based on TPI in ASTM D6792 (incorporated by reference in § 1090.95).

(iii) A gasoline manufacturer 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 NSTOP, including sample collection, transportation, storage, and analysis.

(d) NSTOP plan requirements. The NSTOP plan specified in paragraph (c)(1) of this section must include, at a minimum, all the following:

(1) Advance notice of sampling. The NSTOP plan must include procedures on how to keep the identification of the gasoline manufacturing facilities included in the NSTOP plan confidential with minimal advanced notification from any participating gasoline manufacturer prior to collecting a sample. However, this information must not be kept confidential from EPA.

(2) Gasoline manufacturing facility selection. (i) Each participating gasoline manufacturing facility must be sampled at least once during each season they produce fuel. The plan must demonstrate how these facilities will be randomly selected within the summer and winter seasons.

(ii) In addition to the summer and winter season samples collected at each participating gasoline manufacturing facility, additional oversight samples are required under paragraph (d)(3)(ii) of this section. The independent surveyor must identify how these samples will be randomly distributed among participating gasoline manufacturing facilities.

(3) Number of samples. (i) The number of gasoline manufacturing facilities to be sampled must be calculated for the total number of samples to be collected for the next calendar year as part of the NSTOP plan.

(ii) The minimum number of samples to be included in the NSTOP plan for each calendar year is calculated as follows:

n = R * F_a * F_b * Su_n

Where:

n = Minimum number of samples in a year.

R = The number of participating gasoline manufacturing facilities.

F_a = Adjustment factor for the number of extra samples required to compensate for samples that could not be included in the NSTOP (e.g., due to technical or logistical considerations), based on the number of additional samples required during the previous 2 calendar years. F_a must be greater than or equal to 1.1.

F_b = Adjustment factor for the number of samples required to ensure oversight. For purposes of this program, F_b equals 1.25.

Su_n = Number of samples required per participating facility per year. For purposes of this program, Su_n equals 2.

(4) Laboratory designation. Any laboratory that the independent surveyor intends to use to test samples collected as part of the NSTOP must be approved annually as part of the program plan approval process in § 1090.1400(a). The independent surveyor must include the following information regarding each laboratory it intends to use to test samples:

(i) The name of the laboratory.

(ii) The address of the laboratory.

(iii) The test methods for each fuel parameter measured at the laboratory.

(iv) Records demonstrating the laboratory's performance in a laboratory crosscheck program for the most recent 12 months prior to submission of the plan.

(5) Sampling procedure. The plan must include a detailed description of the sampling procedures used to collect samples at participating gasoline manufacturing facilities.

(6) Notification of test results. The NSTOP plan must include a description of how the independent surveyor will notify EPA and gasoline manufacturers of test results under paragraph (c)(4) of this section.

(7) Submission. NSTOP plans submitted under this section must be approved annually under § 1090.1400(a).

Subpart P—Retailer and Wholesale Purchaser-Consumer Provisions

§ 1090.1500

Overview.

(a) A retailer or WPC must comply with the labeling requirements in §§ 1090.1510 and 1090.1515, as applicable, and the refueling hardware requirements in §§ 1090.1550 through 1090.1565, as applicable.

(b) An alternative label design to those specified in this subpart may be used if the design is approved by EPA prior to use and meets all the following requirements:

(1) The alternative label must be similar in substance and appearance to the EPA-required label.

(2) The alternative label must contain the same informational elements as the EPA-required label.

(3) The alternative label must be submitted as specified in § 1090.10.

Labeling

§ 1090.1510

E15 labeling provisions.

Any retailer or WPC dispensing E15 must apply a label to the fuel dispenser as follows:

(a) Position the label to clearly identify which control the consumer will use to select E15. If the dispenser is set up to dispense E15 without the consumer taking action to select the fuel, position the label on a vertical surface in a prominent place, approximately at eye level.

(b) Figure 1 of this paragraph shows the required content and formatting. Use black letters on an orange background for the lower portion and the diagonal “Attention” field and use orange letters on a black background for the rest of the upper portion. Font size is shown in Figure 1. Set vertical position and line spacing as appropriate for each field. Dimensions are nominal values.

§ 1090.1515

Diesel sulfur labeling provisions.

A retailer or WPC dispensing heating oil, 500 ppm LM diesel fuel, or ECA marine fuel must apply labels to fuel dispensers as follows:

(a) Labels must be in a prominent location where the consumer will select or dispense either the corresponding fuel or heating oil. The label content must be in block letters of no less than 24-point bold type, printed in a color contrasting with the background.

(b) Labels must include the following statements, or equivalent alternative statements approved by EPA:

(1) For dispensing heating oil along with any kind of diesel fuel for any kind of engine, vehicle, or equipment, apply the following label:

Heating Oil

Warning

Federal law prohibits use in highway vehicles or engines, or in nonroad, locomotive, or marine diesel engines.

Its use may damage these diesel engines.

(2) For dispensing 500 ppm LM diesel fuel, apply the following label:

Locomotive and Marine Diesel Fuel (500 ppm Sulfur Maximum)

Warning

Federal law prohibits use in nonroad engines or in highway vehicles or engines.

(3) For dispensing ECA marine fuel, apply the following label:

ECA Marine Fuel (1,000 ppm Sulfur Maximum)

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

Warning

Federal law prohibits use in any engine that is not installed in a C3 marine vessel; use of fuel oil with a sulfur content greater than 1,000 ppm in an ECA is prohibited except as allowed by 40 CFR part 1043.

Note: If a pump dispensing 500 ppm LM diesel fuel is labeled with the “LOW SULFUR LOCOMOTIVE AND MARINE DIESEL FUEL (500 ppm Sulfur Maximum)” label, the retailer or WPC does not need to replace this label.

Refueling Hardware

§ 1090.1550

Requirements for gasoline dispensing nozzles used with motor vehicles.

(a) The following refueling hardware specifications apply for any nozzle installation used for dispensing gasoline into motor vehicles:

(1) The outside diameter of the terminal end must not be greater than 21.3 mm.

(2) The terminal end must have a straight section of at least 63 mm.

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

(b) For nozzles that dispense gasoline into motor vehicles, the dispensing flow rate must not exceed a maximum value of 10 gallons per minute. The flow rate may be controlled through any means in the pump/dispenser system, as long as it does not exceed the specified maximum value. Any dispensing pump dedicated to heavy-duty vehicles or airplanes is exempt from this flow-rate requirement.

§ 1090.1555

Requirements for gasoline dispensing nozzles used primarily with marine vessels.

The refueling hardware specifications of this section apply for any nozzle installation used primarily for dispensing gasoline into marine vessels. Note that nozzles meeting these specifications also meet the specifications of § 1090.1550(a).

(a) The outside diameter of the terminal end must have a diameter of 20.93 ± 00.43 mm.

(b) The spout must include an aspirator hole for automatic shutoff positioned with a center that is 17.0 ± 01.3 mm from the terminal end of the spout.

(c) The terminal end must have a straight section of at least 63.4 mm with no holes or grooves other than the aspirator hole.

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

§ 1090.1560

Requirements related to dispensing natural gas.

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

(b) Determine the amount of natural gas vented using calculations based on the geometric shape of the nozzle and hose.

§ 1090.1565

Requirements related to dispensing liquefied petroleum gas.

(a) Except for pumps dedicated to heavy-duty vehicles, any pump installation used for dispensing liquefied petroleum gas into motor vehicles must have a nozzle that has no greater than 2.0 cm³ dead space from which liquefied petroleum gas will be released when the nozzle disconnects from the vehicle.

(b) Determine the volume of the nozzle cavity using calculations based on the geometric shape of the nozzle, with an assumed flat surface where the nozzle face seals against the vehicle.

Subpart Q—Importer and Exporter Provisions

§ 1090.1600

General provisions for importers.

(a) This subpart contains provisions that apply to any person who imports fuel, fuel additive, or regulated blendstock.

(b)(1) Except as specified in paragraph (b)(2) of this section, all applicable gasoline and diesel standards in subparts C and D of this part apply to imported gasoline and diesel.

(2) A gasoline importer that imports gasoline at multiple import facilities must comply with the gasoline average standards in §§ 1090.205(a) and 1090.210(a) as specified in § 1090.705(b), unless the importer complies with the provisions of § 1090.1610 to meet the alternative per-gallon standards for rail and truck imports specified in §§ 1090.205(d) and 1090.210(c).

(c) An importer must separately comply with any applicable certification or other requirements for U.S. Customs.

(d) Alternative testing requirements for an importer that imports gasoline or diesel fuel by rail or truck are specified in § 1090.1610.

§ 1090.1605

Importation by marine vessel.

An importer that imports fuel, fuel additive, or regulated blendstock using a marine vessel must comply with the requirements of this section.

(a) The importer must certify each fuel, fuel additive, or regulated blendstock imported at each port, unless the fuel is certified at the first port of entry in the United States and then transported by the same vessel to subsequent ports without picking up additional fuel.

(b) Except as specified in paragraph (d) of this section, the importer must certify each fuel, fuel additive, or regulated blendstock while it is on-board the vessel used to transport it to the United States. Certification sampling must be performed after the vessel's arrival at the port where the fuel, fuel additive, or regulated blendstock will be offloaded.

(1) The importer must sample each compartment of the vessel and use one of the following methods to meet testing requirements:

(i) Treat each compartment as a separate batch.

(ii) Combine samples from separate compartments into a single, vessel volumetric composite sample using the procedures in Section 9.2.4 of ASTM D4057 (incorporated by reference in § 1090.95). Test results from the composite sample are valid only after samples are collected from each affected compartment and homogeneity is demonstrated for all samples as specified in § 1090.1337.

(2) The importer must ensure that all applicable per-gallon standards are met before offloading the fuel, fuel additive, or regulated blendstock.

(3) The importer must not rely on testing conducted by a foreign supplier.

(c) Once the fuel, fuel additive, or regulated blendstock on a vessel has been certified under paragraph (b) of this section, it may be transferred to shore tanks using smaller vessels or barges (lightered) as a certified fuel, fuel additive, or regulated blendstock. These lightering transfers may be to terminals located in any harbor and are not restricted to terminals located in the harbor where the vessel is anchored. For example, certified gasoline could be transferred from an import vessel anchored in New York harbor to a lightering vessel and transported to Albany, New York or Providence, Rhode Island without separately certifying the gasoline upon arrival in Albany or Providence. In this lightering scenario, transfers of certified gasoline to a lightering vessel must be accompanied by PTDs that meet the requirements of subpart L of this part.

(d) As an alternative to paragraphs (b) and (c) of this section, the importer may offload fuel, fuel additive, or regulated blendstock into shore tanks that contain the same fuel, fuel additive, or regulated blendstock if the importer meets the following requirements:

(1) For gasoline, the importer must offload gasoline into one or more empty shore tanks or tanks containing PCG that the importer owns.

(i) If the importer offloads gasoline into one or more empty shore tanks, they must sample and test the sulfur content and benzene content, and for summer gasoline, RVP, of each shore tank into which the gasoline was offloaded.

(ii) If the importer offloads gasoline into one or more shore tanks containing PCG, they must sample the PCG already in the shore tank prior to offloading gasoline from the marine vessel, test the sulfur content and benzene content, and report this PCG as a negative batch as specified in § 1090.905(c)(3)(i). After offloading the gasoline into the shore tanks, the importer must sample and test the sulfur content, benzene content, and for summer gasoline, RVP, of each shore tank into which the gasoline was offloaded and report the volume, sulfur content, and benzene content as a positive batch.

(iii) Include the PCG in the shore tank before offloading and the volume and properties after offloading in compliance calculations as specified in § 1090.700(d)(4)(i).

(iv) The sample retention requirements in § 1090.1345 apply to the samples taken prior to offloading and those taken after offloading.

(2) For all other fuel, fuel additive, or regulated blendstock, the importer must sample and test the fuel, fuel additive, or regulated blendstock in each shore tank into which it was offloaded. The importer must ensure that all applicable per-gallon standards are met before the fuel, fuel additive, or regulated blendstock is shipped from the shore tank.

§ 1090.1610

Importation by rail or truck.

(a) An importer that imports fuel, fuel additive, or regulated blendstock by rail or truck must meet the sampling and testing requirements of subpart N of this part by sampling and testing each compartment of the truck or railcar unless they do one of the following:

(1) Use supplier results. The importer may rely on test results from the supplier for fuel, fuel additive, or regulated blendstock imported by rail or truck if the importer meets all the following requirements:

(i) The importer obtains documentation of test results from the supplier for each batch of fuel, fuel additive, or regulated blendstock in accordance with the following requirements:

(A) The testing includes measurements for all the fuel parameters specified in § 1090.1310 using the measurement procedures specified in § 1090.1350.

(B) Testing for a given batch occurs after the most recent delivery into the supplier's storage tank and before transferring the fuel, fuel additive, or regulated blendstock to the railcar or truck.

(ii) The importer conducts testing to verify test results from each supplier as follows:

(A) Collect a sample at least once every 30 days or every 50 rail or truckloads from a given supplier, whichever is more frequent. Test the sample as specified in paragraphs (a)(1)(i)(A) and (B) of this section.

(B) Treat importation of each fuel, fuel additive, or regulated blendstock separately, but treat railcars and truckloads together if the fuel, fuel additive, or regulated blendstock is imported from a given supplier by rail and truck.

(2) Certify in a storage tank. The importer may transfer the fuel, fuel additive, or regulated blendstock imported by rail or truck into storage tanks that also contain the same product if the importer meets the following requirements:

(i) For gasoline, the importer transfers gasoline into one or more empty tanks or tanks containing PCG that the importer owns.

(A) If the importer transfers gasoline into one or more empty tanks, they must sample and test the sulfur content, benzene content, and for summer gasoline, RVP, of each tank into which the gasoline was transferred.

(B) If the importer transfers gasoline into one or more tanks containing PCG, they must sample the PCG already in the tank prior to transferring gasoline from the truck or train, test the sulfur content and benzene content, and report this PCG as a negative batch as specified in § 1090.905(c)(3)(i). After transferring the gasoline into the tanks, the importer must sample and test the sulfur content, benzene content, and for summer gasoline, RVP, of each tank into which the gasoline was transferred and report the volume, sulfur content, and benzene content as a positive batch.

(C) Include the PCG in the tank before transferring and the volume and properties after transferring in compliance calculations as specified in § 1090.700(d)(4)(i).

(D) The sample retention requirements in § 1090.1345 apply to the samples taken prior to transferring and those taken after transferring.

(ii) For all other fuel, fuel additive, or regulated blendstock, the importer must sample and test the fuel, fuel additive, or regulated blendstock in each tank into which it was transferred. The importer must ensure that all applicable per-gallon standards are met before the fuel, fuel additive, or regulated blendstock is shipped from the tank.

(b) If an importer that elects to comply with paragraph (a)(1) or (2) of this section fails to meet the applicable requirements, they must meet the sampling and testing requirements of subpart N of this part for each compartment of the truck or railcar until EPA determines that the importer has adequately addressed the cause of the failure.

§ 1090.1615

Gasoline treated as a blendstock.

(a) An importer may exclude GTAB from their compliance calculations if they meet all the following requirements:

(1) The importer reports the GTAB to EPA under § 1090.905(c)(7).

(2) The GTAB is treated as blendstock at a related gasoline manufacturing facility that produces gasoline using the GTAB.

(3) The related gasoline manufacturing facility must report the gasoline produced using the GTAB and must include the gasoline produced using the GTAB in their compliance calculations.

(b) After importation, the title of the GTAB must not be transferred to another party until the GTAB has been either certified as gasoline under subpart K of this part or used to produce gasoline that meets all applicable standards and requirements under this part.

(c) The facility at which the GTAB is used to produce gasoline must be physically located at either the same terminal at which the GTAB first arrives in the United States, the import facility, or at a facility to which the GTAB is directly transported from the import facility.

(d)(1) The importer must treat the GTAB as if it were imported gasoline and complete all requirements for a gasoline manufacturer under § 1090.105(a) (except for the sampling, testing, and sample retention requirements in § 1090.105(a)(6)) for the GTAB at the time it is imported.

(2) Any GTAB that ultimately is not used to produce gasoline (e.g., a tank bottom of GTAB) must be treated as newly imported gasoline and must meet all applicable requirements for imported gasoline.

§ 1090.1650

General provisions for exporters.

Except as specified in this section and in subpart G of this part, fuel produced, imported, distributed, or offered for sale in the United States is subject to the standards and requirements of this part.

(a) Fuel designated for export by a fuel manufacturer is not subject to the standards in this part, provided all the requirements in § 1090.645 are met.

(b) Fuel not designated for export may be exported without restriction. However, the fuel remains subject to the provisions of this part while in the United States. For example, fuel designated as ULSD must meet the applicable sulfur standards under this part even if it will later be exported.

(c) Fuel that has been classified as American Goods Returned to the United States by the U.S. Customs Service under 19 CFR part 10 is not considered to be imported for purposes of this part, provided all the following requirements are met:

(1) The fuel was produced at a fuel manufacturing facility located within the United States and has not been mixed with fuel produced at a fuel manufacturing facility located outside the United States.

(2) The fuel must be included in compliance calculations by the producing fuel manufacturer.

(3) All the fuel that was exported must ultimately be classified as American Goods Returned to the United States and none may be used in a foreign country.

(4) No fuel classified as American Goods Returned to the United States may be combined with any fuel produced at a foreign fuel manufacturing facility prior to reentry into the United States.

Subpart R—Compliance and Enforcement Provisions

§ 1090.1700

Prohibited acts.

(a) No person may violate any prohibited act in this part or fail to meet a requirement that applies to that person under this part.

(b) No person may cause another person to commit an act in violation of this part.

§ 1090.1705

Evidence related to violations.

(a)(1) EPA may use results from any testing required under this part to determine whether a given fuel, fuel additive, or regulated blendstock meets any applicable standard. However, EPA may also use any other evidence or information to make this determination 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.

§ 1090.1710

Penalties.

(a) Any person liable for a violation under this part is subject to civil penalties as specified in 42 U.S.C. 7524 and 7545 for each day of such violation and the amount of economic benefit or savings resulting from the violation.

(b)(1) Any person liable for the violation of an average standard under this part is subject to a separate day of violation for each day in the compliance period.

(2) Any person liable under this part for a failure to fulfill any requirement for credit generation, transfer, use, banking, or deficit correction is subject to a separate day of violation for each day in any compliance period in which invalid credits are generated, transferred, used, or made available for use.

(c)(1) Any person liable under this part for a violation of a per-gallon standard, or for causing another party to violate a per-gallon standard, is subject to a separate day of violation for each day the non-complying fuel, fuel additive, or regulated blendstock remains any place in the distribution system.

(2) For the purposes of paragraph (c)(1) of this section, the length of time the fuel, fuel additive, or regulated blendstock that violates a per-gallon standard remained in the distribution system is deemed to be 25 days, unless a person subject to liability or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, that the non-complying fuel, fuel additive, or regulated blendstock remained in the distribution system for fewer than or more than 25 days.

(d) Any person liable for failure to meet, or causing a failure to meet, any other provision of this part is liable for a separate day of violation for each day such provision remains unfulfilled.

(e) Failure to meet separate requirements of this part count as separate violations.

(f) Violation of any misfueling prohibition under this part counts as a separate violation for each day the noncompliant fuel, fuel additive, or regulated blendstock remains in any engine, vehicle, or equipment.

(g) The presumed values of fuel parameters in paragraphs (g)(1) through (6) of this section apply for cases in which any person fails to comply with the sampling or testing requirements and must be reported, unless EPA, in its sole discretion, approves a different value. EPA may consider any relevant information to determine whether a different value is appropriate.

(1) For gasoline: 339 ppm sulfur, 1.64 volume percent benzene, and 11 psi RVP.

(2) For diesel fuel: 1,000 ppm sulfur.

(3) For ECA marine fuel: 5,000 ppm sulfur.

(4) For the PCG portion for PCG by subtraction under § 1090.1320(a)(1): 0 ppm sulfur and 0 volume percent benzene.

(5) For fuel additives: 339 ppm sulfur.

(6) For regulated blendstocks: 339 ppm sulfur and 1.64 volume percent benzene.

§ 1090.1715

Liability provisions.

(a) Any person who violates any prohibited act or requirement in this part is liable for the violation.

(b) Any person who causes someone to commit a prohibited act under this subpart is liable for violating that prohibition.

(c) Any parent corporation is liable for any violation committed by any of its wholly-owned subsidiaries.

(d) Each partner to a joint venture, or each owner of a facility owned by two or more owners, is jointly and severally liable for any violation of this subpart that occurs at the joint venture facility or facility owned by the joint owners, or any violation of this part that is committed by the joint venture operation or any of the joint owners of the facility.

(e)(1) Any person that produced, imported, sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, caused the transportation or storage of, or introduced into commerce fuel, fuel additive, or regulated blendstock that is in the storage tank containing fuel, fuel additive, or regulated blendstock that is found to be in violation of a per-gallon standard is liable for the violation.

(2) In order for a carrier to be liable under paragraph (e)(1) of this section, EPA must demonstrate by reasonably specific showing, by direct or circumstantial evidence, that the carrier caused the violation.

(f) If a fuel manufacturer's corporate, trade, or brand name is displayed at a facility where a violation occurs, the fuel manufacturer is liable for the violation. This also applies where the displayed corporate, trade, or brand name is from the fuel manufacturer's marketing subsidiary.

§ 1090.1720

Affirmative defense provisions.

(a) Any person liable for a violation under § 1090.1715(e) or (f) will not be deemed in violation if the person demonstrates all the following:

(1) The violation was not caused by the person or the person's employee or agent.

(2) If PTD requirements of this part apply, the PTDs account for the fuel, fuel additive, or regulated blendstock found to be in violation and indicate that the violating fuel, fuel additive, or regulated blendstock was in compliance with the applicable requirements while in that person's control.

(3) The person conducted a quality assurance program, as specified in paragraph (d) of this section.

(i) A carrier may rely on the quality assurance program carried out by another party, including the party that owns the fuel in question, provided that the quality assurance program is carried out properly.

(ii) A retailer or WPC is not required to conduct sampling and testing of fuel as part of their quality assurance program.

(b) For a violation found at a facility operating under the corporate, trade, or brand name of a fuel manufacturer, or a fuel manufacturer's marketing subsidiary, the fuel manufacturer must show, in addition to the defense elements required under paragraph (a) of this section, that the violation was caused by one of the following:

(1) An act in violation of law (other than the Clean Air Act or this part), or an act of sabotage or vandalism.

(2) The action of any retailer, distributor, reseller, oxygenate blender, carrier, retailer, or WPC in violation of a contractual agreement between the branded fuel manufacturer and the person designed to prevent such action, and despite periodic sampling and testing by the branded fuel manufacturer to ensure compliance with such contractual obligation.

(3) The action of any carrier or other distributor not subject to a contract with the fuel manufacturer, but engaged for transportation of fuel, fuel additive, or regulated blendstock despite specifications or inspections of procedures and equipment that are reasonably calculated to prevent such action.

(c) For any person to show under paragraph (a) of this section that a violation was not caused by that person, or to show under paragraph (b) of this section that a violation was caused by any of the specified actions, the person must demonstrate by reasonably specific showings, through direct or circumstantial evidence, that the violation was caused or must have been caused by another person and that the person asserting the defense did not contribute to that other person's causation.

(d) To demonstrate an acceptable quality assurance program under paragraph (a)(3) of this section, a person must present evidence of all the following:

(1)(i) A periodic sampling and testing program adequately designed to ensure the fuel, fuel additive, or regulated blendstock the person sold, dispensed, supplied, stored, or transported meets the applicable per-gallon standard. A person may meet this requirement by participating in the NFSP under § 1090.1405 that was in effect at the time of the violation.

(ii) In addition to the requirements of paragraph (d)(1)(i) of this section, a gasoline manufacturer must also participate in the NSTOP specified in § 1090.1450 at the time of the violation.

(2) On each occasion when a fuel, fuel additive, or regulated blendstock is found to be in noncompliance with the applicable per-gallon standard, the person does all the following:

(i) Immediately ceases selling, offering for sale, dispensing, supplying, offering for supply, storing, or transporting the non-complying fuel, fuel additive, or regulated blendstock.

(ii) Promptly remedies the violation and the factors that caused the violation (e.g., by removing the non-complying fuel, fuel additive, or regulated blendstock from the distribution system until the applicable standard is achieved and taking steps to prevent future violations of a similar nature from occurring).

(3) For any carrier that transports a fuel, fuel additive, or regulated blendstock in a tank truck, the periodic sampling and testing program required under paragraph (d)(1) of this section does not need to include periodic sampling and testing of gasoline in the tank truck. In lieu of such tank truck sampling and testing, the carrier must demonstrate evidence of an oversight program for monitoring compliance with the requirements of this part relating to the transport or storage of the fuel, fuel additive, or regulated blendstock by tank truck, such as appropriate guidance to drivers regarding compliance with the applicable per-gallon standards and PTD requirements, and the periodic review of records received in the ordinary course of business concerning gasoline quality and delivery.

(e) In addition to the defenses provided in paragraphs (a) through (d) of this section, in any case in which an oxygenate blender, distributor, reseller, carrier, retailer, or WPC would be in violation under § 1090.1715 as a result of gasoline that contains between 9 and 15 percent ethanol (by volume) but exceeds the applicable standard by more than 1.0 psi, the oxygenate blender, distributor, reseller, carrier, retailer, or WPC will not be deemed in violation if such person can demonstrate, by showing receipt of a certification from the facility from which the gasoline was received or other evidence acceptable to EPA, all the following:

(1) The gasoline portion of the blend complies with the applicable RVP standard in § 1090.215.

(2) The ethanol portion of the blend does not exceed 15 percent (by volume).

(3) No additional alcohol or other additive has been added to increase the RVP of the ethanol portion of the blend.

(4) In the case of a violation alleged against an oxygenate blender, distributor, reseller, or carrier, if the demonstration required by paragraphs (e)(1) through (3) of this section is made by a certification, it must be supported by evidence that the criteria in paragraphs (e)(1) through (3) of this section have been met, such as an oversight program conducted by or on behalf of the oxygenate blender, distributor, reseller, or carrier alleged to be in violation, which includes periodic sampling and testing of the gasoline or monitoring the volatility and ethanol content of the gasoline. Such certification will be deemed sufficient evidence of compliance provided it is not contradicted by specific evidence, such as testing results, and provided that the party has no other reasonable basis to believe that the facts stated in the certification are inaccurate. In the case of a violation alleged against a retail outlet or WPC facility, such certification will be deemed an adequate defense for the retailer or WPC, provided that the retailer or WPC is able to show certificates for all the gasoline contained in the storage tank found in violation, and, provided that the retailer or WPC has no reasonable basis to believe that the facts stated in the certifications are inaccurate.

Subpart S—Attestation Engagements

§ 1090.1800

General provisions.

(a) The following parties must arrange for attestation engagement using agreed-upon procedures as specified in this subpart:

(1) A gasoline manufacturer that produces or imports gasoline subject to the requirements of subpart C of this part.

(2) A gasoline manufacturer that performs testing as specified in subpart N of this part or that relies on testing from a third-party laboratory.

(b) An auditor performing attestation engagements must meet the following requirements:

(1) The auditor must meet one of the following professional qualifications:

(i) The auditor may be an internal auditor that is employed by the fuel manufacturer and certified by the Institute of Internal Auditors. Such an auditor must perform the attestation engagement in accordance with the International Standards for the Professional Practice of Internal Auditing (Standards) (incorporated by reference in § 1090.95).

(ii) The auditor may be a certified public accountant, or firm of such accountants, that is independent of the gasoline manufacturer. Such an auditor must comply with the AICPA Code of Professional Conduct, including its independence requirements, the AICPA Statements on Quality Control Standards (SQCS) No. 8, A Firm's System of Quality Control (both incorporated by reference in § 1090.95), and applicable rules of state boards of public accountancy. Such an auditor must also perform the attestation engagement in accordance with the AICPA Statements on Standards for Attestation Engagements (SSAE) No. 18, Attestation Standards: Clarification and Recodification, especially as noted in sections AT-C 105, 215, and 315 (incorporated by reference in § 1090.95).

(2) The auditor must meet the independence requirements in § 1090.55.

(3) The auditor must be registered with EPA under subpart I of this part.

(4) Any auditor suspended or debarred under 2 CFR part 1532 or 48 CFR part 9, subpart 9.4, is not qualified to perform attestation engagements under this subpart.

(c) An auditor must perform attestation engagements separately for each gasoline manufacturing facility for which the gasoline manufacturer submitted reports to EPA under subpart J of this part for the compliance period.

(d) The following provisions apply to each attestation engagement performed under this subpart:

(1) The auditor must prepare a report identifying the applicable procedures specified in this subpart along with the auditor's corresponding findings for each procedure. The auditor must submit the report electronically to EPA by June 1 of the year following the compliance period.

(2) The auditor must identify any instances where compared values do not agree or where specified values do not meet applicable requirements under this part.

(3) Laboratory analysis refers to the original test result for each analysis of a product's properties. The following provisions apply in special cases:

(i) For a laboratory using test methods that must be correlated to the standard test method, the laboratory analysis must include the correlation factors along with the corresponding test results.

(ii) For a gasoline manufacturer that relies on a third-party laboratory for testing, the laboratory analysis consists of the results provided by the third-party laboratory.

§ 1090.1805

Representative samples.

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

(1) Determine sample size using the following table:

Table 1 to Paragraph (a)(1)—Sample Size Determination

Population	Sample size
1-25	The smaller of the population or 19.
26-40	20.
41-65	25.
66 or more	29.

(2) Determine sample size corresponding to a confidence level of 95 percent, an expected error rate of 0 percent, and a maximum tolerable error rate of 10 percent, using conventional statistical principles and methods.

(3) Determine sample size using an alternate method that is equivalent to or better than the methods specified in paragraphs (a)(1) and (2) of this section with respect to strength of inference and freedom from bias. An auditor that determines a sample size using an alternate method must describe and justify the alternate method in the attestation report.

(b) Select specific data points for evaluation over the course of the compliance period in a way that leads to a simple random sample that properly represents the overall population for the data set.

§ 1090.1810

General procedures for gasoline manufacturers.

An auditor must perform the procedures in this section for a refiner, blending manufacturer, or transmix processer that produces gasoline.

(a) Registration and EPA reports. An auditor must review registration and EPA reports as follows:

(1) Obtain copies of the gasoline manufacturer's registration information submitted under subpart I of this part and all reports (except batch reports) submitted under subpart J of this part.

(2) For each gasoline manufacturing facility, confirm that the facility's registration is accurate based on the activities reported during the compliance period, including that the registration for the facility and any related updates were completed prior to conducting regulated activities at the facility and report any discrepancies.

(3) Confirm that the gasoline manufacturer submitted all the reports required under subpart J of this part for activities they performed during the compliance period and report any exceptions.

(4) Obtain a written statement from the gasoline manufacturer's RCO that the submitted reports are complete and accurate.

(5) Report in the attestation report the name of any commercial computer program used to track the data required under this part, if any.

(b) Inventory reconciliation analysis. An auditor must perform an inventory reconciliation analysis review as follows:

(1) Obtain an inventory reconciliation analysis from the gasoline manufacturer for each product type produced at each facility (e.g., RFG, CG, RBOB, CBOB), including the inventory at the beginning and end of the compliance period, receipts, production, shipments, transfers, and gain/loss.

(2) Foot and cross-foot the volumes.

(3) Compare the beginning and ending inventory to the manufacturer's inventory records for each product type and report any variances.

(4) Report in the attestation report the volume totals for each product type on the basis of which gasoline batches are reported.

(c) Listing of tenders. An auditor must review a listing of tenders as follows:

(1) Obtain detailed listings of gasoline tenders from the gasoline manufacturer, by product type.

(2) Foot the listings of gasoline tenders.

(3) Compare the total volume from the gasoline tenders to the total volume shipped in the inventory reconciliation analysis for each product type and report any variances.

(d) Listing of batches. An auditor must review listings of batches as follows:

(1) Obtain the batch reports submitted under subpart J of this part.

(2) Foot the batch volumes by product type.

(3) Compare the total volume from the batch reports to the total production or shipment volume from the inventory reconciliation analysis specified in paragraph (b)(4) of this section for each product type and report any variances.

(4) Report as a finding in the attestation report any gasoline batch with reported values that do not meet a per-gallon standard in subpart C of this part.

(e) Test methods. An auditor must follow the procedures specified in § 1090.1845 to determine whether the gasoline manufacturer complies with the applicable quality control requirements specified in § 1090.1375.

(f) Detailed testing of BOB tenders. An auditor must review a detailed listing of BOB tenders as follows:

(1) Select a representative sample from the listing of BOB tenders.

(2) Obtain the associated PTD for each selected sample.

(3) Using a unique identifier, confirm that the correct PTDs are obtained for the samples and compare the volume on the listing of each selected BOB tender to the associated PTD and report any exceptions.

(4) Confirm that the PTD associated with each selected BOB tender contains all the applicable language requirements under subpart L of this part and report any exceptions.

(g) Detailed testing of BOB batches. An auditor must review a detailed listing of BOB batches as follows:

(1) Select a representative sample from the BOB batch reports submitted under subpart J of this part.

(2) Obtain the volume documentation and laboratory analysis for each selected BOB batch.

(3) Compare the reported volume for each selected BOB batch to the volume documentation and report any exceptions.

(4) Compare the reported properties for each selected BOB batch to the laboratory analysis and report any exceptions.

(5) Compare the reported test methods used for each selected BOB batch to the laboratory analysis and report any exceptions.

(6) Determine each oxygenate type and amount that is required for blending with the BOB.

(7) Confirm that each oxygenate type and amount included in the BOB hand blend agrees with the manufacturer's blending instructions for each selected BOB batch and report any exceptions.

(8) Confirm that the manufacturer participates in the NFSP under § 1090.1405, if applicable.

(9) For a blending manufacturer, confirm that the laboratory analysis includes test results for oxygenate content, if applicable, and distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue). For a blending manufacturer not required to measure oxygenate content, confirm that records demonstrate that the PCG or blendstock contained no oxygenate, no oxygenate was added to the final gasoline batch, and the blending manufacturer did not account for oxygenate added downstream under § 1090.710.

(h) Detailed testing of finished gasoline tenders. An auditor must review a detailed listing of finished gasoline tenders as follows:

(1) Select a representative sample from the listing of finished gasoline tenders.

(2) Obtain the associated PTD for each selected sample.

(3) Using a unique identifier, confirm that the correct PTDs are obtained for the samples and compare the volume on the listing for each finished gasoline tender to the associated PTD and report any exceptions.

(4) Confirm that the PTD associated with each selected finished gasoline tender contains all the applicable language requirements under subpart L of this part and report any exceptions.

(i) Detailed testing of finished gasoline batches. An auditor must review a detailed listing of finished gasoline batches as follows:

(1) Select a representative sample of finished gasoline batches from the batch reports submitted under subpart J of this part.

(2) Obtain the volume documentation and laboratory analysis for each selected finished gasoline batch.

(3) Compare the reported volume for each selected finished gasoline batch to the volume documentation and report any exceptions.

(4) Compare the reported properties for each selected finished gasoline batch to the laboratory analysis and report any exceptions.

(5) Compare the reported test methods used for each selected finished gasoline batch to the laboratory analysis and report any exceptions.

(6) For a blending manufacturer, confirm that the laboratory analysis includes test results for oxygenate content, if applicable, and distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue). For a blending manufacturer not required to measure oxygenate content, confirm that records demonstrate that the PCG or blendstock contained no oxygenate, no oxygenate was added to the final gasoline batch, and the blending manufacturer did not account for oxygenate added downstream under § 1090.710.

(j) Detailed testing of blendstock batches. In the case of adding blendstock to TGP or PCG under § 1090.1320(a)(2), an auditor must review a detailed listing of blendstock batches as follows:

(1) Select a representative sample of blendstock batches from the batch reports submitted under subpart J of this part.

(2) Obtain the volume documentation and the laboratory analysis for each selected blendstock batch.

(3) Compare the reported volume for each selected blendstock batch to the volume documentation and report any exceptions.

(4) Compare the reported properties for each selected blendstock batch to the laboratory analysis and report any exceptions.

(5) Compare the reported test methods used for each selected blendstock batch to the laboratory analysis and report any exceptions.

(6) For blending a manufacturer not required to measure oxygenate content, confirm that records demonstrate that the PCG or blendstock contained no oxygenate, no oxygenate was added to the final gasoline batch, and the blending manufacturer did not account for oxygenate added downstream under § 1090.710.

§ 1090.1815

General procedures for gasoline importers.

An auditor must perform the procedures in this section for a gasoline importer.

(a) Registration and EPA reports. An auditor must review registration and EPA reports for a gasoline importer as specified in § 1090.1810(a).

(b) Listing of imports. An auditor must review a listing of imports as follows:

(1) Obtain detailed listings of gasoline imports from the importer, by product type.

(2) Foot the listings of gasoline imports from the importer.

(3) Obtain listings of gasoline imports directly from the third-party customs broker, by product type.

(4) Foot the listings of gasoline imports from the third-party customs broker.

(5) Compare the total volume from the importer's listings of gasoline imports to the listings from the third-party customs broker for each product type and report any variances.

(6) Report in the attestation report the total imported volume for each product type.

(c) Listing of batches. An auditor must review listings of batches as follows:

(1) Obtain the batch reports submitted under subpart J of this part.

(2) Foot the batch volumes by product type.

(3) Compare the total volume from the batch reports to the total volume per the listings of gasoline imports obtained under paragraph (b)(1) of this section for each product type and report any variances.

(4) Report as a finding in the attestation report any gasoline batches with parameter results that do not meet the per-gallon standards in subpart C of this part.

(d) Test methods. An auditor must follow the procedures specified in § 1090.1845 to determine whether the importer complies with the quality control requirements specified in § 1090.1375 for gasoline, gasoline additives, and gasoline regulated blendstocks.

(e) Detailed testing of BOB imports. An auditor must review a detailed listing of BOB imports as follows:

(1) Select a representative sample from the listing of BOB imports from the importer and obtain the associated U.S. Customs Entry Summary and PTD for each selected BOB import.

(2) Using a unique identifier, confirm that the correct U.S. Customs Entry Summaries are obtained for the samples and compare the location that each selected BOB import arrived in the United States and volume on the listing of BOB imports from the importer to the U.S. Customs Entry Summary and report any exceptions.

(3) Using a unique identifier, confirm that the correct PTDs are obtained for the samples. Confirm that the PTD contains all the applicable language requirements under subpart L of this part and report any exceptions.

(f) Detailed testing of BOB batches. An auditor must review a detailed listing of BOB batches as follows:

(1) Select a representative sample of BOB batches from the batch reports submitted under subpart J of this part and obtain the volume inspection report and laboratory analysis for each selected BOB batch.

(2) Compare the reported volume for each selected BOB batch to the volume inspection report and report any exceptions.

(3) Compare the reported properties for each selected BOB batch to the laboratory analysis and report any exceptions.

(4) Compare the reported test methods used for each selected BOB batch to the laboratory analysis and report any exceptions.

(5) Determine each oxygenate type and amount that is required for blending with each selected BOB batch.

(6) Confirm that each oxygenate type and amount included in the BOB hand blend agrees within an acceptable range to each selected BOB batch and report any exceptions.

(7) Confirm that the importer participates in the NFSP under § 1090.1405, if applicable.

(g) Detailed testing of finished gasoline imports. An auditor must review a detailed listing of finished gasoline imports as follows:

(1) Select a representative sample from the listing of finished gasoline imports from the importer and obtain the associated U.S. Customs Entry Summary and PTD for each selected finished gasoline import.

(2) Using a unique identifier, confirm that the correct U.S. Customs Entry Summaries are obtained for the samples and compare the location that each selected finished gasoline import arrived in the United States and volume on the listing of finished gasoline imports from the importer to the U.S. Customs Entry Summary and report any exceptions.

(3) Using a unique identifier, confirm that the correct PTDs are obtained for the samples. Confirm that the PTD contain all the applicable language requirements under subpart L of this part and report any exceptions.

(h) Detailed testing of finished gasoline batches. An auditor must review a detailed listing of finished gasoline batches as follows:

(1) Select a representative sample of finished gasoline batches from the batch reports submitted under subpart J of this part and obtain the volume inspection report and laboratory analysis for each selected finished gasoline batch.

(2) Compare the reported volume for each selected finished gasoline batch to the volume inspection report and report any exceptions.

(3) Compare the reported properties for each selected finished gasoline batch to the laboratory analysis and report any exceptions.

(4) Compare the reported test methods used for each selected finished gasoline batch to the laboratory analysis and report any exceptions.

(i) Additional procedures for certain gasoline imported by rail or truck. An auditor must perform the following additional procedures for an importer that imports gasoline into the United States by rail or truck under § 1090.1610:

(1) Select a representative sample from the listing of batches obtained under paragraph (c)(1) of this section and perform the following for each selected batch:

(i) Identify the point of sampling and testing associated with each selected batch in the tank activity records from the supplier.

(ii) Confirm that the sampling and testing occurred after the most recent delivery into the supplier's storage tank and before transferring product to the railcar or truck.

(2)(i) Obtain a detailed listing of the importer's quality assurance program sampling and testing results.

(ii) Determine whether the frequency of the sampling and testing meets the requirements in § 1090.1610(a)(2).

(iii) Select a representative sample from the importer's sampling and testing records under the quality assurance program and perform the following for each selected batch:

(A) Obtain the corresponding laboratory analysis.

(B) Determine whether the importer analyzed the test sample, and whether they performed the analysis using the methods specified in subpart N of this part.

(C) Review the terminal test results corresponding to the time of collecting the quality assurance test samples. Compare the terminal test results with the test results from the quality assurance program, noting any parameters with differences that are greater than the reproducibility of the applicable method specified in subpart N of this part.

§ 1090.1820

Additional procedures for gasoline treated as blendstock.

In addition to any applicable procedures required under §§ 1090.1810 and 1090.1815, an auditor must perform the procedures in this section for a gasoline manufacturer that imports GTAB under § 1090.1615.

(a) Listing of GTAB imports. An auditor must review a listing of GTAB imports as follows:

(1) Obtain a detailed listing of GTAB imports from the GTAB importer.

(2) Foot the listing of GTAB imports from the GTAB importer.

(3) Obtain a listing of GTAB imports directly from the third-party customs broker.

(4) Foot the listing of GTAB imports from the third-party customs broker and report any variances.

(5) Compare the total volume from the GTAB importer's listing of GTAB imports to the listing from the third-party customs broker.

(6) Report in the attestation report the total imported volume of GTAB and the corresponding facilities at which the GTAB was blended.

(b) Listing of GTAB batches. An auditor must review a listing of GTAB batches as follows:

(1) Obtain the GTAB batch reports submitted under subpart J of this part.

(2) Foot the batch volumes.

(3) Compare the total volume from the GTAB batch reports to the total volume from the listing of GTAB imports in paragraph (a)(6) of this section and report any variances.

(c) Detailed testing of GTAB imports. An auditor must review a detailed listing of GTAB imports as follows:

(1) Select a representative sample from the listing of GTAB imports obtained under paragraph (a)(1) of this section.

(2) For each selected GTAB batch, obtain the U.S. Customs Entry Summaries.

(3) Using a unique identifier, confirm that the correct U.S. Customs Entry Summaries are obtained for the samples. Compare the volumes and locations that each selected GTAB batch arrived in the United States to the U.S. Customs Entry Summary and report any exceptions.

(d) Detailed testing of GTAB batches. An auditor must review a detailed listing of GTAB batches as follows:

(1) Select a representative sample from the GTAB batch reports obtained under paragraph (b)(1) of this section.

(2) For each selected GTAB batch sample, obtain the volume inspection report.

(3) Compare the reported volume for each selected GTAB batch to the volume inspection report and report any exceptions.

(e) GTAB tracing. An auditor must trace and review the movement of GTAB from importation to gasoline production as follows:

(1) Compare the volume total on each GTAB batch report obtained under paragraph (b)(1) of this section to the GTAB volume total in the gasoline manufacturer's inventory reconciliation analysis under § 1090.1810(b).

(2) For each selected GTAB batch under paragraph (d)(1) of this section:

(i) Obtain tank activity records that describe the movement of each selected GTAB batch from importation to gasoline production.

(ii) Identify each selected GTAB batch in the tank activity records and trace each selected GTAB batch to subsequent reported batches of BOB or finished gasoline.

(iii) Match the location of the facility where gasoline was produced from each selected GTAB batch to the location where each selected GTAB batch arrived in the United States, or to the facility directly receiving the GTAB batch from the import facility.

(iv) Determine the status of the tank(s) before receiving each selected GTAB batch (e.g., empty tank, tank containing blendstock, tank containing GTAB, tank containing PCG).

(v) If the tank(s) contained PCG before receiving the selected GTAB batch, take the following additional steps:

(A) Obtain and review a copy of the documented tank mixing procedures.

(B) Determine the volume and properties of the tank bottom that was PCG before adding GTAB.

(C) Confirm that the gasoline manufacturer determined the volume and properties of the BOB or finished gasoline produced using GTAB by excluding the volume and properties of any PCG, and that the gasoline manufacturer separately reported the PCG volume and properties under subpart J of this part and report any discrepancies.

§ 1090.1825

Additional procedures for PCG used to produce gasoline.

In addition to any applicable procedures required under § 1090.1810, an auditor must perform the procedures in this section for a gasoline manufacturer that produces gasoline from PCG under § 1090.1320.

(a) Listing of PCG batches. An auditor must review a listing of PCG batches as follows:

(1) Obtain the PCG batch reports submitted under subpart J of this part.

(2) Foot the batch volumes.

(3) Compare the volume total for each PCG batch report to the receipt volume total in the inventory reconciliation analysis specified in § 1090.1810(b) and report any variances.

(b) Detailed testing of PCG batches. An auditor must review a detailed listing of PCG batches as follows:

(1) Select a representative sample from the PCG batch reports obtained under paragraph (a)(1) of this section.

(2) Obtain the volume documentation, laboratory analysis, associated PTDs, and tank activity records for each selected PCG batch.

(3) Identify each selected PCG batch in the tank activity records and trace each selected PCG batch to subsequent reported batches of BOB or finished gasoline and report any exceptions.

(4) For each selected PCG batch, report as a finding in the attestation report any instances where the reported PCG batch volume was adjusted from the original receipt volume, such as for exported PCG.

(5) Compare the volume for each selected PCG batch to the volume documentation and report any exceptions.

(6) Compare the product type and grade for each selected PCG batch to the associated PTDs and report any exceptions.

(7) Compare the reported properties for each selected PCG batch to the laboratory analysis and report any exceptions.

(8) Compare the reported test methods used for each selected PCG batch to the laboratory analysis and report any exceptions.

§ 1090.1830

Alternative procedures for certified butane blenders.

An auditor must use the procedures in this section instead of or in addition to the applicable procedures in § 1090.1810 for a certified butane blender that blends certified butane into PCG under § 1090.1320(b).

(a) Registration and EPA reports. An auditor must review registration and EPA reports as follows:

(1) Obtain copies of the certified butane blender's registration information submitted under subpart I of this part and all reports submitted under subpart J of this part, including the batch reports for the butane received and blended.

(2) For each butane blending facility, confirm that the facility's registration is accurate based on activities reported during the compliance period, including that the registration for the facility and any related updates were completed prior to conducting regulated activities at the facility and report any discrepancies.

(3) Confirm that the certified butane blender submitted the reports required under subpart J of this part for activities they performed during the compliance period and report any exceptions.

(4) Obtain a written statement from the certified butane blender's RCO that the submitted reports are complete and accurate.

(5) Report in the attestation report the name of any commercial computer program used to track the data required under this part, if any.

(b) Inventory reconciliation analysis. An auditor must perform an inventory reconciliation analysis review as follows:

(1) Obtain an inventory reconciliation analysis from the certified butane blender for each butane blending facility related to all certified butane movements, including the inventory at the beginning and end of the compliance period, receipts, blending/production volumes, shipments, transfers, and gain/loss.

(2) Foot and cross-foot the volumes.

(3) Compare the beginning and ending inventory to the certified butane blender's inventory records and report any variances.

(4) Compare the total volume of certified butane received from the batch reports obtained under paragraph (a)(1) of this section to the inventory reconciliation analysis and report any variances.

(5) Compare the total volume of certified butane blended from the batch reports to the inventory reconciliation analysis and report any variances.

(6) Report in the attestation report the total volume of certified butane received and blended.

(c) Listing of certified butane receipts. An auditor must review a listing of certified butane receipts as follows:

(1) Obtain a detailed listing of all certified butane batches received at the butane blending facility from the certified butane blender.

(2) Foot the listing of certified butane batches received.

(3) Compare the total volume from batch reports for certified butane received at the butane blending facility to the certified butane blender's listing of certified butane batches received and report any variances.

(d) Detailed testing of certified butane batches. An auditor must review a detailed listing of certified butane batches as follows:

(1) Select a representative sample from the certified butane batch reports submitted under subpart J of this part.

(2) Obtain the volume documentation and laboratory analysis for each selected certified butane batch.

(3) Compare the reported volume for each selected certified butane batch to the volume documentation and report any exceptions.

(4) Compare the reported properties for each selected certified butane batch to the laboratory analysis and report any exceptions.

(5) Compare the reported test methods used for each selected certified butane batch to the laboratory analysis and report any exceptions.

(6) Confirm that the butane meets the standards for certified butane under subpart C of this part and report any exceptions.

(e) Quality control review. An auditor must obtain the certified butane blender's sampling and testing results for certified butane received and determine if the frequency of the sampling and testing meets the requirements in § 1090.1320(b)(4) and report any discrepancies.

§ 1090.1835

Alternative procedures for certified pentane blenders.

(a) An auditor must use the procedures in this section instead of or in addition to the applicable procedures in § 1090.1810 for a certified pentane blender that blends certified pentane into PCG under § 1090.1320(b).

(b) An auditor must apply the procedures in § 1090.1830 by substituting “pentane” for “butane” in all cases.

§ 1090.1840

Additional procedures related to compliance with gasoline average standards.

An auditor must perform the procedures in this section for a gasoline manufacturer that complies with the standards in subpart C of this part using the procedures specified in subpart H of this part.

(a) Annual compliance demonstration review. An auditor must review annual compliance demonstrations as follows:

(1) Obtain the annual compliance reports for sulfur and benzene and associated batch reports submitted under subpart J of this part.

(2)(i) For a gasoline refiner or blending manufacturer, compare the gasoline production volume from the annual compliance report to the inventory reconciliation analysis under § 1090.1810(b) and report any variances.

(ii) For a gasoline importer, compare the gasoline import volume from the annual compliance report to the corresponding volume from the listing of imports under § 1090.1815(b) and report any variances.

(3) For each facility, recalculate the following and report in the attestation report the recalculated values:

(i) Compliance sulfur value, per § 1090.700(a)(1), and compliance benzene value, per § 1090.700(b)(1)(i).

(ii) Unadjusted average sulfur concentration, per § 1090.745(b), and average benzene concentration, per § 1090.700(b)(3).

(iii) Number of credits generated during the compliance period, or number of banked or traded credits needed to meet standards for the compliance period.

(iv) Number of credits from the preceding compliance period that are expired or otherwise no longer available for the compliance period being reviewed.

(v) Net average sulfur concentration, per § 1090.745(c), and net average benzene concentration, per § 1090.745(d).

(4) Compare the recalculated values in paragraph (a)(3) of this section to the reported values in the annual compliance reports and report any exceptions.

(5) Report in the attestation report whether the gasoline manufacturer had a deficit for both the compliance period being reviewed and the preceding compliance period.

(b) Credit transaction review. An auditor must review credit transactions as follows:

(1) Obtain the gasoline manufacturer's credit transaction reports submitted under subpart J of this part and contracts or other information that documents all credit transfers. Also obtain records that support intracompany transfers.

(2) For each reported transaction, compare the supporting documentation with the credit transaction reports for the following elements and report any exceptions:

(i) Compliance period of creation.

(ii) Credit type (i.e., sulfur or benzene) and number of times traded.

(iii) Quantity.

(iv) The name of the other company participating in the credit transfer.

(v) Transaction type.

(c) Facility-level credit reconciliation. An auditor must perform a facility-level credit reconciliation separately for each gasoline manufacturing facility as follows:

(1) Obtain the credits remaining or the credit deficit from the previous compliance period from the gasoline manufacturer's credit transaction information for the previous compliance period.

(2) Compute and report as a finding the net credits remaining at the end of the compliance period.

(3) Compare the ending balance of credits or credit deficit recalculated in paragraph (c)(2) of this section to the corresponding value from the annual compliance report and report any variances.

(4) For an importer, the procedures of this paragraph (c) apply at the company level.

(d) Company-level credit reconciliation. An auditor must perform a company-level credit reconciliation as follows:

(1) Obtain a credit reconciliation listing company-wide credits aggregated by facility for the compliance period.

(2) Foot and cross-foot the credit quantities.

(3) Compare and report the beginning balance of credits, the ending balance of credits, the associated credit activity at the company level in accordance with the credit reconciliation listing, and the corresponding credit balances and activity submitted under subpart J of this part.

(e) Procedures for gasoline manufacturers that recertify BOB. An auditor must perform the following procedures for a gasoline manufacturer that recertifies a BOB under § 1090.740 and incurs a deficit:

(1) Perform the procedures specified in § 1090.1810(a) to review registration and EPA reports.

(2) Obtain the batch reports for recertified BOB submitted under subpart J of this part.

(3) Select a representative sample of recertified BOB batches from the batch reports.

(4) For each sample, obtain supporting documentation.

(5) Confirm the accuracy of the information reported and report any exceptions.

(6) Recalculate the deficits in accordance with the provisions of § 1090.740 and report any discrepancies.

(7) Confirm that the deficits are included in the annual compliance demonstration calculations and report any exceptions.

§ 1090.1845

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

(a) General provisions. (1) An auditor must conduct the procedures specified in this section for a gasoline manufacturer.

(2) An auditor performing the procedures specified in this section must meet the laboratory experience requirements specified in § 1090.55(b)(2).

(3) In cases where the auditor employs, contracts, or subcontracts an external specialist, all the requirements in § 1090.55 apply to the external specialist. The auditor is responsible for overseeing the work of the specialist, consistent with applicable professional standards specified in § 1090.1800.

(4) In the case of quality control testing at a third-party laboratory, the auditor may perform a single attestation engagement on the third-party laboratory for multiple gasoline manufacturers if the auditor directly reviewed the information from the third-party laboratory. A third-party laboratory may also arrange for an auditor to perform a single attestation engagement on the third-party laboratory and make that available to gasoline manufacturers that have testing performed by the third-party laboratory.

(b) Non-referee method qualification review. For each test method used to measure a parameter for gasoline as specified in a report submitted under subpart J of this part that is not one of the referee procedures listed in § 1090.1360(d), the auditor must review the following:

(1) Obtain supporting documentation showing that the laboratory has qualified the test method by meeting the precision and accuracy criteria specified under § 1090.1365.

(2) Report in the attestation report a list of the alternative methods used.

(3) Confirm that the gasoline manufacturer supplied the supporting documentation for each test method specified in paragraph (b)(1) of this section and report any exceptions.

(4) If an auditor has previously reviewed supporting documentation under this paragraph (b) for an alternative method at the facility, the auditor does not have to review the supporting document again.

(c) Reference installation review. For each reference installation used by the gasoline manufacturer during the compliance period, the auditor must review the following:

(1) Obtain supporting documentation demonstrating that the reference installation followed the qualification procedures specified in § 1090.1370(c)(1) and (2) and the quality control procedures specified in § 1090.1370(c)(3).

(2) Confirm that the facility completed the qualification procedures and report any exceptions.

(d) Instrument control review. For each test instrument used to test gasoline parameters for batches selected as part of a representative sample under § 1090.1810, the auditor must review whether test instruments were in control as follows:

(1) Obtain a listing from the laboratory of the instruments and period when the instruments were used to measure gasoline parameters during the compliance period for batches selected as part of the representative sample under § 1090.1810.

(2) Obtain statistical quality assurance data and control charts demonstrating ongoing quality testing to meet the accuracy and precision requirements specified in § 1090.1375 or 40 CFR 80.47, as applicable.

(3) Confirm that the facility performed statistical quality assurance monitoring of its instruments under § 1090.1375 and report any exceptions.

(4) Report as a finding in the attestation report the instrument lists obtained under paragraph (d)(1) of this section and the compliance period when the instrument control review was completed.

§ 1090.1850

Procedures related to in-line blending waivers.

In addition to any other procedure required under this subpart, an auditor must perform the procedures specified in this section for a gasoline manufacturer that relies on an in-line blending waiver under § 1090.1315.

(a) Obtain a copy of the gasoline manufacturer's in-line blending waiver submission and EPA's approval letter.

(b) Confirm that the sampling procedures and composite calculations conform to specifications as specified in § 1090.1315(a)(2).

(c) Review the gasoline manufacturer's procedure for defining a batch for compliance purposes. Review available test data demonstrating that the test results from in-line blending correctly characterize the fuel parameters for the designated batch.

(d) Confirm that the gasoline manufacturer corrected their operations because of previous audits, if applicable.

(e) Confirm that the equipment and procedures are not materially changed from the gasoline manufacturer's in-line blending waiver. In cases of material change in equipment or procedure, confirm that the gasoline manufacturer updated their in-line blending waiver and report any exceptions.

(f) Perform any additional procedures unique to the blending operation, as specified in the in-line blending waiver, and report any findings, variances, or exceptions, as applicable.

(g) Confirm that the gasoline manufacturer has complied with all provisions related to their in-line blending waiver and report any exceptions.

Footnotes

1.  Under the current regulations, EPA's fuels regulations are in 40 CFR parts 79 and 80. Part 79 contains provisions related to the registration of fuel and fuel additives under CAA sections 211(a), (b), (e), and (f), while part 80 contains provisions for fuel quality (e.g., fuel controls and prohibitions established under CAA section 211(c) and the RFG program requirements promulgated under CAA section 211(k)) and the Renewable Fuel Standard (RFS) program. This action is limited to the provisions related to EPA's fuel quality standards in part 80, as the registration requirements in part 79 and the RFS program in part 80, which are established under CAA section 211(a), (b), (e) and (o), are significantly different in scope, and would involve different considerations to update those regulatory requirements.

2.  We also noted in the NPRM that we would treat these comments outside the scope of this action. See 85 FR 29036 (May 14, 2020). Additionally, we are not reopening any aspects of the RFS program or any RFS regulations, other than to make minor edits that are intended to ensure consistency with the new language used in part 1090.

3.  CAA section 211(h)(1) requires EPA to establish volatility requirements—that is, a restriction on Reid Vapor Pressure (RVP)—during the high ozone season. To implement these requirements, under part 80, EPA defined “high ozone season” as the period from June 1 to September 15. Also under part 80, the regulations specify that all parties (except for retailers) must make and distribute gasoline meeting the RVP standards from May 1 through September 15 and calls this period the “regulatory control period.” In general practice by industry and for purposes of this preamble, the high ozone season and regulatory control period are referred to as the “summer” or “summer season” and gasoline produced to be used during the regulatory control period and high ozone season is called “summer gasoline.” EPA's regulations do not impose any volatility requirements on any type of blend of gasoline outside of the summer season. In part 1090, we are maintaining the terms regulatory control period and high ozone season as they are implemented under part 80.

4.  The Complex Model is a predictive model that estimates emissions performance of gasoline based on measured fuel parameters against a statutory baseline in model year 1990 vehicles (see 40 CFR 80.45 and CAA section 211(k)(10)). Under part 80, refiners and importers are required to use the Complex Model to demonstrate compliance with RFG standards. The Complex Model is available at: https://www.epa.gov/​fuels-registration-reporting-and-compliance-help/​complex-model-used-analyze-rfg-and-anti-dumping.

5.  See 72 FR 8428 (February 26, 2007).

6.  See https://www.epa.gov/​diesel-fuel-standards/​fuels-regulatory-streamlining. The four discussion drafts are available in the docket for this action.

7.  See 83 FR 20812 (May 8, 2018).

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

9.  40 CFR 80.2(h).

10.  40 CFR 80.2(i).

11.  Under this approach, transmix processors are also considered fuel manufacturers.

12.  See 40 CFR 80.2(y).

13.  See 40 CFR 80.2(ttt).

14.  85 FR 29034, 29040 (May 14, 2020).

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

16.  CAA section 211(k)(1).

17.  CAA section 211(k)(4)(A).

18.  Currently, refiners use the Complex Model to demonstrate compliance with the RFG provisions. Under part 1090, refiners are required to instead demonstrate compliance by testing the RVP of the fuel, along with benzene and sulfur as currently required under part 80.

19.  The VOC performance standard specifies that reductions are as compared to baseline vehicles using baseline gasoline. CAA section 211(k)(10) defines “baseline vehicles” as representative of 1990 vehicles and “baseline gasoline.” Our translation of the VOC performance standard uses the statutorily specified points of comparison (i.e., 1990 vehicle technology using baseline gasoline as specified in the CAA).

20.  As discussed in Section IX, manufacturers that certify batches of oxygenated gasoline would need to test for oxygenates, while manufacturers of BOBs would need to follow hand blending procedures for batch certification.

21.  The process and rationale for the RFG maximum RVP per-gallon standard of 7.4 psi discussed in “History, Methods, and Underlying Data Support for RFG Standard Translation to RVP,” available in the docket for this action.

22.  As discussed in Sections VIII and IX, blending manufacturers will need to sample, test, and report for additional fuel parameters.

23.  Typically, under part 1090, gasoline manufacturers must sample for sulfur, benzene, and, for summer gasoline, RVP for batch certification. In cases where gasoline manufacturers are certifying a batch of gasoline that has already had oxygenate added (not including a hand blend), the manufacturer must also test for oxygenates. In addition, blending manufacturers must also test batches of gasoline for distillation parameters. Therefore, a gasoline manufacturer must test between 3 and 5 parameters under part 1090.

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

25.  40 CFR 80.82 and 80.85, respectively.

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

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

28.  See http://www.epa.gov/​gasoline-standards/​state-fuels.

29.  See CAA section 211(c)(4)(C)(v)(III).

30.  See 71 FR 78195 (December 28, 2006).

31.  Some states where the federal 7.8 psi RVP standard is required have chosen instead to apply RFG or another state fuel regulation that limits RVP to less than 7.8 psi. Such a practice is consistent with the CAA. If a state with such an area decided to remove its fuel program, the state should work closely with EPA to ensure that the state's SIP demonstration also supports removal of multiple fuel programs, if desired. See Section V.A.4.g for more information.

32.  California has set requirements for gasoline sold throughout the entire state (“California gasoline”), and these requirements include limits on the gasoline RVP. See Title 13, sections 2250-2273.5 of the California Code of Regulations. These standards apply in lieu of federal RVP standards.

33.  In the absence of California's RFG regulation, either federal RVP standards or RFG would apply in California. Some areas would be RFG covered areas because either they were among the original nine RFG covered areas or they were reclassified to Severe nonattainment for an ozone National Ambient Air Quality Standard (NAAQS). See CAA section 211(k)(10)(D).

34.  See CAA section 211(k)(10)(D).

35.  The Sacramento Metro area was reclassified as a severe ozone nonattainment area on June 1, 1995, and became an RFG covered area on June 1, 1996. See 60 FR 20237 (April 25, 1995). The San Joaquin Valley area was reclassified as a severe ozone nonattainment area on December 10, 2001, and became an RFG covered area on December 10, 2002. See 66 FR 56476 (November 8, 2001).

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

37.  See 70 FR 71687 (November 29, 2005).

38.  See CAA section 110(l).

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

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

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

42.  See CAA section 110(l).

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

44.  See CAA section 110(l).

45.  See https://www.epa.gov/​gasoline-standards/​state-fuels.

46.  See 71 FR 78192 (December 28, 2006).

47.  See CAA section 211(c)(4)(C)(v)(III).

48.  Since December 2006, the following fuels have been removed from approved SIPs: Pennsylvania—7.8 psi RVP; Maine—7.8 psi RVP; Illinois—7.2 psi RVP; and Georgia—7.0 psi RVP with sulfur provisions.

49.  EPA has approved Alabama's request to move its SIP approved 7.0 psi RVP program to the contingency measure portion of the SIP for the Birmingham area. Because the fuel rule was retained as a contingency measure it remains on the boutique fuel list (see 77 FR 23619, April 20, 2012).

50.  Nevada's winter gasoline (aromatics and sulfur) fuel rule was retained as a contingency measure and therefore remains on the boutique fuel list (see 75 FR 59090, September 27, 2010).

51.  The FFARs requirements do, however, require that manufacturers of fuels and fuel additives demonstrate that fuels and fuel additives are either substantially similar under CAA section 211(f)(1) or have a waiver under CAA section 211(f)(4). See 40 CFR 79.11(i) and 79.21(h).

52.  Our authority to codify the “substantially similar” requirement in regulations is explained at 81 FR 80877-78 (November 16, 2016).

53.  See 73 FR 22277 (April 25, 2008).

54.  See 84 FR 26980 (June 10, 2019).

55.  See 73 FR 22277 (April 25, 2008) and 84 FR 26980 (June 10, 2019).

56.  See 44 FR 20777 (April 6, 1979), Octamix Waiver, 53 FR 3636 (February 8, 1988).

57.  Such as diesel fuel used in school buses.

58.  See 40 CFR 80.520(b).

59.  The vast majority of heating oil is used in the Northeast where states require that heating oil meet a 15 ppm sulfur standard. See “Guidance, Exemptions And Enforcement Discretion For New England's ULSHO Transition,” New England Fuel Institute (NEFI), available at https://nefi.com/​regulatory-compliance/​new-englands-ulsho-transition.

60.  See 40 CFR 80.520(b)(1).

61.  See 40 CFR 80.512.

62.  Designated ECAs for the U.S. include the North American ECA and the U.S. Caribbean Sea ECA. More specific descriptions may be found in EPA fact sheets: “Designation of North American Emission Control Area to Reduce Emissions from Ships,” EPA-420-F-10-015, March 2010; and “Designation of Emission Control Area to Reduce Emissions from Ships in the U.S. Caribbean,” EPA-420-F-11-024, July 2011.

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

64.  See 40 CFR 80.597(d)(3).

65.  See 40 CFR 80.597 regarding the distributor registration requirements and 40 CFR 80.590(a)(6)(i) for the associated PTD requirements.

66.  The production of 500 ppm LM diesel fuel is discussed in Section XIII.E.4.

67.  See 40 CFR 80.580(d).

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

69.  Under part 80, fuel manufacturers of California gasoline that recertify their fuels must recertify their gasoline and comply with federal fuel quality standards (per-gallon and average standards).

70.  The explanation for the analysis we performed to determine the equivalency of the California fuel standards can be found in the technical memorandum, “California Fuel Equivalency,” available in the docket for this action.

71.  The California reformulated gasoline and diesel fuel standards are at least as stringent as the standards under part 1090; therefore, these fuels should be allowed to be used throughout the rest of the U.S. Cal. Code Regs. tit. 13, §§ 2281-2282 (2019).

72.  The part 80 programs generally had two hardship provisions: (1) Unusual circumstances that significantly affected the refiner's ability to initially comply by the applicable date, under which EPA allowed financial and supplier difficulties as a reason for additional lead time; and (2) extreme, unusual, and unforeseen events, like a natural disaster or refinery fire, that occur after the standards have become effective, and for which economic and supplier difficulties have never been a qualifying hardship event. Since part 1090 is not introducing new standards, we did not propose and have effectively removed the first (sunsetted) hardship provision, which allowed for financial and supplier difficulties for initial compliance relief, and are only keeping the second (ongoing) extreme, unusual, and unforeseen hardship provision.

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

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

75.  See 40 CFR 80.69.

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

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

78.  Parties that add more of the same type of oxygenate would not be expected to submit reports for those volumes. For example, under part 1090, if a party only blended 15 volume percent ethanol into a BOB that was specified for blending up to 10 volume percent ethanol, the blender would not submit reports.

79.  Diesel fuel manufacturers must still submit periodic reports related to the additives used in their diesel fuel as specified under 40 CFR 79(a)(1).

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

81.  This action does not address how these fuels are accounted for inclusion in obligated parties' renewable volume obligation (RVO) calculations under the RFS program. We recently finalized changes to part 80 to account for the redesignation of distillate fuels meeting the ULSD standards (see 85 FR 7054-57, February 6, 2020).

82.  The updated procedures are described in greater detail in the technical memorandum, “Technical Issues Related to Streamlining Measurement Procedures for 40 CFR part 1090,” available in the docket for this action.

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

84.  The regulations at 40 CFR 80.69 and 80.101 practically limits this practice to RBOB. As discussed in Section VII, we are making it more practical for all fuel manufacturers of BOB to account for the addition of oxygenate added downstream. Part 80 also does not currently specify preparation procedures for hand blends.

85.  See CAA section 211(i) and 40 CFR 80.520(a)(2).

86.  See 40 CFR 80.46 and 80.47.

87.  See Section VII.F.

88.  See 40 CFR 80.69.

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

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

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

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

93.  See 19 CFR part 151, subpart C.

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

95.  See 40 CFR 80.2(r).

96.  See 40 CFR 80.1349 and 80.1641. It should also be noted that under part 1090 we are allowing these provisions to be used for rail imports in addition to the currently allowed truck imports under part 80. Under part 1090, diesel fuel is only subject to per-gallon standards, so alternative standards to diesel fuel imported via rail or truck are not necessary.

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

98.  We choose the summer baseline for sulfur as it was 1 ppm higher (339 ppm for summer versus 338 ppm for winter) and the winter baseline for benzene as it was 0.09 volume percent higher (1.64 volume percent for winter versus 1.53 volume percent for summer).

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

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

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.

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

103.  See 40 CFR 80.92 and 80.1469.

104.  See 40 CFR 80.573.

105.  The purpose of allowing parties to make new batches of gasoline using PCG is to provide flexibility for parties making new fuels to accommodate market demands while ensuring that the fuel quality standards are met. The provisions are designed to ensure that the new batch meets gasoline per-gallon standards and that the blending manufacturer does not increase the average sulfur and benzene levels in the national gasoline pool.

106.  See 79 FR 23575-23576 (April 28, 2014).

107.  In PCG by subtraction, a blending manufacturer determines the regulated fuel parameters of the PCG and the new batch to quantify the sulfur and benzene levels of added blendstocks for making the new fuel. In PCG by addition, a blending manufacturer directly measures the parameters of added blendstocks to quantify the sulfur and benzene levels. In both cases, the new fuel has to meet per-gallon specifications for gasoline and blending manufacturers will need to sample and test for sulfur year-round and for RVP in the summer.

108.  Refiners that produce gasoline and diesel fuel by processing crude oil must not use the provisions that apply to transmix processors and are subject to all requirements that apply to a fuel manufacturer.

109.  See 40 CFR 80.1607.

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

111.  See 40 CFR 80.84.

112.  Industry minimum flash point specifications in ASTM D975 prevent the blending of transmix into diesel fuel. Hence, there is not a need for regulatory provisions regarding blending transmix into previously certified diesel fuel.

113.  See 61 FR 35310 (July 5, 1996).

114.  Under part 80, this period can be up to 30 days. Part 1090 does not change this period.

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

116.  Coordinating Research Council (CRC) Annual Report, September 2018. The CRC Gasoline Engine Deposit Task Group, CRC Project No. CM-136, consists of members of the auto, oil, and additive industries. The objectives of this group include developing test procedures to evaluate fuel and fuel additive contributions to intake valve deposits, and injector deposits in port fuel injection and direct injection engines.

117.  The detergent program requires demonstration of no more than 5 percent flow restriction on any one port fuel injector when tested in accordance with ASTM D5598-94.

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

119.  Id.

120.  65th percentile concentrations are specified for sulfur, aromatics, T90 distillation, and olefins. Under the national generic detergent certification option, 10 volume percent ethanol must be blended into a base fuel meeting 65th percentile concentrations for sulfur, aromatics, T90 distillation, and olefins.

121.  See 65 FR 6698 (February 10, 2000) and 82 FR 23414 (April 28, 2014).

122.  The approved sulfur doping compound is di-tertiary di-butyl sulfide.

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

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

125.  It is worth noting that the test protocols will be compared to a baseline established by the EPA ASTM D5500 procedure using the part 80 test fuels. This baseline was adopted since that was the baseline for determining the deposit control specifications under CAA section 211(l).

126.  See 40 CFR 80.163.

127.  See Section XIII.F.4 regarding the expansion to the applicability of California-based detergent certifications.

128.  See 40 CFR 80.141 through 80.156.

129.  See 40 CFR 80.161(a)(3).

130.  See 81 FR 80828 (November 16, 2016).

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

132.  5 U.S.C. 552(b)(4).

133.  We note that CAA section 114 explicitly excludes emissions data from treatment as confidential information.

134.  Argus Leader, 139 S. Ct. at 2366.

135.  Id. at 2363.

136.  “Exemption 4 After the Supreme Court's Ruling in Food Marketing Institute v. Argus Leader Media and Accompanying Step-by-Step Guide,” Office of Information Policy, U.S. DOJ, (October 4, 2019), available at https://www.justice.gov/​oip/​exemption-4-after-supreme-courts-ruling-food-marketing-institutev-argus-leader-media.

137.  See id.; see also “Step-by-Step Guide for Determining if Commercial or Financial Information Obtained from a Person is Confidential under Exemption 4 of the FOIA,” Office of Information Policy, U.S. DOJ, (updated October 7, 2019), available at https://www.justice.gov/​oip/​step-step-guide-determining-if-commercial-or-financial-information-obtained-person-confidential.

138.  We note that this list does not convey the entire scope of information that we may release. Other information that does not meet the legal requirements for confidential treatment can also be released despite not being listed here.

139.  Comments from Small Refineries Coalition, Docket Item No. EPA-HQ-OAR-0227-0080.

140.  See, e.g., https://www.epa.gov/​fuels-registration-reporting-and-compliance-help/​rfs-small-refinery-exemptions,, which provides only aggregated information.

141.  See, e.g., press release regarding hardship exemptions from the sulfur standards, available at: https://archive.epa.gov/​epapages/​newsroom_​archive/​newsreleases/​d07550f8d366e3c485256b1300637472.html.

142.  We outline in more detail these areas for savings in the technical memorandum, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” available in the docket for this action.

143.  The supporting statement for the ICR and other supporting materials are available in the docket for this action.

144.  These savings are discussed in the technical memorandum, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” available in the docket for this action.

145.  Id.

146.  The ICR supporting statement is available in the docket for this action.

147.  We discuss many of these areas, including a much more detailed analysis of the cost savings, in the technical memorandum, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” and the ICR supporting statement, available in the docket for this action.

148.  These results are discussed in more detail in the technical memorandum, “Economic Analysis: Fuels Regulatory Streamlining Final Rule,” available in the docket for this action.

149.  In the NPRM we identified those areas that had the potential to have an effect on in-use fuel quality. These areas included whether the proposed RFG maximum RVP per-gallon standard of 7.4 psi was too high, whether allowing CG manufacturers the ability to account for oxygenate added downstream would slightly increase average in-use sulfur and benzene levels, and whether making compliance with EPA fuel requirements less burdensome would result in a number of new, less sophisticated fuel manufacturers that would be less likely to comply with EPA fuel quality standards. We also noted that the improved oversight, especially through third-party surveys, may improve the quality of fuel sold at retail and that by simplifying and modernizing our reporting requirements information would be more readily available to better enable the fuel quality oversight.

150.  See Section XIV.C.