Fuels Regulatory Streamlining: Response to Comments United Stales Environmental Prutuclion m »Agency ------- Fuels Regulatory Streamlining: Response to Comments Assessment and Standards Division Office of Transportation and Air Quality U.S. Environmental Protection Agency ¦SEPA United States Environmttntsl ProlGfiliOn Ag en cy EPA-420-R-20-011 October 2020 ------- Table of Contents List of Acronyms and Abbreviations iv List of Organizations Submitting Comments on the Fuels Regulatory Streamlining Rule vi 1. Streamlining Rulemaking 1 1.1. General Comments 1 2. Changes to Other Parts of Title 40 2 2.1. General Comments 2 3. Structure of Part 1090 5 3.1. General Comments 5 4. General Provisions (Subpart A) 7 4.1. Implementation Dates 7 4.2. Confidential Business Information 16 4.3. Requirements for Independent Parties 22 4.4. Definitions 26 5. General Requirements for Regulated Parties (Subpart B) 51 5.1. General Comments 51 6. Gasoline Standards (Subpart C) 56 6.1. Gasoline 56 6.2. RFG 62 6.3. C ertifi ed Butane and Pentane 70 6.4. State and Local Fuel Standards 72 6.5. Substantially Similar 77 7. Diesel Fuel Standards (Subpart D) 87 7.1. General Comments 87 7.2. Removing the Red Dye Requirement 91 7.3. Annex VI Marine Fuel Standards 94 8. Transmix and Pipeline Interface Provisions (Subpart F) 95 8.1. General Comments 95 8.2. Gasoline Produced from TGP 98 8.3. I LSI) Produced from TDP 99 8.4. 500 ppm LM Diesel Fuel Produced from Transmix 100 8.5. Pipeline Interface 101 9. Exemptions, Hardships, and Special Provisions (Subpart G) 107 i ------- 9.1. General Comments 107 9.2. Segregation Requirements 117 10. Averaging, Banking, and Trading Provisions (Subpart H) 128 10.1. Compliance on Average 128 10.2. Credit Generation, Use, and Transfer 131 10.3. Invalid Credits 133 10.4. Downstream Oxygenate Accounting 134 10.5. Downstream BOB Recertification 142 11. Registration Requirements (Subpart I) 158 11.1. General Comments 158 12. Reporting Requirements (Subpart J) 165 12.1. General Comments 165 12.2. Reporting Forms 183 13. Batch Certification, Designation, and PTD Requirements (Subparts K and L) 193 13.1. General Comments 193 13.2. Batch Certification and Designation 194 13.3. PTDs 205 13.4. Commingling of Oxygenates 218 14. Recordkeeping Requirements (Subpart M) 221 14.1. General Comments 221 15. Sampling, Testing, and Retention Requirements (Subpart N) 223 15.1. General Comments (Scope of Testing) 223 15.2. Handling and Testing Samples 236 15.3. Measurement Procedures 265 16. Proposed Third-Party Survey Provisions (Subpart O) 290 16.1. National Fuels Survey Program 290 16.2. National Sampling and Testing Oversight Program 297 17. Labeling and Refueling Hardware (Subpart P) 309 17.1. Refueling Hardware Requirements for Dispensing Facilities 309 17.2. Refueling Hardware Requirements for Motor Vehicles 312 18. Importers and Exporters (Subpart Q) 313 18.1. Importation 313 18.2. Special Provisions for Importation by Rail or Truck 314 18.3. Special Provisions for Importation by Marine Vessel 318 ii ------- 18.4. Gasoline and Diesel Fuel Treated as Blendstocks 324 18.5. Exportation 326 19. Compliance and Enforcement Provisions (Subpart R) 329 19.1. General Comments 329 20. Attest Engagements (Subpart S) 337 20.1. General Comments 337 21. Other Requirements 365 21.1. PCG 365 21.2. Gasoline Deposit Control 371 21.3. In-line Blending 392 22. Other Comments 401 22.1. Statutory and Executive Orders 401 22.2. Beyond the Scope 404 iii ------- List of Acronyms and Abbreviations Numerous acronyms and abbreviations are included in this document. While this may not be an exhaustive list, to ease the reading of this document and for reference purposes, the following acronyms and abbreviations are defined here: ABT averaging, banking, and trading ARV accepted reference value BOB gasoline before oxygenate blending CAA Clean Air Act CARB California Air Resources Board CBI Confidential Business Information CBOB conventional BOB CFR Code of Federal Regulations CG conventional gasoline DFE denatured fuel ethanol EPA Environmental Protection Agency ECA Emission Control Area EMTS EPA Moderated Transaction System FTC Federal Trade Commission GTAB gasoline treated as blendstock ILB in-line blending ILCP inter-laboratory cross-check program IRS Internal Revenue Service IVD intake valve deposits LAC lowest additive concentration MVNRLM motor vehicle, nonroad, locomotive, or marine NAAQS National Ambient Air Quality Standard NFSP National Fuels Survey Program NPRM notice of proposed rulemaking NSTOP National Sampling and Testing Oversight Program NTDF non-transportation 15 ppm distillate fuel PBMS Performance-based Measurement System PCG previously certified gasoline PFI port fuel injector PPm (mg/kg) parts per million (or milligram per kilogram) PTD product transfer document Q&A question and answer QAP quality assurance plan R&D research and development RBOB reformulated BOB RCO responsible corporate officer RFG reformulated gasoline RFS renewable fuel standard RIN Renewable Identification Number RVO Renewable Volume Obligation iv ------- RVP Reid vapor pressure SIP state implementation plan SQC statistical quality control TDP transmix distillate products TGP transmix gasoline products TPI test performance index U.S. United States U.S.C. United States Code ULSD ultra-low-sulfur diesel fuel VCSB voluntary consensus standards body WPC wholesale purchaser-consumer ------- List of Organizations Submitting Comments on the Fuels Regulatory Streamlining Rule Docket Item Number3 Commenter or Organization Name 0028 Citizen - Alex Lau 0029 Citizen - Anonymous 0030 Camin Cargo Control 0031 Texon L.P. 0032 Buckeye Partners, L.P. 0034 National Marine Manufacturers Association (NMMA) 0035 Shell Oil Products US 0036 Ingevity Corporation 0037 Renewable Fuels Association (RFA) 0038 Afton Chemical Corporation 0039 TIC Council Americas 0040 Chevron Oronite 0041 National Association of Clean Air Agencies (NACAA) 0042 Florida Department of Environmental Protection 0043 American Chemistry Council (ACC) 0044 Energy Transfer, L.P. (ET) 0045 Turner, Mason & Company (TM&C) 0046 bp America Inc. 0047 BRP US Inc. Marine Group 0048 Marathon Petroleum Company LP 0049 Exxon Mobil Corporation 0050 Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd. 0051 Alliance for Automotive Innovation 0052 Flint Hills Resources (FHR) 0053 Growth Energy 0054 CITGO Petroleum Corporation 0055 Wisconsin Department of Natural Resources (WDNR) 0056 Valero Energy Corporation 0057 Association of Marina Industries (AMI) 0058 Coalition for Renewable Natural Gas (RNG Coalition) 0059 Husky Energy 0060 Phillips 66 Company 0061 International Liquid Terminals Association (ILTA) vi ------- Docket Item Number3 Commenter or Organization Name 0062 Producers of Renewables United for Integrity Truth and Transparency 0063 Gevo, Inc. 0064 Independent Fuel Terminal Operators Association (IFTOA) 0065 American Association for Laboratory Accreditation (A2LA) 0066 National Association of Truckstop Operators (NATSO), National Association of Convenience Stores (NACS), and Society of Independent Gasoline Marketers of America (SIGMA) 0067 Suncor Energy 0068 Butamax Advanced Biofuels, LLC 0069 Chevron U.S.A. Inc. 0070 RINAlliance 0071 Urban Air Initiative, Inc. 0072 National Corn Growers Association (NCGA) 0073 Motiva Enterprises, LLC 0074 American Fuel & Petrochemical Manufacturers (AFPM) and American Petroleum Institute (API) 0075 U.S. Chamber of Commerce 0076 Eversheds Sutherland (US) LLP 0077 American Motorcyclist Association (AMA) et al. 0078 Magellan Midstream Partners L.P. 0079 Weaver and Tidwell, L.L.P. 0080 Small Refineries Coalition 0081 Texon L.P. 0082 1980 et al. 0083 Petroleum Marketers Association of America (PMAA) 0084 American Fuel & Petrochemical Manufacturers (AFPM) and American Petroleum Institute (API) 0085 Shell Oil Products US 0086 Flint Hills Resources 0087 Holly Frontier 0088 Camin Cargo Control a Individual comments from the public (and attachments submitted with comments) submitted to Docket No. EPA- HQ-OAR-2018-0227 are assigned a unique 4 digit docket number that follows the base docket number (i.e., XXXX, where "XXXX" represents the unique 4 digit document docket number). For example, Docket Item No. EPA-HQ- OAR-2018-0227-0050 is presented as 0050 in this table and within the text of this document. vii ------- 1. Streamlining Rulemaking 1.1. General Comments Commenters that provided comment on this topic include but are not limited to: 0030, 0031, 0032, 0034, 0035, 0037, 0038, 0039, 0041, 0043, 0044, 0045, 0046, 0047, 0048, 0049, 0050, 0052, 0053, 0054, 0056, 0057, 0058, 0060, 0061, 0063, 0064, 0065, 0066, 0067, 0068, 0069, 0072, 0073, 0074, 0075, 0076, 0078, 0081, 0082, 0083. Comment: Numerous commenters expressed support for the proposed Fuel Regulatory Streamlining rule. Response: We thank the commenters for their support. ------- 2. Changes to Other Parts of Title 40 2.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1 (b) (1) "These standards and related requirements are specified in 40 CFR part 1043." Comment: Part 1090 appropriately refers to part 1043 as an applicable related part. However, part 1043 still has references in it to part 80. Part 1043's references to part 80 should be changed to part 1090. [EPA-HQ-OAR-2018-0227-0074-A1, p.30] Preamble Language or Regulatory Language: Part 80, subpart M has legacy references to now-reserved subparts of part 80 Comment: The following references need to be revised or removed: • §80.1400 refers to subpart K • §80.1441 (b) (4) refers to subpart K • §80.1401 definition for Certified NTDF refers to subpart I • §80.1440(a) (2) refers to "a national security exemption under any other subpart of 40 CFR part 80 (e.g., §§80.606, 80.1655)" [EPA-HQ-OAR-2018-0227-0074-A1, p.45] > Coalition for Renewable Natural Gas (RNG Coalition) II. RNG Coalition Supports Retention of 40 C.F.R. Part 80. Subpart M. but We Remain Concerned with EPA's Continued Reliance on Provisions for Unrelated Fuels Programs. While the RFS regulations have always relied on certain provisions in other subparts of EPA's fuels regulations, references to these provisions have not always taken into account the "unique" nature of the RFS program. This has created confusion as biofuel producers have to navigate and reconcile provisions drafted with other fuel markets and requirements in mind. While EPA is keeping Subpart M as a standalone section in Part 80, moving virtually all other regulations to Part 1090, EPA continues this practice of cross-referencing (and purportedly "align[ing]") these other fuel provisions. EPA should acknowledge the differences in the fuels markets and the 2 ------- emissions requirements, as well as the overarching goals of the RFS program and minimize cross-references to avoid such confusion. At a minimum, EPA must make sure it is using the correct cross-references. EPA may have inadvertently missed some cross-references in the RFS regulations that would appear to no longer be applicable with the implementation of Part 1090. If EPA finalizes the proposal as written (rather than simply treat Subpart M on its own), EPA should correct these to avoid any confusion once part 1090 becomes effective. These cross-references include the following. • 80.1407(e) (obligated fuels) - EPA cross-references 80.2(qqq) in defining MVNRLM fuel subject to the RFS requirements, but EPA proposes to revise 80.2 to remove the subsections. • 80.1440 (military uses) - EPA cross-references 80.606 and 80.1655, both of which EPA proposes to remove from Part 80 (Subparts I and O), but EPA does not propose amendments to these provisions. RNG Coalition was supportive of these provisions to promote biofuel use in the military, and these provisions should continue. • 80.1453(e) and 80.1475 (non-transportation distillate fuel) - EPA cross references 80.590, which EPA proposes to remove from Part 80 (Subpart I), but EPA does not propose amendments to these provisions.2 RNG Coalition was supportive of EPA ensuring all obligated fuels are subject to the RFS program. In short, EPA should consider whether a cross-reference remains valid throughout the RFS regulations or whether it would be clearer (and therefore better assures compliance) to simply state the requirements as they may apply to the RFS within the RFS regulations. Where EPA believes cross-references remain useful (and clear), EPA should make certain that all cross- references are corrected prior to Part 1090 becoming effective. [EPA-HQ-OAR-2018-0227- 0058-Al.pp.3-4] 2 EPA also appears to have omitted revisions to references to §§80.125-80.127 and §80.130 with respect to the attest engagements required in §80.1475. > Flint Hills Resources 1) Part 1090 subpart A - §1090.1(b)(1) Applicability and relationship to other parts Suggestion: Revise part 1043's part 80 references to part 1090. Discussion: Part 1090 appropriately refers to part 1043 as an applicable related part. However, part 1043 still has references in it to part 80. Part 104 3's references to part 80 should be changed to part 1090. [EPA-HQ-OAR-2018-0227-0052-A1, p.2] 13) Part 80 subpart M - Legacy regulatory references Suggestion: Part 80 subpart M has legacy references to now-reserved subparts of part 80. Revise or remove these references: 3 ------- • §80.1400 refers to subpart K • §80.1441 (b) (4) refers to subpart K • §80.1401 definition for Certified NTDF refers to subpart I • §80.1440(a) (2) refers to "a national security exemption under any other subpart of 40 CFR part 80 (e.g., §§80.606, 80.1655)" [EPA-HQ-OAR-2018-0227-0052-A1, p.8] > National Association of Clean Air Agencies (NACAA) First, Subpart IIII of 40 CFR Part 60 includes a fuel requirement that cross references to Subpart I of Part 80: 40 CFR 60.4207 requires owners and operators to meet the fuel requirements in 40 CFR 80.510. Subpart I of Part 80 is among those that EPA proposes to eliminate in favor of new Part 1090, where fuel program requirements will be centralized. As EPA replaces the multiple fuel regulations in Part 80 with a single set of integrated provisions in Part 1090, the agency should also update cross references in regulations outside Part 80, including those in Subpart IIII of Part 60. [EPA-HQ-OAR-2018-0227-0041-A1, p.2] Response: We thank the commenters for their input and have corrected most of the aforementioned cross- references in parts 60, 63, 80, and 1043. Based on a closer review of the definition of public vessel in §1043.20, we realized that we need to make further changes to properly describe how to reference the fuel-based national security exemption in §1090.605. As a result, we are deferring action on this change and expect to amend that definition in a future rulemaking. In addition, we found and corrected references to part 80 in 40 CFR part 1042 (Marine CI emission standards) and 40 CFR part 1065 (engine testing procedures). One reference in §1065.703 required further adjustment. This section identifies measurement procedures for sulfur content and other test fuel parameters. The regulation currently references a protocol in part 80 to determine which reference procedures are appropriate. Rather than identifying the PBMS protocol in part 1090, subpart N, we are simply naming ASTM D2622, ASTM D5453, and ASTM D7039 as acceptable methods for distillate diesel fuel with any of the specified sulfur concentrations. This approach is consistent with the current regulation, but removes the ambiguity and the process for demonstrating that each procedure is adequate for measuring sulfur content. 4 ------- 3. Structure of Part 1090 3.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • the overall structure of the new regulations under 40 CFR Part 1090 and the sunset of most sections of the current 40 CFR Part 80; • the organization of the subparts by topic rather than by separate fuel programs; [EPA-HQ- OAR-2018-0227-0074-A1, p.6] > Eversheds Sutherland (US) LLP Proposed Regulatory Changes 2.1 General Overview Generally, Eversheds Sutherland believes that the layout of the proposed regulations makes sense and is easier to navigate than the current rules. [EPA-HQ-OAR-2018-0227-0076-A1, p.2] > Petroleum Marketers Association of America (PMAA) Reorganization Under New Part 1090 PMAA supports reorganizing the fuel regulations in Part 80 into a new Part 1090 and arrangement by regulated party. The haphazard regulatory structure of the current Part 80 is difficult and time consuming to navigate. The proposed organizational changes including, simplification of language, organizing regulations by regulated party, using dedicated subparts specific fuels and functions and removing outdated provisions will make the regulations easier to search, understand and ultimately to explain to regulated parties. PMAA believes it is particularly important to remove outdated provisions such as the ULSD PTD language and labelling requirements. Petroleum supply vendors still sell ULSD labels and other compliance products that are no longer required by referencing outdated provisions in advertising material. Removing these provisions will help prevent small business petroleum marketers from diverting compliance resources to products they no longer need. PMAA members are primarily small businesses who don't often have dedicated regulatory compliance officers to explain and implement regulatory requirements. Instead, principal officers involved in the day to day operations of their company are responsible for regulatory compliance, with assistance from PMAA staff. Simplifying the regulatory language and organizing it in a logical user-friendly framework will not only increase compliance, but also significantly reduce the regulatory burden 5 ------- on small business petroleum marketers. PMAA fully supports all the proposed changes and applauds the EPA for undertaking them. [EPA-HQ-OAR-2018-0227-0083-A1, p.2] Response: We thank the commenters for their support and have retained the proposed structure for the final regulations. 6 ------- 4. General Provisions (Subpart A) 4.1. Implementation Dates Comment: > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. We urge EPA to finalize the proposed rule as soon as possible, and no later than year's end. [EPA-HQ-OAR-2018-0227-0063-A2, p.2] > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) While we support EPA's efforts to implement the rule on January 1, 2021, we are concerned that the rule may not be finalized until late in 2020. The Associations urge EPA to finalize the rule as early as possible, to maximize the time available to prepare for the new Part 1090 provisions. If a final rule is not available until late 2020 or perhaps early 2021, it would create tremendous uncertainty for regulated parties and could confound the regulated parties' ability to comply. We believe additional discussion with EPA is warranted to consider different implementation scenarios if a final rule cannot be completed expeditiously. We have included some specific recommendations for implementation flexibility, based on having sufficient time between a final rule and the January 1, 2021 start date. However, additional flexibility or alternative implementation plans may be necessary to accommodate delays in the approval and publication of a final rule. The Associations suggest implementing the new part 1090 provisions effective one year from publication in the Federal Register or no sooner than January 1, 2022. These provisions include items like the National Sampling and Testing Oversight Program and downstream oxygenate accounting for conventional gasoline, along with the product transfer document updates and reporting that goes along with these changes. [EPA-HQ-OAR-2018-0227- 0074-A1, pp.5-6] 3.9 Implementation Dates: Administrative Changes EPA has indicated their plan to make the rule effective January 1, 2021. The Associations support this date for many of the provisions of the new Part 1090. However, there are some areas where additional time is warranted. In the preamble, EPA seeks comment specifically on what provisions may require additional lead time to implement. [EPA-HQ-OAR-2018-0227-0074-A1, P-21] Various changes will be needed across the system that are part of the ongoing supply and distribution of products. For example, there will no longer be a regional distinction for reformulated gasoline with differing VOC-emission control standards. The industry will need to develop new reformulated gasoline commodity codes for trading and tracking purposes. Changes in the butane and pentane provisions to capture the new certified product standards will also require some administrative changes with contracts and reporting. As such, the Associations 7 ------- suggest an alternative that would provide additional time by requiring the changes be complete by May 1, 2021.18 [EPA-HQ-OAR-2018-0227-0074-A1, p.21] 3.10 Implementation Dates: National Sampling and Testing Oversight Program The proposed national sampling and testing oversight program is a new program and has a significant number of administrative requirements starting with registration of facilities. For the RFG Survey Association ("RFGSA") to be ready for a January 1 implementation, they are asking that all facilities register by August 1st and complete a questionnaire by end of October. Facilities will need to determine whether they want to participate and, if so, determine who will be responsible for the administration of the program on site. The site personnel will need to be trained in using the system as documents must be uploaded, and responses registered during the process. Additionally, each site will need to ensure they are prepared to receive the contractors on site to witness and receive samples and review lab SQC information. Since a company has no idea which facilities will be selected for a visit first, the Associations' member companies will have to ensure that all facility personnel are trained in these administrative procedures by the end of the year. [EPA-HQ-OAR-2018-0227-0074-A1, p.21] The Associations suggest reducing the number of surveys the first year to allow them to be completed during the summer and fall/winter. The RFGSA provided a presentation to the Associations recently and estimated about 1000 sampling events at an estimated 350 facilities. The 1000 sampling event estimate is based on assumptions for the adjustment factors in the NPRM.19 In order to allow the industry additional time to prepare for the new administrative requirements of the survey, the Associations recommend setting these adjustment factors to " 1" for the first year of the program. This would limit the site visit to one summer and one winter visit for the first year. Limiting the first year of the program to 1 summer visit and 1 winter visit, scheduled to start with summer, and then increasing the number of events the following year, would allow sites additional time to prepare and train for these new administrative requirements. [EPA-HQ-OAR-2018-0227-0074-A1, p.21] 3.11 Implementation Dates: Product Transfer Documents One complicating factor in the product transfer document ("PTD") changes is the number of PTDs throughout the supply and distribution system that will require change. Some changes are minimal while others are more substantial. The list includes refinery statements such as designation, RVP and oxygenate types, pipeline codes updated to reflect new statements, bill of ladings ("BOL") at the truck racks updated for new language, and invoices, contracts or other documents used to memorialize title transfers. Within a company, these documents are usually created by different systems20 thus requiring modifications to multiple systems. Additionally, the agency may receive comments that result in changes to the required PTD language. The final language will not be certain until the final rule is issued which further compresses the timeline for making the requisite changes through all the systems. The Associations suggest an alternative for §1090.1150 through §1090.1175 that would provide additional time by requiring the changes be complete by May 1. This date coincides with the summer gasoline transition at most terminals, which constitutes the largest number of facilities that would need to make changes. [EPA-HQ-OAR-2018-0227-0074-A1, p.22] 8 ------- 18 See § § § § 1090.1150, 1090.1160, 1090.1170, 1090.1175. > bp America Inc. (bp) §1090.1150- §1090.1175 Product transfer document language Various changes will be needed across the distribution system to comply with changes in the fuels regulations including product transfer documents. For example, there will no longer be a regional distinction for reformulated gasoline with differing VOC-emission control standards. The industry will need to develop new reformulated gasoline commodity codes for trading and tracking purposes. Pipelines and terminals will need to implement the new CBOB with oxygenate designation and determine how they will update their specifications and manage their systems to reflect this change. In addition, there are a number of revised PTD requirements in the Streamlining Rule proposal. To accommodate these changes, all persons in the fuel distribution chain will need to make changes to their PTD language and related systems. PTD language is managed using complex systems that facilitate a number of fuel custody and title transfer activities simultaneously. Changes to those systems require careful thought, the involvement of numerous people, and verification that the changes being made are accurate. That is an involved and complex process that by its nature takes time to complete. Due to the complexity of these systems, bp recommends the PTD changes in the Streamlining Rule go into effect four months after the effective date of the rule. That will allow sufficient time for all parties involved with the supply chain to make the necessary changes prior to the summer season. [EPA-HQ-OAR-2018-0227- 0046-A1, pp.18-19] > Chevron U.S.A., Inc. We urge EPA to work expeditiously to finalize this proposal in time for a January 1, 2021 start date. [EPA-HQ-OAR-2018-0227-0069-A1, p.l] Timing of the Final Rule and the Implementation Date Chevron supports EPA's efforts to implement the rule on January 1, 2021. However, we are concerned that the rule may not be finalized until very late in 2020. We would prefer to have a final rule as early as possible, ideally in September or October 2020, to maximize the time available to prepare for the new Part 1090 requirements. If a final rule is not available until later in 2020 or perhaps early 2021, this creates tremendous uncertainty for regulated parties. We believe additional discussion with EPA is warranted to consider different implementation scenarios if a final rule cannot be completed expeditiously. Our comments are based on having sufficient time between a final rule and the January 1, 2021 start date. Additional flexibility or alternative implementation plans may be necessary to accommodate delays in the approval and publication of a final rule. [EPA-HQ-OAR-2018-0227-0069-A1, p.l] 9 ------- > Eversheds Sutherland (US) LLP Timing Streamlining of the gasoline and diesel rules under Part 80 is a substantial and daunting undertaking. Taking this into account, EPA has released a series of draft proposals prior to this Proposed Rule. The first draft was released in May 2018, and shortly afterwards EPA held a three-day workshop in Chicago open to the public to review the draft with stakeholders; subsequent drafts were released in August 2018, April 2019, and December 2019. Eversheds Sutherland greatly appreciates this effort and commends EPA staff on its communication and consideration of input received during this time. However, we remain concerned that the implementation date of January 1, 2021, is ambitious. The stated purpose of the streamlining effort is to ease regulatory burdens for EPA and regulated parties as well as lower costs by eliminating redundant and outdated regulatory sections of the gasoline and diesel regulations. However, the current regulations are not merely being stripped of outdated provisions. Instead, EPA has redrafted most of the definitions and provisions, and while many of the changes maintain—or are intended to maintain—the status quo, there will be many new requirements and procedures to follow to ensure compliance. Because the changes touch all aspects of the governing rules for gasoline and diesel, we are concerned that regulated parties may not fully appreciate how the final rule will impact business and may not be ready. Issuance of a final rule in the fall provides for very limited time to review and implement the final requirements if the implementation date remains January 1, 2021. Causing additional tension, before issuance the comments received on the Proposed Rule will require attention and action in order to make necessary clarifications and other changes, which will take time—indeed, as set forth in our comments, there are several areas that need modification and EPA attention. Eversheds Sutherland has requested additional workshops, such as that held in Chicago, be held again—robust dialogue with all stakeholders at one time is essential, in our view, for an effort of this magnitude. We are concerned that in the absence of such interaction, there will be a myriad of issues arising after the rule is implemented that will raise numerous questions that could impact business as well as compliance. Hopefully, the collective comments received by EPA will adequately address our concerns, but we still encourage EPA to carefully consider whether all parts of the Proposed Rule will be ready for implementation on January 1, 2021. [EPA-HQ- OAR-2018-0227-0076-A1, pp.1-2] > Gevo, Inc. We'd also urge EPA to finalize the proposed rule as soon as possible, and no later than year's end. [EPA-HQ-OAR-2018-0227-0063-A1, p.4] Finally, we'd recommend the aforementioned recommendations be adopted and put into effect as soon as possible once and/or shortly after this becomes a final rule, rather than some lengthy phase-in period. For example, PTD changes should be exceptionally easy to comply with, and therefore days/weeks, rather than months, would be all it takes to integrate changes for 10 ------- businesses already very familiar with the process and this rule-making. [EPA-HQ-OAR-2018- 0227-0063-A1, p.4] > International Liquid Terminals Association ILTA's CONCERNS While the proposal includes many provisions that ILTA supports (listed above), there are also areas of concern. We discuss these below. 1. Timing EPA has proposed an effective date of January 1, 2021 effective date for Part 1090 regulations. We propose an effective date of no sooner than June 1, 2021, to align with the changeover to VOC-season gasoline, and at least 90 days after EPA finalizes the Part 1090 Fuels Streamlining Regulation, allowing sufficient time to make all necessary changes to Product Transfer Documents (PTDs) and prepare and submit necessary blend waivers. Finally, ILTA agrees with EPA's proposal for a March 31, 2022 deadline for the first compliance reports for the 2021 compliance and a June 1, 2022 deadline for the first attest engagement reports for the 2021 compliance period. [EPA-HQ-OAR-2018-0227-0061-A1, p.3] > Magellan Midstream Partners Implementation Timeline It is our understanding that this rule may not be final when posted in the Federal Register until mid-December, or later, although the proposed effective date of the rule is January 1, 2021. We believe that adhering to such a rapid implementation timeline will prove unfeasible for certain portions of the rule, and as such, in our comments, we have delineated a number of requirements that should be postponed. Considering the depth of the changes necessary to comply with the consolidation of the RFG program with the other fuel programs and the necessary investment in new equipment for compliance, we believe that said portions should have an effective date no earlier than May 1, 2021 which will allow sufficient time to acquire equipment, make all necessary changes to internal systems, conduct required training and prepare and submit necessary applications related to the new requirements. [EPA-HQ-OAR-2018-0227-0078-A1, p.l] §1090.1150 Product transfer documents A complicating factor in the product transfer document ("PTD") revisions is the number of PTDs throughout our system that will require change. Some changes are minimal while others are more substantial. The list includes refinery statements such as designation, RVP and oxygenate types, pipeline codes updated to reflect new statements, bill of ladings ("BOL") at the truck racks updated for new language and invoices, contracts or other documents used to memorize title transfers. Within our company, these documents are created by different systems requiring 11 ------- modifications over multiple systems. The final language will not be certain until the final rule is issued possibly in mid-December which further compresses the timeline for making the requisite changes through all the systems. As with the overall implementation date of the rule, we are requesting additional time by requiring the changes be complete by May 1. This change can be accomplished through the following change: "(a) General. (1) Beginning on May 1. on each occasion when any person transfers custody or title to any product covered under this part other than when fuel is sold or dispensed for use in motor vehicles at retail outlet or WPC facility, the transferor must provide to the transferee PTDs that include all the following information:" This date coincides with the summer gasoline transition at most terminals, where the largest number of facilities would need to make changes. [EPA-HQ-OAR-2018-0227-0078-A1, p.6] > Marathon Petroleum Company LP (MPC) Implementation Dates "One potential solution is to allow more time for these specific provisions to phase in. For example, we could allow regulated parties to continue to use the part 80 PTD requirements until the beginning or end of the high ozone season (June 1 and September 15, respectively). A similar approach could be allowed for other provisions that potentially need more lead time. We seek comment specifically on what provisions may require additional lead time to implement." MPC strongly supports the proposed January 1, 2021 compliance date for most provisions of part 1090. However, as EPA notes in the Preamble, additional time is needed to implement some of the proposed provisions. Specifically, the administrative efforts involved in updating PTDs, such as developing new commodity codes, updating forecasting, pricing, accounting, and reporting systems. In addition, implementation of streamlined sampling and testing requirements and preparing for the new oversight survey, will take more time. Similarly, updating contracts and implementing requirements associated with certified butane and pentane producers will require additional lead time. Finally, MPC supports the extension of in-line blending waivers granted under 40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] > Suncor Energy (U.S.A.) Inc. Time for Implementation. EPA's preamble requested comment on the implementation schedule for the Proposed Rulemaking, including whether a phase-in of certain requirements is appropriate. [EPA-HQ-OAR-2018-0227-0067-Al,p.3] The time required to implement the required changes is not sufficient. EPA's preamble states that the changes in the Proposed Rulemaking will minimize the burden associated with meeting the regulation. However, this is not the case. The changes impose a substantial burden on fuel manufacturers with respect to the initial changes necessary to demonstrate compliance. Further, most, if not all, companies impacted by the changes have been and continue to be impacted by decreased staffing and increased workloads associated with the COVID-19 pandemic, such that a 12 ------- January 1, 2021 implementation date is simply not achievable, particularly given the likely end of year publishing date. [EPA-HQ-OAR-2018-0227-0067-A1, p.4] Suncor agrees with and supports a delayed implementation or phased-in approach. Most, if not all, of the proposed changes that affect Suncor's facilities require administrative and procedural changes as well as training for all affected stakeholders. For example, modifications are required to laboratory testing procedures, PTD language and designations, and in-line blending waivers. In addition, new processes must be established for the sampling surveys, in-line blending audits, and Attestations. Each element by itself may not seem very time consuming but when all of the proposed changes are rolled up, it will be a significant effort when added to existing daily work. [EPA-HQ-OAR-2018-0227-0067-A1, p.4] > U.S. Chamber of Commerce V. EPA's Finalization Of The Rulemaking Should Be Prioritized To Provide Adequate Lead Time For Implementation We applaud EPA's streamlining effort and the collaborative working relationship that the agency fostered with stakeholders to develop the Proposed Rule, but recommend that the agency expedite its finalization. The agency issued four discussion drafts, equivalent in detail to the Proposed Rule, with the first being make public in May 2018.6 The discussion drafts undoubtedly improved the quality of the Proposed Rule; however, to meet the implementation deadlines in the Proposed Rule, the agency should expedite the completion of the final rulemaking. Issuing the final rulemaking this Fall will provide a few more months for regulated entities to implement the new testing and paperwork provisions. [EPA-HQ-OAR-2018-0227- 0075-A1, p.5] 6Fuels Regulatory Streamlining - Discussion Draft Regulations, May 2018, https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P 100UI40.pdf > Valero Energy Corporation The proposed rule changes are significant and will require time to implement. Thus, Valero requests that EPA allow sufficient time for implementation but also urges EPA not to set compliance dates in the middle of a compliance year. Implementation will be better accomplished if it is not required in the middle of a compliance year. [EPA-HQ-OAR-2018- 0227-0056-A1, p.2] K. Implementation Dates 1. The product transfer document ("PTD") updates will require more time to be implemented. Product transfer documentation is generated through automated systems that involve integration with accounting and inventory management systems. Modifying these systems to generate the appropriate required language for various product transfer scenarios involves development or modification of software and database systems. Valero agrees with AFPM that EPA should 13 ------- extend the period for compliance. EPA has reported that the final rule might not be issued until December 2020. It is unreasonable for EPA to expect compliance with the new requirements in less than six (6) months after issuance of the final rule. Valero requests that EPA delay the compliance date or effective date of new requirements applicable to PTDs to at least six (6) months following the publication of the final rule. [EPA-HQ-OAR-2018-0227-0056-A1, pp.12- 13] 2. Downstream blendstock ("BOB") recertification requires time. Valero recommends extending the time period for implementation of recertification requirements due to the time needed to implement tracking, recordkeeping, and reporting processes, which will include system updates, new commodity codes, and training. The proposed new requirement will require training and development of procedures for tracking downstream oxygenate activities across many more blending facilities and compliance personnel. Valero requests that EPA delay the effective date of the BOB recertification requirements to one year following publication of the femal rule. [EPA-HQ-OAR-2018-0227-0056-A1, p. 13] III. Conclusion EPA has reported that EPA will not finalize this rule until December 2020; thus, the final rule might not be published until very late 2020 or early 2021. Valero requests that EPA take the time to make all changes that Valero along with AFPM and API suggest to improve the clarity of the rules and ease compliance and implementation. Since the final rule will not be available until the end of the year, Valero requests EPA to ensure that implementation deadlines are reasonable and do not create a mid-year shift in rules. Mid-year implementation will complicate compliance and reporting. [EPA-HQ-OAR-2018-0227-0056-A1, p.14] Response: We appreciate the many comments that support the January 1, 2021, implementation date and are finalizing it at the implementation date for the vast majority of part 1090. We believe that for the most part, part 1090 carries forward the part 80 requirements. This should result in minimal disruption in existing industry practices. Also, in response to comments, we have made many adjustments that more closely align with the existing part 80 requirements (e.g., establishing homogeneity criteria for batches more consistent with part 80 requirements) that should make it easier for regulated parties to begin implementation for most provisions on January 1, 2021. We believe that maintaining the January 1, 2021, implementation date is important to align with the considerable effort stakeholders have already invested to plan for it. However, we also appreciate the fact that some provisions may take more time for regulated parties to implement and that the short lead time from the time this rule is finalized to January 1, 2021, may make implementation difficult. For these areas, as discussed in more detail in Section III.B of the preamble, we are providing more lead time. These areas include the part 1090 PTD provisions, which go into effect May 1, 2021, and the NSTOP, which goes into effect June 1, 2021. 14 ------- Several commenters asked that we also delay implementation of the downstream BOB recertification provisions. However, we believe the additionally flexibilities that we are providing for small volume blenders in the final regulations will allow parties that recertify BOBs to meet the January 1, 2021, implementation date. These flexibilities are discussed in detail in Section VII.G of the preamble and Section 10 of this document. Finally, as highlighted by some commenters, we intend to engage in public outreach to regulated parties (e.g., webinars, job aids) to increase awareness of, understand, and aid in the implementation of the part 1090 regulatory changes. 15 ------- 4.2. Confidential Business Information Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Confidential Business Information. The Associations are concerned about EPA's proposed disclosure of certain information provided to the agency in various petitions for regulatory relief. This includes the submitter's name, the location of the facility for which relief is requested, the general nature of the request, the relevant time period for the request, and the extent of EPA's action to grant or deny the request, and any relevant conditions. The Agency proposes to provide notice so each 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. [EPA-HQ-OAR-2018-0227-0074-A1, p.6] This approach is contrary to Congress's specific intent and is inappropriate. Congress provided hardship relief in the Clean Air Act and it is up to Congress to amend these provisions for disclosure without notice. EPA has treated these requests as confidential for many years and disclosure has the potential to impact markets and have a chilling effect on an individual's ability to file. Thus, the Associations oppose this proposed initiative. Instead, the Associations support the continuation of the notice and substantiation requirements for confidential business information in the CFR. Therefore, the text of section 1090.15(a) should be edited to read: (a) Except as specified in paragraphs (b) and (c) of this section, a Any information submitted under this part claimed as confidential remains subject to evaluation by EPA under 40 CFR part 2, subpart B. Additionally, the proposed provisions in section 1090.15(b), (c) and (d) should not be finalized. [EPA-HQ-OAR-2018-0227-0074-A1, p.7] > Coalition for Renewable Natural Gas (RNG Coalition) III. There Is No Reason to Continue to Delay Codifying EPA's Determinations that Basic Information Regarding Small Refinery Exemptions is NOT Entitled to Confidential Treatment. RNG Coalition also notes that EPA is proposing to find certain identifying information for parties seeking exemptions under other fuels programs to not be considered confidential business information. EPA's rationale in support of this proposal is equally applicable to its 2016 proposal to codify its determination that basic information on small refinery exemption requests and decisions are not entitled to treatment as confidential business information. RNG Coalition again urges EPA to finalize these similar findings it has made with respect to small refinery exemptions under the RFS program, which EPA sought additional comment and still has not finalized.3 [EPA-HQ-OAR-2018-0227-0058-A1, p.4] 16 ------- 3 85 Fed. Reg. 7016, 7019 (Feb. 6, 2020). > Eversheds Sutherland (US) LLP Confidential Business Information The Proposed Rule states that confidential business information ("CBI") will be treated under 40 C.F.R. part 2, subpart B, which is the current position under Part 80.1 However, under the new proposed CBI provisions, certain information contained in "submissions" to EPA and incorporated into EPA determinations on submissions are not provided confidential treatment under 40 C.F.R. part 2 or 5 U.S.C. § 552(b)(4). EPA states it may disclose such information falling into the exceptions on its website or make it available to interested parties without additional notice, even if claimed as CBI. According to the Preamble of the Proposed Rule, it appears that by "submissions," EPA means requests under the following processes: Testing and R&D exemptions under 40 C.F.R. § 1090.610, hardship exemptions under 40 C.F.R. § 1090.635, alternative quality assurance programs under 40 C.F.R. § 1090.505, alternative PTD language under 40 C.F.R. § 1090.1175, inline blending waivers under 40 C.F.R. § 1090.1315, alternative measurement procedures under 40 C.F.R. § 1090.1365, survey plans under 40 C.F.R. § 1090.1400, and alternative labels under 40 C.F.R. § 1090.1500.2 EPA should better define "submissions" in the final rule to limit the application of this provision to the actions listed in the preamble; this would make it clear which "submissions" may not be protected, while also clarifying that regulated entities retain their rights to CBI protection for reporting, responding to request for information, and documentation provided to EPA. [EPA-HQ-OAR-2018-0227-0076-A1, pp.2-3] 1 Proposed Rule at § 1090.15 2 Fuels Regulatory Streamlining, 85 Fed. Reg. 29,085 (May 14, 2020). > International Liquid Terminals Association 5. Confidentiality EPA's revised Confidential Business Information (CBI) provision sets a precedent of the agency releasing potentially confidential information at its sole discretion. ILTA suggests that EPA issue notices to the businesses in question and include an option to appeal the disclosure before it is made public. [EPA-HQ-OAR-2018-0227-0061-A1, p.3] > Producers of Renewables United for Integrity Truth and Transparency EPA must make the public aware of the circumstances in which companies may be exempt from statutory requirements. But such requirements can be rendered meaningless if the public is unaware of how EPA applies those exemptions and cannot ensure that EPA is properly applying those exemptions and enforcing the statute. When those companies seek an exemption from 17 ------- compliance then EPA must be held to account to do the public's bidding in public. There should be nothing secretive about which company seeks an exemption from compliance. Put another way, there should be nothing secretive when a company receives an exemption from the renewable fuels program, why they received the exemption, and for how many gallons the relief is provided. By contrast, there is absolutely nothing confidential about the plant closings caused by those exemptions. Closing a biofuels production company is an extremely public process. Therefore, how can it be reasonable that those seeking non-compliance can be allowed to continue to lurk in EPA's shadows when those impacted by their actions can't hide? EPA explained that, under Food Marketing Institute v. Argus Leader Media, 139 S. Ct. 2356, 2366 (2019), the U.S. Department of Justice (DOJ) clarified that 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." 85 Fed. Reg. at 29,085. Along those lines, EPA indicates it is "providing an express indication that we may release certain basic information incorporated into EPA actions on petitions and submissions, as well as information contained in submissions to EPA under part 1090 without further notice, and that such information will not be entitled to confidential treatment under Exemption 4 of the FOIA." Id. " [T]o expedite processing of information requests and increase transparency related to EPA determinations, we are proposing to clarify in the regulations that a clearly delineated set of basic information related to our decisions on exemptions, waivers, and alternative procedures under part 1090 will not be treated as confidential." Id. This basic information includes: the 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. And, EPA would also find, after it has adjudicated submissions, that EPA may release the following additional information: the extent to which EPA either granted or denied the request, and any relevant conditions. EPA found "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." Id. "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." Id. While Producers United takes no position on the specific decisions EPA references as to whether they should not be entitled to CBI treatment, these submissions do include voluntarily seeking "exemptions" from EPA fuel requirements. EPA has made similar determinations with respect to small refinery exemptions under the RFS. In 2016, EPA proposed to codify a similar regulation as proposed 40 C.F.R. §1090.15 here under the RFS program in its Renewables Enhancement and Growth Support (REGS) proposed rule.1 EPA has still yet to codify this determination. This is despite the fact that numerous refineries have lost any such claims through a FOIA lawsuit and waived any such claims in SEC filings and in other publicly available documents, including comments to EPA and litigation documents.2 The FOIA lawsuit has established that EPA, at a minimum, can make its decisions public, while protecting specific CBI through redaction. 18 ------- Producers United and other stakeholders throughout the fuels industry have urged EPA to provide more transparency on its small refinery exemption decisions under the RFS program. And, EPA's Proposed Rule here provides even further support for doing so. Indeed, EPA has provided small refineries with notice that it will release this basic information. In February of 2020, EPA established its "Inventory of Active Guidance Documents" through its Guidance Portal. 85 Fed. Reg. 31,104, 31,106 (May 22, 2020). EPA's Guidance Portal lists "active guidance documents issued" by EPA, and includes a 2011 memorandum indicating EPA "will" post "all hardship exemption requests," including under the RFS (listing 40 C.F.R. §80.1441(a)(2)), and "post its decision."3 Similar to the transparency sought in the Proposed Rule, this memorandum states that: "We believe that public notification will enhance EPA's interest in conducting a fair and open process for evaluating requests for hardship exemptions."4 Even if EPA claims this 2011 "active guidance" memorandum was not sufficient notice, the 2016 REGS proposed rule similarly provided notice of EPA's determination that the basic information regarding small refinery exemption requests and decisions is not entitled to CBI (confirmed again in the 2020 RFS proposal). At a minimum, the industry should now be well aware of EPA's position that the fact of the request and the grant or denial of such exemptions are not entitled to CBI. As such, EPA must begin providing the public with this basic information on all small refinery exemption requests and decisions, including, among others, the 52 recent exemption requests EPA has indicated are now pending for compliance years 2011- 2018 (as of June 18, 2020). EPA must honor this Administration's commitment to transparency, particularly with respect to decisions that have had national implications and have had such adverse impacts on the biofuels industry that the RFS program was intended to promote. [EPA- HQ-OAR-2018-0227-0062-Al.pp.l-3] 1 EPA sought additional comments on this proposal in the 2020 Renewable Fuel Standard proposal, but EPA, again, declined to finalize the provisions in the 2020 final standards. 85 Fed. Reg. 7016, 7019 (Feb. 6, 2020). 2 For example, in the record index submitted in litigation related to exemptions for compliance year 2018 (Case No. 20-1099 (D.C. Cir.)), EPA continues to hide the names of refineries despite references to SEC filings and despite the waiver of CBI claims for earlier years. 3 EPA, July 5, 2011 Memorandum, Processing of Hardship Exemptions Requests, posted on EPA's list of Guidance Documents Managed by the Office of Air and Radiation (last updated June 26, 2020). The following is a snapshot from EPA's Guidance Portal, using the search term "exemption" (last searched June 29, 2020). [See the image on p.3 of EPA-HQ-OAR-2018-0227-0062-A1.] 4 Id. In fact, EPA further stated it would accept comments on these requests. > Small Refineries Coalition I. The Coalition Objects to EPA's Proposed Blanket Treatment of Information Claimed as Confidential by Submitters. The Coalition opposes EPA's proposed disclosure of certain information provided to the agency in various petitions for regulatory relief that the submitter has claimed as confidential under 19 ------- Exemption 4 of the Freedom of Information Act ("FOIA"), 5 U.S.C. § 552(b)(4).3 EPA proposes the release of the following information without further notice to the submitter and without following EPA's procedures set forth in 40 C.F.R. part 2, subpart B, which provide the submitter an opportunity to substantiate any claims of confidentiality for the information it submits: the submitter's name, facility location, the general nature of the request, the relevant time period for the request, and the extent to which EPA either granted or denied the request, including any relevant conditions.4 If finalized, the proposed rules would put small refineries in the impossible position of weighing the benefits of possible regulatory relief against the reputational and commercial damage that most likely will result from disclosure of confidential information. This would lead to a perverse implementation of the regulatory relief provisions that were promulgated to help entities in need of relief. Unfortunately, EPA appears to embrace this approach, recognizing that its proposal would force submitters "to decide whether to make such a request with the understanding that EPA may release certain information about the request without further notice."5 Historically, submitters have claimed their identities and the nature and relevant time period for their requests as confidential in their petitions for regulatory relief. For good reason, EPA also has treated that information as confidential. The mere fact of a company's petition for regulatory relief, if disclosed to the public, would have tremendously negative effects on the submitter's competitive position. Disclosure of a company's need for regulatory relief could cause its competitors, partners, customers, and others to question the company's viability and, as a result, cause the company to suffer competitive harm. Competitors could seize upon the company's identified vulnerabilities to gain a competitive advantage through any number of methods. In the proposal, EPA claims to be applying recently released United States Department of Justice ("DOJ") guidance issued in the wake of the Supreme Court's decision on the protection of CBI under FOIA Exemption 4. Food Marketing Inst. v. Argus Leader Media, 139 S. Ct. 2356 (2019). In that case, the Court held that where commercial or financial information is both (1) "customarily kept private, or at least closely held," by its owner, and (2) provided to the government under "some assurance" of privacy, the information is "confidential" within Exemption 4's meaning. Id. at 2363, 2366. 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. In the wake of the Argus Leader decision, DOJ released guidance explaining that agencies should consider whether a submitter provided information to an agency under either an express or implied assurance of confidentiality.6 Because the Supreme Court opinion did not determine to what extent the government assurance condition must be met, DOJ's guidance advises agencies to employ "sound administrative practice" in their determination of whether they provided an express or implied assurance of confidentiality.7 The guidance does not suggest that agencies should mechanically remove entire categories of information from CBI protection, including categories of information historically treated as confidential by EPA.8 However, EPA does exactly that in its proposal by stating that the proposal acts as "an express indication that [EPA] may release certain basic information . . . without further notice, and that such information will not be entitled to confidential treatment under Exemption 4 of the FOIA."9 20 ------- EPA's proposed approach contradicts Congress's intent in promulgating provisions for hardship relief under the Clean Air Act and represents a misguided application of DOJ's guidance. The Coalition opposes EPA's proposed treatment of CBI and requests that EPA continue to follow the notice and substantiation requirements for CBI that are provided at 40 C.F.R. part 2, subpart B. [EPA-HQ-OAR-2018-0227-0080-A1, pp. 1-3] 3 85 Fed. Reg. at 29084; proposed 40 C.F.R. § 1090.15. 4 85 Fed. Reg. at 29085. 5 Id. 6 "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-institute-v-argus-leadermedia. 7 Id. 8 Id. 9 85 Fed. Reg. at 29085. Response: These comments are addressed in Section VIII.H. of the final rule. 21 ------- 4.3. Requirements for Independent Parties Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.14 Independence Requirement for Auditors EPA seeks comment on the independence requirements and their impacts on independent third parties, as well as the anticipated effectiveness of these provisions to increase reliability in the third-party oversight program. Effectively, to be an eligible independent party, no employee could have worked for the regulated party within the preceding 3 years. [EPA-HQ-OAR-2018- 0227-0074-A1, p.23] EPA has proposed to expand the employment criteria in §1090.55 for independent auditors to apply universally to other independent parties, including independent inspection and independent surveys. The Associations believe that independent auditors are distinct from other independent parties. Auditors should still be held to the same 3-year requirement as they are in 40 CFR 80.92. The 3-year requirement could be codified in §1090.175 that deals specifically with auditors. However, requiring that independent contractors cannot be employed within the previous three- year period by a regulated party is more stringent than the current requirements of 40 CFR 80 and creates serious impacts and risks to an industry that requires specific knowledge and skills for safety and compliance. To prevent a gap in skilled workers, EPA should implement a one- year employment criteria for independent parties. This aligns with the independence requirements of the Securities Exchange Commission ("SEC").22 An alternative process to address circumstances that cannot be managed with a one-year employment lag, such as survey activities, should be managed through a disclosure submission to the EPA. [EPA-HQ-OAR- 2018-0227-0074-A1, p.23] 22 See 17 CFR § 210.2-01. > Marathon Petroleum Company LP (MPC) Requirements for independent parties 1090.55(a) Independence. The independent third party, their contractors, subcontractors, and their organizations must be independent of the regulated party. All the criteria listed in paragraphs (a)(1) and (2) of this section must be met by every individual involved in the specified activities in this part that the independent third party is hired to perform for a regulated party, except as specified in paragraph (a)(3) of this section. (1) Employment criteria. No person employed by an independent third party, including contractor and subcontractor personnel, who is involved in a specified activity performed by the independent third party under the provisions of this part, may be employed, currently or previously, by the regulated party for any duration 22 ------- within the 3 years preceding the date when the regulated party hired the independent third party to provide services under this part. MPC believes three years presents too large of a gap between working for a company and being able to work for an independent, third party contractor. Similarly, many of the tasks require specific knowledge. While MPC agrees there should be a set period of time, we would propose that one (1) year is sufficient. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] > TIC Council Americas Independent Inspectors and Laboratories provide an unbiased oversight to help the Industry comply with EPA Regulations. The Independent Laboratories have functioned for many years as the check system, educators and enforcers of EPA regulations. The removal of the Independent Laboratory designation requirement will place an additional burden on the Independent Laboratories as they will be subject to greater audit frequencies and requirements for a smaller portion of the workload under the premise of analytical requirements being divided across multiple laboratories rather than contracted entirely to a single designated laboratory over a given compliance cycle. As such, we request the reinstatement of the EPA registered Independent Laboratory designation for the EPA compliance testing. This reinstatement action will maintain data traceability and record keeping requirements, whereby ensuring a strong and enforceable quality control process with no budgetary impact on the EPA Program or cost to any parties involved. We can support a compromise that would maintain the requirement for testing by Registered Independent Laboratories but no longer require that the data be reported to the EPA. Instead, the labs would maintain the data and make it available to the EPA upon request. The advantage of this approach is that any problems would be detected up front allowing to maintain air quality requirements. Randomly surveying fuel after it has been distributed or spent may negatively affect air quality. In addition, we strongly believe that the Independent Laboratories provide critical guidance and expertise helping the Industry implement the proper procedures. • We recognize that the EPA's goal is to move toward a single program for all fuels. While the upfront testing and data retention would be unique to RFG, no data would be required to be reported to the EPA, which is similar to the other fuel streams. Subpart Comments: Subpart A - General Provisions 1. 1090.55 Requirements for Independent Parties a. Item (a)(1) Employment Criteria i. The restriction on 3rd party contractors involved in the attestation process to not have been employed by the regulated party within three (3) years of performing activities for the regulated 23 ------- party will prevent the movement of expertise within the production and inspection community. The pool of talent for the attestation process is limited and this provision will restrict the ability of the industry to improve expertise within their organizations [EPA-HQ-OAR-2018-0227-0039- A2, pp.1-2] > Turner, Mason & Company (TM&C) Subpart A - General Provision Independence EPA seeks comment on the 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 support the concern regarding the potential for conflict of interest between independent third parties and the regulated entities; however, prohibiting an independent contracting firm in its entirety from engaging in services for three years based solely on the requirement to "ensure that their employees, contractors, and subcontractors had not worked for the regulated party that hired third party for any amount of time over the previous three years" will create a gap in the availability of skilled, technical individuals allowed to engage as an independent contractor. We propose the agency consider reducing the requirements from three years to one year. [EPA-HO- OAR-2018-0227-0045-A1, p.2] > Weaver and Tidwell, L.L.P. We believe that the qualification requirements should be more direct and quantifiable, as is the case for other regulatory programs. [EPA-HQ-OAR-2018-0227-0079-A1, p.l] §1090.55 Requirements for independent parties. (b) Technical ability. (2) Laboratories attempting to qualify alternative procedures must contract with an independent third party to verify the accuracy and precision of measured values as specified in §1090.1365. Such independent third parties must demonstrate have a minimum of two years of full-time work experience in a petroleum laboratory work experience and have a good working knowledge of the voluntary consensus standards specified in §§1090.1365 and 1090.1370; further, have a, with training and expertise corresponding to a bachelor's degree in chemistry, chemical engineering, cal engineering, or combined bachelor's degrees in chemistry and statistics, mathematics, or other equivalent field of study. Response: We agree with commenters' concern that a three-year requirement between employment with a regulated party and an independent third party may not be necessary for independent parties' 24 ------- contractors. We have changed the regulations to reflect a one-year requirement, as commenters suggested. We also appreciate commenters' concerns about ensuring auditors have industry knowledge and their concerns about the general nature of the requirements on technical ability. However, we believe that the broad language is appropriate to ensure both competency and flexibility. We also note that a laboratory can meet the good working knowledge requirements by having multiple staff with a variety of educational backgrounds instead of having one person have all the expertise necessary to evaluate a new method. The laboratory could also contract or subcontract for expertise to meet the requirement. Therefore, we are not changing §1090.55 as suggested by some commenters. 25 ------- 4.4. Definitions Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 2.3 Definition of Non-Transportation Distillate Fuel ("NTDF") While the Associations realize it is beyond the scope of this rulemaking, we draw your attention to the inconsistency that exists between §80.1401 definitions and the NPRM. We suggest regulatory language changes below to rectify the inconsistency since a technical change is also needed to address the citation change from 40 CFR part 80, subpart I to 40 CFR part 1090, subpart D. [EPA-HQ-OAR-2018-0227-0074-A1, p.7] Certified non-transportation 15ppm distillate fuel or certified NTDF is defined as distillate fuel that meets all of the following: 1. It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics standard, and all applicable sampling, testing, and recordkeeping requirements of subpart I of this subpart D of 40 CFR part 1090. 2. It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non- transportation fuel (e.g., jet fuel, kerosene, heating oil, diesel for export only, or No. 4 fuel) on its product transfer document and has not been designated as MVNRLM diesel fuel. [EPA-HQ- OAR-2018-0227-0074-A1, p.7] > CITGO Petroleum Corporation (CITGO) Definition of NTDF in §80.1401. While CITGO realizes that comments associated with the Renewable Fuel Standard are beyond the scope of this rulemaking, we draw your attention to the inconsistency that exists for the definition of certified non-transportation 15 ppm distillate fuel ("certified NTDF") in §80.1401 and the preamble (Federal Register vol. 85, No. 25, page 7055-7056). In §80.1401, certified nontransportation 15 ppm distillate fuel or certified NTDF is defined as distillate fuel that meets all of the following: (1) It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics standard, and all applicable sampling, testing, and recordkeeping requirements of subpart I of this part. (2) It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other nontransportation fuel (e.g., jet fuel, kerosene, heating oil, or No. 4 fuel) on its product transfer document and has not been designated as MVNRLM diesel fuel. 26 ------- (3) The PTD for the distillate fuel meets the requirements in §80.1453(e). Whereas, certified NTDF in the preamble lists distillate fuel for export only as an example of "other non-transportation fuel." We feel that the listing of "heating oil" rather than "diesel for export only" within the examples presented in parenthesis in §80.1401 was in error during publication and recommend addressing this inconsistency since a technical change is also needed to address the citation change from 40 CFR part 80, subpart I to 40 CFR part 1090, subpart D as follows: §80.1401 certified non-transportation 15 ppm distillate fuel or certified NTDF is defined as distillate fuel that meets all of the following: (1) It has been certified as complying with the 15 ppm sulfur standard, cetane/aromatics standard, and all applicable sampling, testing, and recordkeeping requirements of subpart I subpart D of 40 CFR part 1090. (2) It has been designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non- transportation fuel (e.g., jet fuel, kerosene, heating oil, diesel for export only, or No. 4 fuel) on its product transfer document and has not been designated as MVNRLM diesel fuel. . [EPA-HQ- OAR-2018-0227-0054-A1, pp.5-6] Response: We have updated the cross reference in the definition of certified NTDF in §80.1401 to reference part 1090. We have also modified the structure of the definition of certified NTDF in §80.1401 to more clearly display the various elements of the definition. However, we did not modify the actual requirements for fuel to meet the definition of certified NTDF. While we have removed the redundant reference to "heating oil" in the definition, we did not add a reference to "diesel for export only," as this change is outside the scope of this rulemaking.1 Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.4 Definitions: Biodiesel In §1090.80 biodiesel is defined as a diesel fuel that contains at least 80 percent mono-alkyl esters made from nonpetroleum feedstocks. [EPA-HQ-OAR-2018-0227-0074-A1, p.13] The reasoning behind EPA's decision to define biodiesel as at least 80 percent mono-alkyl esters is unclear and has significant consequences for other fuel regulations, such as the renewable fuel standard. Under EPA's proposed definition, there is little direction on what constitutes the remaining "up to 20%" of biodiesel under this definition. Moreover, in ASTM D6751 the purity 1 Note that the certified NTDF provisions at 40 CFR 80.1408(c) specify that" [t]he provisions of this section do not apply to gasoline or diesel fuel that is designated for export." 27 ------- of biodiesel is typically 95-98%. Defining biodiesel as up to 80% could create confusion with products that are typically defined as a biodiesel blend. EPA's proposed definition of biodiesel also conflicts with EPA's definition in the Renewable Fuel Standards ("RFS"),7 congressional definitions of biodiesel established for retail labeling purposes,8 and for IRS purposes.9 [EPA- HQ-OAR-2018-0227-0074-A1, p.13] The Associations recommend that EPA define biodiesel as a mono-alkyl ester that meets ASTM D6751. [EPA-HQ-OAR-2018-0227-0074-A1, p.13] 7 See 40 C.F.R. §80.1401. "Biodiesel means a mono-alkyl ester that meets ASTM D 6751" 8 See 42 U.S.C. § 17021. "The term "biodiesel" means the monoalkyl esters of long chain fatty acids derived from plant or animal matter that meet: (A)the registration requirements for fuels and fuel additives under this section; and (B)the requirements of ASTM standard D6751." See 42 U.S.C. § 17021. 9 See 26 U.S.C. § 40A. The term "biodiesel" means the monoalkyl esters of long chain fatty acids derived from plant or animal matter which meet: (A)the registration requirements for fuels and fuel additives established by the Environmental Protection Agency under section 211 of the Clean Air Act (42 U.S.C. 7545), and (B)the requirements of the American Society of Testing and Materials D6751. See 26 U.S.C. § 40A. > CITGO Petroleum Corporation (CITGO) Definition of Biodiesel in §1090.80. In §1090.80, biodiesel is defined as a diesel fuel that contains at least 80 percent mono-alkyl esters made from nonpetroleum feedstocks. EPA's decision to define biodiesel as at least 80 percent mono-alkyl esters is unclear. Under EPA's proposed definition, there is no explanation for what constitutes the remaining "up to 20%". Additionally, in §1090.80 diesel is defined as: (1) Any fuel commonly or commercially known as diesel fuel. (2) Any fuel (including NP diesel fuel) that is intended or used to power a vehicle or engine that is designed to operate using diesel fuel, except for residual or gaseous fuel. (3) Any fuel that conforms to the specifications of ASTM D975 (incorporated by reference in § 1090.95) and is made available for use in a vehicle or engine designed to operate using diesel fuel. ASTM D975 includes blends up to B5. 28 ------- Furthermore, EPA's proposed definition of biodiesel does not align with EPA's definition in the Renewable Fuel Standards, whereby biodiesel is defined as "a mono-alkyl ester that meets ASTM D 6751 (incorporated by reference, see §80.1468)." It is recommended that that EPA define biodiesel as a mono-alkyl ester that meets ASTM D6751. [EPA-HQ-OAR-2018-0227-0054-A1, pp.4] > Marathon Petroleum Company LP (MPC) Definitions Biodiesel means a diesel fuel that contains at least 80 percent mono-alkyl esters made from nonpetroleum feedstocks. This definition of biodiesel is not consistent with ASTM D6751 which is -100% mono-alkyl esters. Because "biodiesel blend" is undefined, there is no clarification on what may comprise the remaining up to 20% of biodiesel under this definition. Ostensibly, the mixture of 80% mono- alkyl esters and anything but used motor oil would be considered biodiesel, which is considered diesel under a separate definition. MPC believes biodiesel should be defined as B99-B100. If a biodiesel blend is allowed, then this should be defined separately. Similarly, the allowable components in that mixture should be enumerated. Definitions Diesel fuel means any of the following: (1)Any fuel commonly or commercially known as diesel fuel. (2) Any fuel (including NP diesel fuel) that is intended or used to power a vehicle or engine that is designed to operate using diesel fuel, except for residual or gaseous fuel. (3) Any fuel that conforms to the specifications of ASTM D975 (incorporated by reference in §1090.95) and is made available for use in a vehicle or engine designed to operate using diesel fuel. Nonpetroleum (NP) diesel fuel means renewable diesel fuel or biodiesel. NP diesel fuel also includes other biomass-based diesel as specified under 40 CFR part 80, subpart M. These two definitions include biodiesel as diesel fuel. B80 and higher biodiesel blends are considered diesel here, but there is nothing about what the other 20 percent would be (presumably petroleum diesel?). B5 or less can be considered diesel by ASTM D975. Therefore, by this definition biodiesel blends between B5 and B80 would not be considered diesel. MPC's concern is that there is nothing included in the definition which details what comprises the remaining 20% of B80. Even if it does not meet ASTM D975, it will be called diesel. Furthermore, it is exempt from testing to ensure compliance with cetane index or aromatic 29 ------- content (preamble, p. 127). While the Preamble reference says no aromatics testing for biodiesel, 1090.1350 only exempts cetane index testing. Response: We do not believe that we should modify the definition of biodiesel in part 1090 to match the definition under the RFS program at §80.1401. The part 1090 and part 80 definitions of biodiesel serve different purposes. Under the RFS program, in order to generate RINs, renewable fuel producers must produce biodiesel that meets ASTM D6751. This specification was imposed to ensure that biodiesel for which RINs were generated was of a sufficient quality to be used as transportation fuel as required under the CAA. Under part 1090, consistent with part 80, biodiesel is subject to EPA's diesel fuel standards regardless of whether the biodiesel meets ASTM D6751 or RINs were generated for the fuel. However, we recognize the perceived confusion on the part of commenters, so we have made some revisions to the definitions of biodiesel, non-petroleum diesel, and diesel fuel to clarify that biodiesel is subject to the diesel fuel standards. Furthermore, as discussed in Section IX.C.2 of the preamble, we have added language to §1190.1350 to clearly exempt biodiesel that meets ASTM D6751 from aromatics/cetane index testing requirements. This will help ensure that only biodiesel that meets ASTM D6751 can be exempt from aromatics/cetane index testing and that parties do not create biodiesel blends as a mechanism to avoid the diesel fuel aromatics/cetane index standards. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.5 Definitions: Gasoline In §1090.80 Gasoline means any of the following: (i) Any fuel commonly or commercially known as gasoline, including BOB. (ii) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel. (iii) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in section 1090.95) and is made available for use in a vehicle or engine designed to operate on gasoline. In the preamble the agency proposes to exclude higher quality blendstocks that are not made available as gasoline but could meet ASTM D4814 specifications for gasoline, including but not limited to alkylates, toluene, reformate, hydrotreated cat gas, isooctane, and isooctene. The Associations support the approach that the EPA has laid out in the NPRM for the definition of gasoline. However, the Associations offer a clarification that would eliminate any ambiguity that could arise regarding higher quality blendstocks. [EPA-HQ-OAR-2018-0227-0074-A1, p.13] 30 ------- (iii) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in section 1090.95) and is made available to a retailer or wholesale purchaser-consumer for use in a vehicle or engine designed to operate on gasoline [EPA-HQ-OAR-2018-0227-0074-A1, p.13] This change would eliminate any ambiguity associated with blendstocks being bought or sold by refiners or blenders because the intent would be to blend blendstock with other gasoline or blendstocks before being distributed to a retailer or wholesale purchaser-consumer for use by the consumer. [EPA-HQ-OAR-2018-0227-0074-A1, p. 14] > Camin Cargo Control Subpart A - General Provisions 1. 1090.80 Definitions d. We suggest that clarification around any requirement to meet D4814 specifications to be considered a gasoline is necessary. While any fuel that does already conform to D4814 may be considered a gasoline, can (should) the product still be considered a gasoline if it does not meet all of the D4814 specifications? [EPA-HQ-OAR-2018-0227-0030-A1, p.2] > CITGO Petroleum Corporation (CITGO) Additionally, EPA proposes that fuel that is chemically and physically similar to gasoline be subject to EPA's gasoline fuel standard. As such, EPA proposes that fuel meeting ASTM D4814 is considered gasoline and thus subject to EPA's gasoline fuel standards. In general, CITGO supports EPA's proposal and approach to include fuel meeting ASTM D4814 and made available for use in a vehicle or engine designed to operate on gasoline in the definition of gasoline however, additional clarification may be needed to the definition of gasoline in §1090.80 to minimize the risk of interpretation that gasoline must meet ASTM D4814 specifications at all points in the production and distribution system. [EPA-HQ-OAR-2018- 0227-0054-Al.pp.6-7] > Eversheds Sutherland (US) LLP Definitions Eversheds Sutherland appreciates EPA's efforts to consolidate most definitions into one section for ease of reference. We did have concerns about the broad definition of gasoline EPA included in previous streamlining drafts, but in the Proposed Rule, EPA states that it understood the concern of encompassing certain blendstocks "that are not made available as gasoline but may otherwise meet the definition of gasoline by meeting ASTM D4814 specifications."3 We agree that the proposed regulatory language focuses the definition4 appropriately and would exclude a blendstock like alkylate that may meet the ASTM specification but is not intended for use in a vehicle or engine before further blending was conducted. Similarly, we agree with the use of the same qualifying language used in the definition of diesel. 31 ------- 3 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,041. 4 Proposed Rule at § 1090.80. > Marathon Petroleum Company LP (MPC) Definitions Gasoline means any of the following: (1) Any fuel commonly or commercially known as gasoline, including BOB. (2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel. (3) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in §1090.95) and is made available for use in a vehicle or engine designed to operate on gasoline. It should be noted certain gasoline blending components (alkylate, straight run cat gasoline, etc.) meet the D4814 standards by themselves. If the intent of the term "made available" is to mean it is sold from terminals into trucks destined for retail, then this should be clearly specified. Without such clarification, "made available" could be misinterpreted as including any commercial transaction from one manufacturer to another, or from a manufacturer to a blender, reseller, etc. Suggest revising to state "...is made available to a retailer for use in a gasoline-fueled vehicle or engine..." Note this concern about the inclusivity of the language was addressed on Page FR29041 of the Preamble, specifically in regards to the industry feedback that certain gasoline components can meet the D4814 criteria. However, there is no commercial desire to market them as finished products. MPC supports efforts to provide additional input to EPA as to how this language should be revised, as input is specifically requested on Page FR29041 of the preamble. [EPA- HQ-OAR-2018-0227-0048-A2, p.l] Response: A fundamental premise of our fuels compliance and enforcement system is that the definition of gasoline applies for what it is, not where it is. Thus, it would not be appropriate to add language limiting the definition of gasoline to that which is made available to a retailer for use in a gasoline-fueled vehicle or engine. We believe that imposing such a limitation on paragraph (3) of the definition of gasoline would potentially exclude volumes of gasoline distributed via pipelines or terminals that are subject to EPA fuel quality requirements under part 80, and will continue to be subject to fuel quality requirements under part 1090. Fuels distributed through pipelines and terminals have a significant effect on compliance at retail outlets, and by the time a retailer takes 32 ------- title or custody of the fuel, it may be too late to ensure fuel quality. Thus, we have designed both the part 80 and part 1090 programs to ensure that fuels meet applicable standards from the point where the fuel is certified to the point where it is dispensed from a retail outlet. We discuss the term "made available for use" in detail in Section III.D.3 of the preamble. Comment: > Renewable Fuels Association (RFA) Definition of Gasoline EPA's proposed rule provides a new definition for gasoline. The definition of gasoline is often discussed amongst the technical community and while the subject seems simple on the surface, the definition of the term for regulatory purposes is a very important topic. The current EPA definition of gasoline is satisfactory for regulatory purposes and the reasons for EPA proposing to modify the definition are unclear. We believe the new proposed definition could prove to be problematic. The new definition of gasoline being proposed includes a requirement that the fuel meet ASTM D4814 Standard Specification for Automotive Spark-Ignition Engine Fuel. RFA has actively participated in the ASTM process to develop and refine fuel performance specifications for over 30 years. ASTM is a voluntary consensus standards body and can take years to reach consensus for updates to standard specifications. For example, El 5 was approved for use by the EPA in 2011 but ASTM deliberated for over 5 years before finally completing updates that included El 5 within the standard. We feel EPA should remove this ASTM requirement to avoid any delays or roadblocks for commercial introduction of future fuels. Response: The changes for the definition of gasoline in part 1090 are explained in Section III.D.3 of the preamble and elsewhere in this section. Our inclusion of the ASTM specifications is intended to capture fuels that are physically and chemically gasoline. We are not requiring that fuel meet the ASTM specifications in order to be gasoline; instead we are defining fuels that meet those specifications to be gasoline if they are made available for use in a vehicle or engine designed to operate on gasoline. The commenter provided no other suggestions for alternative formulations that would capture a fuel with physical and chemical characteristics of gasoline that avoids the use of ASTM D4814. Additionally, in including ASTM D4814, we do not intend to limit the ethanol concentration of the fuel. We are therefore finalizing the third prong of the gasoline definition which refers to ASTM D4814. 33 ------- Comment: > Renewable Fuels Association (RFA) Definition of Gasoline Also, this definition does not provide clarity regarding the regulation of mid-level ethanol blends (El6 - E50). It is unclear how EPA could or would regulate these blends or whether these blends are being included in definition and regulated as gasoline. [EPA-HQ-OAR-2018-0227-0037-A1, pp.1-2] > Urban Air Initiative 2. Urban Air Initiative objects to the current interpretation of the definition of gasoline The proposed rule's definition of gasoline also recodifies and therefore reopens EPA's current definition of gasoline for comment. This current definition of gasoline includes any fuel "commonly or commercially known" as gasoline. EPA has asserted that this definition of gasoline would include mid-level ethanol blends like E20 or E30 as gasoline. This interpretation is arbitrary and inconsistent with commercial usage. Mid-level blends are not commonly or commercially sold as gasoline. They are instead sold as an alternative "flex fuel." The final rule must clarify that mid-level blends are not commonly or commercially sold as gasoline. [EPA- HQ-OAR-2018-0227-0071-A1, p.6] II. THE PROPOSED RULE'S DEFINITION OF GASOLINE REOPENS EPA'S ERRONEOUS ASSERTION THAT MID-LEVEL BLENDS ARE "COMMONLY OR COMMERCIALLY KNOWN OR SOLD AS GASOLINE." Where an agency "has opened [an] issue up anew, even though not explicitly, its renewed adherence is substantively reviewable."66 The proposed rule reopens EPA's interpretation of the current definition of "gasoline," because it promulgates a new definition of gasoline that "is consistent with the existing parts 79 and part 80 definitions of gasoline," and that would arry forward EPA's interpretive gloss on those terms to the new streamlined fuel quality rules for gasoline. [EPA-HQ-OAR-2018-0227-0071-A1, pp.16-17] EPA has previously asserted that mid-level blends are "commonly or commercially known or sold" as gasoline because " [i]n the fuel and fuel additive registration program, the gasoline family includes fuels composed of at least 50 percent clear gasoline by volume. "67 This legal conclusion was based on a non sequitur, and the conclusion has always been wrong. [EPA-HQ- OAR-2018-0227-0071-A1, p.17] First, EPA's legal conclusion was based on a non sequitur. In particular, EPA's reliance on this "fuel family" definition is badly misplaced. EPA's rules unambiguously provide that the fuel family definitions apply only to "subpart F of this part"—the registration group testing protocols of part 79, subpart F of Title 40.68 The "fuel family" definition, therefore, does not in any way govern what fuels are "commonly or commercially known or sold" as gasoline for purposes of 34 ------- the fuel quality (part 80) requirements of Title 40. Nor are these "fuel family" definitions responsive to the relevant question under EPA's regulations: whether mid-level blends are "commonly or commercially known or sold" as gasoline. EPA's illogical leap from the "fuel family" definition of gasoline to the assertion that mid-level blends are regulated as gasoline was thus a non sequitur. [EPA-HQ-OAR-2018-0227-0071-A1, p.17] Second, the legal conclusion was wrong. To assess whether a fuel is "commonly or commercially known or sold as gasoline," courts use "objective standards."69 For example, consensus-based industry standards like ASTM's gasoline standards are "useful to the court as an aid in determining whether a particular product is ' commonly or commercially known or sold as gasoline.' "70 [EPA-HQ-OAR-2018-0227-0071-A1, p.17] ASTM's D4814 standards for gasoline make no provision for gasoline-ethanol blends with more than 15% ethanol.71 ASTM instead addresses mid-level blends through a separate "standard practice" for "midlevel ethanol blends"—ASTM D7794.72 ASTM D7794 provides that these fuels "are sometimes referred to at retail as 'Ethanol Flex Fuel'" and "are only suitable for use in ground flexible-fuel vehicles equipped with spark-ignition engines."73 ASTM standards, therefore, contradict EPA's assertion that mid-level blends are "commonly or commercially known or sold" as gasoline. It shows instead that they are commonly and commercially known and sold as an alternative ethanol "flex-fuel" for use in flex-fuel vehicles only. [EPA-HQ-OAR- 2018-0227-0071-A1, p.17] Confirming this view, mid-level blends are labeled as alternative "ethanol flex fuel" by retailers under the Federal Trade Commission's pump labeling rules, not as gasoline.74 These rules require fuel retailers who sell mid-level blends to include a prominent label displaying the fuel's ethanol content and warning consumers: "Use Only In Flex-Fuel Vehicles. May Harm Other Engines."75 [EPA-HQ-OAR-2018-0227-0071-Al,p.l8] The objective evidence thus demonstrates that mid-level blends are not known or sold as gasoline, and EPA's assertion to the contrary is both unlawful and arbitrary and capricious. In the final rule, EPA should clarify that mid-level blends are not "commonly or commercially known or sold" as gasoline. Even if there is some ambiguity, as EPA acknowledged in the REGS rule,76 at a minimum, EPA must disavow its prior, illogical interpretation of that phrase, which is completely untethered to actual commercial usage. [EPA-HQ-OAR-2018-0227-0071-A1, P-18] 66 CTIA-Wireless Ass'n v. FCC, 466 F.3d 105, 110 (D.C. Cir. 2006) (citation omitted) 67 Tier 3 Rule, supra note 24, 79 Fed. Reg. at 23,558. 68 40 C.F.R. § 79.50. 69 United States v. Coastal Ref. & Mktg., Inc., 911 F.2d 1036, 1039 (5th Cir. 1990). 70 Id. 35 ------- 71 See ASTM D4814 -16e, Table 1, n.d. 72 ASTM D7794-18a. 73 Id. 74 16 C.F.R. § 306.0(o) ("Ethanol flex fuels means a mixture of gasoline and ethanol containing more than 10 percent but not greater than 83 percent ethanol by volume."). E15's labeling requirements are governed by EPA rules, not FTC rules. See Complying with the FTC Fuel Rating Rule, Fed. Trade Comm'n (Oct. 2016), https://www.ftc.gov/tips-advice/business-center/guidance/complying-ftc-fuel-rating-rule ("You do not need to post a label for ethanol flex fuels containing no more than 15% ethanol if you have labeled the dispenser in accordance with the EPA's E15 labeling requirements at 40 CFR 80.1501."). 75 16 C.F.R. § 306.12(a)(4)(H), (f). 76 Proposed REGS Rule, supra note 13, 81 Fed. Reg. at 80,844. Response: In this action we are not changing the fundamental aspect of our gasoline regulations that they apply to a fuel that is predominantly gasoline.2 Therefore, as was the case prior to the implementation of this action, "mid-level blends" (i.e., E16-50) remain gasoline under part 1090. One commenter suggested that this action reopens our interpretation of gasoline as encompassing gasoline ethanol blends containing up to 50 percent ethanol. We are not reopening this aspect of our definition of gasoline. Notably, our definition of gasoline in part 1090 contains three elements, the first of which is unchanged from part 80 and with which the commenters' take issue. As such, this action does not change the treatment of gasoline-ethanol blends containing less than 50 percent ethanol as gasoline. Contrary to the commenter's position, gasoline-ethanol blends like E20 and E30 are commonly and commercially known as gasoline because they are predominantly gasoline. The commenter suggested that gasoline ethanol blends up to 50 percent ethanol are not properly treated as gasoline and that the part 79 regulations cannot inform part 80 or part 1090 definitions of gasoline. We do not find this argument compelling, and notably, the commenter stated in other parts of their comment that EPA must act consistent with part 79 definitions (see Section 6 of this document). Gasoline-ethanol blends containing less than 50 percent ethanol are predominately gasoline, and therefore subject to EPA's gasoline regulations. EPA retains discretion in interpreting its own regulations, and thus the commenter's suggestion that, for example, the ASTM definition of gasoline must control what is "gasoline" for EPA's fuel quality regulations is incorrect. We are free to define the scope of our regulations separate and apart from how a non-governmental organization defines gasoline. The commenter also pointed to FTC's definition of ethanol flex fuels as evidence that mid-level blends are not treated as gasoline. FTC's definition of ethanol flex fuels include gasoline-ethanol blends containing 2 See 79 FR 23414 at 23557-8 (April 28, 2014). 36 ------- more than 10 percent ethanol and would thus encompass El5. We do not find FTC's definitions illustrative or controlling as to how EPA regulates fuel quality. We continue to maintain that fuel "commonly and commercially known as gasoline" includes gasoline ethanol blends of up to 49 percent ethanol. Comment: > Urban Air Initiative 1. Urban Air Initiative objects to the new definition of gasoline The proposed rule "focuses primarily on streamlining and consolidating" the Clean Air Act's gasoline and diesel fuel quality regulations. 1 But while sailing under the flag of a deregulatory action, the proposed rule would significantly expand the reach of the gasoline regulations and impose enormous compliance burdens on an important segment of the industry. [EPA-HQ-OAR- 2018-0227-0071-A1, p.5] The proposed rule would do so through an expansive new definition of gasoline.2 Under the proposal, "gasoline" would, for the first time, include" [a]ny fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel."3 On its face, that definition would include alternative flex fuels that have never been regulated as gasoline, including E85. E85 is "used to power" flex-fuel vehicles, which are "designed to operate on gasoline." Under the only reasonable interpretation of the proposed definition of gasoline, thus, E85 or other flex fuels would be "gasoline," and subject to extensive compliance burdens that are ill-suited for these fuels. [EPA-HQ-OAR-2018-0227-0071-A1, p.5] This regulatory expansion is not only costly; it is also unlawful, for at least three reasons: First. The proposed rule would subject E85 and other alternative flex fuels that have never previously been regulated to the controls applicable to gasoline, without making any of the administrative findings or following any of the legal procedures required by the Clean Air Act. That procedural evasion is illegal. [EPA-HQ-OAR-2018-0227-0071-A1, p.5] Second. The proposed rule fails to even acknowledge the change in policy or consider the significant industry reliance interests that would be overturned by treating flex fuels as gasoline. [EPA-HQ-OAR-2018-0227-0071-A1, p.5] Third. The proposed rule violates the Regulatory Flexibility Act because EPA's certification that the proposed rule will not harm small businesses is conclusory and does not take into account the effects that EPA's expansive definition of gasoline will have on small businesses. [EPA-HQ- OAR-2018-0227-0071-A1, p.5] Apart from being unlawful, the proposed rule contravenes Executive Order 13,771. The expansive definition of gasoline would impose significant burdens on an industry that has never 37 ------- been regulated. That makes this action regulatory under Executive Order 13,771. [EPA-HQ- OAR-2018-0227-0071-A1, p.5] I. THE PROPOSED RULE'S DEFINITION OF GASOLINE IS CONTRARY TO LAW AND ARBITRARY AND CAPRICIOUS. A. The proposed rule's definition of gasoline is unlawful because it would control E85 and other fuels as "gasoline" without complying with the statutory requirements of § 211 (c). The Fuels Regulatory Streamlining proposed rule "includes a new definition of gasoline. "37 [EPA-HQ-OAR-2018-0227-0071-A1, p. 12] The proposed definition of gasoline includes: "(1) Any fuel commonly or commercially known as gasoline, including BOB. " (2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel. "(3) Any fuel that conforms to the specifications of ASTM D4814 (incorporated by reference in § 1090.95) and is made available for use in a vehicle or engine designed to operate on gasoline."38 [EPA-HQ-OAR-2018-0227-0071-A1, p.12] Paragraph 1 of the new definition "is consistent with the existing parts 79 and part 80 definitions of gasoline. "39 [EPA-HQ-OAR-2018-0227-0071-A1, p.12] Paragraph 2 expands the definition of gasoline to any fuel "made available for use or used in a gasoline-fueled vehicle or engine."40 EPA reasons that" [s]ince the ultimate purpose of our fuel standards is to ensure that compliant fuel is used in vehicles and engines, ... if [a] product is used in a gasoline-fueled vehicle or engine, the product should be subject to EPA standards."41 [EPA-HQ-OAR-2018-0227-0071-A1, p.12] Paragraph 3 aims to capture "fuel[s] that [are] chemically and physically similar to gasoline."42 [EPA-HQ-OAR-2018-0227-0071-A1, p.12] The proposed definition of gasoline is overbroad. In particular, paragraph 2 of the proposed definition of gasoline would include alternative fuels like E85 or mid-level blends that have never been treated as "gasoline." Under that paragraph, " [a]ny fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel" would be considered "gasoline."43 But ethanol flex-fuel vehicles are "designed to operate on gasoline."44 Thus, E85 would be treated as "gasoline" under the proposed definition, even though the fuel is sold exclusively for use in flex-fuel vehicles and has never been treated as gasoline. [EPA-HQ-OAR- 2018-0227-0071-A1, pp.12-13] 38 ------- EPA lacks authority to make such a sweeping change in the regulatory treatment of E85 or mid- level blends without first making the findings and following the procedures required by the Clean Air Act. Under the Clean Air Act, EPA may regulate a fuel under section 211 (c) only (A) "if, in the judgment of the Administrator, [the] fuel or ... or any emission product of such fuel . . . causes, or contributes to, air pollution or water pollution (including any degradation in the quality of groundwater) that may reasonably be anticipated to endanger the public health or welfare, or (B) if emission products of such fuel. . . will impair to a significant degree the performance of any emission control device or system[.]"45 [EPA-HQ-OAR-2018-0227-0071-A1, p.13] EPA has made no such findings for E85, mid-level blends, or other alternative fuels used in flex- fuel vehicles in the proposed rule. EPA may not avoid its obligation to make these findings by simply recategorizing these fuels as gasoline. [EPA-HQ-OAR-2018-0227-0071-A1, p.13] Moreover, EPA may not control fuels that endanger public health or welfare "except after consideration of all relevant medical and scientific evidence available to [EPA], including consideration of other technologically or economically feasible means of achieving emission standards under [section 202],"46 Similarly, EPA may not control fuels that impair emission control systems "except after consideration of available scientific and economic data, including a cost-benefit analysis."47 EPA has not considered any of this evidence in the proposed rule. [EPA-HQ-OAR-2018-0227-0071-A1, p. 13] EPA should fix the illegal proposed rule by striking paragraph 2 from the proposed definition of gasoline. Alternatively, EPA should amend the text of the proposed rule as follows: " (2) Any fuel intended or used to power a vehicle or engine designed to operate solely on gasoline, except for gaseous fuel." [EPA-HQ-OAR-2018-0227-0071-A1, p.13] This modification would exclude fuels like E85 sold for use in flex-fuel vehicles, correcting this illegal proposal. [EPA-HQ-OAR-2018-0227-0071-A1, p.14] B. The proposed rule's definition of gasoline is arbitrary and capricious because it fails to consider important reliance interests. The proposed definition of gasoline is also arbitrary and capricious because the proposed rule fails to consider important reliance interests or acknowledge that the proposed definition of gasoline would subject E85 or mid-level blends to new, burdensome regulation. When an agency departs from its own precedent, the agency must "at least 'display awareness that it is changing position,' " provide "good reasons for the new policy," and take into account any "serious reliance interests" affected by the change in agency policy.48 As the Supreme Court recently held, when an agency is "not writing on a blank slate, it [is] required to assess whether there were reliance interests, determine whether they were significant, and weigh any such interests against competing policy concerns."49 [EPA-HQ-OAR-2018-0227-0071-A1, p.14] 39 ------- The proposed rule does not meet this basic standard. E85 has never been regulated under § 211 (c). Nor is regulation necessary: E85 made with previously certified gasoline and denatured fuel ethanol yields a quality fuel product that ensures low vehicle emissions and does no harm to emission controls. And under EPA's interpretation of the sub-sim law, it appears that the use of uncertified natural gasoline is already unlawful. [EPA-HQ-OAR-2018-0227-0071-A1, p.14] Ethanol plants, terminal blenders, and fuel retailers have made significant investments in E85 infrastructure, relying on this light-touch regulatory treatment of E85.50 But the proposal would now subject E85 fuel manufacturers to significant compliance burdens for crude oil refiners, without acknowledging any change in agency policy or the effect of the new policy on the longstanding and important reliance interests of E85 fuel manufacturers. It would also impose novel regulatory burdens on the approximately 5,000 fuel retailers who sell E85.51 Failure to "consider[] those matters" is arbitrary and capricious.52 [EPA-HQ-OAR-2018-0227-0071-A1, P-14] Similarly, despite EPA's erroneous statements to the contrary, mid-level blends have never been regulated as gasoline. Treating such blends as regulated gasoline would make it impossible for retailers to lawfully continue the practice of selling mid-level blends using blender pumps, which EPA specifically approved as legal under the Clean Air Act.53 Thus, the proposed rule would overturn the significant reliance interests of fuel retailers who sell these blends.54 By subjecting hundreds or thousands of small fuel retailers who sell mid-level blends to the same compliance rules as crude oil refiners, while failing to acknowledge their "serious reliance interests" or any change in Agency policy, the proposed rule is arbitrary and capricious.55 [EPA-HQ-OAR-2018- 0227-0071-A1, pp.14-15] To avoid finalizing an arbitrary and capricious rule, EPA must narrow its proposed definition of gasoline or publish a supplemental notice of proposed rulemaking explaining the Agency's reasons for departing from prior policy and the strong reliance interests. [EPA-HQ-OAR-2018- 0227-0071-A1, p.15] 1 Proposed Rule, 85 Fed. Reg. 29,034, 29,035 (May 14, 2020). 2 See id. Fed. Reg. at 29,040-41, 29,101. 3 Id. at 29,101. 37 85 Fed. Reg. at 29,040. 38 Id. at 29,101 (to be codified at 40 C.F.R. § 1090.80). 39 Id. at 29,040. 40 Id. 41 Id. 40 ------- 42 Id. 43 Id. at 29,101. 44 40 C.F.R. § 86.1803 01 (defining "flexible fuel vehicle" as a "motor vehicle engineered and designed to be operated on a petroleum fuel and on a[n] . . . ethanol fuel, or any mixture of the petroleum fuel and . . . ethanol"). 45 42 U.S.C. § 7545(c)(1). 46 Id. § 7545(c)(2)(A). 47 Id. §7545(c)(2)(B). 48 Encino Motorcars, LLC v. Navarro, 136 S. Ct. 2117, 2126 (2016) (quoting FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)). 49 Dep't of Homeland Sec. v. Regents of the Univ. of California, No. 18-587, 2020 WL 3271746, at *15 (U.S. June 18, 2020) (quotation marks and citation omitted). 50 See, e.g., supra note 17. 51 Ken Colombini, Flex Fuel Spreads Its Reach, as Casey's Becomes 5,000th Station to Offer E85 (Mar. 23, 2020), https://ethanolrfa.Org/2020/03/flex-fuel-spreads-its-reach-as-caseys-becomes-5000th-station-to-offer-e85//. 52 Regents, 2020 WL 3271746, at *15. 53 Proposed REGS Rule, supra note 13, 81 Fed. Reg. at 80,847. 54 While the number of fuel retailers who sell these blends nationwide is unclear, retailer data gathered by Minnesota's Commerce Department shows 284 fuel retail stations report selling significant amounts of E20, E30, E40, and E50 in Minnesota. 2019 Minnesota E85 + Mid-blends Station Report, https://mn.gov/commerce- stat/pdfs/e85-fuel-use-2019.pdf. Other states across the Midwest are likely to experience similar sales. 55 Encino Motorcars, 136 S. Ct. at 2126. Response: To the extent the commenter highlighted an alternative reading of our proposed definition of gasoline that would encompass E85, we did not propose to impose gasoline standards on E85. We have made modifications to the definition of E85 to further indicate that is it not gasoline. The commenter suggested that the definition of gasoline will also impose new burdens on "mid- level blends" without defining what the commenter means by "mid-level blends." We presume that the commenter is referring to gasoline-ethanol blends containing 50-83 percent ethanol, as commenters acknowledged EPA's longstanding treatment of gasoline-ethanol blends containing less than 50 percent ethanol as gasoline, which we did not propose to change. Gasoline-ethanol blends containing more than 50 percent ethanol are E85 and not gasoline. 41 ------- Comment: > Growth Energy First, in section 1090.80, the definition of gasoline appears to be too broad, particularly: (2) Any fuel intended or used to power a vehicle or engine designed to operate on gasoline. While we do not believe this is the intent, as written, the definition could inadvertently impose gasoline regulations on all ethanol blends beyond El5 including E85. We would urge the agency to clarify its definition to specify that the gasoline requirements do not extend beyond fuel with 15 percent ethanol. [EPA-HQ-OAR-2018-0227-0053-A1, p.l] > National Corn Growers Association (NCGA) The proposed rule includes changes to the definition of gasoline. While perhaps unintentional, EPA's proposed definition appears to add E85 to the definition of gasoline, which would subject E85 to regulations designed for gasoline. By including, "Any fuel intended or used to power a vehicle or engine designed to operate on gasoline, except for gaseous fuel," this definition could include E85 used in flex-fuel vehicles and engines, which are designed to operate on gasoline as well as E85. 1 This change in definition could also impact mid-level ethanol blends used in flex- fuel vehicles. We ask EPA to clarify this proposed definition of gasoline to ensure fuel sold for use in flex-fuel vehicles such as E85 is not defined as gasoline and, therefore, not unnecessarily subject to gasoline regulations. [EPA-HQ-OAR-2018-0227-0072-A1, pp.1-2] 1 85 Federal Register at 29101, May 14, 2020. Response: As discussed in the previous response, we did not propose to impose gasoline standards on E85. To the extent there was ambiguity in the proposed definition of E85, we have added a statement to the definition that makes it clear that E85 is not gasoline and therefore not subject to gasoline standards under part 1090. Comment: > bp America Inc. (bp) Subpart A—General Provisions Definition of fuel manufacturing facility gate §1090.80. There is a new definition for "fuel manufacturing facility gate" which is included in §1090.80 and states "Fuel manufacturing facility gate means the point where the fuel leaves the 42 ------- fuel manufacturing facility at which it was produced or imported by the fuel manufacturer." There are instances where a fuel manufacturing facility has a terminal connected to the facility that it may own or where it leases tankage. Those terminals can be used to conduct operations that normally occur at a refinery such as combining blendstocks or designating the fuel as domestic or export. Those tanks are within the control of the refiner and are often used because of limited tank capacity at the refinery itself, bp believes that adjacent terminals used for these types of purposes should be considered to be within the fuel manufacturing facility gate for purposes of 40 CFR parts 80 and 1090. bp believes that including a clarification to this effect in the preamble would adequately address these types of situations. bp recommends that EPA assure the final regulations reflect a consistent and accurate use of the terms defined in Subpart A to prevent confusion and provide clarity to the regulations. For example, bp provided comments and suggested edits to the deficit carryforward provisions in Subpart H to clarify the applicability of those requirements to fuel manufacturing facilities rather than gasoline manufacturers. It will be important for the agency to provide similar clarifications throughout the rule to assure the final version accurately reflects EPA's intent and provides clarity for regulated parties. [EPA-HQ-OAR-2018-0227-0046-A1, p.2] > CITGO Petroleum Corporation (CITGO) Definition of Facility in §1090.80. In §1090.80, a facility is defined as "any place or series of places where any fuel, fuel additive, or regulated blendstock is produced, imported, blended, transported, distributed, stored or sold." CITGO supports EPA's decision to retain a series of places to comprise a facility such as, a fuel manufacturing facility. With the removal of the aggregation terminology of 80.502(b) (1) through (b)(4), this should allow a fuel manufacturer to consider a vessel, tankage, or distribution equipment within the refiner's control as part of its "series of places". [EPA-HQ-OAR-2018- 0227-0054-A1, p.5] Response: We have modified the definition of fuel manufacturing facility gate to clarify that the fuel manufacturing facility gate is the point where the fuel leaves the fuel manufacturing facility at which the fuel manufacturer certified the fuel. We believe this change, coupled with the definition of facility, allows fuel manufacturers the flexibility to certify batches of fuels in many different facility configurations, including cases where the fuel manufacturer operates an adjacent terminal. To clarify under what conditions a fuel manufacturer may certify batches, we have also added language at §1090.1000(a) (5) that requires the fuel manufacturer to certify each batch of fuel at the facility where they produced the fuel or at a facility that is under the complete control of the fuel manufacturer before they transfer title or sole custody of the fuel to any other person. 43 ------- Comment: > Camin Cargo Control Subpart A - General Provisions 1. 1090.80 Definitions a. We believe Part 1090 requires either a definition for Representative Sample or a reference to "ASTM D4057 3.2.7 representative sample, n—portion extracted from a total volume that contains the constituents in the same proportions that are present in that total volume" to stay in- line with the terminology used by the Petroleum Industry as defined by API/ASTM and avoid conflicts with the Rule's definition on 1090.1805. It is extremely important to clarify the distinction between a representative sample as per petroleum industry standards and a statistically representative sample as we believe the context to suggest in 1090.1805. For example 'representative sample' in 1090.505, 1090.1345 and other paragraphs relate to the quality / contents of the liquid, not to the statistical sampling value as implied in 1090.1415, 1090.1805. [EPA-HQ-OAR-2018-0227-0030-A1, p.2] > TIC Council Americas 2. 1090.80 Definitions We believe the document requires either a definition for Representative Sample or a reference to "ASTM D4057 3.2.7 representative sample, n—portion extracted from a total volume that contains the constituents in the same proportions that are present in that total volume" to avoid conflicts with the 3rd edition Draft definition on 1090.1805. For example, 'representative sample' in 1090.1345, 190.1410 and other paragraphs are related to the quality / contents of the liquid not to the statistical sampling value as implied in 1090.1805 [EPA-HQ-OAR-2018-0227-0039-A2, p.2] Response: We have made clarifying edits to the regulations to address the commenters' concerns. However, we do not believe that a definition of representative sample is necessary in light of the clarifying edits we have made regarding representative samples of fuels and statistical samples from the population of retail outlets. 44 ------- Comment: > Camin Cargo Control Subpart A - General Provisions 1. 1090.80 Definitions c. We request the addition of a definition for "Independent Laboratories" Response: We do not think that a definition of independent laboratories is necessary. Under part 1090, as discussed in Section X.B of the preamble, we are not requiring that fuel manufacturers have independent laboratories perform sampling and testing. A definition for "independent laboratories" would only have been necessary if we required independent lab testing or the registration of independent labs. Comment: > CITGO Petroleum Corporation (CITGO) Definition of Batch in §1090.80. In §1090.80, a batch is defined as "a quantity of fuel, fuel additive, or regulated blendstock that has a homogeneous set of properties." However, §1090.1335(b) (4) provides cases where the homogeneity testing requirement does not apply such as when each sample is tested for every parameter subject to a testing requirement and the worse-case test result for each parameter is used for the purposes of reporting, meeting per-gallon and average standards, and all other aspects of compliance. It is recommended that the definition be revised as follows: A batch is defined as a quantity of fuel, fuel additive, or regulated blendstock that has a homogeneous set of properties or analysis and compliance determination is based on §1090.1335(b)(4). [EPA-HQ-OAR-2018-0227-0054-A1, pp.4] Response: We have changed the definition of batch to reflect the alternative compliance determination and updated the referenced language in the final regulations accordingly. 45 ------- Comment: > CITGO Petroleum Corporation (CITGO) Definition of Blendstock in §1090.80. In §1090.80, blendstock is defined as "any liquid compound or mixture of compounds (not including fuels or fuel additives) that is used or intended for use as a component of a fuel." CITGO supports EPA's decision to allow a mixture of compounds not meeting fuel or fuel additive standards to be distributed as a blendstock for use as a component of a fuel. This would allow off-spec product that does not meet per-gallon standards or blended products that will be further blended or processed by another party to be distributed to another refiner for use as a component of a fuel and included in the receiving refiner's compliance calculations. [EPA-HQ- OAR-2018-0227-0054-A1, pp.5] Response: We thank the commenter for their support. Comment: > CITGO Petroleum Corporation (CITGO) 2.2 Definition and Designation of Suboctane Gasoline. In §1090.1110, gasoline manufacturers must designate each batch of gasoline as one of the following fuel types: (1) Winter RFG or RBOB (2) Summer RFG or RBOB (3) Winter CG or CBOB (4) Summer CG or CBOB (5) Exempt gasoline under subpart G of this part (including additional identifying information) (6) California gasoline In §1090.80, Conventional Gasoline (CG) is defined as "gasoline that is not certified to meet the requirements for RFG in §1090.245" and CBOB is defined as "conventional gasoline for which a gasoline manufacturer has accounted for the effects of oxygenate blending that occurs downstream of the fuel manufacturing facility." Clarity is needed to eliminate any ambiguity 46 ------- associated with a suboctane conventional gasoline that is intended for blending with higher octane gasoline downstream to produce a finished gasoline with a specific octane rating. This is easily achievable through the specific inclusion of suboctane gasoline in the definition of "Gasoline". This would clarify that suboctane conventional can be tested as an EO Conventional gasoline that the manufacturer is not claiming the dilution effect on and reported on the RFG030X Gasoline and Gasoline Blendstock Batch Summary Report as a 'CG' Conventional product type, not to be confused with a "CU' CBOB not including oxygenate product type. . [EPA-HQ-OAR-2018-0227-0054-Al.pp.6-7] Response: We believe that, in the scenario the commenter presents, the suboctane conventional gasoline would appropriately be designated as conventional gasoline and reported as such to EPA under part 1090. However, we do not believe that it is necessary to include "suboctane gasoline" in the definition of gasoline, as such a product already meets the definition of gasoline and we do not regulate the octane of gasoline. Comment: > Eversheds Sutherland (US) LLP Definitions In definitions referring to Category 3 vessels, we suggest that EPA consistently use the full term or "C3."7 [EPA-HQ-OAR-2018-0227-0076-A1, p.3] 7 See id. (using the term C3 in the definition for "ECA marine fuel" and the term Category 3 in the definition of "Global marine fuel"). Response: We have revised the definition of Category 3 marine vessels to reflect that "Category 3" and "C3" are used interchangeably in part 1090. Comment: > Eversheds Sutherland (US) LLP Marine Fuel The Proposed Rule defines "global marine fuel" as diesel, distillate or residual fuel subject to MARPOL Annex VI (5000 ppm sulfur) and for use outside an ECA. EPA has dropped the qualifier "distillate" global marine fuel used in the Part 80 definition, although the exemption from fuel manufacturer requirements19 and standards generally20 in Part 1090 uses the term 47 ------- "distillate global marine fuel." Additionally, the designation and redesignation,21 PTDs,22and recordkeeping23 requirements are for "distillate global marine fuel." It appears that EPA is excluding global marine fuel that is produced using residual fuel, but EPA does not provide an explanation. Eversheds Sutherland believes that global marine fuel made with residual fuel should not be considered to be "distillate global marine fuel." [EPA-HQ-OAR-2018-0227-0076- Al, pp.7-8] 20 Id. at § 1090.650. 21 Id. at § 1090.1115. 22 Id. at § 1090.1165 23 Id. at § 1090.1215. Response: We have revised the definition of global marine fuel to address the issue raised by the commenter to make it clear that the part 1090 requirements apply to distillate global marine fuel consistent with the part 80 definition. Comment: > Independent Fuel Terminal Operators Association (IFTOA) IV. Transmix The Association supports the proposed definition of "transmix" under § 1090.80, which makes clear that the streamlined provisions that apply to transmix include production of gasoline or diesel fuel using mixtures of fuels produced from normal business operations at both pipelines and terminals. This inclusion will allow terminals to use a lower cost blending component when producing gasoline and diesel, thereby avoiding costly reprocessing operations. [EPA-HQ-OAR- 2018-0227-0064-A1, p.3] In addition, the Association supports proposed revisions to the compliance provisions for transmix blenders, including: (a) establishing that the only difference between the streamlined provisions for producing RFG and CG from transmix is volatility; (b) excluding the volume of transmix and PCG used to produce gasoline from a transmix blender's annual compliance calculations for the sulfur and benzene average standards; and (c) reducing restrictions on blending pipeline interface into adjacent shipments of either RFG or CG. [EPA-HQ-OAR-2018- 0227-0064-A1, p.3] > Magellan Midstream Partners §1090.80 Definition of Transmix 48 ------- We encourage EPA to add language to the definition of transmix similar to that which is contained in 80.84 to include blendstocks suitable for blending into gasoline without further processing. We also believe renewable fuels should be added to this definition. Otherwise, a substantial percentage of interface product resulting from normal pipeline operations will not fit within the definition of transmix. We suggest the following change to the definition of transmix: " Transmix means any of the following mixtures of fuels, blendstocks. or renewable fuels, which no longer meet the specifications for a fuel that can be used or sold as a fuel without further procession:" [EPA-HQ-OAR-2018-0227-0078-A1, p.2] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Transmix The Associations endorse EPA for expanding the definition of transmix. As proposed, the Agency will provide the industry with a lower cost blending component for gasoline, leading to reduced costs to consumers while also avoiding costly reprocessing operations.9 [EPA-HQ- OAR-2018-0227-0066-A1, p.5] 9 Proposal, supra note 1 at 29078-29080 (§§ 1090.145, 1090.150, 1090.500 et seq.). Response: We thank the commenters for their support. Comment: > Weaver and Tidwell, L.L.P. Can EPA please clarify in the preamble of the final rule what "made available for use" means relative to the definition of ECA fuels?[EPA-HQ-OAR-2018-0227-0079-A1, p.l] Is it that any fuel being made available for use as ECA fuel, regardless whether it is called MDO or MGO, blendstock or light cycle oil, if it is being sent off for ECA use do you have to call it ECA fuel? [EPA-HQ-OAR-2018-0227-0079-A1, p.2] §1090.80 Definitions. ECA marine fuel means diesel, distillate, or residual fuel used, intended for use, or made available for use in C3 marine vessels while the vessels are operating within an Emission Control Area (ECA), or an ECA associated area. [EPA-HQ-OAR-2018-0227-0079-A1, p.2] 49 ------- Response: We discuss how we interpret the term "made available for use" and how it relates to ECA marine fuel in Section III.D.3 of the preamble. 50 ------- 5. General Requirements for Regulated Parties (Subpart B) 5.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Regulation of Blender Pumps. The proposed obligations that apply to blender pumps at retail and wholesale purchaser consumer ("WPC") facilities in §1090.165 eliminate a loophole that may have allowed uncertified hydrocarbons to be blended into gasoline. Natural gas liquids, including Natural Gasoline, may be used as the hydrocarbon portion of E85. Natural gasoline is also used as a blendstock by refiners and refiner-blenders where it is used to produce gasoline. Parties that blend natural gasoline or other uncertified hydrocarbon blendstocks into gasoline are fuel manufacturers and must be subject to the same requirements applicable in §1090.105, including the imposition of a Renewable Volume Obligation under the RFS. [EPA-HQ-OAR-2018-0227- 0074-Al.pp.7-8] Some stakeholders testifying at the Public Hearing on May 28, 2020 expressed concerns that the proposed blender pump requirements were too onerous for fuel retailers and ethanol producers. However, retailers can escape all the burdens associated with meeting the definition of a Fuel Manufacturer in §1090.165 by using previously certified gasoline in the production of E85 used in blender pumps that manufacture El 5. EPA's proposal does not hinder the availability of El 5, allows Natural Gasoline to still be used in E85 sold for use in Flex-Fuel Vehicles, and ensures all gasoline sold at retail meets the same stringent regulatory standards. [EPA-HQ-OAR-2018-0227- 0074-Al,p.8] > Magellan Midstream Partners §1090.165 Blender pumps We strongly support EPA's proposal to require retailers and wholesale purchaser consumers ("WPC") using uncertified hydrocarbons to produce E85 to comply with the requirements of a fuel manufacturer when the fuel is dispensed through a blender pump. We appreciate EPA recognizing that the previous regulatory treatment of natural gas liquid ("NGL") blenders like Magellan was inconsistent when compared to NGL blenders producing E85 which was blended and distributed with other fuels through blender pumps, and in doing so gained both a financial advantage over other methods and were not held to the same regulatory standards. This proposed action creates a level playing field and requires high quality enforceable control standards, which is better for consumers and industry. Parties that blend NGL's, especially natural gasoline or other uncertified hydrocarbon blendstocks into gasoline are fuel manufacturers and all such parties regardless of blending 51 ------- methods should be subject to the same requirements applicable in §1090.105, including the imposition of a Renewable Volume Obligation under the RFS. Background Magellan has been offering blending services which provide recipes to manage the RVP of E85 at virtually all of our terminals since the adoption of ASTM D5798 in 2011. We do not offer natural gasoline as the hydrocarbon portion of the E85 blend at any of our terminals. E85 produced at Magellan's terminals that utilize our recipes meets the ASTM standard by using previously certified gasoline or sub-octane gasoline as the hydrocarbon portion of the blend. We are confident that E85 loaded at our terminals with these recipes will meet the applicable RVP standards when leaving our facilities. We are also confident that the use of certified gasoline or sub-octane gasoline, when producing on-specification E85, will result in compliance with applicable RVP standards when the E85 is blended with on-specification E0 or E10 to produce El5 via a blender pump. For a chart that provides the recipes for the percentage of ethanol and certified gasoline or sub- octane gasoline used to produce E85 at Magellan terminals, please see Appendix A. Please note that the blend percentage changes to meet the seasonal volatility standards. [Appendix A can be found on pp.11-12 of EPA-HQ-OAR-2018-0227-0078-A1.] We are aware that some retailers receive E85 directly from ethanol production facilities which utilize natural gasoline for the hydrocarbon portion of the blend. Then, some of this E85 is blended with E10 or E0 through a blender pump at a retail station to make El 5. According to the Renewable Fuels Association (RFA)i "much of the E85 that is used to make El 5 via blender pumps today contains natural gasoline denaturant..The Renewable Fuels Association advocates the continued use of natural gasoline as the hydrocarbon portion of E85 when used at blender pumps to produce El5. While convenient and financially driven, maintaining this status quo has little basis from a technical, compliance or environmental standpoint. According to our own annual E85 data, the typical hydrocarbon portion of the E85 blend is approximately 30% by volume. While ASTM D5798 permits the hydrocarbon percentage of the E85 blend to range from 17% to 49% volume, we also assume the typical blend percentage of natural gasoline blended by ethanol producers to produce E85 is approximately 30% volume. Based on our laboratory data regarding the vapor pressure of natural gasoline, it can be more than 15psi which far exceeds the maximum allowable vapor pressure limits during the summer months in conventional gasoline markets. When considering the typical blend rate, it is indeed possible that the RVP of El 5 made at blender pumps with E85 produced from natural gasoline would often violate the EPA RVP limits during the VOC control period. Based on the facts above, we support EPA's proposal to require retailers and WPC's uncertified hydrocarbons to produce E85 to comply with the requirements of a fuel manufacturer when the fuel is dispensed through a blender pump. [EPA-HQ-OAR-2018-0227-0078-A1, pp.2-3] Some stakeholders testifying at the Public Hearing on May 28, 2020 expressed concerns that the proposed blender pump requirements were too onerous for fuel retailers and ethanol producers. 52 ------- However, retailers can escape regulatory requirements associated with meeting the definition of a Fuel Manufacturer in §1090.165 by using previously certified gasoline in the production of E85 used in blender pumps that manufacture El 5. EPA's proposal does not hinder the availability of El 5, allows natural gasoline to still be used in E85 sold for use in Flex-Fuel Vehicles, and ensures all gasoline sold at retail meets the same stringent regulatory standards. [EPA-HQ-OAR-2018-0227-0078-A1, pp.4] Response: We thank the commenters for their support. Comment: > CITGO Petroleum Corporation (CITGO) 3 Inconsistency Between Subparts and/or Preamble 3.1 Designation of Diesel Fuel In subpart K, diesel fuel and ECA marine fuel manufacturers must certify diesel fuel which according to §1090.1100(c) (iv) includes designating batches of diesel fuel as specified in §1090.1115. Whereas, in §1090.105(b), diesel fuel and ECA marine fuel manufacturers must comply with the following requirements which does not include designation: (1) Producing and certifying compliant gasoline (2) Registration (3) Reporting (4) PTDs (5) Sampling, testing, and sample retention (6) Surveys This can easily be corrected by modifying the language in §1090.105(b) to include product designation. [EPA-HQ-OAR-2018-0227-0054-A1, p.ll] Response: We have made the change suggested by the commenter. 53 ------- Comment: > Eversheds Sutherland (US) LLP Subpart B provides a helpful reference of the applicable obligations for regulated parties. [EPA- HQ-OAR-2018-0227-0076-A1, p.2] Response: We thank the commenter for their feedback. Comment: > Magellan Midstream Partners §1090.130 Certified butane producers Section (d) calls for certified butane producers to retain samples as per Subpart M. Through our interpretation of the proposed rulemaking, we understand that it is EPA's intention to remove the retention requirement for certified butane producers. This can be accomplished in the following manner: "(d) Sampling and testing, and retention requirements. Certified butane blenders must conduct sampling and testing, and sample retention in accordance with subpart M of this part." Response: We have changed the regulations as the commenter suggested. We did not intend to require the retention of certified butane samples. Comment: > Marathon Petroleum Company LP (MPC) Terminal transmix blending Section 1090.150(a) states transmix blenders must comply with the transmix requirements of subpart F and are required to certify batches of fuel under subpart K. While subpart F tracks closely with those requirements contained within the applicable regulations regarding transmix blending presently in place, subpart K does not. Subpart K requires fuel manufacturers, fuel additive manufacturers, and regulated blendstock producers to certify and designate batches of fuels, fuel additives, and regulated blendstocks. These Subpart K certification and designation requirements are not required under the present regulations, nor were they included in the previous iterations of the streamlining proposals. 54 ------- Under section 1090.80 of the NPRM, "transmix blender" and "transmix processor" are similarly defined except for the second sentence in the definition of "transmix processor" that says: "Transmix processor means any person who owns, leases, operates, controls, or supervises a transmix processing facility. Transmix processors are fuel manufacturers." This distinction may make it more likely that "transmix processors" should be required to comply with subpart K as opposed to "transmix blenders." In light of these concerns, MPC recommends removing the requirement that transmix blenders comply with subpart K. [EPA-HQ-OAR-2018-0227-0048-A1, p.5] Response: We have revised §1090.150 to clarify that transmix blenders do not need to certify or designate fuels under Subpart K. 55 ------- 6. Gasoline Standards (Subpart C) 6.1. Gasoline Comment: > Afton Chemical Corporation Maintaining existing fuel quality standards - We support EPA's approach to not change any of the substantive standards addressed in these regulations. [EPA-HQ-OAR-2018-0227-0038-A1, P-l] Maintaining existing fuel quality standards Afton supports EPA's decision not to change any of the substantive standards included in the existing Part 80 regulations, including the lead, phosphorous, sulfur, benzene, RVP, oxygenate, or gasoline additive standards as a part of the fuels streamlining proposal.1 Afton also supports EPA's clear acknowledgement that the fuels streamlining proposal is not intended to change any of the substantive standards addressed in EPA's existing Part 79 regulations.2 [EPA-HQ-OAR- 2018-0227-0038-A1, p.2] 1 See 85 Fed. Reg. at 29041. 2Id. at 29035, fn. 1. > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • provisions to improve the fungibility of the gasoline pool, including wintertime conventional gasoline ("CG") and reformulated gasoline ("RFG"), flexibility for California gasoline, and emergency waivers for supply reliability; [EPA-HQ-OAR-2018-0227-0074-A1, p.6] • the elimination of the requirement to sample, test, and report certain gasoline parameters which are no longer relevant under Part 1090. [EPA-HQ-OAR-2018-0227-0074-A1, p.6] > Marathon Petroleum Company LP (MPC) MPC supports EPA's efforts to consolidate and streamline the fuels regulations, specifically the following provisions: 56 ------- • Allowing non-VOC conventional and RFG gasolines to be fungible, along with increased flexibility in redesignating fuels, increases efficiency and provides additional tools to manage the fuel distribution system. [EPA-HQ-OAR-2018-0227-0048-A1, p.l] Response: We thank the commenters for their support. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Comment: California has a rule that stations that have not received product for 14 days prior to the RVP transition date are not held to the standard until they receive their next delivery. It's meant to give some leeway to low-volume stations so we're not pumping them out just because they can't sell the product in time. Not only would this apply to a limited number or retail outlets, but it would also reduce the emissions and safety risk associated with pumping out a retail location. The Associations request a similar approach to low-volume retail stations based on their most recent delivery of low-RVP products. The Associations recommend the addition of the following language as a new subsection under 1090.215(c) Exceptions: 1090.215(c)(3) The gasoline is located at a retail station that has not received a delivery designated as summer gasoline in the 14 days prior to the June 1 RVP transition date. In this case, the gasoline at the retail station would not be required to meet the RVP standard until the station receives its next delivery designated as summer gasoline. [EPA-HQ-OAR-2018-0227- 0074-A1, p.38] > Chevron U.S.A., Inc. Low volume throughput retail transition flexibility Certain gasoline retail stations can experience low sales volumes, particularly for premium and mid-grade octane products, which can result in a reduced frequency of gasoline deliveries. This low throughput phenomenon may create difficulty for the station to meet the June 1 summer RVP requirement, even if the regional supply terminals have fully transitioned to compliant summer gasoline on May 1. 57 ------- Under the NPRM, low throughput retail stations, which are unable to fully transition to summer gasoline by June 1, may be forced to remove or "pump out" the winter gasoline from their underground storage tanks. The pump out of winter gasoline may be required to allow a delivery of summer gasoline in sufficient volume to meet the RVP standard. The pump out operation is costly for the retailer. The pump out creates additional safety risk and potential for increased VOC emissions. Managing the transition at these locations is a manual, resource intensive operation. In order to alleviate this concern, Chevron requests an exception be added in 1090.215(c) for summer RVP transition for low throughput retail stations. We propose that retail locations that have not received product during the 14 days prior to the June 1 RVP transition date should not be held to the summer RVP standard until they receive their next delivery. This approach is not unprecedented. The California Reformulated Gasoline Regulations (CCR Title 13, Section 2262.4(c)(3)) provides a mechanism for low throughput locations to have flexibility with RVP transitions. Similar provisions for low throughput retail stations are incorporated in other state regulations. Our suggested revision to the regulatory text is as follows: 1090.215(c)(3) The gasoline is located at a retail station that has not received a delivery designated as summer gasoline in the 14 days prior to the June 1 RVP transition date. In this case, the gasoline at the retail station would not be required to meet the RVP standard until the station receives its next delivery designated as summer gasoline. [EPA-HQ-OAR-2018-0227- 0069-A1, p.2-3] Response: We do not believe that additional flexibility is warranted for retailers to meet the RVP requirements by June 1. Under part 1090, consistent with part 80, we require that all parties except retailers meet the applicable summer RVP standards by May 1. We allow retailers an additional month to come into compliance with applicable summer RVP standards by June 1. We have had this requirement in place since the early 1990s and have had minimal issues with retailers being able to comply with applicable RVP standards by June 1. Comment: > Camin Cargo Control Subpart C—Gasoline Standards 3. Stated Precision a. Oxygen Content 58 ------- Part 1090 makes reference within the multiple document's sections that E10 and El5 must meet the 9-10 and 10-15 volume percent using no decimals in some cases and a single .0 decimal in others. Considering E29 is used to meet the standards, we suggest revising these statements with similar precision to ensure consistency. Examples: 1090.265 uses 10 1 1090.1160 uses 9, 10, 15, 9.0, 10.0 and 15.0 1090.1410 uses 10, 15 b. Sulfur Standards 1090.205 Items (a) and (d) specify sulfur standards at two different precision levels stated. Example 10.00 ppm and 10 ppm respectively. [EPA-HQ-OAR-2018-0227-0030-A1, pp.5-6] > TIC Council Americas Subpart C—Gasoline Standards 1. Oxygen Content a. Part 1090 3rd Ed. Draft still makes reference within the document's sections that E10 and El5 must meet the 9-10 and 10-15 volume percent using no decimals in some cases and a single (i.e. "X.X") decimal in others. Considering E29 is used to meet the standards, we suggest revising these statements with similar precision to ensure consistency. 2. Sulfur Standards a. 1090.305 Items (a) and (d) specify sulfur standards at two different precision levels. [EPA- HQ-OAR-2018-0227-0039-A2, p.2] Response: We assume that the commenter intended to refer to 1090.205(a) and (d). We are not changing the levels of precision for the sulfur standards in part 1090 compared to part 80. The two different precision levels for sulfur refer to the 10.00 ppm sulfur average standard and the 10 ppm sulfur maximum per-gallon standard for truck and rail importers that elect to comply with the 10 ppm sulfur maximum per-gallon standard. For average standards, under part 80 and part 1090, compliance with the annual average standard is determined by a formula that includes values from each individual batch of gasoline produced during the compliance period. The use of two decimal places in 1090.205(a) is intended to reflect that fact that the formula accounts for a number of individual test results where uncertainty in the test method is averaged out. For maximum sulfur per-gallon standards, under part 80 and part 1090, the stated precision is to the 59 ------- nearest whole ppm reflecting the fact that it is an individual test result where uncertainty in the test method is relevant. We are also not changing the level of precision for ethanol in part 1090 compared to part 80. We continue to believe different approaches to evaluating the ethanol content of gasoline are appropriate depending on whether a party is designing and blending gasoline-ethanol blends or testing for oxygenates. Part 1090 follows the same approach as part 80 and prohibits a person from designating 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 and from designating a fuel as El 5 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. When measuring the ethanol content, however, the ASTM E29 rounding procedures will continue to apply. As such, we are finalizing as proposed the stated precision levels for ethanol blending. Comment: > Camin Cargo Control Subpart M—Sampling. Testing, and Retention 6. 1090.1320 - Winter RVP limits a. It is understood that RVP will be required to be measured for all summer gasoline products. As it is currently written, RVP becomes an optional test for winter products. What RVP controls will be in place for winter gasolines entering the marketplace if this parameter is not even being measured? It is not uncommon for blenders to exceed the 15 psi limit currently in place for different grades of gasoline, and the only reason they become aware is because they tested it. [EPA-HQ-OAR-2018-0227-0030-A1, p.6] Response: EPA does not have an RVP standard for gasoline during the winter. Therefore, we are not requiring that fuel manufacturers certify batches of winter gasoline for RVP. However, as the commenter notes, state and voluntary consensus board standards may apply to winter gasoline. Comment: > Eversheds Sutherland (US) LLP Gasoline Requirements Under the Proposed Rule, EPA will allow RVP variation during the summer season—that is, the sale or movement of high-RVP gasoline—if: (a) the gasoline is designated as winter gasoline and is not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into commerce for use during the summer season, and is not delivered to any retail station or wholesale purchaser consumer during the summer season; or (b) the gasoline is designated for use in an 60 ------- area other than the area in which it is located and the gasoline is not sold, offered for sale, supplied, offered for supply, dispensed or introduced into commerce in that area.10 Eversheds Sutherland believes this language appropriately allows for transition from summer to winter gasoline such that production and movement of gasoline with a higher RVP can take place when it is not sold, offered for sale, supplied, offered for supply, dispensed, or introduced into commerce for use during the summer season, or is not delivered to any retail station or wholesale purchaser consumer during the summer season. It is critical to the seasonal change to allow for such a transition so supplies are distributed where needed, and we believe that the proposed language allows for the transition while ensuring that the higher RVP gasoline is not used during the summer season. [EPA-HQ-OAR-2018-0227-0076-A1, p.4] 10Proposed Rule at § 1090.215(c). Response: We thank the commenter for their support. Comment: > National Association of Clean Air Agencies (NACAA) Second, NACAA suggests EPA consider placing limits on certain gasoline properties, such as Reid Vapor Pressure and aromatics and/or benzene as appropriate, such that the proposed fuels regulatory streamlining changes do not result in any emission backsliding or loss of benefits relative to the current program. [EPA-HQ-OAR-2018-0227-0041-A1, p.2] Response: As discussed in Section V.2 of the preamble, we believe that the new 7.4 psi RVP standard for RFG, coupled with the existing sulfur and benzene limits, will ensure that the statutory requirements for the emission performance of RFG will continue to be met and that the current environmental performance of RFG will continue into the future. As a result, imposing additional limits and associated sampling, testing, and compliance oversight would simply add additional cost without providing any additional environmental benefit. However, as a backstop we are still requiring the sampling and testing of a portion of the retail samples from the NFSP to measure for other properties, including aromatics, and report the results back to EPA. Should fuel properties such as aromatics reverse course from their recent trends and rise to the degree that it might cause concern over the emission performance of RFG, we will then have the data on which to base appropriate limits. 61 ------- 6.2. RFG Comment: > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. In addition, we strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is justifiable for the reasons EPA has stated and resolves the prior RVP concerns Gevo and others have communicated. [EPA-HQ-OAR-2018-0227-0063-A2, p.2] > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • the establishment of a 7.4 psi Reid Vapor Pressure ("RVP") per gallon cap to replace the RFG volatile organic compound ("VOC") requirement; [EPA-HQ-OAR-2018-0227-0074-A1, p.6] > Association of Marina Industries (AMI) We also strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is justifiable for the reasons EPA has stated and resolves the prior RVP concerns the Biobutanol Coalition and others have communicated to the Agency. [EPA-HQ-OAR-2018-0227-0057-A1, p.3] > Gevo, Inc. In addition, we strongly support EPA's revised RVP limit per gallon cap of 7.4psi. That is justifiable for the reasons EPA has stated and resolves the prior RVP concerns Gevo and others have communicated. [EPA-HQ-OAR-2018-0227-0063-A1, p.4] > Independent Fuel Terminal Operators Association (IFTOA) II. 7.4 psi Per Gallon RFG Volatility Standard The Association supports EPA's proposed 7.4 psi per-gallon Reid Vapor Pressure ("RVP") standard set forth in § 1090.215. EPA explains that the analysis conducted to determine this proposed standard equates to the current 27.5 percent reduction in VOC emissions performance when compared to baseline gasoline using the Complex Model. Therefore, the change to a per- gallon standard should not pose any more compliance difficulty for the regulated community and would allow the Agency to eliminate the use of the Complex Model as a means of certifying batches of gasoline. [EPA-HQ-OAR-2018-0227-0064-A1, p.2] > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS 62 ------- ILTA supports most of the provisions included in the proposal. This includes: 1. Simplifying the current summer RFG VOC standard into an RVP per-gallon cap of 7.4 psi. This change is long overdue. It eliminates a great deal of unneeded laboratory testing and allows for significantly faster RFG batch certification. > Petroleum Marketers Association of America (PMAA) Simplification of Summertime VOC Standards - RFG RVP Cap PMAA supports the EPA's proposal to simplify the RFG VOC standards by replacing the current complex model that averages emission performance, with a 7.4 psi RVP cap on reformulated gasoline. PMAA supports the change because it will create more fungibility by allowing comingling of RFG and conventional gasoline during the wintertime driving season. > Phillips 66 Company Complex model elimination Proposed RVP standard of 7.4 psi Phillips 66 supports replacing the reformulated gasoline VOC emission reduction standard with a flat RVP limit and eliminating use of the complex model. EPA has thoroughly evaluated gasoline batch data to determine the appropriate RVP standard which would maintain the stringency of the current VOC emission reduction standard. In addition to evaluating RFG batch data, EPA also looked at conventional gasoline batch reports to compare reported RVP values with the maximum 9.0 psi refinery gate standard. Operationally, refineries set a gasoline batch blend target below the standard to ensure that when the batch is sampled and tested, the results will not exceed the standard. This same approach will apply to refinery blending operations when producing RFG with a flat RVP refinery gate limit. Therefore, given a 7.4 psi standard, the average RVP will be lower, as evidenced by the analysis EPA did with conventional gasoline. EPA concluded "a summer RVP standard for RFG of 7.4 psi would meet the goal of preserving the current environmental performance of RFG, while imposing little to no additional industry burden based upon the batch reports for CG, based on their analysis". We agree with EPA's conclusion and support the proposed standard of 7.4 psi. [EPA-HQ-OAR- 2018-0227-0060-A1, p.2] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Reformulated Gasoline Standards 63 ------- The Associations support EPA's Proposal to simplify the RFG standards by translating the current summer RFG volatile organic compound standard into a RVP per-gallon cap of 7.4 psi for summer gasoline and support a 7.4 psi limit for RFG nationwide during the summer.5 5 See generally, Proposal, supra note 1 at §1090.215. Response: We thank the commenters for their support. Comment: > CITGO Petroleum Corporation (CITGO) 2.3 RFG Standards - Heavy Metals Standard In §1090.245(d), RFG or RBOB must not contain any heavy metals, including but not limited to, lead or manganese. Specific test methods for determining values such as, ASTM D3237-17, Standard Test Method for Lead in Gasoline by Atomic Absorption Spectroscopy are incorporated by reference in §1090.95. Clarity is needed to address the expectations around testing for confirmation of this standard and if so, how often. [EPA-HQ-OAR-2018-0227-0054- Al,p.7] Response: We intend for the heavy metals standard for RFG in part 1090 to apply in the same way that the same standard applies under part 80.3 This requirement is specified in CAA section 211 (k) (2) (C) and we have not changed requirements for RFG manufacturers under part 1090 compared to part 80. Comment: > Independent Fuel Terminal Operators Association (IFTOA) I. Winter Gasoline The proposed rule recognizes that winter RFG and CG currently meet the same standards under Part 80. However, existing regulations still require that the two fuels be segregated in the winter. This restriction results in additional storage and distribution costs that are unnecessary. Therefore, the Association supports EPA's proposed regulation, § 1090.1110, to allow commingling of the two products during the winter season by permitting all winter gasoline to be used in RFG areas without recertification. The ability to commingle the fuels will lead to a more 3 See 40 CFR 80.41(h)(1). 64 ------- efficient distribution system that will in turn reduce costs and regulatory burden. [EPA-HQ- OAR-2018-0227-0064-Al,p.2] > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 3. Allowing all winter gasoline to be used in RFG areas without recertification. [EPA-HQ-OAR- 2018-0227-0061-A1, p.2] > Petroleum Marketers Association of America (PMAA) Simplification of Summertime VOC Standards - RFG RVP Cap PMAA is concerned however, the proposed change facilitating comingling could cause delays upstream in the annual transition to summertime gasoline blends. The lack of upstream storage capacity and just-in-time inventory practices leaves little room for error in the timing of transition to summertime gasoline. Retail marketers depend on upstream parties for efficient turnover to summertime gasoline in order to meet their June 1 transition deadline and avoid liability for noncompliant fuel. PMAA would not support an RFG RVP cap if it threatened the efficient transition to summertime gasoline blends. PMAA requests the EPA fully consider the potential impact wintertime comingling of RFG and conventional gasoline would have on the transition to summertime blends and take the necessary actions to avoid delays that would prevent the timely turnover of retail tanks. [EPA-HQ-OAR-2018-0227-0083-Al,p.3] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Reformulated Gasoline Standards Furthermore, the Associations approve of the Agency's Proposal to allow the commingling of RFG with Conventional Gasoline ("CG") during the winter season. Permitting the commingling of RFG with CG during the winter will generally provide for a more fungible and efficient gasoline distribution system, which may ultimately result in lower fuel prices for American consumers. [EPA-HQ-OAR-2018-0227-0066-A1, p.3] Despite the benefits of commingling in the winter, the Associations do want to highlight that the transition from winter to summer may become more challenging as terminal operators navigate the shift from commingled to segregated product.6 This challenge would not be so great that it would outweigh the benefits of the changes the Agency is proposing; however, EPA may wish to consider ways to smooth or facilitate this transition during the first few cycles after the Proposed Rule is finalized. [EPA-HQ-OAR-2018-0227-0066-A1, p.4] 65 ------- 6 Certainly, this will be a bigger concern for terminals that have lesser tank capacity and are thus required to run inventory down, including rejecting winter deliveries earlier in the season than they would normally, in order to meet the new specification deadline. Response: We thank the commenters for their support of the provisions that allow for improved fungibility of fuels. Regarding RVP transition, we believe the continuation of the 0.3 psi RVP tolerance and simplified provisions for recertifying different summer gasoline RVP grades should provide adequate flexibility for the fuel distribution system to transition from winter to summer gasoline. We also note that the requirement to come into compliance with RVP requirements (and VOC control periods in RFG) is the same under part 80 as it is under part 1090 (i.e., May 1 for all parties except retailers, who have a June 1 date). We believe that parties should continue to maintain the same practices under part 1090 as they do under part 80 to ensure for a smooth transition to meet applicable summer RVP requirements by May 1 or June 1, as applicable. Comment: > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 2. Eliminating the 14 gasoline parameters used in gasoline recertification and reporting, along with the retention of just four gasoline parameters: sulfur, benzene, RVP and oxygenate type/content. > Marathon Petroleum Company LP (MPC) • Defining reformulated gasoline (RFG) by vapor pressure instead of toxics reduction. As a result of the MSAT2 and Tier 3 rulemakings, most of the terms in the complex model have become inactive, leaving only RVP. Such simplification decreases the burden on the regulated parties to certify RFG. [EPA-HQ-OAR-2018-0227-0048-A1, p.l] > Phillips 66 Company Complex model elimination Reduced testing requirements The complex model requires 11 different inputs for calculation of VOC emissions. Replacing the VOC emission reduction standard with an RVP standard reduces the number of properties fuel manufacturers are required to test and report to 3 - sulfur, benzene, and summer RVP. Elimination of aromatics and olefins testing is a significant savings for refinery laboratories. The 66 ------- savings include time to prepare and run the tests, time to conduct required QC on the testing apparatuses, cost saving on supplies to run the tests and maintain the instruments and any correlations, and reduction in attestation of test results. The batch testing and certification simplification resulting from the proposed changes is significant and reduces potential for errors (the fewer tests and less data input required along with correlating the data, the less opportunity for error). We are strongly supportive of the simplification and reduction in required gasoline property testing and reporting that results from elimination of the complex model use. [EPA-HQ- OAR-2018-0227-0060-A1, p.2] > U.S. Chamber of Commerce III. EPA's Proposal to Define RFG By Reid Vapor Pressure Instead Of Percent Reductions In Toxic Air Pollutants Emissions Performance To update the fuels regulations consistent with today's market, we support the agency's proposal to (1) replace the existing compliance mechanism used for RFG batch certification—the Complex Model5—with a summer RVP maximum per gallon standard; (2) apply that same single RVP standard to all RFG nationwide; (3) provide greater flexibility for blending of oxygenates (ethanol and biobutanol) and EO in RFG areas; and (4) remove a number of other restrictions that now create a distinction without a difference between RFG and conventional gasoline. The Proposed Rule will greatly reduce the testing and associated reporting requirements by shifting testing for gasoline to the most important parameter, reid vapor pressure (RVP), as opposed to the extensive list of toxic air pollutant and other fuel component measurements. This shift in testing is possible as the differences in RFG fuels, used to address potentially higher summertime emissions in major metropolitan areas, and conventional fuels, used in the remainder of the country, have narrowed. With updates to fuel quality standards and other market changes over the last several decades, RVP is the primary variable that changes to produce RFG fuels in the summer months, making it a logical choice for driving compliance testing. These proposed changes are expected to maintain the stringency of the standards associated with RFG while alleviating unnecessary compliance requirements by simplifying the fuel testing, recordkeeping, and reporting requirements. The current requirements are for refiners to sample and test RFG for 11 parameters that would then be entered into the Complex Model to show compliance, while the Proposed Rule would allow refiners to show compliance with the RFG standards by adjusting just one parameter, the RVP. In addition to reducing the required number of parameters to be tested and reported, we support EPA's proposal to consolidate the RFG regions so that a single RVP standard applies to all RFG nationwide. Currently, there are three different RFG VOC regions each with slightly different required levels of VOC emissions reductions as compared to conventional gasoline. The RFG program with different regions was established in 1995 at a time when RFG gasoline composition was vastly different from conventional gasoline. Since 2000, a series of gasoline 67 ------- regulations and market changes have narrowed this gap making it possible to consolidate the VOC regions and create a single summer RVP standard for all RFG areas. Not only do these changes help reduce fuel testing and the associated recordkeeping and reporting requirements, but it is also expected to reduce costs in the fuel supply chain. Having one fuel that meets the RFG requirements across the nation will allow refiners, distributors, and retailers to eliminate the need for separate transportation containers and storage vessels for gasoline. This will also help reduce fuel supply bottlenecks caused by emergency situations such as hurricanes or other natural disasters where the necessity to keep RFG separate from conventional fuel can disrupt supply of fuels to impacted areas. In addition to the disruptions to the supply chain due to these emergencies, refiners were often required to apply for administrative waivers from the RFG requirements. These administrative steps will be eliminated by allowing for the nationwide use of the same fuel and help refiners get needed fuels to meet demand. [EPA-HQ-OAR-2018-0227-0075-A1, pp.3-4] 5 The Complex Model required refiners to sample and test RFG for 11 parameters. Response: We thank the commenters for their support. Comment: > Magellan Midstream Partners §1090.215 Gasoline RVP Standards We encourage EPA to amend paragraph 1090.215(a)(2) as follows: " (2) RFG maximum RVPper-gallon standard. Gasoline designated as Summer RFG or located in RFG covered areas specified in § 1090.270 during the summer season must meet a maximum RVP per-gallon standard of 7.4 psi. Notwithstanding the requirement to meet a 7.4# RVP. gasoline or BOB with neat RVP 6.2 psi or less, or RVP with 10% ethanol of 7.4# or less, will be deemed in compliance irrespective of the retail RVP." This will ensure that downstream parties are not penalized for test variability. The requirement for a neat RVP standard will also allow the pipeline community to standardize a controllable specification. In order for a pipeline to manage/control RVP specifications, the pipeline operator would be required to blend ethanol on conveyed gasoline to demonstrate compliance with 7.4# RVP, which would also require the operator to test for oxygenates to demonstrate the correct ethanol blend percentage used to demonstrate compliance with the 7.4# standard. Testing oxygenates downstream of refineries at terminal locations is not a reasonable expectation. Additional issues arise with the RVP variation that could exist in the ethanol that is used to demonstrate the 7.4# RVP. 68 ------- We also believe that establishing a neat specification will result in an EO market during the summer that will effectively introduce a less volatile product into the marketplace. The current rule would allow for the combination of premium octane 9.0# product with summer RBOB to make an 87 octane EO gasoline with an RVP of 7.4#. [EPA-HQ-OAR-2018-0227-0078-A1, p.4] Response: We require compliance with the RFG 7.4 psi RVP standard by using a hand blend (i.e., with oxygenates blended to represent compliance after oxygenate blending has occurred). For DFE, due to the requirements for denaturant and the DFE itself, we believe that a hand blend test result will be representative of the RVP of the RFG after DFE is added to the RBOB. Additionally, as discussed in Section XII.C of the preamble, we are continuing the practice of applying the 0.3 psi RVP tolerance to account for downstream testing variability. We believe the combination of the provisions for hand blends and the application of the 0.3 psi RVP test tolerance provides enough flexibility for parties downstream of the fuel manufacturer to accommodate the distribution of RBOB that complies with RFG RVP requirement. Therefore, we do not believe it would be necessary or appropriate to establish an RBOB maximum RVP per-gallon standard of 6.2 psi as suggested by the commenter. If it would be helpful for industry to have such an interim blend product specification in place to ensure all product blended downstream still meets the 7.4 psi RVP standard, then it is free to put such a limit in place. 69 ------- 6.3. Certified Butane and Pentane Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: We request comment on whether the proposed 92 volume percent purity specification for certified butane would provide sufficient flexibility to allow for the presence of pentane in certified butane while still preserving gasoline quality or whether a more or less stringent purity specification would be appropriate. Comment: Agree with the proposed 92% purity specification for certified butane [EPA-HQ-OAR-2018- 0227-0074-A1, p.29] > Eversheds Sutherland (US) LLP Certified Butane Pursuant to feedback received previously, in the Proposed Rule, EPA is proposing a minimum 92 volume percent purity specification for certified butane. While Eversheds Sutherland agrees with the lowering of the specification from the original draft, there would continue to be unnecessary additional processing costs to remove pentane at 92 volume percent. EPA should lower this somewhat further to 90 volume percent in the final rule. [EPA-HQ-OAR-2018-0227-0076-A1, P-7] > Independent Fuel Terminal Operators Association (IFTOA) V. Butane Purity Under the proposal, butane designated as "certified butane" under § 1090.1100 (e) for use under the butane blending provisions of § 1090.1320 (c) must meet, on a per-gallon basis, a butane content level of 92 volume percent. See § 1090.220. Members of the Association believe that a minimum purity level of 92 percent is too high and would restrict the source of butane to only a small number of certified butane producers/suppliers. Therefore, the Association recommends that EPA consider lowering the butane minimum level to 85 percent for "certified butane." In this way, the Agency would facilitate great butane blending. [EPA-HQ-OAR-2018-0227-0064- Al,pp.3-4] 70 ------- > International Liquid Terminals Association ILTA's CONCERNS While the proposal includes many provisions that ILTA supports (listed above), there are also areas of concern. We discuss these below. 4. Butane Purity The minimum purity level (92%) proposed by EPA for certified butane is high and would restrict sources of butane to only a handful of certified butane producers. We propose EPA consider lowering the butane purity level to 85% (minimum) for certified butane. [EPA-HQ-OAR-2018- 0227-0061-A1, p.3] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Certified Butane While the Associations are generally supportive of the proposed changes to certified butane and certified pentane in Sections 1090.220 and 1090.225, the minimum purity level (92%) EPA proposes for certified butane is high and would restrict the source of butane to only a handful of certified butane producers. As such, the Associations urge the Agency to consider lowering the minimum purity level to 85% for certified butane to preserve supply options. [EPA-HQ-OAR- 2018-0227-0066-A1, p.4] Response: We have reduced the minimum butane purity specification for certified butane to 85 volume percent. Under part 80, we do not have a butane purity specification for butane blended under the provisions of §80.82. We did not intend to limit blending practices already permissible under part 80, and we believe that the combination of sulfur, benzene, and butane purity specifications will ensure that only high-quality butane is used as certified butane under part 1090. 71 ------- 6.4. State and Local Fuel Standards Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Mandatory RFG Covered Areas. EPA proposes that mandatory RFG covered areas could opt-out of the RFG program if certain conditions are met. This would give states the ability to determine whether this program should continue in areas that are designated by statute. Congress created mandatory RFG covered areas, and it is up to Congress to eliminate this provision. EPA does not have the authority to remove the RFG program for a mandatory RFG area created by Congress. The statute is unambiguous regarding this matter. The ability to opt-out of RFG must be restricted to RFG opt-in covered areas as currently in 80.72(a) to comport with EPA's statutory authority. [EPA-HQ-OAR-2018-0227-0074-A1, p.7] Response: We are not taking any action that would in any way eliminate or diminish the effectiveness of the RFG program as it applies in areas that have been subject to the program under CAA section 211 (k)(10) (D). All areas that have been subject to the RFG requirement either because they were among the nine areas with the highest 1987 to 1989 1-hour ozone design values and met the population threshold or because they have been reclassified to Severe for any ozone NAAQS will remain RFG covered areas until they satisfy the criteria for redesignation to attainment of the most stringent ozone NAAQS in effect at the time as specified in §1090.290(c). Once such an area meets that initial criterion, the state would then have to follow the procedure in §1090.290(d) to have the requirement for RFG removed. This includes demonstrating that the area can continue to attain the relevant ozone NAAQS. In such areas, RFG would have played a significant role in helping these areas to attain the current health-based ozone NAAQS. However, once such an area reaches attainment of the relevant ozone NAAQS, we believe that the state has discretion to decide what controls are appropriate for maintaining the NAAQS into the future while also acknowledging that measures used for attainment are generally retained as contingency measures. CAA section 175A. Further, any area that is reclassified to Severe in the future will become subject to the RFG requirement one year after the effective date of the reclassification as required by CAA section 211 (k) (10) (D). The commenter argues that Congress intended the RFG covered areas under CAA section 211 (k) (10) (D) to remain subject to RFG for an unlimited period and even after such areas have attained the ozone NAAQS. In fact, CAA section 211 (k) is largely silent on the length of time that an RFG covered area must remain subject to the RFG requirement. The only exception is that CAA section 211 (k) (6) (B) (ii) (II) requires that opt-in areas in the ozone transport region remain in the program for at least four years. Not specifying how long an area must remain as an RFG covered area is consistent with many CAA requirements. And EPA as the agency tasked with administering the Clean Air Act can give effect and meaning to such provisions. ("The power of an administrative agency to administer a congressionally created . . . program necessarily requires the formulation of policy and the making of rules to fill any gap left, 72 ------- implicitly or explicitly, by Congress." Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 843 (1984)). For example, CAA sections 182(b)(4) and 182(c)(3) require basic and enhanced vehicle inspection and maintenance (I/M) programs in certain ozone nonattainment areas. These sections do not specify how long these programs must remain in place. EPA has established a regulation that allows areas to end their I/M program when they are redesignated to attainment for the ozone NAAQS and can demonstrate that they will maintain the ozone NAAQS without the I/M program.4 Similarly, CAA section 211 (h) requires EPA to regulate the RVP of gasoline during the high ozone season including regulations for more stringent RVP standards that apply in nonattainment areas. The CAA does not contain any requirement for how long such nonattainment areas must remain subject to the more stringent RVP standard. EPA indicated in its amended Phase II volatility standards that the 7.8 psi RVP standard remains in effect, even after such a subject area is redesignated to attainment.5 However, separate rulemakings can be carried out to relax the RVP standard in that area from 7.8 to 9.0 psi. An area seeking relaxation of the RVP requirement would have to demonstrate that it would maintain the relevant ozone NAAQS for the length of the relevant maintenance period without the lower RVP gasoline. In fact, this has already occurred on numerous occasions. EPA has relaxed the 7.8 psi RVP standard in a number of ozone maintenance areas that have demonstrated continued maintenance of the ozone NAAQS without maintaining the requirement for gasoline to meet the 7.8 psi RVP standard.6 Additionally, the regulations for the transition from the 1997 ozone NAAQS to the 2008 ozone NAAQS allow anti-backsliding measures for the 1997 ozone NAAQS (e.g., the CAA section 182(c) (4) clean fuel fleet program) to be terminated when the area is redesignated to attainment for the 2008 ozone NAAQS, provided that the area will continue to maintain the 2008 ozone NAAQS without the control(s) in place.7 In part 1090, we have similarly structured the regulations that allow mandatory RFG areas to have the RFG requirement removed. A state may only request the termination of the RFG requirement in a mandatory area if the area is designated as attainment or redesignated to attainment for the most stringent ozone NAAQS in effect and if the relevant ozone maintenance plan for the area demonstrates that the area will continue to maintain the ozone NAAQS without RFG. Relatedly, EPA has previously been challenged on the promulgation of regulations allowing for RFG opt-in for ozone areas other than those classified as Marginal, Moderate, Serious, or Severe under CAA section 211 (k) (6), including areas that had been designated as ozone nonattainment areas but had subsequently redesignated to attainment (i.e., maintenance areas).8 Specifically, in American Petroleum Institute v. EPA, 198 F.3d 275 (D.C. Cir. 2000) , the Court disagreed with EPA's reading of CAA section 211 (k) (6) as allowing for RFG beyond listed opt-in areas, finding instead that" [i]f an area is in attainment, its historical design value has no relationship to its need for RFG. ... In § 211 (k) (6) Congress provided for opt-in only for areas classified as Marginal, Moderate, Serious or Severe. It meant what it said."9 EPA is therefore, concluding that consistent with this decision, mandatory RFG areas that are now in attainment of the most stringent ozone NAAQS currently in effect at the time of a state's request to have the RFG requirement removed 4 See 40 CFR 51.350(c). 5 See 56 FR 64706 (December 12, 1991) 6 The recent RVP relaxations include Baton Rouge, LA (83 FR 53584, October 24, 2018), Nashville, TN (82 FR 26354, June 7, 2017) and Birmingham, AL (80 FR 38284, July 2, 2015). 7 See 40 CFR 51.1105(b). 8 See 63 FR 52094 (September 29, 1998). 9 API at 281. 73 ------- should not continue to be subject to RFG. In other words, they should not be treated differently from opt-in areas if the state follows the criteria and procedure in part 1090. We believe that this approach will provide more consistency across the various state fuel programs and also improve the fungibility of the gasoline supply. These benefits will be accomplished while protecting air quality improvements and public health. Comment: > Eversheds Sutherland (US) LLP For RFG covered areas, we suggest that EPA maintain its website listing for reference, and also create an interactive map to ease reference further and facilitate compliance. [EPA-HQ-OAR- 2018-0227-0076-A1, p.4] Response: We intend to maintain an up-to-date list of RFG areas on our web page (https://www.epa.gov/gasoline-standards/reformulated-gasoline). We may also consider adding in the future, as resources allow, a map depicting the areas where RFG is required. Comment: > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 4. Allowing mandatory RFG areas to remove the applicability of the RFG program provided the three specified requirements are met. [EPA-HQ-OAR-2018-0227-0061-A1, p.2] Response: We thank the commenter for their support. Comment: > Wisconsin Department of Natural Resources (WDNR) Clean Air Act (CAA) Section 211 (k) (10) (D) mandates RFG use in the six-county Milwaukee- Racine area.1 This area must use RFG because it was among the areas with the nine highest 1- hour ozone design values from 1987-1989 that also met a specific population threshold. The CAA did not define a way for RFG programs in these areas to be terminated, modified, or replaced with other emissions control programs in the future. 74 ------- In this proposed rule, EPA is for the first time offering a way for states to request removal of these RFG programs in areas like Milwaukee-Racine. Specifically, EPA is proposing that such programs can be removed when the most recent and prior ozone national ambient air quality standards (NAAQS) have been attained in these areas, and if the state can demonstrate that the removal of the RFG requirement would not interfere with reasonable further progress requirements, continued maintenance of the NAAQS, or any other CAA requirement. EPA proposes to address the CAA's requirements for RFG areas by providing a pathway out of that requirement in a way that continues to ensure attainment and maintenance of air quality and the protection of public health. As EPA notes, it is important that states use their limited resources for programs that are necessary for attainment, rather than require the implementation of an RFG program indefinitely simply because a covered area had the highest ozone design values thirty years ago. It is important to note that states would still need to demonstrate, in an approved maintenance plan, that the NAAQS would be maintained without the emissions reductions attributable to RFG. EPA's proposal sensibly allows states the option to pursue emissions reductions programs other than RFG should those alternatives be more cost-effective or otherwise better reflect state-specific goals or circumstances. To assist states interested in opting-out of RFG in mandatory areas, EPA should clarify the following eligibility and procedural requirements in the proposed regulatory text. First, EPA should clarify in 40 CFR 1090.275(c) (2) whether the mandatory RFG area, to be eligible to opt- out, must be attainment for all prior ozone NAAQS, or only the immediately prior ozone NAAQS (in addition to the most stringent NAAQS). This distinction is important if EPA continues to not revoke previous ozone standards when a new standard is promulgated, as has been the agency's recent practice.2 Second, if EPA intends the opt-out procedures in 40 CFR 1090.275(d) to apply to both opt-in and mandatory areas, this text should be generalized so that it clearly applies equally to both types of areas. As written, the regulations would appear in places to make distinctions between opt-in and mandatory areas. For example, a strict reading of 40 CFR 1090.275(d) and 1090.275(d) (1) (i) would indicate only opt-in areas can request removal of an RFG program from a portion of the covered area. If this is not EPA's intent, this potential confusion could be avoided by eliminating such distinctions in the text. [EPA-HQ-OAR-2018-0227-0055-A1, pp.l- 2] 1 Kenosha, Milwaukee, Ozaukee, Washington, Waukesha, and Racine counties. 2 Consider a potential future situation when a mandatory area is subject to three, non-revoked ozone standards. As written, the regulation would allow this area to opt-out of the RFG program if designated (or redesignated to) attainment for the most recent two standards, but not the oldest (third) NAAQS. While unlikely, such a situation is possible. 75 ------- Response: We thank the commenter for their support. With respect to the commenter's request that we clarify two aspects of the proposal, we have addressed these requests in Section V.A.4.f of the preamble. Additionally, we have revised § 1090.290(d) to clarify that a state may request that a portion of a mandatory RFG area be removed from the RFG program. 76 ------- 6.5. Substantially Similar Comment: > bp America Inc. (bp) Substantially similar clarification for isobutanol blended at 16 vol% The proposed rule includes provisions at §1090.740 which ease present restrictions on downstream recertification of RBOBs and CBOBs with the intent to facilitate blending of oxygenates other than 10% ethanol. The new recertification provisions will facilitate the broader use of renewable isobutanol since, as noted by the Agency under the present recertification requirement of Part 80 ".. .the high cost associated with recertifying batches of RBOB downstream essentially precludes oxygenate blenders from blending isobutanol in RFG areas...." (85 Fed. Reg. 29059) However, the preamble of the proposed rule further opines in VII.G. that fuels made from BOBs recertified per the new rule provisions ".. .would need to meet RVP requirements in the summer, meet per-gallon sulfur requirements, and be substantially similar under CAA section 211 (f)" (85 Fed. Reg. 29059) Taken literally, the substantially similar requirement introduced here (which is not reflected in the regulatory language at §1090.740) would limit isobutanol blending to 11.5 vol% which corresponds to the 2.7wt% oxygen limit of the substantially similar definition for oxygenates other than ethanol. We do not believe this implied limitation to be the Agency's intent, particularly since EPA has registered isobutanol for blending up to 16vol%. We recommend the Agency clarify the preamble on this point to include both fuels which are substantially similar or meet the conditions of an approved waiver under CAA §211 (f). > Butamax Advanced Biofuels, LLC Substantially similar clarification for isobutanol blended up to 16 vol% As specified in its registration of isobutanol as a gasoline additive in 2018 (see 83 FR 13460 and subsequent EPA registration action), the Agency allows blending of isobutanol up to 16 vol% if the blender complies with the conditions of the Octamix waiver. However, in the preamble of the proposed rule and with regard to the aforementioned revisions to BOB recertifications, the Agency asserts in VII.G. of the NPRM that fuels made from BOBs recertified per the streamlined rule provisions . .would need to meet RVP requirements in the summer, meet per- gallon sulfur requirements, and be substantially similar under CA section 211(f)..." (85 FR 29059). Taken literally, the substantially similar requirement introduced in the NPRM preamble (which is not reflected in the regulatory language at §1090.740) would limit isobutanol blending to 11.5 vol% which corresponds to the 2.7 wt% oxygen limit of the substantially similar definition for aliphatic alcohols other than ethanol (such as isobutanol). Butamax does not believe this implied limitation to be the Agency's intent, particularly since EPA has registered isobutanol for blending up to 16 vol%. Butamax recommends the Agency clarify the preamble on this point to include both fuels which are substantially similar or meet the conditions of an approved waiver under CAA 211(f). [EPA-HQ-OAR-2018-0227-0068-A1, p.2] 77 ------- Response: We have made the suggested edit in the preamble to reflect that fuels made from recertified BOBs could be substantially similar or meet the conditions of a CAA section 211 (f) (4) waiver. Comment: > Chevron U.S.A., Inc. Substantially similar definition In the preamble, the EPA proposes to include a requirement in 40 CFR 1090 that all gasoline, BOBs, and gasoline fuel additives must be "substantially similar" (SubSim) under CAA section 211 (f) (1) (B) or have a waiver under CAA section 211 (f) (4). Chevron supports inclusion of a requirement for gasoline and gasoline fuel additives to be SubSim since this is derived directly from CAA section 211. The need to regulate and enforce fuels based on the SubSim definition is particularly relevant for El5, where specific fuel composition, physical and chemical characteristics, and misfueling mitigation were established specifically for that fuel to be deemed substantially similar. [EPA-HQ-OAR-2018-0227-0069-A1, p.3] However, we oppose the concept of requiring a BOB to meet the SubSim definition or have a SubSim waiver as this is outside of the direction provided in CAA section 211. Including a requirement for a BOB to meet SubSim diverges from EPA's prior interpretation which applies to finished fuels and fuel additives. [EPA-HQ-OAR-2018-0227-0069-A1, p.3] A BOB, by definition, means a gasoline designated for downstream oxygenate blending before being dispensed into a vehicle or engine's fuel tank. The BOB should not be subject to SubSim since it is not a gasoline that will be directly consumed unless it is recertified or oxygenate is added. Modification of the SubSim interpretation to include BOBs is a significant change and should only be considered in a separate rulemaking. [EPA-HQ-OAR-2018-0227-0069-A1, p.3] In the NPRM, BOBs are included the proposed definition of gasoline. Therefore, a specific exception for a BOB is needed within the proposed §1090.260 Gasoline SubSim provisions. To acknowledge that a BOB is an unfinished fuel which should not be subject to CAA section 211 (f) (1) (B) or CAA section 211 (f) (4), we recommend the addition of the following language: §1090.260 (a) Gasoline (excluding BOBs) and gasoline additives (including oxygenates) are subject to the substantially similar requirement in 42 U.S.C. § 7545(f) unless waived under 42 U.S.C. § 7545(f)(4). We also suggest that the reference to BOB should be removed from the discussion on SubSim within the preamble. [EPA-HQ-OAR-2018-0227-0069-A1, p.4] 78 ------- Response: Under EPA regulations, we have historically treated BOBs as gasoline. Notably, under EPA's regulatory definition, a BOB is gasoline as we have no octane requirement. While the BOB is intended by the fuel manufacturer to be an unfinished gasoline that is finished downstream with the blending of oxygenate, there is nothing about the characteristics of the BOB that should make compliance with the substantially similar requirement a problem in the absence of the oxygenate. In fact, §1090.740 allows for BOBs to be redesignated downstream as finished gasoline without the addition of oxygenates. Therefore, BOBs are appropriately treated as gasoline under part 1090 and also appropriately required to be substantially similar unless waived under CAA section 211 (f) (4). Comment: > CITGO Petroleum Corporation (CITGO) 2.4 Application of Gasoline Substantially Similar and ASTM D4814 Provisions In §1090.260, gasoline and gasoline additives (including oxygenates) are subject to the substantially similar requirement in 42 U.S. C. § 7545(f) unless waived under 42 U.S.C. §7545(f) (4). EPA further stipulates that no fuel or fuel additive manufacturer may introduce into commerce gasoline or gasoline additives (including oxygenates) that are not consistent with its definition or waiver conditions and has incorporated by reference in §1090.95 ASTM D4814-20, Standard Specification for Automotive Spark-Ignition Engine Fuel. While CITGO supports EPA's intent to control new gasoline formulations and ensure product quality, clarification is needed on the application of these provisions to outline whether substantially similar provisions apply only at the point of manufacture (refinery) or downstream as well. Similarly, does ASTM D4814-20 incorporated by reference apply solely at the point of sale to the ultimate consumer or from a distributor and/or fuel manufacturer upstream as well? [EPA-HQ-OAR-2018-0227-0054- Al,p.7] Response: CAA section 211 (f) prohibits fuel and fuel additive manufacturers from introducing into commerce any fuel not substantially similar to certification fuel. A fuel or fuel additive manufacturer, as defined in §1090.80, is any party that makes fuels, including refiners, importers, blending manufacturers, and transmix processors. Depending on the activities performed by downstream parties, those activities may make those parties fuel or fuel additive manufacturers (e.g., blending components other than oxygenates or other additives at allowed levels into fuel). Therefore, the substantially similar requirement in part 1090 applies to downstream parties to the extent they are engaging in activities that would make them a fuel or fuel additive manufacturer under EPA's regulations. While the commenter ties the ASTM D4814-20 specification to the substantially similar provisions under CAA section 211 (f) and under part 1090, we did not propose to modify in any 79 ------- way the substantially similar determination we issued in 2019.10 This action does not require that gasoline meet ASTM D4814 at any point (ASTM D4814 has specifications for many properties not included in our regulations), but if a fuel does meet ASTM D4814 and it is made available for use in engines designed to operate on gasoline, this action defines it as gasoline. Such fuel is gasoline and is subject to all applicable standards and requirements for gasoline under part 1090. Comment: > Urban Air Initiative 3. Urban Air Initiative objects to the new definition of "fuel additive" under the Clean Air Act's "substantially similar" law The proposed rule would codify a new definition of "fuel additive." The proposed rule would define "fuel additive" to mean "a substance that is designated for registration under 40 CFR part 79 and is added to fuel such that it amounts to less than 1.0 volume percent of the resultant mixture, or is an oxygenate added up to a level consistent with levels that are 'substantially similar' under 42 U.S.C. 7545(f) (1) or as permitted under a waiver granted under 42 U.S.C. 7545(f) (4)." But the statute does not allow EPA to contort the meaning of fuel additive based on what concentrations of fuel additives the Agency deems "substantially similar." [EPA-HQ-OAR- 2018-0227-0071-A1, p.6] 4. Urban Air Initiative objects to the 15% ethanol cap under EPA's interpretation of the Clean Air Act's "substantially similar" law The proposed rule reopens EPA's 2019 definition of "substantially similar" by proposing to codify a new rule asserting that fuel manufacturers must meet "any parameters articulated in [EPA's] definition of 'substantially similar,' '' and adhering to "the parameters associated with the 2019 definition of substantially similar." That definition caps the concentration of ethanol in gasoline at 15%. That cap lacks a statutory basis under the law, because fuel blends with more than 15% ethanol are "substantially similar" to the high-level ethanol-gasoline test fuel. [EPA- HQ-OAR-2018-0227-0071-A1, p.6] III. THE PROPOSED RULE'S INTERPRETATION OF THE SUB-SIM LAW IS UNLAWFUL. The Clean Air Act's sub-sim law forbids fuel and fuel additive manufacturers from increasing the concentration in use of fuels or fuel additives that are not "substantially similar" to the fuels or fuel additives used in the motor vehicle certification test fuels.77 [EPA-HQ-OAR-2018-0227- 0071-A1, p.18] The proposed rule would codify this "substantially similar" requirement for gasoline fuel and fuel additives, based on the Clean Air Act's sub-sim law.78 In addition to parroting the text of the statute, the proposal adds a new rule that" [n]o fuel or fuel additive manufacturers may 10 See 84 FR 26980 (June 10, 2019). 80 ------- introduce into commerce gasoline or gasoline additives (including oxygenates) that violate any parameters articulated in the definition of 'substantially similar.' "79 That includes "the parameters associated with the 2019 definition of substantially similar. "80 These parameters limit the concentration of ethanol in gasoline to blends "no more than 15% ethanol."81 [EPA- HQ-OAR-2018-0227-0071-Al,p.l8] The proposed rule would then also simultaneously codify a new definition of "fuel additive." It would define "fuel additive" to mean "a substance that is designated for registration under 40 CFR part 79 and is added to fuel such that it amounts to less than 1.0 volume percent of the resultant mixture, or is an oxygenate added up to a level consistent with levels that are 'substantially similar' under 42 U.S.C. 7545(f)(1) or as permitted under a waiver granted under 42 U.S.C. 7545(f) (4)."82 Thus, denatured fuel ethanol would be considered a "fuel additive" only if the finished fuel is El 5, but not if the finished fuel is E20. [EPA-HQ-OAR-2018-0227- 0071-A1, p.19] A. The proposed rule's definition of "fuel additive" under the Clean Air Act's "substantially similar" law is unlawful. The proposal's novel definition of fuel additive cannot be reconciled with the text and structure of CAA § 211. [EPA-HQ-OAR-2018-0227-0071-A1, p.19] First, this definition of fuel additive is contrary to the ordinary meaning of the term. "In statutory interpretation disputes, a court's proper starting point lies in a careful examination of the ordinary meaning and structure of the law itself. "83 As relevant here, a gasoline "additive" is defined by a contemporary dictionary as "a chemical (as an antiknock agent or an agent for counteracting deposits on spark plugs) added to gasoline."84 This dictionary gives the example of "tetraethyl lead."85 This ordinary meaning includes any chemical agent intentionally added to gasoline, regardless of concentration. [EPA-HQ-OAR-2018-0227-0071-A1, p. 19] Second, the "normal rule of statutory construction [is] that identical words used in different parts of the same act are intended to have the same meaning. "86 Courts should particularly strive to avoid interpretations that give the same word "two different meanings in the same section of the statute."87 That canon is relevant here, because under the Part 79 regulations of CAA § 211 (a), (b), and (e), the term fuel additive is not limited to any particular concentration. EPA's rules define "additive" in these provisions to mean "any substance, other than one composed solely of carbon and/or hydrogen, that is intentionally added to a fuel named in the designation . . . and that is not intentionally removed prior to sale or use."88 That definition includes any fuel additive added to gasoline regardless of its concentration in the fuel. While the canon of consistent usage may yield to context, context reinforces its application here. CAA §§ 211 (a), (b), (c)(1), (e), and (f) are interrelated parts of a comprehensive "scheme" to control fuels and fuel additives.89 Such a scheme "should not be read as a series of unrelated and isolated provisions."90 The provisions should instead "be interpreted together, as though they were one law."91 That requires interpreting the term "fuel additive" consistently. [EPA-HQ-OAR-2018- 0227-0071-A1, pp.19-20] 81 ------- Third, the prior-construction canon also supports interpreting "fuel additive" to include any fuel additive, even those that are not "substantially similar." Language that is "obviously transplanted from another legal source . . . brings the old soil with it."92 Thus, " [w]hen administrative . . . interpretations have settled the meaning of an existing statutory provision, repetition of the same language in a new statute indicates, as a general matter, the intent to incorporate its administrative . . . interpretations as well. "93 EPA promulgated its administrative definition of "fuel additive" in 1975.94 Two years later, Congress enacted the sub-sim law, borrowing the term "fuel additive." Under the prior-construction canon, then, the sub-sim law "is presumed to carry forward" EPA's prior administrative definition of "fuel additive. "95 That definition of fuel additive includes any fuel additive added to gasoline, regardless of concentration.96 [EPA-HQ- OAR-2018-0227-0071-A1, p.20] Fourth, this definition of fuel additive would create needless surplusage. It is a fundamental rule of statutory interpretation that" [a] court should give effect, if possible, to every clause and word of a statute."97 But under EPA's interpretation of the sub-sim law, the law's prohibition on "increasing] the concentration in use off] any . . . fuel additive" that is not "substantially similar" to a fuel additive used in certification would do no work, because fuel additives that EPA believes are not substantially similar would not be considered fuel additives.98 That is illogical. [EPA-HQ-OAR-2018-0227-0071-A1, p.20] In conclusion, EPA's novel definition of fuel additive is unlawful. It should be withdrawn in the final rule. [EPA-HQ-OAR-2018-0227-0071-A1, p.20] B. The proposed rule must acknowledge that mid-level blends are "substantially similar" to the high-level ethanol-gasoline test fuel. By proposing to codify a requirement that manufacturers must meet "any parameters articulated in [EPA's] definition of 'substantially similar,' " and by adhering to "the parameters associated with the 2019 definition of substantially similar," the proposed rule has reopened those parameters.99 [EPA-HQ-OAR-2018-0227-0071-A1, p.21] Those parameters include a limit on the concentration of ethanol in gasoline to "no more than 15 volume percent ethanol ('El5')."100 This limitation is unlawful, because mid-level blends are "substantially similar" to the high-level ethanol-gasoline blend test fuel used to certify flex-fuel vehicles. 101 [EPA-HQ-OAR-2018-0227-0071-A1, p.21] To determine whether a fuel is "substantially similar," EPA considers whether—compared to "any fuel. . . utilized in the certification of any . . . vehicle," CAA § 211 (f) (1) (B)—the candidate fuel has similar effects on (1) emissions; (2) the durability of vehicle emission controls; and (3) a vehicle's performance or "driveability."102 These criteria are "linked" because "they are intended to answer the same question: Whether a fuel[] . . . will harm emission controls on vehicles and engines or result in increases in regulated emissions. "103 When determining whether a fuel is "substantially similar," EPA does not consider the fuel's compatibility with every type of motor vehicle, as that would make the sub-sim law unworkable. (Indeed, no fuel is compatible with all motor vehicles.) Instead, as the El5 Rule explains, " [i]n assessing whether a fuel is substantially similar to a certification fuel, [EPA] must look only to its use in the engines 82 ------- and vehicles within which it can be used, and not its use in vehicles and engines which are fueled by other types of fuel."104 [EPA-HQ-OAR-2018-0227-0071-A1, p.21] Mid-level blends are "substantially similar" to high-level ethanol-gasoline test fuel under these criteria. Flex-fuel vehicles are the only vehicles certified to operate on high-level ethanol- gasoline test fuel, so only such vehicles could be the relevant unit of analysis for purposes of the "substantially similar" criteria. When used in flex-fuel vehicles, mid-level ethanol blends do not pose any risk to compliance with emission standards, because flex-fuel vehicles are designed to maintain "emissions performance across the full range of potential in-use fuel formulations," meaning any mixture of "gasoline and ... up to 83 volume percent ethanol." 105 Nor do they pose any risk to vehicle emission controls or driveability: as the Department of Energy has explained, "FFVs can run on E85, gasoline, or any blend of the two, without adverse effects on fuel system and engine materials, onboard diagnostics systems, or driveability." 106 Mid-level blends are thus "substantially similar" to the high-level ethanol-gasoline test fuel under all of the criteria that EPA considers, so they are not "unlawful" under the sub-sim law. [EPA-HQ-OAR- 2018-0227-0071 - A1, pp.21-22] The conclusion that mid-level blends are substantially similar to the high-level ethanol-gasoline test fuel is consistent with prior EPA guidance on mid-level blends. EPA stated in 2006 that "blends such as E20 and E30 for use in FFVs ... are covered under the emissions certification for an E85 FFV, and thus are not prohibited under the Clean Air Act." 107 This statement would make no sense unless mid-level blends are "substantially similar" to the high-level ethanol- gasoline test fuel used to certify flex-fuel vehicles; fuels that are not sub-sim are by definition prohibited under the Clean Air Act, unless granted a waiver under § 211(f)(4). The El5 rule's limit on the concentration of ethanol is thus arbitrary and capricious because it upsets reasonable expectations without acknowledging this past guidance or the "serious reliance interests" it has induced. 108 [EPA-HQ-OAR-2018-0227-0071-A1, p.22] EPA's interpretation is arbitrary and capricious for an additional reason: it treats E85 and mid- level blends differently for purposes of the sub-sim law for no identifiable policy reason. E85 would still be allowed into commerce because the Agency says it is not regulated "gasoline." Mid-level blends, by contrast, would be shut out, even though flex-fuel vehicles are designed to meet EPA's standards on both fuels. The Court "must reverse an agency policy when [it] cannot discern a reason for it." 109 No reason anchored in the sub-sim law's text, history, or purpose supports EPA's disparate treatment of E85 and mid-level blends for use in flex-fuel vehicles. [EPA-HQ-OAR-2018-0227-0071-A1, p.22] EPA must acknowledge that mid-level blends are substantially similar to the high-level ethanol- gasoline blend test fuel. [EPA-HQ-OAR-2018-0227-0071-A1, p.22] 77 42 U.S.C. § 7545(f)(1). 78 85 Fed. Reg. at 29,111-12, to be codified at 40 C.F.R. § 1090.260. 79 Id. at 29,112. 83 ------- 80 Id. at 29,053. 81 Modifications to Fuel Regulations To Provide Flexibility for El5; Modifications to RFS RIN Market Regulations, 84 Fed. Reg. 26,980, 27,021 (June 10, 2019) (E15 Rule). 82 Proposed Rule, 85 Fed. Reg. at 29,101. 83 Food Mkt'g Inst. v. Argus Leader Media, 139 S. Ct. 2356, 2364 (2019). 84 Webster's (Third) Int'l Dictionary 24 (1966). 85 Id. 86 Gustafson v. Alloyd Co., 513 U.S. 561, 570 (1995) (quotation marks omitted). 87 Mohasco Corp. v. Silver, 447 U.S. 807, 826 (1980). 88 40 C.F.R. § 79.2(e). 89 Ethyl Corp. v. EPA, 51 F.3d 1053, 1061 (D.C. Cir. 1995) (Ethyl II). 90 Gustafson, 513 U.S. at 570. 91 Antonin Scalia & Bryan Garner, Reading Law: The Interpretation of Legal Texts 252 (2012). 92 Stokeling v. United States, 139 S. Ct. 544, 551 (2019) (citation omitted) (quoting Felix Frankfurter, Some Reflections on the Reading of Statutes, 47 Colum. L. Rev. 527, 537 (1947)). 93 Bragdon v. Abbott, 524 U.S. 624, 645 (1998). 94 40 Fed. Reg. at 52,011. 95 Scalia & Garner, supra note 91, at 322. 96 40 C.F.R. § 79.2(e) ("Additive means any substance, other than one composed solely of carbon and/or hydrogen, that is intentionally added to a fuel named in the designation (including any added to a motor vehicle's fuel system) and that is not intentionally removed prior to sale or use.") 97 See Moskal v. United States, 498 U.S. 103, 109 (1990) (quotation marks omitted). 98 42 U.S.C. § 7545. 99 CTIA-Wireless Ass'n , 466 F.3d at 110. 100 E15 Rule, supra note 81, 84 Fed. Reg. at 27,021. 101 40 C.F.R. § 1065.725. 102 E15 Rule, supra note 81, 84 Fed. Reg. at 26,997. 103 Id. 84 ------- 104 Id. 105 Tier 3 Rule, supra note 24, 81 Fed. Reg. at 23,529, 23,557. 106 E85 is subject to ASTM standard D5798. See Dep't of Energy, Handbook for Handling, Storing, and Dispensing E85 and Other Ethanol-Gasoline Blends 16 (2016) (DOE Ethanol Handbook). 107 2006 Oge Letter, supra note 15. 108 Nat'l Lifeline Ass'nv. FCC, 921 F.3d 1102, 1114 (D.C. Cir. 2019). 109 Judulang v. Holder, 565 U.S. 42, 64 (2011). Response: We have modified our proposed definition of fuel additive to align more closely with our definition of "additive" in part 79. We believe that this change alleviates commenter's concerns regarding the proposed definition. We note, however, that the sulfur limitations on gasoline and diesel fuel additives in part 1090 are the same as part 80 and we are finalizing the transposition of those requirements in part 1090 from part 80, unchanged. As to the requirement that gasoline be "substantially similar," as we have stated in prior actions, the commenter's interpretation of CAA section 211 (f) (1) would result in harm to vehicles and engines and would run contrary to Congress's intent in enacting 211 (f).11 The commenter suggests, again, that CAA section 211 (f) (1) does not limit the concentration of fuel additives if the fuel additive is substantially similar to a fuel additive used in certification fuel. The commenter focuses on the treatment of ethanol under our fuel additive definition. The commenter also suggests that the proposal adds a new rule that no fuel or fuel additive manufacturers may introduce into commerce gasoline or gasoline additives (including oxygenates) that violate any parameters articulated in the definition of 'substantially similar' including the parameters associated with the 2019 definition of substantially similar which limit the concentration of ethanol in gasoline to blends "no more than 15% ethanol." We note, initially, that in the final regulations we are promulgating, we have removed the regulatory references to parameters in the definition of substantially similar, as well as the reference to conditions under a CAA section 211 (f) (4) waiver due to concerns about potential misunderstanding regarding the parameters and definitions referenced in the proposed rule. However, fuel and fuel additive manufacturers must still meet these statutory requirements, including parameters associated with a "substantially similar" interpretive rule, and the conditions imposed under a CAA section 211 (f) (4) waiver, despite its removal from the final part 1090 regulations. This requirement has existed since the promulgation of the 2019 definition of substantially similar, and indeed existed as a result of the 2010 and 2011 El 5 partial waivers, of 11 See "Modifications to Fuel Regulations to Provide Flexibility for E15; Modifications to RFS RIN Market Regulations: Response to Comments." EPA-420-R-19-004, pp. 28-31. 85 ------- which a condition is that the ethanol content of gasoline cannot exceed 15% when used in 2001 and newer light-duty motor vehicles.12 The text of CAA section 211 (f) (1) provides that the manufacturer of a fuel or fuel additive shall not introduce into commerce or increase the concentration in use of any fuel or fuel additive that is not substantially similar to a certification fuel or fuel additive. It does not, as the commenter suggests, allow the use of "fuel additives used in the motor vehicle certification test fuels" at any concentration. The commenter's interpretation of the statute would read out the phrase "increase the concentration in use." The commenter also suggests that in this action we have reopened the 2019 substantially similar definition. This action does not reopen the 2019 substantially similar definition for gasoline. While in the proposal, we identified that gasoline and gasoline additive manufacturers must introduce fuel and fuel additives that are substantially similar (or have a waiver), we took no action to reassess or reevaluate the definition of substantially similar. This aspect of the comment is beyond the scope of this rulemaking. EPA is free to define the scope of its rulemakings and incorporating a concept into regulations does not reopen that underlying action. We further note that the commenter challenged the 2019 definition and that litigation is currently pending before the D.C. Circuit. The commenter also suggests that the mid-level ethanol blends are substantially similar to E85, which is used to certify flex-fuel vehicles. This action does not modify the treatment of mid-level ethanol blends used in flexible-fueled vehicles.13 Flex-fuel vehicles are specifically designed and certified to run on high-level ethanol blends. Gasoline-fueled vehicles, in contrast, are not. This action is not modifying the treatment of gasoline-ethanol blends of less than 50 percent ethanol as gasoline, nor is it taking any new action under the substantially similar provision at CAA section 211(f)(1). We are merely incorporating the statutory requirement that fuel being introduced into commerce must be "substantially similar" under CAA section 211 (f) (1) or have a waiver under CAA section 211 (f) (4) into our regulations at part 1090 in order to make it clear to parties when they look at part 1090 for what standards and requirements apply to their fuel that the "substantially similar" requirements also apply. This provision does not create any new requirement beyond what already existed under the statute. Additionally, the conditions and parameters of EPA's definitions of "substantially similar" continue to apply, as explained above. 12 See 84 FR 26980 (June 10, 2019). 13 For our most recent discussion of the treatment of these fuels, see 79 FR 23414, 23557-58 (April 28, 2014). 86 ------- 7. Diesel Fuel Standards (Subpart D) 7.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.300(e)(1) No person may produce, import, sell, offer for sale, distribute, offer to distribute, supply, offer for supply, dispense, store, transport, or introduce into commerce any diesel fuel, ECA marine fuel, or diesel fuel additive that exceeds any standard set forth in this subpart. Comment: The word "exceed" assumes a maximum spec. Cetane index for aromaticity is a minimum. The Associations suggest "ECA marine fuel, or diesel fuel additive that exceeds does not meet any standard set forth in this subpart." [EPA-HQ-OAR-2018-0227-0074-A1, p.38] > Marathon Petroleum Company LP (MPC) Overview and general requirements 1090.300(e)(1) No person may produce, import, sell, offer for sale, distribute, offer to distribute, supply, offer for supply, dispense, store, transport, or introduce into commerce any diesel fuel, ECA marine fuel, or diesel fuel additive that exceeds any standard set forth in this subpart. The word "exceed" assumes a maximum spec. The cetane index limit is a minimum. [EPA-HQ- OAR-2018-0227-0048-A2, p.l] Response: We have made responsive edits to §1090.300(e)(1) as suggested by the commenters. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: 87 ------- 1090.305(a) Except as specified in §1090.300(a) (1) and (2), diesel fuel must meet the ULSD per- gallon standards of this section. (b) Sulfur standard. Maximum sulfur content of 15 ppm. Comment: The preamble (p. 7) states "Most importantly, this action does not change the stringency of the existing fuel quality standards." However, removing the 2-ppm allowance for diesel S at downstream locations does just that. As long as fuels with higher S content, especially jet fuel, share the distribution system with ULSD some sulfur contamination can occur. The effect of removing the allowance will force refiners to produce diesel with S content below the 15-ppm intended standard. [EPA-HQ-OAR-2018-0227-0074-A1, p.38] The sulfur standard for gasoline, which is transported in the same distribution system, allows 95 ppm S content at downstream locations, 15 ppm higher than the level required at the refinery gate. Whether this allowance is for test reproducibility (for 15 ppm it is 3 ppm for the referee method) or potential for contamination in the distributions system, diesel fuel should have the same consideration. [EPA-HQ-OAR-2018-0227-0074-A1, pp.38-39] > Marathon Petroleum Company LP (MPC) ULSD Standards 1090.305(a) Except as specified in §1090.300(a) (1) and (2), diesel fuel must meet the ULSD per- gallon standards of this section. (b) Sulfur standard. Maximum sulfur content of 15 ppm. Page FR29035 of the Preamble states, "Most importantly, this action does not change the stringency of the existing fuel quality standards." However, removing the 2 ppm allowance for diesel sulfur at downstream locations likely exacts the stringency EPA states it seeks to avoid. As long as fuels with higher sulfur content, especially high sulfur jet fuel, share a distribution system with ultra-low sulfur diesel, then the potential for sulfur contamination will exist. The effect of removing the allowance will force refiners to produce diesel with sulfur content below the 15 ppm intended standard. The sulfur standard for gasoline, which is transported in the same distribution system, allows 95 ppm sulfur content at downstream locations, 15 ppm higher than the level required at the refinery gate. Whether this allowance is for test reproducibility (for 15 ppm it is 3 ppm for the referee method) or potential for contamination in the distributions system, diesel fuel should have the same consideration. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] > Eversheds Sutherland (US) LLP Downstream Tolerance 88 ------- EPA should continue to provide for a downstream sulfur tolerance for ULSD as well as for ECA marine fuel, or at least repeatability similar to what ISO testing allows. A downstream tolerance for ULSD would also be consistent with current diesel rules that allow a 2 ppm adjustment factor to test results.18 EPA does not explain why this was dropped, and EPA should include the same testing "adjustment factor" in the final rule. [EPA-HQ-OAR-2018-0227-0076-A1, p.7] 18See 40 C.F.R. § 80.580(d)(1). Response: While most diesel fuel in-use is well below 15 ppm sulfur and therefore would no longer seem to need the downstream testing adjustment, a review of the data suggests that the test variability is still in the 2 ppm range. Therefore, as suggested by commenters, to account for testing variability and avoid changing the apparent stringency of the standard, we are carrying over into part 1090 the 2-ppm downstream testing adjustment that is currently specified in §80.580(d). Comment: > Eversheds Sutherland (US) LLP Diesel Requirements Use of "Diesel" In the Proposed Rule, when referencing specific requirements throughout Part 1090, it would be less confusing if EPA used the specific terminology for the fuel in question, which is primarily ULSD, LM, and ECA Marine Fuel. "Diesel" is a broad term, and in EPA's effort to facilitate understanding of the requirements, the regulations should clearly state the types of fuel implicated under a particular section. One example is that the registration subpart lists "diesel fuel manufacturers,"16 which could be read broadly to include jet fuel, kerosene and other "diesel" producers, but it actually just applies to ULSD and LM. EPA specifies that ECA Marine Fuel manufacturers must register, and similarly EPA should incorporate the most precise terminology available to simplify compliance. Another example is the provision "Reports by diesel manufacturers," which only applies to ULSD—the title should state "Reports by ULSD manufacturers."17 [EPA-HQ-OAR-2018-0227-0076-A1, p.7] 16 Id. at § 1090.800. 17 Id. at § 1090.935. 89 ------- Response: In general, jet fuel, kerosene, and heating oil are not considered diesel fuel as defined under §1090.80; they are distillate fuels. Under part 1090, manufacturers that exclusively produce jet fuel, kerosene, and heating oil (i.e., they produce no diesel or ECA marine fuel) do not need to register or submit reports. However, if jet fuel, kerosene, or heating oil is made available for use in vehicles and engines that require the use of ULSD, those fuels then become diesel fuel and subject to ULSD requirements under part 1090, regardless of whether the fuel is designated as jet fuel, kerosene, or heating oil. Given the fungibility of these fuels and the desire from many manufacturers to certify distillate fuels for multiple uses, we believe it is necessary for the terminology to address the many situations that could arise from this added flexibility. In the alternative, we could have restricted the use of dual- or triple-certified distillate fuels, imposing significant limitations on how distillate and diesel fuels are produced and distributed. Therefore, we believe that the definitions and usage of the term "diesel fuel" is sufficiently precise, and we are finalizing as proposed. Comment: > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) The Associations also urge the Agency to clarify in the final rule that the proposed revisions designed to enhance fungibility between heating oil and diesel fuel do not lead to unintended consequences with respect to excise tax liability or obligated parties' renewable volume obligations under the Renewable Fuel Standard ("RFS") (See Section II.C). [EPA-HQ-OAR- 2018-0227-0066-A1, p.2] Response: This action does not change any requirements under the RFS program related to RVOs, nor does it change any requirement for excise taxes under IRS regulations. The RFS regulations under part 80 specify provisions for obligated parties to account for distillate fuels that are certified as non-transportation diesel fuel in RVOs.14 14 See §80.1408. 90 ------- 7.2. Removing the Red Dye Requirement Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • the removal of EPA's red dye requirement for diesel fuel, and [EPA-HQ-OAR-2018-0227- 0074-A1, p.6] > Florida Department of Environmental Protection Red Dye Diesel Waiver Requests During hurricane season, the Department has specific procedures in place for making all necessary requests for regulatory assistance to EPA. This includes, among other things, a request to waive the requirement that red dye diesel only be used in a manner that is tax exempt under section 4082 of the Internal Revenue Code. The Department's request for a red dye diesel waiver demonstrates that supplies of highway diesel fuel are constricted due to extreme and unusual supply circumstances that could not have reasonably been foreseen or prevented and is not attributable to a lack of prudent planning, per the requirements of Clean Air Act Section 211(c) (4) (C)(ii). Under the current regulatory regime, EPA's response to Florida's request for a red dye diesel waiver usually notes that "EPA in consultation with the U.S. Department of Energy (DOE), has evaluated the impact of fuel supplies as the result of disruptions to the fuel distribution system []" and then allows certain limited uses of red dye diesel to help alleviate Florida's fuel supply concerns.1 EPA's consultation with DOE on whether a fuel waiver is necessary is required pursuant to Clean Air Act Section 211 (c) (4) (C) (ii). After Florida secures a red dye diesel waiver from EPA, the Department sends a letter to the IRS requesting tax penalty relief. The request usually notes that it satisfies Clean Air Act Section 211 (c) (4) (C) (ii). The IRS then provides the tax penalty relief noting that it is consistent with EPA's red dye waiver.2 Proposed Changes to EPA's Red Dye Diesel Regulations 40 CFR Part 80 currently requires that motor vehicle diesel fuel must be free of visible evidence of dye, except for tax exempt purposes. EPA's proposal states that this requirement complicates the fuel waiver process as states must receive a waiver from EPA and tax penalty relief from the IRS: " [EPA's red dye requirement] complicates the process of providing alternate sources of diesel fuel when supplies of highway diesel fuel are constricted due to extreme and unusual supply 91 ------- circumstances. State authorities are currently required to request a waiver from EPA and the Internal Revenue Service (IRS) from the respective agency's red dye requirements to enable the use of 15 ppm NRLM diesel fuel on highway during such circumstances. Eliminating our red dye requirement would reduce state officials' waiver requests to just an IRS waiver during such events without substantially affecting the ability of EPA to enforce highway ULSD standards. Therefore, we are proposing to remove the EPA requirement that motor vehicle diesel fuel must be free from visual evidence of red dye." It is true that if EPA did not have to issue a red dye diesel waiver, then states seeking expanded uses of this red dye diesel would only have to seek IRS tax penalty relief. In the Department's experience, however, the relief granted by the IRS is predicated on the facts and findings in EPA's waiver. This is supported by Clean Air Act Section 211 (c) (4) (C) (ii) which requires EPA, in consultation with DOE, to determine that an "extreme and unusual fuel or fuel additive supply circumstances exist[s]." If EPA were no longer involved, then presumably, neither would DOE and this would leave the IRS to make a factual and legal determination that a fuel waiver is necessary and appropriate, and it is not clear whether the criteria in Clean Air Act Section 211 (c) (4) (C) (ii) are relevant to any future IRS decisions to grant relief. In order to clarify how EPA's proposed IRS-only fuel waiver process would work, the Department requests that EPA and IRS provide clear instructions to states regarding future tax penalty relief requests and what the factual and legal basis is for receiving that relief. The Department's ability to quickly seek any needed relief to ensure an adequate supply of fuel before, during, and after a hurricane is critical. [EPA-HQ-OAR-2018-0227-0042-A1, pp.1-2] 1 See EPA Waiver to Florida, August 30, 2019, available at: https://www.epa.gov/sites/production/files/2019- 08/documents/floridafuelwaiverconcerningreddye0819.pdf 2 See IRS Press Release Granting Tax Penalty Relief to Florida, August 30, 2019, available at: https://www.irs.gov/newsroom/irs-announces-waiver-of-dyed-fuel-penalty-in-florida-due-to-hurricane-dorian > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 5. Removing the requirement that motor vehicle diesel fuel be free of red dye. [EPA-HQ-OAR- 2018-0227-0061-A1, p.2] > Petroleum Marketers Association of America (PMAA) ULSD. Heating Oil. Diesel Fuel. Recertification PMAA supports the EPA's proposals to simplify the downstream recertification of distillates, removal of outdated provisions in the ULSD regulations and elimination of the prohibition 92 ------- against the presence of red dye in motor vehicle diesel fuel. [EPA-HQ-OAR-2018-0227-0083- Al, p.3] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Ultra-Low Sulfur Diesel & Red Dye Provided the Agency can provide assurances that removing the red dye restriction for ultralow sulfur diesel ("ULSD") would not trigger unintended policy consequences, the Associations support this change as well.7 This proposed change should enhance product fungibility by permitting fuel marketers to re-designate ultra-low sulfur heating oil ("ULSHO") to USLD without recertification, which will provide the industry with greater flexibility to supply consumers with product when supplies of highway diesel fuel are constricted. [EPA-HQ-OAR- 2018-0227-0066-A1, p.4] It is noted, however, that removing this restriction could potentially trigger unintended consequences. First, diesel fuel that contains red dye is generally not subject to the diesel excise tax; EPA should receive assurances from the Internal Revenue Service ("IRS") that removing the red dye restriction will not enable market participants to circumvent excise tax liability. Second, because heating oil does not trigger renewable volume obligations for obligated parties under the RFS, EPA must ensure that this requirement will not enable obligated parties to artificially lower their RVOs by simply re-designating heating oil as ULSD. The Associations only support removing the red dye restriction if EPA can ensure these potential unintended consequences will not be realized. [EPA-HQ-OAR-2018-0227-0066-A1, p.4] 7 See generally, Proposal, supra note 1, at 29054 and § 1090.1170. Response: The need for EPA to assess emergency fuel waivers in the event of things such as hurricanes will continue, and we will continue to work with our state and federal partners in making those decisions. In this particular case, the process can be streamlined by eliminating what is now an unnecessary EPA requirement. EPA has informed the IRS about our action to eliminate the red dye requirement from the EPA's fuels regulations. The action also does not change how obligated parties determine RVOs under the RFS program. The RFS regulations under part 80 specify provisions for obligated parties to account for distillate fuels that are certified as NTDF in RVOs.15 15 See §80.1408. 93 ------- 7.3. Annex VI Marine Fuel Standards Comment: > Eversheds Sutherland (US) LLP Marine Fuel Under the distillate global marine fuel exemption, fuel not meeting the requirements should not be subject to the standards for ULSD, as proposed,25 but instead to the standards for ECA Marine Fuel. ULSD is a wholly different market, while ECA Marine Fuel and distillate global marine fuel are both bunker fuels. It is very onerous to find that fuel not complying with a 5000 ppm standard for exemption purposes is actually subject to a 15 ppm standard—and presumably onerous and disproportionate penalties could follow. This proposal also is not logical—a bunker fuel exceeding the 5000 ppm standard will not inadvertently be sold into the ULSD market; it is likewise highly unlikely it would be sold into the ECA Marine Fuel market, but the marine fuels are obviously much more analogous. [EPA-HQ-OAR-2018-0227-0076-A1, p.8] Response: Under part 1090, we did not propose to change the distillate global marine fuel exemption from part 80, which notes that the MVNRLM diesel fuel standard applies if a party fails to meet the conditions of the distillate global marine fuel exemption.16 The MVNRLM diesel fuel standards under part 80 are the same as the ULSD standards under part 1090. We also believe that by making exempt fuels otherwise subject to a more stringent standard, parties will have a stronger incentive to adhere to the conditions of the exemption to ensure that non-exempt fuel is not contaminated by exempt fuel and that exempt fuel will not be used in vehicles and engines for which such fuel is inappropriate. Therefore, we are finalizing the distillate global marine fuel exemption as proposed. 16 See §80.605. 94 ------- 8. Transmix and Pipeline Interface Provisions (Subpart F) 8.1. General Comments Comment: > Marathon Petroleum Company LP (MPC) Gasoline produced from blending transmix into PCG 1090.505(d) Any transmix blender may petition EPA for approval of a quality assurance program that does not include the minimum sampling and testing requirements in paragraph (c) of this section. To seek approval for such an alternative quality assurance program, the transmix blender must submit a petition to EPA that includes all the following: The rule does not address Quality Assurance Plans that have already been approved by EPA and are currently in use. It should clarify that previously submitted and approved plans stay in effect. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] Response: As discussed in Section III.C of the preamble, prior approvals under part 80 do not need to be reapproved by EPA under part 1090. This includes quality assurance plans for transmix blenders approved under part 80 as described by the commenter. Comment: > Valero Energy Corporation Also, this rulemaking presents an opportunity to clarify an ambiguity in the rules suggesting that refineries are ineligible to exclude the gasoline or diesel portion of transmix from their renewable volume obligations ("RVOs") due to the manner in which terms cross-referenced in the Renewable Fuel Standard regulations are defined in the fuel standard regulations. [EPA-HQ- OAR-2018-0227-0056-A1, p.2] D. Corrections to Cross-References Compelling Double-Counting of Transmix Under RFS at Refineries That Process Transmix EPA proposes to modify 40 CFR §80.1407(f)(7) to update cross-references to definitions related to transmix processing that are being relocated to Part 1090. Consistent with §80.1407(c)'s directive against double-counting, Valero requests that EPA provide additional clarification in §80.1407(f) or in the cross-referenced definitions of "transmix processor" and "transmix processing facility" to ensure that transmix processed at crude oil refineries is not double- counted for purposes of calculating refineries' renewable volume obligations. 95 ------- Section 80.1407(f)(7) of the Renewable Fuel Standard (RFS) regulations include a provision that allows transmix processors and transmix blenders to exclude the gasoline or diesel portion of transmix from their renewable volume obligations ("RVOs"). The purpose of this provision is to prevent double-counting of volumes that have already been included in the RVO for the refiner that originally produced the gasoline and diesel that comprises the transmix. This exclusion is consistent with the proviso of §80.1407(c) that volumes of gasoline and diesel should not be double-counted for purposes of calculating RVOs. However, petroleum refineries that accept volumes of transmix for reprocessing appear to be ineligible to make this exclusion due to the manner in which defined terms from the fuel standards regulations are cross-referenced in the RFS regulations. Specifically, the transmix processer RVO exclusion provision in the RFS regulations cross-references the definition of "transmix processor" from §80.84 as someone who operates a transmix processing facility, which in turn is defined as "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." The regulatory history of the "transmix processing facility" definition suggests that the purpose of excluding refiners from being considered transmix processors was to avoid creating a loophole that would allow refiners to avoid certain obligations under the antidumping regulations; it had nothing to do with the RFS regulations. Further, the regulatory history of the RFS transmix exclusion does not suggest any rational basis for allowing transmix to be excluded from RVO calculations unless it happens to be processed at a facility that also processes crude oil, nor is there any discussion of why crude oil refiners are not supposed to double-count volumes of gasoline and diesel unless those volumes are attributable to transmix. Valero's research has not revealed any indication that this scenario was considered at all. Thus, it appears that allowing transmix to be excluded from RVOs to avoid double counting unless it is processed at a petroleum refinery is an arbitrary and perhaps unforeseen consequence of defining terms by cross-reference to other parts of the regulation. Finalizing the currently proposed rules will perpetuate this ambiguity in the rules between the directive not to double- count volumes in §80.1407(c) and the limitation against refiners relying on the transmix processing exclusion in §80.1407(f)(7). Valero suggests that this ambiguity be remedied by amending §80.1407(f)(7) as follows: Transmix gasoline product (as defined in 40 CFR §1090.80) and transmix distillate product (as defined in 40 CFR §1090.80) produced by a transmix processor, and transmix blended into gasoline or diesel fuel by a transmix blender under 40 CFR §1090.505. and transmix (as defined in 40 CFR §1090.80) that is reprocessed at a petroleum refinery; [EPA-HQ-QAR-2018-0227- 0056-A1, pp.5-6] Response: The transmix provisions under part 1090 do not change who may exclude the gasoline or diesel portion of transmix from their RVOs under the RFS program in part 80. As we noted in the 96 ------- preamble to the proposed rule, we are treating comments that suggest substantive changes to the RFS program as outside the scope of this rulemaking. 97 ------- 8.2. Gasoline Produced from TGP Comment: > Shell Oil Products US Transmix: The proposed revisions to section 1090.905 contemplate only a scenario where TGP is utilized by the owner of the transmix processing unit that produced the TGP. This proposal overlooks the possibility of the TGP being sold as a blendstock to a blender/refiner for use in producing gasoline for the market. The proposed regulations should be revised to take this situation into account. [EPA-HQ-OAR-2018-0227-0035-A1, pp.1-2] Response: We have revised §1090.505 to allow TGP to be used by blending manufacturers and accounted for in the same way that blending manufacturers account for PCG. We have also revised related reporting, designation, PTD, recordkeeping, and testing provisions. 98 ------- 8.3. ULSD Produced from TDP Comment: > Magellan Midstream Partners §1090.515 ULSD produced from TDP We encourage EPA to change the title of this section as follows: "ULSD Distillate Fuels produced from TDP or transmix". Except as provided in 1090.520, transmix processors and transmix blenders must demonstrate that each batch of distillate fuels (to include locomotive/marine) produced from transmix or TDP meets the applicable standards by measuring the sulfur content of each batch in accordance with subpart M of this part. [EPA-HQ-OAR-2018-0227-0078-A1, p.4] Response: We have revised §1090.510 to address the commenter's concerns. 99 ------- 8.4. 500 ppm LM Diesel Fuel Produced from Transmix Comment: > CITGO Petroleum Corporation (CITGO) 4.3 Volume Determination In §1090.520, parties that handle 500 ppm LM diesel fuel must confirm that any increase in the volume of 500 ppm delivered compared to the volume received is completely attributable to one or more of the following: • Normal pipeline interface cutting practices under (e) (1) of this section. • Thermal expansion due to a temperature difference between the times when the volume of 500 ppm LM diesel fuel received and the volume of 500 ppm LM diesel fuel delivered were measured. • The addition of ULSD to a retail outlet or WPC 500 ppm LM diesel fuel storage tank under paragraph (e) (2). Clarity is needed relative to gross versus net measurement. If measurement is expected to be net as is presumed to be the case, then thermal expansion should not be considered as a valid reason for volume difference since volumes are already temperature corrected to 60 degrees. [EPA-HQ- OAR-2018-0227-0054-A1, p.15] Response: We have removed proposed §1090.520(c). Since part 1090 requires all volume measurements to be temperature adjusted, thermal expansion should not be considered a valid reason for volume differences. Comment: > bp America Inc. (bp) Subpart F—Transmix and Pipeline Interface Provisions §1090.515(c) Does Not Exist There is a reference to §1090.515(c) on page 29061 of the preamble in the section addressing facilities that need to be registered with EPA. However, there is no such provision in the proposed regulatory text. If EPA provides a similar discussion in the final rule, bp requests that this typo be corrected. [EPA-HQ-OAR-2018-0227-0046-A1, pp.2-3] Response: We have corrected the error in the final rule preamble. 100 ------- 8.5. Pipeline Interface Comment: > Magellan Midstream Partners §1090.525 Handling practices for pipeline interface that is not transmix We believe paragraph (b) of this section should be removed. The cut procedure described in 525(a) should apply year round. Based on the example of RFG and conventional product being transported as adjacent pipeline batches, since RFG compliance is going to be based on the RVP and there is no apparent prohibition to blend conventional product into RFG as long as the RVP requirements are met at the point of custody transfer, we believe that it is not relevant if a portion of the conventional gasoline contained within the interface is cut into RFG. The ramifications of cutting the entire interface into the conventional gasoline (lesser economic value) would result in a physical shortage of RFG, which must be recovered through purchase of additional RFG by the pipeline or the shipper. It will add an undue expense to summer gasoline and potentially negatively impact supply of RFG. "§ 1090.525 Year round handling practices for pipeline interface that is not transmix. (a) Subject to the limitations in paragraph (b) of this section, pipeline operators may cut pipeline interface from two batches of gasoline subject to EPA standards that are shipped adjacent to each other by pipeline into either or both these batches of gasoline provided that this action does not cause or contribute to a violation of the standards in this part. (b) During the summer season, pipeline operators may not cut pipeline interface from two batches of gasoline subject to different RVP standards that are shipped adjacent to each other by pipeline into the gasoline batch that is subject to the more stringent RVP standard. For example, during the summer season, pipeline operators may not cut pipeline interface from a batch of RFG shipped adjacent to a batch of conventional gasoline into the batch of RFC." [EPA-HQ-OAR- 2018-0227-0078-A1, p.5] Response: We believe that the proposed pipeline handling practices are consistent with the general approach set forth in part 80 and will help to prevent the sale and distribution of gasoline that exceeds the RVP standards. Accordingly, we are finalizing these provisions as proposed. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 101 ------- 1090.505 Comment: Subpart F—Transmix and Pipeline Interface Provisions §1090.505(c) Transmix blenders must follow the requirements in §1090.505 including the quality assurance program requirements in §1090.505(c) (2). That provision allows in-line samples as a part of the quality assurance program if the requirements in (d) (2) are followed. The latter provision further cross-references §1090.1315 which sets forth the requirements for in-line blending petitions. In other words, transmix blenders who collect their quality assurance samples in-line need to obtain an in-line blending waiver which requires the submission of a detailed in-line blending petition. Under EPA's current rules for transmix blenders, it does not require an in-line blending petition if the transmix blender takes at least two quality control samples each month. EPA currently requires transmix blenders who use computer controlled in-line blending systems to conduct a quality assurance program that includes a minimum of two composite samples per month. §80.84 (d) (2) (ii). However, if transmix blenders who conduct in-line blending desire to sample less than the minimum two composite samples per month, they are required to submit an in-line blending petition to EPA. §80.84(d) (3) (ii). The Associations request that EPA maintain this reasonable distinction in the Streamlining rules. As EPA is aware, transmix blending involves the addition of small amounts of distillates and/or gasoline into pipelines. In the case of transmix blending with PCG, the final transmix-blended gasoline endpoint must not exceed 437°F. Transmix blenders can assure that the final-transmix blended gasoline does not exceed 437 degrees Fahrenheit by monitoring all PCG entering the pipeline, limiting the diesel endpoint for all shippers, and routinely sampling and testing the transmix tanks for distillation endpoint. That parameter along with the required written quality assurance program are sufficient to assure that the resulting gasoline meets RVP, sulfur, and benzene specifications for the reasons provided below. First, the gasoline component of the transmix is already required to meet RVP specifications for that season by pipeline specifications, state laws requiring adherence to ASTM D4814, and EPA RVP requirements. Any distillate blended with that transmix would have the effect of lowering and not raising the RVP because of its inherently lower vapor pressure. Therefore, given the very limited amount of transmix being blended into the PCG along with these considerations assures that the EPA RVP requirements are met during the summer season. Second, for a similar reason the gasoline component of the transmix is already required to meet benzene requirements. The distillate component is unlikely to have benzene because light ends such as benzene are absent in distillates. Again, considering the small amounts of transmix blended into the PCG and these additional factors, achieving the benzene standard for the blended batch is assured. 102 ------- Finally, the PCG is already required to be compliant with EPA sulfur limits and pipeline specifications. Also, the transmix blender's written quality assurance program includes sulfur content oversight to provide confidence that the final transmix-blended gasoline sulfur meets the downstream sulfur standard. For example, the QA program will have a process to periodically check the transmix tanks and monitor inbound PCG (e.g., reviewing the manufacturer's certificate of analysis) for sulfur and make adjustments to the transmix injection plan as needed to assure conformance. In addition, transmix blenders have a detailed knowledge of the specifications of the products they are handling and how those might impact transmix blended gasoline, all of which is factored into setting the transmix injection rate. The volume of any distillate component that might contribute sulfur to the blend is also limited by the 437°F distillation endpoint of the final transmix-blended gasoline which assures that the quantity of distillate in the transmix is sufficiently limited to achieve EPA's sulfur specification. Compliance with the EPA sulfur specification is further assured by the small quantity of transmix added to the PCG. Considering all of the factors above, achieving EPA's gasoline specifications for the transmix/PCG blend is assured. Therefore, the added burden of obtaining an in-line blending waiver as a part of the transmix blending process is not necessary to assure that EPA's gasoline specifications are met. We suggest that EPA make the following edits to the proposed regulations: Recommended Regulatory Text Edits: 1090.505 (c)(2): For transmix that is blended by a computer controlled in-line blending system, the transmix blender must collect composite samples of the final transmix-blended gasoline at least twice each calendar month during which transmix is blended. In line samples may be collected to comply with the requirements of this paragraph if the applicable requirements in paragraph (d) (2) of this section arc met. 1090.1315(b): Waivers granted under 40 CFR part 80 are no longer valid. Any party who received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under the waiver until January 1, 2022. Any party who had not previously been required to obtain an in-line blending waiver may continue to operate under 40 CFR 80 until January 1. 2022. To obtain a waiver under this part, submit a request signed by the RCO to EPA with the following information. [EPA-HQ-OAR-2018-0227-0074-A1, p.35-37] > bp America Inc. (bp) 51090.505 (c) Transmix blenders must follow the requirements in §1090.505 including the quality assurance program requirements in §1090.505(c) (2). That provision allows in-line samples as a part of the quality assurance program if the requirements in (d) (2) are followed. The latter provision further cross-references §1090.1315 which sets forth the requirements for in-line blending petitions. In 103 ------- other words, transmix blenders who collect their quality assurance samples in-line need to obtain an in-line blending waiver which requires the submission of a detailed in-line blending petition. Under EPA's current rules for transmix blenders, it does not require an in-line blending petition if the transmix blender takes at least two quality control samples each month. EPA currently requires transmix blenders who use computer controlled in-line blending systems to conduct a quality assurance program that includes a minimum of two composite samples per month. §80.84 (d) (2) (ii). However, if transmix blenders who conduct in-line blending desire to sample less than the minimum two composite samples per month, they are required to submit an in-line blending petition to EPA. §80.84(d)(3) (ii). bp requests that EPA maintain this reasonable distinction in the Streamlining Rule. As EPA is aware, transmix blending involves the addition of small amounts of distillates and/or gasoline into pipelines. In the case of transmix blending with PCG, the final transmix-blended gasoline endpoint must not exceed 437°F. Transmix blenders can assure that the final-transmix blended gasoline does not exceed 437 degrees Fahrenheit by monitoring all PCG entering the pipeline, limiting the diesel endpoint for all shippers, and routinely sampling and testing the transmix tanks for distillation endpoint. That parameter along with the required written quality assurance program are sufficient to assure that the resulting gasoline meets RVP, sulfur, and benzene specifications for the reasons provided below. First, the gasoline component of the transmix is already required to meet RVP specifications for that season by pipeline specifications, state laws requiring adherence to ASTM D4814, and EPA RVP requirements. Any distillate blended with that transmix would have the effect of lowering and not raising the RVP because of its inherently lower vapor pressure. Therefore, given the very limited amount of transmix being blended into the PCG along with these considerations assures that the EPA RVP requirements are met during the summer season. Second, for a similar reason the gasoline component of the transmix is already required to meet benzene requirements. The distillate component is unlikely to have benzene because light ends such as benzene are absent in distillates. Again, considering the small amounts of transmix blended into the PCG and these additional factors, achieving the benzene standard for the blended batch is assured. Finally, the PCG is already required to be compliant with EPA sulfur limits and pipeline specifications. Also, the transmix blender's written quality assurance program includes sulfur content oversight to provide confidence that the final transmix-blended gasoline sulfur meets the downstream sulfur standard. For example, the QA program will have a process to periodically check the transmix tanks and monitor inbound PCG (e.g., reviewing the manufacturer's certificate of analysis) for sulfur and make adjustments to the transmix injection plan as needed to assure conformance. In addition, transmix blenders have a detailed knowledge of the specifications of the products they are handling and how those might impact transmix blended gasoline, all of which is factored into setting the transmix injection rate. The volume of any distillate component that might contribute sulfur to the blend is also limited by the 437°F distillation endpoint of the final 104 ------- transmix-blended gasoline which assures that the quantity of distillate in the transmix is sufficiently limited to achieve EPA's sulfur specification. Compliance with the EPA sulfur specification is further assured by the small quantity of transmix added to the PCG. Considering all of the factors above, achieving EPA's gasoline specifications for the transmix/PCG blend is assured. Therefore, the added burden of obtaining an in-line blending waiver as a part of the transmix blending process is not necessary to assure that EPA's gasoline specifications are met. BP is also concerned about the requirement to take 9,604 samples that would be imposed on transmix blenders with inline autocompositors by §1090.1315(b) (2). That provision requires compliance with ASTM D4177. Part II of the ASTM standard requires the taking of 9,604 samples per batch. However, that part applies to crude oil shipments not refined products. Refined products are addressed in Part III of that ASTM standard and do not require that many samples. In addition, transmix blenders typically inject transmix only into a portion of a batch not the entire volume. That is necessary since pipeline operators need to consider the quality of the pipeline interface which is less suitable for transmix blending than the rest of the batch. That reduces the volume into which the transmix can be injected thereby limiting the number of samples that can be feasibly taken using available technology. That makes the collection of 9,604 samples even more difficult, bp recommends that this provision clarify in-line blenders are subject to Part III of ASTM D4177 and not Part II. (Note, a more detailed discussion of the applicability of D4177 to refined product sampling can be found elsewhere in bp's comments.) In addition, the transmix blending process is much simpler than refining gasoline at a refinery and in combination with the quality assurance program described in §1090.505(b) provides a high degree of assurance that EPA's gasoline specifications will be met. bp requests that EPA remove the in-line blending requirement under §1090.505(c) (2). If EPA decides to include the in-line blending petition requirement for transmix blenders, we request that the petition be simplified to fit the nature of the transmix blending operation and that the initial petition not be required before January 1, 2022. bp suggests that EPA make the following edits to the proposed regulations: 1090.505 (c)(2): For transmix that is blended by a computer controlled in-line blending system, the transmix blender must collect composite samples of the final transmix-blended gasoline at least twice each calendar month during which transmix is blended. In line samples may be collected to comply with the requirements of this paragraph if the applicable requirements in paragraph (d) (2) of this section are met. 1090.1315(b): Waivers granted under 40 CFR part 80 are no longer valid. Any party who received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under the waiver until January 1, 2022. Any party who had not previously been required to obtain an in-line blending waiver may continue to operate under 40 CFR 80 until January 1, 2022. To 105 ------- obtain a waiver under this part, submit a request signed by the RCO to EPA with the following information: [EPA-HQ-OAR-2018-0227-0046-A1, pp.3-5] Response: We have provided a more flexible approach to in-line transmix blending systems in part 1090, consistent the current requirements at §80.84. 106 ------- 9. Exemptions, Hardships, and Special Provisions (Subpart G) 9.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.615(e) Any party that transports fuel exempt under this section must take reasonable precautions to avoid the contamination of nonexempt fuel. For example, parties should prepare tanker trucks under API recommended practice 1595 or the Energy Institute & Joint Inspection Group standard 1530 to avoid contamination of nonexempt fuel when the same tanker truck is used to transport exempt and nonexempt fuels. Comment: Associations recommend removing all example "references" to external guidance documents within regulations as these documents may change and are not incorporated by reference. Appropriate to leave in Preamble. [EPA-HQ-OAR-2018-0227-0074-A1, p.32] Response: We had proposed the new regulatory language at §1090.615(e) in order to avoid contamination of motor vehicle fuels with lead. However, as discussed in Section VI.A of the preamble, we have concluded that the proposed provision was superfluous with the existing requirement now in §1090.615(c), so we are removing the paragraph entirely, not just the example references highlighted by the commenter. We believe that the requirement to keep exempt fuels completely segregated from non-exempt fuels is adequate to avoid contamination of the nonexempt fuels. Comment: > bp America Inc. (bp) Subpart G—Exemptions. Hardships, and Special Provisions §1090.610 §1090.610(e) (2) indicates that the R&D exemption expires at the completion of the test program or one year, whichever occurs first, and requires reapplication for the exemption. The existing 107 ------- gasoline sulfur rule in 40 CFR §80.1656(e) (2) indicates that the exemption expires at the completion of the test program or three years, whichever occurs first. There is no expiration date for the diesel fuel R&D exemptions in 40 CFR §80.607 — just a requirement to inform the agency when the test program is completed. Usually R&D programs are multiyear or perpetual while the relevant details concerning the fuel used do not change. Requiring reapplication too frequently will result in the resubmission of information that has not changed since the previous exemption request. That will impose unnecessary burdens both on parties and the agency without a commensurate benefit. If any of the details in the exemption request have changed, the petitioner is required to immediately notify EPA of the change by §1090.610(e)(4). That is a better way of updating exemption requests than automatically requiring a renewal each year. Also, given the delays in EPA's approvals of such exemption requests and the uncertainty that entails for the regulated party, including potential interruption of R&D activities, the agency should assure such programs extend for the duration of the test program or three years, whichever occurs first, not one year maximum. According to §1090.610(e) (4), if any information submitted along with the R&D exemption request changes after EPA's approval, the regulated party must notify the EPA immediately. Otherwise the exemption is void ab initio. In a large organization like bp responsibilities for various aspects of a research program are dispersed among numerous individuals and sometimes multiple countries. The information flow although timely may not be "immediate". Furthermore, it will take time for that information to reach the person charged with updating the R&D exemption renewals and updates. This provision should be qualified so that it applies to changes that are material, and the regulated party should be given at least 30 days to notify EPA of those changes. [EPA-HQ-OAR-2018-0227-0046-A1, pp.5] Response: We believe that three years is too long of a time period to grant an R&D exemption, and that an annual renewal of the exemption will prevent parties from inappropriately using the R&D test exemption to avoid meeting fuel quality standards. We also believe that annual resubmissions that largely mirror previously approved R&D testing exemptions will require minimal review time and should not be burdensome to submit and approve. Regarding the comments on immediate notification of changes to an EPA-approved R&D exemption, we believe that this requirement is appropriate because it relates to the terms and conditions under which the R&D test fuel was exempted from the standards. Exemption from the standards was premised on the information presented in the R&D exemption application, and any deviation could result in the R&D test exemption being revoked due to the submission of false, misleading, or inaccurate information. Furthermore, this is not a change from the part 80 regulations.17 For these reasons, we are finalizing this provision as proposed. 17 See §80.1656. 108 ------- Comment: > bp America Inc. (bp) Subpart G—Exemptions. Hardships, and Special Provisions §1090.615 The exception mentioned at the end of the exemption for aviation and racing fuels in §1090.615(d) indicates that an approved use is in sanctioned racing events but fails to mention aviation. Since that is a use permitted by this exemption, it would be appropriate to reference it at the end of this paragraph. [EPA-HQ-OAR-2018-0227-0046-A1, pp.5-6] Response: We have revised §1090.615(d) to indicate that aviation fuel can be made available for use in aircraft. Comment: > bp America Inc. (bp) Subpart G—Exemptions. Hardships, and Special Provisions §1090.635 bp would appreciate a clarification of the hardship provision in §1090.635. That provision would apply in extreme, unusual, and unforeseen circumstances such as natural disasters (e.g., hurricanes). These circumstances are already addressed in §211 of the Clean Air Act (CAA) (42 USC 7545(c) (4) (ii) and (iii)) which sets forth almost identical criteria for granting a waiver. 42 USC 7545(c) (4) (v) prohibits the imposition of penalties for actions taken pursuant to a waiver issued under this provision: "Nothing in this subparagraph shall. . . subject any . . . person to an enforcement action, penalties, or liability solely arising from actions taken pursuant to the issuance of a waiver under this subparagraph." bp suggests that EPA clarify in the preamble to the final rules the distinction between the natural disaster hardship provision in §1090.635 and the similar circumstances addressed in §211 of the CAA. That distinction is important since the CAA prohibits the imposition of penalties for reliance on a waiver while §1090.635(a) (3)-(5) would require the refiner to offset the air quality detriment and pay a penalty covering the economic benefit. [EPA-HQ-OAR-2018-0227-0046-A1, pp.6] Response: The commenter fails to account for CAA section 211 (c) (4) (C) (v) (I), which states that nothing in CAA section 211 (c) (4) "shall limit of otherwise affect the application of any other waiver authority of the Administrator pursuant to this section or pursuant to a regulation promulgated 109 ------- pursuant to this sectionf.]" Thus, CAA section 211 (c) (4) (C) (v) (II) does not limit EPA's ability to impose penalties as described in §1090.635. Additionally, CAA section 211 (c) (4) (C) (v) (II) states that the limitation applies to "an enforcement action, penalties, or liability solely arising from actions taken pursuant to the issuance of a waiver under this subparagraph." (emphasis added). For these reasons, the limitation of CAA section 211 (c) (4) (C) (v) (II) does not apply to waivers issued pursuant to §1090.635. Comment: > bp America Inc. (bp) Subpart G—Exemptions. Hardships, and Special Provisions §1090.645 bp suggests that EPA provide some added flexibility for changed circumstances in fuel markets or unexpected situations that arise that would allow downstream parties to redesignate fuels for export for domestic use. As written, this provision will not accommodate those changes, bp believes that the exemption for exports in §1090.645 should be modified to allow the domestic sale of fuels originally designated for export if the party who redesignates the fuel for sale in the US is registered as a fuel manufacturer, reports all of the required properties to EPA, incurs the renewable volume obligation, and otherwise complies with the fuel manufacturer requirements. [EPA-HQ-OAR-2018-0227-0046-A1, p.7] Response: We revised §1090.645(d) to add flexibility as the commenter suggested. Comment: > bp America Inc. (bp) The benzene and sulfur deficit carryforward provisions should provide adequate flexibility to gasoline manufacturers who can be affected by unplanned shutdowns and natural disasters which could impact credit and deficit generation. In addition, those provisions should be clarified to eliminate ambiguities which could impact the smooth functioning of the sulfur and benzene credit markets. [EPA-HQ-OAR-2018-0227-0046-A1, p.2] Subpart H—Averaging. Banking, and Trading Provisions §1090.715-Deficit Carryforward At the beginning of a compliance period, gasoline manufacturers develop and implement fuel production plans for each of their fuel manufacturing facilities based on anticipated market and operating conditions. Those conditions may fluctuate during a compliance period as a result of process unit shutdowns within the facility and maintenance then e activities on these process 110 ------- units that may be critical for meeting EPA fuel requirements. External events such as natural disasters and national emergencies can also affect gasoline manufacturers' fuel production plans. As a result, a gasoline manufacturer may need one of its fuel manufacturing facilities to incur a compliance deficit carryover for benzene or sulfur, which EPA currently provides in Subparts L and 0 of Part 80. EPA already provides some relief to refiners in the benzene regulations in the event they experience hardship conditions. In that case EPA may allow an extended period of deficit carryforward under the benzene hardship provisions. §80.1230(c) (3). As described above and as EPA recognized with the extended period of deficit carry-forward in the benzene standard, relief may be appropriate if hardship conditions are experienced, bp recommends that EPA provide a similar opportunity for hardship relief in the Streamlining Rule by allowing fuel manufacturers to request such relief under §1090.635. As noted in §1090.705(a), compliance with the sulfur and benzene average standards is determined at the facility level. In addition, the proposed deficit carryfoward provision in §1090.715 consolidates the gasoline sulfur and benzene deficit carryforward provisions from Part 80 into a single carryforward provision. However, the proposed provision is written ambiguously where it is difficult to understand EPA's intention that an individual fuel manufacturing facility may carryforward a deficit for a compliance period as long as the facility obtains credits to offset this deficit during the next compliance period, bp believes that careful use of the terms "fuel manufacturing facility" and "gasoline manufacturer" would clarify this ambiguity. In order for the deficit carryfoward provision to be clearer and remain consistent with the current benzene and sulfur deficit carryforward provisions provided in §80.1230(c) and §80.1605(a), respectively, it is recommended that the following edits (in red text below) be made to 1090.715. §1090.715 Deficit carryforward. (a) A gasoline manufacturer's fuel manufacturing facility incurs a compliance deficit if they it exceeds 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 (ab) (2) of this section for benzene.1 (b) Gasoline manufacturers must use all sulfur or benzene credits previously generated or obtained at any of their facilities to achieve compliance A fuel manufacturing facility may incur a deficit for with an average standard specified in subpart C of this part before carrying forward a sulfur or benzene deficit at any of their facilities, for a given compliance period provided it did not incur a deficit for that average standard during the previous compliance period. (c) A Cgasoline manufacturers that incurs a deficit under this section for one of its fuel manufacturing facilities during a given compliance period must: satisfy that 111 ------- (1) obtain and use sufficient credits to offset the deficit for that fuel manufacturing facility during the next compliance period regardless of whether the gasoline manufacturer fuel manufacturing facility produces gasoline during the next compliance periodr, and (2) achieve compliance with that average standard at that fuel manufacturing facility during the next compliance period. (d) EPA may allow an extended period of deficit carryforward if it grants hardship relief under §1090.635 from an average standard specified in subpart C of this part. [EPA-HQ-OAR-2018- 0227-0046-Al.pp.7-8] 1 bp is not suggesting any changes be made to paragraphs (a) (1) and (2) in §1090.715 and has excluded them from the proposed revisions for the sake of simplicity. Response: We believe the combination of the average standards, credit provisions, and deficit carryforward provisions already provides tremendous flexibility to allow for compliance and that EPA's enforcement authority already includes the ability to allow for periods of extended deficit carry- forward where appropriate circumstances exist. Therefore, we are finalizing §1090.715 as proposed. Comment: > Chevron U.S.A., Inc. Use CARB gasoline and diesel outside of California Chevron supports the flexibility provided in 1090.625 to sell California gasoline and diesel fuel outside of California. We agree with the assessment that California gasoline and diesel meet or exceed the emissions performance of federally regulated RFG, CG and ULSD. The NPRM provides two options: 1) recertify California gasoline or diesel fuel as compliant EPA fuels, which allows participation in the Averaging, Banking, and Trading program for gasoline sulfur and benzene; or 2) re-designating these fuels for direct distribution without the ability to generate sulfur and benzene credits. Each of these options provides operational flexibility for California refiners to meet the needs of the regional fuel markets and maximize supply reliability, without impacting the environment. [EPA-HQ-OAR-2018-0227-0069-A1, p.2] Response: We thank the commenter for their support. 112 ------- Comment: > Eversheds Sutherland (US) LLP With regard to fuel that is excluded from sulfur and benzene compliance calculations, the Proposed Rule includes gasoline exempted under Subpart G such as "California gasoline, racing fuel, etc."11 Eversheds Sutherland requests that more specificity is provided to identify exactly what gasoline is exempted. The current language implies all gasoline subject to an exemption is also exempt from sulfur and benzene standards, but that may not be the case. Given the desire to streamline burdens, it make sense to clarify this language so it is clearly stated what exactly is excluded. [EPA-HQ-OAR-2018-0227-0076-A1, p.5] 11 Id. at § 1090.700(e)(6). Response: It is unclear to EPA what the commenter is suggesting. However, we have attempted to address the apparent confusion by making clarifying revisions to §1090.600. Comment: > Flint Hills Resources 2) Part 1090 subpart G - §1090.645 Exemption for exports a) Suggestion: Revise (a) as follows: (a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer designated the fuel, fuel additive, or regulated blendstock for export as specified in § 1090.1650(a). Discussion: §1090.1650(a) does not specify how export fuel is to be designated. [EPA-HQ- OAR-2018-0227-0052-A1, p.2] Response: We have removed the reference to §1090.1650(a) as the commenter suggested. Comment: > Flint Hills Resources 2) Part 1090 subpart G - §1090.645 Exemption for exports 113 ------- b) Suggestion: Revise (c) as follows: (c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps records demonstrating that the fuel, fuel additive, or regulated blendstock is ultimately exported from the United States. Discussion: We are suggesting below that certain verbiage be removed from §1090.1650(a) because it duplicates the exemption conditions in §1090.645. However, 1650(a) included a record-keeping condition that was not in 645; therefore, we suggest adding the record-keeping condition here in (c). [EPA-HQ-OAR-2018-0227-0052-A1, p.2] Response: We have made the revision to §1090.645(c) as the commenter suggested. Comment: > Small Refineries Coalition II. The Coalition Objects to EPA's Proposal to Exclude Financial and Supplier Hardship as Qualifying Events for Hardship Relief Under Certain 40 C.F.R. Part 80 Provisions. EPA is proposing to consolidate the 40 C.F.R. part 80 hardship relief provisions for "unforeseeable circumstances (e.g., a natural disaster or refinery fire) that a refinery cannot avoid with prudent planning."10 The proposal, though, does more than consolidate. It adds new language that specifically excludes "financial and supply chain hardship" as examples of "extreme, unusual and unforeseen circumstances."11 The Coalition objects to EPA's exclusion of financial and supplier hardship as qualifying events for hardship relief. Although EPA claims that the revised provision is not intended to change the opportunity for hardship or the regulated party's burden to demonstrate that it merits hardship, if finalized, the revisions would make it more difficult for refineries to receive relief, especially small refineries experiencing unforeseen financial hardship. The exclusionary language in EPA's proposal, for example, is not included as a limit on hardship relief from the current gasoline benzene program12 or the gasoline sulfur program.13 And there is good reason for that. For small refineries that depend on the credit market for compliance with the annual average gasoline benzene and sulfur standards, an extreme and unforeseen financial hardship can make it impossible to purchase the necessary compliance credits without jeopardizing the refinery's entire business. In the past, EPA has recognized the importance of provisions for unforeseen hardship as "a safety valve should all the other flexibilities provided prove insufficient."14 By consolidating the hardship provisions and excluding "financial and supply chain hardship" from consideration, EPA would be making that safety valve significantly less meaningful to the small refineries that need it the most. 114 ------- Now is not the time to raise the bar for refineries, particularly small refineries, to receive hardship relief. The COVID-19 global pandemic has led to an economic recession that has caused an unprecedented decrease in demand for refined products. For small refineries that lack economies of scale and have less access to capital and credit, limited geographic reach, and less market diversification, the downturn poses an unprecedented threat to their continued viability. To categorically remove financial and supply chain hardship from relief eligibility is contrary to the stated purposes of Clean Air Act hardship relief and unnecessarily harmful to small refineries. For these reasons, the Coalition opposes EPA's proposal to exclude financial and supplier hardship as qualifying events for hardship relief. [EPA-HQ-OAR-2018-0227-0080-A1, PP.3-4] 10 85 Fed. Reg. at 29057. 11 Id.; proposed 40 C.F.R. § 1090.635. 12 See 40 C.F.R. §§ 80.1334 80.1336. 13 See 40 C.F.R. § 80.1625. 14 Control of Air Pollution From Motor Vehicles: Tier 3 Motor Vehicle Emission and Fuel Standards, 79 Fed. Reg. 23414, 23419 (Apr. 28, 2014). Response: The commenter does not explain how the extreme, unusual, and unforeseen circumstances hardship provision of part 1090 is inconsistent with the hardship provisions of the CAA. We believe the commenter may be referring to hardship provisions for small refiners under the RFS program in CAA section 211 (o) (9), which are outside the scope of this action. If the commenter is referring to waiver authority under CAA section 211 (c) (4) (C) (ii), as discussed above, this is separate from the extreme, unusual, and unforeseen circumstances hardship provision of part 1090, which is carried over from part 80. CAA section 211 (c) (4) (C) (v) (I) also notes that nothing in CAA section 211 (c) (4) (C) shall "limit or otherwise affect the application of any other waiver authority of the Administrator pursuant to this section or pursuant to a regulation promulgated pursuant to this section." We interpret this to indicate Congressional knowledge of EPA- promulgated hardship exemption provisions under CAA section 211 (c) and that they did not intend for the emergency fuel waiver provisions in CAA section 211 (c) (4) (C) (ii) to override such provisions. We proposed to carry over the extreme, unusual, and unforeseen hardship relief provisions from part 80 to part 1090 intact. The new parenthetical language in §1090.635(a) simply provides additional clarification on the kinds of extreme, unusual, and unforeseen hardship events that have qualified a refiner for relief under this provision in part 80 and can continue to qualify a refiner for relief under this provision in part 1090. Because the standards of part 80 have been in place for several years, the upfront capital costs have been incurred and regulated parties should have compliance plans that account for the ongoing costs and supplier logistics of operating the 115 ------- refinery in a manner that also meets the applicable standards and other market specifications. Therefore, we do not, and have never, interpreted financial or supplier difficulties as qualifying hardships under the extreme, unusual, and unforeseen circumstances provision. This clarification is consistent with EPA's historic interpretation and application of the extreme, unusual, and unforeseen hardship provisions under part 80. Comment: > Valero Energy Corporation I. Exemptions. Hardships and Special Provisions Proposed §1090.625(c) is for [u]se of California test methods and offsite sampling procedures" for gasoline or diesel produced in California but that is not California gasoline or diesel. Under §1090.625(c) (1), such fuel may be sampled and tested using "methods approved in Title 13 of the California Code of Regulations instead of the sampling and testing methods required by subpart M" of Part 1090. Valero requests EPA to clarify that California sampling procedures may also be used for onsite sampling, by revising the first sentence of §1090.625(c) as follows: "Use of California sampling procedures and test methods and offsite sampling procedures." Similar to clarity already provided in §1090.625 (c)(2) (i), Valero requests EPA clarify that refiners can also use approved alternative sampling/test methods under approved protocols or executive orders with CARB, by adding these provisions to §1090.625(c)(1): • §1090.625(c) (1) (i) "In addition to methods explicitly referenced by Title 13 of the California Code of Regulations, the sampling and testing may also be conducted per a current and valid protocol agreement between the manufacturer and the California Air Resources Board or by Executive Order." • §1090.625(c) (1)(ii) "Such protocols or Executive Orders shall be provided to EPA upon request." [EPA-HQ-OAR-2018-0227-0056-A1, p.12] Response: We have revised §1090.625(c) to allow for alternative methods approved by CARB under Title 13 of the California Code of Regulations. 116 ------- 9.2. Segregation Requirements Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.7 Export Segregation EPA is transferring provisions that exempt fuels from applicable standards that are currently contained in part 80 to part 1090. EPA is also proposing minor revisions for purposes of modernizing these exemptions as well as removing obsolete exemption provisions. EPA states that any exemptions that were granted under part 80 will remain in effect with their original conditions as applicable under part 1090. As a result, instead of being scattered through various subparts as is the current practice in part 80, these provisions would be consolidated into a single subpart in part 1090 (subpart G) for all exemptions. The Associations recognize that fuels, fuel additives, and regulated blendstocks designated for export that do not comply with EPA requirements must be completely segregated throughout the production and distribution system. However, the Associations urge that fuels, fuel additives, and regulated blendstocks designated for export that comply with EPA requirements do not need to be completely segregated provided that proper accounting is conducted. [EPA-HQ-OAR-2018-0227-0074-Al,p.l7] §1090.615, §1090.620, §1090.630 and §1090.645 require segregation starting at production. Consistent with the requirements outlined in 1090.615(d), 1090.620(d), 1090.630(d), and 1090.645(d), segregation should begin at designation, shipment, or distribution from the production tank. The preamble outlines EPA's definition of "certification" and "designation," and this requirement to maintain segregation on product that is not yet designated could cause a disconnect. 10 Segregation of product at production will introduce significant logistical complications at refineries and terminals acting as fuel manufacturers through blending with limited tankage and/or space to accommodate the additional tankage needed to blend components separately. This may result in suboptimum tankage utilization, reduced blending flexibility, and ultimately reduced supply. [EPA-HQ-OAR-2018-0227-0074-A1, p.17] In many cases, the products that are produced for use in U.S. territories, Commonwealths, or export are virtually indistinguishable to products that are used in the 48 contiguous states. As such, fuel manufacturers will blend larger batches of product that are intended to ship to multiple destinations. Requiring these products to remain segregated "throughout production" will prevent manufacturers from continuing to operate in this manner, even though demonstration of compliance with all applicable regulations is easily achievable. Indeed, the same set of test data and documentation is used repeatedly for the shipments until the tank is reblended or recertified. [EPA-HQ-OAR-2018-0227-0074-A1, p. 17] One example is a tank of distillate that meets the 15 parts per million ("ppm") sulfur requirement and can be distributed as ultra-low sulfur diesel ("ULSD"), heating oil, emission control area ("ECA") marine fuel, or export diesel. In such cases the distinction is currently made at designation and distribution. This is consistent with the new definition in §80.1401 for certified 117 ------- non-transportation diesel fuel ("NTDF"), whereby distillate fuel certified and designated as meeting 15 ppm sulfur may be designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non-transportation fuel 11 on its product transfer document and not designated as motor vehicle, nonroad, locomotive or marine ("MVNRLM") diesel fuel. It is recommended, however, that for clarity of the definition that heating oil be replaced with diesel for export in the examples of "other non-transportation diesel fuel" since heating oil is already specified individually in the definition and diesel for export while included in the discussion relative to NTDF is not specifically listed. 12 The Associations believe this is needed for clarity and consistency between programs and is not a substantive change impacting the Renewable Fuel Standard program. [EPA-HQ-OAR-2018-0227-0074-A1, pp. 17-18] The Associations offer regulatory language suggestions below. §1090.615 - Racing and Aviation Exemption (c) The fuel, fuel additive, or regulated blendstock is completely segregated from all other non- exempt fuel, fuel additive, or regulated blendstock throughout production, at the point of distribution-and sale to the ultimate consumer from the point the fuel is designated for racing and aviation events. §1090.620 - Guam, America Samoa, Mariana Island Exemption (d) The fuel is completely segregated from non-exempt gasoline, diesel fuel, and IMO marine fuel at all points throughout production, the point of distribution-and sale to the ultimate consumer from the point the fuel is designated as exempt fuel for use only in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands, while the exempt fuel is in the United States (including an ECA or an ECA associated area under 40 CFR 1043.20) but outside these territories. §1090.630 - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption (d)The summer gasoline is completely segregated from non-exempt gasoline at all points throughout production, the point of distributionT and sale to the ultimate consumer from the point the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these states or territories. §1090.645 Exemption for exports of fuels, fuel additives, and regulated blendstocks. (a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer designated the fuel, fuel additive, or regulated blendstock for export, as specified in § 1090.1650(a). (c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps records demonstrating that the fuel, fuel additive, or regulated blendstock was ultimately exported from the United States. 118 ------- (d) Segregation requirement. Fuel, fuel additive, and regulated blendstock designated for export must be completely segregated from non-exempt fuel, fuel additive, and regulated blendstock at all points throughout the production and distribution system-from the point the fuels, fuel additives, and regulated blcndstocks are produced or imported to of designation and distribution from the point where fuel manufacturer through exportation from the fuels, fuel additives, and regulated blcndstocks are exported. United States. [EPA-HQ-OAR-2018-0227-0074-A1, pp. 18- 19] §1090.1650 General provisions for exporters. (a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part, provided all requirements are met as specified in §1090.645.they arc ultimately exported to a foreign country. However, such fuels must be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that the fuel is for "export only'' under subpart K of this part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all fuel intended for use in the United States. [EPA-HQ-OAR-2018-0227-0074-A1, p. 19] 10 See 85 Fed. Reg. 29066. 11 For example, jet fuel, kerosene, heating oil, No. 4 fuel. 12 See 85 Fed. Reg. 7056. > CITGO Petroleum Corporation (CITGO) 2.5 Export Segregation CITGO recognizes EPA's intent that fuel, fuel additive, and regulated blendstock that does not comply with EPA regulations must be designated for export, accompanied by a PTD, and completely segregated throughout the production and distribution system until ultimately exported from the United States. As per language in the preamble, CITGO also recognizes EPA's intent that diesel meeting the per-gallon standards in subpart D of the NPRM does not require segregation throughout the production and distribution system. However, an inconsistency exists between the preamble language and the language in §1090.645 relative to the segregation of gasoline meeting the per-gallon standards in subpart C. Per language in the preamble, EPA is transferring requirements for designation, product transfer documents, and gasoline segregation to 40 CFR part 1090; EPA is not proposing to change the required segregation for gasoline designated for export. However, no regulatory language exists in requiring segregation of gasoline meeting the per-gallon standards for export versus domestic non-exempt gasoline. If EPA's intent is to require this for gasoline but not for all fuels then language in §1090.645 and §1090.1650 must be modified to differentiate gasoline from other fuels, such as ULSD. 119 ------- Recommended language is as follows: §1090.645 Exemption for exports of fuels, fuel additives, and regulated blendstocks (a) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer designated the fuel, fuel additive, or regulated blendstock for export, as specified in § 1090.1650(a). (c) The fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer keeps records demonstrating that the fuel, fuel additive, or regulated blendstock was ultimately exported from the United States. (d) Segregation requirement. Fuel, fuel additive, and regulated blendstock All gasoline designated for export must be completely segregated from non-exempt fuel designated for domestic use-from the point the fuels, fuel additives, and regulated blendstocks arc produced or imported to of designation and distribution from the point where fuel manufacturer through exportation from the fuels, fuel additives, and regulated blendstocks arc exported. United States. §1090.1650 General provisions for exporters (a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part, provided all requirements are met as specified in §1090.645.they are ultimately exported to a foreign country. However, such fuels must be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that the fuel is for "export only'' under subpart K of this part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all fuel intended for use in the United States. [EPA-HQ-OAR-2018-0227-0054-Al.pp.7-8] Additionally, subpart G Exemptions, Hardships, and Special Provisions require segregation, when needed, starting at production. Consistent with the requirements outlined in 1090.615(d), 1090.620(d), 1090.630(d), and 1090.645(d), segregation should begin at designation and shipment/distribution from the production tank. The preamble outlines EPA's definition of "certification" and "designation," and this requirement to maintain segregation on product that is not yet designated could cause a disconnect. Segregation of products at production will introduce significant logistical complications at refineries and terminals acting as fuel manufacturers through blending with limited tankage and/or space to accommodate the additional tankage needed to blend components separately. In many cases, the products that are produced for use in U.S. territories, Commonwealths, or export are virtually indistinguishable to products that are used in the 48 contiguous states. As such, fuel manufacturers will blend larger batches of product that are intended to ship to multiple destinations. Requiring these products to remain segregated "throughout production" will prevent manufacturers from continuing to operate in this manner, even though demonstration of compliance with all applicable regulations is easily achievable. Indeed, the same set of test data and documentation is used repeatedly for the shipments until the tank is reblended or recertified. 120 ------- One example is a tank of distillate that meets the 15 parts per million ("ppm") sulfur requirement and can be distributed as ultra-low sulfur diesel ("ULSD"), heating oil, emission control area ("ECA") marine fuel, or export diesel. In such cases the distinction is currently made at designation and shipment/distribution. This is consistent with the new definition in §80.1401 for certified non-transportation diesel fuel ("NTDF"), whereby distillate fuel certified and designated as meeting 15 ppm sulfur may be designated as 15 ppm heating oil, 15 ppm ECA marine fuel, or other non-transportation fuel on its product transfer document and not designated as motor vehicle, non-road, locomotive or marine ("MVNRLM") diesel fuel. As previously noted, it is recommended that for clarity of the definition that heating oil be replaced with diesel for export in the examples of "other non-transportation diesel fuel" since heating oil is already specified individually in the definition. Diesel for export while included in the discussion relative to NTDF is not specifically listed. This is needed for clarity and consistency between programs and not a substantive change impacting the Renewable Fuel Standard program. Existing citations can easily be modified as follows: §1090.615 - Racing and Aviation Exemption (c) The fuel, fuel additive, or regulated blendstock is completely segregated from all other nonexempt fuel, fuel additive, or regulated blendstock throughout production, at the point of distribution^- and sale to the ultimate consumer from the point the fuel is designated for racing and aviation events. §1090.620 - Guam, America Samoa, Mariana Island Exemption (d) The fuel is completely segregated from non-exempt gasoline, diesel fuel, and IMO marine fuel at all points throughout production, the point of distribution-: and sale to the ultimate consumer from the point the fuel is designated as exempt fuel for use only in Guam, American Samoa, or the Commonwealth of the Northern Mariana Islands, while the exempt fuel is in the United States (including an ECA or an ECA associated area under 40 CFR 1043.20) but outside these territories. §1090.630 - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption (d) The summer gasoline is completely segregated from non-exempt gasoline at all points throughout production, the point of distributionT and sale to the ultimate consumer from the point the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these states or territories. [EPA-HQ-OAR-2018-0227-0054-A1, pp.8-10] > Eversheds Sutherland (US) LLP Exports The Proposed Rule allows for fuel designated for export by a fuel manufacturer to be exempt from the standards, provided the fuels are ultimately exported. The proposed regulations state 121 ------- that such fuels must be designated at the fuel manufacturing facility and accompanied by PTDs stating "for export only" and records must be maintained to demonstrate the fuel was exported.35 EPA should allow for any fuel designated downstream as "for export only" to be exempt from fuel standards at that point; such designation should not be limited to occurring at the fuel manufacturing facility. Once designated as "for export only" the fuel will be segregated from fuel designated for domestic use, and it may be commingled with other fuel for export that does not meet Part 1090 standards. Under a strict reading of the proposed language, this would be a standards violation despite the export designation, which is nonsensical. The final rule should be amended to prevent this outcome. Relatedly, segregation of fuel for export from domestic barrels is not necessary if contamination does not occur. The tracking of fuel volumes allows for other product with the same properties to be commingled even if designations are different. Heating oil and ULSD are prime examples of fuel with different designations but, if commingled, both have 15 ppm sulfur and either a minimum cetane index of 40 or a maximum aromatic content of 35 vol%. Trading entities track each barrel within a tank, with both the PTD as well as the price also providing evidence of the fuel designation. Allowing for such commingling achieves all the goals of streamlining— lowering the burden on product owners and terminals by using the most efficient approach, thus lowering the costs—as well as the environmental benefit of the need for fewer tanks to achieve the same outcome. EPA states that the Proposed Rule would not have an adverse impact on low income populations, but the need for more tankage to accommodate new segregation requirements may in fact impact the populations living closest to tank farms and terminals. EPA should provide the necessary flexibility here to allow for commingling where certificates of analysis support the belief that there would be no contamination and eliminate the proposed requirement to segregate. [EPA-HQ-OAR-2018-0227-0076-A1, p.11] Exemptions Our concerns about exported fuel are discussed above in Section 2.8. EPA should adopt a consistent approach and thus consistent language for exemptions that require segregation. The exemption for territories calls for segregation "from the point the fuel is designated as exempt fuel."51 This same language should be incorporated into all of the exemptions—national security and military use;52 temporary research, development, and testing;53 racing and aviation;54 California gasoline and diesel;55 exports;56 and global marine fuel.57 However, the requirement that segregation occurs "at all points throughout production"58 should be removed. Designation occurs upon exit of a production or blend tank, and the proposed language would require segregation during production—a new and burdensome requirement as there is not enough physical tankage to have segregated tanks throughout production. EPA does not explain why it adopted this language in a few of the exemptions, but regardless, it will adversely impact fuel manufacturers and would result in the need for more tankage—a result EPA should avoid. [EPA- HQ-OAR-2018-0227-0076-A1, pp. 16-17] 35 Id. at § 1090.1650. 51 Id. at § 1090.620(d). 122 ------- 52 Id. at § 1090.605. 53 Id. at § 1090.610. 54 Id. at § 1090.615. 55 Id. at § 1090.625. 56 Id. at § 1090.645. 57 Id. at § 1090.650 58 Id. at §§ 1090.615; 1090.620(d); 1090.630; 1090.645. > Flint Hills Resources 2) Part 1090 subpart G - §1090.645 Exemption for exports c) Suggestion: Revise (d) and add a new (f) as follows: (d) The fuel, fuel additive, or regulated blendstock must be completely segregated from non- exempt fuels, fuel additives, and regulated blendstocks at all points throughout the production and distribution system, from the point the fuel, fuel additive, or regulated blendstock is produced or imported designated as an export product on a PTD to the point where the fuel, fuel additive, or regulated blendstock is ultimately exported from the United States. (f) The exported volume of fuel, fuel additive, or regulated blendstock is attributable to a distinct production batch certified by the fuel manufacturer, fuel additive manufacturer, or regulated blendstock producer. Discussion: Complete segregation throughout production is a very restrictive way to ensure that the properties of the very fuel exported are known. In some cases, fuel is exported that originated from a refinery tank that also contained fuel for US consumption. And, while such exported fuel was commingled with US fuel in the refinery tank, the refiner can attribute the exported fuel to a distinct batch of fuel. The refiner should be able to exclude such fuel from its part 1090 standard compliance. [EPA-HQ-OAR-2018-0227-0052-A1, pp.2-3] > Magellan Midstream Partners §1090.1650 General provisions for exporters This section was updated but still requires segregation of designated exports. We believe comingling of various batches is critically important and should be allowed in transporting, storing and distributing ULSD/Heating Oil/Diesel for Export once designated at the refinery. We believe ULSD identified as "for Export Only" downstream of the refinery is unrealistic and should not be required to be segregated. [EPA-HQ-OAR-2018-0227-0078-A1, p.9] 123 ------- > Marathon Petroleum Company LP (MPC) Exemptions for Alaska. Hawaii. Puerto Rico, and the U.S. Virgin Islands summer gasoline 1090.630(d) The summer gasoline is completely segregated from non-exempt gasoline at all points throughout production, distribution, and sale to the ultimate consumer from the point the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these states or territories. The comments here are also applicable to the following sections: 1090.615(c) - Racing and Aviation Exemption 1090.620(d) - Guam, America Samoa, Mariana Island Exemption 1090.630(d) - Alaska, Hawaii, Puerto Rico, Virgin Island Exemption 1090.645(d) - Exports Exemptions MPC proposes to eliminate the "throughout production" statement, as it creates a conflict (and confusion, at a minimum) on the expectation for how products are blended, tested and designated. This is especially true because the requirements of 1090.620(d) and 1090.630(d) further state segregation needs to be maintained from the point the product is designated, not "produced." Page FR29066 of the Preamble outlines the EPA's definition of "certification" and "designation", and this requirement to maintain segregation on product that is not yet designated will cause disconnect. Oftentimes, those products produced for use in the US territories and Commonwealths are virtually indistinguishable to products used in the 48 contiguous states of the United States. As such, fuel manufacturers will blend larger batches of product intended for shipping to multiple destinations. Requiring these products to remain segregated "throughout production" severely limits manufacturers' ability to maximize blend sizes and efficiently utilize tankage, even though demonstration of compliance with all applicable regulations is easily achievable. The same set of test data and documentation could be utilized repeatedly for such shipments until the tank is reblended or is recertified. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] Eliminate the requirement to segregate export volumes Section 1090.1650(d) states: "The fuel, fuel additive, or regulated blendstock must be completely segregated from non-exempt fuels, fuel additives, and regulated blendstocks at all points throughout the production and distribution system, from the point the fuel, fuel additive, or regulated blendstock is produced or imported to the point where the fuel, fuel additive, or regulated blendstock is ultimately exported from the United States." 124 ------- Similar language is also found in sections 1090.620(d), 1090.630(d) and 1090.645(d), respectively. Our comments below apply to all four scenarios. MPC believes that the requirement to segregate fuels "throughout production" will become a constraint on the fuel manufacturer's facility. Often, products that are produced for use in U.S. territories, Commonwealths, or export are virtually indistinguishable from those used in the 48 contiguous states. As such, fuel manufacturers will blend larger batches of product intended for shipping to multiple destinations. Requiring these products to remain segregated "throughout production" severely limits manufacturers' ability to maximize blend sizes and efficiently utilize tankage, even though demonstration of compliance with all applicable regulations is easily achievable. The same set of test data and documentation could be utilized repeatedly for such shipments until the tank is reblended or is recertified. Additionally, the language causes a potential ambiguity for when the segregation requirements apply. Per the definition outlined in the preamble, "designation" necessarily takes place after the product is produced. Because the requirements in § 1090.620(d) and § 1090.630(d) specify segregation is applicable "from the point the [fuel] is designated...", then "production" (which occurs before the product is designated) should be removed. Further, MPC believes the segregation requirements are too strict and presents severe limitations to the flexibility of the distribution system. We agree fuels, fuel additives and regulated blendstocks designated for export, and that do not comply with EPA requirements, must be completely segregated throughout the distribution system. However, we believe fuels, fuel additives and regulated blendstocks designated for export, and that also comply with EPA requirements, do not need to be completely segregated. At a minimum, diesel meeting the definition of Non-Transportation Distillate Fuel (NTDF) (as defined in §80.4101), should be exempt from the distribution system segregation requirement, as these products can be better tracked and managed through the use of accounting systems. [EPA-HQ-OAR-2018-0227-0048- Al, pp.2-3] > Shell Oil Products US P. Sections §1090.630 (d) and §1090.645 (d)- Remove Production Language Terminology from Segregation Language These sections require segregation starting at production. Tankage at refineries and terminals is limited. Tanks are dual certified for domestic and export gasoline and diesel. The material in the tank is the same but the shipments are different - pipeline and vessel for example. The same test results are used for all shipments from the tank until new material is introduced into the tank. Segregation should begin at distribution/shipments. We propose the following language: §1090.630 (d)The summer gasoline is segregated from non-exempt gasoline at the point of distribution and sale to the ultimate consumer from the point the summer gasoline is designated as exempt fuel for use only in Alaska, Hawaii, Puerto Rico, or the U.S. Virgin Islands, while the exempt summer gasoline is in the United States but outside these states or territories. 125 ------- §1090.645 (d) Segregation requirement. Fuels, fuel additives, and regulated blendstocks designated for export must be segregated from non-exempt fuels, fuel additives, and regulated blendstocks at all points of the distribution system once the material is designated/distributed as an exported fuel and is actually exported. [EPA-HQ-OAR-2018-0227-0035-A1, pp.14-15] > Valero Energy Corporation The new proposed requirement to segregate export product from production to distribution is another proposed requirement that is not consistent with existing regulations and imposes additional burdens. The new requirement is unreasonable and unnecessary. [EPA-HQ-OAR- 2018-0227-0056-A1, p.2] B. Export Segregation Proposed §1090.645(d) provides that exported fuel is exempt from EPA's fuel standards if it meets specific requirements, including the following: The fuels, fuel additive, or regulated blendstock must be completely segregated from nonexempt fuels, fuel additives, and regulated blendstocks at all points throughout the production and distribution system, from the point the fuel, fuel additive, or regulated blendstocks is produced or imported to the point where the fuel, fuel additive, or regulated blendstock is ultimately exported from the United States. Although the preamble language suggests this is simply restating existing requirements from Part 80, this is inaccurate; the existing rules in Part 80 do not require exports to be segregated from production to export in order to be exempt from domestic fuel standards. Furthermore, this rule language is at odds with EPA's statement in the preamble that the proposed export segregation requirement does not apply to fuel additives and blendstocks.1 The segregation requirement for exported fuels, fuel additives, and blendstocks is a new and burdensome requirement that is at odds with market realities. Marketing decisions are frequently made downstream from the refinery to designate products for domestic sale or for export as appropriate based on market demand. Segregation of export product which also complies with domestic fuels standards will introduce significant logistical complications at terminals with limited tankage and/or space to accommodate additional tankage. This may result in non- optimum tankage utilization, reduced gasoline blending flexibility, and ultimately gasoline supply. Valero requests that EPA strike proposed §1090.645(d). [EPA-HQ-OAR-2018-0227- 0056-A1, pp.4-5] 5. Export Segregation The proposed export segregation requirement for export fuels, fuel additives and regulated blendstocks to be exempt from the fuel standards is a new requirement and unnecessary. For the reasons discussed above, Valero urges EPA not to finalize the export segregation requirement. If this requirement is nevertheless adopted, additional time will be needed to develop the infrastructure required to provide for segregation, which may entail development of capital 126 ------- projects as well as negotiation of new or amended commercial agreements. Valero will need more than a year to undertake all that is needed to comply with this new segregation requirement. [EPA-HQ-OAR-2018-0227-0056-A1, pp.13-14] 185 FR 29056 Response: We are providing the following clarifications on the segregation requirement under part 1090. In regard to racing and aviation fuel, the exempt fuel must be segregated from the point of production due to its lead content and the risk of nonexempt fuel becoming contaminated. For all other exported fuels, we believe that segregation at the point of distribution is reasonable. Regarding the concern that we were no longer allowing the commingling of ULSD that meets applicable ULSD standards, the provisions for requiring segregation from the point of designation for export until the fuel is exported provide flexibility for ULSD to be commingled until the fuel is designated for export, as long as the fuel is certified as meeting the ULSD standards. Under §1090.1650(b), we impose no restriction on the redesignation of fuels that meet the applicable standards, including ULSD. Regarding the suggestion to add an additional paragraph (f) be added to §1090.645, we do not believe that the suggested language adds any clarity since we have modified the language to require segregation from the point of designation. As modified, fuel manufacturers may certify a batch of fuel, designate a portion for domestic use and designate another portion for export. As discussed in Section 12 of this document, we have included instructions for how to report this situation with average standard compliance for gasoline on the final reporting form instructions. 127 ------- 10. Averaging, Banking, and Trading Provisions (Subpart H) 10.1. Compliance on Average Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.745(b) Gasoline manufacturers must calculate and report the unadjusted average sulfur level as follows: Comment: What is meant by unadjusted in the context of calculating the facility net average sulfur and benzene? Does it mean sulfur and benzene concentration prior to downstream oxygenate dilution and credit use? [EPA-HQ-OAR-2018-0227-0074-A1, p.39] These are also new required calculations that are not used for compliance which begs the question of why they are needed. [EPA-HQ-OAR-2018-0227-0074-A1, p.39] Response: The unadjusted sulfur or benzene average is the average level of sulfur or benzene produced at a facility prior to the inclusion of any deficits or credits, which would also exclude deficits incurred from downstream BOB recertification. Gasoline manufacturers that account for oxygenate added downstream would include the dilution effects of the anticipated oxygenate content when calculating the unadjusted sulfur or benzene average for a facility. We included the calculations for unadjusted and net sulfur annual averages and the net benzene annual average for two reasons. First, during the rule development process, several stakeholders requested that we include equations to calculate these annual averages. These stakeholders noted that some fuel manufacturers use these values to aid in developing their compliance strategies. Second, we use these values as a check to evaluate the agreement between information reported on batch reports and annual compliance reports. Given these considerations, we are finalizing the unadjusted and net sulfur annual averages and the net benzene annual average calculations as proposed. 128 ------- Comment: > bp America Inc. (bp) §1090.700(d) (5)-Inclusion of a Gasoline Batch in a Compliance Period In §1090.700(d) (5), EPA proposes to require the inclusion of a gasoline batch in a compliance period based on the date the batch was produced, rather than when it was shipped. Gasoline manufacturers may only have the capability to determine the volume of a gasoline batch when it is shipped from a fuel manufacturing facility, and thus would have to "back-date" the batches' production date based on when it was lab certified. This "back-dating" process for determining a batches' production date can create difficulties for classifying and reporting batches for a compliance period when storing batches for an extended period of time that may cross-over winter and summer gasoline seasons, as well as compliance periods, and may result in having to reclassify batches or amend reports after the batches have been shipped. To address these issues, bp recommends amending §1090.700(d) (5) with the following changes noted in red text to allow a gasoline manufacturer the option to define the production date of a batch by either its shipment date or lab certification date, as long as the gasoline manufacturer applies the same option for all of its batches produced during a compliance period: (5) Inclusion of a particular batch of gasoline for compliance calculations for a compliance period is based on the date the batch is produced, which may be determined by the date the batch was net shipped or lab certified, as long as the gasoline manufacturer uses the same basis for reporting all of their batches produced during the compliance period. For example, a batch that was lab certified produced on December 30, 2021, but shipped on January 2, 2022, would may be included in the compliance calculations for either the 2021 or 2022 compliance period, depending upon the option the gasoline manufacturer has chosen for determining the production date for all of its gasoline batches. However, the volume included in the 2021 compliance period for that batch would be the entire batch volume, even though the shipment of all or some of the batch did not occur until 2022. [EPA-HQ-OAR-2018-0227-0046-A1, p.9] Response: Under part 80, we have required that inclusion of batches of gasoline in a given compliance period is included in the period in which the gasoline is produced.18 We did not propose to make the suggested change to the regulations under part 1090 as we believe it is necessary to ensure that fuel manufacturers account for gasoline production for all batches in a consistent manner. This helps ensure that all fuel manufacturers are playing on a level playing field and all batches are reported consistently allowing us to oversee the program. Therefore, we are finalizing as proposed the provision that whether a batch is included in a compliance period's compliance calculations is based on when the batch was produced, not shipped. 18 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. 129 ------- Comment: > Flint Hills Resources 3) Part 1090 subpart H - §1090.700(b)(l) Benzene value calculation Suggestion: Remove the sigma notation from the (b)(1) (i) equation. The equation should read: CBVy = Btot,y+ DBz,(y-l) + DBz_Oxy_Total ~ CBz Also remove the term "m" which is defined at §1090.700(b)(l)(ii). This term is part of the sigma notation being removed. Discussion: The sigma notation in this (b) (1) (i) equation represents a summation of the benzene deficit from BOB recertification, per §1090.740(b) (4), derived from each recertified batch. However, the batch summation has already occurred in §1090.740(b) (4) such that DBz_Oxy_Totai is the summation of all the batches. Therefore, the sigma notion and the definition of its related term "m" should be removed. [EPA-HQ-OAR-2018-0227-0052-A1, p.3] Response: We have revised §1090.700(b) (1) (i) as the commenter suggested. 130 ------- 10.2. Credit Generation, Use, and Transfer Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.725(a)(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. Comment: There can be a situation where a deficit carryforward was taken for a fuel manufacturing facility for the previous compliance period and credits would be used to clear that deficit but for the current compliance period the facility was below the applicable annual average standard and in this instance credit generation should be allowed for the current compliance period. Associated recommend the following language revisions: (3) No sulfur credits may be generated at a fuel manufacturing facility if that facility used sulfur credits in that same compliance period with the exception if a deficit carryforward was taken the previous compliance year period and the facility was below the applicable average standard during the current compliance period year is below the applicable average. (4) No benzene credits may be generated at a fuel manufacturing facility if that facility used benzene credits in that same compliance period with the exception if a deficit carryforward was taken the previous compliance period yeaf and the facility was below the applicable average standard during the current compliance period year is below the applicable average [EPA-HQ- OAR-2018-0227-0074-A1, p.31] > Shell Oil Products US M. Section 1090.725 (a)(3) and (a)(4) - Credit Use and Generation Language Needs Revised §1090.725 Credit Generation. (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. 131 ------- There can be a situation where a deficit was taken the previous compliance year and credits would be used to clear that deficit, but the current compliance year was below the applicable annual average and in this instance credit generation should be allowed for the current compliance year. We propose the following language: (3) No sulfur credits may be generated at a facility if that facility used sulfur credits in that same compliance period with the exception if a deficit was taken the previous compliance year and the current compliance year is below the applicable average. (4) No benzene credits may be generated at a facility if that facility used benzene credits in that same compliance period with the exception if a deficit was taken the previous compliance year and the current compliance year is below the applicable average. [EPA-HQ-OAR-2018-0227- 0035-A1, p.12] Response: Allowing fuel manufacturing facilities to generate credits as suggested by the commenter would allow fuel manufacturers to effectively eliminate the 5-year credit life, as a manufacturer could retire a credit that was expiring and then generate a new credit to replace the expiring credit if a deficit was incurred. The provision that restricts facilities from both retiring credits and generating credits in the same compliance period is designed to prevent this sort of activity as it would provide incentives for parties to intentionally go out of compliance to renew the life of credits. We also note that this is not a change from how the same provisions operate under part 80. Therefore, we are finalizing the credit generation provisions as proposed. 132 ------- 10.3. Invalid Credits Comment: > Valero Energy Corporation F. Adjustments to Reduce Burdens Associated with Invalid Credits EPA seeks comment on whether to rearrange the compliance deadlines as a means to reduce the frequency of resubmissions and remedial actions.3 In addition to following recommendations made by AFPM, Valero suggests that EPA enhance the EMTS system. EPA can identify remedial actions that can be handled more quickly and easily in an enhanced EMTS system, similar to the "Guidance for Remedial Actions for RFS" EPA issued when RFS was implemented. [EPA-HQ-OAR-2018-0227-0056-A1, p.7] 385 FR 29057-29058 Response: We are always interested in making improvements to our systems that will benefit the user and program goals. However, the commenter did not provide specific recommendations for EMTS improvements in their comment. With respect to remedial actions, such actions for sulfur and benzene may include missed/under/over-generation, missed retirement deadlines, and under- retirements for various reasons. We do not believe that parties should self-correct without discussing the situation with EPA. Therefore, we intend to continue to work with parties who have a need to request remedial actions on a case-by-case and individual basis. We intend to post implementation information and job aids, similar to the RFS remedial action materials, as part of program implementation. 133 ------- 10.4. Downstream Oxygenate Accounting Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • provisions to allow downstream oxygenate accounting to the entire gasoline pool, [EPA-HQ- OAR-2018-0227-0074-A1, p.6] > Marathon Petroleum Company LP (MPC) MPC supports EPA's efforts to consolidate and streamline the fuels regulations, specifically the following provisions: • Adding methodology to reflect the impacts of downstream ethanol blending on sulfur and benzene for all gasoline is a significant step forward and more accurately reflects the realities of US transportation fuel market. [EPA-HQ-OAR-2018-0227-0048-A1, p.l] > Petroleum Marketers Association of America (PMAA) Downstream Oxygenate Blending - BOB The EPA is proposing to allow downstream parties to redesignate BOB when more oxygenate is added than indicated on PTDs, without triggering an array of onerous regulations that typically apply upstream parties. PMAA supports the provision because it would clarify downstream party obligations for higher content ethanol blending. [EPA-HQ-OAR-2018-0227-0083-A1, p.3] > U.S. Chamber of Commerce IV. EPA's Proposal To Allow Refiners To Obtain Credit For Sulfur And Benzene Reductions Due to Downstream Ethanol Blending We support providing credit to refiners for sulfur and benzene reductions due to downstream ethanol blending. As the transportation fuel market has continued to evolve, the vast majority of gasoline sold in the U.S. is blended with ten percent ethanol. Ethanol is typically very low in sulfur and benzene content. Because much of the ethanol blending does not happen at the refinery gate, which is the point of regulation for these fuel quality requirements, the refiners do not currently get credit for the downstream dilution benefit of the lower sulfur and benzene content of the finished gasoline. Parties at all locations downstream of refineries (e.g., pipeline, terminal, retail) are now increasingly engaged in the process of adding ethanol to produce the finished fuel. Blending ethanol downstream of the refinery is done in part due to ethanol's affinity for water. If blended 134 ------- too early in the supply chain, ethanol-gasoline blends adsorb water and separate into two phases, causing the water to collect in low spots of pipelines, storage systems, and transportation vehicles. Gasoline that contains water can cause engine performance issues. Due to the limitations on where ethanol can be blended, the fuel product at the refinery gate does not account for the emission reduction benefits of the ethanol blending that happens downstream. What this means is that the final fuel retail product overcomplies with EPA's standards. Compliance is achieved at the refinery gate, but those additional emissions reductions are not currently captured by refiners when ethanol is blended downstream. EPA's proposal would allow refiners to get credit for those sulfur and benzene reductions after completing a few verification steps. We support the proposal to give dilution credit to downstream blenders of ethanol and the associated verification steps for the associated sulfur and benzene reductions. [EPA-HQ-OAR- 2018-0227-0075-Al.pp.4-5] Response: We thank the commenters for their support. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.6 Downstream Oxygenate Accounting: Option to Use Default The preparation and testing of a hand blend introduce more variability than if the properties were calculated from the neat sample. The neat fuel test variability comes from the sampling and measurement process. The hand blend increases test time and introduces additional variability from the preparation of the hand blend and the potential for human error caused by the additional sample handling. There is also additional complexity as neat analytical results are required by commercial specifications (e.g., pipeline specifications); thus, a neat gasoline analysis would be required in those cases despite any hand blend analytical results. [EPA-HQ-OAR-2018-0227- 0074-A1, p.14] The Associations recommend EPA consider allowing an option for gasoline manufacturers to utilize a compliance calculation with assumed values for sulfur and benzene to account for the downstream addition of denatured fuel ethanol ("DFE"). From Jan. 2018 to Dec. 2019, an API- member company tested hundreds of DFE samples taken from a multitude of ethanol suppliers. Histograms of the benzene and sulfur sampling data are provided Attachment 1. The analysis of the data the API-member company collected is extremely consistent with the analysis EPA included in Table 1 of "EPA's Technical Support Document - Downstream Oxygenate Accounting Regulation Revisions" that is based on Flint Hill's 2016 DFE sampling data for benzene and sulfur. When considering the histogram data in Attachment 1, the assumed sulfur value of 2 ppm is the average ppm value of the data rounded to one significant figure, and the assumed benzene value of 0.01 volume percent is the average volume percent of the data rounded to two significant figures, per EPA's RFG0303 reporting guidelines. The histogram data 135 ------- demonstrates the assumed value of 2 ppm for sulfur and 0.01 volume percent for benzene represent over 95% and 93% of the reported data, respectively. Assumed values that reflect higher values than the proposed values are not justified as the proposed values ensure almost complete coverage of field-tested DFE. Additionally, it is extremely unlikely that the proposed assumed values would result in an industry increase in the benzene and sulfur content of DFE over time, since gasoline manufacturers who might benefit by reporting assumed values have little influence in the production of DFE. If this is a concern, EPA could consider reviewing DFE field data periodically, such as every three years, for the appropriateness of the assumed values. [EPA-HQ-OAR-2018-0227-0074-A1, p. 14] In addition, the Associations suggest that there may be a process that EPA could develop for parties to request assumed values for other oxygenates to account for the other oxygenate's sulfur and benzene levels, if any. That is, a party could provide sufficient data for those values that would support assumed values. That could be accomplished by a party submitting a petition to EPA for approval of such values. That could also involve a public notice and comment proceeding and publication of the final default values so that they could be used by persons who certify the BOB for that type and amount of oxygenate. That would encourage oxygenate producers to produce additional renewable fuels and reduce the amount of sulfur and benzene in those fuels. The use of realistic sulfur and benzene levels would be critical to incentivize that innovation. [EPA-HQ-OAR-2018-0227-0074-A1, p.14] The Associations recommend EPA add the following edits to §1090.710(a) (2) that would allow gasoline manufacturers the option to use assumed values for sulfur and benzene of 2 ppm and 0.01 volume percent, respectively for DFE and provide an option for establishing assumed sulfur and values for other oxygenates in the future, [EPA-HQ-OAR-2018-0227-0074-A1, p.15] §1090.710 Downstream oxygenate accounting. (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)iil Conduct tests on each batch of BOB produced or imported that represents the gasoline after each specified type and amount of oxygenate is added to the batch of BOB by creating a hand blend in accordance with §1090.1340 and determining the properties of the hand blend using the methods specified in subpart M of this part. When creating the hand blend, gasoline manufacturers must not add any more oxygenate to the BOB than the amount of oxygenate specified on the PTD for the BOB under paragraph (a)(5) of this section. (ii) As an alternative to the hand-blend method in §1090.710(a)(2)(i), assume the DFE contains 2 ppm for sulfur and 0.01 volume percent benzene. Conduct sulfur and benzene tests on each batch of BOB produced or imported before the specified amount of DFE is added. Compute the 136 ------- volume-weighted sulfur and benzene of the theoretical blend of BOB and DFE using the test results of the BOB and the assumed sulfur and benzene values for the DFE. (iii) As an alternative to using the assumed values for sulfur and benzene for DFE in 2(i). a party may petition the EPA for assumed values for another oxygenates. If approved by the EPA, those values can be used in place of the values stated in 2(ii) for that oxygenate. (3) Participate in the national sampling oversight program specified in §1090.1440 or have an approved in-line blending waiver under §1090.1315. (4) Transfer ownership of the BOB only to an oxygenate blender that is registered with EPA under subpart I of this part or to an intermediate owner with the restriction that it only be transferred to a registered oxygenate blender. (5) Specify each oxygenate type and amount (or range of amounts) that the gasoline manufacturer certified for compliance of the hand blend on the PTD for the BOB, as specified in §1090.1160(b)(1). (6) Participate in the national fuels survey program under subpart N of this part. [EPA-HO-OAR- 2018-0227-0074-A1, p.15] > bp America Inc. (bp) Downstream Oxygenate Accounting §1090.700(c) gives refiners and importers the option of including the volume of oxygenate added downstream in calculating sulfur and benzene content of the gasoline that is produced or imported if they comply with the downstream oxygenate accounting requirements in §1090.710. Some refiners already hand blend ethanol with BOB and analyze that blend for the ASTM and pipeline specifications. However, a significant number of refiners are not currently blending that fuel with oxygenate and then testing for those specifications. Those refiners would need to expend substantial resources to add laboratory equipment, instrumentation and qualified personnel. The preparation and testing of a hand blend introduce more variability than if the properties were calculated from the neat sample. The neat fuel test variability comes from the sampling and measurement process. The hand blend increases test time and introduces additional variability from the preparation of the hand blend and the potential for human error caused by the additional sample handling. There is also additional complexity as neat analytical results are required by commercial specifications (e.g., pipeline specifications); thus, a neat gasoline analysis would be required in those cases despite any hand blend analytical results. EPA is seeking comments and supporting data that would allow parties to use assumed values on the sulfur and benzene content of an oxygenate added downstream. bp recommends EPA consider allowing an option for gasoline manufacturers to utilize a compliance calculation with assumed values for sulfur and benzene to account for the 137 ------- downstream addition of denatured fuel ethanol (DFE). From Jan. 2018 to Dec. 2019, bp tested hundreds of DFE samples taken from a multitude of ethanol suppliers. Histograms of the benzene and sulfur sampling data are provided Figure 1. The analysis of the data bp collected is extremely consistent with the analysis EPA included in Table 1 of "EPA's Technical Support Document - Downstream Oxygenate Accounting Regulation Revisions" that is based on Flint Hill's 2016 DFE sampling data for benzene and sulfur. When considering the histogram data in Figure 1, the assumed sulfur value of 2 ppm is the average ppm value of the data rounded to one significant figure, and the assumed benzene value of 0.01 volume percent is the average volume percent of the data rounded to two significant figures, per EPA's RFG0303 reporting guidelines. The histogram data demonstrates the assumed value of 2 ppm for sulfur and 0.01 volume percent for benzene represent over 95% and 93% of the reported data, respectively. Assumed values that reflect higher values than the proposed values are not justified as the proposed values ensure almost complete coverage of field-tested DFE. Additionally, it is extremely unlikely that the proposed assumed values would result in an industry increase in the benzene and sulfur content of DFE over time, since gasoline manufacturers who might benefit by reporting assumed values have little influence in the production of DFE. If this is a concern, EPA could consider reviewing DFE field data periodically, such as every three years, for the appropriateness of the assumed values. In addition, bp suggests that there may be a process that EPA could develop for parties to request assumed values for other oxygenates to account for the other oxygenate's sulfur and benzene levels, if any. That is, a party could provide sufficient data for those values that would support assumed values. That could be accomplished by a party submitting a petition to EPA for approval of such values. That could also involve a public notice and comment proceeding and publication of the final default values so that they could be used by persons who certify the BOB for that type and amount of oxygenate. That would encourage oxygenate producers to produce additional renewable fuels and reduce the amount of sulfur and benzene in those fuels. The use of realistic sulfur and benzene levels would be critical to incentivize that innovation, bp recommends EPA add the following edits (in red text below) to §1090.710(a) (2) that would allow gasoline manufacturers the option to use assumed values for sulfur and benzene of 2 ppm and 0.01 volume percent, respectively for DFE and provide an option for establishing assumed sulfur and values for other oxygenates in the future, §1090.710 Downstream oxygenate accounting. (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) (i) Conduct tests on each batch of BOB produced or imported that represents the gasoline after each specified type and amount of oxygenate is added to the batch of BOB by creating a hand blend in accordance with §1090.1340 and determining the properties of the hand blend 138 ------- using the methods specified in subpart M of this part. When creating the hand blend, gasoline manufacturers must not add any more oxygenate to the BOB than the amount of oxygenate specified on the PTD for the BOB under paragraph (a) (5) of this section. (ii) As an alternative to the hand-blend method in § 1090.710(a) (2) (i), assume the oxygenate DFE contains 2 ppm for sulfur and 0.01 volume percent benzene. Conduct sulfur and benzene tests on each batch of BOB produced or imported before specified amount of DFE is added. Compute the volume-weighted sulfur and benzene of the theoretical blend of BOB and DFE using the test results of the BOB and the assumed sulfur and benzene values for the DFE. (iii) As an alternative to using the assumed values for sulfur and benzene for DFE in 2(i), a party may petition the EPA for assumed values for other oxygenates. If approved by the EPA, those values can be used in place of the values stated in 2 (ii) for that oxygenate. (3) Participate in the national sampling oversight program specified in §1090.1440 or have an approved in-line blending waiver under §1090.1315. (4) Transfer ownership of the BOB only to an oxygenate blender that is registered with EPA under subpart I of this part or to an intermediate owner with the restriction that it only be transferred to a registered oxygenate blender. (5) Specify each oxygenate type and amount (or range of amounts) that the gasoline manufacturer certified for compliance of the hand blend on the PTD for the BOB, as specified in §1090.1160(b)(1). (6) Participate in the national fuels survey program under subpart N of this part. [EPA-HQ-OAR- 2018-0227-0046-A1, pp.11-13] > Phillips 66 Company Oxygenate Accounting In the preamble, EPA asks for comment on use of assumed or default values for ethanol sulfur and benzene for use in lieu of hand blends. We support EPA providing this flexibility and think that it will provide a valuable option for refinery labs. There is a plethora of ethanol data that can be used to determine appropriate values to use. API and AFPM have provided data in their comments that support a value of 2 ppm sulfur and 0.01 vol% benzene. Different sections of the regulations would need to be updated to provide this option. Section 1090.710 on Downstream Oxygenate Accounting and Section 1090.1340 on Preparing a Hand Blend from BOB are two areas that would need to be modified. [EPA-HQ-OAR-2018-0227-0060-A1, p.6] Response: It is integral to the intended purpose of this action to reduce the complexity and optionality for compliance, wherever possible, in order to modernize and simplify the gasoline programs. With that in mind, we sought industry feedback on which methodology to use for demonstrating 139 ------- downstream oxygenate accounting very early in the development of this action. A wide range of industry participants voiced overwhelming support for the hand blend methodology as it mimicked existing marketplace requirements for ensuring product quality. In response to that feedback, we proposed the hand blend methodology as the sole compliance demonstration mechanism for downstream oxygenate accounting under part 1090. Allowing more options would add unnecessary complexity to program oversight and introduce opportunities for cherry- picking among the most favorable approaches in any given situation. Furthermore, fuel manufacturers are not required to account for the addition of downstream oxygenates to demonstrate compliance; it is a flexibility that may be utilized by fuel manufacturers should they find that the economic benefits outweigh the costs. Consequently, we are finalizing the provisions as proposed. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.6 Downstream Oxygenate Accounting: Option to Use Default If EPA does not allow assumed values to be used for sulfur and benzene in DFE, given the amount of time it may take a gasoline manufacturer to secure sufficient resources, such as lab equipment, instrumentation and qualified personnel, for one of its fuel manufacturing facilities to begin conducting oxygenate hand blending, the Associations recommend EPA to allow a fuel manufacturing facility until Jan. 1, 2022, or one-year from the effective date of the final Streamlining Rule, to implement oxygenate hand blending. In addition, until the oxygenate hand blending has been implemented, the Associations recommend that a fuel manufacturing facility may use an assumed sulfur value of 2 ppm and an assumed benzene value of 0.01 volume percent, which is discussed in detail above and supported by the histogram data provided below. These values capture 95% of sulfur and 93% of benzene observed data. [EPA-HQ-OAR-2018- 0227-0074-A1, pp.15-16] [[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 16 for the histogram mentioned above.]] > bp America Inc. (bp) Downstream Oxygenate Accounting If EPA does not allow assumed values to be used for sulfur and benzene in DFE, given the amount of time it may take a gasoline manufacturer to secure sufficient resources, such as lab equipment, instrumentation and qualified personnel, for one of its facilities to begin conducting oxygenate hand blending, bp recommends EPA allow a facility until January 1, 2022, or one year from the effective date of the final Streamlining Rule, to implement oxygenate hand blending. In addition, until the oxygenate hand blending has been implemented, bp suggests a facility should be permitted to use an assumed sulfur value of 2 ppm and an assumed benzene value of 0.01 volume percent, which is discussed in detail above and supported by the histogram data provided in Figure 1. 140 ------- Figure 1: Denatured Fuel Ethanol (DFE) Benzene and Sulfur Sample Data [Figure 1 can be found on p. 14 of EPA-HQ-OAR-2018-0227-0046-A1.] [EPA-HQ-OAR-2018- 0227-0046-A1, pp.13-14] Response: Fuel manufacturers are not required to account for the addition of downstream oxygenates to demonstrate compliance. It is a flexibility that may be utilized by fuel manufacturers should they find that the economic benefits outweigh the costs. As such, there is no compelling reason to provide an interim program for, or to delay the adoption of, the downstream oxygenate accounting regulations, and we are finalizing the provisions as proposed. 141 ------- 10.5. Downstream BOB Recertification Comment: > Buckeye Partners, L.P. §1090.710 E0 Provisions (i.e. neat gasoline with no ethanol). Comment #7 - Although a majority of gasoline distributed to the public is ethanol blended (typically E10), there is a small but important market and need for ethanol-free gasoline (i.e. E0 Recreation Fuel). The compliance burden (redesignation, credits, reporting, attestation) on the neat market for supplying E0 from the E10 pool appears to be disproportional burdensome to the small market. EPA should consider allowing the production of E0, while removing regimented compliance obligations for these minimal volumes. [EPA-HQ-OAR-2018-0227-0032-A1, p.3] > International Liquid Terminals Association ILTA's CONCERNS While the proposal includes many provisions that ILTA supports (listed above), there are also areas of concern. We discuss these below. 3. E0 provisions While there are several gasoline engine applications that require the use of E0, and E0 usage is growing briskly, ethanol-free gasoline is still a miniscule portion of the national gasoline pool. EPA should allow the terminal production of E0 but remove any requirement to force the blender to track and account for the de minimis amount of oxygenate not used in the E0 product pool. [EPA-HQ-OAR-2018-0227-0061-A1, p.3] > Magellan Midstream Partners §1090.710 Downstream oxygenate accounting There are a number of gasoline engine applications that require the use of E0. In addition, many Midwestern motorists in markets served by the Magellan pipeline system freely select E0 as their fuel of choice in automobiles, SUVs and pickup trucks when given the option at the pump. In fact, E0 demand from terminals on the Magellan central pipeline system is over 40,000 barrels per day. Even at this level, it is a small percentage of the nation's gasoline demand. Presently, in some markets, it is exceedingly difficult to purchase the appropriate fuel for certain internal combustion engines. This can lead to engine failure and in some cases, it presents safety issues. We applaud EPA for taking steps to provide an option for E0 in traditional RFG markets. Nonetheless, we believe EPA should continue to allow the terminal production of E0 but should remove any requirement to force the blender to track and account for the de-minimis amount of oxygenate not used in the E0 product pool. 142 ------- "§ 1090.710 Downstream oxygenate accounting. The requirements of this section apply to BOB for which a gasoline manufacturer is accounting for the effects of the oxygenate blending that occurs downstream of the fuel manufacturing facility in the gasoline manufacturer's average standard compliance calculations of this subpart. This section includes requirements on distributors to ensure that oxygenate is added in accordance with the blending instructions specified by the gasoline manufacturer in order to ensure fuel quality standards are met. (a) Provisions for gasoline manufacturers. In order to account for the effects of oxygenate blending downstream, a gasoline manufacturer must meet all the following requirements: (1) Produce or import BOB such that the gasoline continues to meet the applicable gasoline standards in subpart C of this part after the addition of the specified type and amount of oxygenate. (2) Conduct tests on each batch of BOB produced or imported that represents the gasoline after each specified type and amount of oxygenate is added to the batch of BOB by creating a hand blend in accordance with § 1090.1340 and determining the properties of the hand blend using the methods specified in subpart M of this part." [EPA-HQ-OAR-2018-0227-0078- Al, pp.5-6] Response: As discussed in Section VII.G of the preamble, we believe these provisions are necessary for parties to make available E0 in RFG areas. We also believe these provisions are necessary in order to provide CG manufacturers the same flexibilities that we provide for RFG manufacturers regarding downstream oxygenate accounting. To mitigate the costs, we have provided a 1,000,000 gallon per year threshold for the most expensive compliance burdens associated with downstream BOB recertification (i.e., exemption from the attest engagement audit and incurring sulfur and benzene deficits). We believe these flexibilities will mitigate burden for small volume blenders, helping to ensure that E0 costs do not increase significantly. Comment: > 1980, A.R.C. Distributors, ABYC, et al. (approximately 350 organizations) Provide more relief from conducting an attest engagement by raising the 200,000-gallon limit to two million gallons - which would be a more appropriate exemption, particularly as sales of marine gasoline in the U.S. account for approximately 1.5 billion gallons annually. [EPA-HQ- OAR-2018-0227-0082-A1, p.l] > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. 1. EPA expand its proposed annual attest engagement limit for small volume blenders from 200.000 gallons to 2 million gallons. EPA has acknowledged the great expense of this requirement, and understands the challenges this poses to small businesses to blending biobutanol cost effectively. The 200,000 gallon limit is too low, given the tight margins businesses have already and the volumes needed for the expanding market demand. [EPA-HQ- OAR-2018-0227-0063-A2, p.l] 143 ------- > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: Therefore, we are proposing that parties that recertify less than 200,000 total gallons of gasoline for different types and amounts of oxygenate during a compliance period would be exempt from the annual attest audit and report.. .We seek comment on whether this allowance is appropriate. Comment: A 200,000-gallon threshold is still too low to require an attestation. This amount does not justify the cost of an attestation. With today's credit value, 200,000 gallons would be a cost of approximately $1,000 in benzene and sulfur credits which does not justify the cost of an attestation. In addition, the number of attestations that this threshold would trigger will be a very large number and be difficult to complete all attestation reports by June 1. We recommend that a more reasonable threshold is 1,000,000 gallons. We also recommend that an aggregate attestation be allowed so that one attestation report includes all company facility locations that has exceeded the 1,000,000-gallon threshold. [EPA-HQ-OAR-2018-0227-0074-A1, pp.29-30] > Association of Marina Industries (AMI) 1. EPA should expand its proposed annual attest engagement limit for small volume blenders from 200,000 gallons to 2 million gallons. EPA has acknowledged the great expense of this requirement, and understands the challenges this poses to small businesses to blending biobutanol cost effectively. The 200,000 gallon limit is simply too low, given the tight margins businesses have already and the volumes needed for the expanding market demand. [EPA-HQ- OAR-2018-0227-0057-A1, p.2] > bp America Inc. (bp) Downstream Oxygenate Recertification In Section VIII.G of the preamble, EPA has requested comments on allowing downstream blending facilities to use assumptions for the benzene and sulfur content of the BOB when recertifying the fuel and the appropriate assumed values for oxygenates added downstream. The agency has included data supporting the use of assumed values. For the recertification of oxygenate by a downstream blending facility, EPA is proposing assumed values for the amount of sulfur (11 ppm) and benzene (0.68 volume percent) from the BOB that are reflective of the national sulfur and benzene average values with a conservative adjustment of 110%. Due to the variability in sulfur and benzene content of BOB, which utilize oxygenate blending by a downstream facility, and the low probability of a downstream blending facility recertifying their BOB with less or no oxygenate, bp supports EPA's proposed assumed values for sulfur and benzene. 144 ------- EPA is proposing downstream blending facilities that recertify less than 200,000 total gallons of gasoline for different types and amounts of oxygenate during a compliance period would be exempt from the annual attest audit and report. (§1090.740(a) (3)) EPA is requesting comments on whether this allowance is appropriate. Based on bp's review of past downstream blending facilities' ethanol volumes, the potential is low for a downstream terminal to blend ethanol in less than the 200,000-gallon threshold. Therefore, bp supports the threshold that EPA has proposed. [EPA-HQ-OAR-2018-0227-0046-A1, pp.14-15] > BRP US Inc. Marine Group (BRP) Relief for small volume blenders. EPA provides some relief for small volume blenders by allowing them to be exempt from an annual attest engagement if they blend less than 200,000 gallons per year. In the preamble, however, EPA admits that an annual attest engagement costs tens of thousands of dollars for which it would be difficult for a small volume fuel blender to recuperate the costs associated with this testing. The margin on gasoline is pennies per gallon; so 200,000 gallons is an extremely low threshold that does not economically make sense. BRP is requesting that EPA consider more meaningful relief from conducting an attest engagement by raising the 200,000 gallon limit to two million gallons, which would be a more appropriate and effective threshold for the exemption, particularly given that sales of marine gasoline in the U.S. typically account for approximately 1.5 billion gallons annually.3 [EPA-HQ-OAR-2018-0227- 0047-A1, p.4] 3 US Department of Transportation OFF-HIGHWAY AND PUBLIC-USE GASOLINE CONSUMPTION ESTIMATION MODELS USED IN THE FEDERAL HIGHWAY ADMINISTRATION Final Report for the 2014 Model Revisions and Recalibrations Publication Number - FHWA-PL-17-012 June 2015 https://www.fhwa.dot.gov/policyinformation/pubs/pll7012.pdf > Gevo, Inc. 1. EPA expand its proposed annual attest engagement limit for small volume blenders from 200.000 gallons to 2 million gallons. EPA has acknowledged the great expense of this requirement, and understands the challenges this poses to small businesses to blending biobutanol cost effectively. The 200,000 gallon limit is simply too low, given the tight margins businesses have already and the volumes needed for the expanding market demand. [EPA-HQ- OAR-2018-0227-0063-A1, p.3] > Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd. 2. We support the Downstream Oxygenate Blending section as written with the exception of A. "...parties that recertify less than 200,000 total gallons of gasoline for different types and amounts of oxygenate during a compliance period would be exempt from the annual attest audit and report", we believe the volume exemption should be two millions gallons per year. [EPA- HQ-OAR-2018-0227-0050, p.2] 145 ------- > National Marine Manufacturers Association (NMMA) • Relief for small volume blenders. EPA provides some relief for small volume blenders by allowing them to be exempt from an annual attest engagement if they blend less than 200,000 gallons per year. In the preamble, however, EPA admits that an annual attest engagement costs tens of thousands of dollars for which it would be difficult for a small volume fuel blender to recuperate the costs associated with this testing. The margin on gasoline is pennies per gallon; so 200,000 gallons is an extremely low threshold that does not economically make sense. NMMA is requesting that EPA consider more meaningful relief from conducting an attest engagement by raising the 200,000 gallon limit to two million gallons, which would be a more appropriate and effective threshold for the exemption, particularly given that sales of marine gasoline in the U.S. typically account for approximately 1.5 billion gallons annually.3 [EPA-HQ-OAR-2018-0227-0034-A1, p.4] 3 US Department of Transportation OFF-HIGHWAY AND PUBLIC-USE GASOLINE CONSUMPTION ESTIMATION MODELS USED IN THE FEDERAL HIGHWAY ADMINISTRATION Final Report for the 2014 Model Revisions and Recalibrations Publication Number - FHWA-PL-17-012 June 2015 https://www.fhwa.dot.gov/policyinformation/pubs/pll7012.pdf > Phillips 66 Company Section §1090.740 (a)(3)- Minimum gallons to trigger attestation for BOB Recertification We support the concept of establishing a minimum volume before attestation of BOB recertification is required. However, we feel that the proposed volume of 200,000 gallons is too low. That equates to approximately 25 truck loads per year. We ask EPA to raise that volume and consider 1,000,000 gallons instead. [EPA-HQ-OAR-2018-0227-0060-A1, p.8] > Shell Oil Products US E. Section §1090.740 (a)(3)- Minimum gallons to trigger attestation for BOB Recertification Needs Revised Preamble states: Therefore, we are proposing that parties that recertify less than 200,000 total gallons of gasoline for different types and amounts of oxygenate during a compliance period would be exempt from the annual attest audit and report. We believe this proposed flexibility would allow small blenders to avoid a substantial amount of compliance costs associated with recertification of batches of gasoline for different types and amounts of oxygenates while ensuring integrity in the sulfur and benzene credit markets. We seek comment on whether this allowance is appropriate. §1090.740 Downstream BOB recertification 146 ------- (3) Unless otherwise required under this part, gasoline manufacturers that recertify 200,000 or less gallons of BOB under this section do not need to arrange for an auditor to conduct audits under subpart R of this part. A 200,000 gallon threshold is still too low to require an attestation. This amount does not justify the cost of an attestation. With today's credit value, 200,000 gallons would be a cost of approximately $1,000 in benzene and sulfur credits which does not justify the cost of an attestation. In addition, the number of attestations that this threshold would trigger will be a very large number and be difficult to complete all attestation reports by June 1. We recommend that a more reasonable threshold is 1,000,000 gallons. We also recommend that an aggregate attestation be allowed so that one attestation report includes all company facility locations that has exceeded the 1,000,000 gallon threshold. > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Downstream BOB Recertification In addition, the Associations urge the Agency to expand the 200,000 gallons exemption threshold (§1090.740(a) (3)) so it applies not only to audit requirements but to other requirements related to recertification as well. Further, EPA should reconsider and ultimately increase this threshold to 2 million gallons. While the Associations appreciate the Agency's efforts to provide flexibility to small blenders and limit substantial compliance costs associated with recertification, according to the Associations' members, 200,000 gallons is too low a threshold and will fail to insulate many small blenders from regulatory burdens the way the Agency intends. [EPA-HQ- OAR-2018-0227-0066-A1, p.5] Response: As discussed in more detail in Section VII.G of the preamble, we are providing additional flexibility for small volume blenders that recertify BOB downstream. Under part 1090, parties that blend 1,000,000 gallons or less per year will not incur sulfur and benzene deficits and will not need to arrange for an annual attestation audit. We believe this provides adequate flexibility for parties to make E0, while keeping costs down and ensuring that national average sulfur and benzene levels do not significantly increase as a result of downstream BOB recertification. However, we will monitor the use of this flexibility and may reconsider it as necessary in the future should the volume of fuel blended by these small volume blenders become significant. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: 147 ------- 1090.740(b)(1) and (b)(3) [[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 31 for sulfur benzene equations] ] Comment: Suggestion: Revise the sulfur and benzene equations to account for the difference between the amount of oxygenate specified on the PTD and the amount of oxygenate actually blended. The equations should read: [[See Docket Number EPA-HQ-OAR-2018-0227-0074-A1, p. 31 for revised sulfur benzene equations] ] Where ACTUALOxy = The volume fraction of oxygenate that was actually added to the BOB. Discussion: The EPA-proposed equations only work properly for cases in which the PTD specifies some volume of oxygenate but the blender blends zero oxygenate. The equations, as proposed, always return the same answer, even when the blender blends more oxygenate than specified on the PTD. If the blender blends a volume less than specified on the PTD, the blender should incur a deficit for the delta between the PTD amount and the actual blended amount. Further, if the blender blends more oxygenate than specified on the PTD, the equation should result in a negative answer (i.e. a negative deficit), which is then excluded per §1090.740(c). [EPA-HQ-OAR-2018-0227-0074-A1, p.31] Note that §1090.710(c) must also be revised to allow downstream oxygenates at different levels to be included. [EPA-HQ-OAR-2018-0227-0074-A1, p.32] > bp America Inc. (bp) Subpart J - Reporting Reporting Templates RFG030X: Gasoline and Gasoline Blendstock Batch Summary and ABT0300: Gasoline Averaging. Banking, and Trading (ABT) Facility Summary Reports Both reporting forms contain line item entries for reporting downstream oxygenate recertification sulfur and benzene deficits. The calculations are detailed in 1090.740(b)(1) through (b) (4). bp recommends EPA consider allowing the sulfur and benzene credit deficit to be based on the difference of 5% not the entire 15%. The deficit calculations included in §1090.740(b) (1) and (b)(3) require the recertifying fuel manufacture to calculate the deficit based on an E0 recertification. EPA should allow fuel manufacturers to only incur a sulfur and benzene deficit for the 5% difference. This will allow parties that blend 10% ethanol to adequately account for the sulfur and benzene deficit and encourage renewable fuel blending. 148 ------- That could be accomplished by modifying the equations in §1090.740(b)(1) and (b)(3) by defining PTD oxy to represent the difference between the certification on the PTD and the recertification. > Flint Hills Resources 4) Part 1090 subpart H - §1090.740(b) Downstream BOB recertification Suggestion: Revise the sulfur and benzene equations to account for the difference between the amount of oxygenate specified on the PTD and the amount of oxygenate actually blended. The equations should read: [See the equations on p.3 of EPA-HQ-OAR-2018-0227-0052-A1.] Where ACTUALoxy = The volume fraction of oxygenate that was actually added to the BOB. Discussion: The EPA-proposed equations only work properly for cases in which the PTD specifies some volume of oxygenate but the blender blends zero oxygenate. The equations, as proposed, always return the same answer, even when the blender blends more oxygenate than specified on the PTD. If the blender blends a volume less than specified on the PTD, the blender should incur a deficit for the delta between the PTD amount and the actual blended amount. Further, if the blender blends more oxygenate than specified on the PTD, the equation should result in a negative answer (i.e. a negative deficit), which is then excluded per §1090.740(c). [EPA-HQ-OAR-2018-0227-0052-A1, p.3] Response: We have revised §1090.740(c) to address the concerns raised by the commenters. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: 1090.740 There is no sampling and testing exemptions for those locations that are conducting downstream recertification per 1090.740. Comment: We recognize the need to account for the sulfur and benzene credit deficit created when a person does not add the BOB manufacture's prescribed concentration of oxygenate into a gasoline. However, we recommend the EPA provide an exemption to subpart M for those facilities that are only recertify BOBs that have already been certified. Applying the full requirements of a gasoline manufacture is unnecessary given the nature of the operation of blending a premium 149 ------- octane BOB with a regular octane BOB to produce an EO gasoline or selling a premium octane BOB as an EO gasoline. [EPA-HQ-OAR-2018-0227-0074-Al,p.32] This concept is implied within the preamble but should be explicit within the regulatory text. [EPA-HQ-OAR-2018-0227-0074-A1, p.32] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Downstream BOB Recertification Finally, the Associations urge EPA to build in a regulatory option for a refiner to sell a product that would not account for the addition of downstream oxygenate. In other words, NACS, NATSO, and SIGMA call upon the Agency to create a separate track for the EO premium BOB fuel marketers supply to the maritime and boating industry. Moreover, the Associations call upon EPA to extend the threshold exemption (§1090.740(a) (3)) to this type of situation in order to insulate small blenders who supply EO for marine applications from unnecessary regulatory burdens. [EPA-HQ-OAR-2018-0227-0066-A1, p.5] > Valero Energy Corporation In addition, Valero believes EPA should ensure that the new rules include clear provisions to account for clear gasoline, also known as EO. EPA's failure to include provisions for EO will simply create compliance uncertainty for blendstocks that are not blended with oxygenate downstream. [EPA-HQ-OAR-2018-0227-0056-A1, p.2] C. Downstream Oxygenate Accounting and Recertification: PTD - Accounting for Oxygenate Addition for EO Valero requests that EPA give further consideration to the downstream oxygenate blending provisions and how to better account for BOBs where the blender has not taken credit for the downstream oxygenate. The rules do not address the situation where the manufacturer chooses not to take credit for downstream oxygenate blending and how to communicate that to downstream blenders. Valero requests that EPA address how to handle BOB batches for which the fuel manufacturer decides not to take credit for downstream addition of oxygenate. Specifically, Valero requests EPA describe the PTD and designation requirements for these BOB batches, including how a downstream party would know if the upstream party has already accounted for oxygenate and if they would have to incur a deficit if they recertify. EPA should consider whether there is a need for different categories for RBOB and CBOB to be blended with oxygenate and RBOB and CBOB that is not accounting for oxygenate. EPA should clarify whether there should be a presumption that credit has been taken already unless otherwise specified in contract/other documentation. EPA should address this scenario to minimize the extent that a downstream party could calculate a credit deficit unnecessarily. Valero asks EPA to provide appropriate revisions to the PTD provisions and designation provisions to account for 150 ------- BOB batches that are not expected to have oxygenate added downstream, including §§1090.1150(a)(2), 1090.1160(b), and 1090.1110(a). [EPA-HQ-OAR-2018-0227-0056-A1, p.5] Response: We believe that the proposed regulations already accommodated a separate track for E0 premium BOB for which a fuel manufacturer does not wish to account for oxygenate added downstream; however, we have added provisions at §1090.1310(c) (2) to more clearly spell out how fuel manufacturers may certify such a BOB. Fuel manufacturers are not required to account for oxygenate added downstream and may either certify the batch as E0 RFG or CG or as BOB for which downstream oxygenate is not accounted. As discussed in responses to other comments in this section and in Section VII.G of the preamble, we are providing additional flexibility for parties that make small volumes of E0 through the BOB recertification provisions (i.e., 1,000,000 gallons or less per year) to avoid sulfur and benzene deficits and forgo the annual attest audit requirements. We believe this additional flexibility should mitigate regulatory burdens associated with downstream BOB recertification. Comment: > bp America Inc. (bp) Clarify who can recertify the BOB from 10% ethanol to 16% isobutanol §1090.740(a) (1) in the proposed rule states that a gasoline manufacturer may recertify a BOB for a different type or amount of oxygenate. However, the preamble states that an oxygenate blender is allowed to recertify batches of BOB for different type and amount of oxygenates. (85 Fed. Reg. 29059) This appears to be inconsistent. Furthermore, the definition of "gasoline manufacturer" in §1090.80 indicates that anyone who certifies a BOB under §1090.740 is considered a gasoline manufacturer. However, there may frequently be times when a person recertifies a BOB for a different type or amount of oxygenate and may not generate any sulfur or benzene deficits. In that case, there are no batch reporting obligations as stated in §1090.910(a) (2). Since there are no batch reports prepared in those instances, there would essentially be no substantive attestation requirements to fulfill under §1090.1840(e). bp recommends that an oxygenate blender be able to redesignate a BOB for a different type or amount of oxygenate when there are no sulfur or benzene deficits. That would involve modifying the definition of "gasoline manufacturer" to clarify that parties who recertify BOBs under §1090.740 are not gasoline manufacturers if they do not have any benzene or sulfur deficits during a compliance period. A similar clarification should also be made in §1090.740. [EPA- HQ-OAR-2018-0227-0046-A1, pp.10] > Butamax Advanced Biofuels, LLC Clarify which parties may recertify the BOB from 10% ethanol to 16% isobutanol 151 ------- §1090.740(a) (1) in the proposed rule states that a gasoline manufacturer may recertify a BOB for a different type or amount of oxygenate. However, the preamble states that an oxygenate blender can recertify batches of BOB for different type and amount of oxygenates (85 FR 29059); on this point, the preamble and regulatory language appear to be inconsistent. Furthermore, the definition of "gasoline manufacturer" in §1090.80 indicates that anyone who certifies a BOB under §1090.740 is considered a gasoline manufacturer. [EPA-HQ-OAR-2018-0227-0068-A1, p.2] Because bio-isobutanol blending achieves its maximum benefits when blended at or near its allowed maximum concentration of 16 vol%, Butamax believes it may frequently occur that parties will use the new rule provisions to recertify a 10% ethanol BOB for a different type or amount of oxygenate without generating sulfur or benzene deficits. In such cases, there are no batch reporting obligations as stated in §1090.910(a) (2). Since there are no batch reports prepared in such instances, there would essentially be no substantive attestation requirements to fulfill under §1090.1840(e). [EPA-HQ-OAR-2018-0227-0068-A1, p.2] Butamax recommend that an oxygenate blender be able to redesignate a BOB for a different type or amount of oxygenate when there are no sulfur or benzene deficits, which could be accomplished by modifying the definition of "gasoline manufacturer" to clarify that parties who recertify BOBs under §1090.740 are not gasoline manufacturers if they do not have any benzene or sulfur deficits during a compliance period. A similar clarification should be made in §1090.740. [EPA-HQ-OAR-2018-0227-0068-A1, pp.2-3] Response: We have added language at §1090.740(a) (4) that highlights what parties that only recertify BOBs by adding more of the same oxygenate (e.g., adding 15 volume percent denatured fuel ethanol to an E10 BOB) or the same or more of a different oxygenate (e.g., adding 16 volume percent isobutanol instead of ethanol to an E10 BOB) must do. Under §1090.740(a) (4), these parties will not incur deficits, do not need to submit reports, and do not need to arrange for an annual attest engagement. However, these parties are still oxygenate blenders and therefore must comply with all applicable requirements for oxygenate blenders. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: We are not proposing to allow deficit carry-forwards for deficits created by downstream oxygenate recertification. However, we seek comment on whether providing such a deficit carry- forward is needed to help implement the proposed downstream oxygenate recertification 152 ------- provisions. Comments on this subject should include a reasonable period of time for consideration. Comment: Allow deficit carryforward for 3 years, through 2023. The credit market is very tight currently. For example, when BOB recertification is allowed in 2021, the additional credits generated from Downstream Oxygenate dilution will be attested for the first time in Spring 2022 and will be made available later in 2022, which is after the first reporting and credit use is due for BOB recertification. We suggest that a deficit be allowed for the first 3 compliance years after the new program begins - through 2023 compliance year. We propose the following language: 1090.740 (d) Deficits are allowed per facility for one year through the 2023 compliance year but cannot occur two years in a row. Any facilities that have a deficit will be attested for the compliance year the deficit is taken and the following year regardless of volume. [EPA-HQ- OAR-2018-0227-0074-A1, p.29] > bp America Inc. (bp) Downstream Oxygenate Recertification EPA is proposing not to allow deficit carry-forwards for deficits created by downstream oxygenate recertification but is taking comments on whether providing such a deficit carryforward is needed and the amount of time that should be allowed. (85 Fed. Reg. 29060) Given the required process for the recertification of BOB, additional resources will be required to determine when oxygenate blending is not occurring. These facilities will encounter the same challenges with internal accounting and managing deficits in the credit markets as upstream fuel manufacturers which may be difficult to complete by the reporting due date. Therefore, bp recommends allowing a deficit carryforward of one year for downstream blending terminals that engage in BOB recertification. This would provide downstream parties sufficient time to make up the deficit in the event the deficit cannot be reconciled due to difficulties with obtaining credits in the market prior to compliance reporting due date. [EPA-HQ-OAR-2018-0227-0046- Al, pp.15] > Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd. 2. We support the Downstream Oxygenate Blending section as written with the exception of B. Providing a deficit carry-forward is needed to help implement the proposed downstream oxygenate recertification provisions and we recommend one year as the carry-forward period. [EPA-HQ-OAR-2018-0227-0050, p.2] 153 ------- > Shell Oil Products US F. Section §1090.740 (d) - Need to Add an Allowance for a Deficit Preamble states: Therefore, we are not proposing to allow deficit carry-forwards for deficits created by downstream oxygenate recertification. However, we seek comment on whether providing such a deficit carry-forward is needed to help implement the proposed downstream oxygenate recertification provisions. Comments on this subject should include a reasonable period of time for consideration. §1090.740 Downstream BOB recertification (d) Deficits incurred under this section must be fulfilled in the compliance period in which they occur and may not be carried forward under §1090.715. The credit market is very tight currently. For example, when BOB recertification is allowed in 2021, the additional credits generated from Downstream Oxygenate dilution will be attested for the first time in Spring 2022 and will be made available later in 2022 which is after the first reporting and credit use is due for BOB recertification. We suggest that a deficit be allowed for the first 3 compliance years after the new program begins - through 2023 compliance year. We propose the following language: 1090.740 (d) Deficits are allowed per facility for one year through the 2023 compliance year but cannot occur two years in a row. Any facilities that have a deficit will be attested regardless of volume for the compliance year the deficit is taken and the following year regardless of volume. [EPA-HQ-OAR-2018-0227-0035-Al.pp.5-6] Response: We do not believe that allowing a deficit carry-forward is necessary to address concerns that deficits incurred from downstream BOB recertification could constrain tight sulfur and benzene markets. The magnitude of the potential impact of this provision on the overall credit market is minor. Furthermore, as discussed in more detail in responses to other comments in this section and in Section VII.G of the preamble, we are not requiring deficit incursion for blenders of small volumes of recertified BOBs (i.e., those that blend 1,000,000 gallons or less per year). Finally, we also believe that the downstream oxygenate accounting provisions will provide some relief on tight credit markets by allowing CG manufacturers to better take into account the dilution effect from oxygenates added downstream. Therefore, we are not providing any deficit carry- forward provisions for deficits incurred from downstream BOB recertification. 154 ------- Comment: > Butamax Advanced Biofuels, LLC Support of proposed rule provisions on downstream recertification of RBOBs and CBOBs The proposed rule includes provisions at §1090.740 which ease present restrictions on downstream recertification of RBOBs and CBOBs with the intent to facilitate blending of oxygenates other than 10% ethanol. The new recertification provisions will facilitate broader use of renewable bioisobutanol since, as noted by the Agency, under the present recertification requirement of Part 80 ".. .the high cost associated with recertifying batches of RBOB downstream essentially precludes oxygenate blenders from blending isobutanol in RFG areas. (85 FR 29059). Butamax supports the new provisions for recertifying BOBs and believes this change will have the intended outcome of alleviating unintended restrictions on downstream blending of bio-isobutanol. However, some aspects of these new BOB recertification provisions could benefit from clarifications as noted in our next two comments. [EPA-HQ-OAR-2018- 0227-0068-A1, p.2] Response: We thank the commenter for their support. Comment: > Eversheds Sutherland (US) LLP Downstream BOB Recertification The downstream BOB recertification procedures appear to be unnecessary, especially to smaller entities, if some fuel manufacturers certify neat despite the fact that much of their fuel will be used as E10. The proposal also penalizes a fuel manufacturer that reports some neat gasoline batches and then is hit at the rack when it needs to recertify to E10; EPA should consider an exception to fuel manufacturers that report neat and also recertify, allowing them to balance out the activities by not having these procedures in § 1090.740 apply if the neat batches certified are greater than recertified BOB volume. [EPA-HQ-OAR-2018-0227-0076-A1, p.6] Response: We believe the downstream BOB recertification procedures are necessary, especially in light of the changes in part 1090 that will allow for CG manufacturers to more easily account for oxygenate added downstream. Based on our experience with RFG, which has similar provisions under part 80, it can become difficult for some areas to have access to E0 if refiners only produce BOB for which oxygenate added downstream has been accounted. We believe that a similar situation will arise in CG areas if we do not provide flexibility for parties to recertify BOBs downstream. As discussed in responses to other comments in this section and in Section VII.G of the preamble, we have exempted small volume blenders (i.e., those that blend 1,000,000 gallons 155 ------- or less per year) from incurring deficits, submitting annual reports, and arranging for an attest audit. We believe this will provide sufficient flexibility for small downstream parties to recertify BOBs without being overly burdensome. Additionally, as also discussed in other responses to comments in this section, we are clarifying how fuel manufacturers can certify EO or BOB without downstream oxygenate accounting. We do not believe that it is necessary to provide additional flexibility for parties that certify batches of gasoline without oxygenate to account for oxygenate that is later added downstream. Such a flexibility would significantly increase the complexity of the program and potentially result in the creation of invalid or fraudulent sulfur and benzene credits. Therefore, we are finalizing the downstream BOB recertification procedures largely as proposed with modifications as discussed elsewhere in this section. Comment: > Growth Energy For El 5 specifically, while there do not appear to major impediments in the proposal, there is some confusion about the language on BOB certification and downstream oxygenate blending in section 1090.740. With El 5 now approved for year-round sale, it makes little sense why El 5 would have substantially different BOB requirements for E10 and El 5. At a minimum, if downstream oxygenate blenders choose to add 15% ethanol, they should not incur any additional requirements of that as a fuel manufacturer or refiner. We believe that current recordkeeping from retailers and downstream blenders should satisfy EPA's need for certainty with the fuel. Alternatively, we would ask that you work with retailers to simplify any BOB recertification, so that there are not any additional burdensome requirements added to the process to sell this fuel, nor are there any additional restrictions imposed on retailers choosing to offer the fuel. [EPA- HQ-OAR-2018-0227-0053-A1, p.2] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) The Associations do, however, have several significant reservations with EPA's proposed Section 1090.740 (Downstream BOB Recertification). As drafted, this provision is unclear and may, if finalized as proposed, not function in the way the Agency intends. For instance, it likely would impose negative externalities and costs on the El5 retail market (See Section II.D). [EPA- HQ-OAR-2018-0227-0066-A1, p.2] Downstream BOB Recertification NACS, NATSO, and SIGMA have several concerns with §1090.740. The Associations believe the Agency's intent in §1090.740 is to permit a downstream party to recertify a BOB without triggering the full suite of requirements applicable to refineries when such downstream party adds more oxygenate than specified in a product transfer document. The Proposal appears to indicate otherwise and should be revised to make clear that adding additional oxygenate would 156 ------- not trigger these additional requirements (including obligated party requirements under the RFS).8 Failure to make this point explicit in the regulatory text will discourage active El5 marketers from continuing to sell higher ethanol blends. It will also discourage marketers that do not currently blend El 5 from entering that space. The Associations encourage EPA to add a clarification as §1090.740(a) (4) stipulating that parties that add more oxygenate to a product are not subject to the full suite of requirements applicable to refineries. [EPA-HQ-OAR-2018-0227- 0066-A1, pp.4-5] 8 The Associations would be extremely concerned and oppose any efforts to indirectly loop blenders into Renewable Fuel Standard requirements for obligated parties via an unintentional drafting error. Response: We have added language at §1090.740(a) (4) to make it clear that parties in situation discussed by the commenters do not have any additional requirements if the party is only adding more oxygenate (at allowable levels) to a BOB. These parties are still oxygenate blenders and therefore must, comply with requirements for oxygenate blenders (e.g., register with EPA, maintain records, use appropriate PTD language, etc.). These requirements already exist under part 80 and do not constitute any new or additional burden on such parties. We believe the additional language at §1090.740(a) (4) addresses commenters' concerns about clarifying what El 5 blenders must do under part 1090. This action does not modify how obligated parties incur RVOs under the RFS program. In an example posed by one commenter, where 15 volume percent DFE was added instead of 10 volume percent DFE to an E10 BOB, the party would not incur an RVO, as renewable fuels are exempt from RVO requirements (see §80.1407(f)(1)). 157 ------- 11. Registration Requirements (Subpart I) 11.1. General Comments Comment: > bp America Inc. (bp) Subpart I—Registration 51090.800(a)(2) Distribution terminals are often owned and operated by a third-party who has custody but not title to gasoline, diesel, and ethanol owned by multiple parties in the on-site tankage. We suggest EPA clarify this provision to indicate that the oxygenate blender who owns and operates an oxygenate blending facility needs to register, but the third parties who have title to the inventory do not. [EPA-HQ-OAR-2018-0227-0046-A1, pp.15] Response: We are not changing our approach to the registration of oxygenate blenders under part 1090 compared to part 80. As described in the 2016 Tier 3 Q&A document, "either the facility owner or a product owner may register an oxygenate blending facility, but each oxygenate blending facility should only be registered by one party. The facility owner and product owner(s) should work together to determine a course of action, independent of EPA. "19 Comment: > bp America Inc. (bp) Subpart I—Registration 51090.800(b) and (c) Parties that submit a registration will delay startup of the activity covered by that registration until the registration becomes effective. However, it is common that EPA does not notify registering parties within the specified waiting period. That can delay the start of an important commercial activity resulting in lost opportunity and cost. The registration provisions should clarify that once the specified waiting period (e.g., 30 or 60 days) has expired, the registration is effective unless otherwise rejected by EPA prior to that time. That will eliminate the uncertainty with the effective date associated with potential delays in EPA's review and approval of the registration. [EPA-HQ-OAR-2018-0227-0046-A1, pp.15] 19 See "Questions and Answers Regarding EPA's Tier 3 Gasoline Sulfur Regulations," EPA-420-F-16-053, November 2016. 158 ------- Response: We will not automatically approve registrations if a certain amount of time has elapsed since a registration request was submitted. We did not propose to change this requirement as it exists under part 80 and we believe that 60 days prior to engaging in activities for which registration is required is necessary for EPA to be able to act on registration submissions in a timely manner. Furthermore, we note that most parties required to register under part 1090 are already registered under part 80 and will not need to re-register as a result of this action. Comment: > bp America Inc. (bp) Subpart I—Registration 5 1090.800(e) As previously noted, distribution terminals are often owned and operated by third parties, and the inventory in their facilities is often owned by petroleum distribution companies. It can be confusing in cases such as that if EPA assigns a registration number to that distributor that differs from that assigned to the facility owner and operator. It would be substantially clearer to both the EPA and the distributor if the distributor's registration number for that facility was the same as the facility owner and operator. That would allow EPA to identify the exact facility where the operation is taking place and still allow clear identification of the distributor through the assignment of the distributor's company ID number. The only exception to that practice would be to further clarify that when registering a foreign facility, a new facility ID needs to be obtained regardless if other EPA registrants are already registered at that same facility. [EPA- HQ-OAR-2018-0227-0046-A1, pp. 15-16] Response: We will consider the commenter's suggestion regarding the implementation of the assignment of company and facility registration numbers as we develop forms and procedures for implementing the part 1090 registration requirements. Comment: > bp America Inc. (bp) Subpart I—Registration 51090.815(b)(1) As currently written, this provision provides registered parties with 30 days to correct any deficiencies in their registrations. The loss of the registration would mean that the activity 159 ------- covered by the registration would need to stop at the end of the 30-day timeframe thereby disrupting operations and important commercial activities. Given the challenges around correcting such deficiencies in a short timeframe such as delayed notification of the person actually responsible for making the change, intervening priorities such as fuel disruptions, absences due to sick days, and scheduled vacations, a longer timeframe to make the correction would be very useful. In order to ensure that a party has sufficient time without disrupting operations, it is recommended that EPA allows 60 days from the date of the notification to correct the deficiencies or explain why there is no need for corrective action. [EPA-HQ-OAR-2018-0227-0046-A1, pp.16] Response: We do not believe that more time is needed to allow for parties to correct deficiencies that could result in involuntary deactivation of company or facilities registration. We believe the regulations provide regulated parties with enough time to submit their required registration and reporting information to comply with regulatory submission deadlines. Under the involuntary deactivation procedures in part 1090, we will not notify regulated parties that we may involuntarily deactivate the party's registration until 30 days after the applicable deadline. We provide an additional 30 days for the party to correct any deficiency after that notification. We believe this provides adequate time for parties to comply with registration or reporting deadlines and correct any deficiencies before having their registration involuntary deactivated. Therefore, we are finalizing the provision as proposed. Comment: > Eversheds Sutherland (US) LLP General Compliance Overview Eversheds Sutherland agrees that currently registered entities should not have to re-register under Part 1090.8 [EPA-HQ-OAR-2018-0227-0076-A1, p.4] Registration. Reporting and Recordkeeping Eversheds Sutherland supports EPA's proposal that entities registered under Part 80 will continue to be registered under Part 1090. We also support EPA's proposed flexibility when there is a change in ownership in terms of what supporting documentation is needed and what timing is required; changes in ownership range in terms of complexity, and mandating a one size fits all approach unnecessarily burdens EPA and regulated entity.46 8 See Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,038. 46 Proposed Rule at § 1090.820. 160 ------- Response: We thank the commenter for their support. Comment: > Eversheds Sutherland (US) LLP Registration. Reporting and Recordkeeping EPA is proposing new provisions to address voluntary and involuntary cancellation of registration47; while there are similar provisions under the Renewable Fuel Standard program, such provisions do not apply to the other mobile source programs. Voluntary cancellation is appropriate and presumably already accomplished by the regulated entity reaching out to EPA to terminate a registration. Involuntary cancellation would be initiated by EPA in instances such as failure to submit a report or an attest engagement, or if the regulated party submits false or incomplete information, among other instances. The proposed rules would give the regulated party 30 days to correct the issue; however, the preamble states that the rule will allow for 14 days.48 If EPA adopts a deactivation provision, a registered entity should have 30 days to respond; fourteen days is too short. The vast majority of late reports will be inadvertent, and deactivation is an extreme and potentially devastating outcome. Further, a regulated entity may not realize information is incomplete, or may disagree with EPA, and adequate time is needed to respond. Therefore, EPA should adopt a timeframe of 30 days after EPA provides notice to the company that there appears to be a deficiency. [EPA-HQ-OAR-2018-0227-0076-A1, pp.15-16] 47 Id. at § 1090.815. 48 Id. at 29062. Response: The NPRM preamble did not match the proposed regulations; the longer time frame should apply and we have made the correction in the final rule. Comment: > Motiva Enterprises, LLC CDX Registration On page 96 of the preamble under section VIII. B. 2. EPA outlines the new roles under part 1090 that may change the designation of a facility relative to the designation under part 80. Page 97 of this section states that "existing registrants would only need to make the type of routine registration updates they already are required to make". 161 ------- Motiva asks if there is an expected date for the new classifications to show up in CDX to allow for time to verify that facilities are registered correctly under the new classification. [EPA-HQ- OAR-2018-0227-0073-A1, p.4] Response: We intend to have the new roles in the registration available as of the effective date of January 1, 2021. Parties will be able to review their registration and make appropriate updates at that time. Comment: > Eversheds Sutherland (US) LLP When an attest auditor, independent surveyor, or other third party associates with a fuel manufacturer's registration in CDX or EMTS, it should not have rights to access or amend any of the fuel manufacturer's information without explicit rights granted by the fuel manufacturer. We expect that EPA will set up the system with such limitations in place, but given the broader number of entities who will potentially have access, this was worth reiterating. [EPA-HQ-OAR- 2018-0227-0076-A1, p.16] > RINAlliance (I) Requiring Auditors to Register AND Associate with a Company is an Added Regulatory Burden with and Added Cost. It does not streamline the process. The point of the Fuel Regulatory Streamlining proposed rule is to streamline companies' compliance processes, resulting in greater efficiency. However, nothing about Section VIII.B of the proposed rule achieves this purpose. In addition to forcing companies to be exposed to increased risks as well as costs, the rule serves as a completely unnecessary duplication. To put it in more colloquial terms, "if it isn't broken, don't fix it." Many companies already submit their own attest engagements and other compliance reports. If the company prefers that the auditor submit their report, the auditor can register as a third party to the company. In effect, an auditor's submission of reports is already allowed. [EPA-HQ-OAR-2018-0227-0070-A1, p.l] Requiring auditors to register for a role that companies already complete is as unnecessary as it is nonsensical. Depending on the auditor, this could be hundreds of companies, and submitting association requests to each company would take several hours to many days as follow up with every company would be required. Most auditors calculate an hourly rate for their time. This means, that in order to achieve the proposed rule, any company would be forced to either absorb the cost or pass the cost of a completely unnecessary compliance procedure to consumers. The end result would only cost RFS participants time, money, and further decrease efficiencies in an already inefficient registration system. Given the fact that Section VIII of the proposed rule would not achieve its regulatory purpose, there is no cause to finalize it. [EPA-HQ-OAR-2018- 0227-0070-Al.pp.l-2] (II) Granting Auditors Unfettered Access to a Company's EPA Account Is Unnecessary. 162 ------- For a Delegated User or an RCO to associate to a company's EPA account, the Delegated User and the RCO are required to self- select their roles about their position within a company's EPA account. A Delegated User must designate at least one of the following roles: Employee, Agent, Engineer, RFS Submitter, RFS Viewer or company editor. Presumably, an auditor would need to self-select the following roles: Agent and RFS Submitter. By selecting these two roles, the auditor would, essentially, have unfettered access to an account the auditor has no need or reason to access. Even further, the auditor would receive every single email associated with a company's account that the auditor would have no reason or need to receive. As a direct result of their association with a company's account, every time a company received an email from EPA, whether for a compliance reason, an EMTS transactional reason, etc., the auditor would also receive it. This means an auditor could potentially be inundated with hundreds of emails daily on a regular basis. If the relationship between the auditor and the company ends, EPA offers no way for the auditor to automatically disassociate. This can only be done by the RCO, leaving the auditor to receive emails and be subject to potential liability long after the relationship is over. This is not only inefficient, but cumbersome and an undue burden the auditors would be forced to undertake. Yet again, Section VIII of the proposed rule only serves to provide unnecessary inefficiencies to the compliance process. [EPA-HQ-OAR-2018-0227-0070-A1, p.2] Granting access to auditors who have no reason to know the information in a company's EPA account is a disservice to the renewable fuel industry on the whole. Confidentiality is a prized possession throughout the industry. In fact, EPA allows all compliance reporting to be confidentially completed. More specifically, the information contained within any compliance reports submitted on a quarterly basis by a company to EPA can be marked as Confidential Business Information (CBI). Even after the implementation of the updated regulations on January 1, 2020, a company is still allowed to consider most of the information reported as CBI. Forcing companies to grant open access to auditors is not only completely unessential and unwarranted, but it is contrary to EPA actions to maintain confidentiality. [EPA-HQ-OAR-2018- 0227-0070-A1, p.2] (III) Conclusion In the final rule, EPA should not enact any portion of Section VIII of the proposed rule that would require auditors to register with the EPA. Doing so does not promote Fuel Regulatory Streamlining and serves no purpose other than to increase costs and the compliance burden. [EPA-HQ-OAR-2018-0227-0070-A1, p.3] Response: The commenters seem to misinterpret the implications of the proposal. EPA's system grants access based upon the role of the registrant. The auditor would only have access to submit the attest engagement to EPA and would not have access to the fuel manufacturer's other information. The auditor would still contact the company regarding the information needed to complete the attest engagement outside of EPA's systems. Although the step of registration and association adds a minor near-term burden, we believe there are benefits that will reduce burden over time. Our experience with part 80 programs has 163 ------- taught us that attest engagement reports often are not submitted or received, either because companies did not send them or because they sent them in a manner that resulted in EPA not receiving them. Having the auditor do the submission, while notifying the company, is an efficient way to eliminate a step and avoid deactivation of registration for failure to submit a required report. Recently, we have engaged in an oversight effort to ensure that all parties required to submit attest engagement reports do so or have their registration involuntarily deactivated. Parties that have failed to have attest engagements performed have had to pay substantial amounts to auditors to perform such work on short notice and spend significant time to come back into compliance. By requiring auditors to submit the reports directly to EPA, we believe we will reduce the number of parties that fail to submit their attest engagement reports, thereby reducing burden over time. Comment: > Valero Energy Corporation J. Subpart I — Registration Valero recommends removing the requirement of acquiring the signature of the RCO or RCO delegate of both companies in §1090.820(b) (3), as it does not serve any meaningful function. As proposed, the rules require the signature of the previous owner only if possible but compliance with a requirement that is imposed "only if possible" sets an unreasonable burden on the new owner to prove that obtaining the signature of the RCO of the prior owner was impossible. If the signature of the prior owner is not required if it is not possible, then EPA should not require it even if possible. The requirement serves no purpose in either case. [EPA-HQ-OAR-2018-0227- 0056-A1 p.12] Response: We believe it is important to require the signature of the RCO or RCO delegate of both companies for a change of ownership of a company or a facility and are finalizing the requirement as proposed. We have encountered cases where parties have tried to transfer ownership of a facility without approval of the prior owner of the facility. We recognize that it may be challenging to obtain a signature from companies that have gone out of business or the RCO no longer works for the company, which is why we only require the signature when possible. We will work with registrants regarding changes in ownership on a case-by-case basis. 164 ------- 12. Reporting Requirements (Subpart J) 12.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.1 Annual. Batch, and Credit Reporting In §1090.905 (c) (5) (i) (H) and (c) (5) (ii) (E), EPA proposes the same flexibilities as under Part 80 for gasoline manufacturers that wish to blend butane that has been certified to meet specifications. However, the May 1 through September 15 wording is misplaced. Butane and pentane suppliers should be reporting RVP year-round and RVP for gasoline batches that include butane blending should be for May 1 through September 15 only. The Associations suggest the following language for clarification. [EPA-HQ-OAR-2018-0227-0074-A1, p.8] (c) (5) (i) (H) The tested RVP of the batch, in psi, provided by the butane or pentane supplier, fer butane or pentane blended into PCG from May 1 through September 15. (c) (5) (ii) (E) The tested RVP of the batch, in psi, and the test method used to measure the RVPt for the batch of blended product from May 1 through September 15. [EPA-HQ-OAR-2018-0227- 0074-A1, p.8] > Buckeye Partners, L.P. §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers. Comment #1 - Section (C) (5) (i) (H) - For certified butane blenders (CBB), the RVP of the butane batch should not be required on EPA reports. Butane RVP is not a standard specification and no limit is required of the certified butane producer or blender. EPA indicates that blenders can report the butane RVP data provided by the producer, but the producer is not required to provide it. Buckeye believes this requirement was included in error, and requests that (H) be deleted from the rule as follows: (H) The RVP of the batch, in psi, provided by the butane or pentane supplier for butane or pentane blended into PCG from May 1 through September 15. [EPA-HQ-OAR-2018-0227-0032- Al, pp.1] Comment #3 - Section (C) (5) (ii) (E) - The requirement for certified butane blenders to report RVP only applies during the summer (May 1 through September 15). Buckeye requests that the required time range be added to the statement as follows: (E) The tested RVP off the batch, in psi, from May 1 through September 15 and the test method used to measure the RVP. [EPA-HQ-OAR-2018-0227-0032-A1, pp.2] 165 ------- > Energy Transfer L.P. (ET) 1) Subpart J—Reporting The new requirement in §1090.905 for the "RVP of the batch, in psi, provided by the butane or pentane supplier" is not in harmony with the focus of the requirement and is duplicative of the requirement for producers of regulated blendstocks to certify butane and pentane production batches. The focus of the RVP requirement is on the gasoline production batch (PCG plus regulated blendstock); the focus is not on the various supply chain parties of the batch. By placing the obligation on both the supplier and producer of the batch, it would result in unnecessary and duplicative testing within the same distribution chain for the same batch. Also, regulated blendstock producers and regulated blendstock suppliers are not always the same company, and §1090.905 would require suppliers to sample and test the same regulated blendstocks for RVP which had already been sampled and tested by a producer. We respectfully propose removing the RVP testing requirement on suppliers and producers of regulated blendstocks, and remove the certified blendstock RVP reporting requirement on regulated blendstocks blenders. [EPA-HQ-OAR-2018-0227-0044-A1, p.l] > Magellan Midstream Partners §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers (5) (ii) (E) As written, certified butane blended gasoline requires reporting of post-blend gasoline RVP year round. We believe this should be clarified to be consistent with the period of May 1st through September 15 as required in 905(5) (i) (H), as follows: (5) (ii) (E): "The tested RVP of the batch, in psi, and the test method used to measure the RVP^ from May 1 through September 15." [EPA-HQ-OAR-2018-0227-0078-A1, p.6] > Phillips 66 Company In §§1090.905 (c) (5) (i) (H) and (c) (5) (ii) (E), EPA proposes the same flexibilities as under Part 80 for gasoline manufacturers that wish to blend butane that has been certified to meet specifications. However, the May 1 through September 15 wording is misplaced. Butane and pentane suppliers should be reporting RVP year-round and RVP for gasoline batches that include butane blending should be for May 1 through September 15 only. The Associations suggest the following language for clarification. (c) (5) (i) (H) The tested RVP of the batch, in psi, provided by the butane or pentane supplier, fer butane or pentane blended into PCG from May 1 through September 15. (c) (5) (ii) (E) The tested RVP of the batch, in psi, and the test method used to measure the RVPt for the batch of blended product from May 1 through September 15. 166 ------- We do not agree with removing the phrase "for butane or pentane blended into PCG from May 1 through September 15" from §1090.905 (c) (5) (i) (H). In removing this language, it would require the butane/pentane blender to report the RVP of the butane/pentane all year round, which is not needed. We do strongly agree with adding it to the end of §1090.905 (c) (5) (ii) (E). > Shell Oil Products US L. Sections §1090.905 (c)(5)(i)(H) and §1090.905 (c) (5) (ii) (E) - Revision Needed Due to Language Being Misplaced §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers. (H) The RVP of the batch, expressed in psi, provided by the butane or pentane supplier for butane or pentane blended into PCG from May 1 through September 15. (E) The RVP of the batch, expressed in psi, and the test method used to measure the RVP. The May 1 through September 15 wording is misplaced. Butane and pentane suppliers should be reporting RVP year-round and RVP for gasoline batches that include butane blending should be for May 1 through September 15 only. We propose the following language: (H) The RVP of the batch, expressed in psi, provided by the butane or pentane supplier. (E) The RVP of the batch, expressed in psi, and the test method used to measure the RVP for butane or pentane blended into PCG from May 1 through September 15. [EPA-HQ-OAR-2018- 0227-0035-Al.pp.n-12] > Turner, Mason & Company (TM&C) Subpart J - Reporting Certified Butane The batch certification requirements for certified butane producers found 1090.1100(e), require one to ensure (2) (i) each batch of certified butane meets the requirements in 1090.220. These standards include butane, benzene, and sulfur content. The reporting requirements for the certified butane blender found in 1090.905(c) (5) (i) on the certified butane batch, require the RVP of the batch (H) when blended into PCG. If the agency intended to require the RVP of the certified butane to be measured, this requirement should be incorporated in 1090.1100(e) (2) (i). However, we would challenge that measuring the RVP of the certified butane does not provide value and would recommend eliminating this requirement in 1090.905(c) (5) as follows: (H) The RVP of the batch, in psi, provided by the butane or pentane supplier for butane or pentane blended into PCG from May 1 through September 15. Certified Pentane 167 ------- Similar to that highlighted above for certified butane, the batch certification requirements for certified pentane producers found 1090.1100(f), require one to ensure (2) (ii) each batch of certified pentane meets the requirements in 1090.225. These standards include butane, benzene, and sulfur content. The reporting requirements for the certified pentane blender found in 1090.905(c) (5) (i) on the certified pentane batch, require the RVP of the batch (H) when blended into PCG. If the agency intended to require the RVP of the certified pentane to be measured, this requirement should be incorporated in 1090.1100(f) (2) (ii). However, we recommend 1090.905(c)(5)(H) be eliminated as stated above for "Certified Butane." [EPA-HQ-OAR-2018- 0227-0045-Al.pp.2-3] Response: The RVP of certified pentane or certified butane does not need to be reported because RVP compliance during the summer is determined by the RVP of the summer gasoline or BOB. We are still requiring that the RVP be reported for new batches of blended summer gasoline or summer BOB (PCG plus certified pentane or certified butane) and have revised § 1090.905(c) (5) (ii) (E) to clarify that reporting RVP is only necessary for summer gasoline and summer BOB. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.1 Annual. Batch, and Credit Reporting Additional clarity is also sought in § 1090.905(c) (3) (i)(D), (F), and (G). Subsection D suggests that the volume should include oxygenate that would have been added with ethanol dilution. The language is not clear on whether the sulfur and benzene should be tested with or without ethanol dilution. With the understanding that the sulfur and benzene should be tested without ethanol dilution, there is a disconnect with the requirement that the volume should be determined on an ethanol dilution basis. Testing and volume determination should be on the same basis. With the understanding that the testing should be on a neat basis, the Associations propose the following language: (D) The batch volume without including the volume of any oxygenate that would have been added to the PCG, expressed as a negative number in gallons. (F) The tested sulfur content of the batch without ethanol dilution, expressed in ppm, and the test method used to measure the sulfur content. (G) The tested benzene content of the batch without ethanol dilution, expressed as a volume percentage, and the test method used to measure the benzene content. [EPA-HQ-OAR-2018- 0227-0074-A1, p.9] 168 ------- > Shell Oil Products US I. Section §1090.905 (c) (3) (i) (D). (F). and (G) - Suggest wording be revised for clarity and consistency for PCG §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers. (D) The batch volume including the volume of any oxygenate that would have been added to the PCG, expressed as a negative number in gallons. (F) The tested sulfur content of the batch, expressed in ppm, and the test method used to measure the sulfur content. (G) The tested benzene content of the batch, expressed as a volume percentage, and the test method used to measure the benzene content. Clarity is needed in this section. (D) suggests that the volume should include oxygenate that would have been added with ethanol dilution. The language above is not clear on whether the sulfur and benzene should be tested with or without ethanol dilution. With the understanding that the sulfur and benzene should be tested without ethanol dilution, then there is a disconnect that the volume should be determined on an ethanol dilution basis. Testing and volume determination should be on the same basis. With the understanding that the testing should be on a neat basis, we propose the following language: (D) The batch volume without including the volume of any oxygenate that would have been added to the PCG, expressed as a negative number in gallons. (F) The tested sulfur content of the batch without ethanol dilution, expressed in ppm, and the test method used to measure the sulfur content. (G) The tested benzene content of the batch without ethanol dilution, expressed as a volume percentage, and the test method used to measure the benzene content. Response: Testing the PCG that is BOB without the addition of oxygenates will result in the PCG appearing to have higher sulfur and benzene content than the original PCG manufacturer assumed in their compliance calculations, resulting in a small increase in the average sulfur and benzene content in the national gasoline pool. As such, we are clarifying the testing and reporting requirements for PCG under part 1090. If a fuel manufacturer adds blendstock to PCG to make a new batch of gasoline and elects to comply by subtraction, the manufacturer must account for the intended volume of the PCG plus oxygenates if the PCG is a BOB. This means adjusting the volume of the negative batch by the volume of oxygenate that would have been added as specified in the PCG manufacturer's PTD blending instructions. This also means creating and testing a hand blend of the PCG with the specified oxygenate type and amount to account for the dilution effect on sulfur and benzene content. We have revised the batch reporting requirements for PCG to 169 ------- appropriately account for the anticipated dilution effects of PCG that is BOB for which the PCG manufacturer accounted for oxygenate added downstream. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.1 Annual. Batch, and Credit Reporting In section VIII.C.4. of the preamble EPA acknowledges that "some regulated parties have expressed concern that they would not know if their attest engagement has been submitted by the auditor and would not be afforded time to review and respond to the auditor's findings." EPA requests comments about "what information and required steps are needed prior to submission by the attest auditor." The Associations share this concern and suggest EPA require attest auditors to obtain from the company an acknowledgement that the company has reviewed the final attest report, and to submit that acknowledgement with the final attest report to EPA. The Associations suggest revising § 1090.930(b) as follows: § 1090.930(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 report available to the company for which it was performed. The auditor must obtain from the company an acknowledgement that the company has reviewed the report, and the auditor must submit a copy of the acknowledgement to EPA with the report. [EPA-HQ-OAR-2018-0227- 0074-A1, p.10] > Flint Hills Resources 5) Part 1090 subpart J - §1090.930 Reports by auditors Suggestion: Revise § 1090.930(b) to read as follows: § 1090.930(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 report available to the company for which it was performed. The auditor must obtain from the company an acknowledgement that the company has reviewed the report, and the auditor must submit a copy of the acknowledgement to EPA with the report. Discussion: In section VIII.C.4. of the preamble EPA acknowledges that "some regulated parties have expressed concern that they would not know if their attest engagement has been submitted by the auditor and would not be afforded time to review and respond to the auditor's findings." EPA requests comments about "what information and required steps are needed prior to submission by the attest auditor." We share this concern and suggest EPA require attest auditors to obtain from the company an acknowledgement that the company has reviewed the final attest report, and to submit that acknowledgement with the final attest report to EPA. [EPA-HQ-OAR- 2018-0227-0052-A1, p.4] 170 ------- Response: We have added a requirement at § 1090.930(f) to require that auditors submit an acknowledgement from the gasoline manufacturer that the gasoline manufacturer has reviewed the attest engagement report. We believe that it is important that gasoline manufacturers receive and review copies of the attest engagement report so that they can take appropriate action to correct any deficiencies. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: However, we seek comment on whether we should rearrange the compliance deadlines as a means to reduce resubmissions and remedial actions. Comment: Report Resubmissions mainly involve properties and volumes and then there is a cascading effect on the sulfur, benzene, and RFS reports and corresponding transactions/retirements in EMTS. We ask for consideration that only the batch reports be due on March 31 for the preceding compliance period. During the attestation process, the batch reports will be reviewed, and resubmissions made as applicable. During the same attestation process and after the batch reports are finalized, the sulfur, benzene, and RFS reports can be completed and reviewed. The remaining reports, EMTS transactions/retirements, and attestation reports are due at the same time when the attestation report is due. This change in process will eliminate many resubmissions of reports and eliminate requests to the EMTS helpdesk to open/revise EMTS accounts. [EPA-HQ-OAR-2018-0227-0074-A1, p.30] As a result of the attest process, report resubmissions typically involve properties and volumes corrections as well as revisions to the sulfur, benzene, and RFS reports and corresponding transactions/retirements in EMTS. We recommend that the fuels compliance reports be due on June 1 for the preceding compliance period. During the attestation process, the preliminary draft batch, sulfur, benzene and RFS reports using EPA's revised reporting format will be reviewed, the final batch, sulfur, benzene , and RFS reports and corresponding EMTS transactions/retirements, would be due when the attestation report is due on June 1. This change in process will eliminate many resubmissions of reports, eliminate requests to the EMTS helpdesk to open/revise EMTS accounts, and issuance of any potential enforcement action by EPA for deficits that haven't been cleared by the facility prior to the compliance date. [EPA-HQ- OAR-2018-0227-0074-A1, p.30] 171 ------- It is recommended that EPA has the batch report using EPA's new format (RFG030X) due on June 1 with the other compliance reports, since the batch report will also require revisions as a result of the attest process. [EPA-HQ-OAR-2018-0227-0074-A1, p.30] > bp America Inc. (bp) Invalid Credits In Section VII.E. of the preamble, EPA discusses stakeholder comments on rearranging the compliance deadlines to have the annual compliance reports due after annual audits have occurred. The EPA did not make these requested changes stating that the revisions to the other sections will minimize the need to resubmit reports after the annual audits; however, they do seek comment on whether rearranging the compliance deadlines to reduce resubmission and remedial action. Based on bp's experience for reporting under the current regulations and a review of the proposed changes in the Streamlining Rule, bp does not believe the proposed changes will address all the issues managed through the attestation process that may lead to revision and resubmittal of fuels reports. However, reversing the order of submitting the fuels report and the attestation report will not fully address these issues. The first step in the process for gasoline manufacturers that have multiple facilities is to validate their data which typically takes 10-11 weeks which would put the completion date well into March. After that has been completed, the attest process is conducted which requires another 6-7 weeks. Thus, it would be more appropriate to align the fuels reporting compliance due date with the attestation report due date of June 1. In addition, an extension of the fuels reporting compliance due date to June 1 would assist gasoline manufacturers in addressing whether any of their facilities would need to consider utilizing the deficit carryforward provision, based on the availability of credits from other gasoline manufacturers, bp has provided the additional benefits for aligning the fuels reporting compliance due date with the attestation report due date of June 1 in their comments on the Reporting and Attest Deadlines. [EPA-HQ-OAR-2018-0227-0046-A1, pp.8-9] Reporting and Attest Deadlines In Section VII.E. of the preamble, EPA discusses stakeholder comments on rearranging the compliance deadlines to have the annual compliance reports due after annual audits have occurred. The EPA did not make these requested changes stating that the revisions to the other sections will minimize the need to resubmit reports after the annual audits; however, they do seek comment on whether rearranging the compliance deadlines to reduce resubmission and remedial action. Based on bp's reporting experience under the current regulations and a review of the proposed changes in the Streamlining Rule, bp does not believe the proposed changes will address all the issues managed through the attestation process that may lead to revision and resubmittal of fuels reports. The report resubmission process can be lengthy and time consuming and even with the changes that EPA has proposed, bp anticipates the necessity to revise reports. 172 ------- Furthermore, reversing the order of submitting the fuels report and the attestation report will not fully address these issues. Prior to conducting an attest, fuel manufacturers conduct a year-end reconciliation of the data that has been gathered to prepare for both reporting and the attest. That process normally takes 6-7 weeks to complete a thorough review of a facility's data. Fuel manufacturers that have multiple facilities typically require 10-11 weeks for data validation. The data is currently not available until early March, which results in a short time period for reviewing the data and then uploading the reports to the EPA reporting system. After the reports have been submitted, the attest process is conducted, which often finds minor reporting discrepancies that require the resubmission of the reports. Although bp agrees that some of the proposed reporting changes will improve the accuracy and efficiency of this process, the reporting process as described above will still remain the same and pose the same challenges. The reporting and attest process could be further improved on the accuracy of the reports and the efficiency of the process by aligning the fuels reporting compliance due date with the attestation report due date of June 1. A revision of the fuels reporting compliance due date to June 1 would also assist gasoline manufactures in determining whether any of their facilities would need to consider utilizing the benzene and sulfur deficit carryforward provisions. That determination is also very challenging with the current report submission deadlines. Given the additional logistical considerations of identifying sellers of those credits, contract negotiation, and contract fulfillment and the restrictions on buying and selling such credits, the current timing of the submission of those reports is very challenging. Revising the reporting deadline to June 1 would substantially facilitate that process. [EPA-HQ-OAR-2018-0227-0046-A1, pp.9-11] > Eversheds Sutherland (US) LLP Under the Proposed Rule, annual compliance reports would continue to be due March 31 of the year following the compliance year and attest audit reports would be due June 1. This is consistent with the current timeframes. Because the attest reports are due after the compliance reports, there are often corrections identified during the attest especially with regard to gasoline and diesel production volumes which impact sulfur and benzene credit generation or deficits. EPA correctly allows for resubmissions of relevant compliance reports, but Eversheds Sutherland agrees with other feedback EPA has received that better alignment of the report deadlines would allow for more accurate first-time submissions. While the resubmission process is not overly onerous, this streamlining effort is precisely the time to address such issues by moving compliance report deadlines to June 1. [EPA-HQ-OAR-2018-0227-0076-A1, pp.4-5] > Independent Fuel Terminal Operators Association (IFTOA) VIII. Annual Reporting Members of the Association also recommend that the deadline for such reports be moved from March 31st to April 30th. This change will provide regulated parties with additional time in which to verify reports, and such verification will, in turn, reduce the number of re-submissions. [EPA-HQ-OAR-2018-0227-0064-A1, p.5] 173 ------- > Shell Oil Products US N. Preamble - Change Reporting Deadlines Preamble states: However, we seek comment on whether we should rearrange the compliance deadlines as a means to reduce resubmissions and remedial actions. Report Resubmissions mainly involve properties and volumes and then there is a cascading effect on the sulfur, benzene, and RFS reports and corresponding transactions/retirements in EMTS. We ask for consideration that only the batch reports be due on March 31 for the preceding compliance period. During the attestation process, the batch reports will be reviewed and resubmissions made as applicable. During the same attestation process and after the batch reports are finalized, the sulfur, benzene, and RFS reports can be completed and reviewed. The remaining reports, ABT/EMTS transactions/retirements, and attestation reports are due at the same time when the attestation report is due. This change in process will eliminate many resubmissions of reports and eliminate requests to the EMTS helpdesk to open/revise ABT/EMTS accounts. [EPA-HQ-OAR-2018-0227-0035-A1, pp.12-13] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Annual Reporting NACS, NATSO, and SIGMA welcome EPA's Proposal to streamline and consolidate the fuel quality programs (i.e., volatility, benzene, and sulfur, etc.) into a single fuel quality program with unified annual reporting. 10 It is inefficient for market participants to have to report different things at different reporting deadlines. Consolidating the multiple reporting requirements into a single, unified annual reporting requirement will dramatically improve industry efficiency and reduce compliance burdens. The Associations, however, would encourage EPA to consider moving the deadline for submission of those reports to April 30th. By doing so, the Agency would provide obligated parties with greater time to verify reports, which will significantly reduce the number of resubmissions and calculation or clerical errors. [EPA-HQ-OAR-2018- 0227-0066-A1, p.5] 10 Proposal, supra note 1 at § 1090.900 et seq. Response: We do not believe the reporting deadlines for annual compliance or batch reports under part 1090 should be changed. Although reducing resubmissions of the annual reports is an important consideration, we must balance this against the need to verify compliance, process and utilize 174 ------- ABT and credit reports, and ensure data availability and transparency for the public in a timely manner. Furthermore, the purpose of the attest audit is to serve as a check on compliance, not to demonstrate compliance. Reversing their sequence or delaying the date for both to June 1 would delay compliance demonstration and change the purpose of the audit. Therefore, we are finalizing the reporting deadlines for annual compliance and batch reports under part 1090 as proposed and consistent with current requirements under part 80. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.905(c) Comment: The NPRM does not address the current situation where TGP is sold to a gasoline blending manufacturer and used as a blend component. In this situation, the TGP is considered PCG. We propose the following language should be inserted in 1090.905 (c) and be item (7): (7) For gasoline blending manufacturers that blend with TGP, where the TGP is treated like PCG, one of the following: (A) The information specified in paragraph (c) (3) of this section. (B) The information specified in paragraph (c)(4) of this section. [EPA-HQ-OAR-2018-0227- 0074-A1, p.39] > Shell Oil Products US J. Sections §1090.905 - TGP - Need Additional Language for Clarity When TGP is used by another entity other than the Transmix Processor §1090.905 (c) Batch Reporting Currently, the proposed rule provides regulations for the transmix processor and blending with TGP. See Depiction below: [The depiction can be found on p. 9 of EPA-HQ-OAR-2018-0227-0035-A1.] 175 ------- The regulations need to address another supply chain involving TGP. See depiction below. [The depiction can be found on p. 9 of EPA-HQ-OAR-2018-0227-0035-A1.] The proposed rule does not address the current situation where TGP is sold to a gasoline blending manufacturer and used as a blend component. In this situation, the TGP is considered PCG. We propose that the following language should be inserted in 1090.905 (c) and be item (7): (7) For gasoline blending manufacturers that blend with TGP, where the TGP is treated like PCG, one of the following: (A) The information specified in paragraph (c) (3) of this section. (B) The information specified in paragraph (c)(4) of this section. [EPA-HQ-OAR-2018-0227- 0035-Al.pp.7-9] Response: We are clarifying the regulations to address situations where TGP is transferred from a transmix processor to another fuel manufacturer and how such TGP will be reported. For TGP that is transferred to a blending manufacturer, the blending manufacturer will treat the TGP as PCG using either the compliance by addition or compliance by subtraction method. For TGP that is transferred to a refinery and further processed into gasoline, refiners will demonstrate compliance on the new gasoline or BOB without accounting for the sulfur, benzene, and volume of the TGP. Comment: > Buckeye Partners, L.P. §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers. Comment #2 - Section (C) (5) (ii) (C) -This requires the volume of the blended batch (CG + butane) to be reported, but not the amount of butane. The volume of butane blended should be required data needed in EPA reporting requirements as it is important to volumetrically report the creation of new gasoline and associated RIN obligations. The new volume of the blended product is difficult to accurately provide and the new volume is not otherwise relevant. The increased data inclusion (volume of blended product) is a new requirement that puts additional burden on butane blenders, with no value provided since the amount of butane blended will continue to be reported. Because the volume of blended product is not required, not relevant and may not be accurate, we ask that it be deleted in recordkeeping and reporting requirements. Our request to modify the requirement is as follows: (C) The butane volume blended batch volume, in gallons. 176 ------- Also, please note that Draft Instructions for Form RFG030X should also be modified to delete the obligation to report the volume of "Butane + PCG (Final)". The volume of the butane injected is sufficient for reporting requirements. [EPA-HQ-OAR-2018-0227-0032-A1, p.2] Response: The volume of certified butane or certified pentane is what should be reported. We have revised § 1090.905(c) (5) (ii)(C) to address this comment. Comment: > Eversheds Sutherland (US) LLP EPA is including in the reporting requirements a broad and amorphous requirement of "any other information as EPA may require."49 This language is not in the current reporting requirements and is unnecessarily broad and vague. It should be deleted, and EPA should go through a rulemaking to amend the reporting requirements to add specific new provisions. [EPA-HQ- OAR-2018-0227-0076-A1, p.16] 49 See Proposed Rule, Subpart J. Response: The "any other information as EPA may require" language is primarily used to help EPA administer the reporting requirements and to address situations where additional information is needed to accept required reports from regulated parties (e.g., comment fields explaining why a party could not submit a required data element or explain why credits were invalidly generated). These situations typically benefit the regulated party, as otherwise we would reject their report or find their report to be insufficient. This language is not intended to collect substantive reporting information that would require significant burden on the part of reporters to develop or report to EPA. We are finalizing this requirement as proposed, but have added clarifying language to reflect our intent to only collect information for administrative purposes. Comment: > Flint Hills Resources Flint Hills Resources (FHR) has been considering system changes as we prepare for implementation of part 1090. We have discovered some uncertainties around some aspects of the downstream BOB recertification provisions. More specifically, it is unclear which, if any, of the BOB recertification requirements apply at a physical facility level. Some provisions in the proposed rule clearly indicate BOB recertification is a company-level requirement. These provisions are listed in Appendix A below. However, other provisions cloud 177 ------- the issue by mentioning "facility" in the context of BOB recertification. Those provisions are listed in Appendix B below. The difference between applying the BOB recertification provisions at the company level versus the facility level is significant. For example, assuming a company does BOB recertification at a modest 100 terminals, then certain requirements - registration, reporting, attestation - are orders of magnitude more burdensome at the facility level versus the company level. There would be 100 facility registrations versus 1 registration at the company level; 1,200 batch reports at the facility level versus 12 batch reports at the company level; 100 facility attestation audits versus 1 company audit. It seems clear from the preamble and some of the proposed provisions that EPA did not intend to impose unreasonable new burdens with regard to the new BOB recertification requirements. Therefore, it is reasonable to assume that the BOB recertification provisions should apply at the company level. Therefore, FHR requests that EPA consider the changes we propose in Appendix C below. [EPA-HQ-OAR-2018-0227-0086-A1, p.l] Appendix A Here are a number of provisions in the proposed rule that clearly indicate BOB recertification batches should be accumulated at the company level: • §1090.1120(c): 11 Gasoline manufacturers that recertify BOBs under §1090.740 may include up to a single month's volume as a single batch for purposes of reporting to EPA." This appears to say that a company could have as few as 12 batches of recertified BOB per year. • §1090.740(a) (3): " Unless otherwise required under this part, gasoline manufacturers that recertify 200,000 or less gallons of BOB under this section do not need to arrange for an auditor to conduct audits under subpart R of this part." This appears to apply at the company level. • §1090.740(b) (2) and (b) (4): The total sulfur and benzene deficit calculations appear to be accumulations of all the individual batch deficits for the entire company. • §1090.1840(e): Several attestation procedures in subpart R specify that they be performed for each of the company's facilities; however, the procedures for companies that recertify BOB in §1090.1840(e) make no mention of facility-level procedures, only that the procedures are to be performed for the "gasoline manufacturer." Appendix B Here are provisions in the proposed rule that refer to "facility" in the context of BOB recertification: • §1090.910(a) (1): Regarding batch reporting, " Any person that recertifies a BOB under §1090.740 with less oxygenate than specified by the fuel manufacturer of the BOB must 178 ------- report the following for each batch: (i) The EPA-issued company andfacility identifiers for the recertifying gasoline manufacturer..." This provision, as it stands, appears to require BOB recertification batch reporting at the physical facility level. • §1090.1120(a): Regarding batch numbering, " Fuel manufacturers ... must assign a number (the "batch number ") to each batch ... The batch number must, if available, consist of... the EPA-assignedfacility registration number where the fuel... was produced..." While the qualifier " if available" might have been intended to apply in the situation of BOB recertification batches, it is not clear and could be interpreted that a physical facility ID is required when formulating batch numbers for BOB recertification batches. • § 1090.905 (a) (2) (iv) (E) and (b) (2) (vi) (E): The reporting requirement for the total sulfur and benzene deficits appear in the paragraphs labeled "Facility-level reporting" despite the deficit totals calculated in §1090.740(b)(2) and (b)(4) being company-level totals. Appendix C FHR suggests the following changes to remove facility-level uncertainties in relation to BOB recertification: • Revise §1090.910(a) (1) to read: "Any person that recertifies a BOB under §1090.740 with less oxygenate than specified by the fuel manufacturer of the BOB must report the following for each batch: (i) The EPA-issued company identifier and facility identifiers for the recertifying gasoline manufacturer. • Revise §1090.1120(a) by appending the following sentence at the end of the paragraph: "For BOB recertification batches created pursuant §1090.740. use "00000" as the facility number part of the batch number." • Add as §1090.905(a)(l)(iii), making this a company-level item: "The total sulfur deficit from downstream BOB recertification. per §1090.740(b)(2)." • Strike §1090.905(a)(2)(iv)(E), removing this as a facility-level item: "The total sulfur deficit from downstream BOB recertification, per § 1090.740(b) (2)." • Add as §1090.905(b)(l)(iii), making this a company-level item: "The total benzene deficit from downstream BOB recertification. per §1090.740(b) (4)." • Strike §1090.905(b)(2)(vi)(E), removing this as a facility-level item: "The total benzene deficit from downstream BOB recertification, per §1090.740(b) (4)." [EPA-HQ-OAR- 2018-0227-0086-Al.pp.l-3] Response: We intended for compliance for BOB recertification to be at the facility level. The proposed language for batch numbering at §1090.1020(a) described company and facility ID's to refer to cases where we do not issue company or facility ID's due to the registration requirements. As the commenter noted, the proposed regulations required the registration of parties that recertify BOB to register at the company and facility level, and so that portion of the batch numbering requirements at §1090.1020(a) would be applicable. The company-level deficit and credit balances include an aggregation of all facility-level compliance, which would include any deficits incurred at the facility level for BOB recertification. We do not believe any changes to 179 ------- the proposed reporting requirements are needed as they captured our intent. However, we have made clarifying edits to the BOB recertification provisions at §1090.740 to more clearly state that compliance with BOB recertification is at the facility level. Comment: > Independent Fuel Terminal Operators Association (IFTOA) VIII. Annual Reporting The Association supports EPA's proposal to eliminate quarterly reporting requirements and require only annual reports for sulfur, benzene, batches, and credit transactions under § 1090.905. This approach will greatly reduce compliance costs for industry and oversight costs for EPA. [EPA-HQ-OAR-2018-0227-0064-A1, p.5] Response: We thank the commenter for their support. Comment: > Magellan Midstream Partners §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers (6) We believe the EPA should remove this portion, and do not believe reporting of TGP should be required unless blendstock is added or if the TGP is included in the benzene and sulfur calculations. [EPA-HQ-OAR-2018-0227-0078-A1, p.6] Response: We have clarified the language at §1090.905(c)(6) to only require reporting for gasoline made by adding or blending TGP with blendstock. Comment: > Shell Oil Products US 2. Collecting and preparing samples for testing section and Reporting Need to Match up There is no issue here from a compliance standpoint but clarity is needed for reporting. If you tested the tank or vessel for homogeneity for RVP, instruction is needed as to what value to report for the batch. I suggest the following in the reporting section: §1090.905 Annual, batch, and credit transaction reporting for gasoline manufacturers. 180 ------- (c) Batch reporting. Gasoline manufacturers, for each of their facilities, must report the following information on a per-batch basis for gasoline and gasoline regulated blendstocks: (1) For gasoline, and BOB for which the fuel manufacturer does not include the addition of downstream oxygenate in their compliance calculations as specified in §1090.710: (B) The tested RVP of the batch, in psi, and the test method used to measure the RVP. If multiple test results exist due to homogeneity testing for example, report the highest value. (2) For BOB in which the oxygenate to be blended with the BOB is reported by, and included in, the compliance calculations of the gasoline manufacturer that produced the BOB: (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. If multiple test results exist due to homogeneity testing for example, report the highest value. [EPA-HQ-OAR-2018-0227- 0085-A1, pp.2-3] Response: We have clarified that fuel manufacturers should report the highest RVP value if multiple test results exist to demonstrate per-gallon standard compliance. We note that for sulfur, fuel manufacturers should report two sulfur values (similar to part 80 reporting requirements): one for per-gallon compliance (which would be the highest value if multiple test results exist) and one for average standard compliance (which would be the average of the values). Comment: > Valero Energy Corporation 3. Due to changes with various aspects of the fuel rules in this Fuel Streamlining Rule, reporting under the new regulation may require additional time for the first set of reports that would be due after implementation of the new rules. Valero recommends that EPA implement reporting in a manner similar to how EPA implemented reporting under the Renewable Fuel Standard where EPA extended the compliance due date for the first compliance year by two months.4 [EPA-HQ- OAR-2018-0227-0056-A1, p.13] 4 40 CFR §80.1152 (a)(x) Response: We believe that there is adequate time for parties with reporting requirements to meet the first annual reporting deadline under part 1090 (March 31, 2022). We must balance the amount of time allowed for submission of required reports against the need to verify compliance, process 181 ------- and utilize ABT and credit reports, and ensure data availability and transparency for the public in a timely manner. 182 ------- 12.2. Reporting Forms Comment: > bp America Inc. (bp) Subpart J - Reporting Reporting Templates RFG030X: Gasoline and Gasoline Blendstock Batch Summary Report As described in section §1090.740(a), a gasoline manufacturer may recertify a BOB for which another gasoline manufacturer has specified oxygenate (s) blending instructions under §1090.710(a) (5). In that case the recertifying gasoline manufacturer may blend a different type or amount of oxygenate (including no oxygenate) if it meets all the requirements of this section. It is bp's understanding that only a 'gasoline manufacturer' can recertify the BOB downstream for a different type or amount of oxygenate even if the recertification is for the same amount or more oxygenate. When that occurs, the 'recertifying gasoline manufacturer' (not the 'original gasoline manufacturer') needs to incur the sulfur and benzene credit deficit downstream and report the BOB recertification when recertifying for less oxygenate. There may be compliance periods when downstream gasoline manufacturers recertify a BOB, or there may be compliance periods when no BOB recertification has taken place. Among the documents EPA posted in the rulemaking docket are the reporting forms that will be used for the submission of reports under 40 CFR Part 1090. Reporting form RFG030X contains two fields for reporting sulfur and benzene deficits created by downstream BOB recertification (See Fields Nos. 27 and 28). Both fields require numerical input. Since the form is designed to be used by all gasoline manufacturers, it will also be applicable to refineries. However, those refineries typically transport their gasoline production on fungible pipeline systems and do not and cannot obtain information on the actual downstream handling of the specific molecules that the refinery produced. Therefore, those refineries would typically not know whether the oxygenate specified on the refinery PTD was appropriately added to the fuel as the refinery is not the recertifying gasoline manufacturer. This would only be known by the downstream gasoline manufacturer who conducted the recertification. It is not possible for refineries in their capacity as gasoline manufacturers to complete Field Nos. 27 and 28 in this form if the BOB is recertified by another gasoline manufacturer. Presumably EPA intended those fields to be inapplicable to refineries that transport their gasoline in fungible systems. Therefore, bp recommends for completing Field Nos. 27 and 28, EPA amend their instructions to allow a gasoline manufacturer to either enter NA (not applicable) or a zero value to represent that no recertification has occurred for a BOB. Otherwise, refineries would not have numerical data reasonably available that would permit them to complete those fields. [EPA-HQ- OAR-2018-0227-0046-A1, pp.16-17] 183 ------- Response: We have revised the final form corresponding to proposed form RFG030X, Fields 27 and 28 to allow for an NA entry, where appropriate. Comment: > bp America Inc. (bp) Subpart J - Reporting Reporting Templates ABT0300: Gasoline Averaging. Banking, and Trading (ABT) Facility Summary Report Reporting form ABT0300 was also posted in the docket, which appears to combine EPA's previous reporting forms GSF100, GSF0302 & RFG2000. Similar to bp's comment on reporting form RFG030X, there may be instances when a gasoline manufacturer downstream of a refinery recertifies a BOB that does not impact the original gasoline manufacturer's sulfur and benzene credit/deficit calculations. Or there may be instances when no BOB recertification has taken place during the reporting period. Therefore, bp recommends for completing Field No. 11 EPA amend their instructions to allow a gasoline manufacturer to either enter NA (not applicable) or a zero value to represent that no recertification has occurred for a BOB. Otherwise, refineries would not have numerical data reasonably available that would permit them to complete that field. [EPA-HQ-OAR-2018-0227-0046-A1, pp.17] Response: We have revised the final form corresponding to proposed form ABT0300, Field 11 to allow for an NA entry, where appropriate. Comment: > bp America Inc. (bp) Subpart J - Reporting Reporting Templates Optional Reporting Forms for Sulfur and Benzene Transactions Currently, EPA does not require Reporting forms GSF0200 and RFG2200 to be completed to identify the sulfur and benzene credit transactions that were conducted by a gasoline manufacturer during a compliance period. EPA discontinued the use of these forms for 2019 reporting, bp recommends EPA provide these optional transaction reporting forms or include the 184 ------- transaction information in the ABT0300 reporting form as optional fields for a gasoline manufacturer to use. [EPA-HQ-OAR-2018-0227-0046-A1, pp.17] Response: We no longer believe these forms are necessary, as the information is available within EMTS, which gasoline manufacturers are required to use, and may be submitted via that system without need for a separate form or fields. Comment: > bp America Inc. (bp) Subpart J - Reporting Reporting Templates RFG030X: Gasoline and Gasoline Blendstock Batch Summary and ABT0300: Gasoline Averaging, Banking, and Trading (ABT) Facility Summary Reports bp also recommends EPA review the citations listed in the Field Formats, Codes and Special Instructions column for each report template as there are errors. For example, ABT0300 form, line item 12 (unadjusted volume weighted average level') references annual average sulfur level - See §1090.700(a) (3) (i). The regulatory citation should be §1090.700(a) (2) (i). [EPA-HQ-OAR- 2018-0227-0046-A1, pp.17-18] Response: We have corrected the regulatory citations in the final forms. Comment: > CITGO Petroleum Corporation (CITGO) 4.4 Reporting Forms During review of the draft RFG030X reporting form, the following was noticed: • FIELD 10 - EXP - There is current additional language that should be updated and added relevant to EXP and ZER instructions. Current RFG0303 Instructions: "Enter the one appropriate volume type code from the following list. There are two cases where it is acceptable to report a negative batch volume: if the batch is either Previously Certified Gasoline (PCG) or if the batch was previously reported and has been subsequently exported (EXP)." 185 ------- Recommended Instructions: "Enter the one appropriate volume type code from the following list. There are three cases where it is acceptable to report a negative batch volume: if the batch is either Previously Certified Gasoline (PCG), a BOB recertification with less oxygenate, or if the batch was previously reported and has been subsequently exported (EXP)." • FIELD 10 - ZER - Clarification is needed as to why you need to state the ZER qualification, especially since the volume would be 0? • FIELD 11 - "If reporting a zero batch volume other than a cancelled batch, please provide additional detail in comments field." - Clarification is needed on the details for when this would be used. • FIELD 14 - This aligns to the current NPRM but need a suboctane designation or clarification that suboctane is reported as CG? Also, what about Blendstock recovered from transmix and added to diesel? • FIELD 15 - Gasoline volatility standards should be §1090.215a. Also what are we to use to designate California gasoline? • FIELD 17 on - When would "otherwise untested" be used? • FIELD 19/20, 24/25, - See notes on FIELD 14 also; suboctane gasoline is "not finished gasoline" and not [regulated] "blendstock". It is gasoline that is tested neat therefore to report parameters neat, it would have to be done on FIELD 19 and 24. However, this is inconsistent with regulatory language. . FIELD 27 -The citation should be § 1090.740(b) (3). [EPA-HQ-OAR-2018-0227-0054- Al, pp.15-16] > Shell Oil Products US R. Clarity is needed for Export Batch reports Report Form - Field 10 Please provide an explanation/example of the situation in which a gasoline batch is designated as "EXP" - Exported Batch and what fields should be reported. Currently, export gasoline batches are not reported to EPA and we do not support that there be a new requirement for export gasoline batch reports for EPA Streamlining. Such a new requirement would be a significant new burden. [EPA-HQ-OAR-2018-0227-0035-A1, pp.15] Response: We have revised the final form instructions to reflect that BOB recertification batches are required to be reported as a negative volume. The "ZER" volume type is for cases where a party has had to zero out an entire batch due to a variety of reasons, including situations such as a need to reprocess a batch due to contamination, a decision to redesignate a batch to another fuel type, or a decision to export an entire batch. Field 11 is for reporters to provide more information regarding the rationale for why a batch was zeroed out. Regarding Field 14, the commenter is correct that suboctane gasoline would be reported as either CG or RFG. Blendstock recovered from transmix added to diesel fuel is not something that needs to be reported to EPA. We have revised the final form instructions to clarify that transmix added to diesel fuel is not something 186 ------- that needs to be reported to EPA. Parties that redesignate California Gasoline for use outside of California without recertification do not report the batch, so we are not adding California RVP requirements to Field 15. Regarding Field 17, we have added clarifying instructions in the final form for when "untested" is reported. For Fields 19/20 and 24/25, these fields would be reported as CG in the case the commenter outlined. For Field 27, we have corrected the regulation citation references in the final form instructions. We are not requiring that exported batches be reported under part 1090, consistent with part 80. For the "EXP" volume type in Field 10, we included this volume type for cases where a batch has been reported to EPA for use in the U.S. but a portion of the batch was exported. The exported portion would be referenced as a negative volume. In cases where an entire batch is exported and needs to be zeroed out, the "ZER" code should be used. Comment: > CITGO Petroleum Corporation (CITGO) 4.4 Reporting Forms During review of the draft ABT0300 reporting form, the following was noticed: • FIELD 8 -The citation for sulfur should be §1090.700(a). The citation for benzene should be should be §1090.700(b). • FIELD 11 -The citation for sulfur should be §1090.740(b) (2). The citation for benzene should be §1090.740(b) (4). • FIELD 12 - The citation for sulfur should be §1090.745(b). • FIELD 13 - Calculation for these values in the NPRM is §1090.745(c) for sulfur and (d) for benzene. • FIELD 15 - The citation for sulfur should be §1090.715(a) (1). The citation for benzene should be §1090.715 (a) (2). [EPA-HQ-OAR-2018-0227-0054-A1, pp.16] Response: We have corrected the citations in the final form. Comment: > CITGO Petroleum Corporation (CITGO) 4.4 Reporting Forms During review of the draft DSL0100 reporting form, the following was noticed: . FIELD 8 - The citation should be §1090.305. [EPA-HQ-OAR-2018-0227-0054-A1, pp.16] 187 ------- Response: We have corrected the citation on the final form. Comment: > CITGO Petroleum Corporation (CITGO) 4.5 General Questions (3) When reviewing the referenced EPA testing chart, the volume of CBOB neat is not reported however, the volume of RBOB neat is, why? [EPA-HQ-OAR-2018-0227-0054-A1, p.17] Response: The proposed regulations at § 1090.905(c) stated that the volume of BOBs be adjusted to include the volume of oxygenate to be added downstream, which we are finalizing as proposed. We have revised the final reporting form instructions to make it clear that this is reported consistently for both RBOB and CBOB. Comment: > Shell Oil Products US 0. Disconnect on Proposed Batch Report Form Below is the language on Page 1 for the Instructions for RFG030X. • Special Instructions for butane blending reporting - Butane reports are a combination of three reports with three separate batch IDs to include: o Butane batch - volume and properties of only the butane blendstock as received by the butane producer as shown in table 1 o PCG + butane or the properties of the finished batch of gasoline as shown in table 1 • Special instructions for pentane blend reporting - Pentane reports are a combination of three reports with three separate batch IDs to include: o Pentane batch - volume and properties of only the pentane blendstock as received by the butane producer as shown in table 1 o PCG + pentane or the properties of the finished batch of gasoline as shown in table 1 The language above suggests that there are three reports for butane and pentane blending batch reports. Only two items are listed for butane and pentane. Clarifications is needed to explain what the third report is for butane and pentane blending or change the language in the instructions that the reports are a combination of two reports for butane and pentane blending. [EPA-HQ-OAR-2018-0227-0035-A1, pp. 15] 188 ------- Response: We are finalizing the two items listed for certified butane and pentane blending and have revised the final forms to be consistent with those reporting requirement. Comment: > Shell Oil Products US S. Additional and Revised Language Needed for Batch Volume Report Form - Field 11 Currently, the following statement is in Field 11. BOB Product Type - This volume is the sum of the BOB volume and the oxygenate volume that the gasoline manufacturer specifies to be blended with the BOB. We recommend that different and additional language be provided in Field 11. We propose the following language: Batches certified without ethanol dilution - Production volume of base gasoline Batches certified with ethanol dilution - Production volume of the BOB and the oxygenate volume that the gasoline manufacturer specifies to be blended with the BOB[EPA-HQ-OAR- 2018-0227-0035-A1, pp.16] Response: As discussed in Section 12.1 of this document, we have revised the reporting requirements for PCG to ensure that PCG volumes and parameters are appropriately accounted for if the PCG manufacturer accounted for oxygenate added downstream under §1090.710. As the commenter suggested, we have revised the reporting instructions to help ensure that PCG volumes are reported accurately and appropriately. Comment: > Shell Oil Products US T. Different Description Needed for "TB" Report Form - Field 14 Currently, the report form defines TB as "Blendstock recovered from transmix and added to gasoline. We propose the following language: 189 ------- TB - TGP recovered from transmix and added to gasoline[EPA-HQ-OAR-2018-0227-0035-Al, pp.16] Response: We have revised the reporting form as the commenter suggested. Comment: > Shell Oil Products US U. Clarification Needed for "EX" Designation Report Form - Field 15 Currently, there is an option for summer gasoline - "EX" - Exempt from RVP control. The "EX" designation would apply to gasoline for Hawaii, Alaska, Puerto Rico, and other US territories. Should "EX" be used year round? If not, what timeframe should "EX" be used for? Batches manufactured during May 1- September 15th? Please clarify in the report form. [EPA-HQ-OAR- 2018-0227-0035-A1, pp.16-17] Response: The commenter is correct that the "EX" designation applies to summer gasoline for Hawaii, Alaska, Puerto Rico, and other US territories. The "EX" designation would not be used for winter gasoline. We have added language on the reporting form to clarify how the "EX" designation is used. Comment: > Shell Oil Products US V. Disconnect between Proposed Batch Report Form and Regulatory Language in 51090.1355(d) §1090.1355 Calculation adjustments and corrections. (d) If measured content of any oxygenate compound is less than 0.1 percent by mass, record the result as "None detected." Report Form - Field 16 [See figure on p. 17 of EPA-HQ-OAR-0227-0035-A1.] 190 ------- The regulatory language requires that "None detected" be reported when the oxygenate compound is below 0.1 percent by mass. The results are reported in %volume. It is suggested that a note be added to Field 16 in the report form to reflect the requirement to report "None detected" when applicable. It is also suggested that "ND" would be sufficient instead of "None detected". [EPA-HQ-OAR-2018-0227-0035-A1, p.17] Response: We have clarified the instructions for Field 16 and provided an appropriate, abbreviated entry for "none detected." Comment: > Shell Oil Products US W. Not Applicable - "NA" - Needs to be an Option in Several Report Fields The statement - Enter "NA" only if field does not apply to the reported batch - needs to be added to the following report fields - Field 16, 17, 18, 27, 28, 29, and 30. For Fields 16, 17, and 18, if one chose not to test for oxygenate, then "NA" would be an option needed because these fields are not applicable. When using ASTM D4815, the correlation equation is only for ethanol. The other oxygenates would not be reported and "NA" would be used for these fields. For Fields 27, 28, 29, and 30, if one does not have a deficit or the batch does not involve butane or pentane, then "NA" would be an option needed because these fields are not applicable. [EPA-HQ-OAR- 2018-0227-0035-A1, pp.17] Response: We have revised the final form corresponding to proposed form RFG030X to allow for an NA entry, where appropriate. Comment: > Shell Oil Products US X. Table 1 - Batch reporting and compliance requirements Needs Revised We suggest that this table represent completely the regulatory requirements. Under Requirements Key, another category should be added - 6 - Measure/Test and Record Keeping Only. In addition, a column should be added for Distillation. Category 6 would be used for Distillation where applicable. [EPA-HQ-OAR-2018-0227-0035-A1, pp.18] Response: Distillation should not be included on the reporting table included in the final form reporting instructions. The reporting table in the proposed RFG030X was intended to reflect only data 191 ------- elements reported to EPA. We believe that inclusion of a tested parameter that is not required to be reported to EPA in reporting form instructions will result in confusion on the part of parties required to report. The sampling, testing, and recordkeeping requirements for distillation are specified in Subparts M and N. 192 ------- 13. Batch Certification, Designation, and PTD Requirements (Subparts K and L) 13.1. General Comments Comment: > Petroleum Marketers Association of America (PMAA) Recertification - PMAA believes simplifying the recertification process for distillates, particularly heating oil, will increase downstream fungibility and provide wholesale and retail distributors the flexibility needed to meet their residential and commercial customer supply obligations. Heating oil dealers must plan their supply needs based on the inexact science of predicting weather temperatures months in advance. The quality of those predictions not only determine the quantity of supply available to heat residential homes, apartment buildings and commercial establishments, but also determines the price at which it will be sold. The process is unforgiving, especially for those who purchase seasonal supply at a fixed price. Problems arise for heating oil dealers with the occurrence of unexpected and prolonged severe wintertime temperatures that push demand beyond supply. The resupply of heating oil during unexpected sever wintertime temperatures can be unpredictable. Most heating oil is supplied by barge. Wintertime deliveries can be delayed for lengthy periods due to iced in port facilities that prevent offloading. When this occurs, heating oil dealers are forced to scramble for alternative supply sources to prevent customer freeze-ups. [EPA-HQ-OAR-2018-0227-0083-A1, pp.3-4] The ability to recertify diesel fuel or kerosene as heating oil without triggering onerous testing and reporting requirements meant for terminal operators and refiners would help ease supply shortages during severe cold weather. Simplified recertification would also provide heating oil dealers with the ability to switch between diesel fuel and heating oil based on price differentials. The ability to recertify heating oil to diesel fuel is less in demand due to IRS dye requirements for nontaxable fuels in order to distinguish it from clear taxable on road motor fuels. Recertification to diesel fuel could only occur if the sulfur content of the heating fuel was limited to 15 ppm and the product is sold for a nontaxable use (by state or local government, in off-road vehicles or for use in emergency generators). Nevertheless, the simplification of the recertification process for distillates, along with removal of the prohibition against the presence of red dye in motor vehicle fuel will significantly improve downstream fungibility allowing heating oil dealers to more easily meet their supply needs and price their product more competitively. [EPA-HQ-OAR-2018-0227-0083-A1, p .4] Response: We thank the commenter for their support. 193 ------- 13.2. Batch Certification and Designation Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.13 In-line Blending: Batch Certification Section 1090.1100(a) (4) proposes, " [f]or fuel produced at a facility that has an in-line blending waiver under §1090.1315, the volume of the batch is the volume of product that is homogeneous under the requirements of §1090.1337 and is produced during a period not to exceed 3 days." The Associations believe that the "not to exceed 3 days" requirement fails to recognize and account for the wide variation in batch sizes that exists within the refining industry. Recognizing this variation in batch size, the implementation of a requirement that limits the size of a batch to the volume produced in 3 days or less would potentially be very disruptive to established product supply and distribution logistics systems. We request that the above regulatory language requiring an in-line blend to not exceed 3 days be removed. [EPA-HQ-OAR-2018-0227-0074- Al, p.23] > bp America Inc. (bp) Subpart K—Product Transfer Documents §1090.1100 Batch certification requirements. §1090.1100(a) (4) states "For fuel produced at a facility that has an in-line blending waiver under §1090.1315, the volume of the batch is the volume of product that is homogeneous under the requirements of §1090.1337 and is produced during a period not to exceed 3 days." We recommend this duration to be for 10 days to reduce missed pipeline shipments. Three days duration is too short for a small to midsize refinery to produce enough volume for one gasoline batch. [EPA-HQ-OAR-2018-0227-0046-A1, p. 19] > Phillips 66 Company We also ask EPA to modify language in §1090.1100(a) (4) by removing the 3-day limitation for batches produced via in-line blending, as follows. (4) For fuel produced at a facility that has an in-line blending waiver under §1090.1315, the volume of the batch is the volume of product that is homogeneous under the requirements of §1090.1337. and is produced during a period not to exceed 3 days. The proposed language seems to also require diesel in-line blend waivers to be resubmitted, even though there should not be any changes to those waivers. The reformulated gasoline waivers will change (elimination of some property monitoring and testing) and the conventional gasoline 194 ------- waivers will change (requires addition of RVP to the waivers previously covering only sulfur). Therefore, it is logical that these waivers need to be modified and resubmitted. We cannot identify a purpose in resubmitting diesel in-line blend waivers so ask EPA to provide clarification that it is only the gasoline waivers that require resubmission and approval. [EPA- HQ-OAR-2018-0227-0060-A1, p.7] > Shell Oil Products US B. §1090.1100 (a) (4) - Limitation on In Line Blend Length Needs Removed §1090.1100 Batch certification requirements. 4) For fuel produced at a facility that has an in-line blending waiver under §1090.1315, the volume of the batch is the volume of product that is homogeneous under the requirements of §1090.1337 and is produced during a period not to exceed 3 days. The above language limiting the length of an in-line blend needs removed. Such limitations can cause issues with pipeline schedules and vessel loadings. For example, a blend to a vessel could be paused due to unforeseen issues with the ballast of the vessel for a long period time. Another example is when there is a schedule change and the pipeline calls a refiner and asks for the blend to be extended until the next refiner is available to pump into the pipeline. [EPA-HQ-OAR-2018- 0227-0035-Al.pp.3-4] Response: We believe that there needs to be some limit on the size of batches under in-line blending waivers in order to ensure all fuel shipped in this manner is still compliant with the standards. However, we are revising the batch certification requirement from 3 days to 10 days, as suggested by one commenter, as we feel this will provide enough flexibility to avoid issues with pipeline schedules and vessel loadings while ensuring that batches are still homogeneous. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1110(b) (2) Distributors may redesignate batches or portions of batches of gasoline for which they transfer custody to another facility without recertifying the batch or portion of the batch as follows: Comment: 195 ------- Terminals that perform butane blending and/or BOB recertifications are refiners. These terminals need the option to perform redesignations. As currently written, only distributors can perform redesignations. Two exceptions need added to allow for terminals that are butane blenders and/or perform BOB recertification to redesignate. This change is needed especially for supply disruptions and terminals should not be disadvantaged due to being butane blenders and/or performing BOB recertifications. We propose the following language: (2) Distributors and terminals that are refiners due to butane blending and/or BOB recertification may redesignate batches or portions of batches of gasoline... [EPA-HQ-OAR-2018-0227-0074- Al, p.39] Response: We have revised §1090.1010(b) (2) to allow certified butane/pentane blenders and parties that recertify BOBs under §1090.740 the ability to redesignate products as necessary in order to be in compliance with the part 1090 designation requirements. Comment: > bp America Inc. (bp) Subpart K—Product Transfer Documents §1090.1115(b) (3)(iv)-Designation requirements for diesel and distillate fuels According to section §1090.1115(b), distributors may redesignate batches or portions of batches of diesel or distillate fuel for which they transfer custody without recertifying the fuel. §1090.1115(b) (3) (iv) describes which fuels a distributor can redesignate to ULSD if they meet the applicable specifications for that fuel. Those fuels include heating oil, kerosene, and jet fuel. However, they do not include EC A marine fuel. Due to logistical constraints (e.g., limited tankage) at fuel manufacturing facilities, it is possible for fuel manufacturers to dual certify a distillate fuel to meet both the diesel specifications under §1090.305 and the ECA marine fuel standards under §1090.325 as allowed in §1090.1115(a)(4). This would allow fuel manufacturers with limited tankage to be able to supply both products from the same tank. Similarly, there are logistical constraints preventing segregation of ECA marine fuel and diesel fuel in the downstream distribution system. The Renewable Fuels Standard (RFS) includes ECA marine fuel in the definition of a certified non-transportation 15 ppm distillate fuel (NTDF) and permits ECA marine fuel to be redesignated as MVNRLM which would include ULSD. 40 CFR §§80.1401 and 80.1408. Therefore, to be consistent with the RFS rules relevant to NTDF, bp recommends that §1090.1115(b) (3) (iv) be modified to include ECA marine fuel as a fuel distributors can redesignate to ULSD. 196 ------- §1090.1115(b) (3)(iv) indicates that the redesignated fuel needs to meet the ULSD requirements of §1090.315. bp believes that the reference to §1090.315 was intended to be to §1090.305 which has the EPA specifications for ULSD. Further, bp recommends adding ECA marine fuel to §1090.315 as a fuel that may not be sold for use in motor vehicles or non-road equipment and is not subject to the ULSD standards in §1090.305 unless also designated as ULSD under §1090.1115(a). [EPA-HQ-OAR-2018-0227-0046-A1, p.18] > Independent Fuel Terminal Operators Association (IFTOA) III. Re-Designation of Distillates EPA's proposal in § 1090.1115 (a) would allow fuel manufacturers to certify and designate certain diesel or distillates, meeting applicable standards, as ULSD, which may also be designated for other suitable uses, including as heating oil, jet fuel, kerosene, ECA marine fuel, or distillate global marine fuel. Such multiple designations will provide greater flexibility to the distillate market. Further, additional flexibility will also be provided by the proposed § 1090.1115 (b)(i) and (ii), which permit downstream parties to re-designate without recertifying ULSD to heating oil, jet fuel, kerosene, ECA marine fuel, or distillate global marine fuel if all applicable standards are met. This latter provision will enhance marketers' ability to readily meet market demand without a complex re-certification process and without complying with a complex and time-consuming notification system involving upstream parties from which the fuel was obtained. It will improve the efficiency of the distillate distribution system and should reduce costs for ultimate consumers. [EPA-HQ-OAR-2018-0227-0064-A1, pp.2-3] However, proposed § 1090.1115 (b) (3) (iv) is unclear. It provides that heating oil, kerosene, or jet fuel may be re-designated by distributors as ULSD if the requirements of § 1090.315 are met. Section 1090.315 provides that heating oil, kerosene, and jet fuel may not be sold for use in motor vehicles or non-road equipment and are not subject to the ULSD standards in § 1090.305 unless the product is also designated as ULSD under § 1090.1115 (a). Section 1090.1115 (a) is the applicable section for designation by the fuel manufacturer. Therefore, it is unclear whether § 1090.1115 (b) (3) (iv) means that a distributor cannot re-designate heating oil, kerosene, or jet fuel as ULSD unless the fuel manufacturer has also already designated the fuel as ULSD. If that is a correct reading of the provision, it lessens the flexibility EPA is providing to distributors and inhibits their ability to meet market demand. A distributor should be able to re-designate heating oil, kerosene, or jet fuel as ULSD if the distributor can demonstrate that the fuel meets the applicable per-gallon standards of 1090.305. [EPA-HQ-OAR-2018-0227-0064-Al,p.3] Response: We have revised the reference of the ULSD standards in §1090.1015 from §1090.315 to §1090.305. We have also revised §1090.315 to include ECA marine fuel to more clearly allow for ECA marine fuel that has been certified as meeting ULSD standards to be redesignated without recertification as ULSD if all applicable requirements are met. 197 ------- Comment: > Camin Cargo Control Subpart K - Batch designation 5. RVP Turnover a. 1090.1110 (b) (5) States that 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. b. Preamble VIII. Registration, Reporting, Product Transfer Document, and Recordkeeping, G. Certification and Designation of Batches state that "When transitioning from winter to summer gasoline, parties are not required to test the RVP but must exercise good engineering judgement to assure that the gasoline meets the applicable RVP standard." c. Based on many years of experience, we strongly believe that 'exercising good engineering judgement' is not enough to guarantee the proper RVP level on the target fuel (Summer). Testing is the only way to ensure the product meets the applicable RVP standards. [EPA-HQ- OAR-2018-0227-0030-A1, p.6] > Motiva Enterprises, LLC Transition from winter to summer gasoline On page 119 of the preamble under section VIII. G. EPA states "When transitioning from winter to summer gasoline, parties are not required to test the RVP but must exercise good engineering judgement to assure that the gasoline meets the applicable RVP standard". Motiva asks for clarification on what would classify as "good engineering judgement" in making that transition. [EPA-HQ-OAR-2018-0227-0073-A1, p.4] Response: Any person that mixes summer gasoline with summer or winter gasoline that has a different RVP designation must ensure that the blended gasoline meets the applicable RVP standards. Part 1090 requires parties who mix summer gasoline with summer or winter gasoline that has a different RVP designation to sample and test the mixture to ensure that the RVP of the new batch meets the applicable standards, except when transitioning from winter to summer gasoline. Although the regulations do not require parties transitioning from winter to summer gasoline to conduct sampling and testing to determine if they meet the applicable RVP standards, all parties involved in transitioning from winter to summer gasoline should take appropriate actions and precautions to ensure that the gasoline they produce, sell or distribute meets applicable RVP standards by May 1 (or June 1 for retail outlets). Part 1090 does not identify the specific actions required to 198 ------- ensure compliance with the RVP standards during the transition from winter to summer gasoline since this is best determined by regulated parties on a case-by-case basis. Comment: > CITGO Petroleum Corporation (CITGO) 3 Inconsistency Between Subparts and/or Preamble 3.1 Designation of Diesel Fuel Additionally, an inconsistency exists between distillate designations of this NPRM and those associated with 40 CFR part 80, subpart M. In the recently released RFS regulations revision, EPA created an additional diesel/distillate designation that is not referenced in subpart K of this NPRM. Specifically, EPA established a new category of distillate fuel (certified NTDF) for fuel certified as complying with diesel standards and designated on a product transfer document with a notation that the fuel is "15 ppm sulfur (maximum) certified NTDF - This fuel is designated for non-transportation use." This designation should be added to subpart K of part 1090 for consistency and alignment between regulations. [EPA-HQ-OAR-2018-0227-0054-A1, p.12] Response: We have added language to the distillate fuel designation requirements at §1090.1015 to clarify that diesel fuel manufacturers may apply a certified NTDF designation and that distributors of certified NTDF may redesignate such fuel as ULSD if the requirements under §80.1408 are met. This is consistent with existing regulatory requirements for certified NTDF under part 80. Comment: > Energy Transfer L.P. (ET) 2) Subpart K—Batch Certification, Designation, and Product Transfer Documents The new requirement in §1090.1100 "testing must occur after the most recent delivery into certified butane producer's storage tank, and prior to transferring the certified butane batch for delivery", adds an artificial time constraint on butane producers, without a corresponding benefit. Currently, in §80.82, butane may be sampled and tested "immediately before transfer of butane to the butane blender". Consequently, the proposed language in §1090.1100 would effectively render §80.82 meaningless. By removing the option provided by §80.82, it could also artificially impact production, supply and distribution of certified butane to certified butane blenders due to loss in the interim period between delivery to a storage tank and transfer to the blender. We respectfully propose re-wording the language in §1090.1100(e) (2) (i) (A) to the following: "Testing must occur after the most recent delivery into certified producer's storage tank, or the sampling and testing must occur immediately before transfer of butane to the butane blender". 199 ------- By making this change, testing and sampling would occur closer in time to the ultimate distribution of the product, which is the focal point of the regulations and will provide a more accurate representation of the product quality at the point of emphasis. [EPA-HQ-OAR-2018- 0227-0044-Al.pp.l-2] > TexonL.P. I. Batch Certification and Designation. §1090.1100 (e)(A) and §1090.1610 (a)(2) §1090.1100 (e)(A), "Certified butane producers must certify butane by: (e)(1)(A) Testing must occur after the most recent delivery into certified producer's storage tank, and prior to transferring the certified butane batch for delivery." Please consider batch certification language as similarly stated in the 2014 Tier 3 Final Rule, §80.82 (i) 2 (i), "Sampling and testing for the sulfur content of the butane by the supplier must be subsequent to each receipt of butane into the supplier's storage tank OR the sampling and testing must be immediately before transfer of butane to blender." This practice upholds the per-gallon lOppm sulfur standards yet offers flexibility for the supplier to choose the point of testing. [EPA- HQ-OAR-2018-0227-0081-A1, p.l] April 13, 2020, Memorandum titled, "Technical Issues Related to Fuels Regulatory Streamlining Measurement Procedures", which states, "Test each batch before or after shipping" (Table 1, p.8). 80.82 Referencing testing language consistent with the OTAQ technical guidance would help producers maintain a certification and quality assurance program prior to product being transferred to a blender. [EPA-HQ-OAR-2018-0227-0081-A1, p.l] As the NPRM requires testing butane after last receipt 'and' prior to transferring the certified butane batch for delivery, it could be interpreted the EPA is requiring the producer to "still" tanks before testing which would cause subsequent operational delays while waiting for results before loading product for transport. This may be difficult and impractical for plant operations as the rate of fractionation output and commercial demand varies. Producers run composite samples through in-line analyzers for butane quality control to ensure each gallon meets the commercial specifications for purity, benzene, and sulfur. Post-production, butane is stored in a range of vessels: storage tanks or caverns of varying volume capacities. Broader language would allow facilities to test at suitable production/storage points, certifying the product, and assuring butane meets specifications before transferring to the blender. [EPA-HQ-OAR-2018-0227-0081-A1, P-1] Response: We have removed the language requiring testing before transferring the certified butane batch for delivery as we believe it is only important that the certified butane batch be tested after the most recent delivery. 200 ------- Comment: > Eversheds Sutherland (US) LLP Definitions However, the Proposed Rule adds new language stating in the PTD subsection that a person must comply with all provisions of Part 1090 even if they fail to properly designate a fuel, and no person may use the designation provision to circumvent any standard or requirement.5 This language is concerning because there may be very legitimate and commercial reasons not to designate a fuel— indeed, that is accounted for in EPA's (new) definitions of gasoline and diesel where the fuel meets the definition if it conforms to the relevant ASTM and is made available for use in a vehicle or engine designed to operate on the fuel. EPA should not adopt this language, or at the very least should add a clarifying statement that the definition must still be met such that the undesignated or improperly designated fuel is made available for the use in question. In addition to the example above, a product may look like Global Marine Fuel but not be "used, intended for use, or made available for use" in a vessel outside of an ECA.6 [EPA-HQ-OAR- 2018-0227-0076-A1, p.3] 5 Id. at § 1090.1105(d)-(e). 6 Id. at § 1090.80. Response: We believe that the language requiring that fuels be appropriately designated and that parties cannot abuse the designation provisions as a means to avoid regulatory requirements is necessary. Parties may not avoid regulatory requirements by refusing to designate their fuels, fuel additives, or regulated blendstocks as required under the regulations. Comment: > Eversheds Sutherland (US) LLP Designation and Product Transfer Documents The Proposed Rule states that designation must be included on PTDs and the designation must be made "prior to the batch leaving the facility where it was produced."36 EPA's intent here is unclear, but title PTDs are not sent in advance but are usually sent with the invoice and confirmed quantity reports. EPA should not change any of the timing requirements for PTDs as the current system not only works, but is a carefully orchestrated exchange of information (some information is mandated by EPA, some by other agencies, and some is merely operational or commercial) between a myriad of different actors, and making changes would throw off the system unnecessarily with no attendant compliance benefits. Note that on initial PTDs, 201 ------- nominated (or estimated) quantity is referenced because it is impossible to send exact quantities before the fuel has moved and been measured. Under designation requirements for gasoline and diesel, the Proposed Rule states that distributors may redesignate batches for which they transfer custody to another facility under certain circumstances.37 However, a distributor is most likely not the title owner of the fuel, and as such the distributor cannot choose to redesignate fuel owned by a third party. The title owner should be able the redesignate, however, and indeed should be able to redesignate without regard to movement to another facility. We ask EPA to correct this language accordingly. [EPA-HQ- OAR-2018-0227-0076-A1, p.12] 36 Id. at § 1090.1105(b). 37Id. at § 1090.1110(b)(2) and § 1090.1115(b)(3). Response: We did not intend to require a change in timing of PTD requirements. We do, however, believe that fuel manufacturers, fuel additive manufacturers, and regulated blendstock producers must designate fuels, fuel additives, and regulated blendstocks prior to the fuel, fuel additive, or regulated blendstock leaving the facility. Parties must reflect appropriate designations as assigned under Subpart K on PTDs under Subpart L, which can occur as allowed under Subpart K and consistent with customary business practices. Comment: > Motiva Enterprises, LLC Redesignation of fuels On page 119 of the preamble under section VIII. G. EPA states "Any person that mixes summer gasoline with summer or winter gasoline that has a different RVP designation must either designate the resulting mixture as meeting the least stringent RVP designation of any batch in the blend or determine the RVP of the mixture and designate the new batch accurately to reflect the RVP of the gasoline as described under this section." In §1090.1110 (b) (2) EPA proposes that distributors may redesignate batches or portions of batches of gasoline for which they transfer custody to another facility. Motiva proposes that in the examples that follow, currently (i)-(v), an example is added stating: "Summer CG or CBOB or any Winter gasoline may be redesignated to Summer RFG or RBOB provided the RVP of the mixture is determined and the new batch accurately reflects the RVP of the gasoline as described under this section. For example, a distributor could redesignate without recertification a portion of a batch of Summer CG to Summer RFG provided the RVP is determined prior to redesignation." 202 ------- In addition, in order to allow for a distributor to redesignate a batch or portion of a batch of gasoline without transferring custody, Motiva proposes that EPA modifies §1090.1110 (b) (2) to state: "Distributors may redesignate batches or portions of batches of gasoline for which they maintain custody or transfer custody to another facility without recertifying the batch or portion of the batch as follows:" [EPA-HQ-OAR-2018-0227-0073-A1, p.3] Response: We have clarified that a party may redesignate winter gasoline as summer RFG or RBOB if the party samples and tests the batch to demonstrate that the new batch meets the new designation. We have also clarified that the party does not need to transfer title or custody of the batch to redesignate the batch of gasoline. Comment: > Weaver and Tidwell, L.L.P. This section seems to be a little unclear and not all-encompassing. There are certain cases when it is not appropriate to simply certify shipment or transfer volumes, but rather the entire tank volume - e.g., spot blending in what is otherwise a throughput tank. Once a spot blend is complete, the way to get the tank back into throughput mode is to certify the entire tank volume. In this scenario, if only the shipment or transfer volumes are captured for batch reporting purposes, one has effectively ignored the heel and understated their compliance volumes. We think it is important to be broader in this provision - taking into consideration various operations and batching scenarios. [EPA-HQ-OAR-2018-0227-0079-Al,p.l] This is probably the appropriate provision to address temperature correction, which is not otherwise addressed in the NPRM. Something along the lines of "batch volumes shall be corrected to 60F for recordkeeping and reporting purposes of this part." [EPA-HQ-OAR-2018- 0227-0079-A1, p.l] §1090.1100 Batch certification requirements. (a) General provisions. (3) For purposes of this part, the volume of a batch is the sum of all shipments or transfers of fuel, fuel additive, or regulated blendstock out of the tank or vessel in which the fuel, fuel additive, or regulated blendstock was certified. If a volume of fuel, fuel additive, or regulated blendstock is placed in a tank, certified (if not previously certified), and is not changed in some way, it is considered to be the same batch even if several shipments or transfers are made out of that tank. 203 ------- Response: We have revised the general provisions for determining batch volumes to allow for cases where an entire volume of a tank needs to be certified, as the commenter suggested. We have added a requirement that batch volumes be temperature corrected to 15.56 °C (60 °F). 204 ------- 13.3. PTDs Comment: > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. 2. EPA's new proposed requirement to list all oxygenates on the product transfer document (PTD). including biobutanol. is essential and must be in the final rule. In addition, we'd recommend EPA explicitly allow and recommend PTD statements for oxygenates may state "contains up to % ethanol and/or % isobutanol (or other approved oxygenate) at maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a load(s). This proposed improvement would be entirely in keeping with EPA's statements already contained within the proposed rule-making regarding naming specific oxygenates. This action would allow a refiner to test and certify a batch to a distributor and subsequent sale to gasoline retailer without additional burdensome and unnecessary testing and certification. The oxygenate percentage(s) as well as other components would still meet all EPA specifications. [EPA-HQ- OAR-2018-0227-0063-A2, p.2] > Association of Marina Industries (AMI) 2. EPA's new proposed requirement to list all oxygenates on the product transfer document (PTD), not only ethanol, but including biobutanol, is essential and must be in the final rule. In addition, we'd recommend EPA explicitly allow and recommend PTD statements for oxygenates may state "contains up to % ethanol and/or % isobutanol (or other approved oxygenate) at maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a load(s). This proposed improvement would be entirely in keeping with EPA's statements already contained within the proposed rule-making regarding naming the specific oxygenates. This action would allow a refiner to test and certify a batch to a distributor and subsequent sale to gasoline retailer without additional burdensome and unnecessary testing and certification. Of course, the oxygenate percentage (s) as well as other components would still meet all EPA specifications. [EPA-HQ-OAR-2018-0227-0057-A1, p.2] > Gevo, Inc. 2. EPA's new proposed requirement to list all oxygenates on the product transfer document (PTD). not only ethanol. but including biobutanol. is essential and must be in the final rule. In addition, we'd recommend EPA explicitly allow and recommend PTD statements for oxygenates may state "contains up to % ethanol and/or % isobutanol (or other approved oxygenate) at maximum lOppm sulfur," or equivalent wording. Without this improvement it will be very difficult and cost prohibitive, for example, for wholesale gasoline distributors to recertify a load(s). This proposed improvement would be entirely in keeping with EPA's statements already contained within the proposed rule-making regarding naming the specific oxygenates. This action would allow a refiner to test and certify a batch to a distributor and subsequent sale to 205 ------- gasoline retailer without additional burdensome and unnecessary testing and certification. Of course, the oxygenate percentage (s) as well as other components would still meet all EPA specifications. [EPA-HQ-OAR-2018-0227-0063-A1, pp.3-4] Response: We do not believe that it would be appropriate to require that PTDs for BOBs include both a statement for ethanol and isobutanol concentrations. We do not require the use of any oxygenate and have allowed fuel manufacturers to certify batches of gasoline/BOB with oxygenates consistent with their production capabilities, business decisions, and market demands. As discussed in Section VII.G of the preamble, we are providing flexibility for parties to recertify BOBs without sampling and testing to substitute isobutanol instead of ethanol. We believe that the BOB recertification procedure is sufficient to allow parties that wish to substitute isobutanol for ethanol for a BOB without adding additional PTD requirements and responsibilities for parties upstream. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1160(c) (2) (i) (D) For E15, the following statement: "E15: Contains up to 15 vol % ethanol. Comment: This should be revised to match the specificity of 9-10 for E10. It should instead be "El5: Contains between 10 and 15 vol % ethanol" rather than "...up to 15 vol%..." The change would align with the requirements within §1090.1160 c (2) (iii). [EPA-HQ-OAR-2018-0227-0074-A1, P-32] Response: We have revised §1090.1110(c) (2) (i) (D) as the commenter suggested. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 206 ------- 1090.1165(c) ECA marine fuel language requirements. For batches of ECA marine fuel, in addition to the information required under paragraph (a) of this section, the following information must be included on the PTD: (1) The following statement: "1,000 ppm sulfur (maximum) ECA marine fuel. For use in Category 3 marine vessels only. Not for use in Category 1 or Category 2 marine vessels." (2) Parties may replace the required statement in paragraph (c) (1) of this section with the following statement for qualifying vessels under 40 CFR part 1043: "High sulfur fuel. For use only in ships as allowed by MARPOL Annex VI, Regulation 3 or Regulation 4." (3) Under 40 CFR 1043.80, fuel suppliers (i.e., ECA marine fuel distributors, retailers, and WPCs) must provide bunker delivery notes to vessel operators in addition to any applicable PTD requirements under this subpart. Comment: There are additional PTD language requirements in 80.1453. There needs to be a reference to this section for ECA marine fuel oil and heating oil for completeness. We recommend the following language: For ECA marine fuel: (c)(4) Refer to §80.1453 for additional PTD requirements. For Heating oil: (e) Heating oil (1) Refer to §80.1453 for PTD requirements. [EPA-HQ-OAR-2018-0227-0074- Al, p.40] 18 See § § § § 1090.1150, 1090.1160, 1090.1170, 1090.1175. 20 Refinery certificates of analysis ("COA"), truck rack BOLs, invoices, contracts, etc. > Shell Oil Products US H. Section §1090.1165 - Additional Language Needed for ECA Marine Fuel and Heating Oil for Completeness §1090.1165 (c) PTD requirements for distillate and residual fuels. (c) ECA marine fuel language requirements. For batches of ECA marine fuel, in addition to the information required under paragraph (a) of this section, the following information must be included on the PTD: 207 ------- (1) The following statement: "1,000 ppm sulfur (maximum) ECA marine fuel. For use in Category 3 marine vessels only. Not for use in Category 1 or Category 2 marine vessels." (2) Parties may replace the required statement in paragraph (c) (1) of this section with the following statement for qualifying vessels under 40 CFR part 1043: "High sulfur fuel. For use only in ships as allowed by MARPOL Annex VI, Regulation 3 or Regulation 4." (3) Under 40 CFR 1043.80, fuel suppliers (i.e., ECA marine fuel distributors, retailers, and WPCs) must provide bunker delivery notes to vessel operators in addition to any applicable PTD requirements under this subpart. There is additional PTD language requirements in 80.1453. There needs to be a reference to this section for ECA marine fuel oil and heating oil for completeness. We recommend the following language: For ECA marine fuel: (c) (4) Refer to §80.1453 for additional PTD requirements. For Heating oil: (e) Heating oil (1) Refer to §80.1453 for PTD requirements. [EPA-HQ-OAR-2018-0227-0035-A1, p.7] Response: We note that not all ECA marine fuel or heating oil is subject to the RFS PTD requirements. We believe the commenters are referring to cases where either the certified NTDF language refers to ECA marine fuel or heating oil that has been certified as meeting USLD standards, but is designated as NTDF for RVO accounting purposes. We also note that renewable heating oil has additional PTD requirements under the RFS program in part 80. Even broader, many oxygenates subject to sulfur requirements under Subpart C are renewable fuels under part 80 and are also subject to RFS PTD requirements. Therefore, to highlight that additional RFS PTD requirements may apply, we have added a cross-reference to the RFS PTD requirements in §1090.1100. Comment: > bp America Inc. (bp) §1090.1160 Gasoline, gasoline additive, and gasoline regulated blendstock PTD provisions §1090.1160 (b) and (c) make specific PTD requirements for gasolines (CBOB and RBOB) meeting 9.0, 7.8, and 7.4 psi specifications. §1090.1160 (c) (1) (ii) then states "For finished gasoline that meets an RVP per-gallon standard required by any SIP approved or promulgated under 42 U.S.C. § 7410 or 7502, additional or substitute language to satisfy the state program 208 ------- may be used as necessary." However, it is not uncommon for some SIPs to mandate a 7.0 psi summer RVP. To avoid confusion and provide consistency for parties that handle such a fuel, we suggest the EPA add PTD language for 7.0 psi summer gasoline. [EPA-HQ-OAR-2018-0227- 0046-A1, pp.18-19] Response: We proposed and are finalizing language that allows for parties that make and distribute fuels in states subject to state fuel programs under a SIP to use the suggested substitute language at §1090.1110(b) (2)(iv) and (c) (1) (ii). We believe the added flexibility is sufficient for parties that make and distribute such fuels to identify products on PTDs across all state fuel programs, not just 7.0 psi RVP programs as suggested by the commenter. It would be onerous to try to capture all state fuel programs under our federal regulations. Comment: > CITGO Petroleum Corporation (CITGO) 3.3 Product Transfer Documents ("PTD") CITGO supports EPA's efforts to consolidate 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. However, a few disconnects exist relative to transfers of custody versus title of products impacting the requirement to provide product transfer documents. Consistent with the preamble and as listed in §1090.1150, on each occasion when any person transfers custody or title to any product covered under this part other than when fuel is sold or dispensed for use in motor vehicles at a retail outlet or wholesale purchase consumer (WPC) facility, the transferor must provide to the transferee PTDs containing specified information. This is consistent with specific language in: • §1090.1155(a) for exempted fuels • §1090.1160(d) for transfers of oxygenates • §1090.1160(e) for gasoline detergents • §1090.1160(f) for gasoline additives • §1090.1160(g) for certified ethanol • §1090.1160(h) for butane and pentane • §1090.1170 for diesel fuel additives However, for gasoline, gasoline additive or gasoline regulated blendstock in §1090.1160(a) and for distillate or residual fuel in §1090.1165(a), PTDs are only required when a person transfers custody without any mention of transfers of title. 209 ------- It is recommended that EPA modify §1090.1160(a) and §1090.1165(a) to either: 1) include transfers of title as well or 2) clarify in §1090.1150 that requirements are product dependent and modify §1090.1160(a) to apply to gasoline only. Response: We have revised §§1090.1110(a) and 1090.1115(a) to indicate that PTD requirements apply to transfers of title as well as transfers of custody. Comment: > CITGO Petroleum Corporation (CITGO) 3.3 Product Transfer Documents ("PTD") Additionally, clarity is needed relative to PTDs associated with marine imports. Although §1090.1150 requires a PTD on each occasion when a person transfers custody or title, the intent of such is to relay relevant information regarding the product between parties and does not exclude marine vessel imports. PTDs associated with marine importation of products is addressed in §1090.1605(c) and is applicable only in the specified lightering scenario. The regulatory text in §1090.1150 and §1090.1815 should be clarified to exclude imports. Recommended language is as follows: §1090.1150 General PTD provisions (a) General. (1) On each occasion when any person transfers custody or title to any product covered under this part other than when fuel is sold or dispensed for use in motor vehicles at a retail outlet or wholesale purchase consumer (WPC) facility or for marine vessel imports, the transferor must provide to the transferee PTDs that include all the following information: §1090.1815 General procedures - gasoline importers (e) (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 non-marine vessel imports for each selected BOB import. (g) (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 non-marine vessel imports for each selected finished gasoline import. If EPA feels that the PTD requirements do apply to marine vessel imports, additional clarity is requested on the party that is expected to generate the PTD since the requirements do not currently apply to the foreign refiner or to product that has not yet been certified and designated. Based on §1090.1605, that does not occur until after the importer has sampled, tested and gone 210 ------- through the entry process. At that point the product is already in the custody of the importer. [EPA-HQ-OAR-2018-0227-0054-A1, pp. 12-13] Response: We do not believe that fuel transfers from marine vessels for imported fuels should be exempt from PTD requirements under part 1090. While the regulations at §1090.1605 provide some clarity on how PTD requirements are met in lightering situations, this does not supplant the requirement that importers adhere to PTD requirements in other scenarios. In general, PTD requirements apply to fuels after those fuels have been certified under Subpart K. This means that PTD requirements do not apply to foreign refiners, as it is the importer of the fuel that is responsible for certifying batches as meeting EPA fuel quality standards and generating PTD information. This is unchanged from the current PTD requirements from part 80. Therefore, we are finalizing PTD requirements for imports from marine vessels as proposed. Comment: > CITGO Petroleum Corporation (CITGO) 3.5 Butane Producer Registration and Batch Numbers Consistent with the preamble language, registration requirements do not exist for certified butane producers in the regulatory text of §1090.125 and §1090.800(a). However, in §1090.1160(h) (i), transferors of certified butane or certified pentane must provide a PTD containing the facility registration number issued by EPA. A producer will not have a registration number to place on the PTD without the requirement to register. Similarly, in § 1090.905(c) (5) (i), certified butane blenders are required to include the batch number for the certified butane in batch reporting however, regulatory text in the following sections does not support a requirement for certified butane producers to assign or provide a batch number: • §1090.1100(e) batch certification for certified butane • §1090.1120(a) batch numbering These inconsistencies can easily be addressed by removing the requirement to place the registration number on the PTD in §1090.1160(h) (i) and by removing the requirement for certified butane blenders to report the certified butane batch number in reporting. This will however result in different regulations for butane producers and pentane producers. [EPA-HQ-OAR-2018-0227-0054-A1, p. 14] > TexonL.P. II. Gasoline, gasoline additive, and regulated blendstock PTD Provisions. §1090.1160(h) (i) 211 ------- §1090.1160(h) (i), the certified butane producer initiates a PTD for each batch that it ships from its facility that contains the following information: (i) The certified butane or certified pentane producer company name and facility registration issued by EPA. Subpart I - Registration, §1090.800, does not list requirements for certified butane producers to register. Please revise the PTD batch identification provisions for butane to not include a facility registration id number as issued by the EPA to be consistent with registration requirements as outlined in Subpart I. [EPA-HQ-OAR-2018-0227-0081-A1, p.2] > Turner, Mason & Company (TM&C) Subpart K - Batch Certification. Designation, and Product Transfer Documents Certified Butane Producer In 1090.1160(i), the product transfer document (PTD) requirements for a certified butane producer reference the facility registration number to be included. As stated in the preamble and observed in Subpart I, certified butane producers do not need to register with the EPA. We suggest the following language for 1090.1160(i) to provide clarification. (i) The certified butane or certified pentane producer company name and for the certified pentane producer the facility registration number issued by EPA. [EPA-HQ-OAR-2018-0227-0045-A1, p.3] Response: We did not intend to require that certified butane producers provide EPA-issued company identification numbers on PTDs since they do not have to register. Therefore, we have made the edits the commenter suggested. Comment: > Eversheds Sutherland (US) LLP Marine Fuel With regard to PTDs, the Proposed Rule requires a PTD for ECA and distillate global marine fuel deliveries into the vessel as well as other custody and title transfers.24 This requirement should exclude deliveries into vessels, as the PTD is redundant due to the requirement to provide a bunker delivery note that already exists under 40 C.F.R. § 1043.80. Such a change is wholly consistent with the purpose of this streamlining effort. [EPA-HQ-OAR-2018-0227-0076-A1 p.8] 24 Id. at § 1090.1150. 212 ------- Response: PTD requirements under part 1090 do not apply to deliveries into vessels. As intended, PTD requirements apply for transfers between parties except when fuels are transferred to the ultimate end user from a retail outlet or WPC facility. We believe that deliveries of ECA and distillate global marine fuel into vessels falls within the category of fuels transferred to the ultimate end user and therefore do not require PTD documents to accompany the fuel under part 1090. As the commenter notes, however, the bunker delivery note requirements under §1043.80 would still apply to such transfers. We have made clarifying edits to the PTD requirements at §§1090.1100, 1090.1105, and 1090.1110 that clarify that PTD requirements do not apply to transfers to ultimate end users from retail outlets and WPC facilities for ECA marine fuel and distillate global marine fuel. Comment: > Eversheds Sutherland (US) LLP Marine Fuel There are several concerns with the "General PTD provisions."38 First, EPA should confirm that PTDs may be compiled from multiple documents including bills of lading, invoices, and other commercial or operational documents that in aggregate convey the required information. [EPA- HQ-OAR-2018-0227-0076-A1, p.12] 38 Id. at § 1090.1150. Response: We do not currently specify which specific document must contain that PTD language under part 80, nor have we done so under part 1090. As a result, it would be acceptable to provide all PTD information, including the transferee's name, on a truck bill-of-lading, with the transferee's address included on a follow-up invoice. Comment: > Eversheds Sutherland (US) LLP Marine Fuel Second, fuel is measured in barrels or metric tons, and only converted to gallons for EPA reports; therefore, EPA must delete the requirement that PTDs list the volume "in gallons". The automated systems used by all the actors involved in fuel storage and transport use measurements other than gallons. EPA should not require conversion to gallons just for PTDs as that would be confusing and could lead to non-compliance (e.g., use of the wrong measurement 213 ------- when calculating the RVO or other credits). The reference to a specific measurement should just be dropped. [EPA-HQ-OAR-2018-0227-0076-A1, p.12] Response: We have revised the regulations to not require that volume be listed "in gallons" on PTDs, consistent with current practice in part 80. Comment: > Eversheds Sutherland (US) LLP Marine Fuel EPA should also add exception from a PTD requirement for sales to end-users, which would be consistent with current requirements in Part 80 (e.g., "except when such fuel is dispensed into motor vehicles or nonroad equipment, locomotives, marine diesel engines or steamships or Category 3 vessels"). In the Proposed Rule, language requires PTDs "on each occasion when any person transfers custody and title" which would unnecessarily capture retail, end-users, and wholesale purchaser-consumers. [EPA-HQ-OAR-2018-0227-0076-A1, p.12] Response: We have revised the regulations to clarify that PTD requirements do not apply when fuels are dispensed into motor vehicles from a retail outlet or at a WPC facility. Comment: > Petroleum Marketers Association of America (PMAA) Downstream Oxygenate Blending - BOB However, PMAA is opposed to any provision that would permit downstream oxygenate blenders to identify El 5 on PTDs, invoices or dispenser labels in any way that obscured the 15% ethanol content of the blend; including terms such as "Unleaded 88" or "Regular 88". PMAA believes use of these terms significantly increases the risk of misfuelling. [EPA-HQ-OAR-2018-0227- 0083-A1, p.3] Response: We do not require that parties identify El5 on PTDs, invoices, or dispenser labels as "Unleaded 88" or "Regular 88". Comments related to El5 labeling and misfueling are outside the scope of this action. 214 ------- Comment: > Petroleum Marketers Association of America (PMAA) PTDs - PMAA supports the EPA proposal to reorganize and consolidate PTD language into a new section, more fully identify exempt fuels, remove outdated language and allow petitions for alternate language. Reorganizing PTD language requirements under a single section is a much needed and greatly appreciated change. Currently, PTD language requirements are scattered throughout the regulations, making them difficult to find and track for possible changes. Probably the most frequent question PMAA receives from members relates to compliance with PTD requirements. PMAA believes that reorganizing PTD language into a single section, removing outdated PTD requirements, particularly ULSD notification requirements, would increase compliance among regulated parties. [EPA-HQ-OAR-2018-0227-0083-A1, p.4] PMAA applauds the EPA for providing a mechanism to petition the agency for alternative PTD language. PMAA members, particularly heating oil dealers with ticket printers limited to as little as 78 characters, often find it impossible to fit lengthy PTD language onto existing customer delivery tickets and invoice platforms. During the ULSD phase-in period, PMAA worked closely with the EPA to come up with over a dozen alternative PTD notifications that provided the required notice while at the same time adjusting for PTD and ticket meter space limitations as well as state and local government fuel notice requirements. Formalizing the process for obtaining alternative language will significantly reduce the PTD compliance burden on small business petroleum marketers and increase compliance. PMAA strongly supports this effort. [EPA-HQ-OAR-2018-0227-0083-Al.pp.4-5] Finally, PMAA has no objection to the proposal requiring more specific PTD identifying language for R&D fuels or elimination of sulfur content language from heating oil dispenser labels. [EPA-HQ-OAR-2018-0227-0083-A1, p.5] > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) Product Transfer Documents ("PTDs ") The Associations applaud the Agency's proposed changes to PTD regulations. 11 First and foremost, consolidating the various PTD requirements throughout Part 80 into a single one-stop- shop section, makes it easier for fuel marketers and other stakeholders to access, digest, and comply with the regulations. It is also helpful to remove obsolete PTD language and provide standard, updated language to address a variety of common products and situations—and the Associations thank the Agency for streamlining PTD regulations in this fashion. [EPA-HQ- OAR-2018-0227-0066-A1, p.6] 11 Proposal, supra note 1 at § 1090.1150 et seq. 215 ------- Response: We thank the commenters for their support. Comment: > Valero Energy Corporation E. General Requirements and Provisions for Regulated Parties - PTDs 1. PTDs for Custody Transfer In the proposed §1090.120(4) — Oxygenate Producers PTDs, EPA requires: on each occasion when an oxygenate producer transfers custody or title to any fuel, fuel additive, or regulated blendstock, the transferor must provide to the transferee PTDs under subpart K of this part. However, current §80.1453 only requires title transfer product transfer documents (PTDs). In the Tier 3 Sulfur rules published in April 2016, EPA clarified that it was not EPA's intent to add a PTD requirement for custody transfers of ethanol: [W]hen the introductory text of 40 CFR 80.1453(a) was amended in the February 2015 direct final rule and parallel proposed rule to provide these exemptions for RFS PTD requirements, the words "custody or" were inadvertently added. The addition of the language "custody or" would have further changed this provision such that we would also be adding PTD requirements to the transfer of custody of renewable fuels, which was not our intent. We received several comments pointing out that this would be costly to industry and not beneficial to the RFS program. Commenters noted that applying PTD requirements to transfers of custody went beyond the PTD requirements of all other 40 CFR part 80 fuels programs, and would impose a new obligation on several parties in the fuel supply chain who otherwise do not have specific PTD obligations. In this action, we are finalizing the originally intended changes to 40 CFR 80.1453: In the introductory text of paragraph (a), we are providing downstream end-user exemptions to the PTD requirements in the RFS program similar to other EPA fuels programs, without the "custody or" language that was inadvertently added in the February 2015 direct final rule and parallel proposal.2 Valero urges EPA not to finalize the requirement for PTDs for transfers of custody. Such a requirement would be a new obligation; it is unnecessary and will create additional compliance issues. Response: We believe the commenter is mistaken over how the oxygenate PTD requirements under §80.1610 apply to ethanol, which is different than the RFS PTD requirements at §80.1453, which the commenter references in their comment. Under §80.1610, the PTD requirements for 216 ------- oxygenates under Tier 3 sulfur apply "in addition to any other product transfer document requirements under this part, on each occasion when any person transfers custody or title to any oxygenate upstream of any oxygenate blending facility..This is the same provision that we proposed at §1090.1110(d). As such, we did not propose to change the existing PTD requirements for oxygenates compared to part 80, nor was it was not our intention to do so. Similarly, we also did not propose to change the RFS PTD requirements for ethanol. It is also worth noting that the Tier 3 and QAP Tech Amendment Rule cited by commenters did not propose or finalize any changes to the PTD requirements under §80.1610. As quoted by the comments, the Tier 3 and QAP Tech Amendment Rule proposed to change the PTD requirements under §80.1453, which is outside the scope of this action. For these reasons, we are finalizing the PTD requirements under part 1090 as proposed. 217 ------- 13.4. Commingling of Oxygenates Comment: > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. 3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is permissible. Gevo, NMMA and others have extensively tested tri-fuel blends without issues. Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. It is cost prohibitive for tanks to be drained completely and have separate tankage for ethanol blends and biobutanol blends. It will not happen because the costs, e.g., infrastructure requirements, are too high. [EPA-HQ-OAR-2018-0227-0063-A2, p.2] > Association of Marina Industries (AMI) 3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is permissible. A variety of organizations have extensively tested tri-fuel blends without issues. Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. And as Gevo and others have previously noted it is entirely cost prohibitive for tanks to be drained completely and have separate tankage for ethanol blends and biobutanol blends. It simply will not happen because the costs, e.g., infrastructure requirements, are too high. We see no reason for such a burdensome prohibition and appreciate EPA further addressing this very important issue in the final rule. If this issue is not properly rectified the EPA will be on the one hand promoting an environmentally beneficial and innovative "drop in" fuel up to B16 blends, while on the other effectively preventing further market penetration, defeating its overarching goals and consumer demands for the fuel. [EPA-HQ-OAR-2018-0227-0057-A1, pp.2-3] > BRP US Inc. Marine Group (BRP) Comingling of Oxygenates. 40 C.F.R. § 80.78(a) (8) (i) restricts the comingling of oxygenates such as ethanol and biobutanol. The regulation states as follows: "No person may combine any ethanol-blended VOC-controlled reformulated gasoline with any non-ethanol-blended VOC- controlled reformulated gasoline... ." This provision makes it difficult for biobutanol blended gasoline to be sold as premium fuel at retail twotank systems. In this particular example, 16.1 vol % isobutanol would be sold as a premium fuel, 10 vol % ethanol would be sold as unleaded regular, and the mid-grade fuel would be a combination of two oxygenates, ethanol and biobutanol. BRP and the marine industry has extensively tested tri-fuel blends of 8% biobutanol, 5% ethanol, and 87 vol% gasoline without any performance, compatibility, or exhaust emissions issues. The resulting oxygen content of the comingled fuel blend remains 3.5% by weight (same as E10 or iB 16) but the sulfur, benzene, and RVP is reduced, providing environmental benefits. NMMA requests that EPA allow 10 vol% ethanol and 16.1 vol% isobutanol to be comingled as both are approved oxygenates. This will allow biobutanol to enter the retail marketplace through two-tank systems and be offered as a premium fuel. We see no technical or environmental reason 218 ------- why 16.1 vol % biobutanol, an approved oxygenate, should be restricted when the resulting mid- grade fuel would not exceed approved oxygen content, sulfur, benzene, or RVP limits. Furthermore, in this example, the mid-grade fuel would result in improved environmental performance both through increased biofuel percentage and through reduced benzene, sulfur, and RVP. EPA should ensure that this issue is resolved within the Proposed Fuels Streamlining Rule and should make this revision when the proposal is finalized. [EPA-HQ-OAR-2018-0227-0047- Al, pp.4-5] > Gevo, Inc. 3. EPA should clarify explicitly that commingling of oxygenates at approved levels in tanks is permissible. Gevo, NMMA and others have extensively tested tri-fuel blends without issues. Oxygen content of commingled blends remains, for example, 3.5% by weight (same as E10 or B16), but sulfur, benzene and RVP is reduced, enhancing environmental quality. And as Gevo and others have previously noted it is entirely cost prohibitive for tanks to be drained completely and have separate tankage for ethanol blends and biobutanol blends. It simply will not happen because the costs, e.g., infrastructure requirements, are too high. We see no reason for such a burdensome prohibition and appreciate EPA explicitly resolving this important concern in the final rule. If this issue is not fully rectified the EPA will be on the one hand promoting an environmentally beneficial and innovative "drop in" fuel up to B16 blends, while on the other effectively preventing further market penetration, defeating its overarching goals and consumer demands for the fuel. [EPA-HQ-OAR-2018-0227-0063-Al,p.4] > Gulf Hydrocarbon, Inc., Gulf Hydrocarbon Partners, Ltd. 3. Although not mentioned in the proposed rules we would like to recommend that per 40 CFR 80.78 (a) 8, retailers would be allowed to combine Ethanol blended RFG and Isobutanol-blended RFG in a retail pump to create a Mid Grade gasoline product. [EPA-HQ-OAR-2018-0227-0050, p.2] > National Marine Manufacturers Association (NMMA) Comingling of Oxygenates. 40 C.F.R. § 80.78(a) (8) (i) restricts the comingling of oxygenates such as ethanol and biobutanol. The regulation states as follows: "No person may combine any ethanol-blended VOC-controlled reformulated gasoline with any non-ethanol-blended VOC- controlled reformulated gasoline... ." This provision makes it difficult for biobutanol blended gasoline to be sold as premium fuel at retail two-tank systems. In this particular example, 16.1 vol % isobutanol would be sold as a premium fuel, 10 vol % ethanol would be sold as unleaded regular, and the mid-grade fuel would be a combination of two oxygenates, ethanol and biobutanol. NMMA has extensively tested tri-fuel blends of 8% biobutanol, 5% ethanol, and 87 vol% gasoline without any performance, compatibility, or exhaust emissions issues. The resulting oxygen content of the comingled fuel blend remains 3.5% by weight (same as El0 or iB 16) but the sulfur, benzene, and RVP is reduced, providing environmental benefits. NMMA requests that EPA allow 10 vol% ethanol and 16.1 vol% isobutanol to be comingled as both are approved oxygenates. This will allow biobutanol to enter the retail marketplace through two-tank systems and be offered as a premium fuel. We see no technical or environmental reason why 219 ------- 16.1 vol % biobutanol, an approved oxygenate, should be restricted when the resulting mid-grade fuel would not exceed approved oxygen content, sulfur, benzene, or RVP limits. Furthermore, in this example, the mid-grade fuel would result in improved environmental performance both through increased biofuel percentage and through reduced benzene, sulfur, and RVP. EPA should ensure that this issue is resolved within the Proposed Fuels Streamlining Rule and should make this revision when the proposal is finalized. [EPA-HQ-OAR-2018-0227-0034-A1, pp.4-5] Response: We did not propose and therefore are not finalizing the commingling prohibition at §80.78(a) (8) (i). We believe this addresses commenters' concerns over the prohibition on commingling E10 and Bul6 under part 80. However, it is worth noting that while we are not including this prohibition in part 1090, commingled fuels must continue to meet all applicable fuel quality standards. For example, a blend of isobutanol at 8 volume percent, ethanol at 5 volume percent, and gasoline at 87 volume percent would not qualify for the 1.0 psi RVP waiver for gasoline-ethanol blends containing at least 9 volume percent during the summer months. Such blends will likely exceed the applicable RVP standards. 220 ------- 14. Recordkeeping Requirements (Subpart M) 14.1. General Comments Comment: > Buckeye Partners, L.P. §1090.1210 Recordkeeping requirements for gasoline manufacturers. Comment #4 - Section (e) (2) - The volume of gasoline prior to and after the certified butane blend is difficult to accurately measure, and the volume is not otherwise relevant. Buckeye agrees that the proper and important recordkeeping obligation is the volume of certified butane added, which is appropriately required in (e) (1). Because the volume of blended gasoline prior to and after blending is not regulated, important, relevant, may not be accurate, and causes unnecessary obligations on certified butane blenders, we ask that (e) (2) be deleted in recordkeeping requirements as follows: (2) The volume of gasoline prior to and after the certified butane or certified pontano blending. Response: We have removed paragraph (e) (2) from §1090.1210 as the commenter suggested. Comment: > Eversheds Sutherland (US) LLP Under § 1090.1210(g) (4) (ii), EPA should delete reference to the facility registration numbers; that is not currently required and is not an option in EMTS. EPA should delete the recordkeeping requirement for Global Marine Fuel because this is not fuel used in the United States, and also, there is (correctly) no batching requirement in Part 1090.50 Further, there should only be a bunker delivery note ("BDN") requirement for deliveries to the end-user (i.e., the vessel); requiring a PTD for vessel deliveries is duplicative and burdensome. [EPA-HQ-OAR-2018-0227-0076-A1, p. 16] 50 Id. at § 1090.1215(c). Response: We have removed the facility registration numbers from §1090.1210(g) (4) (ii) as the commenter suggested. 221 ------- We disagree with the suggestion to remove recordkeeping requirements for distillate global marine fuel as records of PTDs need to be kept to demonstrate that the fuel has been designated as exempt from the applicable diesel fuel standards. As noted in Section 13.3 of the RTC document, PTD requirements and related recordkeeping requirements under part 1090 do not apply to transfers to the ultimate end user; however, as noted, the bunker delivery note requirements continue to apply. Comment: > Independent Fuel Terminal Operators Association (IFTOA) VI. VARs Under Part 80, gasoline detergent blenders must maintain periodic volumetric accounting reconciliation ("VAR") reports to ensure that the correct amount of detergent has been added to gasoline before it is entered into commerce. Current regulations also include detailed formatting requirements for the records kept to demonstrate that the proper concentration has been added. The Association supports EPA's proposed change to the formatting requirement, allowing gasoline detergent blenders to keep the records in whatever form is consistent with their regular practice. See § 1090.1240. [EPA-HQ-OAR-2018-0227-0064-A1, p.4] This revision of the VAR format requirement will properly eliminate the current risk of unnecessary violations where records are maintained to demonstrate compliance with detergent lowest acceptable concentration ("LAC") requirements but may deviate from the EPA prescribed format. The amendment will provide needed flexibility to each blender. [EPA-HQ-OAR-2018- 0227-0064-A1, p.4] Response: We thank the commenter for their support. 222 ------- 15. Sampling, Testing, and Retention Requirements (Subpart N) 15.1. General Comments (Scope of Testing) Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.1 Annual. Batch, and Credit Reporting There is a clear distinction in §1090.905 on how gasoline without oxygenate dilution and gasoline with oxygenate dilution should be tested. This same clear distinction should be added to the language in §1090.1310 for consistency. Not all gasoline will be a blendstock for oxygenate blending ("BOB") and take ethanol dilution. The Associations propose the following language for §1090.1310: (c) The following testing provisions apply for gasoline and gasoline regulated blendstock: (1) Gasoline manufacturers producing BOB must prepare a hand blend as specified in §1090.1340 and gasoline that does not include the addition of downstream oxygenate in their compliance calculations must perform the following measurements: (1) For Summer CG and suboctane. measure RVP of the batch. (ii)For Summer RFG. measure RVP of the batch. (iii) For Summer RBOB/suboctane. measure RVP of the handblend. (iv)Measure the sulfur content of the batch. (v)Measure the benzene content of the batch. (2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate in their compliance calculations must prepare a hand blend as specified in §1090.1340 and perform the following measurements: (i) For Summer CBOB, measure RVP in the BOB. (ii) For Summer RBOB, measure RVP in the hand blend. (iii) Measure the sulfur content of both the BOB and the hand blend. (iv) Measure the benzene content of the hand blend. [EPA-HQ-OAR-2018-0227-0074-A1, pp.8- 9] > Exxon Mobil Corporation Subpart M - Testing and Retention ExxonMobil proposes the following streamlined regulatory language: §1090.1310 Testing to demonstrate compliance with standards 223 ------- (c) Gasoline manufacturers, for each of their facilities, must test and report the following information on a per-batch basis for gasoline and gasoline regulated blendstocks: (1) Gasoline manufacturers producing gasoline must perform the following measurements on every batch: (1) Measure the RVP for all Summer gasoline; except Summer RBOBs when tested under (c)(3)© (ii) Measure the benzene content, except BOBs tested under (c) (2) (ii) (iii) Measure the sulfur content (2) A gasoline manufacturer who intends to include downstream oxygenate blending in their compliance calculations, must prepare a hand blend as specified in §1090.1340. (i) Measure the sulfur content of hand blend (ii) Measure the benzene content of hand blend (3) A gasoline manufacturer producing a RBOB designated for summer season and for downstream oxygenate blending requirements, must prepare a hand blend as specified in §1090.1340. (i) Measure the RVP of the hand blend [EPA-HQ-OAR-2018-0227-0049-A1, pp. 1-2] > Phillips 66 Company §1090.1310 - Property testing - hand blends versus neat product We request EPA modify regulatory language to rectify what appears to be an omission. We think the regulation is missing language that would apply in the situation where a refinery is producing sub-grade or BOBs but has chosen not to claim downstream dilution. In this scenario, the fuel manufacturer would have to certify RBOB RVP on a hand-blend but would be required to certify and report sulfur and benzene on a neat basis. In order to properly include this scenario in the regulatory language, we recommend modifying §1090.1310(c) as follows: (c) The following testing provisions apply for gasoline and gasoline regulated blendstock: (1) Gasoline for which the manufacturer does not include the addition of downstream oxygenate in its compliance calculations must perform the following measurements: (i) For Summer CG and suboctane. measure RVP of the batch. (ii)For Summer RFG. measure RVP of the batch. 224 ------- (iii) For Summer RBOB/suboctane. measure RVP of the handblend. prepared as specified in §1090.1340. (iv)Measure the sulfur content of the batch. (v)Measure the benzene content of the batch. (2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate in their compliance calculations must prepare a hand blend as specified in §1090.1340 and perform the following measurements: (i) For Summer CBOB, measure RVP in the BOB. (ii)For Summer RBOB, measure RVP in the hand blend. (iii)Measure the sulfur content of both the BOB and the hand blend. (iv)Measure the benzene content of the hand blend. These changes to the regulatory language would ensure that all manufacturing and certification options are covered. [EPA-HQ-OAR-2018-0227-0060-A1, pp.3-4] > Shell Oil Products US K. Sections §1090.905 (c)(1) (viii). §1090.905 (c) (2) (viii). and §1090.1310 (c)(1) - Need Consistency and Clear Distinction between CG and BOB in these Sections There is a clear distinction in §1090.905 on how gasoline without oxygenate dilution and gasoline with oxygenate dilution should be tested. This same clear distinction needs to be added to the language in §1090.1310 for consistency - not all gasoline will be a BOB and take ethanol dilution. We propose the following language for §1090.1310 (c): (c) The following testing provisions apply for gasoline and gasoline regulated blendstock: (1) Gasoline manufacturers producing gasoline that does not include the addition of downstream oxygenate in their compliance calculations must perform the following measurements: (i) For Summer CG and sub-octane, measure RVP of the batch. (ii) For Summer RFG, measure RVP of the batch. (iii) For Summer RBOB, measure the RVP of the handblend. (iv) Measure the sulfur content of the batch. (v) Measure the benzene content of the batch. 225 ------- (2) Gasoline manufacturers producing BOB that include the addition of downstream oxygenate in their compliance calculations must prepare a hand blend as specified in §1090.1340 and perform the following measurements: (i) For Summer CBOB, measure RVP in the BOB. (ii) For Summer RBOB, measure RVP in the hand blend. (iii) Measure the sulfur content of both the BOB and the hand blend. (iv) Measure the benzene content of the hand blend. [EPA-HQ-OAR-2018-0227-0035-A1, pp.10-11] > Turner, Mason & Company (TM&C) Subpart M - Sampling. Testing, and Retention Downstream Oxygenate Accounting In the preamble, EPA outlines a single method a gasoline manufacturer can account for oxygenate added downstream of a fuel manufacturing facility, creating flexibility to ensure average standards are satisfied. The approach described requires a gasoline manufacturer to use a "hand blend" when accounting for oxygenate added downstream. As written, this provides an option for the gasoline manufacturer to determine their approach for compliance; however, the language in 1090.1310(c)(1) for a gasoline manufacturer producing a BOB does not clearly allow this option. Rather, it requires one to prepare a "hand blend" and perform the measurement of the sulfur content (iii) and benzene content (iv) on both the BOB and the hand blend. This language is in conflict with the preamble, and we suggest the following to provide alignment with that proposed. (iii) Measure the sulfur content of the BOB, and when accounting for downstream oxygenate for compliance, measure the sulfur content of both the BOB and the hand blend. (iv) Measure the benzene content of the BOB, and when accounting for downstream oxygenate for compliance, measure the benzene content of both the BOB and the hand blend. [EPA-HQ- OAR-2018-0227-0045-A1, pp.3-4] Response: Consistent with the commenters' suggestion, we have revised §1090.1310(c) to clearly identify the testing requirements for BOBs, hand blends, or finished gasoline, depending on whether the gasoline manufacturer accounts for oxygenate added downstream. We believe the final language makes it clear that gasoline manufacturers have the option to account for oxygenate added downstream. 226 ------- Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.18 Testing: Benzene Timing Requirements EPA seeks comment on whether it would be appropriate to require gasoline manufacturers to test for benzene before shipping gasoline from the fuel manufacturing facility. The Associations note that the preamble states EPA is not proposing to require benzene testing prior to release, though the regulatory language indicates it is required. This inconsistency with the proposed regulatory language is found in 1090.1310(b) (2). The Associations offer proposed language below. [EPA- HQ-OAR-2018-0227-0074-A1.P .25] (b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive, or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as specified in §1090.1315: (2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur and benzene standards and perform testing for each batch of summer gasoline to demonstrate compliance with RVP standards. The Associations request modification of the regulatory language to gain agreement with what is outlined in the preamble. Benzene test results should not be required prior to shipment from the facility. There is no per gallon benzene maximum standard that a manufacturer would need to demonstrate compliance with prior to shipment. The regulatory text should be amended to reflect that for gasoline, only sulfur and summer RVP results are required prior to shipment. [EPA-HQ- OAR-2018-0227-0074-A1, p.26] > CITGO Petroleum Corporation (CITGO) 3.2 Testing to Demonstrate Compliance with Standards In 1090.1310(b)(2), fuel manufacturers must perform testing for each batch of gasoline to demonstrate compliance with sulfur and benzene standards and perform testing for each batch of summer gasoline to demonstrate compliance with RVP standards prior to the gasoline leaving the fuel manufacturing facility, except as specified in §1090.1315. CITGO supports EPA's intent to confirm gasoline meets applicable per-gallon standards however no per-gallon maximum standard exists for benzene and thus, benzene test results should not be required to demonstrate compliance prior to shipment. The regulatory text in §1090.1310(b) (2) should be amended removing benzene testing from the citation. [EPA-HQ- OAR-2018-0227-0054-A1, p.12] 227 ------- > Eversheds Sutherland (US) LLP For any required sampling and testing, we agree that EPA should continue the current RFG/RBOB requirement that testing is just for sulfur and RVP, and not for benzene. However, under 1090.1310(b)(2), the language includes benzene testing to demonstrate compliance. This would be a new requirement and would contribute to delays, which EPA's new testing requirements are already causing for imports. EPA should not include benzene as it states in the preamble. [EPA-HQ-OAR-2018-0227-0076-A1, p. 10] > Phillips 66 Company §1090.1310 - Benzene test results prior to batch shipment We ask EPA to modify the language to remove the requirement for benzene test results prior to shipment from the facility. The language in §1090.1310(b) (2) states that fuel manufacturers must test for sulfur, benzene and summer RVP before the batch leaves the facility (unless they have an inline blend waiver). This regulatory language contrasts with the preamble, which states: "We are not proposing to require gasoline manufacturers to test for benzene before shipping gasoline from the fuel manufacturing facility, but we are seeking comment on whether this would be appropriate". Since there is no per gallon benzene standard, there is no need for a fuel manufacturer to complete the testing prior to shipment. We ask that the regulatory language be modified to remove the requirement for benzene testing prior to batch shipment. (b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive, or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as specified in §1090.1315: (2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur and benzene standards and perform testing for each batch of summer gasoline to demonstrate compliance with RVP standards. [EPA-HQ-OAR-2018-0227-0060-A1, pg.3] > Shell Oil Products US C. Preamble Section IX. Sampling. Testing, and Retention and §1090.1310(b) (2) - Benzene Result Requirement Prior to Release Not Needed Preamble states: We are not proposing to require gasoline manufacturers to test for benzene before shipping gasoline from the fuel manufacturing facility, but we are seeking comment on whether this would be appropriate. 228 ------- §1090.1310 (b)(2): (b) Fuel manufacturers must perform the following measurements before the fuel, fuel additive, or regulated blendstock from a given batch leaves the fuel manufacturing facility, except as specified in §1090.1315: (2) Gasoline. Perform testing for each batch of gasoline to demonstrate compliance with sulfur and benzene standards and perform testing for each batch of summer gasoline to demonstrate compliance with RVP standards. The Preamble and the proposed rule are inconsistent. The preamble asks for comment in regard to requiring benzene analysis prior to release and the proposed rule already has this change written in the regulation. We do not support the requirement for a benzene result prior to release. There is no per gallon standard for benzene, so there is no need for a benzene result prior to release. This new requirement will be a burden and delay release of product. In addition, since the designated method for benzene is changing to ASTM D5769 and those facilities that would like to use the designated method may be planning to send the result to a third party lab so they do not have to purchase equipment. Shipping samples and awaiting test results will provide a significant delay to release of product. [EPA-HQ-OAR-2018-0227-0035-A1, p.4] Response: We did not intend to propose the requirement of benzene testing prior to shipment, as discussed in the NPRM.20 However, we inadvertently included language in the proposed regulations that suggested that fuel manufacturers would need to test benzene prior to shipment, inconsistent with the preamble. As such, we have revised §1090.1310 (b) (2) to clarify that we are not requiring benzene measurement before shipment. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Referenced ASTM Test Methods and Fuel Specifications The proposed Fuels Regulatory Streamlining rule contains references to old versions of several ASTM test methods and fuel specifications. These have either been updated since the proposal was released on May 14, 2020 or will be updated before the final rule is published by the end of 2020. The methods which have been updated by ASTM include: • ASTM D86-20a Standard Test Method for Distillation of Petroleum Products and Liquid Fuels at Atmospheric Pressure 20 See 85 FR 29067 (May 14, 2020). 229 ------- • ASTM D5769-20 Standard Test Method for Determination of Benzene, Toluene, and Total Aromatics in Finished Gasolines by Gas Chromatography/Mass Spectrometry • ASTM D5191-20 Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method) • ASTM D4814-20a Standard Specification for Automotive Spark-Ignition Engine Fuel • ASTM D975-20a Standard Specification for Diesel Fuel • ASTM D7039-15a (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 • ASTM D6299-20 Standard Practice for Applying Statistical Quality Assurance and Control Charting Techniques to Evaluate Analytical Measurement System Performance • ASTM D3606-20 Standard Test Method for Determination of Benzene and Toluene in Spark Ignition Fuels by Gas Chromatography'4 We request that, for the final published rule, EPA replace the references to the outdated ASTM test methods and fuel specifications that were shown in the proposed rule with the current updated references listed above. [EPA-HQ-OAR-2018-0227-0084-A1, pp. 1-2] 4 This latest version contains equations that allow users to correlate results with ASTM D5769. Response: We have updated the test methods as the commenter suggested. Comment: > bp America Inc. (bp) §1090.1320 Adding blendstock to PCG §1090.1320(b) (2) requires testing each blended batch of PCG and blendstock for T10, T50, T90, final boiling point and distillation residue. However, EPA does not have specifications for these parameters. States and pipelines already regulate these and other parameters by requiring adherence to ASTM D4814 specifications, bp recommends that EPA not require testing of parameters that it does not regulate which would have the effect of relieving an unnecessary burden. [EPA-HQ-OAR-2018-0227-0046-A1, p.20] > Flint Hills Resources 6) Part 1090 subpart M - 51090.1320(b)(2) Adding blendstock to PCG Suggestion: Revise (b) (2) to read: 230 ------- Determine At a fuel blending facility or a transmix processing facility, determine the following distillation parameters: T10, T50, T90, final boiling point, and distillation residue." Discussion: In the preamble at IX.A., EPA expresses that "For gasoline produced at a blending manufacturing facility or a transmix processing facility... distillation testing provides... confirmation that the blended product has a distillation profile ... consistent with ... subsim." Consistent with this rationale, one of the testing requirements spelled out in §1090.1310(e) is "For gasoline produced at a fuel blending facility or a transmix processing facility, gasoline manufacturers must measure such gasoline for oxygenate and for distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue) in addition to other measurements to demonstrate compliance with applicable standards." This requirement to test distillation is further expressed in the context of the blended gasoline that results from blending PCG with blendstocks, in §1090.1320(b)(2); however, as (b)(2) is currently proposed, it applies to all fuel manufacturers. It should be clarified that this distillation testing only applies when PCG is used to make a blended batch of gasoline at a fuel blending facility and transmix processing facility. [EPA-HQ-OAR-2018-0227-0052-A1, p.4] Response: We have removed the language in §1090.1320(b) (2) because it is redundant and created confusion. As the commenter pointed out, the requirement for gasoline manufacturers who produce gasoline at a blending manufacturing facility or a transmix processing facility to test for distillation is already set forth in §1090.1310(e). Comment: > CITGO Petroleum Corporation (CITGO) Definition of Facility in §1090.80. However, modification to subpart M to include sampling and testing of vessels similar to §1090.1605 is needed. [EPA-HQ-OAR-2018-0227-0054-A1, p.5] Response: The proposed rule included a paragraph in §1090.1300 referencing subpart Q to clarify that additional sampling and testing provisions apply uniquely for importation. We believe that this is more appropriate than repeating information from §1090.1605 in subpart N. Therefore, we are finalizing the cross-reference to the additional sampling and testing requirements for vessels in subpart N, as proposed. Comment: > CITGO Petroleum Corporation (CITGO) 2.7 Diesel Testing - Cetane/Aromatics Timing 231 ------- CITGO supports EPA's proposal not to require aromatic testing and cetane index for every batch of diesel fuel. CITGO also supports EPA's proposal to specify 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. Likewise, CITGO supports the addition of ASTM D4737 to ASTM D976 as acceptable procedures for calculating cetane index in diesel fuel. [EPA-HQ-OAR-2018-0227-0054-A1, pp. 10-11] Response: We thank the commenter for their support. Comment: > Magellan Midstream Partners §1090.1310 Testing to demonstrate compliance with standards Sections §1090.1310 (e) and §1090.1320(b)(1) both unnecessarily require oxygenate testing categorically for fuel blenders and transmix processors. This is also referenced in §1090.1810(g) (7) & (i)(5) attestation. §1090.1325(e) provides exemption for TGP if records show no oxygenate content in blendstock. We believe similar exemptions should be added for §1090.1310 (e) and for §1090.1320 (b)(1). We advise rewriting§1090.1310 (e) as follows: "§1090.1310 (e): For gasoline produced at a fuel blending facility or a transmix processing facility, gasoline manufacturers must measure such gasoline for oxygenate and for distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue) in addition to other measurements to demonstrate compliance with applicable standards. However, fuel manufacturers and transmix blenders do not have to measure the oxygenate content of the finished gasoline if the records for each blendstock show no oxygenate content." [EPA-HQ- OAR-2018-0227-0078-A1, p.6] Response: We have revised the final rule as the commenter suggested. Comment: > The American Association for Laboratory Accreditation (A2LA) Subpart M - Sampling. Testing, and Retention The ISO/IEC 17025 standard includes requirements for sampling, handling, and preparing samples; measurement procedures including selection of methods, method validation and method verification; and requirements for the transportation, receipt, handling, protection, storage, retention, and disposal or return of test samples. Through the accreditation process, laboratories can show to the accreditation body that they have the procedures in place and demonstrate 232 ------- adherence to the EPA requirements as set forth in Part 1090. Relying on accredited third party laboratories, will result in the test reports being more consistent because the laboratories will have reporting requirements that include both ISO/IEC 17025 and ASTM reporting requirements. [EPA-HQ-OAR-2018-0227-0065-A1, p.l] Subpart N - Survey Provisions By relying on accredited, third party testing laboratories as mentioned above, the breadth and complexity of a national fuel survey program may be reduced. The EPA-approved laboratory process may be simplified by relying on accreditation bodies to assess and accredit third party testing laboratories to the EPA criteria. Over time the annual sampling may be reduced by initiating a risk assessment process, by sampling and testing fuels that are more problematic or have shown a history of quality issues, instead of regularly testing all fuel types, thus reducing the overall costs of the program without reducing data quality. [EPA-HQ-OAR-2018-0227-0065- Al,p.2] An example of EPA Reiving on ILAC Recognized Accreditation Bodies US EPA National Lead Laboratory Accreditation Program (NLLAP): The agency has relied on A2LA since 1993 to conduct assessments and provide laboratory accreditation services to commercial and government environmental testing laboratories testing for lead in paint, paint chips and dust in public housing. This has reduced the need for the Agency to inspect the laboratories directly. Additional details of the program can be found at this link: https://www.epa.gov/lead/national-lead-laboratory-accreditation-program-nllap By requiring ILAC-recognized accreditation as an integral part the rule, the EPA can be assured of a program that is: • impartial and independent; • using the necessary industry expertise to assess the testing laboratories; • using appropriate sampling and test methods and procedures; • implementing recordkeeping and reporting processes; and • likely to reduce the practice of laboratory shopping, since all the laboratories will be operating at the same level of technical competency. [EPA-HQ-OAR-2018-0227-0065- Al,p.2] By relying on ILAC-recognized accreditation, governmental resources are available to focus on oversight and enforcement of the program while relying on approved, qualified technical experts for conducting the assessments. We ask that the EPA include in the rule a provision requiring testing laboratories to achieve and maintain ISO/IEC 17025 accreditation through an ILAC- recognized accreditation body. Reliance on ISO/IEC 17025:2017 accreditation is already widely accepted in the US testing industry and is being maintained by commercial testing laboratories, in-house captive testing laboratories and federal and state government laboratories. [EPA-HQ- OAR-2018-0227-0065-A1, p.2] 233 ------- Response: We do not believe that we should require ISO/IEC 17025 accreditation for labs. We did not propose to require that labs go through accreditation procedures and we believe that finalizing such a requirement would result in a substantial amount of burden on labs. Furthermore, we believe the provisions for instrument qualification and statistical quality control help ensure that labs provide high-quality test results for compliance demonstrations for EPA fuel quality requirements. Finally, we believe that the NSTOP will serve as a more robust oversight mechanism for sampling and testing procedures by fuel manufacturers and their labs, as this focuses specifically on the sampling and testing of fuel samples specific to EPA requirements by an independent party versus a generalized accreditation procedure. Comment: > Valero Energy Corporation H. Sampling. Testing and Retention Provisions I. Crosscheck Program The proposed rule Subpart M §1090.1300 — Crosscheck Program, requires (1)A crosscheck program is an arrangement for laboratories to perform measurements from test samples prepared from a single homogeneous fuel batch to establish an accepted reference value for evaluating precision and accuracy. This subpart relies on inter-laboratory crosscheck programs sponsored by ASTM International or another voluntary consensus standards body, or on crosscheck programs conducted separately by one or more companies. (2)A voluntary consensus standards body (VCSB) is an organization that follows consistent protocols to adopt standards reflecting a wide range of input from interested parties. ASTM International and the International Organization for Standardization are examples of VCSB organizations. Current §80.47(k)(4) references cross-check programs: (4) For a voluntary consensus standards body, such as ASTM, or for a commercially available industry crosscheck program, the summary statistics (mean and standard error = standard deviation/square root [number of results]) from the VCSB or commercially available inter- laboratory cross-check program (ILCP) data may be used as is without imposing the reference installations requirements of this section, provided that the number of non-outlying results is greater than 16 for both the designated and alternative test methods. The determination of ARV of check standards as specified in ASTM D6299, clause 6.2.2.1 and Note 7 shall be followed for the inter-laboratory crosscheck program. The use of VCSB or commercially available ILCP data as described above is deemed suitable for an ASTM D6708 assessment of VCSB alternative test methods. Valero recommends that EPA ensure that EPA can rely on cross-check programs other than ASTM or VCSBs while also specifying the standard for a cross-check program. Valero believes 234 ------- that the language suggested below, which incorporates additional elements from the current Part 80 regulation, would provide a more accurate description of a crosscheck program: (1) A crosscheck program is an arrangement for laboratories to perform measurements from test samples prepared from a single homogeneous fuel batch in participation within a study group to establish "accepted reference values" used to evaluate accuracy of individual laboratories and measurement systems. This subpart relies on periodic inter-laboratories studies sponsored by ASTM International, other voluntary consensus standards bodies and/or by independent companies that conform to ASTM D6708 Standard Practice for determination of "accepted reference values" on identical fuel batch samples for properties such as benzene, vapor pressure and sulfur (sulfur includes gasoline and ULSD). [EPA-HQ-OAR-2018-0227-0056-A1, pp.9-10] Response: The referenced paragraph is introductory material that simply describes what a crosscheck program is. The regulatory provisions at §§1090.1370 and 1090.1375 describe how parties rely on crosscheck programs as part of a compliance demonstration; these sections include further specifications describing how crosscheck programs can meet applicable requirements. The description in §1090.1300(f)(1) properly addresses the principles highlighted in the comment. However, we have incorporated some of the suggested wording to more carefully describe crosscheck programs, which will allow for crosscheck programs other than ASTM or VCSBs if certain conditions are met. 235 ------- 15.2. Handling and Testing Samples Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.15 Sampling: Collecting and Preparing Samples for Testing At §1090.1335(c), the NPRM proposes to perform automatic sampling as specified in ASTM D4177,23 and to "follow the recommended approach of at least 9,604 samples to represent a batch." As stated in comments submitted by API to the Agency in October 2019, there is concern that EPA is inappropriately referencing language in ASTM D4177 in specifying requirements for collecting and preparing samples for testing. The NPRM fails to recognize that ASTM D4177 is written primarily for crude oil automatic sampling which typically use Jiskoot systems that cycle every few seconds to collect the targeted 9604 samples per batch. [EPA-HQ-OAR-2018-0227- 0074-A1, pp.23-24] In fact, ASTM D4177 explicitly recognizes that small batch sizes, the homogeneity of the samples being grabbed for testing, capacity of the compositor itself, and other sampling system constraints may result in or necessitate the use of designs based on different statistical margin of error and confidence level criteria. Per ASTM D4177, 19.1.2, for refined products, "[a] representative sample does not necessarily require 9604 grabs per parcel because the product is usually homogeneous." The experience of facilities with established in-line blending supports this observation in ASTM D4177. As a rule, existing industry sampling capability designs for finished product streams has been sufficient to represent a batch with fewer than 9,604 grab samples. Most existing systems were not designed for and are not capable of achieving 9,604 grabs during the batch. If the rule is promulgated as proposed, all these existing systems would have to be modified, for no good technical reason. [EPA-HQ-OAR-2018-0227-0074-A1, p.24] The Associations recommend that the Agency adopt a bifurcated approach that: (a) grandfathers the typical grab sample frequencies used by experienced facilities with existing in-line blending and automatic sampling capability; and (b) for facilities that need to apply for waivers to use new in-line blending and sampling capabilities, the required number of grab samples should revert back to the language used in the previous "Discussion Draft" document which specified a margin of error of 0.03 and a 95 percent confidence interval (equivalent to a minimum of 1,067 grab samples per batch). [EPA-HQ-OAR-2018-0227-0074-A1, p.24] Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.505 236 ------- Comment: Subpart F—Transmix and Pipeline Interface Provisions §1090.505(c) The Associations are also concerned about the requirement to take 9,604 samples that would be imposed on transmix blenders with inline autocompositors by §1090.1315(b) (2). That provision requires compliance with ASTM D4177. Part II of the ASTM standard requires the taking of 9,604 samples per batch. However, that part applies to crude oil shipments not refined products. Refined products are addressed in Part III of that ASTM standard and do not require that many samples. In addition, transmix blenders typically inject transmix only into a portion of a batch not the entire volume. That is necessary since pipeline operators need to consider the quality of the pipeline interface which is less suitable for transmix blending than the rest of the batch. That reduces the volume into which the transmix can be injected thereby limiting the number of samples that can be feasibly taken using available technology. That makes the collection of 9,604 samples even more difficult. The Associations recommend that this provision clarify that in-line blenders are subject to Part III of ASTM D4177 and not Part II. (Note, a more detailed discussion of the applicability of D4177 to refined product sampling can be found elsewhere in the Association's comments.) In addition, the transmix blending process is much simpler than refining gasoline at a refinery and in combination with the quality assurance program described in §1090.505(b) provides a high degree of assurance that EPA's gasoline specifications will be met. The Associations requests that EPA remove the in-line blending requirement under §1090.505(c) (2). If EPA decides to include the in-line blending petition requirement for transmix blenders, we request that the petition be simplified to fit the nature of the transmix blending operation and that the initial petition not be required before January 1, 2022. 23 Incorporated by reference in proposed §1090.95. > bp America Inc. (bp) §1090.1335 Collecting and preparing samples for testing bp suggests adding a reference to Table 6 of ASTM D4057 to §1090.1335(b) to address tanks with a capacity of less than or equal to 10,000 barrels. That scenario is not adequately addressed in the current draft of the sample preparation requirements. Refineries that have EPA approved in-line blending waivers are able to collect their certification samples using the in-line blending equipment and analyzers and are permitted to transport the fuel outside the refinery gate prior to the receipt of certification sample results. However, those refineries that do not have such waivers and use manual sampling techniques need to certify individual tanks as they are 237 ------- produced. It can sometimes be challenging to collect the necessary samples from such tanks during times when a refinery is experiencing high winds, rain, snow, or ice making it dangerous for personnel to take samples. §1090.1335(c) permits sample collection using automatic samplers as specified in ASTM D4177. bp suggests that those fuel manufacturers who conduct manual tank sampling be permitted to use auto-compositors as an alternative to manual tank sampling and in accordance with §1090.1335(c) when they are experiencing inclement weather that could adversely affect the safety of personnel who take the manual samples. In addition, bp requests that EPA confirm that auto-compositors can be used under this provision without obtaining an EPA approved inline blending petition, provided the fuel is not permitted to leave the fuel manufacturing facility prior to the receipt of the certification sample results. Persons who perform automatic sampling must do so under ASTM D4177 as required by §1090.1335(c). That provision states that the . . . [d]efault sampling frequency should follow the recommended approach of at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy under §1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch." As stated in bp's comments above, Part II of ASTM D4177 requires the taking of 9,604 samples per batch. However, that part applies to crude oil shipments not refined products. Refined products are addressed in Part III of that ASTM standard and do not require that many samples. Setting a sample frequency for automatic sampling for a given batch as currently proposed is unnecessarily stringent and would require a significant investment to achieve. This may in fact be too many samples to practically achieve, especially for small batches. ASTM D4177 does not mandate a sampling frequency for automatic sampling systems of at least 9,604 samples batch. ASTM D4177, PART III—Refined Product Sampling states as follows: "19.1.2: A representative sample does not necessarily require 9604 grabs per parcel because the product is usually homogeneous". The statistical treatment in ASTM D4177 Annex A is only appropriate for a rapidly changing stream which is not typical of refined product streams. bp recommends that EPA require that sites collect a representative sample which would allow them to tie the sampling rate to their actual production batch volume, bp suggests this provision be amended as follows: "Perform automatic sampling as specified in ASTM D4177 (incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at the sampling point. Ensure that a representative sample of the entire batch is taken. Take steps to align the start and end of sampling with the start and end of creating the batch." [EPA-HQ-OAR- 2018-0227-0046-A1, pp.20-21] > Magellan Midstream Partners §1090.1335 Collecting and preparing samples for testing As batch sizes are defined and not approaching an infinite volume, in most cases small batch sizes do not allow for samples to physically be collected at a representative volume and frequency to meet the 0.01 margin of error as suggested in §1090.1335(c). Samples are collected 238 ------- as described in ASTM D4177-16el Section 18.3.7. It is acknowledged within D4177-16el that this applies to crude sampling, and section 19 implies that the statistical margin of error could apply to refined products. However, section 19.1.2 states that the 0.01 margin of error is not necessarily required as the product is usually homogenous. Therefore, it is recommended that a dual approach be used to address small batch sampling or high rate pipeline transfers: (a) the margin of error is specified at 0.03 and a 95 percent confidence level, or (b) the aliquots are collected at a frequency of no more than 00:20 seconds apart throughout the batch. This can be accomplished via the following changes: "(c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177 (incorporated by reference in § 1090.95). Configure the system to ensure a well-mixed stream at the sampling point. The default sampling frequency should follow the recommended approach of at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy under § 1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take steps to align the start and end of sampling with the start and end of creating the batch. A dual approach may be used to address small batch sampling or high rate pipeline transfers: (a) the margin of error is specified at 0.03 and a 95 percent confidence level, or (b) the aliquots are collected at a frequency of no more than 00:20 seconds apart throughout the batch." [EPA-HQ- OAR-2018-0227-0078-A1, pg.7] > Marathon Petroleum Company LP (MPC) Automatic Sampling 1090.1335(c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177 (incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at the sampling point. The default sampling frequency should follow the recommended approach of at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy under §1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take steps to align the start and end of sampling with the start and end of creating the batch. The requirement of 9,604 grab samples per batch may not always be achievable. Rather than citing a specific number in the rule, it should be sufficient to follow ASTM D4177 guidance. ASTM D4177 has a requirement of about 10,000 grabs/injections into an automated sampler vessel. This 10,000 grabs/injections is for crude oil and does not apply to finished products such as with an in-line gasoline blender. Per ASTM D4177, PART III—Refined Product Sampling, "19.1.2 A representative sample does not necessarily require 9604 grabs per parcel because the product is usually homogeneous". [EPA-HQ-OAR-2018-0227-0048-A2, p.l] > Phillips 66 Company Automatic Sampling We ask EPA to remove the language in §1090.1335(c) that requires a minimum of 9,604 sample grabs. This is a misapplication of the ASTM D4177 standard and is not necessary for gasoline or 239 ------- diesel streams. Existing systems would likely not be able to meet this requirement and would have to be replaced, even though they have been operating and performing adequately to date. We strongly support the more detailed and extensive comments on this issue supplied by API and AFPM. [EPA-HQ-OAR-2018-0227-0060-A1, pg.6] > Shell Oil Products US A. Section 1090.1335(c) - In line Blending Margin of Error §1090.1335 Collecting and preparing samples for testing. (c) Automatic sampling. Perform automatic sampling as specified in ASTM D4177 (incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at the sampling point. The default sampling frequency should follow the recommended approach of at least 9,604 samples to represent a batch. EPA may approve a less frequent sampling strategy under §1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take steps to align the start and end of sampling with the start and end of creating the batch. Historically, in line blending has been occurring for over 20+ years and we are unaware of an issue in the marketplace that involved a compositor misrepresenting a product blend. In some cases, the same installation has been in place for the entire 20+ years and is unable to meet the requirements in an updated 2016 version of ASTM D4177 and be able to take 9,604 samples. In addition, the 9,604 sampling frequency is written in ASTM D4177 for crude sampling. Installation of new systems would take years and cost a considerable amount of money. We suggest that all in-line blending installations in place prior to the start of EPA Streamlining (January 1, 2021) be grandfathered and not have to meet the new requirements. Any new installations should be required to meet the sampling suggested in the 4th draft of the EPA Streamlining regulations - meet the margin of error of 0.03 and a 95 percent confidence level. We propose the following language: (c) Automatic sampling. For installations after January 1, 2021, perform automatic sampling as specified in ASTM D4177 (incorporated by reference in §1090.95). Configure the system to ensure a well-mixed stream at the sampling point. The default sampling frequency should follow the recommended approach of meeting the margin of error of 0.03 and a 95 percent confidence level. EPA may approve a less frequent sampling strategy under §1090.1315(b) (2) if it is appropriate for a given facility or for a small-volume batch. Take steps to align the start and end of sampling with the start and end of creating the batch. Installations prior to January 1, 2021 are grandfathered from the language above. [EPA-HQ-OAR-2018-0227-0035-A1, p.3] Response: We are revising regulations to better address situations where the ASTM D4177 minimum sampling frequency of 9,604 samples cannot be met. Due to the variable nature of small batch sizes, we are finalizing an option to allow for parties to establish a minimum frequency by collecting aliquots least once every 20 seconds). We believe these options will allow for parties 240 ------- that use automatic sampling enough flexibility to always collect a representative compositive sample regardless of batch size. We do not believe it is appropriate to just require that a representative sample be taken adhering to Part III of ASTM D4177. Part III of ASTM D4177 provides no criteria as to how a representative sample is determined. Such a requirement would be meaningless if both our regulations and ASTM D4177 provide no criteria for how to determine whether a sample is representative of the batch. We are also not grandfathering facilities with previously approved ILB waivers. We believe we have provided enough flexibility for facilities to comply and we want to ensure that all facilities using automatic sampling adhere to the most recent version of ASTM D4177. To accommodate the potential impact of facilities, with or without ILBs, implementing the most recent version of ASTM D4177, we are allowing all facilities to use the older version of ASTM D4177 until January 1, 2022. We are, however, removing the requirement for transmix blenders to request and receive an ILB waiver. As one commenter suggests, this is not necessary if the transmix blender adheres to applicable automatic sampling protocols in ASTM D4177. Finally, we have clarified the regulations to permit automatic sampling for batches without an ILB waiver. Note that testing must be complete prior to shipping for cases involving automatic sampling if there is no ILB waiver. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.16 Sampling: Homogeneity EPA proposes to consider a batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than the published repeatability of the test method. If repeatability is a function of measured values, EPA proposes to calculate repeatability using the average value of the measured parameter representing all tested samples. EPA also notes that for cases that do not require a homogeneity demonstration under § 1090.1335(b) (4), the lack of homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or regulated blendstock from being considered a batch for demonstrating compliance with the requirements of §1090.1337. [EPA-HQ-OAR-2018-0227-0074-A1, p.24] EPA's proposal to use the published repeatability of the test method as the criterion for determining batch homogeneity (based on measurements of samples drawn from the upper, middle, and lower levels of a batch) for a given fuel parameter is too stringent. Repeatability is defined as the difference between two test results obtained by the same operator with the same apparatus under constant operating conditions on identical test material. Reproducibility is the difference between two single and independent results obtained by different operators working in 241 ------- different laboratories on identical test material. While the upper, middle, and lower samples are presumed to be identical they are separate aliquots which makes the published test method Reproducibility the more appropriate tolerance. Furthermore, measurements of the RVP of summer gasoline fuels and the API gravity of winter gasoline fuels pose variability issues related to the control of volatile sample components. To address these concerns, the Associations recommend that EPA instead use a maximum tolerance of 0.75 x R (where "R" is the published Reproducibility of the relevant ASTM test method) as the required criterion for demonstrating homogeneity. This metric is consistent with the criterion used in EPA's Performance-Based Analytical Test Method Assessment program documented in 40 CFR § 80.47. [EPA-HQ-OAR- 2018-0227-0074-A1, pp.24-25] > bp America Inc. (bp) §1090.1337 Demonstrating homogeneity §1090.1337(e) states "Consider the batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than the published repeatability of the test method. If repeatability is a function of measured values, calculate repeatability using the average value of the measured parameter representing all tested samples..." The use of published repeatability to establish homogeneity presumes that testing on all samples will occur back-to-back on a single instrument by a single individual. Since it is typically more efficient and more common to run these samples in parallel on multiple instruments by multiple people, a more applicable homogeneity criterion would be one based on site precision. This could be designated in one of three ways, listed in order of increasing complexity: 1. A fixed criterion calculated from the acceptable site precision for each test (based on ASTM D6792) for a typical value of the parameter. (Note: Discussion Draft #3 from April 2019 used the following criteria for establishing homogeneity): [See the table on p.22 of EPA-HQ-OAR- 2018-0227-0046-A1.] We have not confirmed that all of these values are based on the target test performance index (TPI) for each test, but they seem to be in the right range. 2. If there is significant variation of the site precision with level of the measured property, an equation could be provided for each test instead of the fixed criterion noted above. 3. Use the actual site precision for each test as the homogeneity criterion if the site demonstrates compliance with the TPI requirements in ASTM D6792, or b. Use the published ASTM repeatability for the test method if the site precision does not meet the TPI requirements of ASTM D6792 [EPA-HQ-OAR-2018-0227-0046-A1, pp.22] > Flint Hills Resources 8) Part 1090 subpart M - 51337(e) Demonstrating homogeneity Suggestion: Revise §1090.1337(e) to read: 242 ------- §1090.1337(e) Consider the batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than 0.75 x R (where "R" is the published Reproducibility of the ASTM test method being used) the published repeatability of the test method. If repeatability Reproducibility is a function of measured values, calculate repeatability 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 §1090.1335(b) (4), the lack of homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or regulated blendstock from being considered a batch for demonstrating compliance with the requirements of this part. Discussion: EPA's proposal to use the published repeatability of the test method as the criterion for determining batch homogeneity (based on measurements of samples drawn from the upper, middle, and lower levels of a batch) for a given fuel parameter is inappropriate and too stringent. ASTM defines repeatability conditions as "conditions where independent test results are obtained with the same method on identical test items in the same laboratory by the same operator using the same equipment within short intervals of time." Samples from various levels in a tank are independent samples and are not be "identical test items." We recommend that EPA instead use 0.75 x R (where "R" is the published Reproducibility of the relevant ASTM test method) as the required criterion for demonstrating homogeneity. This metric is consistent with the criterion used in EPA's Performance-Based Analytical Test Method Assessment program documented in 40 CFR § 80.47 . [EPA-HQ-OAR-2018-0227-0052-A1, pp.5-6] > Magellan Midstream Partners §1090.1337 Demonstrating homogeneity EPA's proposal to use the published repeatability of the test method as the criterion for determining batch homogeneity (based on measurements of samples drawn from the upper, middle and lower levels of a batch) for a given fuel parameter is too stringent and not an accurate use of the meaning of repeatability (same sample and retested by same operator/or instrument). Measurements of the RVP of summer gasoline fuels and the API gravity of winter gasoline fuels pose variability issues related to the control of volatile sample components. To address these concerns, we recommend that EPA instead use R (where "R" is the published Reproducibility of the relevant ASTM test method) as the required criterion for demonstrating homogeneity. R is more reasonable since it would be measuring the closeness of three unique samples from the same batch. Additionally, we recommend the inclusion of D7777 as an acceptable method to measure gravity as the R of this method is very comparable to the other listed methods. R for D7777 is 0.0021 g/mL as compared to 0.0019 g/mL for D4052. §1090.1337 Demonstrating homogeneity. 243 ------- (1) Measure API gravity from each sample using ASTM D287, ASTM D1298, ASTM D7777 or ASTM D4052 (incorporated by reference in §1090.95)." [EPA-HQ-OAR-2018-0227-0078-A1, PP-7-8] > Marathon Petroleum Company LP (MPC) Revise standard for tank homogeneity Section 1090.1337(e) states: "Consider the batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than the published repeatability of the test method." MPC believes the use of repeatability is the wrong measure. Instead, the EPA should use reproducibility. Repeatability would be the correct method when testing the same sample multiple times. In this instance, sampling of a tank is done from multiple levels to determine if the tank is homogeneous. Because the samples are collected individually and are not from the same aliquot, the correct method should be reproducibility. The use of repeatability for determination of homogeneity is more strict than current requirements. For example, refiners currently use 0.5 to 0.6 API to demonstrate homogeneity and the test method repeatability is 0.09, an order of magnitude tighter. [EPA-HQ-OAR-2018-0227-0048-A1, p.2] > Marathon Petroleum Company LP (MPC) Demonstrating Homogeneity 1090.1337(e) Consider the batch to be homogeneous for a given parameter if the measured values for all tested samples vary by less than the published repeatability of the test method. If repeatability is a function of measured values, calculate repeatability using the average value of the measured parameter representing all tested samples. Calculate using all meaningful significant figures as specified for the test method, even if §1090.1350(c) describes a different precision. For cases that do not require a homogeneity demonstration under §1090.1335(b)(4), the lack of homogeneity demonstration does not prevent a quantity of fuel, fuel additive, or regulated blendstock from being considered a batch for demonstrating compliance with the requirements of this part. The new method for demonstrating homogeneity is more strict than 40 CFR part 80 requirements. Using the test method repeatability as a criterion will be hard to meet. For example, refiners are currently using 0.5 or 0.6 API to demonstrate homogeneity and the repeatability is 0.09. The previous practice was more straightforward (0.6 API, 2ppm sulfur, 0.06 vol% benzene, 0.3 psi RVP). A survey of laboratory data shows repeatability limits to be overly restrictive, particularly for volatile winter gasolines which may have additional sampling and handling impacts. For example, the D4052 API requirement (r=0.063°API for automatic instruments) is ten times more stringent than the previous proposal. This gives an estimated 10% fail rate in the summer and a 30% failure rate during winter compared to a <1% fail rate at a 0.5°API target. D4052 does not give a level-dependent repeatability statement but it does give a level-dependent reproducibility statement, which suggests that the ASTM r may not adequately represent the winter fuels. 244 ------- Because the samples are collected individually, and samples are not from the same aliquot, it is recommended this requirement be expanded to use reproducibility. [EPA-HQ-OAR-2018-0227- 0048-A2, p.2] > Phillips 66 Company Demonstrating Homogeneity We recommend EPA modify the proposed language regarding homogeneity demonstration and provide additional clarity on collection and preparation of samples. The proposed requirements for demonstrating homogeneity are too stringent and represent a significant change from current industry practices. Part 80 defines batch of gasoline as "a quantity of gasoline that is homogeneous with regard to those properties that are specified for conventional or reformulated gasoline", however there is no corresponding regulatory section that provides details on how to demonstrate homogeneity. It is likely most parties utilize the guidance contained in an EPA Questions and Answer document. In response to a question titled "How should storage tanks be sampled for RFG?", EPA states Gravity analyses of upper, middle, and lower samples is an appropriate means of establishing tank homogeneity. EPA would consider a tank to be homogeneous where the maximum difference in tested gravities between any two samples from different tank strata is no greater than 0.6 °API, unless there is reason to believe the tank contents are not mixed in spite of such gravity test results. EPA is now proposing that fuel manufacturers take upper, middle and lower tank samples and test for 2 properties (RVP, gravity, sulfur, or benzene). The test results for the 3 samples must agree within repeatability of the test method for the tank to be considered homogeneous. The test method for density and API gravity is ASTM D4052 and the API gravity repeatability for gasoline is 0.09 ?API. Per the proposal, in order to use gravity as one of the tests for demonstrating homogeneity, the 3 samples would have to agree within 0.09 ?API. This is a significant change versus the 0.6 ?API the industry has been using, which is the published reproducibility and consistent with prior guidance. We ask EPA to change the proposed language in §1090.1337(e) to require the test results agree within reproducibility (R) rather than repeatability (r). [EPA-HQ-OAR-2018-0227-0060-A1, pg.4] Response: We recognize commenters' concerns that using the repeatability of the method to establish homogeneity for a batch is too restrictive in many cases.21 However, we believe that using reproducibility as the criteria for establishing homogeneity is inappropriate. Reproducibility is the variation in a test result when a sample is tested at multiple labs using the same method. For 21 Repeatability is the variation in a test result when a sample is tested at the same lab, using the same instrument, with the same operator. 245 ------- homogeneity testing, the same lab will be conducting the testing often using the same instrumentation and operator. We also do not believe that we should specify specific criteria for each fuel parameter (e.g., 0.6 API gravity). Under part 1090 (consistent with part 80), we allow for a variety of test methods for each fuel parameter (i.e., any method that can meet PBMS requirements). Given the number of different methods that could be used for a given parameter, either now or in the future, it would be inappropriate to set static homogeneity criteria for each fuel parameter based on current testing methodologies. Therefore, we are modifying the proposed homogeneity criteria in response to commenters' suggestion to use 0.75 times the reproducibility of the method. We believe this is an appropriate compromise between a method's stated repeatability and reproducibility while also being flexible to accommodate the variety of methods allowable under part 1090. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: We are therefore proposing that gasoline manufacturers do not need to keep each hand-blended sample; they would instead need to keep a DFE sample to allow them to create new hand- blended samples corresponding to each BOB sample. With this approach, a single DFE sample might be available for blending with multiple BOB samples. 1090.1345(a) (2)(i) If you test a hand blend under §1090.1340, keep a sample of the BOB. Comment: There is an inconsistency between the preamble and the NPRM language. We concur with the sample retention change mentioned in the preamble, but the NPRM language is missing language involving keeping a DFE sample. The requirement should be for a retain of a "prior to blending" sample of any DFE and BOB sample used for product certification. We proposed the following language: (i) If you test a hand blend under §1090.1340, keep a sample of the BOB and a representative DFE sample. Additionally, sample retention is 30 days for fuel manufacturer, and 120 days for blending manufacturers. Section 1090.1345(a)(1): If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under this subpart, you must keep a representative fuel sample for at least 30 days after testing is complete, except that a longer sample retention of 120 days applies for blending manufacturers that produce gasoline. The requirement of 120 days of 246 ------- sample retention for gasoline and diesel samples is prohibitive to current laboratory space and storage. Associations suggest a minimum 60-day requirement [EPA-HQ-OAR-2018-0227-0074- Al, p.32] > bp America Inc. (bp) §1090.1345 Retaining samples §1090.1345(a)(1) and (e) require fuel manufacturers to retain samples for 30 days but require blending manufacturers and/or the third-party inspection companies they engage to retain a representative fuel sample for 120 days. There is no discernible rationale for a longer retention time for blending manufacturers and independent third-party inspection companies. That requirement can have a significant impact on those blending manufacturers that have storage limitations. In addition, longer retention times are likely to significantly impact costs unnecessarily due to limited availability of storage space, bp recommends retention times of 90 days for blending manufacturers and independent third-party inspection companies as this reflects standard industry practices. [EPA-HQ-OAR-2018-0227-0046-A1, pp.22-23] > Buckeye Partners, L.P. §1090.1345 Retaining samples. Comment #5 - Section (a) (1) - This section requires all blending manufacturers to keep retain samples for at least 120 days. EPA indicates in the preamble that "blending manufactures typically have less control over the quality of the blendstock they use to produce gasoline" and therefor are requiring a longer sample retention time of 120 days to help trace potential issues with fuel quality. Certified butane blenders do not have this concern as the quality of the certified butane and the BOB gasoline is known and documented, and the blended material is certified post blend. We respectfully request that EPA allow for certified butane blenders to store retain samples at least 30 days. Most certified butane blenders do not have enough dedicated flammable storage cabinets to safely store four times the current about of samples required. Four months greatly exceeds current requirements and industry standards, and current sample storage capacity is undersized to keep 120 days of gasoline samples on hand. Buckeye respectfully requests the following edits to this section: (1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under this subpart, you must keep a representative fuel sample for at least 30 days after testing is complete^ including samples require forT Certified Butane Blender and Certified Pentane Blenders, ej^eept that-Aa longer sample retention of 120 days applies for other blending manufacturers that produce gasoline. [EPA-HQ-OAR-2018-0227-0032-A1, pp.2-3] 247 ------- > Camin Cargo Control B. The proposed rule calls for an extended sample retention time of 120 days (Part 1090.1345) which will impose an undue financial burden on laboratories. Petroleum laboratories currently store thousands of gasoline and diesel samples at each facility for an Industry average of 90 days maximum. In our case, based on the current utilized storage capacity, we predict we will need to increase our storage space by 30%, at an average cost of over USD 150,000 per laboratory. This expense will NOT be covered by laboratory clients but will be borne by the laboratory industry placing an undue financial burden on them, which is in direct opposition to the stated objective of cost reduction in the Preamble XIV. Costs and Benefits. [EPA-HQ-OAR-2018-0227-0030- Al,p.2] 7. 1090.1335 Collecting and preparing samples for testing d. Sample Retention In 1090.1345(a)(1) EPA proposes to keep samples for 30 days for all fuel manufacturers (all oil companies, refiners, blenders, traders, importers, etc.) but on (1) it says 'except that a longer sample retention of 120 days applies for blending manufacturers...' As written and based on the definitions found in 1090.80, parties are directed to retain samples of all gasolines, regulated blendstock and Diesel for the majority of market players for 120 days. This retention time is impractical, very onerous and increases the liability on both the responsible party (product owner) and the entity storing the sample (custody laboratory). As per Industry experience, professional knowledge and Best Laboratory Practices recommendations, testing of a sample should occur as close to the sampling as possible to avoid deterioration of the sample quality by aging, chemical contamination and environmental conditions. If the retention remains at 120 days on the Federal Regulations, fuel manufacturers/stakeholders will impose this period on the samplers/testing laboratories without further compensation for the additional costs. This would contradict EPA's objective of cost reduction to the Industry as expressed in the Preamble XIV. Costs and Benefits. The retention period should start from sample COLLECTION DATE, not from testing completion date, which necessarily changes with any additional testing; it is impractical to track retention times when the disposal date becomes a moving target. [EPA-HQ-OAR-2018-0227- 0030-Al.pp.7-8] > Energy Transfer L.P. (ET) 3) Subpart M—Sampling. Testing, and Retention The requirement for certain parties in §1090.1345 to retain samples for 120 days is excessive. Since products typically do not remain in the distribution system for more than 30 days, holding 248 ------- samples beyond that time would be of no benefit and the corresponding detriment would substantially outweigh. Samples need to be maintained in dedicated flammable hazardous materials storage cabinets. Blending manufacturers, including butane blending facilities, typically do not have unlimited storage capacity available to store four (4) times the samples, so they would be forced to acquire or build additional costly storage units. This also potentially imposes additional health and safety considerations which would further burden on-site facilities. Additionally, blending manufacturers produce and ship fuels through the same distribution network as crude oil refineries and, as such, they also are subject to the same "multiple levels of control to ensure fuel quality" as stated in the preamble. We respectfully propose re-wording the proposed language in §1090.1345(a) (1) to the following: "If you test gasoline, regulated blendstock blended gasoline, diesel fuel, or oxygenate to measure any parameter as required under this subpart, you must keep a representative fuel sample for at least 30 days after testing is complete, except that a longer sample retention of 120 days shall apply to blending manufacturers who produce gasoline and supply directly to end users. By making this change, it is more appropriately narrowly-focused to complement reality. [EPA-HO- OAR-2018-0227-0044-A1, p.2] > Eversheds Sutherland (US) LLP Gasoline and Diesel Sampling and Testing EPA is proposing that sample retention for blenders be 120 days for gasoline and diesel, but only 30 days for refineries.39 This additional burden on blenders and labs is not warranted and will cost both money and additional resources to accomplish. EPA justifies this inequitable requirement by concluding that blenders can make fuel on a more ad hoc basis "e.g., in a tanker truck."40 EPA also states that blending manufacturers have less control over the quality of the blendstocks they use to produce gasoline. Such a statement is confounding given that blenders have always been treated as refiners under the statute and regulations and therefore produce gasoline that meets the exact same standards. Despite the critical role played by blenders in our gasoline distribution system, EPA paints a picture of subpar components and on-the-fly blending operations. Blending manufacturers are sophisticated entities who take compliance seriously— and have done so since the inception of Part 80. Gasoline produced through blending operations meet EPA's standards and are also shipped via pipelines "that have strict product specification prior to injection."41 Additionally, blending manufacturers have customers who expect to receive on-spec fuel (just as refiners' customers do). The cost of such additional retention is an unknown at this point but would add to the compliance costs for blending manufacturers. EPA should require the exact same sample retention for all gasoline and diesel samples—30 days—and the sample should be from the date of collection, not upon test completion. 39 Id. at § 1090.1345(a)(1). 40 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,068. 249 ------- 41 Id. > Magellan Midstream Partners §1090.1345 Retaining samples In order to ensure the highest quality control standards for consumers, and to provide a level playing field for all obligated parties, we believe sample retention should be 30 days, except for butane samples. This can be achieved via the following: "(1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under this subpart, you must keep a representative fuel sample for at least 30 days after testing is completeexcept that a longer sample retention of 120 days applied for blending manufacturers that produce gasoline." Certified butane batch samples and certified butane blender oversight sample cylinders should not have to be retained beyond receipt of testing results from the laboratory due to the following reasons: 1) EPA has previously acknowledged the concerns that pertain to these high pressure containers, as noted in this excerpt from 65 FR page 6809 - "A final comment by NPRA about the sample retention and submission requirements is addressed in the final rule. NPRA raised a concern about the required retention and submission of samples of pressurized blendstock, particularly butane, which would require the use of specialized high-pressure containers. EPA agrees that there is legitimate concern about the handling, storing and shipping of such samples. We also believe that the final rule's quality assurance testing requirements and the testing requirements for blendstock suppliers provides adequate assurance of the compliance of these blendstocks. Hence, the final sulfur rule does not contain a requirement that samples of pressurized blendstock must be retained." 2) Cost - each constant pressure sample cylinder costs more than $2,000 and must be stored in a protective case and can't be used while storing a sample, so retaining the samples will require the purchase of a significant number of additional units. In addition to the cost of purchase, each cylinder must be inspected once per year and recertified once every 5 or 7 years which results in significant additional cost. 3) Retention Space - sample cylinders are upwards of two feet long and must be stored in a protective case. Retention of samples would require building or acquisition of additional storage facilities. If it is EPA's intent to remove the sample retention requirement for certified butane producers, then paragraph (a) of this section should be changed as follows: 250 ------- (a) "Fuel manufacturers, regulated blcndstock producers, and independent surveyors must retain samples of fuel and oxygenate tested under this subpart as follows:" [EPA-HQ-OAR-2018-0227- 0078-Al.pp.8-9] > Marathon Petroleum Company LP (MPC) Sample retention requirements for Butane Blenders Section 1090.1345(a) states: "Fuel manufacturers, regulated blendstock producers, and independent surveyors must retain samples of fuel and oxygenate tested under this subpart as follows: (1) If you test gasoline, diesel fuel, or oxygenate to measure any parameter as required under this subpart, you must keep a representative fuel sample for at least 30 days after testing is complete, except that a longer sample retention of 120 days applies for blending manufacturers that produce gasoline." MPC believes this requirement is in error and should not apply to winter gasoline produced by blending certified butane because Reid Vapor Pressure (RVP) testing of the final batch is not required. For summer fuel produced by blending certified butane, MPC understands testing the RVP of a final batch is a requirement. MPC is concerned with the requirement to retain a sample for one hundred (120) days. Specifically, MPC does not believe a sample to be used strictly for volatility testing will be representative of the blend for an extended period of time. As an alternative, MPC would propose relying on vendor supplied Certificates of Analysis (COA). Or, in the alternative, if a sample must be retained, then the retention period should be limited to thirty (30) days. Finally, MPC does not believe these sample retention requirements should apply to the certified butane oversight samples discussed in 1090.1320(c)(4). As currently stated, sample retention for certified butane and certified pentane blenders is not identified in the fuel regulatory streamlining proposal. Retention of either regulated blendstock rests with the producer (s). [EPA-HQ-OAR- 2018-0227-0048-Al.pp.5-6] > Shell Oil Products US G. Preamble and Section §1090.1345 (a)(2)(i) - Inconsistency Between Preamble and Proposed Regulation for Sample Retention Preamble states: We are therefore proposing that gasoline manufacturers do not need to keep each hand-blended sample; they would instead need to keep a DFE sample to allow them to create new hand- blended samples corresponding to each BOB sample. With this approach, a single DFE sample might be available for blending with multiple BOB samples. §1090.1345 (a)(2)(i) Downstream oxygenate accounting (i) If you test a hand blend under §1090.1340, keep a sample of the BOB. 251 ------- There is an inconsistency between the preamble and the proposed rule language. We concur with the sample retention change mentioned in the preamble but the proposed rule language is missing language involving keeping a DFE sample. We proposed the following language: (i) If you test a hand blend under §1090.1340, keep a sample of the BOB and a DFE sample. [EPA-HQ-OAR-2018-0227-0035-Al.pp.6-7] > TexonL.P. IV. Blendstock Sample Retention. §1090.1345(a)(l) §1090.1345(a) regulated blendstock producers.. .must retain samples of fuel and regulated blendstocks. Please consider an exemption for butane sample retention for the following reasons: A. Samples of butane are contained in pressurized LPG cylinders that are highly specialized, and unlike laboratory glass bottles used for liquid fuel/blendstock samples. B. LPG cylinders must be stored in climate-controlled areas for safe product handling. Large safe storage areas may not be readily available at laboratories or production facilities to hold samples for 120-days. C. OSHA requires Flammable Material Storage programs and stockpiling flammable hazardous materials for 120-days would pose unnecessary health and safety risks. D. As liquefied gases expand in warm ambient temperatures, the cylinders are designed with pressure relief valves for safe transport and handling. The cylinders are safety designed and expensive with a unit cost $ 1200-S2500, and require an annual inspection/maintenance cost of $700/unit for DOT compliance. E. Producers and blenders maintain LPG-cylinders, but 120-day retention would require a number of cylinders to be added to operating fleets. This would be costly and may be impossible to procure an adequate fleet to manage 120-day samples. [EPA-HQ-OAR-2018-0227-0081-A1, p.2] > TIC Council Americas 2) The proposed sample retention time of 120 days (Part 1090.1345) will increase the financial burden on all testing laboratories, with no demonstrable added value. An average increase of 30 days retention across the industry would result in thousands of additional samples remaining on premises, increasing both laboratory and client liabilities. Many laboratories do not have the real estate that would be required to expand their retain storage capacities. Further, the expense associated with such an expansion would be absorbed exclusively by the laboratories themselves, in direct conflict with the cost savings intention outlined in the EPA's streamlining efforts. While 252 ------- monies may be saved in one area of the industry, this additional requirement would impose excessive costs unfairly on another. On a related note, any retention period should originate from the sample COLLECTION DATE and not on the analysis completion date. Any additional testing requests on a sample would unpractically and illogically extend the retention period. [EPA-HQ-OAR-2018-0227-0039-A1, p.2] > Turner, Mason & Company (TM&C) Subpart M - Sampling. Testing, and Retention Retention requirements of Blendstocks In 1090.1345(a), EPA incorporates sample retention provisions for regulated blendstock producers. This would place sample retention requirements on the certified butane producer where the current regulation does not. As the agency is aware, butane samples are collected in pressurized cylinders. The valving mechanism on the pressurized cylinders historically have been known to fail over time, allowing the contents to be expelled. Retaining pressurized samples for any duration of time does present a hazard to the health and safety of the facility. We do not believe this was the intent of the agency and would provide the following for clarification. (a) Fuel manufacturers, regulated blendstock producers (excluding certified butane and certified pentane). and independent surveyors must retain samples of fuel and oxygenate tested under this subpart as follows. [EPA-HQ-OAR-2018-0227-0045-A1, pp.5-6] Response: We are finalizing a 90-day sample retention period for gasoline blending manufacturers in response to commenters' concerns that the proposed 120-day sample retention period is too long and would result in added burden. Several commenters noted that a 90-day period is consistent with customary business practice by laboratories and many fuel manufacturers. Consequently, we believe that a 90-day retention period would not result in a substantial increase in burden for blending manufacturers. As discussed in Section IX.B.3 of the preamble, we continue to believe that a longer retention period for blending manufacturers is necessary. We also do not believe that this should only apply to blending manufacturers that supply fuel directly to end users. We do not see any reason to treat these blending manufacturers differently and the commenter does not provide a reason why we should do so. Regarding regulated blendstocks, due to the difficulty and expense of storing certified butane, we are no longer requiring that certified butane samples be retained. However, we are requiring that samples of certified butane collected for quality assurance testing under §1090.1320(c) (4) be retained until the quality assurance testing is completed. We believe that samples of certified pentane, which is liquid at room temperature, must still be retained and are therefore requiring that certified pentane samples be retained. As suggested by some commenters, the retention period for samples collected by certified pentane producers is 30 days. 253 ------- Sample retention periods begin after the sample has been tested, not when the sample is collected as some commenters suggested. We believe that allowing the retention period to begin at the time the sample is collected could allow for parties to delay testing of certain parameters past the retention period and undermine the purpose of requiring a retained sample, which is to verify the testing of a product should an issue arise downstream. We have revised §1090.1345(a) (5) (i) to reflect our intent stated in the NPRM that, for hand blends, gasoline manufacturers must keep a sample of the BOB and a representative sample of the oxygenate. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: 1090.1335(b) (4) ... homogeneity does not apply in the following cases: (i) There is only a single sample using the procedures specified in paragraph (b) (1) of this section. (ii) Upright cylindrical tanks that have a liquid depth (from the tank outlet) less than 10 feet. ... Comment: Remove the (b) (4) (ii) requirement - it is at best redundant but is arguably conflicting with D4057. (b)(1) appropriately requires using D4057 Table 5 to adjust the number of spot samples to pull on vertical cylinder tanks, indicating that in a case where the liquid level is 10' or less (unqualified with regards to outlet level) only one sample is to be pulled. Adding the exception in (b) (4) (ii) that homogeneity does not apply if the "liquid depth (from the tank outlet) [is] less than 10 feet" is unnecessary and could be confusing. For instance, a tank that uses floating suction has a variable "tank outlet" with regard to its depth in the tank cylinder, but it is often less than 10' below the top of the liquid level even on a completely full tank. Another example would be a tank that has a fixed tank outlet at 3 feet. If the liquid level is 12 feet, then Table 5 says to pull two samples; however, (b) (4) (ii) would seem to indicate that homogeneity checking is not required (i.e. the liquid depth is only 9 feet above the outlet), resulting in a situation where two samples have been pulled, but no homogeneity check is required. [EPA-HQ-OAR-2018- 0227-0074-A1, p.41] > bp America Inc. (bp) §1090.1335 Collecting and preparing samples for testing §1090.1335(b) (1) states "If you test more than one sample for a given parameter, calculate the arithmetic average of the test results to represent the batch and use the test average result for 254 ------- determining compliance with the standards under this part." In section §1090.1335(d) (2), it states "If you measure RVP for multiple test samples to demonstrate compliance, do not calculate an average result." These statements appear to conflict with each other. We request that EPA clarify how to calculate results from multiple samples, such as upper, middle, lower tank samples. > Flint Hills Resources 7) Part 1090 subpart M - §1090.1335(b)(4)(ii) Homogeneity Suggestion: Remove the (b) (4) (ii) requirement. Discussion: §1090.1335(b)(1) says: (b) (1) ... Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057 as applicable. ... [Table 1 is for horizontal cylindrical tanks, and Table 2 is for vertical/upright cylindrical tanks.] §1090.1335(b)(4) says: (b) (4) ... homogeneity does not apply in the following cases: (i) There is only a single sample using the procedures specified in paragraph (b) (1) of this section. (ii) Upright cylindrical tanks that have a liquid depth {from the tank outlet) less than 10 feet. ... [emphasis added] §1090.1335(b) (1) appropriately requires using D4057 Table 5 to adjust the number of spot samples to pull from vertical cylinder tanks, indicating that in a case where the liquid level is 10' or less (unqualified with regards to outlet level) only one sample is to be pulled. As indicated in (b) (4) (i), when a single sample is pulled, homogeneity does not apply. However, adding the exception in (b) (4) (ii) that homogeneity is not applicable when "liquid depth (from the tank outlet) [is] less than 10 feet" is unnecessary and could be confusing. For instance, a tank that uses floating suction has a variable "tank outlet" with regard to its depth in the tank cylinder, but it is often less than 10' below the top of the liquid level even on a completely full tank. Another example would be a tank that has a fixed tank outlet at 3 feet. If the liquid level is 12 feet, then Table 5 says to pull two samples; however, (b) (4) (ii) would seem to indicate that homogeneity checking is not required (i.e. the liquid depth is only 9 feet above the outlet), resulting in a situation where two samples have been pulled, but no homogeneity check is required. By removing (b) (4) (ii), D4057's Table 5 would clearly indicate when a single sample should be pulled, and in such a case (b) (4) (i) would indicate that homogeneity does not apply. [EPA-HO- OAR-2018-0227-0052-A1, pg.5] 255 ------- > Phillips 66 Company Handling and Preparing of Samples We find the language in §1090.1335 to be confusing. The language in §1090.1335(b) (4) provides an option where tank homogeneity does not have to be demonstrated. According to this section, a fuel manufacturer can test the upper, middle and lower samples for all properties (RVP, sulfur and benzene) and report the highest value. This provision is clear. However, in (b) (1), it states "If you test more than one sample for a given fuel parameter, calculate the arithmetic average of the test results to represent the batch and use the average result for determining compliance with the standards under this part". We think the clarity of Section 1090.1335 could be improved with some changes in order and language. Following is our suggestion for revisions to this section. (b) Manual sampling. Perform manual sampling using one of the methods specified in ASTM D4057 (incorporated by reference in § 1090.95) as follows: (1) Use tap sampling or spot sampling to collect upper, middle, and lower samples. Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057 as applicable. For tap sampling, collect samples that most closely match the recommendations in Table 5 of ASTM D4057. If you test more than one sample for a given fuel parameter, calculate the arithmetic average of the test results to represent the batch and use the average result for determining compliance with the standards under this part. Each measured sample must meet all applicable per gallon standards. If you test only one sample for a given parameter, you must use that test result to represent the batch. You may not use the results from a composite sample to determine compliance with the standards under this part. (2) Collect a "running'' or "all-levels'' sample from the top of the tank. Drawing a sample from a standpipe is acceptable only if it is slotted or perforated to ensure that the drawn sample properly represents the whole batch of fuel. (3) If the procedures in paragraphs (b)(1) and (2) of this section are impractical for a given storage configuration, you may use alternative sampling procedures as specified in ASTM D4057. This applies primarily for sampling with trucks, railcars, retail stations, and other downstream locations. (c) Testing of Manual Samples (1) Test results with manual sampling are valid only after you demonstrate homogeneity as specified in § 1090.1337, except that the homogeneity testing requirement does not apply in the following cases: (i) There is only a single sample using the procedures specified in paragraph (b)-(4)-(2) of this section. 256 ------- (ii) Upright cylindrical tanks that have a liquid depth (from the tank outlet) less than 10 feet. (iii) You draw spot or tap samples as specified in paragraph (b) (1) of this section and test each sample for every parameter subject to a testing requirement and use the worst-case test result for each parameter for purposes of reporting, meeting per-gallon and average standards, and all other aspects of compliance. (iv) Sampling at a downstream location where it is not possible to collect separate samples and you take steps to ensure that the batch is well mixed. (2) The upper, middle, lower samples used to demonstrate homogeneity may be used for batch reporting purposes. Homogeneity demonstration requires testing of two separate fuel properties. i. For fuel properties tested on all 3 samples, average the results to represent the batch and use the average result for determining compliance with the standards. ii. To test for the remaining properties (the ones not tested as part of the homogeneity demonstration), the fuel manufacturer can use any of the samples (upper, middle, or lower) or may pull another single sample from any location to do the remaining testing. [EPA-HQ-OAR- 2018-0227-0060-Al.pp.4-6] Response: We have revised the regulations to clarify situations where multiple samples are collected to demonstrate homogeneity. As revised, if a batch is determined to be homogeneous, parties may use one of the homogeneity samples to test for remaining properties. For parameters that were measured for homogeneity samples, gasoline manufacturers must report the average of the samples in annual batch reports. For sulfur and summer RVP per-gallon compliance, gasoline manufacturers must meet the applicable per-gallon standards for all homogeneity samples and report the highest test result across the homogeneity samples in annual batch reports. We believe this approach provides the most robust demonstration that fuels meet EPA's fuel quality standards while allowing parties flexibilities to minimize sampling and testing burden. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Preamble Language or Regulatory Language: 1090.1340(c) If you produce or import BOB and you blend in oxygenate before selling or transporting the fuel, you must instead draw samples from your blended fuel. Comment: 257 ------- Theoretically, oxygenate/ethanol is blended into BOBs at load racks prior to the sale transaction occurring (typically the flange of the truck), so this language reads as though the requirement is to sample after blending yet before the sale occurs, which is not possible. [EPA-HQ-OAR-2018- 0227-0074-A1, p.41] Suggest re-wording to clarify the intent: "If you produce or import BOB and you blend in oxygenate before selling or transporting the fuel (other than blending that occurs at the load rack immediately prior to title or custody transfer), you must instead draw samples from your blended fuel." [EPA-HQ-OAR-2018-0227-0074-Al,p.41] > Marathon Petroleum Company LP (MPC) Preparing a Hand Blend From BOB 1090.1340(c) If you produce or import BOB and you blend in oxygenate before selling or transporting the fuel, you must instead draw samples from your blended fuel. Theoretically, oxygenate/ethanol is blended into BOBs at load racks prior to the sale transaction occurring (typically the flange of the truck). The proposed language of the rule reads as though the requirement is to sample after blending, yet before the sale occurs, which is not possible. MPC suggests re-wording this to clarify the intent: "If you produce or import BOB and you blend in oxygenate before selling or transporting the fuel (other than blending that occurs at the load rack immediately prior to title or custody transfer), you must instead draw samples from your blended fuel." [EPA-HQ-OAR-2018-0227-0048-A2, p.2] Response: We have removed §1090.1340(c). This paragraph does not add value since gasoline that is blended with oxygenate before sale or transport is not BOB. Comment: > bp America Inc. (bp) §1090.1335 Collecting and preparing samples for testing bp recommends that after a tank is tested and proven to be homogenous in accordance with §1090.1337, the EPA batch certification samples should be permitted to be taken from one side tap. We believe that once a tank is demonstrated to be homogeneous under that provision, subsequent samples taken from the tank will be representative of the entire batch. This would reduce the number of sample bottles the operator needs to carry from the top of the tank making that operation more safe. It is recommended that §1090.1335(b) (5) be added to and state "After a tank meets the homogeneity requirements in §1090.1337, then a single side tap sample can be used to certify the tank." [EPA-HQ-OAR-2018-0227-0046-A1, pp.21-22] 258 ------- Response: We have revised the regulation as the commenter suggested. Comment: > Camin Cargo Control 7. 1090.1335 Collecting and preparing samples for testing a. Manual Sampling 1090.1335 (b)(1) Manual Sampling directs the sampler to perform TAP samplings of UML levels and to do a mathematical average but also says IF you test only one sample, use that test result to represent the batch. This is both contradictory and incorrect, and we advise not offering the 'one sample option,' as industry may be inclined to pick the lower strata for RVP testing, typically not representative of the material. [EPA-HQ-OAR-2018-0227-0030-A1, pp.6-7] > CITGO Petroleum Corporation (CITGO) 2.6 Collecting and Preparing Samples for Testing According to the preamble, EPA is transferring the sampling procedures and homogeneity demonstration requirement of fuel samples that are currently specified in 40 CFR part 80 and adding numerous minor clarifications and adjustments to the regulatory text based on previous guidance through the years. CITGO supports EPA's efforts to reflect current sampling practices and offers some additional clarifying language as follows: In §1090.1335, samples of the upper, middle, and lower levels of a tank are tested for homogeneity criteria as specified in §1090.1337. Once determined, fuel manufacturers using tap sampling or spot sampling must calculate the arithmetic average of the test results to represent the batch and use the average result for determining compliance with the regulatory standards when multiple samples are tested. EPA further clarifies that each measured sample must meet all applicable per-gallon standards. Alternatively, fuel manufacturers that only test one sample for a given parameter must use that test result to represent the batch. This language implies but does not explicitly specify that once homogeneity is determined, the fuel manufacturer is allowed to choose a single sample from the upper, middle, and lower samples already secured, and perform testing for the remaining regulatory parameters and subsequent batch representation and for determining compliance. Additional clarity is needed to explicitly specify this allowance. Recommended language is as follow: §1090.1335(b) (1) - Use tap sampling or spot sampling to collect upper, middle, and lower samples. Adjust spot sampling for partially filled tanks as shown in Table 1 or Table 5 of ASTM D4057, as applicable. For tap sampling, collect samples that most closely match the recommendations in Table 5 of ASTM D4057. If you test more than one sample for a given fuel 259 ------- parameter, calculate the arithmetic average of the test results to represent the batch and use the average result for determining compliance with the standards under this part. Each measured sample must meet all applicable per-gallon standards. Alternatively, fuel manufacturers may select a single sample from the upper, middle, and lower samples secured and perform testing for the remaining regulatory parameters and subsequent batch representation. If you test only one sample for a given parameter, you must use that test result to represent the batch and for determining compliance. You may not use the results from a composite sample to determine compliance with the standards under this part. [EPA-HQ-OAR-2018-0227-0054-A1, p.10] > TIC Council Americas Subpart M - Sampling. Testing, and Retention Requirements 1. 1090.1340 Collecting and preparing fuel samples for testing a. Item (b) (1) Manual Sampling directs the sampler to perform TAP samplings of UML levels and do a mathematical average OR ('Otherwise') just use a single test result to represent the batch. We believe this is incorrect, and advise not offering the option to 'pick one'; the liquid level should determine from which taps to sample (as per ASTM D4057). As per Industry practices TAP samples -unless the only ones possible- are not acceptable for Custody Transfer and contractual Quality determination therefore will conflict with stakeholders sampling/operating instructions and create an unnecessary burden for services provided to multiple parties. [EPA-HQ-OAR-2018-0227-0039-A2, pg.3] Response: §1090.1340(b) (1) is written to reflect the fact that homogeneity testing involves measuring one or more fuel parameters from multiple samples, and that only a single sample needs be tested for other fuel parameters once homogeneity is established. We have revised the regulation to clarify this point. Regarding RVP in the summer, we have revised the regulations to clarify that if multiple samples are taken to demonstrate homogeneity, all samples must meet the applicable maximum RVP per- gallon standard and the highest RVP value must be reported to EPA in annual batch reports. We believe that this addresses commenters' concerns about selecting a sample from multiple samples that are likely to have the lowest RVP levels. We have further revised the regulation to allow tap sampling only if running samples, all-levels samples, and spot samples are impractical for a given batch. Comment: > Camin Cargo Control 7. 1090.1335 Collecting and preparing samples for testing 260 ------- b. Automatic Sampling 1090.1335 (c) Automatic Sampling does not have a homogeneity requirement (1090.1337) as required for Manual Sampling 1090.1335 (b)(4). With the current market dynamics and component blending on large storage facilities, it is possible (and has happened) to have a shore tank holding stratified product which is later pumped to other smaller tanks or barges/ships. If the sample obtained is from the automatic sampling option (c), the resulting sample would be representative only of the product that passed through the auto-sampler. The product on the receiving tanks or compartments would not be a homogeneous mix of the certified source product in the tank unless the entire tank is emptied and all of the product is evenly transferred / loaded onto the target container (tank or vessel compartments). Considering the guidance provided in Part 80, our experience coupled with past guidance by EPA on the subject where the need to have test results in hand before shipping was emphasized, we suggest EPA add a requirement to demonstrate homogeneity for samples collected via automatic sampling. [EPA-HQ-OAR-2018-0227-0030-A1, pg.7] Response: We have revised the regulation as the commenter suggested. Comment: > Camin Cargo Control 7. 1090.1335 Collecting and preparing samples for testing c. Sample Preparation for BOB Testing 1090.1340 (a) and (a)(1) describes the process to create a hand-blend and is unclear because it uses the 'worst-case for oxygenate' sample scenario by giving recommendations to the selection of a mid-range sulfur if 'three,' or just 'randomly' select the sample. We suggest swapping the order on item (1) 'take steps to avoid..' and (2) 'If your instructions, to keep the focus on the 'oxygenate worstcase' and then referring to the sulfur. [EPA-HQ-OAR- 2018-0227-0030-A1, pg.7] > TIC Council Americas Subpart M - Sampling. Testing, and Retention Requirements 3. 1090.1342 Sample Preparation for BOB Testing 261 ------- i. In (a) and (a)(1) the text describing the process to test a hand-blend is unclear because it uses the 'worst-case' sample scenario by referring to the worst sulfur of the BOB samples but hand- blends are prepared from a representative sample that usually is a running, all-levels (of a tank) or a volumetric composite of the Upper-Middle-Lower samples so you have only one sulfur result. ii. In (a) where it says 'meet sampling requirements' should be 'testing requirements'. [EPA-HQ- OAR-2018-0227-0039-A2, pg.3] Response: We have revised the regulation to refer to "testing requirements." The comment about worst-case testing is based on a preliminary draft that was changed before publishing the proposed rule. The proposed rule describes how selecting from multiple sample must be done in a way that avoids introducing high or low bias in sulfur content. Comment: > Camin Cargo Control I realized we missed the opportunity to ask and confirm whether the determination of the compartments homogeneity should be performed using the volumetric adjusted concentration for each selected parameter (RVP, API, Sulfur, Benzene) or if it should simply use the straight mathematical average as in .1337. Section 1090.1337(e) states that for those parameters whose repeatability depend on measured values (i.e. concentration) the average should be used, but unlike upright cylindrical shore tanks where all strata have the same volume, marine vessel compartments are odd shaped and may not have similar volumes and the repeatability determination and the homogeneity establishment would necessarily be influenced by actual volumes. Also note that often and due to operational needs (stability, partial discharges), the compartment volumes may vary. We interpret that the mention of a ' volume-weight composite sample' in section .1605 is both for the determination of properties and to meet the applicable standards including 1090.1337 (homogeneity). Would you be at liberty to confirm this assertion, or at least clarify this point in the final published CRF? [EPA-HQ-OAR-2018-0227-0088-A1, pg.l] Response: We have revised the proposed language at §1090.1605 to clarify that a volume-weighted composite sample that represents fuel in the various marine vessel compartments may be used for batch certification if the vessel compartments are determined to be homogeneous using samples collected from each vessel compartment. The fact that vessel compartments contain different volumes of fuel is not relevant for determining homogeneity of the fuel across compartments. The homogeneity demonstration is designed to ensure that the fuel in the different 262 ------- vessel compartments has consistent properties for purposes of certifying a batch of fuel. Similarly, calculating the homogeneity criterion from the reproducibility that applies for a given test method should be based on measured values for each test, without adjustment for the fuel volume in the compartment corresponding to each sample. Comment: > Eversheds Sutherland (US) LLP Gasoline and Diesel Sampling and Testing The Proposed Rule directs that manual sampling must use one of the methods specified in ASTM D4057 and details acceptable procedures.42 While the Proposed Rule adopts some of the tank sampling procedures that are currently set forth in guidance and used widely and for a long period of time, but there are no references to EPA having a preference for "running" or "all- levels" samples or that a sample can be collected from a truck or barge, although it is "marginally acceptable."43 Such guidance has been invaluable, and we request that EPA at the least incorporate the guidance language into the final rule preamble if it does not adopt more of the language in its final rule. Under "Demonstrating homogeneity," §1090.1337(b) should reference §1090.1335(b)(1) or (2) to allow for a running or all-levels sample. [EPA-HQ-OAR-2018-0227-0076-A1, p.13] 42 Proposed Rule at § 1090.1337. 43 See EPA, How Should Storage Tanks Be Sampled?, https://www.epa.gov/fuels-registration-reporting-and- compliancehelp/how-should-storage-tanks-be-sampled-rfg. > TIC Council Americas Subpart M - Sampling, Testing, and Retention Requirements 1. 1090.1340 Collecting and preparing fuel samples for testing b. Item (b)(2) Manual Sampling i. Indicates performing TAP sampling is first option then 'running' or 'all levels'. This technique is in disagreement with ASTM D4057 where the preferred sampling method is from top of the tank via open hatch, secondarily via slotted standpipes using an 'all level' or 'running' and lastly using SPOT samples if it's not possible to obtain samples from the top of the tank. Tap samples are stated as the least representative of the product inside the tank. [EPA-HQ-OAR-2018-0227- 0039-A2, pg.3] 263 ------- Response: We have revised the regulation to identify preferred sampling techniques, consistent with ASTM D4057 as suggested by commenters. Comment: > Phillips 66 Company Demonstrating Homogeneity The proposed rule also contains language that requires fuel manufacturers to demonstrate homogeneity on diesel tanks. Refinery diesel batches are produced through blending of fewer components versus gasoline batches and, in general, the components do not vary as widely in gravity, distillation, etc. as gasoline components. Therefore, the tanks are much less prone to stratification. Also, diesel is subject to a per gallon sulfur specification and downstream testing and enforcement has not shown any issues. We ask EPA to consider removing the requirement to demonstrate diesel tank homogeneity as it is appears to be unnecessary and will add to the sampling and testing time and burden. [EPA-HQ-OAR-2018-0227-0060-A1, pg.4] Response: Part 1090 includes two related changes to reduce homogeneity testing for diesel fuel. First, testing for API gravity is no longer required, which allows manufacturers to demonstrate homogeneity by measuring sulfur levels from collected samples. These same tests are used for demonstrating compliance with standards. Second, the homogeneity demonstration is not required if all tested samples meet the standards. 264 ------- 15.3. Measurement Procedures Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.17 Testing: Overview of Testing Procedures Section 1090.1350(c) (3) (iii) states that a published procedure is considered non-voluntary consensus standards body ("VCSB") for testing with fuel parameters that fall outside the range of values covered in the research report of the ASTM D6708 candidate and referee method comparisons. The Associations request that EPA also consider allowing alternative spectroscopic methods that conform to statistically sound correlations per D6122 Standard Practice for Validation of the Performance of Multivariate Online, At- Line, and Laboratory Infrared Spectrophotometer Based Analyzer Systems. This approach allows for more streamlined testing practices in the future. The general validation step is consistent with D6708, and the local validation emphasizes local performance against the primary test method. In §1090.1350(d), EPA proposes that, "for any measurements or calculations that depend on the volume of the test sample, correct the volume of the sample to a reference temperature of 15.5 °C (288.65 K). Use a correction equation that is appropriate for each tested compound. This applies for all fuels, blendstocks, and additives, except butane."24 [EPA-HQ-OAR-2018-0227-0074-A1, p.25] Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1360(c)(3) (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. Comment: Does everything have to be shown as equivalent by ASTM D6708 for an alternate method? What about spectroscopy and the Local Validation in D6122? Companies can correlate to properties, such as aromatics in diesel and benzene in gasoline by spectroscopy, so can they show agreement by the Local Validation in D6122 which is a scientifically sound practice? This is going to be big for refiners, especially when the industry eventually gets the newly proposed ASTM standard practice for Performance-Based Qualification of Spectroscopic Analyzers (currently still under development) approved by ASTM. In my opinion, it is expected that the majority of the industry are likely to use the Local Validation of D6122 when it comes to the spectroscopic methods instead of D6708. [EPA-HQ-OAR-2018-0227-0074-A1, p.41] 265 ------- 24 See 85 Fed. Reg. 29143. > Marathon Petroleum Company LP (MPC) Performance-based Measurement System 1090.1360(c) (3) (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. MPC suggests that for spectroscopy the local validation in ASTM D6122 would be an appropriate assessment. Companies can correlate to properties, such as aromatics in diesel and benzene in gasoline by spectroscopy, so can they show agreement by the local validation in D6122, which is a scientifically sound practice. Once the newly proposed ASTM standard practice for Performance-Based Qualification of Spectroscopic Analyzers (currently still under development) is approved by ASTM, it is expected that the majority of the refining industry is likely to use the local validation of D6122 when it comes to the spectroscopic methods instead of D6708. [EPA-HQ-OAR-2018-0227-0048-A2, p.2] Response: 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. Such a procedure may qualify as an alternative procedure using the protocol that applies for non-VCSB procedures. The proposed rule did not specify ASTM D6122 as a procedure for online system measurement. We continue to have concerns over how well online analyzers will correlate to laboratory bench test methods. We did not propose to allow for online analyzers and are not finalizing allowing them, as we believe more work needs to be done to determine how to correlate the methods to bench test methods. We may consider that in an appropriate future rulemaking. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.17 Testing: Overview of Testing Procedures The Associations also suggest a solution to the proposal in §1090.1350(d). If the text refers to the execution of a designated ASTM test method, then any required procedural corrections (such as for temperature) would already be defined in the test method. If a correction is applied after application of the test method, then it would be considered to be a change in the method (like a bias correction) that would have to be vetted and approved through the established voting procedures of the VCSB, otherwise it would be invalid or a non-VCSB method. The Associations believe this is inappropriate, that the methods should say how to do volume 266 ------- correction if it is necessary for the method and suggest EPA strike (d). [EPA-HQ-OAR-2018- 0227-0074-A1, p.25] Response: The proposed requirement to correct measured values to standard conditions of 60 °F or 15.56 °C has been standard industry practice for complying with EPA testing requirements for over 20 years. If a given test method includes a correction equation, the proposed correction instructions in §1090.1350(d) would require the use of that correction equation. It would not be appropriate to change these well-established corrections, as this may result in inconsistent measurement and reporting of fuel parameters to EPA. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters Issue: 1090.1350(b) Specific test procedures apply for (3) Measure the purity of butane and pentane as reference in §1090.95). Comment: D2163 employs liquid sample valve for cylinder samples. This is a good choice for butane, but pentane might not be sampled in cylinder. A method such as D5134 or D6729 may be more appropriate. Streamlining composition and benzene content measurements utilizing the same method (such as D5134) may be a benefit to the user. [EPA-HQ-OAR-2018-0227-0074-A1, P-28] > Valero Energy Corporation H. Sampling. Testing and Retention Provisions 2. Test Procedures In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the following: (b) Specific test procedures apply for measuring other fuel parameters, as follows: measuring other fuel parameters, as follows: specified in ASTM D2163 (incorporated by 267 ------- (3) Measure the purity of butane and pentane as specified in ASTM D2163 (incorporated by reference in §1090.95). Valero requests that EPA correct the rule to address several errors. Pentane is beyond the scope of D2163; EPA must remove pentane in (b) (3). Response: We have revised §1090.1350(b) (3) to include ASTM D5134 for pentane purity measurement. ASTM D2163 remains the test method for butane purity measurement. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters Issue: 1090.1350(b) (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 (incorporated by reference in §1090.95). Comment: Butane testing can be simplified by allowing D2163 for both purity and benzene content of butane. D5134 does not cover analysis of LPG (see D5134 note 2) and lacks guidance to conversion to vol%. Discussion: D2163 measures LPG composition in vol%. and allows speciation of >C5+ per section 12.2. Response factors in D2163 were taken from D6729 and converted to volume basis relative to n-butane. A benzene mass response factor of 0.812 per D6729 corresponds to a theoretical relative volume response factor (RVRF) of 0.592 relative to butane (assuming density of 0.8845 per D5769.) Guidance on calculation of the RVRF is provided in D2163 XI.1. [EPA- HQ-OAR-2018-0227-0074-A1, p.28] > Buckeye Partners, L.P. §1090.1350 Overview of test procedures. Comment #6 - Section (b)(4) - Test procedures for benzene content of butane should include ASTM D2163. This method is the current industry standard, and is readily available and has been successfully utilized for years. D5134 is not readily available in all locations. In order to align with EPA's goal of Streamlining the efficiency of fuel production and transportation, and because benzene concentration in butane is not typically a compliance concern, Buckeye 268 ------- respectfully requests that ASTM D2163 be added as an allowable method for benzene testing in certified butane: (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 or ASTM D2163 (incorporated by reference in §1090.95). [EPA-HQ-OAR-2018-0227-0032-A1, p.3] > Magellan Midstream Partners §1090.1350 Overview of test procedures Section (b) (3) (4) - Benzene content of butane - EPA has identified an accepted test method for benzene in butane. A butane blender that is sampling and testing every batch of its butane that it receives should be able to generate credits. For purposes of the benzene rule, such blenders are not benefitting from any streamlined provisions relative to other refiners. Regarding the accepted test method D5134, we recommend additionally allowing the use of D6730 and D2163 test methods for measuring benzene in butane as these methods are the most contemporary and allow the use of hydrogen as a carrier gas. " (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 (incorporated by reference in §1090.95), ASTM D6730. and ASTM D2163." Additionally, D2163 is used to demonstrate butane purity, therefore, it would allow the producer to avoid duplicative testing. [EPA-HQ-OAR-2018-0227-0078-A1, p.9] > Marathon Petroleum Company LP (MPC) Overview of Test Procedures 1090.1350(b) (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 (incorporated by reference in §1090.95). ASTM D2163 is already being utilized to determine butane purity and is also an acceptable method for measuring benzene content in butane. In order to avoid duplicate testing, it should be allowed in addition to ASTM D5134. > Texon L.P. II. Sampling, Testing and Retention, §1090.1350 (b)(4) Please consider D2163 adequate for benzene testing in butane as most U.S. labs are not equipped to run D5134 for benzene testing in butane. D5134 is capable of measuring many components found in a hydrocarbon mixture, but it is our belief a DHA at this detail is unnecessary for a refined product like normal (certified) butane. Laboratory chemists confirm gas chromatography by D2163 is effective for measuring benzene as a component in liquefied petroleum gases. Additionally, D5134 takes two hours to complete, whereas widely recognized, alternate benzene 269 ------- testing method, GPA2186, takes 40 minutes and is specific to measuring benzene components in light-end hydrocarbons. [EPA-HQ-OAR-2018-0227-0081-A1, p.2] > Turner, Mason & Company (TM&C) Subpart M - Sampling. Testing, and Retention Butane Benzene Reference Method In 1090.1350(b) (4), the benzene content of butane is required to be measured by D5134 (incorporated by reference in 1090.95). In 1090.1350(b)(3) the purity of the benzene is measured by D2163. According to the text of the method, D5134 does not cover analysis of LPG. In addition, there is no guidance incorporated into the method on the conversion to vol%. Over the years, TM&C has reviewed hundreds of certificates of analysis on butane and do not recall observing D5134 being used to measure benzene. The current industry practice, based on our experience, has been the measurement of benzene by D2163. The proposed change would result in a significant investment by laboratories having to purchase the new analytical method D5163. We recommend the method D5134 be replaced by the method D2163 for the measurement of benzene. (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 D2163 (incorporated by reference in §1090.95). [EPA-HQ-OAR-2018-0227-0045-A1, p.6] > Valero Energy Corporation 2. Test Procedures In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the following: (b) Specific test procedures apply for measuring other fuel parameters, as follows: (4) Measure the benzene content of butane and pentane as specified in ASTM D5134 (incorporated by reference in §1090.95). Valero requests that EPA correct the rule to address several errors. Butane testing is beyond the scope of this test method. EPA must remove butane from (b) (4). Response: We have revised §1090.1350(b) (3) to include ASTM D5134 for pentane purity measurement. ASTM D2163 remains the test method for butane purity measurement. We have also revised §1090.1350(b) (4) to include ASTM D2163, ASTM D6729, and ASTM D6730 for measuring benzene in butane and pentane in addition to ASTM D5134. 270 ------- Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters Issue: 1090.1350(b) (5) Measure the sulfur content of pentane as specified in ASTM D6667 (incorporated by reference in §1090.95). Comment: D6667 is for LPG samples which readily volatilize in the gas box. Recommend allowing D5453, which is a similar analysis method with liquid injector rather than an LPG/gas box. Even if the sample is collected in a cylinder, it can be transferred to a sample vial for this test. D5453 has better precision. [EPA-HQ-OAR-2018-0227-0074-A1, p.28] > Marathon Petroleum Company LP (MPC) Overview of Test Procedures 1090.1350(b) (5) Measure the sulfur content of pentane as specified in ASTM D6667 (incorporated by reference in §1090.95). The sulfur content of pentane should be measured by ASTM D5453, not ASTM D6667. > Valero Energy Corporation 2. Test Procedures In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the following: (b) Specific test procedures apply for measuring other fuel parameters, as follows: (5) Measure the sulfur content of pentane as specified in ASTM D6667 (incorporated by reference in §1090.95). Valero requests that EPA correct the rule to address several errors. ASTM D6667 is for LPGs, not pentane; EPA should delete (b)(5). Response: We have revised §1090.1350(b) (5) to add ASTM D5453 for sulfur in pentane measurement and remove ASTM D6667. 271 ------- Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 1 - Specific Test Procedures for Measuring Other Fuel Parameters Issue: 1090.1350(b) (7) Measure the sulfur content of neat ethanol as specified in ASTM D5453 (incorporated by reference in §1090.95). You may use an alternative procedure if you correlate your test results with ASTM D5453. Comment: Does this require a D6708 correlation? Such a correlation for ethanol is not published, and this effort would be burdensome on the industry. [EPA-HQ-OAR-2018-0227-0074-A1, p.28] > Valero Energy Corporation 2. Test Procedures In proposed subpart M § 1090.1350(b) 3 through 7 — Test Procedures, EPA requires the following: (b) Specific test procedures apply for measuring other fuel parameters, as follows: (7) Measure the sulfur content of neat ethanol as specified in ASTM D5453 (incorporated by reference in §1090.95). You may use an alternative procedure if you correlate your test results with ASTM D5453. Valero requests that EPA correct the rule to address several errors. ASTM D5453 is for hydrocarbons, not alcohols; EPA should delete (b)(7). Response: We specified the use of ASTM D5453 for measuring sulfur in neat ethanol at §1090.1350(b) (7). Alternative test methods may be used if adequately correlated to ASTM D5453. The correlation for sulfur in neat ethanol does not require a D6708 assessment. We have accordingly revised the regulation to require an "adequate" correlation. 272 ------- Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: "We are proposing to change the designated referee procedure for measuring benzene in gasoline from ASTM D3606 to ASTM D5769." Comment: Do not change the referee test method for benzene in gasoline. [EPA-HQ-OAR-2018-0227- 0074-A1, p.30] > bp America Inc. (bp) §1090.1360 Performance-based Measurement System. § 1090.1360(c) (5) (ii) states "Qualification testing is not required for laboratories that measure the benzene content of gasoline using Procedure B of ASTM D3606 (incorporated by reference in §1090.95)." bp requests that initial qualification testing also not be required for laboratories that measure the benzene content of gasoline using ASTM D5580. ASTM D5580 is an alternative procedure for measuring benzene in gasoline under part 80, is a CARB approved benzene regulatory method, and is commonly used by laboratories on the West Coast. As EPA stated with regards to ASTM D3606, the performance-based management system quality demonstrations will be sufficient to demonstrate the proper precision and accuracy of ASTM D5580. (85 Fed. Reg. 29069) In addition, ASTM D5580 does not have the ethanol interference that existed in older versions of ASTM D3606. EPA selected ASTM D5769 as the referee for benzene. (§1090.1360(d)) Although a lab could qualify ASTM D5580 by correlating it to ASTM D5769, there is no ASTM correlation equation for correlating ASTM D5580 to ASTM D5769 for benzene. The only correlation equation that currently exists for ASTM D5580 was for ASTM D5580 to ASTM D3606. ASTM is working to develop this correlation, but it is not known when that correlation development will be completed. If that does not occur before the effective date of the Streamlining Rule, many laboratories currently using that method will need to qualify it using a qualification difficult process. bp believes that ASTM D5580 (Standard Test Method for Determination of Benzene, Toluene, Ethylbenzene, p/m-Xylene, o-Xylene, C9 and Heavier Aromatics, and Total Aromatics in Finished Gasoline by Gas Chromatography) is superior to ASTM D5769. 273 ------- • D5580 is a much simpler analytical measurement system than D5769, is less costly to purchase and maintain, and is not subject to interference due to the presence of ethanol. • The scope of D5580 is 0.1 - 5 vol% benzene. The scope of D5769 is 0.1 to 4 vol% benzene. • The precision statements for D5580 show that the repeatability and reproducibility are tighter than those results for D5769. For example, at 0.50 vol% benzene, the repeatability using D5580 is 0.016 vol% whereas D5769 is 0.029 vol%. For the same level of benzene, the reproducibility using D5580 is 0.070 vol% and D5769 of 0.139 vol%. • Many labs have already qualified and are using ASTM D5580. In the March 2020 ASTM Interlaboratory Crosscheck Program (ILCP) for RFG-2003, 43 participating labs including USEPA lab reported benzene results using D5580. (118 labs reported D3606 Proc B results and 61 labs reported GCMS D5769 results.) In the December 2019 ASTM ILCP for MG-1912, 54 labs including a USEPA lab reported benzene results using D5580. (59 labs reported D3606 Proc B, and 12 labs reported D5769.) [EPA-HQ-OAR- 2018-0227-0046-A1, pp.23-24] > Flint Hills Resources 9) Part 1090 subpart M - §1090.1065(d) and preamble IX.C.3.b. Referee test method for benzene in gasoline Suggestion: Do not change the referee test method for benzene in gasoline. Discussion: EPA is proposing to replace D3606 with D5769 as the referee test method for benzene in gasoline. EPA states in the preamble that this change is driven by the fact that "ASTM D3606 has interference effects from ethanol that require careful work to adjust for that interference." This is not a strong case for abandoning D3606. Industry can successfully execute D3606, despite its limitations, and there are already correlations in place that allow use of alternate test methods under the PBMS scheme. Switching the referee test method is unnecessary and will cause undesirable secondorder effects (e.g. establishing new correlations so industry can continue using methods already correlated to D3606, and refinery staff would need to learn to run and maintain the relatively complex D5769 test method). [EPA-HQ-OAR-2018-0227-0052- Al, p.6] > TIC Council Americas 5. 1090.1352 Performance-Based Measurement System a. Item (c) (5) (ii) states that qualification testing is not required for laboratories utilizing Procedure B of ASTM D3606. That said, with the designation of D5769 as the referee method for Benzene determination, the non-existence of a published correlation between D3606 and D5769 may lead to demonstrable differences in results obligating laboratories currently equipped with D3606 to analyze via D5769 causing undue burden on the industry. Additionally, as correlation equations have already been established for alternative methods for Benzene determination against D3606, we recommend retaining D3606 as a designated (referee) method for Benzene determination. 274 ------- b. Item (c) (5) (ii) also defines that ASTM D1319-15 is exempt from the requirement of qualification as an alternate method. It should be noted that the dyed gel formulation referenced in this method is no longer being manufactured and therefore not commercially available. If/when a new dyed gel formulation is introduced, it would represent a deviation from the method adopted for this regulation. That said, the current and any future iteration of this method should be removed from the regulation as ASTM D1319 will never be able to satisfy the qualification requirements of an alternate method as defined in 1090.1354. [EPA-HQ-OAR- 2018-0227-0039-A2, p.4] Response: While we appreciate the logistical concerns raised by commenters, we are finalizing that ASTM D5769 be the referee method under part 1090. We have finalized provisions that allow for the continued use of ASTM D3606 that should mitigate most of the burden associated with using the new method. However, we believe that ASTM D5769 is a superior method for several reasons. First, ASTM D5769 does not suffer from matrix effects like ASTM D3606 does when testing gasoline-oxygenate blended fuels, which are predominant in the marketplace today. Second, ASTM D5769 produces three-dimensional data that can confirm the presence of the analyte of interest or an interference. Third, ASTM D5769 is a more reproducible method with respect to benzene as demonstrated by ASTM International's Proficiency Testing Program.22 We note that parties are not required to use ASTM D5769 and that we are aware that ASTM International is in the process of establishing correlation to ASTM D5769 that should allow parties to continue to rely on other commonly used benzene test methods without having to switch to a new method. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Comment: No counterpart to this current rule requirement. Part 80.66(a) states: "All volume measurements required by these regulations shall be temperature adjusted to 60 degrees Fahrenheit." [EPA-HQ- OAR-2018-0227-0074-A1, p.38] > Valero Energy Corporation 2. Volume Adjustment Under the current fuel regulations, 40 C.F.R. §80.66 (a) provides: "All volume measurements required by these regulations shall be temperature adjusted to 60 degrees Fahrenheit." The proposed rules do not include this requirement. Valero believes that this was an oversight by 22 Information regarding ASTM International's Proficiency Testing Program is available at: https://www.astiii.ofg/STATOA. 275 ------- EPA and recommends that EPA add a provision matching §80.66 (a) in the General Requirements of Part 1090. [EPA-HQ-OAR-2018-0227-0056-A1, pp.6-7] Response: We proposed this requirement at §1090.1350(d). In addition to finalizing the requirement for temperature correction at §1090.1350(d) as proposed, we have added clarifying regulatory language to the reporting regulations at §1090.900(a) (2) to note that reported volumes must be temperature corrected as required under §1090.1350(d). Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1360(c) (4) You may qualify updated versions of the referee procedures as alternative procedures under §1090.1365. You may ask EPA for approval to use an updated version of the referee procedure for qualifying other alternative procedures if the updated referee procedure has the same or better accuracy and precision compared to the version specified in §1090.95. If the updated procedure has worse accuracy and precision compared to the earlier version, you must complete the required testing specified in §1090.1365 using the older, referenced version of the referee procedure. 1090.1365(a) (2) Testing to qualify an alternative procedure applies for the specified version of the procedure you use for making the necessary measurements. Once an alternative procedure for a method-defined fuel parameter is qualified for your laboratory, updated versions of that same procedure are qualified without further testing, as long as the procedure's specified reproducibility is the same as or better than the values specified in the earlier version. For absolute fuel parameters, updated versions are qualified without testing if both repeatability and reproducibility are the same as or better than the values specified in the earlier version [EPA- HQ-OAR-2018-0227-0074-A1, pp.42-43] Comment: Clarification is needed. [EPA-HQ-OAR-2018-0227-0074-Al,p.42] o 1090.1360(c) (4) - says "You may qualify updated versions of the referee procedures as alternative procedures under §1090.1365. You may ask EPA for approval to use an updated version of the referee procedure for qualifying other alternative procedures if the updated referee procedure has the same or better accuracy and precision compared to the version specified in §1090.95. If the updated procedure has worse accuracy and precision compared to the earlier 276 ------- version, you must complete the required testing specified in §1090.1365 using the older, referenced version of the referee procedure." o 1090.1365(a) (2) - says "once an alternative procedure for a method-defined fuel parameter is qualified.. .updated versions.. .are qualified without further testing, as long as the procedure's specified reproducibility is the same or better. So, you have to qualify an updated version of a referee method, but then future version updates don't have to be qualified? Need to clarify what they intend to say here. Propose to allow updated versions of referee methods to be used without further testing or approval from EPA ("you may ask EPA....") if they have same/better reproducibility. [EPA-HQ-OAR-2018-0227- 0074-A1, p.42] > Valero Energy Corporation H. Sampling. Testing and Retention Provisions 3. Referee Procedures Proposed subpart M §1090.1360(c) (4) and related/ referenced language in §1090.1365(a) (2) provides the following: • §1090.1360(c)(4) You may qualify updated versions of the referee procedures as alternative procedures under §1090.1365. You may ask EPA for approval to use an updated version of the referee procedure for qualifying other alternative procedures if the updated referee procedure has the same or better accuracy and precision compared to the version specified in §1090.95. If the updated procedure has worse accuracy and precision compared to the earlier version, you must complete the required testing specified in §1090.1365 using the older, referenced version of the referee procedure. • §1090.1365(a) The following general provisions apply for qualifying alternative procedures: ... §1090.1365(a) (2) Testing to qualify an alternative procedure applies for the specified version of the procedure you use for making the necessary measurements. Once an alternative procedure for a method-defined fuel parameter is qualified for your laboratory, updated versions of that same procedure are qualified without further testing, as long as the procedure's specified reproducibility is the same 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. Valero requests EPA to provide clarification of these provisions. Specifically, Valero asks EPA to clarify that updated versions of referee procedures can be used without further qualification or approval from EPA as long as the procedure's specified reproducibility (for method-defined fuel parameters) or repeatability and reproducibility (for absolute fuel parameters) are the same or better than the values specified in the earlier version. As the regulation is currently written, it appears that additional qualification work would be required for updated versions of referee methods, but not for qualified alternative procedures. If additional qualification and approval 277 ------- from EPA is required for updated versions of referee method, Valero seeks clarification on what steps must be taken to request and receive EPA approval. Response: We have revised §1090.1360(c) (4) by replacing "repeatability" and "reproducibility" for the terms "accuracy" and "precision" as criteria for allowance of using updated referee test procedures for qualifying other alternative test methods. We believe that if updated referee test procedures for qualifying other alternative test methods have the same or better "repeatability" and "reproducibility" compared to its older referee test procedure, then it is reasonable to assume the new test procedure would have the same or better accuracy and precision compared to the older test procedure. Thus, we are allowing updated referee test procedures that have the same or better repeatability and reproducibility compared to the specified referee test procedure to be used without qualification. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1365(a) (5) Testing for method-defined fuel parameters must take place at a reference installation as specified in §1090.1370. Comment: There should not be a requirement for all the testing for an alternative method qualification to be conducted at a reference location. This should be revised to reflect the language in 1090.1370. " (5) The property value of the material used for alternative method-defined qualification must be generated at a reference installation as specified in 1090.1370 or through an inter-laboratory cross check program (i.e. ASTM ILCP) " [EPA-HQ-OAR-2018-0227-0074-A1, p.43] Response: The proposed requirement to perform testing at a reference installation to qualify an alternative procedure for method-defined parameters is consistent with requirements already established under §80.47. This continues to be an important provision to be confident in the testing outcome. 278 ------- Comment: > Citizen - Lau 1) with regards to 1090.1370 Qualifying criteria for reference installations, part (c) : " (c) Qualify a reference installation for non-VCSB procedures based on the following measurement protocol" > Since Reference Installations only pertain to VCSB referee test methods, the 'non' in front of 'VCSB' in this clause appears to be in error, and should be struck out to read: "Qualify a reference installation for VCSB procedures based on the following measurement protocol:" Response: We have revised §1090.1370(c) to be available for both VCSB and non-VCSB procedures. Comment: > Citizen - Lau 2) with regards to 1090.1375 Quality control procedures, part (c)(1) : " (1) Meeting the accuracy criteria of this paragraph (c) qualifies your test facility for 130 days." > the "130 days" is too long; suggest every 90 days (every 3 months), since this is consistent with quarterly conducted ILCP's that are commonly available. [EPA-HQ-OAR-2018-0227-0028, P-l] Response: Under §80.47(o) (1) (i), participation in a VCSB ILCP at least three times a year satisfies the accuracy SQC requirement for method defined test methods. This flexibility is discussed in the Tier 3 final rule.23 We did not propose to change this requirement in part 1090 and are finalizing it as proposed. Comment: > bp America Inc. (bp) §1090.1350 Overview of test procedures 23 See 79 FR 23587 (April 28, 2014). 279 ------- §1090.1350(b) (8) and (9) address the measurement of phosphorus and lead content of gasoline as specified in ASTM D3231 and D3237, respectively. It is bp's understanding that there is no requirement to test for or report gasoline phosphorus and lead levels. We suggest the preamble to the final rule explicitly state that there is no phosphorus or lead test requirement for gasoline. Response: While there is no requirement to test and report the lead and phosphorous content of motor vehicle gasoline to EPA, we have provided test method ASTM D3231 for phosphorous content in motor vehicle gasoline and test method ASTM D3237 for lead content of motor vehicle gasoline should a party wish to establish an affirmative defense to these standards. Comment: > Chevron U.S.A., Inc. Quality Control Procedures: Long term precision Many of Chevron's concerns with the proposed quality control requirements are addressed within the API/APFM joint comments sections 3.2 - Attestation: SQC and PBMS Review, 3.16 - Sampling Homogeneity, and Appendix 1 - PBMS requirements. However, a question remains on what constitutes "long-term" in the context of precision data within 1090.1375(b)(3). Other sections specifically define a number of days or number of data points for statistical evaluation, but neither is established in 1090.1375(b) (3) which leaves the section ambiguous. The criteria defined in other sections are either too brief or exceed the number of data points that would be needed to provide a meaningful indication of a "long term" control of precision. Chevron requests the EPA defines the duration in 1090.1375(b)(3) as either: (1) the calibration/maintenance frequency interval stated in the VCSB test method used; or (2) a 12 month period. This is consistent with the duration defined in 1090.1375(c) to meet an annual accuracy demonstration through participation in an ILCP. [EPA-HQ-OAR-2018-0227- 0069-A1, p.4] Response: We have removed the reference to "long-term" for testing to meet quality control requirements. Testing must include calculation of standard deviation as specified in ASTM D6299. Comment: > CITGO Petroleum Corporation (CITGO) 4.1 Updated Method Versions as Alternative Procedure 280 ------- In subpart M, updated method year versions of absolute parameters and those test methods identified for measuring other fuel testing in § 1090.1350 (b) (12) are allowed as alternative procedures if both repeatability and reproducibility are at least as precise as the values specified in the earlier version. However, updated method year versions of method-defined parameters are allowed as alternative procedures if only the reproducibility is at least as precise as the values specified in the earlier version. Clarification is needed on whether this is intended or an error during publication. [EPA-HQ-OAR-2018-0227-0054-A1, pp.14-15] Response: We have revised §1090.1365(b) (2) to add repeatability as a criterion for exemption from approval for method-defined alternative test methods. This correction will maintain consistency of performance criteria between §§1090.1350(b) (12) and 1090.1365(b)(2). Comment: > CITGO Petroleum Corporation (CITGO) 4.2 Quality Control Procedures In general, §1090.1375 provides specifics on requirements relative to quality control precision and accuracy requirements to include responsibilities moving forward if you fail to conduct testing or fail to meet the criteria. Specifically, §1090.1375 (a) (1) states that if you fail to conduct testing, the test facility is not qualified for measuring fuel parameters. Also, if the test facility fails to meet the criteria, it is not qualified for measuring fuel parameters until necessary changes are made and testing is performed to show the facility meet the criteria. However, there is no mention of whether the situation of failing to meet criteria invalidates prior data and if so, for how long? Further clarification is needed. [EPA-HQ-OAR-2018-0227-0054-A1, pg.15] Response: Quality control demonstrations under §1090.1375 are valid for the specified term. Additional testing is required to again qualify testing equipment for a new term before the end of the term established by the earlier testing. A failing result for this quality testing therefore does not apply retroactively. Comment: > CITGO Petroleum Corporation (CITGO) 4.2 Quality Control Procedures Precision demonstration. In §1090.1375(b) (1), meeting the precision criteria of this paragraph qualifies your test facility for performing up to 20 production tests or 7 days, whichever is less. Clarity is needed to determine whether EPA's use of the term "production tests" is to mean 281 ------- testing relative to certification batches only, not inclusive of all testing on the device. [EPA-HQ- OAR-2018-0227-0054-A1, pg.15] Response: We recognize that the term "production tests" creates an ambiguity. This ambiguity has been part of the regulation in part 80 for many years. As a matter of principle, the need for confirming precision over time does not change depending on the type of tests being performed. It is therefore appropriate to consider all discrete tests when considering the validity of the precision demonstration. On the other hand, including all tests could force test labs to perform these precision demonstrations multiple times in a day. To counteract the potential for increased testing burden for counting all tests, we have revised the regulation to allow for precision demonstrations to be valid for a full day regardless of the number of tests performed. Comment: > CITGO Petroleum Corporation (CITGO) 4.5 General Questions (1) For ongoing SQC precision demonstration, additional detail is needed on how to use I charts and MR charts as specified in ASTM D6299-19a to show that the long-term standard deviation for the test facility meets precision criteria in §1090.1365(b). [EPA-HQ-OAR-2018-0227-0054- Al, p.16] Response: ASTM D6299 describes how to use I charts and MR charts to quantify standard deviation for a test facility. We have removed the reference to "long-term" for meeting the SQC requirements. Comment: > CITGO Petroleum Corporation (CITGO) 4.5 General Questions (2) For ongoing SQC accuracy demonstration, what is EPA's expectation for comparison of results and how we show and confirm we have made the comparison to ARV in an ILCP at least three (3) times per year for method-defined parameters? [EPA-HQ-OAR-2018-0227-0054-A1, p.17] Response: §1090.1365(c) (4) defines criteria for conformance to SQC accuracy requirements for method- defined fuel parameters. 282 ------- Comment: > CITGO Petroleum Corporation (CITGO) 4.5 General Questions (4) In §1090.1350(d), for any measurement or calculation depending on the volume of the test sample, we are to correct the volume of the sample to a reference temperature of 15.5°C (288.65 K). Use a correction equation that is appropriate for each tested compound. This applies for all fuels, blendstocks, and additives, except butane. Since a 60°F~15.56, is it still acceptable to use a 60°F? [EPA-HQ-OAR-2018-0227-0054-A1, p.17] > Marathon Petroleum Company LP (MPC) Overview of Test Procedures 1090.1350(d) For any measurement or calculation that depends on the volume of the test sample, correct the volume of the sample to a reference temperature of 15.5 °C (288.65 K). Use a correction equation that is appropriate for each tested compound. This applies for all fuels, blendstocks, and additives, except butane. MPC believes this may cause confusion due to the slight differentiation in the test method requirements. Please specify a reference temperature of 15.56°C (60°F). Response: We have revised the regulation to specify a reference temperature of 15.56 °C. Celsius units align with the referenced test methods, which are generally written based on measured values using SI units. With the extra decimal place, the reference temperature is consistent with any form testing based on a correction to 60 °F. However, it is important to note that there are not two reference values. This involves a minor adjustment, but the reference temperature is 15.56 °C. Comment: > Holly Frontier One of our laboratories has informed us of an inconsistency with regard to the reporting instructions for oxygenates in §1090.1355, Calculation adjustments and corrections, and the range limits in the scope of ASTM D4815. §1090.1355(d) states: "If measured content of any oxygenate compound is less than 0.1 percent by mass, record the result as "None detected."" For D5599, the referee method, the published range minimum is 0.1 mass %. However, for D4815, which is widely used as an alternate method, the published range minimum is 0.20 mass %. This inconsistency may result in confusion and potential reporting issues when an oxygenate is measured lower than 0.20 mass % by D4815. For example: 283 ------- Would it be acceptable to report "None detected" if the measured D4815 result is below 0.20 mass %, or would <0.20 mass % have to be reported? Would it be acceptable to report "None detected" only if the measured D4815 result is below 0.10 mass %? [EPA-HQ-OAR-2018-0227-0087-A1, p.l] Response: We have revised §1090.1355(e) to state that test results for oxygenates with less than 0.20 mass percent be recorded as "None detected." We believe this change will allow for consistency in recording and reporting of test results for oxygenates for the two most commonly used methods for oxygenate measurement, which will help reduce confusion and potential reporting issues associated with oxygenate measurement. Comment: > Husky Energy Husky requests that EPA amend its regulations to provide for alternative sampling, testing and certification methods for calculating Reid vapor pressure (RVP) in gasoline. Currently, the regulations require use of a manual sampling and testing method or a highly burdensome and multi-year process in order to use new or alternative sampling technologies for compliance purposes. Advances in technology allow for more accurate and reproducible sampling and testing methods, but the existing regulations make those technologies nearly impossible to be implemented. Gasoline manufacturers cannot benefit from these technological advances because the existing regulations do not provide a reasonable pathway to adopt them in order to certify compliance. This is exactly the type of issue this rulemaking is intended to correct. EPA should model its regulations in a manner similar to those that provide for alternative monitoring plans for stationary sources in order to allow for use of new technology to demonstrate compliance with RVP regulations. EPA limits gasoline RVP during the summer ozone season as a way of limiting evaporative emissions from gasoline that contribute to ground-level ozone. See 40 C.F.R. § 80.27. In order to certify compliance with this limitation, regulated parties must determine the RVP using a standard developed in the 1930s - the ASTM D5191 standard (D5191). See 40 C.F.R. §§ 80.46(c), 80.47(g). To comply with RVP limits using D5191, refiners must manually obtain a "grab sample," - a representative sample of a gasoline blend after tank mixing - and transport it to the lab for analysis and certification. While there are many details in the D5191 standard regarding the sampling the procedure and guidelines for handling the sample, it ultimately remains a manual process with many steps that can increase the reproducibility number or random variation of the test. A primary cause of this issue is due to the fact the process entails moving a product with volatile chemical properties out of a controlled tank and into a physical laboratory. This human interaction with the sample causes error by changing the RVP properties of the fuel every time a bottle is opened and closed. Additionally, the manual sampling process can increase the reproducibility number because 284 ------- refiners use a different, more advanced technology to measure RVP in the manufacturing process (typically analyzers on the blend header) but have to certify the gasoline for RVP using the manual sampling method (D5191 in the lab), which is out of date. The D5191 standard also can increase the cost of fuel production. As a result of the variability inherent in manual sampling and testing, refiners such as Husky, build in unnecessary compliance margins that can increase the cost of gasoline. Manual sampling may also give rise to errors, which requires refiners to resample to ensure that batches of gasoline comply with RVP limitations. The addition of compliance margins, as well as the time and effort required to resample batches impose costs that could be avoided using more advanced sampling technology. One technology that easily could provide alternative compliance paths for RVP certification is the use of online analyzers. These devices replicate the laboratory (D5191) test method without the need for manual sampling and thus reduces human error. Online analyzers are a bolt-on technology that can be incorporated directly to a blend header. They can provide refiners with more data (multiple readings per day in contrast to a single daily manual sample) that can be more accurate than traditional manual sampling and testing. Online analyzers also provide value by lowering compliance costs without sacrificing emissions compliance. Because refiners can obtain more and accurate data on the RVP levels of a batch of fuel using online analyzers, refiners can reduce gasoline manufacturing costs. The data quality and quantity also ensures that lower manufacturing costs do not threaten compliance with RVP restrictions. This results in a win-win situation for manufacturers, consumers and the EPA. The benefits of new technologies such as online analyzers cannot be realized, however, because these technologies do not, according to EPA staff, fall within the scope of D5191 because they do not constitute laboratory testing (i.e. involve the transport of a manual sample to a laboratory). Because these new technologies do not squarely fit within the current regulatory language, the regulations create a bureaucratic road block for advancing new technologies. Consequently, EPA's regulations do not clearly permit regulated parties to rely on these technologies to certify compliance with RVP limits. EPA's regulations do provide parties with opportunities to petition for alternative testing methods and compliance requirements, but the time involved in pursing such alternatives is often cost and time prohibitive. One option, referred to as a Voluntary Consensus Standard Based (VCSB), "allows for qualifying methods that have been sponsored and published by a voluntary consensus standards body, such as ASTM International." 79 Fed. Reg. 23,413, 23,585 (Apr. 28, 2014); see also 40 C.F.R. § 80.47(1). Such approaches take many years to complete and they may be too costly for many regulated parties. The other option is a non-VCSB method. This approach "involves qualification for a laboratory that has developed its own analytical test method but has decided not to offer it for evaluation and establishment through a VCSB-based organizational process." 79 Fed. Reg. at 23,585; see also 40 C.F.R. § 80.47(m). Like the VCSB approach, this alternative method would take a long time to complete and it can be cost-prohibitive to smaller refiners because it requires testing on a 285 ------- number of fuels in a number of laboratories. Such refiners generally lack access to multiple laboratories and a broad range of fuels. The alternative test method provisions in 40 C.F.R. § 80.47(1) and (m) do not provide meaningful opportunities to invest in new technology. As indicated above, establishing alternative test methods requires a long lead time and a significant investment by a regulated party. Given the risk in such approach and the changes in technology that can occur during that process, there is a substantial disincentive to adopt new technology that could result in greater efficiency, lower costs, and more accurate data. Thus, EPA should provide regulated parties with a reasonable process for requesting an alternate compliance method. This process can mirror the procedure for submission and approval of alternative monitoring plans (AMPs) that EPA allows for stationary sources. See 40 C.F.R. § 60.13. The purpose of the AMP regulations is to allow facilities to justify alternative methods for documenting compliance other than those in the regulations. EPA could easily use the same formal submittal and approval process to assure proper oversight as in 40 CFR Part 60. Once approved, the alternative monitoring techniques replace applicable regulations at the applicable facility. EPA has many years of experience with this type of approach and there is no reason why the fuels program cannot have a similar program to advance new sampling technologies. Husky requests that EPA amend its fuel regulations to include a provision that provides a reasonable process for adopting new sampling technologies to certify compliance with fuels regulations. The proposal would set forth a process that could be completed in a matter of months and provides regulated parties an opportunity to develop a testing protocol, analyze a number of samples, demonstrate an appropriate correlation to an approved method, and petition for EPA acceptance of the method. We ask that EPA include this provision in the final rule, as it is a logical outgrowth of the proposed rule seeking to update, streamline, and improve fuels regulations, including regulations regarding RVP compliance. [EPA-HQ-OAR-2018-0227-0059- Al, pp.1-3] Response: We continue to have concerns over how well online RVP analyzers will correlate to laboratory bench test methods like ASTM D5191. We note that while the commenter contends that online RVP analytical methods correlate well, the commenter provided no data or analysis that we could rely upon to make such an assessment. We did not propose to allow for online analyzers and are not finalizing to allow them as we believe more work needs to be done to determine how to correlate the methods to bench test methods. Comment: > Marathon Petroleum Company LP (MPC) Overview of Test Procedures 286 ------- 1090.1350(b) (11) Use referee procedures specified in §1090.1360(d) and the following additional methods to measure gasoline fuel parameters to meet the survey requirements of subpart N of this part: Olefin content, volume percent, ASTM D6550 ASTM D6550 measures olefins in wt%. Please specify if ASTM D6550 results are intended to be correlated to vol% per ASTM D1319. Response: Part 1090 includes the most current version of ASTM D6550. Per Section 13.3.2 of ASTM D6550-15, results are expected to be converted to volume percent as correlated via ASTM D 6 708 to ASTM D1319. Since the procedure to convert to volume percent is included in ASTM D6550-15, we do not believe that it is necessary for us to revise our regulations, as the procedure is already incorporated by reference. Comment: > Valero Energy Corporation 4. Quality Control Procedures General Provisions In proposed subpart M §1090.1375 (a) (3) & (4) (b) (2), Valero recommends that EPA change from "Q-Procedure" to "procedure 2-A or procedure 2-B." These procedures are designed to streamline evaluation of precision and are statistically valid. Specifically, Valero recommends these provisions revised as follows: (3) If you perform major maintenance such as overhauling an instrument or recalibrating it, confirm that the instrument still meets precision and accuracy criteria before you start testing again. In reference to D6299 (incorporated by references) use sections 8.7.3 and 8.7.4 respectively for either procedure 2-A or procedure 2-B with the MR chart. (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 qualifies your test facility for performing up to 20 production tests or 7 days, whichever is less. (2) Perform precision testing using the control-chart procedures in ASTM D6299 (incorporated by reference in §1090.95). If you opt to use procedure 2- B, 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 287 ------- precision (R1) of the ARV of the standard reference material, as determined by ASTM D6792. [EPA-HQ-OAR-2018-0227-0056-A1, pp. 10-12] 2 81 FR 23462 (April 22, 2016) Response: As suggested by the commenter, we have revised the quality control procedures to reflect the updates to ASTM D6299 that occurred subsequent to the NPRM. Under part 1090, there will be three allowable quality control procedures: concurrent testing of both QC materials, ASTM D6299 procedure 2-A (the "Q-Procedure"), and ASTM D6299 procedure 2-B (dynamically updated exponential weighed moving average or "EWMA" procedure) that can be used when changing QC materials. We have removed references to ASTM D6792 in §§1090.1375 (a) (3) and 1090.1375(4) (b)(2), as there is no reference to how to determine the ARV in ASTM D6792. Comment: > Valero Energy Corporation H. Sampling. Testing and Retention Provisions 4. ASTM D6792 In subpart A §1090.95(e) (34) - Incorporation By Reference D6792-17, EPA proposes the following: ASTM D6792-17, Standard Practice for Quality Management Systems in Petroleum Products, Liquid Fuels, and Lubricants Testing Laboratories, approved May 1, 2017 ("ASTM D6792"); IBR approved for §§1090.1375(b) and 1090.1440(c). First, Valero requests that EPA clarify that this standard practice will only apply to test methods that are contained in the regulations and not any others at the refinery level, e.g., olefins and aromatics. Second, full implementation of this standard practice could take up to 12 months. Valero requests that this method not be required until one year following the publication of this final rule. [EPA-HQ-OAR-2018-0227-0056-A1, p.13] Response: We have removed the reference to ASTM D6792 in §1090.1375(b) as we do not believe that it was appropriately referenced in the proposal. We are maintaining that reference for TPI determination and evaluation for the NSTOP and this will only apply to parameters that fuel manufacturers must measure for batch certification (i.e., sulfur, benzene, and, for summer gasoline, RVP). Since this requirement applies to the independent surveyor and not fuel manufacturers, we do not believe additional time for implementation is needed. However, it is 288 ------- worth noting that we have extended the implementation date for the NSTOP to June 1, 2021, which will provide the independent surveyor more time to develop procedures to determine and evaluate TPI. 289 ------- 16. Proposed Third-Party Survey Provisions (Subpart O) 16.1. National Fuels Survey Program Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • consolidation of multiple retail sampling programs into a single National Fuel Sampling Program; [EPA-HQ-OAR-2018-0227-0074-A1, p.6] > Chevron U.S.A., Inc. National Fuels Survey Chevron supports the expansion of the National Fuels Survey Program (NFSP) to include RFG, CG, El 5, and ULSD. The ability to increase the breadth of the program while reducing the overall compliance cost for participants is a welcome improvement. The program design should facilitate EPA oversight to help ensure regulatory compliance and encourage equitable enforcement across gasoline and diesel fuels offered for sale at retail. [EPA-HQ-OAR-2018- 0227-0069-A1, p.2] We also support the continued exemption of California retail locations from the NFSP. The California Air Resources Board maintains their own oversight of gasoline and diesel fuel across the supply chain including retail locations. The exemptions provided in 1090.620(a) are warranted given California's existing program. We recognize that California refineries are subject to the National Sampling Oversight Program (NSOP) if they choose to meet the downstream oxygenate blending requirements for gasoline distributed and sold outside of California. However, California retail locations should remain exempt from the NFSP. [EPA- HQ-OAR-2018-0227-0069-A1, p.2] > Growth Energy Additionally, while we continue to seek removal of the burdensome El 5 sampling survey requirement as unnecessary, we are pleased to see that EPA is taking steps to hopefully reduce costs to ethanol producers and retailers. As you know, since the approval of El 5 in 2011, a fuel sampling survey has been a requirement under the misfuelling mitigation regulation, and the costs have been solely borne by ethanol producers and retailers - costs that exceed a million dollars annually. By consolidating the various sampling programs, including the El5 sampling survey, into one national fuel survey, we are hopeful that a larger group of survey participants including oil refiners and other fuel manufacturers will lower costs for all participants including our member producers and El 5 retail partners. [EPA-HQ-OAR-2018-0227-0053-A1, p.2] 290 ------- > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 6. Consolidating the four in-use retail fuel surveys into a single national in-use retail program. The reduction of sample quantities from 18,000 samples annually to less than 7,000 should result in a significant reduction in the cost of this survey program. However, ILTA has concerns about the legality of requiring all conventional gasoline be covered under this national in-use program. [EPA-HQ-OAR-2018-0227-0061-A1, p.2] > Petroleum Marketers Association of America (PMAA) Fuel Quality Survey Consolidation PMAA supports the EPA's proposal to consolidate the RFG, RVP, ULSD and El5 fuel quality surveys into a single one stop testing mechanism. PMAA agrees with the agency that the consolidation would lessen the regulatory burden on small business petroleum marketers by reducing the number of testing sites from 18,000 to approximately 5000 retail sites nationwide. However, PMAA remains concerned that the lack of adequate fuel quality testing above the terminal rack is exposing retail petroleum marketers to a higher risk of liability than if third party testing were performed across the entire petroleum distribution chain. PMAA members often cite the lack of verifiable upstream testing for downstream fuel quality problems. It is difficult, if not impossible under the current survey program for retail marketers to determine the origin of non- spec fuels in their possession without comprehensive fuel quality testing upstream. [EPA-HQ- OAR-2018-0227-0083-A1, p.2] > Renewable Fuels Association (RFA) National Survey Program We are pleased to see the proposed consolidation of the existing fuel compliance surveys into one National Survey Program. RFA has been working for years to reduce the costs and burdens associated with the El5 survey, which is the only survey program that is currently mandatory. Ethanol manufacturers have incurred unnecessarily large costs to fund the required survey and testing of ethanol content, summer RVP and compliance with mandatory labeling requirements. While we continue to question the need for an El 5 survey program moving forward, we are encouraged that EPA is at least taking steps to reduce the cost and administrative burden. It is obvious that, overall, the projected cost reductions associated with this proposed rulemaking principally benefit petroleum refiners, but ethanol producers are pleased this expanded National Survey Program proposal should help ethanol producers lower their survey costs as well. [EPA- HQ-OAR-2018-0227-0037-A1, p.2] 291 ------- > The National Association of Convenience Stores (NACS), the National Association of Truckstop Operators (NATSO), and the Society of Independent Gasoline Marketers of America (SIGMA) National Fuels Survey Program Participation NACS, NATSO, and SIGMA are generally supportive of EPA's proposal to consolidate the four survey programs into a single national survey in-use retail program. 12 The Associations concur with EPA's assessment that consolidating the survey programs will reduce costs and expand the benefits of the survey program across the nation. [EPA-HQ-OAR-2018-0227-0066-A1, p.6] 12 Proposal, supra note 1 at § 1090.1400 et seq. Response: We thank the commenters for their support. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Comment: Similarly §1090.1410 Independent surveyor requirements (e)(4) should be modified to identify that an El 5 yielding an ethanol content below 10 volume percent should be the basis of a notification in addition ethanol content exceeding 15 volume percent. [EPA-HQ-OAR-2018- 0227-0074-A1, p.32] Response: Under part 1090, we require that the independent surveyor periodically report all test results to EPA quarterly except when a test result for a collected gasoline sample does not meet per-gallon standards or when an El5 labeling requirement is not met. In these cases, the independent surveyor must notify EPA within 24 hours of identifying the potential non-compliance issue. In the case of a pump labeled as dispensing El5 with a test result showing less than 10 volume percent ethanol content, no per-gallon standard has failed to be met. While there may be a labeling issue since El5 labels are required for gasoline-ethanol blends containing more than 10 but no greater than 15 volume percent ethanol, it is not a labeling issue that will result in the misfueling of El 5 in vehicles, engines, and equipment that are not allowed to use El 5. Therefore, we do not believe that it is necessary for the independent surveyor to notify EPA of these issues within 24 hours. However, it is worth nothing that these issues will be identified as 292 ------- part of quarterly and annual reports, which will allow EPA to take appropriate action if necessary. Comment: > bp America Inc. (bp) Subpart N—Survey Provisions 1090.1415(d)(1) Survey Plan Design Requirements bp recommends the modification of the requirement to base the selection of retail sites to be sampled on the basis of proportionate volumes since survey companies will not be able to obtain retail station gasoline volume information to make this determination, bp recommends this determination be made on the actual site count of the retailer, preferably by market area, but remains concerned that low-volume or small-scale marketers could be disproportionately overlooked in favor of brands with very large market presence. [EPA-HQ-OAR-2018-0227- 0046-A1, p.29] Response: We believe that a change in retail selection methodology as suggested by the commenter could bias the results of the survey in a way that would result in less robust estimates of national fuel parameters as small-scale retailers by definition represent a smaller segment of the national fuel pool. However, we note that smaller-scale retailers, if they make up a sizeable portion of an area's fuel pool, will be selected as part of the survey randomly and thus proportionate to their relative market share in the area. We believe the proposed retail sample selection methodology will provide for both robust national fuel parameter estimation and provide meaningful oversight on smaller-scale retailers. Therefore, we are finalizing the retail station selection methodology as proposed. Comment: > Camin Cargo Control b. We suggest rewording 1090.1405(b) to 'The survey program must be conducted using samples representative of the gasoline and diesel available at retail outlets ...' [EPA-HQ-OAR- 2018-0227-0030-A1, p.2] Response: We have clarified the language around statistically representative samples in the survey programs versus requirements to collect samples that are representative of the fuel for sampling, testing, and retention purposes, as the commenter suggested. 293 ------- Comment: > Eversheds Sutherland (US) LLP National Survey and Oversight Programs EPA is updating its requirements regarding a national gasoline sampling program to require both a National Fuels Sampling Program ("NFSP") and a National Sampling Oversight Program ("NSOP"). The NFSP is mostly analogous to the currently-in-effect RFG Survey Association ("RFGSA") program for gasoline, while the NSOP is a new program under the Proposed Rule. Both new programs can either be conducted internally or by participation in the new NFSP and NSOP programs that the RFGSA will administer as a third-party surveyor; the majority of fuel manufacturers will opt for the latter as undertaking these programs individually is generally cost- prohibitive. While EPA's stated desire is to manage the costs of compliance, at this time the costs of the NFSP and NSOP remain quite uncertain to fuel manufacturers, and it is uncertain that the decrease in the overall number of samples collected will result in any cost savings for regulated entities. RFGSA is mandating that a fuel manufacturer commit to enrollment in the programs prior to RFGSA providing the costs of the programs; especially for the mid-to-smaller fuel manufacturers, this arrangement is backwards, and fees and program details should be shared before enrollment commitments. EPA should not abdicate its critical role here merely because of the surveyor's role under Part 80 and assume savings or even maintenance of current fees, but instead should ensure that interactive dialogue is taking place where answers about costs and processes are fully addressed. While a recent workshop presentation was helpful, this information should have been presented well before the Proposed Rule was released, and there was no meaningful dialogue that allowed for further understanding as to the costs or the set-up of the programs. [EPA-HQ-OAR-2018-0227-0076-A1, pp.13-14] Response: Participation in NFSP or NSTOP is voluntary. As such, we expect that parties that wish to participate in NFSP or NSTOP will balance the costs of such participation versus the benefits from taking advantage of flexibilities of downstream oxygenate accounting (as discussed in Section VII.G of the preamble) or establishing an element of an affirmative defense (as discussed in Section XII of the preamble). Regarding the fee structure of the RFG Survey Association and participating manufacturers, we do not regulate the contractual agreements between parties in the marketplace. We do not believe any changes to the NFSP or NSTOP regulations are necessary based on this comment. Comment: > International Liquid Terminals Association ILTA's CONCERNS 294 ------- While the proposal includes many provisions that ILTA supports (listed above), there are also areas of concern. We discuss these below. 2. Moving Conventional Gasoline (CG) Under the RFG Survey Program While we understand the logic for proposing that CG be included under the RFG Survey fuel oversight requirements, we do not believe that EPA has the authority to put this requirement into effect. In addition, there are many U.S. terminals that only handle CG and therefore have no current requirement to deal with RFG rules and surveys and the new fuel sampling requirements. The imposition of this requirement would significantly increase the compliance costs for these CG only terminals without providing any environmental benefits. [EPA-HQ-OAR-2018-0227- 0061-A1, p.3] Response: The commenter provides no explanation for why EPA lacks authority to establish a voluntary survey program to provide flexibilities to fuel manufacturers and other regulated parties in the fuel distribution chain. As stated in the Section X.A of the preamble, participation in the NSFP is voluntary. For fuel manufacturers, as currently under the RFG program in part 80, we are providing a mechanism for fuel manufacturers to account for oxygenate added downstream if those parties can demonstrate that the oxygenate blending occurs downstream via the NSFP. Under part 80, RFG refiners have the opportunity to take advantage of this as long as certain conditions are met (e.g., ensure that oxygenate levels added downstream at levels assumed by the RFG refiners either via survey or by establishing a downstream quality assurance program). This provision was not allowed for CG refiners and part 1090 now provides this flexibility to all fuel manufacturers. However, these fuel manufacturers are not required to account for oxygenate added downstream and we expect that fuel manufacturers will make the decision on whether the financial benefits of accounting for oxygenates added downstream outweigh the costs of participating in the NSFP. Furthermore, regulated parties can help establish an affirmative defense against violations that occur downstream by participating in the NSFP in addition to other things spelled out in §1090.1720. Affirmative defenses are by their nature voluntary; however, we believe it prudent for parties that make and distribute fuels to ensure that EPA's fuel quality standards are met. On the other hand, we recognize that having thousands of regulated parties individually establish robust quality assurance programs at retail would be expensive and potentially less effective than having a single program that undergoes an annual EPA approval process. Therefore, we believe that providing an element of an affirmative defense will incent some parties to participate in the NSFP without requiring participation. As for accounting for oxygenates added downstream, participation in the NSFP is in no way mandatory. Regulated parties can establish their own quality assurance procedures, but EPA may find those procedures inadequate in practice. This is not a risk for the NSFP since EPA approves the NSFP on an annual basis. 295 ------- Comment: > Independent Fuel Terminal Operators Association (IFTOA) IX. National Survey The EPA proposes that gasoline manufacturers that elect to account for the addition of oxygenate added downstream under § 1090.710 must participate in the national survey program. While this approach is an appropriate way in which a regulated party may ensure compliance, it is very costly. Therefore, to minimize that burden, EPA should make participation voluntary and allow gasoline manufacturers to achieve compliance in alternative ways. For example, a gasoline manufacturer who adds oxygenate at its terminal rack could retain an independent consultant/surveyor to test its system monthly to ensure that oxygenate is added at levels reported to the EPA. The regulated entity would be required to maintain records of such inspections and make them available to the Agency upon request. In this manner, gasoline manufacturers would employ sufficient oversight but would do so less expensively. EPA regulations should focus on compliance not on the specific mechanism used to achieve it. The program should remain voluntary under all circumstances. [EPA-HQ-OAR-2018-0227-0064-A1, pp.5-6] Response: As proposed and highlighted by the commenter, participation in the NFSP is voluntary. Only fuel manufacturers that wish to account for the addition of oxygenate added downstream must participate in the NFSP. As discussed in Section VII.G of the preamble, we are attempting to simplify and consolidate the various downstream oxygenate provisions from part 80 into a single set of consistently applicable provisions that apply equally to all gasoline manufacturers across the country that elect to account for oxygenate added downstream. Allowing for individual oxygenate blending verification programs by any number of gasoline manufacturers would significantly complicate the downstream oxygenate accounting provisions and make it difficult for EPA to oversee the program. For these reasons, and those discussed in Section VII.G of the preamble, we are maintaining a single set of provisions for downstream oxygenate accounting, including mandatory participation in the NSFP. 296 ------- 16.2. National Sampling and Testing Oversight Program Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • the establishment of the National Sampling and Testing Oversight Program; [EPA-HQ-OAR- 2018-0227-0074-A1, p.6] > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 7. Establishing a voluntary, third-party survey program for oversight of gasoline manufacturing facilities and the proposal to require gasoline manufacturers that elect to account for oxygenate added downstream to participate in the proposed national sampling oversight program. [EPA- HQ-OAR-2018-0227-0061-A1, p.2] Response: We thank the commenters for their support. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.19 Third Party Lab Registration for NSTOP In the preamble, EPA provides an overview of its proposed National Sampling and Testing Oversight Program ("NSTOP") and seeks comment on all aspects the program. Specifically, EPA explains its rationale for no longer requiring laboratories to register under part 1090, except in the limited case where a third party laboratory is acting as a report-submitting agent on behalf of a regulated party. 25 The Associations support EPA's approach of not requiring third party laboratories to register as a prerequisite to a regulated party using the third party for laboratory sampling and testing services. [EPA-HQ-OAR-2018-0227-0074-A1, p.26] EPA also discusses a concern expressed by some stakeholders that "replacing the RFG independent laboratory testing program with the proposed voluntary national sampling oversight program would allow for parties to more easily arrange for favorable test results that demonstrated a fuel met EPA fuel quality standards."26 The Associations do not share this 297 ------- concern. EPA has effectively prohibited this kind of behavior in that anyone responsible for testing is required to follow good laboratory practices for all required testing.27 "Shopping around" for favorable test results is contrary to good laboratory practice and would be a failure to meet that requirement. Further, a fuel manufacturer is responsible for any testing that is performed on its behalf. This is true whether the testing is performed by the manufacturer's on- site laboratory or performed by a third-party laboratory.28 Restricting fuel manufacturers to using a single third-party laboratory could be a burden and a constraint. Fuel manufacturers should not be limited in which laboratory or laboratories it chooses to use provided that the regulatory requirements for testing are met. [EPA-HQ-OAR-2018-0227-0074-Al,p.26] 19 See 1090.1440(d)(3)), Fa and Fb 25 See 85 Fed. Reg. 29061. 26 See 85 Fed. Reg. 29073. 27 See proposed §1090.1300(d). 28 See proposed §1090.1300(c). > Camin Cargo Control A. The proposed rule calls for the elimination of the Independent Laboratories requirement in the current regulations. Independent Inspectors and Laboratories provide an unbiased oversight to help the Industry comply with EPA Regulations. The Independent Laboratories have functioned for many years as the check system, educators to industry and enforcers of EPA regulations. We request the reinstatement of the EPA registered Independent Laboratory designation for compliance testing because we believe that the independent laboratories are an integral part of compliance and necessary for maintaining environmental performance. This reinstatement action will maintain data traceability and record-keeping requirements, ensuring a strong and enforceable quality control process with no budgetary impact on the EPA program or cost to any parties involved. We support a compromise approach that would maintain the requirement for testing by registered Independent Laboratories but no longer require that the data be reported by the Independent Lab to the EPA. Instead, the laboratories would maintain the data and make it available to EPA upon request. The advantage of this approach is that any problems would be detected up front, which would help maintain air quality. Randomly surveying fuel after it is distributed or spent is less effective and may negatively affect air quality. In addition, we strongly believe the Independent Laboratories provide critical guidance and help Industry implement the proper procedures. [EPA-HQ-OAR-2018-0227-0030-A1, p.l] Subpart B—General Requirements and Provisions for Regulated Parties 298 ------- 2. Independent Laboratory requirement: "EPA seeks comments on whether they should require that all third-party laboratories register and that refiners be limited to using a specified, registered third-party laboratory." As stated in the Rule's Executive Summary, environmental performance is a key element in the rewriting of the regulations. Independent Laboratories have spent the last three decades improving their Operational, Field, Laboratory and Quality programs to achieve extremely high standards. Independent Laboratories' investment in personnel, training, equipment, quality and oversight programs provided the entire Petroleum Industry with traceable and robust data to ensure environmental performance was measured properly. EPA's proposal to remove the Independent Laboratories from the legal framework will jeopardize the quality of the data obtained moving forward and directly reduce the reliability of any future evaluations and controls. While we understand that the oversight program proposed to replace Part 80 Independent Sampling Program would act as a monitoring tool, the Industry would only obtain fuel quality data after the fuel has been dispensed, which would not serve as a deterrent in a very competitive and dynamic blending market. In addition, because of the limited scope (considering the entire US fuel pool) of the survey, it will not be truly representative of the fuels in the marketplace. EPA is proposing to remove the registration requirement for independent labs unless they submit information directly on behalf of another party. If an independent lab is submitting on behalf of another party, they are effectively an agent for that party, and thus, no longer 'independent.' Registration requirements are minimal, easy, and are not a cost factor for the Industry stakeholders or the EPA. The system is already in place and removing the independent labs may prove to be more expensive and problematic with the disassociation of all the past data from the parties involved and the loss of inherent traceability for historical data. Sample quality is the most important element in the proper determination of a product property and how it affects the environment. If the sampling is reduced in size compared to the Independent Lab program or left to unqualified personnel, there will be greater uncertainty surrounding any of the obtained test results. Correct sampling requires proper equipment that is well maintained and calibrated, plus trained and qualified personnel. Independent Laboratories have built their businesses around these elements, obtaining international certifications and accreditations to attest to the quality and integrity of their systems; these conditions cannot be guaranteed with other entities or refiners' internal staff. EPA notes that having an independent lab collect a sample is the most expensive part of the testing process, but this task is necessary for all Custody Transfer movements. In other words, industry will need to continue to sample their products for it to be sold, regardless of the requirements by EPA. 299 ------- Cost feedback from the stakeholders which EPA mentioned may include the normal delays derived from operational constraints beyond the scope of the sampling (e.g: unavailability of the product, tanks not ready, re-blending, unrelated to sampling vessels demurrage, etc.) which will remain a factor in the process regardless of the Independent Laboratory's involvement. The reduction in sample size (surveys vs 100% of products being monitored in the marketplace) while also adding additional products to be monitored will negatively impact EPA's ability to detect non-compliances. The removal of the independent laboratory requirement will, without question, enable producers/blenders to use multiple laboratories for their quality work and select desired results as currently prevented by Part 80. We do not believe this was the intention of the EPA, and it is not conducive to a strong and enforceable quality control process. In Part 80, the EPA warns producers not to shop for results by changing laboratories but in the Rule's Preamble, EPA clearly states that it is aware of fuel manufacturers biasing test results to make 'dirty fuels' and makes no similar prohibition in Part 1090. Since the inception of Part 80, Camin Cargo has observed events and behaviors that conflict with the EPA's efforts to enforce the CAA under 40 CFR Part 80. These events, which primarily occurred as a result of fuel operator inexperience or market pressures (timing/price) have included (but are not limited to) the following examples: • efforts to exploit the limits of reproducibility/shopping of results ultimately thwarted by the EPA laboratory designation; • submission of batches with products failing to meet EPA specs; • improper import testing and testing procedures; • testing of products in tankage whose construction does not allow for obtaining representative samples; • submission of theoretical (rather than tested) results; • batching confirmed non-homogeneous products as well as submission of products lacking demonstration of homogeneity; • submission of volumes exceeding those of the product that was certified; • discovery of terminal line displacements which changed the product properties and volumes; and • the usage of tanks as storage for intentionally stratified products. These events/actions would go largely undetected by the EPA under the proposed rule if the independent laboratories are removed from the compliance process but would continue to be addressed in Camin's proposed hybrid approach to testing. The EPA already has all approved Independent Laboratories currently registered via the OTAQREG Fuels Program Registration system, containing all of the pertinent facility/company information and establishing the relationship between stakeholders and their selected primary and alternate independent laboratories. The CDX website is a much improved tool that simplifies any documentation requirements with a simple login and form submission. This is not a burden given today's technology and e-commerce experience. By contrast, not having an Independent 300 ------- lab perform the EPA-related work will force companies to use a commercial laboratory, or their own laboratory, for testing while also still hiring the Independent Inspection company (Independent Labs) to perform the required Custody Transfer inspection, as typical US commercial agreements require a qualified US Customs-approved Gauger (Independent Inspection company). We propose that EPA maintain the requirement to use a registered Independent Laboratory for sampling and testing of RFG without making any significant changes to the Part 1090 Sampling, Testing and Reporting Requirement. This proposed change would bear no additional burden or cost to any participant with tremendous benefits to the compliance enforcement of Part 1090. Since the designation of an Independent Laboratory as the selected provider for these services by Stakeholders requires the approval of their Senior management, we believe the inclusion of the Independent Laboratory language will, de facto, prevent selection of preferred test results. The main driver behind retaining the Independent Labs is to ensure proper sampling and to maintain robust laboratory and quality data, at no additional cost to EPA or customers. By preserving the role of Independent Labs and having the inspection and laboratory data made available to EPA upon request, we are creating a strong incentive for the continued outstanding environmental performance Part 80 has already achieved. Camin Cargo's proposal to maintain the Independent Laboratories is summarized below in practical terms as changes to Part 1090: • Add a definition for Independent Laboratories in the Definitions section 1090.80. • List the Independent Laboratory requirements (already in Part 80 and much simplified in Part 1090 Independent Parties section), providing framework. • Add back the Registration requirement for Independent Laboratories. As with other existing registrations under Part 80, these would carry to Part 1090 without any extra burden to stakeholders or EPA. • Add a paragraph under General Requirements for Regulated Parties - 1090.17x Independent Laboratories for o (a) Registration, o (b) Sampling, Testing, and retention requirements, o (c) Independence Requirements o and NOT for 'Reporting' which is an identified cost element in XIV. Costs and Benefits • Add a paragraph under Recordkeeping Requirements • Add back from Part 80.65 to Subpart M—Sampling, Testing, and Retention o Determination of volume and properties can be carried out either by the refiner or importer, or by a registered independent laboratory Refiner/importer may designate an alternate independent laboratory to be used when the designated laboratory is unavailable and cannot perform the testing required for compliance (closed, test methods down, personnel unavailable). Not to be used to select preferred test results. [EPA-HQ-OAR-2018-0227-0030-Al.pp.2-5] 301 ------- > Eversheds Sutherland (US) LLP We are also concerned that the surveyor is mandating participation in the additional programs such as the NSOP and the diesel survey even though EPA's proposed rules do not mandate participation. There is no transparency in why this is being mandated and what the additional cost will be to participate in a program that a company might otherwise not; EPA should prohibit the surveyor from de facto expansion of EPA's own rules and should include an explicit statement that the surveyor must stay within the parameters of EPA's regulations. Details of the new NSOP were not previously known by many survey members and appear to put a significant burden on the fuel manufacturer that EPA does not seem to have considered. The proposed requirement that the NSOP must be conducted at each gasoline manufacturing facility of all participating gasoline manufacturers is burdensome, especially for blending manufacturers, and the initial estimated annual cost at $10,000 per facility would be a significant new compliance cost. For a fuel manufacturer who imports into several PADDs and has multiple blending locations in the Gulf and Northeast, the potential price tag adds up quickly and is contrary to EPA's efforts to lessen compliance burdens. In the first instance, EPA should maintain the independent laboratory designation and registration, and have the surveyor coordinate random sampling and testing of the independent laboratories in lieu of adopting a new, burdensome and likely expensive NSOP. Such random sampling would, in fact, be a streamlined effort that places the least burden on all parties while achieving the oversight (and random nature of the oversight) that EPA is looking for. Sometimes a "less is more" approach is the right one, and this is such a case. In contrast, the NSOP is not well vetted or conceived, is being created pursuant to draft and proposed regulations, and picks one winner in the surveyor while placing fuel manufacturers in a position where they have to go along or they will be out of compliance on day one of the implementation of Part 1090. EPA should reconsider its approach and adopt a simpler but more effective solution—and one that will be ready and understood on day one. [EPA-HQ-OAR-2018-0227-0076-A1, pp.14] > Flint Hills Resources 12) Part 1090 Preamble X.B. National Sampling and Testing Oversight Program Suggestion: Do not require all third-party laboratories to register with EPA. And, do not prohibit fuel manufacturers from using multiple third-party laboratories. Discussion: In the preamble, EPA provides an overview of its proposed National Sampling and Testing Oversight Program and seeks comment on all aspects the program. Specifically, EPA explains its rationale for no longer requiring laboratories to register under part 1090, except in the limited case where a third-party laboratory is acting as a report-submitting agent on behalf of a regulated party. We support EPA's approach of not requiring third party laboratories to register as a prerequisite to a regulated party using the third party for laboratory sampling and testing services. EPA also discusses a concern expressed by some stakeholders that "replacing the RFG independent laboratory testing program with the proposed voluntary national sampling oversight 302 ------- program would allow for parties to more easily arrange for favorable test results that demonstrated a fuel met EPA fuel quality standards." We do not share this concern. EPA has effectively prohibited this kind of behavior in that anyone responsible for testing is required to follow good laboratory practices for all required testing. "Shopping around" for favorable test results is contrary to good laboratory practice and would be a failure to meet that requirement. Further, a fuel manufacturer is responsible for any testing that is performed on its behalf. This is true whether the testing is performed by the manufacturer's on-site laboratory or performed by a third-party laboratory. Restricting fuel manufacturers to using a single third-party laboratory could be a burden and a constraint. Fuel manufacturers should not be limited in which laboratory or laboratories it chooses to use provided that the regulatory requirements for testing are met. [EPA-HQ-OAR-2018-0227-0052-Al.pp.7-8] > Shell Oil Products US D. Preamble - X. Proposed Third-Party Survey Provisions - Third Party Lab Registrations Not Needed Preamble states: Therefore, we seek comment on whether we should require that all third-party laboratories register and that refiners be limited to using a specified, registered third-party laboratory. We disagree with the suggestion to require third party lab registration requirements for conventional and reformulated gasoline manufacturers. This requirement is a burden and a constraint. Many gasoline manufacturers test their own product but, in the event, that their equipment is out of service, a third party lab must be used. The industry needs flexibility to choose a lab at that appropriate time and situation and not be constrained on what lab can be used. Gasoline manufacturers need the flexibility to move to different third party labs for when a lab is not meeting their performance/customer needs without having to go into CDX and make a registration change. There have been recent instances of third party lab closures with short notice which is another reason that flexibility is needed. [EPA-HQ-OAR-2018-0227-0035-A1, p.5] > TIC Council Americas 1) The current regulations would eliminate the important role that Independent Laboratories have long played in the fuels compliance arena, assisting their clients in understanding and complying with EPA Regulations and positively influencing environmental / air quality gains. We believe the benefits of preserving the existing role of the independent laboratory far outweigh any industry cost savings which their elimination might provide; thus we hereby request the reinstatement of the EPA registered Independent Laboratory designation for compliance testing. The independent laboratories have been and should remain an integral part of EPA's regulatory compliance structure. While we can detect no substantial cost associated with this reinstatement request, such an action would provide many benefits including maintaining data traceability and accessibility, and would further support the formidable advances made in the industry's overall quality control efforts. 303 ------- We fully support an approach that would eliminate the requirement for independent labs to submit corroborating data to the EPA. We believe, however, it is important to continue to safeguard the data, and its traceable association to the registered oil company that has designated the EPA registered lab for testing. The independent laboratory's involvement in the process has included crucial guidance and education of novice industry participants, helping to ensure they more closely abide by EPA's procedures. In order to maintain air quality, it is important to detect compliance issues prior to any gasoline products entering the marketplace. We believe that both the timing and the reduction in sampling/testing will negatively impact non-compliance detection rates and overall air quality. [EPA-HQ-OAR-2018-0227-0039-A1, pp. 1-2] In closing, we reaffirm that the TIC Council supports the EPA's efforts to streamline fuels regulations but urge the Agency to maintain the requirement for EPA registered and designated Independent Laboratories to both ensure unbiased oversight and compliance and to minimize any negative environmental impact. [EPA-HQ-OAR-2018-0227-0039-A1, p.2] Response: While we appreciate the concern of ensuring integrity in the sampling and testing of fuels for determining compliance with EPA fuel quality standards, we do not believe that the RFG independent lab testing requirement should be maintained, nor that we should require the registration of all third-party laboratories. We believe the PBMS/SQC provisions originally promulgated in Tier 3, which are being transposed and updated in part 1090, provide adequate oversight over sampling and testing at labs to perform testing for fuels compliance. We also believe that the NSTOP will further help ensure that labs are sampling and testing in a manner consistent with EPA requirements. Finally, we believe the updates to the attest engagement procedures to have attest auditors verify the existence of PBMS qualification and SQC records will provide additional oversight. Taken together, these provisions should allow sufficient independent oversight for adherence to the sampling and testing provisions. Furthermore, we believe that maintaining the independent lab testing requirement for RFG only creates unnecessary disparity between the treatment of RFG manufacturers and CG manufacturers. One of the goals of this action is to reduce the complexity of the various programs by consolidating the various provisions into a single set of regulatory requirements that apply consistently to regulated parties. We do not believe that treating RFG manufacturers and CG manufacturers differently with regards to how sampling and testing is conducted is necessary and that the PBMS/SQC, NSTOP, and attest engagement requirements provide both sufficient oversight and equal treatment of all gasoline manufacturers. We also believe that requiring third-party laboratories to register and have gasoline manufacturers designate registered laboratories, as suggested by some commenters, is unnecessarily burdensome. Such a requirement would require hundreds of new registrants and hundreds of new registration updates by all gasoline manufacturers for little benefit. Requiring gasoline manufacturers to designate a lab and use only that lab could create disruptions in the production and distribution of fuels if there is an issue that causes the lab to be unable to complete testing. Such situations have occurred occasionally under the RFG program and have 304 ------- resulted in substantial pressure on the gasoline manufacturer and EPA to submit and process registration updates so that testing could resume. Again, we believe that the oversight mechanisms in part 1090 are sufficient to ensure that fuel manufacturers and their third-party labs conduct sampling and testing for compliance in a robust and consistent manner. As such, we are removing the RFG independent lab testing requirement and replacing it with the NSTOP, as proposed. Comment: > bp America Inc. (bp) §1090.1440 National Sampling oversight program requirements §1090.1440(a) states that a gasoline manufacturer with an in-line blending waiver is not required to participate in the national sampling oversight program to account for the oxygenate added downstream in §1090.710. §1090.1440(b) states that other gasoline manufactures may elect to participate in the national sampling oversight program for purposes of establishing affirmative defense to a violation under §1090.1720. bp recommends adding a statement in §1090.1440(a) (2) stating that a gasoline manufacturer with an in-line blending waivers does not need to be part of the national sampling oversight program in order to qualify for affirmative defense under §1090.1720. Conducting in-line blending with an EPA approved in-line blending waiver and meeting the auditor requirements under §1090.1850 provides equivalent assurance as the national sampling program and is sufficient to justify the request for an affirmative defense. bp suggests that EPA make the following edits to the proposed regulations: §1090.1440(a) National sampling oversight program participation. (1) Except for gasoline manufacturers that have an approved in-line blending waiver under §1090.1315, any gasoline manufacturer that elects to account for the addition of oxygenate added downstream under §1090.710 must participate in the national sampling oversight program in this section. (2) Other gasoline manufacturers may elect to participate in the national sampling oversight program for purposes of establishing an affirmative defense to a violation under §1090.1720. However, gasoline manufacturers that have an approved in-line blending waiver under §1090.1315 can establish an affirmative defense to a violation under §1090.1720 without participating in the national oversite sampling program. [EPA-HQ-OAR-2018-0227-0046-A1, pp.29-30] Response: We have added the suggested clarification to §1090.1450(a). Comment: > Motiva Enterprises, LLC Participation in NSOP while operating under an in-line blending waiver 305 ------- On pages 188 to 189 of the preamble under section XIII.G. EPA explains the process and timeline for new in-line blending applications. Under section 1090.1440 (a) (1) of the Fuels Streamlining Draft, EPA states that "Except for gasoline manufacturers that have an approved in- line blending waiver under §1090.1315, any gasoline manufacturer that elects to account for the addition of oxygenate added downstream under §1090.710 must participate in the national sampling oversight program in this section." Motiva asks for clarification from EPA regarding participation in the NSOP while operating under an in-line blending waiver. If a refinery has an in-line blending waiver in place, is it exempt from NSOP if situational tank certifications are performed at the refinery? [EPA-HQ- OAR-2018-0227-0073-A1, p.4] Response: We appreciate the commenter's request for clarification regarding how in-line blending waivers interact with NSTOP participation. Unless the gasoline manufacturer has an in-line blending waiver for the entire facility's gasoline production, the gasoline manufacturer must participate in the NSTOP. In the case where a gasoline manufacturer has situational tank certification as part of their in-line blending waiver (e.g., as a contingency to mechanical issues with in-line blending equipment or analyzers), if the in-line blending waiver covers all of the gasoline production at the facility, the gasoline manufacturer would be exempt from participation in the NSTOP. Comment: > Eversheds Sutherland (US) LLP In the event EPA moves forward, we have the following additional comments. Under the NSOP, the proposal states that the program must be conducted at each gasoline manufacturing facility from all participating gasoline manufacturers44 and that a winter and summer sample must be taken. EPA needs to address situations where there is not production in both seasons, or when there is only one or just a few blending events at one facility, and the surveyor is not able to sample those or the fuel manufacturer's expectation for future activity changed prior to scheduling the surveyor. Our suggestion that EPA instead have the surveyor randomly sample and test the laboratories would address these issues directly. Imports should not be included in the NSOP as having to arrange for the surveyor to attend the sampling and testing will delay vessels even further (see other comments herein) risking port safety as well as incurring demurrage costs. At the very least, import laboratories could be randomly sampled to avoid these concerns. None of these issues should result in the surveyor being able to report to EPA that there was "any refusal" to allow samples to be taken under § 1090.1440(c) (2) (iii). EPA should also delete the onerous outcome that "any refusal" results in EPA considering that the fuel manufacturer is no longer participating in the NSOP; this gives the surveyor unprecedented power over the fuel manufacturer that only belongs to EPA after EPA has itself investigated whether there truly was a refusal. The Proposed Rule calls for samples to be shipped to an EPA-approved lab and a subset to the EPA National Vehicle and Fuel Emissions Laboratory.45 The cost of this shipping will 306 ------- undoubtedly be passed to the fuel manufacturers, once again increasing their costs. Additionally, we are concerned that shipping throughout the year and with various handling of the samples that the accuracy of subsequent testing will be impacted. This may result in false non-compliance due to external factors outside of the fuel manufacturer's control. Meanwhile, local laboratory testing as done now is more accurate. Again, an oversight program could just be set up in conjunction with the independent laboratories to maintain accuracy. As noted in the beginning of our comments, EPA should not push to finalize this rule when there are many critical issues, such as the survey and oversight programs, that would benefit greatly from further dialogue between EPA and industry—and necessary modification. EPA's workshop in 2018 was incredibly successful in that regard, but the Proposed Rule has changed considerably since that initial draft (and rightly so) such that robust interaction where parties have the opportunity to hear the others' comments will make such a broad sweeping rule strong and clear. [EPA-HQ-OAR-2018-0227- 0076-A1, pp.14-15] 44 Id. at§ 1090.1440(c)(2) (i). 45 Id. at§ 1090.1440(c)(2) (v). Response: We believe that having NSTOP samples shipped to EPA's NVFEL provides a necessary oversight element and will not substantially increase costs of the program. Concerning costs, several hundred fuel samples are currently sent from RFG refiners to NVFEL each year under part 80. We anticipate that fewer samples will be sent to NVFEL than is currently required under the part 80 RFG oversight program, which will, if anything, result in a small decrease in collective burden of the NSTOP versus part 80 requirements. Additionally, it is worth noting that the primary cost in terms of time and money for the NSTOP will be the cost to have an independent surveyor visit a fuel manufacturing facility to obtain samples. Having the independent surveyor collect an additional sample and ship that to NVFEL represents a very small marginal increase in costs since the independent surveyor will already have gone through the expense of visiting the fuel manufacturing facility. Concerning value, we believe that it will be necessary to have NVFEL help resolve cases where test results from the independent surveyor's lab disagree with the fuel manufacturer's lab. Without having this third result, it will be difficult for us to determine whether there is an issue with the fuel manufacturer's test result or the independent surveyor's lab. Therefore, we are finalizing the provisions that some NSTOP samples will be sent to NVFEL as proposed. Comment: > Phillips 66 Company National Sampling Oversight Program We ask EPA to revise the number and frequency of site visits for the first year of the program (2021) to ensure that all refineries are fully prepared for the program. The result would be that 307 ------- the initial site visits would not occur until the summer sampling period in 2021 and would be limited to 1 summer and 1 winter. According to a presentation by the RFGSA, under the current program design, a majority of the facilities will have 3 site visits during the year (estimated 350 facilities and 1000 events per year) and would be scheduled to commence January 1, 2021. In order to try and be ready by January 1, 2021, the Survey Association is asking for all facilities to register and complete questionnaires by August 1st and October 31st respectively. Refinery personnel will need to be trained on use of the system (uploading documents, responding to issues, etc.). Sites will need to develop protocols for these site visits so that the inspectors can come into the refinery and conduct the inspection without delays. In order to assure all facilities are ready to meet these new administrative requirements, we believe postponing the first site visits until the summer, versus January, would be beneficial. The program would be able to assume the higher number of site visits in the second year, 2022. EPA had asked for input on whether there were provisions that would need delayed implementation timing and we think this is one area where delayed timing is needed. [EPA-HQ- OAR-2018-0227-0060-A1, p.6] Response: We are requiring only one site visit per facility occur for the 2021 compliance period due to the delayed implementation date for the NSTOP of no later than June 1, 2021. We believe that it would be too difficult for the independent surveyor and participating fuel manufacturers to comply with the minimum two site visits annual requirement in only 7 months, especially during the first year of the program. For 2022 and subsequent compliance periods, the two site visit requirement must be fulfilled. 308 ------- 17. Labeling and Refueling Hardware (Subpart P) 17.1. Refueling Hardware Requirements for Dispensing Facilities Comment: > Ingevity Corporation 1. 40 CFR § 1090.1550 (a) Nozzle Specifications Comment: The preamble explains that the intent of this provision is to simplify the units to all metric and to move to part 1090 from part 80. The complication is that the proposed specifications are not fully consistent with those of SAE 1285 or ISO, as shown below, and could lead to potentially greater confusion: [See the table found on p. 2 of Docket number EPA-HQ-OAR-2018-0036-A1.] Recommendation: The nozzle design specifications should be aligned more closely with those in the consensus standards. It is most likely that nozzle manufacturers in the U.S. market manufacture nozzles for U.S. gasoline dispensing facilities that meet the SAE specifications. Response: The proposed regulations only included adjusted wording and measurement units to describe nozzle design specifications that are aligned with regulatory requirements that apply under our CAA authority; we did not propose to change the underlying requirement for nozzles to meet these existing specifications. As a result, this comment is outside the scope of this rulemaking. We encourage industry efforts to standardize hardware specifications in a way that reduces undesirable variability and limits compatibility across industries. Comment: > Ingevity Corporation 2. 40 CFR § 1090.1550 (b) In-use Dispensing Rates for Heavy-duty Gasoline Vehicles (HDGVs) Comment: In the Enhanced Evaporative Emission final rule from 1993, EPA implemented an in- use dispensing rate limit of 10 gallons per minute (gpm) for retail and wholesale purchaser- consumers for gasoline dispensing facilities.1 In the same rule, EPA implemented a vehicle refueling spit back test procedure and emission standard to be conducted at the 10 gpm dispensing rate for LDVs, LDTs, and HDGVs < 14,000 lbs. GVWR. HDGVs > 14,000 lbs. GVWR were not covered by the new spit back standard because it was believed that their fuel tanks are typically designed with filler necks so short that fuel can be dispensed directly into the fuel tank. These vehicles were not expected to experience spit back. Using this same reasoning, 309 ------- dispensers dedicated to heavy-duty vehicles were exempted from the 10 gpm limit. An example here would be a centrally-fueled fleet. Preceding the Enhanced Evaporative Emission final rule mentioned above, the test procedure in EPA's 1987 NPRM related to control of refueling emissions through Onboard Refueling Vapor Recovery (ORVR), included a maximum dispensing rate of 10 gpm for certification testing, meaning the system would have to operate properly and meet the refueling emission standard while being refueled at that rate.2 The EPA refueling emission standard, test procedure and related provisions for LDVs and LDTs were adopted in 1994, and in several subsequent rulemakings these refueling emission control requirements were extended to all HDGVs of 14,000 lbs. GVWR or less.3,4,5 The Tier 3 final rule extended the refueling emission control requirement to all HDGVs between 10,000 and 14,000 lbs. GVWR for the 2018 model year and complete HDGVs over 14,000 lbs. GVWR for the 2022 model year using the same emission standard, test procedures and related provisions as apply to gasoline-fueled LDVs, LDTs, and HDGVs under 10,000 lbs. GVWR.6 The basic concern is that the in-use dispensing rate limit of 10 gpm needs to also apply to HDGV fueling points. Otherwise, there will be a disconnect between the dispensing rate used for designing and testing the HDGV ORVR system (10 gpm) and that encountered in use which could be greater than 10 gpm. The spit back standard does not apply to HDGVs over 14,000 lbs. GVWR. Alignment between the certification and in-use dispensing rate limits will help ORVR systems to function as designed and will eliminate the need to apply the vehicle refueling spit back standard to HDGVs over 14,000 lbs. GVWR. Recommendation: In § 1090.1550 (b), eliminate the clause "... heavy-duty vehicles or... " from the third sentence. In-use dispensing rate limits are needed for HDGV ORVR. [EPA-HQ-OAR- 2018-0227-0036-Al.pp.2-3] 1 US EPA, "Evaporative Emission Regulations," 58 FR 16001, March 24, 1993. 2 US EPA, "Refueling Emission Regulations for Gasoline-Fueled Light-Duty Vehicles and Trucks and Fleavy-Duty Vehicles; Notice of Proposed Rulemaking," 52 FR 31161, August 19, 1987. 3 US EPA, "Refueling Emission Regulations for Light-Duty Vehicles and Light-Duty Trucks," 59 FR 16261, April 6, 1994. 4 US EPA, "Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements, " 65 FR 6697, February 10, 2000. 5 US EPA, "Control of Emissions of Air Pollution from 2004 and Later Model Year Heavy-Duty Highway Engines and Vehicles; Revision of Light-Duty On-Board Diagnostics Requirements," 65 FR 59895, October 6, 2000. 6 US EPA, "Tier 3 Motor Vehicle Emission and Fuel Standards," 79 FR 23412, April 28, 2014. 310 ------- Response: We did not propose any changes to these requirements, but simply proposed to transfer the existing regulatory provisions from §80.22 into part 1090. Therefore, this comment is outside the scope of this rulemaking. We expect to revisit this question in an appropriate future rulemaking. 311 ------- 17.2. Refueling Hardware Requirements for Motor Vehicles Comment: > Ingevity Corporation 3. 40 CFR §§ 1810-17(i) and 1037.115(c) Vehicle Refueling Nozzle Inlet Diameter Specifications Comment: The NPRM proposes to add a new subparagraph § 1810-17 (j) and to revise § 1037.115(c) related to vehicle refueling nozzle inlet diameter specifications for LDVs/ LDTs and HDGVs, respectively. It is not clear if the diameter value proposed for each (24 mm) is simply a nominal value or if it is traceable back to SAE J285. The concern arises because the nozzle spout diameter value in paragraph 4.1.2.1 of SAE J285 for light-duty compression ignition fuel nozzles (diesel fuel) is 23.6/23.8 mm creating the possibility for inadvertent misfuelling of gasoline vehicles with diesel fuel if the vehicle refueling inlet diameter for a gasoline-fueled LDV/LDT is 24 mm. Recommendation: Referring first to 40 CFR § 1810-17 (j), the proposed nozzle spout diameter for gasoline nozzles is 21.3 mm so the 24 mm value for the gasoline-powered LDVs/LDTs, and HDGVs less than 14,000 lbs. GVWR may be acceptable for these vehicles which are ORVR- equipped and usually use underbody mounted tanks and traditional fill pipes. However, EPA should consider reducing the vehicle refueling nozzle inlet diameter specification for gasoline- powered LDVs/LDTs and HDGVs less than 14,000 lbs. GVWR to less than 23.6 mm to help prevent inadvertent misfuelling with diesel fuel. Referring to 40 CFR § 1037.115(c), the proposed 24 mm value may be problematic for HDGVs >14,000 lbs. GVWR without ORVR (incomplete vehicles) which use side-mounted metal tanks (step, D, or rectangular design) since they traditionally have tank refueling openings of 50.8 mm (2 inches) or more. For HDGVs >14,000 lbs. GVWR we recommend that the specification not inadvertently force smaller than normal fuel tank nozzle inlet openings for non-ORVR designs. We also recommend that this issue (including concerns for diesel misfuelling for light and heavy-duty vehicles) be revisited more fully in the upcoming EPA NPRM related to Heavy-Duty Engine Standards. [EPA-HQ-OAR-2018-0227-0036-A1, p.3] Response: The commenter raises several questions about how to adapt or apply the filler-neck requirements for current and future vehicle designs. We believe it is important to address these issues in a later rulemaking. As a result, we are not finalizing any change at this time and the provisions of §80.24 will remain in part 80 and continue to apply. 312 ------- 18. Importers and Exporters (Subpart Q) 18.1. Importation Comment: > Eversheds Sutherland (US) LLP Imports The preamble of the Proposed Rule states that the importer under Part 1090 would generally be the importer of record under the Bureau of Customs and Border Protection regulations.26 This is the current position based on long-standing guidance, and Eversheds Sutherland agrees that should be the case. While we do not believe the definition itself needs to make a reference to Customs' regulations, we encourage EPA to restate this position in the final rule preamble to reiterate this approach and make it clearly accessible. [EPA-HQ-OAR-2018- 0227-0076-A1, p.8] 26 Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,074. > Independent Fuel Terminal Operators Association (IFTOA) VII. Importation of Product A. Definition of Importer EPA has proposed to maintain the current definition of the term "importer." The Association supports this approach because the term should be consistent with the definition used by Customs and Border Protection. Retaining such consistency avoids any confusion between the two regulatory regimes and long-standing commercial obligations relied upon by the petroleum industry. [EPA-HQ-OAR-2018-0227-0064-A1, p.4] Response: We thank the commenters for their support. 313 ------- 18.2. Special Provisions for Importation by Rail or Truck Comment: > Exxon Mobil Corporation Compliance Options for Imported Volume by Rail Car and Tank Truck ExxonMobil requests that EPA modify section §1090.1610 to allow an additional third option to meet sampling / testing requirements under Subpart M for rail car and tank truck imported fuels. We believe Options 1 & 2 (listed below) are present in the NPRM, but we are discussing them here for context with the proposed regulatory language for the additional Option 3 presented below: Option 1: Use third party source tank sampling/testing data for compliance; gasoline must meet cap of 10 ppm sulfur and 0.62 volume percent benzene. This option is clear under §1090.1610(a),(b),&(c) and provides conditions to meet sampling/testing requirements under Subpart M for railcars and tank trucks where the supplier is a third party and unassociated with importer. Option 2: We interpret that under §1090.1335(b)(3) an importer may conduct manual sampling of fuels directly from rail cars and tank trucks, following practices detailed in ASTM D4057. The test results from these samples would represent batch properties corresponding to each rail car and/or tank truck and would then be reported to EPA. Once test results are obtained, compliant fuel may then be discharged directly into commerce or fungible storage for distribution. Option 3: Fuel imported by rail car/tank truck directly into domestic storage tanks for compliance sampling/testing. ExxonMobil offers the following amended regulatory language in §1090.1610, similar to §1090.1605(d): §1090.1610 (d) Importers by railcar and tank trucks may offload fuel, fuel additive, or regulated blendstock into storage tanks containing the same fuel, fuel additive, or regulated blendstock if the importer meets the following requirements: (1) For gasoline, importers must offload gasoline from rail cars or tank trucks into one or more empty storage tanks or tanks containing PCG that the importer owns or leases. (i) If importers offload gasoline into one or more empty storage tanks, they must sample and test the sulfur and benzene content, and for summer gasoline, RVP, of each storage tank into which the gasoline was offloaded. (ii) If importers offload gasoline into one or more storage tanks containing PCG, they must: 314 ------- a) Sample the PCG already in the storage tank prior to offloading gasoline from the marine vessel. Test the sulfur and benzene content, and report this PCG as a batch with a negative volume. b) After offloading the gasoline into the storage tanks, the importer must (1) Sample and test the sulfur and benzene content, and RVP for summer gasoline, of each storage tank into which the gasoline was offloaded and (II) Report the volume and sulfur and benzene content as a positive batch. (2) For all other fuel, fuel additive, or regulated blendstock, importers must sample and test the fuel, fuel additive, or regulated blendstock in each storage tank into which it was offloaded. Importers must ensure that all applicable per-gallon standards are met before the fuel, fuel additive, or regulated blendstock is shipped from the storage tank. [EPA-HQ-OAR-2018-0227- 0049-Al.pp.2-3] Response: We believe that the option for certification of gasoline imported by rail or truck (namely, the option to offload the gasoline or diesel into storage tanks and then to sample and test the fuel using the compliance by subtraction approach) is currently available under part 80 and it was not our intent to eliminate this option. We have added this third option to §1090.1610(d) as the commenter suggested. Comment: > Suncor Energy (U.S.A.) Inc. Gasoline Importer Standard Change. Under 40 C.F.R. Part 80.195, 80.1603, and 80.1230, EPA requires both gasoline producers and importers meet the same annual average standards and per- gallon cap associated with sulfur and benzene concentrations. In Part 1090, EPA duplicated the alternative sampling and testing requirements in Part 80.583 (NRLM imports via truck or rail car) to gasoline imported via truck or rail car. Even though the streamlining requirements in Part 1090.1610 for gasoline truck and rail car imports eliminate the burden of sampling and testing every truck or rail car, EPA has effectively changed the standard for these imports such that it must meet both the sulfur and benzene annual average standards on a per gallon basis: 1090.205 (d) Sulfur standard for importers that import gasoline by rail or truck. Importers that import gasoline by rail or truck under §1090.1610 must comply with a maximum sulfur per- gallon standard of 10 ppm instead of the standards in paragraphs (a) through (c) of this section. 1090.210 (c) Benzene standard for importers that import gasoline by rail or truck. Importers that import gasoline by rail or truck under §1090.1610 must comply with a 0.62 volume percent benzene per-gallon standard instead of the standards in paragraphs (a) and (b) of this section. [EPA-HQ-OAR-2018-0227-0067-A1, p.l] 315 ------- Contrary to EPA's express intent of the Proposed Rulemaking requiring sulfur and benzene compliance on a per gallon basis is significantly more restrictive. The per gallon compliance requirement also decreases the number of options for supplying gasoline to the U.S. via imports since not all foreign fuel manufacturers can meet the requirements on a per gallon basis. EPA did not explain why this change is necessary; Suncor requests that it do so or offer an alternative requirement that abates EPA's concerns while preserving the current gasoline sulfur and benzene annual average standards for imports. [EPA-HQ-OAR-2018-0227-0067-A1, pp. 1-2] Response: We do not believe that we are making compliance more restrictive for truck and rail importers of gasoline, as we are not changing the per gallon standards for truck importers of gasoline from those that already exist under §§80.1349 and 80.1641. We are, however, revising the regulations only to clarify that rail and truck importers that wish to take advantage of the flexibilities of §1090.1610(a) are required to meet the per-gallon sulfur and benzene standards specified at §§1090.205(d) and 1090.210(c). Comment: > Valero Energy Corporation G. Import of Fuels. Fuel Additives and Blendstocks Proposed § 1090.205(d) Sulfur Standards and §1090.210(c) Benzene Standards provide as follows: (d) Sulfur standard for importers that import gasoline by rail or truck. Importers that import gasoline by rail or truck under §1090.1610 must comply with a maximum sulfur per-gallon standard of 10 ppm instead of the standards in paragraphs (a) through (c) of this section. (c) Benzene standard for importers that import gasoline by rail or truck. Importers that import gasoline by rail or truck under §1090.1610 must comply with a 0.62 volume percent benzene per-gallon standard instead of the standards in paragraphs (a) and (b) of this section. The current regulations in Part 80 (§80.65) provide that: "Standards must be met on either a per- gallon or on an average basis." Although the proposed changes appear to continue to provide the option to comply on a per-gallon basis or on an average basis, it does not for the importer and supplier that are affiliated companies. Instead, as written, the rule unnecessarily and unreasonably excludes truck and rail imports from the annual averages for sulfur and benzene and imposes the per-gallon standard. In a prior draft of the proposed regulations, it did not appear that EPA intended to do this. The draft used "may" instead of "must" for rail and truck imports in the per-gallon standards. Valero requests that EPA revise this provision to ensure that the means of compliance and the applicable standard does not change for importers that are affiliated with suppliers who can meet the testing requirements of Subpart M. §1090.200(c) provides: 316 ------- 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, except for truck and rail importers using the provisions of §§1090.205(d) and 1090.210(c)... §1090.205(d) and 1090.210(c) requires imports meet a per-gallon standard and other requirements in §1090.1610. §1090.1610 exempts importers from Subpart M sampling and testing but imposes different sampling, testing and document retention requirements. For importers affiliated with suppliers that meet the sampling, testing and document retention requirements under Subpart M, the exemption is not needed. The importer should be able to show compliance under §1090.200. Valero requests that EPA add a provision to §§1090.200, 1090.205 and 1090.210 as follows: Gasoline imported by truck or rail by a fuel manufacturer from a corporate affiliated supplier may show compliance under §1090.200(c), instead of §§1090.205(d) and 1090.210(c), if the affiliated supplier meets the requirements of Subpart M and compliance is demonstrated with the affiliated supplier origin tank certificate of analysis. If the importer and supplier are affiliated companies then the certification for the product in tank should satisfy the batch sampling and testing requirements in Subpart M provided the trucked volume can be associated with a specific tank quality/certification. This should satisfy the EPA batch sampling and testing requirements for compliance with the annual average standard. Valero understands the alternative sampling and testing requirements in §1090.1610 are intended for importers purchasing product from a third party supplier to minimize sampling and testing frequency, yet demonstrate compliance with the fuel standards and provide a level of QA/QC on the third party supplier. Importers who source their product internally (from an affiliated company) should not be subject to the truck importer requirements as the fuel quality and certification is managed by the same procedure as all gasoline production at domestic facilities and marine receipts. [EPA-HQ-OAR-2018-0227-0056-A1, pp.7-9] Response: It would be difficult for EPA to investigate compliance with sampling and testing requirements conducted outside of the U.S., regardless of whether the sampling and testing was conducted by third parties or by domestic companies. As such, we do not believe it is appropriate to allow the sampling and testing flexibilities the commenter requested. Therefore, we are finalizing these provisions as proposed. 317 ------- 18.3. Special Provisions for Importation by Marine Vessel Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.12 Importer and Exporter Provisions There is misalignment between the preamble and regulatory language regarding marine vessel imports.21 The preamble lists three scenarios where a single composite batch can be reported. Those scenarios include a homogeneous ship compartment, ship compartments discharged to a single shore tank, or each individual vessel compartment is shown, through sampling and testing, to meet all applicable standards. The second and third options are not present in the regulatory text. This misalignment can be easily be corrected with the following edits to 1090.1605: § 1090.1605 Importation by marine vessel. Importers that import fuel, fuel additive, or regulated blendstock using a marine vessel must comply with the requirements of this section. (a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at each port, unless the fuel is transported by the same vessel making multiple stops but does not pick up additional fuel. (b)(1) Except as specified in paragraph (d) of this section, importers must certify each fuel, fuel additive, or regulated blendstock while it is onboard the vessel used to transport it to the United States, and certification sampling must be performed after the vessel's arrival at the port where the fuel, fuel additive, or regulated blendstock will be offloaded. (2) Importers must sample each compartment of the vessel and either treat each compartment as a separate batch or combine samples from separate compartments into a single, volume-weight composite sample using ASTM D4057 (incorporated by reference in §1090.95) and demonstrates that the fuel, fuel additive, or regulated blendstock is homogeneous across the compartments under §1090.1337. [EPA-HQ-OAR-2018-0227-0074-A1, pp.22-23] 21 See proposed § 1090.1605 - Importation by marine vessel. > CITGO Petroleum Corporation (CITGO) 3.4 Importer and Exporter Provisions 318 ------- In §1090.1605, there is inconsistency between the preamble and regulatory language regarding marine vessel imports. The preamble lists three scenarios where a single composite batch can be reported: (1) Demonstration of homogeneity across the compartments (2) When all compartments are off-loaded into a single shore tank (3) When each compartment is shown, through sampling and testing, to meet all applicable standards However, option three is not drafted in the regulatory text in §1090.1605. This inconsistency can be easily corrected with the following edits to §1090.1605: §1090.1605 Importation by marine vessel. Importers that import fuel, fuel additive, or regulated blendstock using a marine vessel must comply with the requirements of this section. (a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at each port, unless the fuel is even if it is transported by the same vessel making multiple stops but does not pick up additional fuel. (b) (2) Importers must sample each compartment of the vessel and either treat each compartment as a separate batch unless the importer collects and combines or combine samples from separate compartments into a single, volume-weight composite sample using ASTM D4057 (incorporated by reference in §1090.95) and demonstrate that the fuel, fuel additive, or regulated blendstock is homogeneous across the compartments under §1090.1337. [EPA-HQ-OAR-2018-0227-0054-A1, pp.13-14] Response: We have revised §1090.1605 as the commenters suggested. Comment: > Eversheds Sutherland (US) LLP Under the Proposed Rule, fuel additive or regulated blendstock must be certified at each port of entry if imported by vessel, even if the same vessel is making multiple stops.27 Once certified, the product may be transferred to shore tanks or terminals located in any harbor and are not restricted to terminals located in the harbor where the vessel is anchored. The proposed regulations provide the example of certified gasoline that could be transferred from an import vessel anchored in New York harbor to a lightering vessel and transported to Albany or Providence without having a separate certification.28 Subject to our further comments below on sampling and testing, Eversheds Sutherland agrees with this language that continues the 319 ------- requirements currently in place for gasoline and that allows for one certification at each port even where there are multiple receiving terminals. In contrast and as further discussed below, this is a new requirement for diesel fuel as there is no current requirement to test at each port for ULSD or ECA Marine Fuel, and EPA should not adopt this new burden. No rationale has been provided in the preamble for this expansion, and we are unaware of any compliance issues under the current rules, which have been in place for an extended period of time, that supports adopting this new burden. EPA should maintain the current requirements unless and until these changes are justified and necessary. 27 Proposed Rule at § 1090.1605(a). 28 Id. at § 1090.1605(c). > Marathon Petroleum Company LP (MPC) Importation by Marine Vessel 1090.1605(a) Importers must certify each fuel, fuel additive, or regulated blendstock imported at each port, even if it is transported by the same vessel making multiple stops. Language contrary to this exists on Page FR29074 of the Preamble saying, "Under part 1090, separate certification would be required at each import facility, unless the fuel is transported by the same vessel making multiple stops but does not pick up additional fuel." It would be preferred to follow the Preamble language and revise part 1090. [EPA-HQ-OAR- 2018-0227-0048-A2, p.2] Response: We have revised §1090.1605 (a) to state that vessels that do not pick up additional fuel do not have to certify the fuel again. Comment: > Eversheds Sutherland (US) LLP In § 1090.1605(c), EPA should add the example of a barge lightering from a vessel where only the barge is imported such that the barge is tested and the resulting certificate of analysis is used for certification purposes. [EPA-HQ-OAR-2018-0227-0076-A1, pp.10] Response: We believe that the proposed regulations were clear as written and that it is not necessary to add the example the commenter suggested. As such, we are finalizing the regulations as proposed. 320 ------- Comment: > Eversheds Sutherland (US) LLP Import Sampling and Testing The Proposed Rule should allow importers use a vessel composite where it demonstrates that each compartment meets applicable standards, as it allowed currently for RBOB imports.29 The Proposed Rule requires all fuels to remain on the vessel until test results are received.30 Eversheds Sutherland requests that EPA follow current rules here and not expand regulatory requirements and burdens. A primary goal that EPA has stated for streamlining is to cut down on sampling and testing and the associated cost and time that industry and EPA incurs. By breaking with longstanding policy and requiring sampling and testing for all fuel imports and delaying offloading until all results are received, EPA will increase burden and costs despite the current protocol working well. Even by "only" requiring testing of sulfur and RVP (in the summertime) for CG/CBOB, it will take approximately 8-10 hours to run the test on all vessel compartments if required for homogeneity, which is in addition to the time needed to merely collect and transport the samples for each compartment. These testing and time delays equate to delays in bringing gasoline supply to the marketplace. Additionally, there is currently ample testing, including the loadport COA and testing of the receiving tank before discharge and after discharge of the imported gasoline. While the loadport COA cannot be used to show compliance in the United States, it provides a good understanding of the fuel's specifications and an indication of whether the fuel may need further blending or not. Also, many importers import fuel from the same source repeatedly, which gives the importer even more understanding of the properties of the fuel. This data is considered by the importer when it determines whether to certify on board or GTAB the fuel. If this is what EPA considers to be an "engineering assessment" that supports the movement of fuel prior to receiving test results,31 then importers are already making such assessments under the current rules. To require an account for "varying refinery processes, maintenance or other system changes or personnel changes"32 is an extreme and impractical suggestion that aims to address a problem that does not appear to exist under the current rules, and thus should not be the adopted policy. In addition to the time delays and costs of the sampling and testing itself, there will be vessel demurrage costs as the vessel must sit for longer periods of time at the port; demurrage costs can be quite high, running from $20,000 to $80,000 per day. Some stakeholders have pointed out that there may be safety concerns in having more vessels sit in the harbors for longer periods and to have more inspectors moving back and forth from the vessel to the lab. EPA should consult with the port authorities on the increased traffic that the additional testing and waiting will cause to ensure that safety and security are not compromised. But, in the first instance, Eversheds Sutherland requests that EPA modify the Proposed Rule at proposed §1090.1605(b) so that these sampling and testing requirements only apply to RFG and RBOB, which is the current requirement. 321 ------- Alternatively, EPA should at the least allow for discharging of fuel, fuel additive and regulated blendstock other than RFG or RBOB into shore tanks where the product can then wait for test results before further movement—which again is consistent with the current rules. This would allow for movements to continue as they currently do and will help prevent the unnecessary delays this proposal would cause. This would also allow for remediation in the event the fuel does not meet a standard and provide the assurance that EPA seeks in this regard. [EPA-HQ- OAR-2018-0227-0076-A1, pp.8-10] 29 Id. at §1090.1605(b)(2). 30 See id. at §1090.1605(b). 31 See Fuels Regulatory Streamlining, 85 Fed. Reg. at 29,067. 32 Id. > Independent Fuel Terminal Operators Association (IFTOA) B. Importation by Marine Vessel The preamble to § 1090.1605 provides that different ship compartments would be considered different batches of fuel. As such, each compartment would have to be sampled and tested separately, imposing a significant regulatory and costly burden on importers. Therefore, EPA is proposing two exceptions to this requirement. [EPA-HQ-OAR-2018-0227-0064-A1, p.4] First, EPA would retain essentially the same exemption that is applicable under Part 80, which requires importers to certify each fuel, fuel additive, or regulated blendstock while it is onboard the vessel. The proposal would allow importers to treat the fuel in different compartments of a ship as a single batch for determining sulfur and benzene levels if they demonstrate, using appropriate test methods, that the fuel is homogeneous across the compartments. However, EPA goes on to explain in the preamble that currently under Part 80, importers must establish homogeneity for all Complex Model parameters, which could be as many as 11. Under the new § 1090.1605 (b), importers would only need to establish homogeneity for two fuel parameters (sulfur and benzene). "This change would result in a substantial decrease in testing burden." However, it appears that for the third parameter, RVP of summer gasoline, importers would still be required to test each compartment to ensure that all per-gallon standards are met. [EPA-HQ- OAR-2018-0227-0064-Al.pp.4-5] Second, EPA would allow importers to offload fuel, fuel additive, or regulated blendstock into either empty shore tanks or tanks containing the same fuel as that being offloaded from the vessel (e.g. imported gasoline being discharged into a tank containing Previously Certified Gasoline). This second approach sets forth detailed sampling and testing requirements for gasoline and all other fuels. See 1090.1605 (d). [EPA-HQ-OAR-2018-0227-0064-A1, p.5] 322 ------- The basic tenet that importers must sample each compartment of a vessel and treat each compartment as a separate batch is overly burdensome and takes an inordinately long period of time. Even if an importer can use a weighted-average composite sample to measure two of the three key parameters and even though the number of parameters will be reduced from eleven to three, the approach under the first exemption is still costly and burdensome. Sampling and testing of each compartment for RVP could result in an additional 12-hour delay. The typical laytime for a vessel (time allotted for unloading the cargo) is 36 hours. Thus, one third of the total time would be exhausted before the vessel could be discharged. Thus, this approach would add costs for the testing itself, additional time at the dock waiting for the laboratory results, and demurrage expenses which can run as high as $75,000 per day. [EPA-HQ-OAR-2018-0227- 0064-A1, p.5] Therefore, IFTOA supports EPA's proposed second alternative under § 1090.1605 (d) that would allow testing of imported product once it is discharged and placed in either empty shore tanks or those containing the same fuel. This approach would result in analyses that are precise and accurate to ensure compliance with EPA fuel quality standards. Further, it would substantially reduce the time needed for sampling and testing which would improve flexibility and reduce the associated costs. [EPA-HQ-OAR-2018-0227-0064-Al,p.5] Response: We are finalizing as proposed several provisions related to the testing of fuel imported by marine vessels under §1090.1605 that are anticipated to reduce the compliance burden and associated costs relative to the existing requirements under part 80. These include not requiring testing of benzene content before fuel is shipped and substantially reducing the burden for imported RFG and RBOB batches by reducing the number of parameters that must be tested for certification from 7 to 3 and by reducing the number of parameters that must be tested to determine homogeneity to 2. We are also finalizing as proposed that the homogeneity testing procedures for RFG and CG imports be the same. One of the goals of this action is to consolidate the various compliance provisions across the various fuel programs into a single set of provisions. The homogeneity procedures now apply consistently to all fuels certified under part 1090 regardless of whether the fuel is produced at a refinery, blended at a terminal, or imported in the United States. This consistency will help ensure compliance by reducing complexity and help ensure a level-playing field for all fuel manufacturers. We are also allowing importers to use either of the approaches outlined in §1090.1605(b) and (c) —test every compartment or test a volume weighted composite sample—or the approach outlined in §1090.1605(d) —offload the fuel into shore tanks and then sample and test the shore tanks. Some commenters may not have understood the flexibility provided and misinterpreted these provisions as potentially adding burden. However, this was not our intent, and we believe that the combination of these two approaches cover the concerns raised by the commenters. 323 ------- 18.4. Gasoline and Diesel Fuel Treated as Blendstocks Comment: > Eversheds Sutherland (US) LLP GTAB The Proposed Rule defines "GTAB" (or gasoline treated as blendstock) as imported gasoline that is excluded from the importer's compliance calculations but is treated as blendstock in a related fuel manufacturing facility such that the GTAB is included in the facility's compliance calculations. An importer may use the GTAB rules if it meets the certain criteria set forth in the Proposed Rule.33 This criteria largely tracks long-standing GTAB guidance, and therefore, Eversheds Sutherland supports its incorporation into new Part 1090, pursuant to the following comments. First, EPA should modify § 1090.1615(b) to state that after the GTAB has been "used" to produce gasoline or "certified" as gasoline; use of the term "blend" is not as clear and if there is more than one blend activity may be premature. [EPA-HQ-OAR-2018-0227-0076-A1, pp.10] 33 Proposed Rule at § 1090.1615. Response: We have revised §1090.1615(b) to clarify that GTAB may be certified as gasoline or used to produce certified gasoline. Comment: > Eversheds Sutherland (US) LLP GTAB Second, EPA has added a new provision that is not part of the long-standing guidance, which states that GTAB that is not ultimately used to produce gasoline, including tank bottoms of GTAB, must be treated as newly imported gasoline and meet all applicable requirements for gasoline.34 It is unclear what EPA's purpose is with this new language as there is no explanation in the preamble. But its result would be to require an importer to track every molecule of the GTAB that may exist in tank bottoms—both a new regulatory burden on importers and one that has no supporting rationale. It should be eliminated entirely. Pursuant to long-standing guidance and to the Proposed Rule, GTAB is testing on board the vessel and then used at the import terminal as a blendstock. The GTAB cannot be sold to another party prior to blending and certification as a finished gasoline. After the GTAB and blendstocks are sampled, tested and certified, the importer sells or moves the finished gasoline from the blend 324 ------- tank. Even if the importer transfers the largest possible volume of finished gasoline from the blend tank, there will always be product left in the tank due to EPA air rules preventing a tank to be emptied below operational bottoms. Under current procedures, those tank bottoms will be blended as part of the next blending activity, with the final blend being sampled and tested prior to certification. This will continue on and on, perhaps until the tank is diverted for another use or emptied for maintenance and repair. EPA's new proposed provision would require tracking of the GTAB down to the last molecule, despite the fact that under use of the GTAB provisions for several decades there is no evidence that this type of burdensome tracking is necessary. The GTAB provisions are being used as intended, and this new requirement should be rejected as unnecessary and unsupported. [EPA-HQ-OAR-2018-0227-0076-A1, pp.10-11] 34 Id. at § 1090.1615(d)(2). Response: This is not a new requirement. As stated in a previous RFG Q&A, "Any GTAB that ultimately is not used in the company's refinery operation (e.g., a tank bottom of GTAB at the conclusion of the refinery operation), must be treated as newly imported gasoline, for which all required sampling and testing, and record keeping must be accomplished, and included in the company's importer compliance calculations for the averaging period when this sampling and testing occurs."24 Our intention it to continue to implement the provision on the same manner as we have historically. 24 See Importer Issues - Question 13, "Consolidated List of Reformulated Gasoline and Anti-Dumping Questions and Answers: July 1, 1994 through November 10, 1997," EPA420-R-03-009, July 2003. 325 ------- 18.5. Exportation Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1650(a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part, provided they are ultimately exported to a foreign country. However, such fuels must be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that the fuel is for "export only" under subpart K of this part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all fuel intended for use in the United States. [EPA-HQ-OAR-2018-0227-0074-A1,pp.43-44] Comment: Keeping records to document the fuel was exported is not always possible, specifically when the product is sold to customers or counterparties that will be responsible for exporting. 1 - Suggest the following revision that includes similar language found in 1090.1705: "Fuel manufacturers must keep records to demonstrate that the fuel was exported, or other business records and commercial documents that indicate the product was designated as intended for export, per 1090.1155(a)(9)." 2 - Or, use language similar to that found in 1090.1320(c) (3): "Fuel manufacturers must keep records to demonstrate that the fuel was exported, or enter into a contract with a customer or counterparty that ensures that party will comply with the requirements of 1090.1650." [EPA-HQ- OAR-2018-0227-0074-A1, p.43] > Flint Hills Resources 10) Part 1090 subpart P - §1090.1650 General Provisions for Exporters Suggestion: Revise (a) as follows: (a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part, provided all requirements are met as specified in §1090.645. they arc ultimately exported to a foreign country. However, such fuels must be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that the fuel is for "export only" under subpart K of this part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all fuel intended for use in the United States. 326 ------- Discussion: As proposed by EPA, (a) echoes the exemption conditions in §1090.645. Restating the conditions here is not necessary and could be confusing; therefore, we are proposing to point the exporter directly back to the exemption conditions in §1090.645. One minor exception is that this struck text identifies a record-keeping condition which is not directly mentioned in §1090.645; therefore, we are proposing above to add the record-keeping condition to §1090.645(c). [EPA-HQ-OAR-2018-0227-0052-A1, pp.6-7] > Marathon Petroleum Company LP (MPC) General provisions for exporters. 1090.1650(a) Fuels designated for export by a fuel manufacturer are not subject to the standards in this part, provided they are ultimately exported to a foreign country. However, such fuels must be designated at the fuel manufacturing facility and must be accompanied by PTDs stating that the fuel is for "export only" under subpart K of this part. Fuel manufacturers must keep records to demonstrate that the fuel was exported. Fuel designated for export must be segregated from all fuel intended for use in the United States. It may not always be possible to keep records documenting the fuel was exported, especially when the product is sold to customers or counterparties who will be responsible for exporting. MPC suggests the following revision that includes similar language found in 1090.1705: "Fuel manufacturers must keep records to demonstrate that the fuel was exported, or other business records and commercial documents that indicate the product was designated as intended for export, per 1090.1155(a)(9)." Alternatively, MPC suggests using language similar to that found in 1090.1320(c) (3): "Fuel manufacturers must keep records to demonstrate that the fuel was exported, or enter into a contract with a customer or counterparty that ensures that party will comply with the requirements of 1090.1650." [EPA-HQ-OAR-2018-0227-0048-A2, p.2] Response: We have removed proposed §1090.1650(a), which was mainly duplicative of §1090.645, and added the requirement to keep records to §1090.645(c) as the commenter suggested. Comment: > Eversheds Sutherland (US) LLP Exports A further concern is that fuel designated as "for export only" should be allowed to be redesignated as domestic gallons. If fuel that is designated as "for export" is being redesignated for domestic use, the regulations merely need to state that the entity doing the redesignating is acting as a fuel manufacturer and must comply with the requirements set forth in proposed 327 ------- §1090.105. EPA allows for redesignation for a variety of designations in the Proposed Rule (and current rules) and there is no material difference in redesignating a fuel that is for non- transportation use to transportation use versus redesignating a fuel that is initially designated for export to a fuel for domestic use. The redesignation should be accompanied by an obligation to follow all the requirements set forth for manufacturing fuel—including sampling and testing and reporting. Eversheds Sutherland suggests that EPA adopt language similar to what the Proposed Rule uses for other fuels: §1090.640(e) Any person may redesignate fuels that have been designated as for export only as a fuel for domestic use if the manufacture making the redesignation properly redesignates the fuel under §1090.105. [EPA-HQ-OAR-2018-0227-0076-A1, pp.11-12] Response: We have revised §1090.645(e) to allow for certification for use in the U.S. of fuel, fuel additive, or regulated blendstock designated for export if all of the requirements of part 1090 are met. 328 ------- 19. Compliance and Enforcement Provisions (Subpart R) 19.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.3 Default Values The existing part 80 regulations provide that if a refiner or importer fails to comply with the gasoline sampling and testing requirements, the gasoline will be deemed to have a sulfur content of 970 ppm, a benzene content of 5 volume percent, and a summer RVP of 11 psi, unless the respective party or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, different properties for the gasoline giving rise to the violations. During the rule development process, several stakeholders requested that EPA reconsider the default values that EPA uses for enforcement when a regulated party lacks a valid test result for a regulated fuel parameter. [EPA-HQ-OAR-2018-0227-0074-A1, p. 11] In its proposal EPA states: EPA is not proposing any revisions to the default values currently found in part 80. EPA recognizes; however, that the gasoline pool today has substantially lower levels of sulfur and benzene than at the time the default values were promulgated. For this reason, EPA seeks comment on whether to establish lower default values for these parameters, and what an appropriate default value should be. EPA is also proposing default values for regulated parameters for fuels, fuel additives, and regulated blendstocks where there are no existing default values in part 80 for parties that fail to meet the applicable sampling and testing requirements. 6 The Associations urge EPA to adopt lower default values that are firmly grounded, and as an alternative provide a provision for refiners and importers to determine and provide a representative value. There can be unintentional reasons (forgot to take a sample - especially in the case of infrequent previously certified gasoline ("PCG"), instrument out of service and sample disposed of before realizing a test result is missing, etc.) for having a situation without a test result (i.e. missing data). This situation should be handled differently than the past whereby the gasoline pool had higher levels of sulfur and benzene. Therefore, we are suggesting two options: 1) the use of default values, or 2) representative values using established missing data procedures. For the use of default values, we propose that the maximum standard be applied, since the refiner or import would expect the fuel to be compliant but with missing data. For the representative value using missing data procedures, we propose that the missing data shall be substituted using a refiner's or importer's established procedure based upon the test results from prior and subsequent gasoline batches or other evidence, such as test results from blendstocks used to produce the batch or from downstream testing. As a result, we propose the following language: 329 ------- (g) The values of fuel parameters provided for in paragraphs (g) (1) or (g) (2) of this section apply for cases in which any person fails to perform required testing and must be reported, unless EPA, in its sole discretion, approves a different value in writing. EPA may consider any relevant information to determine whether a different value is appropriate. (1) Default values when unable to determine a representative value: a. Gasoline Sulfur - 80 ppm b. Gasoline Benzene - 1.30 %vol c. Gasoline RVP - 9.0 psi for Conventional and 7.4 for RFG d. Gasoline PCG Sulfur - national average e. Gasoline PCG Benzene - national average f. Diesel Sulfur - 15 ppm g. ECA Sulfur - 1000 ppm (2) Representative values determined from the refiner's or importer's established missing data procedures. These procedures: a. May be based upon the test results from prior and subsequent gasoline batches or through other evidence, such as test results and volume data from blendstocks used to produce the batch of gasoline or test results from downstream gasoline testing, and b. May provide, through direct or circumstantial evidence, that the properties for the gasoline are lower or higher than the default values in (g)(1) [EPA-HQ-OAR-2018-0227-0074-A1, p.12] 6 See 85 Fed. Reg. 29075. > bp America Inc. (bp) Subpart 0—Compliance and Enforcement Provisions §1090.1710(g)-Default Values EPA has proposed maintaining the same default values for sulfur, benzene, and RVP as it currently has in 40 CFR 80.80. EPA recognizes in the preamble that the levels of sulfur and benzene in gasoline and diesel fuel have been substantially reduced from the levels that existed when the default values for originally adopted in the 1990s. (85 Fed. Reg. 29075) It would be reasonable to reduce the default values in proposed §1090.1710(g) in recognition of those reductions. In addition, EPA should permit regulated parties to demonstrate by presenting evidence that alternative default values would be appropriate in specific cases. For example, a regulated party may not have conducted certification testing but may have other results applicable to the batches in question to demonstrate with reasonable certainty what the regulated parameters likely were. That might be done by comparing data from batches produced at about the same time or from the 330 ------- same tank or through testing the batch in question downstream of the certification point but still within the manufacturing facility boundary. > CITGO Petroleum Corporation (CITGO) 2.8 Default Values The existing part 80 regulations provide specific default batch values for when a refiner or importer lacks a valid test result for a regulated fuel parameter to comply with the gasoline sampling and testing requirements. Specifically, gasoline is deemed to have the following default batch values applicable moving forward: a sulfur content of 970 ppm, a benzene content of 5 volume percent, and a summer RVP of 11 psi, unless the respective party or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, different properties for the gasoline giving rise to the violations. Consistent with EPA's intent in the preamble, EPA has proposed maintaining the applicable default values of §80.80. In §1090.1710(g), gasoline is deemed to have the following default batch values: a sulfur content of 970 ppm, a benzene content of 5 volume percent, and a summer RVP of 11 psi. However, EPA has added the requirement that in such cases where a person fails to perform required testing that it must be reported to EPA where at its sole discretion they will review the relevant information (any specific showing, direct or circumstantial evidence) and determine whether a different value is appropriate in writing before the refiner or importer can assign batch values. Additional details are needed relative to this "report to EPA" such as, the quality of material required for alternative values to be assigned and whether or not this report may be a verbal or written report versus entering into the self-disclosure system. [EPA-HQ-OAR-2018-0227-0054- Al, p.11] > Eversheds Sutherland (US) LLP Enforcement and Prohibited Acts Eversheds Sutherland agrees that the default values of fuel parameters used when a company failed to perform required testing59 should be adjusted downward given that the gasoline pool has substantially lower levels of sulfur and benzene. Use of these inflated numbers in an enforcement scenario could result in very large and wholly inappropriate penalties. Pursuant to the Clean Air Act Mobile Source Fuels Civil Penalty Policy Title II of the Clean Air Act 40 C.F.R. Part 80 Fuels Standards Requirements, EPA has penalty guidelines for benzene and sulfur standard violations, and the larger the deviation the larger the per-gallon penalty. The default values should be set at 5-10 percent above the Downstream per-gallon cap for sulfur (95 ppm) and the maximum annual average for benzene (1.30 vol.%). [EPA-HQ-OAR-2018-0227-0076-A1, p.17] 59 Id. at § 1090.1710(g). 331 ------- > Magellan Midstream Partners §1090.1710 Penalties We believe section (g) should be amended to the following: " (g) The presumed values of fuel parameters in paragraphs (g) (1) through (6) (h)(1) through (3) of this section apply for cases in which any person fails to perform required testing, and the values must be reported, unless EPA, in its sole discretion, approves of reporting a different value in writing. EPA may consider any relevant information to determine whether a different value is appropriate (1) For gasoline: 95 ppm sulfur, -5 2J) volume percent benzene and 11 psi RVP. (2) For diesel fuel: 1.000 100 ppm sulfur. (3) For ECA marine fuel: 5.000 2.000 ppm sulfur." [EPA-HQ-OAR-2018-0227-0078-A1, pp.9- 10] > Shell Oil Products US 0. Preamble - Suggested Default values Preamble states: For this reason, we seek comment on whether to establish lower default values for these parameters, and what an appropriate default value should be. We suggest that there be two different sets of default values. There are situations where someone unintentionally does not have a test result (forgot to take a sample, instrument was out of service and sample accidentally was untested, etc.) and there are situations where someone intentionally does not have a test result (deliberately did not take a sample). For the unintentional situation, we recommend that the maximum standard be applied. We propose the following: Default Values for Unintentional Situations and where an appropriate value is unable to be determined: Gasoline Sulfur - 80 ppm Gasoline Benzene - 1.30 %vol Gasoline RVP - 9.0 psi for Conventional and 7.4 psi for RFG Gasoline PCG sulfur - national average 332 ------- Gasoline PCG Benzene - national average Diesel Sulfur - 15 ppm ECA Sulfur - 1000 ppm Default Values for Intentional Situations Gasoline Sulfur - 200 ppm (The component in gasoline blending that has the highest sulfur concentration is approximately 200 ppm.) Gasoline Benzene - 4.0 %vol (The Consumer Products Safety Commission (CPSC) regulation (in 16CFR1500.14) includes special labeling requirements when products contain more than 5 weight percent benzene. With the conversion to volume, the maximum 4 volume percent benzene is used in the industry.) Gasoline RVP - 11.0 psi Gasoline PCG sulfur - 0 ppm Gasoline PCG Benzene - 0 %vol Diesel Sulfur - 1000 ppm ECA Sulfur - 5000 ppm [EPA-HQ-OAR-2018-0227-0035-A1, p.13] > Suncor Energy (U.S.A.) Inc. Default Values. EPA is not proposing any revisions to the default values included in Part 80 but did request comments as to what the appropriate default values should be when sampling or testing was not properly executed. [EPA-HQ-OAR-2018-0227-0067-A1, p.2] Suncor submits that the current default values for sulfur and benzene (listed in Table XII.A-1 of the preamble) are not appropriate: ? The sulfur and benzene levels in today's gasoline pool are significantly lower than when these default values were established. ? The cost of compliance for fuel manufacturers has significantly increased using the current default values for gasoline sulfur and benzene (970 ppm sulfur and 5 vol% benzene) and would negatively affect the already tight credit markets. [EPA-HQ-OAR-2018-0227-0067-A1, p.2] The table below computes the sulfur and benzene credit costs using the current default values and in comparison, the sulfur and benzene credit costs using the per-gallon and annual average cap cited in the regulation. A 50,000 bbl batch of gasoline would result in a $4,032,000 sulfur 333 ------- credit cost (using a $2,000/M ppm gal price) and a $367,920 benzene credit cost (using a $4.00 per credit price). These costs are significant and unnecessary to deter fuel manufacturers from improperly sampling and/or testing a batch of gasoline. The Proposed Rulemaking includes additional Attestation and Sampling Oversight Program requirements to ensure proper sampling and testing so it is unclear why such a substantial financial deterrent is needed. [EPA-HQ-OAR- 2018-0227-0067-Al,p.2] [[See page 2 of Docket Number EPA-HQ-OAR-2018-0227-0067-A1 for table mentioned above] Suncor submits that the default values should be more reasonable and aligned with the intent of the Proposed Rulemaking, which (among other things) is to reduce regulatory burden. In the absence of proper sampling and/or testing, we suggest using the established per gallon or annual average cap. [EPA-HQ-OAR-2018-0227-0067-A1, p.3] In addition, the Proposed Rulemaking is not clear as to when these default values might be necessary and what reasonably specific showings or evidence would satisfy the use of a different value. EPA's preamble only describes a scenario in which sampling or testing was not performed per the requirements. However, there are other circumstances that may arise resulting in missing data, for example a missing sample, a compositor problem, or an inadvertently skipped sample. The EPA should confirm whether default values should be used when there are other potential causes of missed data. EPA also should clarifys the type or kind of evidence that it considers acceptable to demonstrate a reasonable value if data is not available or accurate. [EPA-HQ- OAR-2018-0227-0067-A1, p.3] Response: These comments are addressed in Section XII.A of the preamble. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • continuation of the RVP test enforcement tolerance; [EPA-HQ-OAR-2018-0227-0074-A1, p.6] > Eversheds Sutherland (US) LLP Gasoline Requirements Under the Proposed Rule, all VOC standards would be defined in relation to a maximum RVP value that would apply to all gasoline at any location in the United States during the summer season9 and all gasoline designated as "summer gasoline" during the summer season. EPA is not allowing for a downstream RVP tolerance in the regulations; however, EPA states in the Proposed Rule preamble that it will exercise enforcement discretion and apply a 0.3 psi downstream test tolerance. As EPA states, this is the current EPA policy based on EPA guidance 334 ------- from 1990 and 1994. Eversheds Sutherland supports the downstream tolerance but believes it should be incorporated into the Final Rule; reliance on a 1990/1994 guidance document will be tenuous, especially after this rulemaking is final and previous guidance may arguably be inapplicable. A downstream tolerance is imminently reasonable to adopt, and the survey testing will continue to ensure compliance. To ease the burden on fuel manufacturers, EPA should clearly incorporate the current policy into the final rule. 9 The definition of "Summer Season" is unchanged from the current Part 80 regulations. Retail outlets and wholesale purchaser consumers must comply with summer gasoline requirements between June 1 and September 15. All other facilities must comply with summer gasoline requirements between May 1 and September 15. States are allowed to extend these dates in their State Implementation Plans. > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 8. Continuing of the 0.3 psi downstream enforcement tolerance over the applicable RVP standards. [EPA-HQ-OAR-2018-0227-0061-A1, p.2] Response: We thank the commenters for their support. The 0.3 psi downstream enforcement tolerance for RVP is discussed in more detail in Section XII.C of the preamble. Comment: > bp America Inc. (bp) Subpart 0—Compliance and Enforcement Provisions §1090.1710-Penalties EPA's daily penalties under §1090.1710 can be applied to time frames that are potentially as long as an entire year; e.g., a per day penalty of approximately $48,000 per day for up to 365 days in a compliance year for a violation of an average annual standard. In some cases, the average standard violation could be very slight, but nonetheless the regulated party could be facing an extremely high penalty relative to the nature of the violation. Since the authorized per day penalty under the Clean Air Act is potentially so large and the number of days for which the penalty is assessed can be up to 365, it would be appreciated if EPA would confirm in the preamble to the final rule that it will be applying its February 3, 2016 Clean Air Act Mobile Source Fuels Civil Penalty Policy as described in that policy which would take these and other factors into consideration when assessing fuels penalties. 335 ------- Response: In determining the appropriate penalty for violations of the fuels regulations, CAA section 211 (d) requires consideration of the gravity of the violation, the economic benefit or savings (if any) resulting from the violation, the size of the violator's business, the violator's history of compliance with the regulations, actions taken to remedy the violation, the effect of the penalty on the violator's ability to continue in business, and other matters as justice may require. EPA currently uses a penalty policy that incorporates these statutory factors and calculates civil penalties for specific cases.25 EPA will publish any future changes to the Penalty Policy on our website. Comment: > bp America Inc. (bp) Subpart 0—Compliance and Enforcement Provisions § 1090.1715 (d)-Liability Provisions §1090.1715(d) is a liability provision that among other things makes a joint venture partner jointly and severally liable for the fuels violations committed by the joint venture, bp believes that if a joint venture partner is going to be held responsible for the violations of the joint venture, then the joint venture partner should have the ability to prevent those violations in the same manner and with the same amount of flexibility it has within its own operations. For example, §1090.730 describes benzene and sulfur credit transfers including activities that are permitted and those that are prohibited. §1090.730(d) only permits two credit transfers between third parties with the exception that intracompany transfers are unlimited. EPA should clarify that benzene and sulfur credit transfers between a joint venture partner and the joint venture would be considered an intracompany transfer. [EPA-HQ-OAR-2018-0227-0046-A1, pp.30-31] Response: We believe that the joint venture liability provisions are distinct from the limitations on credit trading. We do not think it would be appropriate to expand the flexibility to allow unlimited intracompany transfers to joint ventures partners because this could create an opportunity to game the system by allowing joint venture partners to delay compliance with the average standards. 25 See "CAA Mobile Source Fuels Civil Penalty Policy - 40 C.F.R. Part 80 Fuels Standards Requirements," February 3, 2016 ("Penalty Policy") available at: https://www.epa.gov/enforcenient/c1ean-air-act-mobile-source- fuels-civil-penalty-policy-title-ii-clean-air-act-40-cfr. 336 ------- 20. Attest Engagements (Subpart S) 20.1. General Comments Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.2 Attestation: Statistical Quality Control ("SOC") and Performance-based Measurement System ("PBMS") Review / In-line Blending Waivers In the preamble, EPA discusses "the requirement for [attest] auditors to review PBMS qualification and SQC records"5 of refiners. This review is described as "a relatively straight- forward" confirmation that the records exist, and not a requirement for the auditors to "interpret this information as auditors may lack the appropriate technical expertise to interpret lab data for conformance with PBMS and SQC requirements." Further, it is noted that "the independent surveyor [will] review this type of information under the voluntary sampling oversight program." The Associations concur with the intent expressed in the preamble; however, the proposed regulatory text does not entirely align with the expressed intent. [EPA-HQ-OAR-2018-0227- 0074-A1, p.10] As proposed, §1090.1845(b)(3) appears to require the attest auditor to perform a review of PBMS test method qualification precision and accuracy records and conclude if the test methods have been properly qualified. Consistent with the intent expressed in the preamble that the attest auditor simply confirms the existence of these PBMS records, the Associations suggest the following revised regulatory text: §1090.1845(b) (3) Report as a finding in the attestation report any of these test methods that have not been qualified by the facility for which supporting documentation sought in (b) (1) of this section is not supplied by the gasoline manufacturer. [EPA-HQ-OAR-2018-0227-0074-A1. p. 10] 5 See 85 Fed. Reg. 29076. > Flint Hills Resources 11) Part 1090 subpart R - §1090.1845 Attest procedures related to PBMS and SOC records Suggestion: Revise §1090.1845(b) (3) as follows: §1090.1845(b) (3) Report as a finding in the attestation report any of these test methods that have not been qualified by the facility for which supporting documentation sought in (b) (1) of this section is not supplied by the gasoline manufacturer. 337 ------- Discussion: §1090.1845(b) (1) requires the attest auditor to "Obtain supporting documentation showing that the laboratory has qualified the test method by meeting the precision and accuracy criteria specified under §1090.1365." At XII.B. in the preamble, EPA discusses "the requirement for [attest] auditors to review PBMS qualification and SQC records" of refiners. This review is described as "a relatively straight-forward" confirmation that the records exist, and not a requirement for the auditors to "interpret this information as auditors may lack the appropriate technical expertise to interpret lab data for conformance with PBMS and SQC requirements." Further, it is noted that "the independent surveyor [will] review this type of information under the voluntary sampling oversight program." We concur with the intent expressed in the preamble; however, the proposed regulatory text does not entirely align with the expressed intent. As proposed, §1090.1845(b)(3) appears to require the attest auditor to perform a review of PBMS test method qualification precision and accuracy records and conclude if the test methods have been properly qualified. Consistent with the intent expressed in the preamble that the attest auditor simply confirms the existence of these records, we are suggesting §1090.1845(b) (3) be revised as stated above. [EPA-HQ-OAR-2018-0227-0052-A1, p.7] Response: We have revised §1090.1845(b) (3) to more clearly state that attest audits are simply verifying that the underlying records for PBMS qualification and SQC exist versus a more thorough technical analysis. These edits align more clearly with our stated intent in the NPRM, which we are finalizing. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.2 Attestation: Statistical Quality Control ("SQC") and Performance-based Measurement System ("PBMS") Review / In-line Blending Waivers As allowed in §1090.1315(b), refiners may operate under a legacy part 80 in-line blending waiver throughout 2021. Part 80 in-line blending waivers specify attest procedures that are required. Attest procedures for part 1090 in-line blending waivers are specified in §1090.1850; however, the proposed requirements do not clearly contemplate the potential overlap during 2021 of the legacy part 80 waiver attest procedures and the procedures applicable to part 1090 waivers. The Associations suggest the leading paragraph of §1090.1850 be clarified with the following revision: §1090.1850 In addition to any other procedure required under this subpart, auditors must perform the procedures specified in this section for gasoline refiners that rely on an in-line blending waiver under §1090.1315. except that the procedures of this section do not apply to any party who operates under an in-line blending waiver granted under 40 CFR part 80 as allowed in 51090.1315(b). [EPA-HQ-OAR-2018-0227-0074-A1, pp.10-11] 338 ------- §1090.1850(c) requires the attest auditor to "Confirm that the sampling procedures and composite calculations conform to specifications as specified in §1090.1315(b) (2)." The relevant specifications are ASTM D4177 and D5854. Confirmation that the refiner's procedures conform to those specifications would have been part of EPA's review and approval process for the refiner's in-line waiver. Further, determining practical adherence to those specifications requires technical expertise that many attest auditors may lack. Therefore, the attest auditor's requirement should be simply to confirm that the refiner is following the procedures as documented in the EPA-approved waiver. The Associations suggest §1090.1850(c) be revised as follows: §1090.1850(c) Confirm that Obtain from the refiner an affirmation that the sampling procedures and composite calculations approved by EPA pursuant to conform to specifications as specified m §1090.1315(b) (2) were followed during the entire compliance year. If the refiner does not provide an unqualified affirmation, obtain from the refiner an explanation of how the sampling procedures and composite calculations deviated from what was approved by EPA. Provide as a finding in the attestation report the refiner's affirmation and any related deviation explanations. [EPA-HQ-OAR-2018-0227-0074-A1, p.11] Appendix 2 - Additional Topics Preamble Language or Regulatory Language: 1090.1850 In addition to any other procedure required under this subpart, auditors must perform the procedures specified in this section for gasoline refiners that rely on an in-line blending waiver under §1090.1315. (a) Obtain a copy of the refiner's in-line blending waiver submission and EPA's approval letter. (b) Confirm that the refiner uses the in-line blending waiver only for qualified operations as specified in §1090.1315(a). (c) Confirm that the sampling procedures and composite calculations conform to specifications as specified in §1090.1315(b) (2). (d) Review the refiner's procedure for defining a batch for compliance purposes. Review available test data demonstrating that the test results from in-line blending correctly characterize the fuel parameters for the designated batch. (e) Confirm that the refiner corrected their operations because of previous audits, if applicable. (f) Confirm that the equipment and procedures are not materially changed from the refiner's in- line blending waiver. Report in the attestation report whether the refiner has failed to update their in-line blending waiver based on a material change in equipment or procedure. (g) Report in the attestation report whether the refiner has complied with all provisions related to their in-line blending waiver. [EPA-HQ-OAR-2018-0227-0074-A1, pp.44-45] 339 ------- Comment: In-line blending waivers—in the past, we've only performed procedures when the waiver specified attest procedures Confirm attest procedures under 1090 will not apply in 2022 of 2021 activity, as we may not be on new waivers that define audit procedures until 2022. First audit for CBOB waiver facilities would not be until 2023 of ops in 2022 under new Part 1090 waivers. [EPA-HQ-OAR-2018-0227-0074-A1, p.44] o 1850(c) refers to 1315(b)(2) which is a big ask for an auditor from a technical perspective given the requirement that auditors auditing in-line blending operations must demonstrate work experience and a good working knowledge of the voluntary consensus standards specified in §§1090.1365 and 1090.1370. [EPA-HQ-OAR-2018-0227-0074-A1, p.44] Preamble seems to make it clear they are expecting a detailed review here, more technical, which is part of why these are exempt from NSOP. Maybe EPA should add provisions here like they added in the PBMS attest section on use of other expert parties? [EPA-HQ-OAR-2018-0227- 0074-A1, p.44] > Valero Energy Corporation A. New Inline Blending Requirements 4. Inline Blending Audit Requirements and Waiver Updates EPA's proposed §1090.1315(c) requires annual audits of inline blending operations to review procedures and documents to determine whether measured and calculated values properly represent the aggregate fuel properties for the blended fuel. The proposed attestation requirement in §1090.1850 includes specific procedures that auditors are to perform on an annual basis to review inline blending operations. These two provisions are not cross-referenced, however, and thus it is unclear whether the annual attestation review required under §1090.1850 will satisfy the annual audit requirement set forth in §1090.1315(c). If EPA intends the attestation under §1090.1850 to meet the audit requirement of §1090.1315(c), EPA should cross-reference these provisions. If that is the case, language in §1090.1315(b) (6) and (c) might not be needed. If EPA intends the audit under §1090.1315(c) to be a distinct activity from the annual attestation under §1090.1850, that should be clarified as well. EPA proposes to require an audit of inline blending operations each calendar year that reviews procedures and documents to determine whether measured and calculated values properly represent the aggregate fuel properties for the blended fuel. However, under §1090.1315(b), operating under the part 80 waiver is allowed until January 1, 2022. Valero requests EPA to clarify that where operations continue under the part 80 waiver until January 1, 2022, the audit under §1090.1315(c) is not required until the year following implementation of an approved waiver under Part 1090. The proposed §1090.1850 simply says "auditors must perform the procedures specified in this section for gasoline refiners that rely on an in-line blending waiver under §1090.1315." It does 340 ------- not say that this attest is to fulfill §1090.1315(c). Similar to the above comment on the timeline for the audit requirement under §1090.1315(c), Valero requests EPA clarify that where operations continue under a part 80 conventional/CBOB only waiver until January 1, 2022, the attest under §1090.1850 is not required until 2023 for operations in 2022. In addition, Valero asks EPA to confirm that if a company is operating under a Part 80 conventional/CBOB only waiver currently, an audit is not required until the year following implementation of an approved waiver under Part 1090 and is not required in 2021 or 2022. [EPA-HQ-OAR-2018-0227-0056- Al, pp.2-4] In proposed Subpart R — Attest Engagements, §1090.1850(c) refers to §1090.1315(b) (2) which is challenging for an auditor from a technical perspective given the requirement that auditors auditing in-line blending operations must demonstrate work experience and a good working knowledge of the voluntary consensus standards specified in §§1090.1365 and §1090.1370. In the preamble, EPA explains the expectation of a detailed, more technical review, which is part of why these are exempt from NSOP. Valero recommends that EPA add provisions similar to the PBMS attest section on use of other expert parties. [EPA-HQ-OAR-2018-0227-0056-A1, p.4] Response: We have clarified §1090.1850(b) to state that gasoline manufacturers with a previously-approved ILB waiver under part 80 that use the waiver for all or part of the 2021 compliance year do not need to have an audit under §1090.1850 for the part 80 ILB waiver. However, if a gasoline manufacturer operates for part of 2021 under a part 80 ILB waiver and the rest of 2021 under a part 1090 ILB waiver, the manufacturer would need to have an audit under §1090.1850 for the part 1090 ILB waiver for the 2021 compliance period. It should be noted that RFG manufacturers that have an approved ILB waiver under part 80 must still have the annual audit required under §80.65(f) (4) performed for the 2021 compliance period. All gasoline manufacturers that have approved ILB waivers under part 1090 must have an audit performed under §1090.1850 for the 2022 compliance period. We are not modifying the requirements for the ILB waiver audit as suggested by commenters. We believe that the ILB waiver audit requirements require sufficient technical expertise to ensure that fuel manufacturers are implementing the approved ILB waiver consistent with the part 80 auditing requirement, and this is what we are requiring under §1090.1850. We recognize that this may involve the hiring of a separate auditor to perform ILB waiver audits or that an attest auditor may need to contract or subcontract for the needed expertise to perform the audit. We do not expect attest auditors to thoroughly evaluate PBMS qualification and SQC records. Consistent with the comments, we have revised the regulations to clarify our intent for attest auditors to verify the existence of such records. Independent surveyors under the NSTOP will more thoroughly verify that PBMS qualification and SQC information meets applicable regulatory requirements. 341 ------- Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Gasoline Treated as Blendstock (GTAB) There is a disparity involving GTAB between the annual batch and credit transaction requirements specified in § 1090.905(c) (7) which state that fuel volume is the only measurement to be reported for GTAB, and the language in §1090.1820(d)(4) and (d)(5) which requires the attestation to also compare properties and test methods in addition to the volumes of the GTAB batches. Items (4) and (5) should be deleted from §1090.1820(d) in order to harmonize the language with the batch reporting requirements listed for Gasoline Treated As Blendstock in § 1090.905(c) (7) which only mention volume. [EPA-HQ-OAR-2018-0227-0084-A1, pp.2-3] > Shell Oil Products US 1. Disparity Involving GTAB between §1090.90(c)(7) and Attestation Requirements in §1090.1820(d)(4) and (d)(5) §1090.90(c)(7) states that only volume is to be reported. The table that EPA put together also states that only volume is required to be reported to EPA for GTAB. In §1090.1820, it requires the attestation to compare reported properties and test methods of the GTAB batches. Items (4) and (5) should be removed and §1090.1820(d) should say: (d) Detailed testing of GTAB batches. Auditors must review a detailed listing of GTAB batches as follows: (1) Select a representative sample from the batch reports obtained under paragraph (b) (1) of this section. (2) For each selected GTAB batch sample, obtain the volume inspection report. (3) Compare the reported volume for each selected GTAB batch to the volume inspection report, reporting any exceptions. [EPA-HQ-OAR-2018-0227-0085-A1, pp.1-2] Response: Since we are no longer requiring the sampling and testing of GTAB for fuel gasoline parameters, we believe it would be inappropriate to require attest auditors to review such information. Therefore, we have removed the proposed regulatory language that would have required attest auditors to review information that is no longer required under part 1090. 342 ------- Comment: > bp America Inc. (bp) Subpart R—Attestation Engagements In Section XII. B of the preamble, EPA is requesting comments on adding a requirement to the attest engagement process for auditors annually to review PBMS qualification and SQC records for labs related to the sampling and testing requirements for gasoline. That would involve verifying labs have records demonstrating that the methods they use have been qualified under the PBMS requirements and that the lab is maintaining SQC records, bp believes that scope of review would be appropriate. §1090.1840(d) specifies the procedures auditors must use to perform a company-level credit reconciliation. However, compliance with the average gasoline standards is at a facility level per §1090.700 and §1090.705. Also, gasoline manufacturers report sulfur and benzene compliance and credit generation at a facility level in accordance with §1090.905(a) and (b). Furthermore, EPA requires auditors to perform a "facility-level" credit reconciliation under §1090.1840(c), so it would appear that a "corporate-level" credit reconciliation does not need to be completed and would otherwise be inconsistent with the requirements mentioned above. In addition, a company's facilities may choose to use different qualified auditors because of proximity of the facility to the attest auditor's office or the availability in that area of qualified auditors, so a company level credit reconciliation requirement may be problematic for reporting purposes and duplicative. [EPA-HQ-OAR-2018-0227-0046-A1, p.31] Response: We believe the company-level credit reconciliation is still needed. Intracompany transfers and how gasoline manufacturers incur and satisfy deficits from BOB recertification may involve credit transfers that occur outside of EMTS. The attest audit is the only check on whether these activities have been properly reported to EPA. This check also ensures that what has been reported at the facility level matches with the company level that is tracked in EMTS. Comment: > Coalition for Renewable Natural Gas (RNG Coalition) I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS Program. EPA asserts that it is only making "slight" modifications to the RFS regulations "for administrative purposes." However, EPA is making significant changes to the attest engagement requirements for the RFS program, explaining only that it is trying "to align" the regulations. 85 Fed. Reg. at 29,063. EPA, however, acknowledges that "subpart M regulations are mostly unique to the RFS program." Id. at 29,035. EPA also notes that "regulated parties have expressed 343 ------- concern" with respect to the proposed changes. Id. at 29,063. The Proposed Rule, however, seems focused on the regulatory impacts on obligated parties, not biofuel producers. Simply stated, EPA does not provide sufficient information (if any) on the need for these changes related to the RFS program despite the Clean Air Act requirements to provide the basis and support for proposed regulations. While EPA asserts that it reached out to stakeholders, EPA did not, to our knowledge, reach out to RNG Coalition with respect to these proposed changes. As an initial matter, EPA is trying to "streamline" its regulations to purportedly improve overall compliance assurance while reducing compliance costs. To do so, however, EPA should reconsider the need for attest engagements when a party is already engaged in a quality assurance program (QAP) or, at a minimum, should reconsider restrictions on the QAP provider being able to conduct attest engagements. Instead, and significantly, EPA is proposing to impose new requirements on parties conducting attest engagements under the RFS, including to register with EPA. This, contrary to any implications by EPA, will increase costs to biofuel producers. Where the bulk of RNG is undergoing QAP and there are restrictions on who can conduct attest engagements in such cases, RNG Coalition is concerned that these revisions do not provide any added benefit under the RFS and only add burdens onto biofuel producers to be able to find parties to conduct these reviews. The need for registration and independence requirements is particularly questionable when EPA appears to allow for employees of fuel manufacturers to conduct attest engagements (excepting them from the independence requirements), but smaller producers may not have the ability to keep auditors on staff. The RFS already has conflicts of interest requirements imposed on biofuel producers, which are required to comply with a myriad of reviews simply to participate in the RFS program. EPA's proposal wholly fails to assess the need and potential implications of "aligning]" the attest engagement provisions for other fuels programs with the RFS program. For example, EPA makes no reference to the RFS' QAP provisions, which provide significant assurances that RNG producers are complying with the RFS program. It is important to remember that the purpose of the RFS program, unlike the other fuels program, is to promote biofuel production, not regulate emissions. Rather than look to provisions to ensure the directives of the RFS, EPA is adding even more regulatory burdens on biofuel producers simply to "align" its provisions. This is wholly contrary to this Administration's purported goals of reducing regulatory costs. Response: We did not propose or consider changes to the annual attest engagement requirements under the RFS program in this action; we may, however, consider such changes in a future action. As the commenter notes, the purpose of this action is to streamline and update the attest engagement procedures for gasoline manufacturers, which have not been significantly modified in over 20 years. We note that the RFS attest engagement procedures rely upon the general procedures established for gasoline manufacturers (under both part 80 and part 1090). These general procedures include the qualifications of the annual attest auditor, how representative samples of records are selected, and the reporting procedures for the annual attest reports. The attest engagement procedures for gasoline manufacturers under part 80 have been moved unchanged to part 1090, with the exception of the process by which they are reported to EPA, which will now be reported directly to EPA by the attest auditor. We do not expect this to add costs for 344 ------- renewable fuel producers as they will continue to have the same annual attest requirements following the same procedures that they used in part 80 and that in many cases the attest auditor already submits attest engagement reports to EPA on behalf of the regulated party. We also note that the allowance of a certified internal auditor ("CIA") to perform attest engagement procedures, if certain conditions are met, is not a new allowance and applies to any party required to have an attest engagement under part 80, including the RFS program. We have simply transported this provision from part 80 to part 1090. CIAs are required to meet specified professional standards that allow them to perform auditing functions in a manner consistent with EPA's regulatory requirements. Comment: > Coalition for Renewable Natural Gas (RNG Coalition) I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS Program. RNG Coalition is also concerned with the requirement that attest engagements be directly submitted to EPA by the auditor conducting the attest engagement under the RFS. Parties should be able to address errors or resolve potential issues and, thus, should be afforded the opportunity to review attest engagements prior to submission. EPA's proposal appears to be trying to turn the attest engagement into a self-audit, but without any of the protections generally provided by EPA to such actions. EPA also ignores the complexity of the RFS regulations with respect to biofuel production for a program that is intended to promote biofuel use. There are a myriad of things that could be corrected through an attest engagement process, and, unless EPA provides similar assurances, parties should be allowed to do that and utilize, as appropriate, self-disclosure processes. [EPA-HQ-OAR-2018-0227-0058-A1, pp.2-3] Response: Nothing in part 1090 prevents a party from arranging with its auditor to receive a copy of the attest engagement prior to, at the time of, or after its submission to EPA. We have not changed the purpose of the attest engagement and the regulations mostly focus on updating the attest engagement and correcting long-standing ambiguities. Submission of the attest engagement by the auditor does not restrict a company from reviewing the report or acting upon any findings. Also, as discussed in Section 12 of this document, we have added a requirement that the attest auditor obtain acknowledgement from the regulated party that they have received and reviewed a copy of the attest engagement report prior to submission to EPA. This will help ensure that regulated parties have an opportunity to review and act upon the attest engagement report prior to submission to EPA. 345 ------- Comment: > Coalition for Renewable Natural Gas (RNG Coalition) I. RNG Coalition Opposes the Revisions to the Attest Engagement Requirements Under the RFS Program. Finally, we note that there appear to be duplicative (and inconsistent) provisions regarding suspension/debarment with respect to the new provisions being incorporated by reference into the RFS regulations. EPA proposes to add a reference to proposed §1090.1800 in §80.1464. Proposed §1090.1800, in turn, references §1090.55. Both of these proposed regulations, however, have provisions related to suspension and debarment, although the cross-references used are inconsistent. While we appreciate EPA's claimed goal of making the regulations easier to follow, it is incumbent on EPA to avoid duplicative, inconsistent and potentially confusing requirements. [EPA-HQ-OAR-2018-0227-0058-A1, p.3] Response: We have corrected the cross-references in the final part 1090 regulations. Comment: > Eversheds Sutherland (US) LLP Attestation Engagement The Proposed Rule would require attest auditors for gasoline manufacturers that produce or import gasoline to conduct certain procedures related to performance-based measurements and statistical quality control at each laboratory used during the compliance period.60 The proposal allows for an auditor to perform a single attestation engagement on a third-party lab for multiple gasoline manufacturers if the auditor directly reviewed the lab's information. This proposal is overly burdensome and problematic for several reasons. Attests are conducted between January and May of the year following the compliance year, and thus overlaps with annual compliance reporting. Under the Proposed Rule, a fuel manufacturer will have to direct its attest auditor to each laboratory used during the compliance year and conduct a review. For an importer into New York Harbor, this alone could involve four to five different laboratories. The number of laboratories for a component blender and importer could range from seven locations to as high as 15-20 due to imports into multiple PADDs and various blending locations. As such, this proposal disproportionately impacts a subset of fuel manufacturers. This is another area where increased costs are a certainty, but the exact amount of the increase remains unknown— but once again is contrary to the goals of this rulemaking. It also is burdensome for the labs themselves, as it is not efficient or necessary to have multiple auditors evaluate the same lab. The proposed language allowing for one auditor to perform a single attest for multiple gasoline manufacturers is logical generally, but must be adopted to be the least burdensome and in a manner that does not advantage larger auditors over smaller auditors. 346 ------- Instead, EPA should allow each lab to retain an attest auditor, and then the lab can provide its clients (or their attest auditor) with the report. EPA should retain the independent lab registration requirement and eventually allow for the labs to file the report directly with EPA. This approach is much more efficient for all entities, but still provides for the same outcome—EPA receiving an attest audit report for each lab used. EPA is incorrect in stating that the attest audit "is a simple review" and underestimates the additional burden and cost this is putting on fuel manufacturers and the labs, as well as disadvantaging many (if not most) of the attest auditors who cannot conduct this type of review. It is wholly inefficient for a fuel manufacturer to have to hire two attest auditors—the one they prefer to use for their gasoline activity and then a separate one for the lab review. The "fix" here is straightforward, and critically, we understand that many labs agree that this very fix is necessary and welcome. [EPA-HQ-OAR-2018-0227-0076-A1, pp.17- 18] 60 Id. at § 1090.1845. > Independent Fuel Terminal Operators Association (IFTOA) X. Attestation of Laboratory Records Pursuant to § 1090.1845, EPA is proposing to require auditors to review whether independent laboratories used to test gasoline for compliance have records demonstrating that methods have been qualified under the Performance Based Measurement System requirements and that such labs are maintaining Statistical Quality Control records. EPA states that this requirement would not impose much of an additional burden on refiner/importers. Moreover, § 1090.1845 (a) (4) provides that an 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. It is clear that EPA is attempting to minimize this regulatory obligation. [EPA-HQ-OAR-2018-0227-0064-A1, p.6] However, this approach would be inefficient and entail unnecessary costs. A typical refiner/importer often will use a number of labs at each of its locations, and this new requirement simply adds another cost to the attestation expense. Moreover, there could be multiple auditors evaluating the same lab. Accordingly, it would be prudent for EPA to require each independent laboratory to retain the services of an auditor and make the laboratory responsible for ensuring an independent review of its records. [EPA-HQ-OAR-2018-0227-0064-A1, p.6] Response: We do not believe that it would be appropriate to require third-party laboratories to register and then require those laboratories to conduct their own audit as suggested by the commenter. Such a requirement would require the registration of thousands of third-party laboratories and require many additional audits that would serve little value. Consistent with part 80, part 1090 places the onus on fuel manufacturers to ensure that annual audits take place and that information needed from third-party laboratories is obtained for attest auditors to review. Such a change, as suggested by commenters, would be a substantial departure from the regulatory approach 347 ------- established under part 80. Furthermore, in response to other comments in this section, we have clarified that the annual attest audit of PBMS qualification and SQC records is mostly to determine the existence of such records, not to conduct a thorough assessment of the veracity of such information. We believe that this clarification also addresses this comment by substantially reducing the amount of effort needed by fuel manufacturers and laboratories to comply with the PBMS and SQC portion of the annual attest audit and avoiding any need to have two attest auditors complete the annual attest engagement audits. Lastly, the part 1090 regulations do not preclude third-party laboratories from retaining the services of an auditor and then making that audit available to multiple gasoline manufacturers as suggested by the commenter. We encourage fuel manufacturers and laboratories that want to engage in such a relationship to cut costs to do so as long as all applicable regulatory requirements are met. Comment: > Turner, Mason & Company (TM&C) Subpart R - Attestation Engagements Attest General Procedures In 1090.1810(g) (6), the auditor is required to confirm the amount of oxygenate included in the BOB hand blend "within an acceptable range." In Appendix B, Table 1, the requirements of the "RBOB with downstream oxy (hand blend)" and "CBOB (hand blend)" is notated as a "2 - Report" versus a "1 - Measure/Test and Report." We do not believe it was the intent of the agency to require the oxygenate content to be measured and that the table correctly depicts the agencies intention. Therefore, we would recommend the following clarification. (6) Confirm that each oxygenate type and amount included in the BOB hand blend agrees within an acceptable range to with each selected BOB batch, reporting any exceptions. In 1090.1810(g) and 1090.1810(i), the auditor is required to review a detailed listing of BOB and finished gasoline batches for specific information. Furthermore, for a blending manufacturer, the auditor is to confirm the laboratory analysis results for oxygenate and distillation as stated in (g)(8) and (i)(5). These requirements conflict with those summarized in Appendix B, Table 1. We believe the agency did not intend to include PCG by Addition within these requirements for a blending manufacturer, and therefore, this requirement would only be applicable on the "PCG + Blendstock (Final)" for PCG by Subtraction as displayed in the table. For the detailed testing of BOB batches, we recommend the following language for clarification. (g)(8) For blending manufacturers demonstrating compliance of PCG by addition, confirm that the laboratory analysis includes test results for oxygenate and distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue), and for blending manufacturers 348 ------- demonstrating compliance of PCG by Subtraction, the test results for oxygenate and distillation parameters (i.e.. TIP. T50. T90. final boiling point, and percent residue). For the detailed testing of finished gasoline batches, we recommend the following language for clarification. (i)(5) For blending manufacturers demonstrating compliance of PCG by addition, confirm that the laboratory analysis includes test results for oxygenate and distillation parameters (i.e., T10, T50, T90, final boiling point, and percent residue), and for blending manufacturers demonstrating compliance of PCG by Subtraction, the test results for oxygenate and distillation parameters (i.e.. TIP. T50. T90. final boiling point, and percent residue). Should the agency incorporate the streamlined approach proposed above in the "Oxygenate measurement requirements" as discussed in the above Subpart M comments, additional text should be added to (g) (8) and (i) (5) to incorporate the appropriate exemption. We would propose the following language to support the proposed streamlined approach. ... for those blending manufacturers not measuring the oxygenate content, confirm the following: records for the PCG or blendstock show no oxygenate content, no oxygenate was added to the final gasoline batch, and the blending manufacturer did not account for downstream oxygenate blending. [EPA-HQ-OAR-2018-0227-0045-A1, pp.6-8] Response: We have clarified §1090.1810(g) to align the attest engagement procedures with sampling and testing procedures for hand blends. We have also clarified that reviewing oxygenate testing for blending manufacturers only is performed by the auditor if such testing is required. In cases where oxygenate testing is not required by the blending manufacturer, we require that the attest auditor verify the records demonstrating that PCG or blendstock has no oxygenate content and that no oxygenate was added to the final gasoline batch as the commenter suggested. Comment: > Turner, Mason & Company (TM&C) Subpart R - Attestation Engagements Attest Procedures for GTAB In regards to GTAB tracing, 1090.1820(e), the auditor would be required to trace and review the movement of all GTAB batches versus only those identified in (c) (1) "select a representative sample from the listing of GTAB imports." We seek further clarification regarding the requirement. [EPA-HQ-OAR-2018-0227-0045-A1, pp.8] 349 ------- Response: §1090.1820(e)(1) compares the total volume of GTAB reported on annual batch reports to the total GTAB volume determined under the inventory reconciliation analysis in §1090.1810. §1090.1820(e) (2) traces the movement of a representative sample of batches of GTAB through the fuel manufacturer's facility. This procedure is identical to the part 80 procedures. We do not believe that further clarification is needed. Comment: > Turner, Mason & Company (TM&C) Subpart R - Attestation Engagements Attest Procedures for PBMS and SOC In 1090.1845(c)(1) the language excludes the review of reference installations for qualifying VSCB using 1090.1370(b) to be excluded from the attest requirement. We believe the intention was to include both VCSB and non-VSCB and therefore suggest the following language for clarification. (1) Obtain supporting documentation demonstrating that the reference installation followed the qualification procedures specified in §1090.1370(c) (1) and (2) (b) and (c)(1) and (2) and the quality control procedures specified in §1090.1370(c) (3). [EPA-HQ-OAR-2018-0227-0045-A1, P-8] In 1090.1845(d) (3) the reference here is to perform an instrument control review of the instrument list obtained under paragraph (b) (1). We believe the intention was for an auditor to perform a review for both non-referenced methods (b) and reference installations (c). We suggest the following language for clarification. (3) Report as a finding in the attestation report the instrument list obtained under paragraph (b) (1) and (c) of this section and the compliance period when the instrument control review was completed. Finally, we seek clarity from EPA regarding the provisions of 1090.1845 and its applicability to parties beyond the gasoline manufacturer. According to Table 1 of the technical memorandum1, additional regulated entities, beyond the gasoline manufacturer, will have testing parameters subject to the PBMS requirements. Is it the intent for the attest procedures of 1090.1845 to apply to regulated entities beyond the gasoline manufacturer? [EPA-HQ-OAR-2018-0227-0045-A1, pp.8-9] Response: We have revised §1090.1370(c) to include both VCSB and non-VCSB procedures. This change will result in the requirement for attest auditors to review both VCSB and non-VCSB procedures 350 ------- under §1090.1845(c)(1). We have also revised §1090.1845(d)(3) to include both non-referee methods and methods qualified by reference installations as the commenter suggested. Attest engagements under part 1090 do not apply to any parties other than gasoline manufacturers. Comment: > Turner, Mason & Company (TM&C) Subpart R - Attestation Engagements Attest Engagement EPA seeks comment on the proposed lab record review requirement and other aspects of the streamlined attest engagement requirements. In addition, the agency is seeking feedback as to whether there are other requirements that would be implemented for purposes of providing adequate annual attest audits. We provide comment on three key areas below: I. The record review for PBMS and SQC of a gasoline manufacturer, as stated in 1090.1845, could further be streamlined to exempt those participating in the voluntary National Sampling Oversight Program (NSOP) by allowing a company to provide the auditor with records confirming their participation in the NSOP. Furthermore, the technical qualifications of an independent auditor conducting the review of the PBMS qualification and SQC records is necessary to be able to satisfy the agencies intent. We support this requirement for those fuel manufacturers who do not participate in the NSOP. In regards to the technical qualifications of the independent contractor conducting the in-line blending audit, the technical expertise is necessary to ensure the quality of the audit. II. With the advancement in technology over the last several years, many laboratories have integrated their analytical instruments directly to their Laboratory Information Management (LIMs) systems. These laboratories no longer have an individual printout from each instrument with the test result. In order to satisfy the requirements of 1090.1800(d) (3), a summary report prepared by the LIMs system should be an acceptable approach, and we recommend the agency incorporate this as a special case notated as (d) (3) (iii). III. For the attestation requirements of a 3rd-party laboratory under 1090.1845(a)(4), the agency could further streamline this requirement by allowing the 3rd-party laboratory assessment to be conducted within 9 months (Oct 1st of prior year - May 31st) of the attestation due date on a rolling 12-month set of data. This approach allows services to be balanced throughout the year versus condensing all of the requirements (reporting, attestation, 3rd-party laboratory attest, etc.) into the first 6 months of a year. 351 ------- For illustration purposes, the assessment of a 3rd-party's laboratory quality program could be conducted any time after October 1, 2021, up to May 31, 2022, on the prior 12 months data (i.e., October 2020 through September 2021). IV. Request the supporting documents provided in Docket EPA-HQ-OAR- 2018-0227-0026 be reviewed for consistency with Part 1090. TM&C appreciates the time invested by the agency to provide these documents to assist with ones understanding of the requirements in Part 1090. [EPA-HQ-OAR-2018-0227-0045-A1, pp.8-10] 1 "Technical Issues Related to Fuels Regulatory Streamlining Measurement Procedures", April 18, 2020, Docket EPA-HQ-OAR-2018-0227 Response: We do not specify the format of the original test results record. We recognize that many laboratories have gone to electronic Laboratory Information Management Systems (LIMS). We believe that printouts from LIMS can be the record for the original test results in cases where instruments record results directly into LIMS. In cases where a separate record is created prior to inputing results into LIMS, we expect the auditor to review those original test result records. We are not modifying the timeframe for which PBMS qualification and SQC record attest audits occur as suggested by the commenter. We believe that creating a separate rolling deadline for these attest audits will create confusion and make it difficult to align review of laboratories PBMS qualification and SQC record attest audits with the rest of the gasoline manufacturer's attest audit, which is based on the entire compliance period. We have ensured that final reporting form instructions align with the part 1090 regulatory requirements as suggested by the commenter. Comment: > Weaver and Tidwell, L.L.P. Based on the procedures listed, the only regulated parties whom are subject to reporting under the NPRM, but do not also have an attest requirement are oxy producers and diesel manufacturers (both of these reporters are inclusive of importers). [EPA-HQ-OAR-2018-0227- 0079-A1, p.2] Generally, regulated parties that have a reporting obligation also have an obligation to ensure that the information submitted is complete and accurate - the mechanism for accomplishing this, in the case, is an attest. This is even true of auditors - QAP providers are subject to reporting requirements; therefore, attest requirements. [EPA-HQ-OAR-2018-0227-0079-A1, p.2] For oxy producers and diesel manufacturers, we understand that this is something that EPA is considering in the future, via adjustments to the RFS attest procedures; however, we believe that 352 ------- the attest requirements should align with the corresponding regulatory requirements. While the RFS encompasses some requirements for both of these parties, the basis for reporting, in this case, is not related to the RFS program. [EPA-HQ-OAR-2018-0227-0079-A1, p.2] Specific to diesel manufacturers, incorporating some general attest procedures to ensure complete and accurate volume reporting on the "front end" most closely aligns with the requirements for gasoline. Generally, what is reported and checked via attest procedures for gasoline (under the gasoline program) directly correlates to (or impacts) the volumes used for RVOs under the RFS program. [EPA-HQ-OAR-2018-0227-0079-A1, p.2] Response: We do not believe that it is appropriate to impose attest engagement procedures for diesel RVOs or oxygenate producers under the RFS program as part of this action. We may consider such attest engagement procedures in a future RFS-related action. Comment: > Weaver and Tidwell, L.L.P. §1090.1800 General provisions. (b) (1) (ii) The auditor may be a certified public accountant, or firm of such accountants, that is independent of the gasoline manufacturer. Such auditors must comply with the AICPA Code of Professional Conduct, including its independence requirements, the AICPA Statements on Quality Control Standards (both incorporated by reference in §1090.95), and applicable rules of state boards of public accountancy. Such auditors must also perform the attestation engagement in accordance with the AICPA Statements on Standards for Attestation Engagements (SSAE) No. -4-819, Attestation Standards: Clarification and Recodification, especially as noted in sections AT-C 105, 215, and 315 (incorporated by reference in §1090.95). or as superseded. * This should be SSAE 19 based on the date of the first attest reports, applicable to the streamline regulations. We've added "or as superseded" to allow for subsequent updates. [EPA- HQ-OAR-2018-0227-0079-A1, p.3] Response: We have updated the AICPA requirements to the latest version as suggested by the commenter. However, we are not allowing for the automatic updating of AICPA requirements, as that would allow AICPA to modify our regulatory requirements without a notice and comment rulemaking. Comment: > Weaver and Tidwell, L.L.P. §1090.1800 General provisions. 353 ------- (d) (3) (ii) For gasoline manufacturers that rely on third-party laboratories for all-testing, the laboratory analysis consists of the results provided by the third-party laboratory. * The word "all" here is not needed. [EPA-HQ-OAR-2018-0227-0079-A1, p.4] §1090.1810 General procedures - gasoline manufacturers. (f) Detail testing Review of BOB tenders. Auditors must review a detailed listing of BOB tenders as follows: * Adjusted for consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.6] (f) (1) Select a representative sample of PTDs from the listing of BOB tenders. * Should be removed to make it clear that the representative sample is of the tenders, not PTDs; also, for consistency of other/similar procedures. [EPA-HQ-OAR-2018-0227-0079-A1, p.6] (g)(1) Select a representative sample from the BOB batch reports submitted to EPA under subpart J of this part and obtain the volume documentation and laboratory analysis for each selected BOB batchsample. * Adjusted for consistency and clarification; same for (2) and (3) below. [EPA-HQ-OAR-2018- 0227-0079-A1, p.6] (g) (2) Compare the reported volume for each selected sampleBOB batch to the volume documentation, reporting any exceptions. (g) (3) Compare the reported properties for each selected sample BOB batch to the laboratory analysis, reporting any exceptions. (h)(1) Select a representative sample from the listing of finished gasoline tenders^ (h)(2-) For each sample, obtain the associated PTDsand obtain the associated PTD for each selected tender. * Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.7] (h) (23) 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^ reporting any exceptions. * Adjusted for consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.7] (h) (34) Confirm that the PTD associated with each selected finished gasoline tender contains all the applicable language requirements under subpart K of this part, reporting any exceptions. 354 ------- (h) (4) Report as a finding in the attestation report any tenders where the PTD did not contain all applicable PTD language requirements under subpart K of this part, reporting any exceptions. * Duplicate procedure to (3) above; also, for consistency with the BOB tender testing section above. [EPA-HQ-OAR-2018-0227-0079-A1, p.7] §1090.1820 Additional procedures for gasoline treated as blendstock. (d)(4) Compare the reported properties for eachthe selected GTAB batches-to the laboratory analysis, reporting any exceptions. * Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12] (d) (5) Compare the reported test methods used for eachthe selected GTAB batches-to the laboratory analysis, reporting any exceptions. * Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12] (e) (2) (i) Obtain tank activity records that describe the movement of eachthe-selected GTAB batch from importation to use to produce gasoline. * Adjusted for consistency. [EPA-HQ-OAR-2018-0227-0079-A1, p.12] §1090.1825 Additional procedures for PCG used to produce gasoline. (b) (4) Report as a finding in the attestation report any instances where the reported PCG batch volume was adjusted from the original receipt volume, such as for exported PCG. for each selected PCG batch. * Procedures (2) through (8) are for each selected batch, so this adjustment is needed for consistency and clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.13] §1090.1830 Alternative procedures for certified butane blenders. (d) Detailed testing of certified butane batches. Auditors must review a detailed listing of certified butane batches received as follows: * Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.15] (d)(1) Select a representative sample from the certified butane batch reports submitted under subpart J of this part andT (d)(2) Oobtain the volume documentation and laboratory analysis for each selected certified butane batch. 355 ------- (d) (23-) Compare the reported volume for each selected certified butane batch to the volume documentation, reporting any exceptions. (d) (34) Compare the reported properties for each selected certified butane batch to the laboratory analysis, reporting any exceptions. (d) (4-&) Compare the reported test methods used for each selected certified butane batch to the laboratory analysis, reporting any exceptions. (d) (50) Confirm that the butane meets the standards for certified butane under subpart C of this part, reporting any exceptions. * Adjusted for consistency with other sections. [EPA-HQ-OAR-2018-0227-0079-A1, p. 15] §1090.1840 Additional procedures related to compliance with gasoline average standards. (a) (3) (ii) Average benzene sulfur concentration, per § 1090.-7QQ745 (b) (b) (3) and average benzene concentration, per §1090.700 (b)(3). * Adjusted to be more specific and accurate. [EPA-HQ-OAR-2018-0227-0079-A1, p.16] * Note that the ABT0300 Report Instructions, Field 12 reference the wrong regulatory section for sulfur level. [EPA-HQ-OAR-2018-0227-0079-A1, p.16] * Paragraph 1090.700(a) (3) (ii) does not appear to exist. [EPA-HQ-OAR-2018-0227-0079-A1, P-16] (a) (3) (v) Net annual average level. * Added to be consistent with new reporting requirements. [EPA-HQ-OAR-2018-0227-0079-A1, P-16] (c) Facility-level credit reconciliation. Auditors must perform a facility-level credit reconciliation separately for each gasoline manufacturing or importing facility as follows: * Adjusted for clarification. [EPA-HQ-OAR-2018-0227-0079-A1, p.17] §1090.1845 Procedures related to meeting performance-based measurement and statistical quality control for test methods. (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 methods listed in §1090.1360(d), the auditor must: * For clarification. [EPA-HQ-QAR-2018-0227-0079-A1, p. 18] 356 ------- Response: We have made appropriate edits to the attest engagement requirements as the commenter suggested. We have also corrected errant cross-references in the regulations and final reporting form instructions. However, we are not modifying §1090.1840(c) to specify "importing facility" as suggested since it would be redundant. As defined under §1090.80, fuel manufacturing facilities include facilities where fuel is imported. Therefore, the language at §1090.1840(c) already covers facilities where gasoline is imported. Comment: > Weaver and Tidwell, L.L.P. §1090.1810 General procedures - gasoline manufacturers. (a) (4) Obtain a written statement from the gasoline manufacturer's RCO or their delegate that the submitted reports are complete and accurate. * Allowing delegates to provide representations should be appropriate, as delegates also submit reports on behalf of the RCO. [EPA-HQ-OAR-2018-0227-0079-A1, p.5] §1090.1830 Alternative procedures for certified butane blenders. (a) (4) Obtain a written statement from the certified butane blender's RCO or their delegate that the submitted reports are complete and accurate. * Adjusted for consistency with the above comment. [EPA-HQ-OAR-2018-0227-0079-A1, p. 14] Response: We believe that it would be inappropriate to allow for a delegate to affirm that a gasoline manufacturer's reports are complete and accurate because this ensures that the gasoline manufacturer is informed of the results of the attest engagement. Comment: > Weaver and Tidwell, L.L.P. §1090.1810 General procedures - gasoline manufacturers. (i) Detailed testing ofblendstock batches. Auditors must review the blendstock batches in the case of adding blendstock to TGP or PCG and complying under the provisions of §1090.1320(a)(2) as follows: 357 ------- (1) Select a representative sample of blendstock batches from the batch reports submitted to EPA under subpart J of this part and obtain the volume documentation and the laboratory analysis for each selected blendstock batch. (2) Compare the reported volume for each selected blendstock batch to the volume documentation, reporting any exceptions. (3) Compare the reported properties for each selected blendstock batch to the laboratory analysis, reporting any exceptions. (4) Compare the reported test methods used for each selected blendstock batch to the laboratory analysis, reporting any exceptions. * Specific procedures are needed to address blendstock batches (PCG by addition batching), which would be the basis for compliance calculations, if applicable. [EPA-HQ-OAR-2018-0227- 0079-A1, p.7] * There is also a requirement to report the final blend when complying under this method. The final blend would be captured through the sections above - Detailed test of BOB/finished gasoline batches. [EPA-HQ-OAR-2018-0227-0079-A1, p.7] Response: We have added a procedure to complete detailed testing for blendstocks that are added to TGP or PCG and the gasoline manufacturer elects to comply by addition under §1090.1320(a) (2). We believe such a procedure is necessary to ensure that gasoline manufacturers that add blendstocks to TGP and PCG are appropriately reporting volumes and parameters for the added blendstocks in compliance calculations for annual sulfur and benzene averages. With this change, attest auditors will perform a detailed review of records and reports for a representative sample of batches for blendstocks and finished gasolines separately. Comment: > Weaver and Tidwell, L.L.P. §1090.1830 Alternative procedures for certified butane blenders. Auditors must use the procedures of this section instead of or in addition to the procedures in §1090.1810 for certified butane blenders that blend certified butane into PCG under the provisions of §1090.1320(c). * These procedures are to be performed "instead of..." not "in addition to..." [EPA-HQ-OAR- 2018-0227-0079-A1, p.14] * Being specific to the section under 1090.1320 that actually applies to butane and pentane under the alternative provisions. [EPA-HQ-OAR-2018-0227-0079-A1, p. 14] 358 ------- §1090.1835 Alternative procedures for certified pentane blenders. (a) Auditors must use the procedures of this section instead of or in addition to the procedures in §§1090.1810 and 1090.1815, as applicable, for certified pentane blenders that blend certified pentane into PCG under the provisions of §1090.1320(c). * Adjustments for clarification and consistency with the butane section. [EPA-HQ-OAR-2018- 0227-0079-A1, p.15] Response: We have corrected the cross-references as suggested by the commenter in §§1090.1830 and 1090.1835; however, we are not removing the "in addition to" language as suggested. We believe that many certified butane and certified pentane blenders also perform activities that may be covered by the general provisions for all gasoline manufacturers under §1090.1810 and that removing the reference to §1090.1810 will cause confusion on the part of regulated parties that must have procedures performed by an attest auditor under both §1090.1810 or §§1090.1830 and 1090.1835. We have, however, revised §§1090.1830 and 1090.1835 to refer only to the applicable provisions of §1090.1810, as some provisions of §1090.1810 may not apply to the certified butane or certified pentane blender. Comment: > Weaver and Tidwell, L.L.P. §1090.1830 Alternative procedures for certified butane blenders. (b) (5) Compare the total volume of certified butane blended from the batch reports to the inventory reconciliation analysis, reporting any variances. (b) (5§) Report in the attestation report the total volume of certified butane received and blended. * It doesn't appear that the total volume of butane blended is part of the current DRAFT report forms. Having said that, it should be noted that the basis for RVO calculations under RFS program is generally the blended volumes, not the receipted volumes; therefore, it still seems prudent to continue to report and agree out the volumes of butane blended. [EPA-HQ-OAR- 2018-0227-0079-A1, p.15] Response: As discussed in Section 12 of this document, we have revised the reporting requirements for certified butane blenders to include the total volume of certified butane blended by the certified butane blender. Under §1090.1830(b), attest auditors must verify that the amount of certified butane blended was correctly computed and reported to EPA. 359 ------- Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (c) (1) Obtain the credits remaining or the credit deficit from the previous compliance period from the gasoline manufacturer's credit transaction information supporting documentation for the previous compliance period. * Credit transaction information will not always be sufficient to confirm an ending balance. Also, the current DRAFT report forms do not show ending balances; therefore, this reference needs to be broader to allow multiple documents combined to support the credit balances. [EPA-HQ- OAR-2018-0227-0079-A1, p.17] Response: We have revised §1090.1840(c) (1) to refer to "supporting documentation" instead of the proposed "credit transaction information" language, as a broader set of records may be needed to verify credit balances for the prior compliance period. Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (c) (2) Compute and report as a finding the net credits remaining at the end of the compliance period, by totaling: (i) Credits remaining from the previous year; plus (minus) (ii) Credits generated (used) under paragraph (a) (3) (iii) of this section; plus (iii) Credits purchased under paragraph (b) of this section; minus (iv) Credits sold under paragraph (b) of this section; minus (v) Credits expired under paragraph (a)(3)(iv) of this section; minus (vi) Credit deficit from the previous year. * We believe this is needed for clarification and consistency in application. [EPA-HQ-OAR- 2018-0227-0079-A1, p.17] 360 ------- Response: We have not added the suggested procedure for verifying credit balances under §1090.1840(c) (2). We do not believe that such specificity is warranted as the procedure could vary across gasoline manufacturers specific situations. As such, we are finalizing the requirements for verifying credit balances under §1090.1840(c) (2) as proposed. Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (c) (3) Compare the ending balance of credits or credit deficit recalculated in paragraph (c) (2) of this section to the corresponding value from the annual compliance report, reporting any variances. * The draft report forms do not include reporting the ending balance, by facility. We believe this level of information is needed for transparency and the company level reconciliation. [EPA-HQ- OAR-2018-0227-0079-A1, p.17] Response: We have not required the submission of ending credit balances by facility in the annual compliance reports as such information is tracked in EMTS and is derivative of other data elements collected in the reports. We do, however, expect that attest auditors will review annual ending credit balances obtained from annual compliance reports as tracked in EMTS. Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (c) (4) For importers, the procedures of this paragraph (c) apply at the company level. * Importers are still subject to facility compliance. We are not sure of the purpose of this procedure in the context of the credit reconciliation. [EPA-HQ-OAR-2018-0227-0079-A1, p.17] Response: We have removed §1090.1840(c) (4) as suggested since facility-level consolidation procedures apply to import facilities. 361 ------- Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (d)(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 in the EPA Moderated Transaction System submitted under subpart J of this part. * Clarifying the point of comparison. [EPA-HQ-OAR-2018-0227-0079-A1, p. 18] Response: As a matter of practice, we have chosen not to reference specific EPA electronic reporting systems in our part 1090 regulations as these systems, and their names, are subject to change over time. Mismatches in named electronic reporting systems can cause confusion on the part of regulated parties required to report to EPA. Therefore, we are not adding references to EMTS as suggested by the commenter. Comment: > Weaver and Tidwell, L.L.P. §1090.1840 Additional procedures related to compliance with gasoline average standards. (e) Procedures for gasoline manufacturers that recertify BOB. Auditors must perform the following procedures for any gasoline manufacturer that recertifies a BOB under §1090.740 and incurs a deficit: * We believe that this section is better suited at the beginning of 1090.1840, since the corresponding deficits are included in the annual compliance calculations. [EPA-HQ-OAR-2018- 0227-0079-A1, p.18] Response: We have not rearranged the attest requirements under §1090.1840 to put the provisions for BOB recertification up front since these provisions are not generally applicable and their inclusion at the beginning of the section may obscure the other, more generally applicable requirements. 362 ------- Comment: > Weaver and Tidwell, L.L.P. §1090.1845 Procedures related to meeting performance-based measurement and statistical quality control for test methods. (d) (1) Obtain a listing from the laboratory of instruments and period when they were used to test gasoline parameters during the compliance period for batches selected as part of the representative sample. * To perform an analysis of the instrument on-going precision and accuracy SQC, one needs a listing and in-service dates for all instruments used during the compliance period. Where a laboratory has multiple instruments of a method, one also needs the laboratory to provide a map that ties batch results to an instrument. This can be accomplished by including the original test printout in the batch data file or extracted from LIMS. [EPA-HQ-OAR-2018-0227-0079-A1, P-19] (d) (2A-) Obtain statistical quality assurance data and control charts demonstrating ongoing quality testing to meet the accuracy and precision requirements specified in §1090.1375. (d) (30) Report as a finding in the attestation report any instruments for which the facility failed to perform statistical quality assurance monitoring under §1090.1375. (d) (43) Report as a finding in the attestation report the instrument list obtained under paragraph (fed) (1) of this section and the compliance period when the instrument control review was completed. * All instruments used during the period, not just alternative methods. [EPA-HQ-OAR-2018- 0227-0079-A1, p.19] * We are not sure what is being requested here. [EPA-HQ-OAR-2018-0227-0079-A1, p.19] Response: We have added the requirement that attest auditors obtain a listing of instruments and the periods when those instruments where used for compliance testing during the compliance period. We believe that in order to verify that SQC records exist, we need to specify which instruments over what time period records need to be obtained. We believe the revisions to §1090.1845(d) should help clarify the SQC record review procedures. Comment: > Weaver and Tidwell, L.L.P. §1090.1850 Procedures related to in-line blending waivers. 363 ------- (f) Perform the additional procedures unique to the blending operation, as specified in the in-line blending waiver. Confirm that the equipment and procedures are not materially changed from the refiner's in line blending waiver. Report in the attestation report whether the refiner has failed to update their in line blending waiver based on a material change in equipment or procedure. (g) Report in the attestation report whether the refiner has complied with all provisions related to their in line blending waivcrany noted deviations from the in line blending waiver. * We believe that it is best for the additional procedures (which are unique to the blending operation) to be written into the in-line blending waiver, as done today. This removes auditor judgement and provides EPA with the ability to approve said unique procedures as part of the waiver approval process - ensuring transparency, etc. [EPA-HQ-OAR-2018-0227-0079-A1, P-20] * Applying materiality and/or assessing that "all" provisions of the waiver have been met is not feasible in the context of this type of attest engagement. [EPA-HQ-OAR-2018-0227-0079-A1, P-20] Response: We have revised §1090.1850 to require that the auditor must review any additional auditing requirements specific to the gasoline manufacturer's facility-specific in-line blending waiver. However, we do not believe that this supplants the requirements to verify that equipment and procedures have not materially changed or that the gasoline manufacturer has complied with all the provisions of their in-line blending waiver. Therefore, we are finalizing the requirements for auditors to verify in-line blending waivers under §1090.1850(f) and (g) as proposed. 364 ------- 21. Other Requirements 21.1. PCG Comment: > 1980, A.R.C. Distributors, ABYC, et al. (approximately 350 organizations) In order to level the playing field between ethanol and biobutanol, we propose allowing biobutanol blenders to add additional butane without registering as a refiner; and [EPA-HQ- OAR-2018-0227-0082-A1, p.l] > Advanced Biofuel Assn, Association of Marine Industries, Biotechnology Innovation Organization, et al. 4. Allow blending of butane with isobutanol. EPA should allow the blending of butane with isobutanol into gasoline without isobutanol blenders needing to register as refiners. The benefit of blending butanes is to reduce fuel cost while still maintaining necessary specifications. Butanes can also help with cold start performance in certain instances such as low RVP blendstock. This action would provide another opportunity to "level the playing field" for isobutanol oxygenate. [EPA-HQ-OAR-2018-0227-0063-A2, p.2] > bp America Inc. (bp) Simplified requirements for butane blending into isobutanol bp believes that a party that will recertify (or redesignate) a BOB to allow 16% isobutanol will need to blend butane in order to meet the RVP and octane specifications. The current requirements for butane blending will hinder some companies from blending isobutanol and butane thus limiting the amount of renewable fuel blended, bp asks EPA to consider flexibility for these parties that blend isobutanol and butane. [EPA-HQ-OAR-2018-0227-0046-A1, pp.10] > BRP US Inc. Marine Group (BRP) Allowance to adjust RVP. Blending biobutanol at 16.1 vol % will provide additional environmental benefits by reducing benzene and sulfur emissions. However, EPA's proposal is not providing any credits for blending biobutanol above the percentage the BOB was intended. For example, it is expected that a BOB intended for E10 will be used to blend 16.1 vol % biobutanol. By blending 16.1 vol % biobutanol, benzene and sulfur will easily be reduced in the final finished fuel, providing significant environmental benefits. In order to level the playing field between ethanol and biobutanol, BRP recommends that EPA allow biobutanol blenders to add additional butane without being required to register as a refiner. The ability to blend butane will be important, particularly when using low RVP blendstocks and also will be important when considering the higher cost of biologically produced isobutanol and its ability to reduce RVP. Indeed, biobutanol will provide environmental benefits by reducing benzene and sulfur so this 365 ------- recommendation would be a fair trade-off in light of the regulations not providing credits. [EPA- HQ-OAR-2018-0227-0047-Al.pp.3-4] > Butamax Advanced Biofuels, LLC Simplified requirements for butane blending into isobutanol gasoline blends In addition to the above clarifications, Butamax encourages the Agency to consider including simplified requirements for butane blending into isobutanol gasoline blends as part of the proposed rulemaking. Butamax believes that a party recertifying (or redesignating) a 10% ethanol BOB for blending with 16% isobutanol will frequently wish to blend butane in order to provide comparable and compliant levels of RVP and octane in the finished blend. The current requirements for butane blending will hinder some parties from blending butane to isobutanol gasoline blends thus limiting the amount of renewable fuel blended. Butamax asks EPA to consider flexibility for these parties that include butane in isobutanol gasoline blends. [EPA-HQ- OAR-2018-0227-0068-A1, p.3] > Gevo, Inc. 4. Allow blending of butane with isobutanol. EPA should allow the blending of butane with isobutanol into gasoline without isobutanol blenders needing to register as refiners. The benefit of blending butanes is to reduce fuel cost while still maintaining necessary specifications. Butanes can also help with cold start performance in certain instances such as low RVP blendstock. This action would provide another opportunity to "level the playing field" for isobutanol oxygenate. [EPA-HQ-OAR-2018-0227-0063-A1, p.4] > National Marine Manufacturers Association (NMMA) Allowance to adjust RVP. Blending biobutanol at 16.1 vol % will provide additional environmental benefits by reducing benzene and sulfur emissions. However, EPA's proposal is not providing any credits for blending biobutanol above the percentage the BOB was intended. For example, it is expected that a BOB intended for E10 will be used to blend 16.1 vol % biobutanol. By blending 16.1 vol % biobutanol, benzene and sulfur will easily be reduced in the final finished fuel, providing significant environmental benefits. In order to level the playing field between ethanol and biobutanol, NMMA recommends that EPA allow biobutanol blenders to add additional butane without being required to register as a refiner. The ability to blend butane will be important, particularly when using low RVP blendstocks and also will be important when considering the higher cost of biologically produced isobutanol and its ability to reduce RVP. Indeed, biobutanol will provide environmental benefits by reducing benzene and sulfur so this recommendation would be a fair trade-off in light of the regulations not providing credits. [EPA-HQ-OAR-2018-0227-0034-A1, pp.2-4] Response: We do not believe that it is necessary to provide additional flexibilities to blend butane into gasoline-isobutanol blended fuels. Parties that wish to add butane into PCG may already use 366 ------- either the certified butane blending provisions or the provisions for PCG to certify new batches when butane is added to PCG. We understand that the certified butane blending provisions limit the addition of certified butane into summer RFG, but this limitation is necessary to ensure that the summer RFG 7.4 psi RVP standard results in an RFG average 7.1-7.2 psi RVP. If we allowed parties to use the certified butane blending provisions for RFG in the summer, to accommodate isobutanol blending or otherwise, downstream parties would likely take advantage of the 0.2-0.3 psi RVP headroom that we assumed when translating the part 80 RFG VOC performance standard into a maximum RVP per-gallon standard. For CG, we believe that the certified butane blending provisions provide sufficient flexibility for parties to blend certified butane to accommodate gasoline-isobutanol blends. Therefore, we are not extending the certified butane blending provisions or adding additional flexibility for gasoline-isobutanol blends. We are also not exempting blending manufacturers that add butane to isobutanol-gasoline blended fuels from registering as gasoline manufacturers under part 1090. All gasoline manufacturers, including parties that only add certified butane to gasoline, must register under part 1090, consistent with part 80, and we see no reason why we should treat parties that add blendstocks into gasoline-isobutanol blends differently. Comment: > Eversheds Sutherland (US) LLP With regard to PCG blending calculations, EPA should clarify if the reported batches should all occur in the same reporting period.12 [EPA-HQ-OAR-2018-0227-0076-A1, p.5] Previously Certified Gasoline The use of PCG in blending operations is a critical activity that allows for the production of gasoline throughout the country and not just limited to where there is a physical refinery. For example, PCG gasoline blending provides supplies to hubs in the Gulf Coast and New York Harbor, from where the supplies can be distributed. While refineries periodically close (the latest was last year in Philadelphia), no new refineries are being built, so blending operations remain critical to providing gasoline supplies. When PCG is blended with blendstocks to make gasoline, the Proposed Rule allows for compliance to be demonstrated through subtraction or addition.13 EPA's initial drafts would have materially changed current PCG rules, but the Proposed Rule largely adopts the current PCG rules as it should. Eversheds Sutherland supports this approach that is consistent with the current rules, subject to the following comments. The Proposed Rule states that the PCG's sulfur and benzene content must be sampled and tested before blending with blendstocks occurs.14 First, there may be blending with other PCG as well as with blendstocks, which is not specifically referenced in the proposed language but still should clearly be allowed. We assume such activity, which is currently allowed under the rules, will continue to be allowed and request that EPA provide notice for all to comment on if not. Second, the Proposed Rule requires testing of the PCG volume in every instance prior to blending. Sampling and testing is not possible in every instance, and therefore, blending 367 ------- manufacturers should be able to rely upon the certificate of analysis ("COA") received from its supplier in certain circumstances. For example, every time there is a purchase of PCG that is made via a tank-to-tank transfer or a pumpover, the blending manufacturer must rely upon the supplier's COA. The PCG is moved from the supplier's tank to the blending manufacturer's tank (which is likely the blend tank), and the blending manufacturer's tank is almost never going to be empty (EPA is aware of its air laws that prevent emptying tanks on a regular basis without a compelling operational need). In this instance, a supplier's COA is the most accurate recording of the PCG's properties, and is likely more representative than a testing of the blend tank prior to and after the receipt of the PCG, where a blender would backout the tank bottom properties. Such testing and backing out is unnecessarily burdensome and results in two additional samples and testing events, an outcome that EPA states it is trying to avoid in this streamlining effort. Transfers also may happen where the supplier's PCG is transferred from a barge to the blend tank. While the PCG could be sampled and tested in the barge and prior to transfer, the supplier's COA taken from its tank prior to barge loading may be preferable, in part to show homogeneity. The supplier's COA is the document that the supplier used itself for compliance purposes and thus is quite accurate and best represents the fuel. Again, an additional sample and test that is unnecessary—indeed it may be impossible to conduct—should be not be mandated. Eversheds Sutherland requests that EPA modify the language to allow use of the supplier's COA but limited only to cases where the blending manufacturer is actually receiving the same barrels of fuel that the supplier sampled. This would not include pipeline shipments, and it would also not include imports. We suggest the following: §1090.1320(a)(1) Compliance by subtraction, (i) Sample and test the sulfur and benzene content of each batch of PCG before blending blendstocks to produce a new batch of gasoline. The supplier's test results can be used in lieu of sampling and testing if the PCG was received directly from the supplier via in-tank transfer or tank-to-tank transfer, including via barge, within the same terminal and is a representative sample of the PCG; the supplier's test results could not be used for imports or when the PCG is commingled with other fuel, (new language in italics.) [EPA-HQ-OAR-2018-0227-0076-A1, pp.5-6] Batch Certifications When certifying a batch volume, EPA needs to allow for the ability to recertify a tank at the beginning of a new year (i.e., new compliance period).15 This allows for PCG in the tank to "rollover" to the new period and ends RVO tracking on December 31. Otherwise, there are times when a blend tank may pump volume certified from the previous year to a truck rack in March or April, and under the current language, the fuel manufacturer could not finalize any year end reporting until that pump date if recertification is prohibited. We understand that the provision on PCG batch certification at § 1090.1100(b) (3) applies when only PCG and PCG are fungibly combined, and not when any blendstock is used and the provisions of § 1090.1320 apply. [EPA-HQ-OAR-2018-0227-0076-A1, pp.6-7] 368 ------- 12 Id. at § 1090.700(d). 13 Id. at § 1090.1320. 14 Id. at § 1090.1320(a) (1) (i). 15Id. at § 1090.1100(a)(3). Response: We have revised §1090.700(d) to clarify that under a compliance by subtraction scenario, the PCG batches and the new batches that are blended from the PCG must all be accounted for within the same compliance period, and to state that this may necessitate splitting a volume of PCG that is blended with blendstock in more than one compliance period into two batches. It is our intent to allow "blending with other PCG as well as with blendstocks". However, we believe that §1090.1320 already allows this as written. Finally, we have revised §1090.1320 to allow the supplier's test results to be used in lieu of testing of PCG under certain circumstances. Comment: > Turner, Mason & Company (TM&C) Subpart M - Sampling. Testing, and Retention RVP measurement requirements for Compliance by Addition (CBA) In 1090.1320(a)(2), the requirements for testing of the blendstock, specifically RVP, is inconsistent with other sections of the regulation. First, the detailed colorcoded batch reporting summary table (Appendix B, Table 1), does specify PCG by Addition "Blendstock" to require RVP to be tested and reported during summer time only (denoted by a 4). Next, 1090.1320(a) (2) (i) only specifies to "Sample and test the sulfur and benzene content of each batch of blendstock used to produce a new batch of gasoline from PCG." There is no further statement in this section regarding the RVP of the blendstock. In regards to the reporting requirements stated in 1090.905(c) (4) (i), the RVP of the batch for summer gasoline is incorporated. We recommend the following language for 1090.1320(a)(2) to provide clarification. (2) Compliance by addition, (i) Sample and test the sulfur and benzene content of each batch of blendstock used to produce a new batch of gasoline from PCG, and the RVP of each batch of blendstock used during the summer control season. [EPA-HQ-OAR-2018-0227-0045-A1, p.4] Again, the same inconsistency is observed for adding blendstock to TGP in 1090.1325(c) and Appendix B, Table 1. The following language is recommended to provide clarification. 369 ------- (c) Determine the volume, sulfur content, and benzene content, and the RVP during the summer control season, 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. [EPA-HQ-OAR-2018-0227-0045-A1, p.4] However, the requirement should be further streamlined by eliminating the testing of the RVP of each batch of blendstock. Measuring the RVP on the blendstock does not provide any additional regulatory value, but rather adds additional economic burden to the industry. The above recommended language of 1090.1320(a)(2)(i) and 1090.1325(c) would therefore need to be modified in support to removing this requirement. In addition, the reporting requirements stated in 1090.905(c) (4) (i) requires alignment. [EPA-HQ-OAR-2018-0227-0045-A1, pp.4-5] Response: Our intent was to not require RVP testing for blendstock added to PCG using compliance by addition. We have revised the batch reporting table to be consistent with this approach. Comment: > Turner, Mason & Company (TM&C) Subpart M - Sampling. Testing, and Retention Oxygenate measurement requirements According to 1090.1320(b), the fuel manufacturer, regardless of the approach used (CBA or CBS), is required to measure the oxygenate content of each blended batch of gasoline. The language, as written, contradicts with Appendix B, Table 1, PCG by addition "PCG + Blendstock (Final.)" We provide the following suggestion for clarification. 1090.1320(b) Regardless of the approach used under paragraph (a) of this section, fuel manufacturers must determine the volume of each blended batch of gasoline, and perform the following measurements for each blended batch of gasoline using the procedures specified in §1090.1320(b). We provide the following suggestion for clarification. (1) Measure the sulfur content, benzene content, for CBS oxygenate content, and for summer gasoline, RVP. [EPA-HQ-OAR-2018-0227-0045-A1, p.5] However, the requirement could be further streamlined for the final batch of PCG by addition "PCG + Blendstock (Final)" to be exempt from this requirement if the following are satisfied: 1) the records for the PCG or blendstock show no oxygenate content, 2) no oxygenate was added to the final gasoline batch, and 3) the refiner or blending manufacturer does not account for downstream oxygenate blending. This approach would need to be carried through to the reporting requirements under 1090.905(c) (4) (i) for testing and reporting the oxygenate type and content of the blendstock. The attestation procedures outlined in 1090.1800 would provide the 370 ------- necessary oversight to ensure this exemption is satisfied. [EPA-HQ-OAR-2018-0227-0045-A1, p.5] Furthermore, in 1090.1320(a)(2) or (b), the proposed language does not require the blendstock to be measured for oxygenate content. Appendix B, Table 1, contradicts the proposed language. For PCG by Addition "Blendstock," the oxygenate % is denoted as "1" to be "Measure/Test and Report." It is unclear the intent of the agency in regards to measuring the oxygenate content of the blendstock; potentially, the proposed streamlined approach outlined in the paragraph above could be applied to the blendstock requirements as well. For transmix processors producing gasoline by only adding TGP to PCG, 1090.1325(e) allows for the exemption of measuring the oxygenate content of the finished gasoline if the records for each blendstock show no oxygenate content. We support this allowance and recommend the agency consider this with the streamlined approach outlined above. [EPA-HQ-OAR-2018-0227-0045-A1, p.5-6] Response: We have revised §1090.1310(e) to state that gasoline produced by blending blendstocks with PCG or by using TGP has to be tested for oxygenate unless: (1) PTDs for PCG demonstrate that the PCG did not contain oxygenates, and (2) the gasoline manufacturer obtains test results or affidavit from the person providing the blendstock demonstrating that there is no oxygenate in the blendstock. We have also revised Table 1 in the final batch reporting form instructions to clarify when oxygenate content must be measured or reported for the blendstock under compliance by addition. We have also made corresponding revisions to the batch reporting requirements specified at §§1090.905(c) (4) (i) and 1090.905(c) (4) (ii). 21.2. Gasoline Deposit Control Comment: > Afton Chemical Corporation Certification testing procedures - We are requesting that the Federal BMW testing option remain in place until a new test with industry consensus and similar stringency can be included in the regulation. Modernizing the test fuel - We request consideration of a new, more modern and easily obtainable certification fuel to replace the out-date 1994-vintage certification fuel currently required in the regulations. We would prefer a performance-based standard for test fuel selection rather than one that specifies chemical limits on the fuel blend. 371 ------- Applicability to more modern vehicles - We support the inclusion of a test for gasoline direct injection (GDI) injector deposit control when one becomes available at some point in the future, and if there is sufficient data to link injector deposit control in GDI engines to emission reductions or air quality improvements. We request that EPA make adoption of this new test possible by a streamlined approval approach. [EPA-HQ-OAR-2018-0227-0038-A1, pp. 1-2] Certification testing procedures The NPRM proposes to modify the testing procedures used to determine the Lowest Additive Concentration (LAC) of a certified gasoline detergent. Afton agrees with the opinion that the BMW is old and no longer representative of modern engine technology, so we support EPA's proposed allowance for a new test once it becomes available and has been shown to correlate to one of the legacy tests. That correlation is important as EPA intends to modernize the certification test but not change the severity of the test or raise the LAC treat rate from historical levels. In the interim, however, we are concerned with the other options that are proposed. CARB-based testing requires an average IVD result of 50 milligram (mg) maximum for a detergent used in a fuel certification, a result half the 100 mg result allowed on a Federal BMW test. In our experience, this difference in specifications will result in LACs that are higher than typical LACs, sometimes significantly higher. Although accepting CARB-based certification data would be a streamlining and cost-saving registration approach for some approvals, it is not a viable alternative to the Federal BMW test outside of California because of the expected treat rate difference. As with the CARB-based test method, we believe the Ford test, ASTM D6201, is also more severe than the Federal BMW test. TOP TIER requires a reduction from a 500 mg base fuel deposit level to a 50 mg maximum deposit level for an additive at a specified treat rate, which is a 90% reduction. The current Federal test procedures only require a 67% reduction (from 290 to 100 mg), so again this is not an equivalent determination. Some SAE papers (SAE 92261, SAE 981365) suggest a 100 mg BMW result is equivalent to a Ford 2.3L result of 130-140 mg. A better option might be to accept a 135 mg Ford 2.3L result in lieu of a 100 mg BMW result. This is also consistent with the requirements of the Canadian General Standards Board — they accept a 135 mg Ford 2.3L test result for compliance with their gasoline detergency requirement. Because both the CARB-based and Ford test methods are more severe, Afton recommends retaining the Federal BMW test on an interim basis until a new test, presumably resulting from an industry effort coordinated through the Coordinating Research Council, becomes available. This would preserve a test option for parties needing to certify an additive who are concerned about the potential for an LAC higher than otherwise expected when using the CARB-based or Ford test methods. This would also be consistent with EPA's acceptance of CARB data for certification, since the CARB protocol is also based on IVD control demonstrated on the same ASTM D5500 BMW test. We agree with EPA's position that detergent certification data will not be required when submitting a certification but will be made available to EPA upon request. We support the 372 ------- removal of a PFI requirement from the rules and agree with the EPA view that an additive treat rate that controls intake valve deposits will also control deposits on port fuel injectors. We have one additional comment regarding the acceptance of a CARB certification. Accepting a CARB data set for certification would mean that a PFI test would need to be run. In much the same way as EPA extracted the IVD requirement from the TOP TIER protocol, EPA could allow the use of the CARB-based BMW procedure without requiring the PFI test. This would mean that a full CARB certification would not be referenced — only the IVD test it requires. CARB does not certify additives — it certifies fuel formulations that include an additive, so you can consider the certification tests as separate from the fuel certification. Modernizing the test fuel As an additive manufacturer, Afton runs many deposit control tests using large quantities of test fuel. We support modernizing the test fuel required for certification testing. The current rules require us to obtain 1994-vintage fuels from specialty fuel blenders. It is difficult to use current fuel blend stocks to produce these fuels. One obvious example is the 340-ppm sulfur requirement, which requires sulfur additives to be used. These specialty fuels are expensive and often have long lead times for supply. A more modern fuel would be easier to obtain and more representative of fuels in the marketplace today. We anticipate that a more modern fuel will be specified in the potential replacement test for the BMW test. We believe that the test fuel should be specified based on its deposit control performance alone. This is consistent with our view that test specifications should be performance based, not chemically based. A passing maximum deposit limit and a qualifying minimum base fuel deposit limit could be proposed, or a percentage improvement from an additive case over a base case. Today's BMW-based standard, for example, requires a 67% reduction in intake valve deposits. Applicability to more modern engines EPA has requested comments regarding the efficacy of the current detergent standard at controlling deposits in modern engines. As fuel economy standards have been raised, many automakers have shifted away from port fuel injection (PFI) to gasoline direct injection (GDI) to improve fuel economy. At the time the EPA detergent rules were written, there were no GDI engines in the marketplace. Today, GDI engines are in over 50% of new vehicles sold, and they represent a growing portion of the US light duty fleet. The current standards require demonstrated deposit control performance for intake valves and port fuel injectors. There is no current industry-standardized test for injector deposit control in GDI engines, although there are efforts underway in both Europe and the US to develop tests. Afton would support the inclusion of a test for GDI injector deposit control when one becomes available at some point in the future, and if there is sufficient data to link deposit control in GDI injectors to emission reductions or air quality improvements. Perhaps EPA could include some language in their rule to easily adopt a GDI injector test standard, in much the same way as it has shown flexibility in adopting a new test to replace ASTM D5500. This would facilitate emissions and fuel economy benefits for all the vehicles in the car park. 373 ------- In the short term, Afton has already expressed concerns about the potential for unfavorably high treat rates for new additives registered during the proposed gap between retiring the Federal BMW and the adoption of new test that correlates to the legacy tests. This concern is even more significant if it becomes an impediment to the use of new additive formulations that target enhanced GDI performance. New additive formulations will be potentially disadvantaged because they will be registered using CARB or Ford 2.3L TOP TIER IVD data, which are more severe test options. [EPA-HQ-OAR-2018-0227-0038-A1, p.2-4] > Alliance for Automotive Innovation Auto Innovators provides the following supportive comments on the subject of gasoline detergency requirements. Auto Innovators supports EPA's proposal to amend the intake valve deposit control test procedure [...]. [EPA-HQ-OAR-2018-0227-0051-A1, p.l] Auto Innovators agrees that the composition of the test fuel, based on 1990 gasoline survey data, is not representative of today's gasoline. Gasoline composition has changed significantly since 1990, with fuel quality requirements and the widespread use of E10 which, as EPA states, results in today's gasoline having different deposit-forming tendencies as compared to 1990 gasoline. EPA has proposed changing test procedures to either California's deposit control program or the Top Tier program, and for the reasons described above, we support EPA's proposal. [EPA-HQ- OAR-2018-0227-0051-A1, pp.1-2] > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) 3.8 Gasoline Deposit Control EPA has proposed changes to the gasoline deposit control testing procedures for determination of the lowest additive concentration ("LAC"). EPA has stated that their objective is to not make substantive changes to the regulations, but to only simplify the rules necessary for compliance. However, the new requirements in §1090.1395 represent a material change in LAC deposit control performance without any demonstration of the technical need nor consideration for the cost impact. Therefore, the Associations recommend that the EPA should: 1. Keep the ASTM D5500 method found in §80.165 and CARB's requirement for intake valve deposit performance and eliminate the port fuel injection testing requirement (ASTM D5598). 2. Keep the current option for the more stringent TOP TIER™ test method as an alternative certification test procedure as provided in 40 CFR §80.176 for those marketers who intend to use TOP TIER™ or higher treat rates. 3. Consider allowing §1090.1395(a) to reflect the correlation between the existing ASTM D5500 detergent certification test and the ASTM D6201 test utilized by the voluntary TOP TIER™ detergent standard using the correlations from SAE 981365 (greater than 310 mg/valve on average for unadditized IVD and less than 135 mg/valve on average for additized). 374 ------- 4. Engage in a separate rulemaking process to allow time for all the facts, ramifications, advantages, and disadvantages to be fully explored. This would also allow time for continued progress on development of a new test and time to better understand the potential differing needs for the GDI technology engines. [EPA-HQ-OAR-2018-0227-0074-A1, p. 19] The Associations provide additional information describing the rational for our concerns below. [EPA-HQ-OAR-2018-0227-0074-A1, p. 19] Limiting certification test methods to TOP TIER™ or CARB will result in substantially increased treat rate requirements. Per the NPRM, until an alternative method can be developed and fully correlated, the only options will be the TOP TIER™ and CARB certification test methods. A review of available data shows that the typical TOP TIER™ and CARB treat rates are about 2.5 and 1.7 times the current EPA LAC treat rate, respectively. 13 EPA has acknowledged that both the TOP TIER™ and CARB procedures could result in higher detergent treat rates. 14 As an alternative, the agency states that industry could petition it to adopt updated deposit control additive ("DCA") procedures. 15 Cooperating vehicle and fuel manufacturers, as part of the Coordinating Research Council, are beginning research to qualify an alternative test. However, it is the Associations' estimate that this process, if successful, will take at least two to three more years before that test can be finalize and a petition filed with EPA. [EPA-HQ-OAR- 2018-0227-0074-A1, pp.19-20] EPA has not demonstrated any environmental benefit from the proposed change. EPA has not evaluated the impact of such higher LAC levels on existing and new engines and whether that could adversely affect those engines or air emissions. [EPA-HQ-OAR-2018-0227-0074-A1, P-20] As the US car fleet continues to evolve with an increase in gasoline direct injection ("GDI") engine technologies, it is highly likely that changes in additive chemistry will be necessary. This will require new LAC testing and certification using either the TOP TIER™ or CARB testing methods. Historically, additive manufacturers have preferentially developed generic additives for port fuel injected engines and have only recently begun to modify the chemistry to benefit GDI engines. Therefore, it is highly likely that additive suppliers will develop new formulations that will be phased in over the next seven to 10 years. Under EPA's NPRM, certification of these new additives will be completed with either TOP TIER™ or CARB testing methods. [EPA-HQ- OAR-2018-0227-0074-A1, p.20] Cost of higher treat rates is significant and will be borne by consumers. The changes to the certification requirements for the LAC proposed in §1090.1395 will have a significant impact on LAC treat rates and costs for the industry. The additional costs of the additive must be considered by EPA when calculating the costs and benefits of the proposed Streamlining Rule. This proposal is also contrary to EPA's stated intent not to increase regulatory burden. [EPA- HQ-OAR-2018-0227-0074-A1, p.20] Utilizing EPA's net present value ("NPV") calculations, as presented in the EPA docket in an Excel file, 16 the economic impact of the more stringent LAC requirements has been estimated. 375 ------- The estimated costs are dependent on whether TOP TIER™ or CARB testing is used for LAC certification with the latter resulting in a smaller, but still significant impact to the NPV30 calculations. The large cost resulting from a more stringent TOP TIER™ based LAC requirement will overwhelm the entire cost savings EPA has estimated for the proposed Fuels Regulatory Streamlining. When the two estimates are combined at the 3% discount rate, a NPV30 of between $40m to -$219m results; a significant reduction from the EPA's calculated NPV30 of $560m.l7 This demonstrates the significant financial impact that the increased stringency will have on the value for EPA's streamlining efforts and must be included in the required cost/benefit analysis. [EPA-HQ-OAR-2018-0227-0074-A1, p.20] 13 Based on confidential additive treat rate (EPA/CARB LAC and TOP TIER™) information from various additive suppliers. 14 See 85 Fed. Reg. 29082. 15 Id. 16 See EPA-HQ-OAR-2018-0227-00150, www.regulations.gov. 17 See Table XIV.C-2 85 Fed. Reg. 29086. > bp America Inc. (bp) The detergent additive testing procedure requirements to determine the lowest additive concentration (LAC) proposes to remove the BMW Test Method as an acceptable method for determining LAC. The removal of that method would be inappropriate considering changes in engine technology, the improvement of fuel quality, and the impact that removal would have on future additive testing, engine performance, and the overall cost of the changes to the Streamlining Rules. [EPA-HQ-OAR-2018-0227-0046-A1, p.2] Gasoline Deposit Control Testing §1090.1395 Gasoline deposit control test procedures The proposed gasoline deposit control test procedures in §1090.1395 provide three options for certifying new deposit control additives: Top Tier test method, the CARB test method, or a method that is correlated either to one of those two methods or the retired EPA BMW test method. The EPA BMW test method is currently required by the Deposit Control Additive (DCA) rules in 40 CFR Part 80, Subpart G. Even though one of the proposed options in §1090.1395 is to correlate an alternative test method to the retired BMW test, that is currently not a feasible option. That is a much more complex and lengthy process than correlating a laboratory test method to a referee method. Cooperating vehicle and fuel manufacturers as part of the Coordinating Research Council are beginning research to qualify an alternative test. However, it is bp's estimate that this process, if successful, 376 ------- will take at least 2-3 more years before that test can be finalized and will not be finalized until well after the expected effective date of the EPA Fuels Streamlining Rule. Consequently, if the EPA detergent additive proposal is finalized in its current form, the only available test methods until an alternative method can be correlated will be the Top Tier and CARB test methods. The problem with both of those tests is that they would result in higher Lowest Additive Concentrations (LAC) for new additives. Modern gasoline is much cleaner and is expected to have significantly less deposits than was the situation when the first DCA rules were promulgated. A review of available data shows that the typical Top Tier treat rate is about 2.5 times the current EPA LAC treat rate.2 This significant increase in LAC treat rate that will result from this proposal will not only be more costly for fuel manufacturers, but will also result in higher prices for consumers without any tangible benefit. Furthermore, EPA has not evaluated the impact of such higher LAC levels on existing and new engines and whether that could adversely affect those engines or air emissions. Simply put, there is no evidence that increased levels of gasoline detergent are warranted to support this proposal. Today's modern, gasoline direct injection engines have evolved from traditional port fuel injection engines and may have significantly different additization requirements to optimize intake valve and fuel injector deposit protection. About 50% of today's newly manufactured vehicles have direct fuel injection so they could potentially be at risk for deposit formation. Neither EPA, nor the industry, has sufficient evidence of the effect that increased additization could have on modern engines and air emissions and should take the time to understand those and other potential impacts. Furthermore, given the advances in fuel quality in the last couple of decades, gasoline has less need for increased additization to assure good performance and adherence to regulated emissions limits. EPA acknowledged the need for updated detergent additive data in the preamble: "... given the lack of emissions test data on the effects of deposits on the emissions from modern vehicles, we are unable to quantify the emissions benefits of different levels of deposit control stringency under the detergent program today." (85 Fed. Reg. 29080) EPA further acknowledged that the Top Tier program was established by the automotive industry based on the premise that a superior level of deposit control was needed for vehicles in use in 2004. (85 Fed. Reg. 29081) The agency also noted that the technology used in the Top Tier procedure (ASTM D6201) is no longer representative of the majority of the vehicles on the road today (85 Fed. Reg. 29082) and that both the Top Tier and CARB procedures could result in higher detergent treat rates. (85 Fed. Reg. 29082) EPA admitted that the use of these two procedures could impact the use of new additives but brushed that concern aside on the basis that it only receives "several applications a year". As an alternative, the agency claimed that industry could petition it to adopt updated DCA procedures. (85 Fed. Reg. 29082) As noted in our comments above, the development of a new test procedure is years away. Requiring a petition process on top of that would only further delay the implementation of a new procedure. All of these facts collectively suggest that EPA should not make any changes to their existing detergent additive rules at this time and certainly should not make them more stringent until all 377 ------- of these issues can be more fully explored in a separate rulemaking process that would lend itself better to examining these issues in more detail supported by technical evidence. Throughout the streamlining process, EPA has stated that their objective is to not make substantive changes to the regulations, but to only simplify the rules necessary for compliance. This does not appear to be true for §1090.1395. The new requirements represent a material change in LAC deposit control performance without any demonstration of the technical need nor consideration for the cost impact. Therefore, bp continues to strongly oppose EPA's proposed changes to the gasoline deposit control rule detailed in §1090.1395 for the following additional reasons: 1. EPA has stated a desire to retire the BMW vehicle test (ASTM D5500) as it is believed to not adequately represent modern engine/vehicle technology. However, this is directly contradicted by the inclusion of the CARB-Based Test Method described in §1090.1395(b). The test procedure specified by CARB in Title 13, California Code of Regulations, section 2257(c) (i) states that "the gasoline formulation meets a maximum of 50 milligrams averaged over all intake valves when tested in accordance with ASTM D5500-98, which is incorporated herein by reference." Therefore, EPA has not retired ASTM D5500 but has only made the certification more restrictive by requiring a passing result to be 50 mg/valve (CARB) rather than the 100 mg/valve in the current LAC requirement (§80.165(b)). 2. §1090.1395(a) also significantly changes the severity of the certification test by proposing that the Top Tier-Based Test Method be used to establish the LAC for detergent additives using ASTM D6201. ASTM D6201 is a test method that the automobile industry has utilized for additive certification under the voluntary Top Tier gasoline detergent standard. Until now, neither EPA nor fuel providers have accepted the Top Tier test method as a minimum performance requirement. EPA has stated during the streamlining process that "It is widely accepted that conformance with the Top Tier IVD and FID control testing requirements is more challenging than complying with the standard EPA IVD and FID testing requirements." 3 In order to achieve the proposed testing methodology and performance criteria addressed in 1 and 2 above, fuel distributors will need to increase the lowest additive concentration in their fuels thereby increasing their costs which will be passed on to consumers. [EPA-HQ-OAR-2018- 0227-0046-A1, pp.24-26] Costs and Benefits EPA stated that "we are not proposing changes to the stringency of our standards" on 85 Fed. Reg. 29086 of the NPRM, but the proposed changes to the gasoline deposit control test procedures will result in increased stringency. The changes to the certification requirements for the lowest additive concentration (LAC) proposed in §1090.1395 will have a significant impact on LAC treat rates and costs for the industry over the next 30 years. The additional costs of the additive will ultimately be passed on to the consumer and should be considered by EPA when calculating the costs and benefits of the proposed Streamlining Rule. 378 ------- A review of confidential additive treat rate information provided by several additive suppliers reveals that additive certification using the Top Tier testing method (§1090.1395 (a)) would lead to new additive LAC treat rates of approximately 2.5 x that of current LAC treat rates certified through ASTM D5500 testing and approximately 1.7 x higher treat rates for new additives using CARB LAC certification (§1090.1395 (b)).4 As the US car pare continues to evolve with an increase in gasoline direct injection (GDI) engine technologies, it is highly likely that changes in additive chemistry will be necessary. This will require new LAC testing and certification using either the Top Tier or CARB testing methods. Historically, additive manufacturers have preferentially developed generic additives for port fuel injected engines and have only recently begun to modify the chemistry to benefit GDI engines. Therefore, it is highly likely that additive suppliers will develop new formulations that will be phased in over the next 7-10 years. Certification of these new additives will be completed with either Top Tier or CARB testing methods. The NPV30 impacts of the associated additive cost increase can be calculated using the following assumptions. 1. Percent of overall US gasoline volume treated with generic additives at the LAC rate: -40% of US Market5'6 2. New additive certification and introduction anticipated over the next seven years a. Additive Company A: 2023 with approximately 40% of the generic additive market b. Additive Company B: 2025 with approximately 10% of the generic additive market c. Additive Company C: 2027 with approximately 50% of the generic additive market 3. Effect of proposed detergent additive testing requirements on generic additive LAC treat rates compared to current LAC requirements a. Top Tier LAC: Approximately 2.5 x higher treat rate b. CARB LAC: Approximately 1.7 x higher treat rate 4. Additive cost sensitivity7 a. Estimated average cost of the additive per pound b. 120% of estimated average cost of additive per pound c. 80% of estimated average cost of additive per pound The total cost savings estimated by EPA from the simplification and/or elimination of certain requirements (e.g., testing and reporting) was $32.9 million in 2019 dollars (Table XIV.C-l on 85 Fed. Reg. 29086). EPA has calculated the NPV for these cost savings over the next 30 years at discount rates of 3% and 7% (Table XIV.C-2 85 Fed. Reg. 29086) with NPV30 values of 379 ------- $560m and $380m, respectively. The calculations used for these net present value estimates are presented in the EPA docket in an Excel file (EPA-HQ-OAR-2018-0227-00150) using estimates for various changes in fuel sampling and analysis. However, these calculations do not include the potential cost of an increase in detergent additive treat rate that will result from the proposed regulations for LAC certification. Using the assumptions above and the EPA Excel spreadsheet, significant additive costs will begin to be passed on to the consumer in 2023 and be fully implemented in 2027. The estimated costs are dependent on whether Top Tier or CARB testing is used for LAC certification with the latter resulting in a smaller, but still significant impact to the NPV30 calculations. However, both have been used below for cost comparison purposes. A standard NPV30 calculation was conducted using the above assumptions and the data/calculations given in "Cost Summary" tab of EPA's EPA-HQ-OAR-2018-0227-00150 Excel spreadsheet.8 The table below shows the impact of these more stringent additive certifications on the net present value costs at the 3% discount rate. An additive cost sensitivity was used since the additive price tends to fluctuate with the price of crude oil and the chemistry used in the additive formulation. Confidential additive costs per pound averaged over the past 4 years were used as the baseline with ±20% sensitivity scenarios. The column for "Estimated NPV30 for Top Tier LAC" shows the significant cost associated with utilizing the Top Tier testing method for LAC certification with costs at the 3% discount rate of between -$518m to -$778m. This large cost for additional additive overwhelms the entire cost savings EPA has estimated for the proposed Streamlining Rule when the two are combined leading to NPV30 of between $40m to -$219m. A lower, but still significant impact is seen when using the CARB LAC testing method for future additive certification that results in a reduction of EPA's NPV30 of between 43 and 65%. Both additive certification scenarios show the financial impact that the increased stringency will have on the value for EPA's streamlining efforts and should be included in any cost/benefit analysis. [See table on p.28 of EPA-HQ-OAR-2018-0227-0046-A1] [EPA-HQ-OAR-2018-0227-0046- Al, pp.26-28] bp's recommendation The proposed Streamlining Rule has proposed changes to the gasoline deposit control testing procedures for determination of the lowest additive concentration (LAC). EPA has stated that their objective is to not make substantive changes to the regulations, but to only simplify the rules necessary for compliance. The new requirements of §1090.1395 represent a material change in LAC deposit control performance without any demonstration of the technical need nor consideration for the cost impact, bp recommends that the EPA should: 1. Keep the ASTM D5500 method found in §80.165 and CARB's requirement for intake valve deposit performance and eliminate the port fuel injection testing requirement (ASTM D5598) 2. Keep the more stringent Top Tier test method as an alternative certification test procedure as provided in 40 CFR §80.176 for those marketers who intend to use Top Tier or higher treat rates. Consider allowing §1090.1395(a) to reflect the correlation between the existing ASTM D5500 detergent certification test and the ASTM D6201 test utilized by the voluntary Top Tier 380 ------- detergent standard using the correlations from SAE 981365 (greater than 310 mg/valve on average IVD for unadditized fuel and less than 135 mg/valve on average IVD for additized fuel) as shown below. a. §1090.1395(a) (2): Perform the 100-hour test for intake valve deposits with the base fuel to demonstrate that the intake valves accumulate at least 310 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. §1090.1395(a)(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 135 mg average per intake valve, the tested detergent concentration is the LAC for the detergent. Given the substantial changes being proposed in the LAC provision in this rule, all the other changes in other provisions of part 1090, and the considerable costs associated with the LAC changes, bp suggests that if EPA does not accept its recommendations on LAC above, the agency should engage in a separate rulemaking process on this issue. That would allow time for all the facts, ramifications, advantages, and disadvantages of these proposed changes to be fully explored. This would also allow time for continued progress on development of a new test and time to better understand the potential differing needs for the GDI technology engines. [EPA-HQ-OAR-2018-0227-0046-A1, pp.28-29] 2 Based on confidential additive treat rate (EPA LAC and Top Tier) information from various additive suppliers. 3 Federal Register/Vol. 79, No. 81/Monday, April 28, 2014/Rules and Regulations; 23591 4 Confidential business information from Additive Suppliers for EPA LAC, CARB LAC and Top Tier treat rates of generic gasoline deposit control additive packages 5 LAC market for generic additives is approximately 40% of overall annual US gasoline demand based on market surveys 6 U.S. Energy Information Administration Frequently Asked Questions; How much gasoline does the United States consume? In 2019, about 142.23 billion gallons (or about 3.39 billion barrels) of finished gasoline were consumed. (https://www. eia.gov/tools/faqs/faq. php?id=23&t= 10) 7 Confidential business information estimating average cost per pound for gasoline additive packages over the period from 2016 through 1Q 2020. 8 See EPA-HQ-OAR-2018—227-0015_LAC Effects for details > Chevron Oronite Chevron Oronite's comments to this Fuels Regulatory Streamlining NPRM are focused on aspects related to proposed changes to the requirements and options for EPA Lowest Additive Concentration ("LAC") certifications of gasoline detergent additives: 381 ------- • New ASTM D5500-based EPA LAC certifications should be allowed as long as the relevant test equipment and certification fuel are available. EPA has not demonstrated a benefit for eliminating this option for certification testing at a time earlier than when the test equipment and/or certification fuels become unavailable. • Using California Air Resources Board ("CARB")-based certification testing as a substitute for the current EPA LAC certification process does not provide a practical solution to ASTM D5500 test availability, since it uses the same test equipment. • Allowing only current CARB or TOP TIER™ standards for new EPA LAC certifications before the completion of a new deposit control test to replace ASTM D5500 is not appropriate, since that introduces a different minimum standard of performance between existing products and newly-certified products that could be in the commercial market simultaneously. Aggregated, anonymized data collected by industry stakeholders has demonstrated that either CARB or TOP TIER™ certification standards for a given gasoline detergent additive require higher treat rates (commonly > 1.5x) than the EPA LAC certification standards for the same gasoline detergent additive. • Allowing EPA LAC certification options that reflect higher performance standards than the current ASTM D5500-based requirements (for example, CARB or TOP TIER™ standards) is acceptable, but not as the only options available. • Allowing new ASTM D6201-based certifications at the correlated performance levels established in SAE 981365 should be given further consideration as an available option to new ASTM D5500-based EPA LAC certifications, in order to maintain better parity of performance standards between existing and future certifications. The testing programs summarized in this peer-reviewed publication showed this approximate equivalence between ASTM D6201 deposit level averages and current EPA LAC certification standards: o Minimum for base fuel severity demonstration (310 mg/valve average in ASTM D6201 compared to 290 mg/valve average in ASTM D5500) o EPA LAC certification maximum (135 mg/valve average in ASTM D6201 compared to 100 mg/valve average in ASTM D5500). • Existing EPA LAC certifications should remain valid as long as there is no fundamental change in EPA LAC requirements based on updated emissions performance standards or analysis. Existing EPA LAC certifications should not be invalidated as the result of changes related only to the available test methods for future certifications. EPA has not demonstrated the need for a change from the emissions performance standards provided by current EPA LAC certifications, nor has it published any financial cost:benefit analysis associated with the consequences of changing the fundamental standards for EPA LAC certifications. • Chevron Oronite supports dropping the EPA LAC certification requirements for PFI injector keep-clean testing. Historical industry data suggests that products passing the ASTM D5500 performance requirements for EPA LAC certification will also pass the current ASTM D5598 PFI injector keep-clean performance requirements. [EPA-HQ- OAR-2018-0227-0040-A1, pp. 1-2] > Chevron U.S.A., Inc. Gasoline deposit control additives 382 ------- Regarding the proposed revisions to the gasoline deposit control additive certification, Chevron supports the comments submitted by API/AFPM and also the comments submitted separately by Chevron Oronite, our fuel and lubricants additive company. The proposed revisions will lead to higher treat rates and consumer cost, without demonstrating a specific environmental or performance benefit as a justification. We encourage EPA to address the concerns expressed in the comments submitted by Chevron Oronite and by API/AFPM. [EPA-HQ-OAR-2018-0227- 0069-A1, p.2] > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 9. Allowing California's or the Top Tier deposit control program to be used for any new detergent deposit control testing. However, EPA must allow future consensus-based testing methods for deposit-control testing to be used. It is imperative that existing detergent certifications based on the EPA ASTM D5500 continue to remain valid indefinitely. [EPA-HQ- OAR-2018-0227-0061-A1, p.2] > Marathon Petroleum Company LP (MPC) Gasoline deposit control In section 1090.1395, EPA has proposed new requirements, which represent a material change in lowest additive concentration (LAC) deposit control performance without demonstrating a technical need for the change. In the NPRM, the EPA proposes three options to establish LAC for gasoline deposit control additives: 1. Use of Top Tier test method (modified ASTM D6201) in lieu of BMW (ASTMD5500). 2. Utilize CARB based test that does use D5500 test method but requires 50 mg/valve average 3. Future test method that correlate to Top Tier D6201, CARB, or D5500 procedures. Option 1 sets forth the use of Top Tier protocols. No data was presented that demonstrated that deposit levels from D6201 correlate/are comparable to those of the BMW D5500. In fact, the Top Tier test requires higher levels of detergent control additive to meet requirements set forth in this procedure. During the Tier 3 Streamlining, EPA said "It is widely accepted that conforming with the Top Tier IVD and FID control testing requirements is more challenging than complying with the standard EPA IVD and FID testing requirements." In addition, no data was presented to demonstrate that the higher treatment rate is necessary or beneficial for vehicles. Option 2 allows the CARB testing protocol to be employed for additive qualifications. The CARB procedure utilizes the BMW ASTM D5500 test procedure but sets a more strict limit for valve deposits, with an average of 50 mg/valve, in lieu of the 100 mg average per the BMW 383 ------- D5500. This option also requires higher concentrations of detergent control additives to meet the requirements. Option 3 allows future test methods to be employed if the procedure correlates to either the Top Tier D6201, the CARB procedure, or the BMW D5500 method. MPC believes this to be the most viable option at this time. However, based on the current work conducted by CRC, in coordination with ACC FATG, several years may pass before another procedure will be ready for consideration. In the fuels regulatory streamlining proposal, EPA expresses a goal to "retire" the BMW D5500 test procedure, the reason being EPA does not believe the BMW D5500 test represents modern engine/vehicle technology. However, the fuels regulatory streamlining proposal allows for the CARB protocol (utilizing the D5500 BMW procedure with lower valve/mg deposit requirements) and/or for alternative test procedures that correlate to BMW D5500 to be introduced for consideration. For these reasons, MPC is concerned BMW D5500 will not be "retired" under the fuels regulatory streamlining proposal. Under the fuels regulatory streamlining proposal, any material changes by an additive vendor to a deposit control package grandfathered into the program requires new testing by one of the options listed above. Because only Options 1 and 2 are presently available, any subsequent testing of the deposit control package will likely result in significant increases to the amount of additive needed to comply with LAC under the proposal. This means if a vendor were to change the amount of carrier solvent by one percent (1%), then new testing protocols would be required. This requirement would equate to undue increased expenses for gasoline control package treatment on the fuel producer and ultimately to the consumer, whether for legitimate production reasons or for a vendor meeting the increased additive useage required to ensure compliance with Top Tier D6201 or CARB D5500. In light of these concerns, MPC recommends the following revisions be considered for the streamlining process: 1. Keep the option to use the current additive requirements set forth in 80.165 and the D5500 test method. 2. Maintain Top Tier D6201 as an alternative method. 3. Modify 1090.1395 so as to reflect better correlation between ASTM D5500 and D6201. Per SAE 1998-05-04 "A Statistical Review of Available Data Correlation the BMW and Ford Intake Valve Deposit Tests," a 310 mg/valve avg deposits for unadditized base gasoline, and a 135 mg/valve avg deposit for additized base fuel on the ASTM D6201 procedure, is equivalent to the BMW ASTM D5500 test results of 290 mg/valve for base gasoline and 100 mg/valve for additized fuel, respectively. 4. Keep Option 3 in the NPRM for future alternative methods once they are developed. MPC directs EPA to the more detailed comments found in the AFPM/API comments that have been submitted to the docket. MPC believes the submittal of additional comments on the issue was necessary to ensure these concerns are properly addressed. [EPA-HO-OAR-2018-0227- 0048-Al.pp.3-4] 384 ------- Gasoline deposit control test procedures In 1090.1395, the USEPA proposes three options to establish the lowest additive concentration (LAC) for gasoline deposit control additives: 1. Use of Top Tier test method (modified ASTM D6201) in lieu of BMW (ASTMD5500). 2. Utilize CARB based test which does use D5500 test method but requires 50 mg/valve average 3. Future test method that correlate to Top Tier D6201, CARB, or D5500 procedures MPC believes the proposed USEPA Streamlining process for the additive registration process under 1090.1395 Gasoline Deposit Control Test Procedure will result in more restrictive and laborious requirements that will result in the need to utilize higher levels of gasoline deposit control additives without any data having been presented to justify these changes. The increased cost in fuel additive requirements will be passed along to the consuming public. MPC recommends the following revisions be considered for the streamlining process: 1. Keep the option to use the current additive requirements in 80.165 and the D5500 test method 2. Maintain Top Tier D6201 as alternative method 3. Modify 1090.1395 to reflect a better correlation between ASTM D5500 and D6201. 3. Modify 1090.1395 to reflect a better correlation between ASTM D5500 and D6201. (please refer to more detailed comments in the next tab) [EPA-HQ-OAR-2018- 0227-0048-A2, p.2] > Phillips 66 Company Detergent Additive Certification We have provided comments on this topic in past drafts. We identified this issue as one of our top priorities due to the potential future impact. API and AFPM have provided detailed comments on the topic of detergent additive certification. We support the recommendations provided by the Associations. The changes proposed in Part 1090 could potentially have significant impact over time as new detergent formulations would result in much higher treat rate requirements. Although companies are currently participating in the Top Tier program and utilizing those testing provisions, the companies generally are not treating their entire gasoline volumes to the Top Tier level. Therefore, a change that would require all gasoline at some point in the future be treated at the higher rates would result in increased costs. We think the Association's recommendations provide a good alternative to the proposed rule. [EPA-HQ- OAR-2018-0227-0060-A1, p.8] > The American Chemistry Council, Fuel Additives Task Group (FATG) Summary of FATG Comments 385 ------- I. The FATG opposes the elimination of the Federal BMW ASTM D5500 test (Federal BMW test) test to certify detergent additives as EPA lowest additive concentration (LAC) on January 1, 2021. Until a new IVD test of similar stringency is available, and while the BMW test and EPA certification fuel are still available, the Federal BMW test should remain an option to certify new detergent additives. II. While retaining the Federal BMW test is the best compliance option in the short term, if it is eliminated, the EPA should consider a Ford 2.3L ASTM D6201 test option to certify new detergent additives as EPA LAC until the new IVD test is ready. III. The FATG supports the EPA's strategy of writing the proposed rule so that future updates may be included through an industry consensus-based administrative process and will not require a full rulemaking. IV. The FATG supports streamlining the detergent certification process and eliminating the port fuel injector deposit control testing requirement. I. Opposition to the January 1, 2021 elimination of the Federal BMW test to certify detergent additives as EPA LAC The proposed implementation date of the new part 1090 regulations is January 1, 2021, at which time the Federal BMW test will no longer be permitted to certify detergent additives as EPA LAC. The FATG opposes the elimination of the Federal BMW test for LAC certifications on that date and asks that it remain an option until a new test of similar stringency is available. In the preamble to the Proposed Rule, the EPA indicates that it does not intend to change the stringency of the existing fuel quality standards. The use of the Ford 2.3L ASTM D6201 test as incorporated in TOP TIER™, or the CARB-Based Test Method, both of which EPA proposes to allow as replacements, will likely result in an increase to LAC treat rates for newly certified detergent additives. FATG previously submitted feedback showing that, on average, CARB treat rates are 38% higher and TOP TIER™ are 90% higher than EPA LAC treat rates2. FATG believes the proposed rule does increase the stringency and create a new standard for all gasolines containing a new detergent additive certified after January 1, 2021 because of the resultant higher treat rates. EPA has not analyzed or met the statutory requirements to raise the standards under Clean Air Act section 211 (1), nor has it suggested that the current LAC are insufficient to meet the current standard. Specifically EPA has explained that LAC treat rates under 211 (1) are intended to represent "an additive treat rate that can meet the standard of performance" with " [t]he certification treat rate constituting the lowest concentration at which an additive may be used" to meet these performance standard3. Accordingly, before requiring increases in the LAC, which the proposed changes would do, EPA must explain why the current treat rates are inadequate to meet the performance standard, which it has not done. The FATG is concerned that the absence of a test of similar stringency to the Federal BMW test will be a barrier to innovation for new additives. New additives developed with the more severe testing options, the TOP TIER™ Ford 2.3L or CARB method, will have to certify to a higher 386 ------- treat rate. The FATG is concerned with the acceptance by the marketplace of new additive products certified with a higher treat rate than what is currently in use. So long as the BMW D5500 test and EPA certification fuel are available, there is no reason why the EPA should cease allowing the existing Federal BMW test LAC certification. Furthermore, the option to use a CARB-Based Test Method does not address the issue of availability of BMW's, it uses the same vehicle. II. Recommendation for additional option for new EPA LAC detergent additive certifications As described in Section I. of these comments, the FATG considers retaining the Federal BMW test as the most appropriate compliance option in the short term. However, the FATG requests that the EPA provide another option to certify a new additive as EPA LAC. Such an option is consistent with the EPA's reasoning that the Ford 2.3L engine is more available than the BMW vehicle. The EPA could establish a Ford 2.3L D6201 based LAC option with suitable base fuel and an additized fuel passing level of <135 mg/valve avg. A true 100 mg/valve BMW ASTM D5500 result is equivalent to a 135 mg/valve Ford 2.3L result. This correlation was established by a model developed by FATG member company authors as described in SAE paper 981365 entitled, "A Statistical Review of Available Data Correlating the BMW and Ford Intake Valve Deposit Tests."4 This correlation was also confirmed by AutoResearch Labs Inc. in SAE paper 922261 "Intake Valve Deposit Testing Using an Engine Dynamometer Procedure."5 This option is used for detergent additive certifications in Canada. The Canada General Standards Board (CGSB), which maintains gasoline standards in Canada, prescribes that all gasoline in Canada contain additives certified using the Ford 2.3L test with a result of <135mg/valve6. III. Support for an administrative process and industry consensus for future updates. Section 1090.1395 Gasoline Deposit Control Test Procedures lists the options to establish LAC and includes "(a) Top Tier-Based Test Method. Use the procedures specified in ASTM D6201 (incorporated by reference in §1090.95), as follows:" and lists requirements for base fuel, base fuel IVD deposit levels, and additized fuel passing IVD deposit levels. The FATG recommends EPA refer to TOP TIER™ in the same way they do for CARB-Based Test Method— without getting into the specific details and requirements. This will allow practitioners to follow changes to TOP TIER™ D6201 requirements without the need for EPA to update its document. The voluntary TOP TIER gasoline program periodically changes its requirements, i.e. base fuel specs. In the likely event that TOP TIER requirements differ from what is listed in 1090.1395 due to a change in TOP TIER, the TOP TIER certification option will no longer be viable for additive manufacturers. In the preamble Section 5. Easing the Adoption of Future Updates to Deposit Control Test Procedures, the EPA introduces the concept of an administrative approach to accept changes to the detergent additive program. The preamble states, 387 ------- Under this approach, stakeholders could petition EPA to adopt changes to the deposit control test procedures previously accepted by EPA (e.g., when an update to an existing test procedure is incorporated into an existing test method). We would then conduct outreach with stakeholders to assess whether there is sufficiently broad support for the proposed change. If we determine that this is the case and the suggested change met applicable requirements, we would publish on our webpage and by direct communications with stakeholders that we have accepted the change. The FATG is comfortable with the concept of an administrative process for the EPA to incorporate industry-acceptable tests into its regulation in the future, such as a test that has been developed or vetted by the Coordinating Research Council (CRC) or another industry body, standardized into an ASTM method, or another acceptable definition. As a stakeholder in deposit control testing, the FATG looks forward to more details on how this process will work and inclusion in those future procedure vetting discussions. This administrative process could allow for incorporation of modern tests. In the preamble Section F. Gasoline Deposit Control overview, the EPA asks for comment on the effects of the federal detergent program on controlling deposits in modern vehicles and the impact on vehicle emissions performance. Additives are currently certified for performance in intake valve and port fuel injector deposit control. The modern vehicle fleet is increasingly made up of vehicles using gasoline direct injection (GDI) technology, and, though test development efforts are underway, there is no current industry standard test to demonstrate control of GDI deposits. There is no industry-consensus data that indicates a negative impact from deposits in GDI engines on emissions or air quality. Similar to the process employed by EPA in 19957 to establish the initial LAC certifications for PFID and IVD deposit control, the EPA should only act if there is an industry accepted test available and if sufficient evidence on the emissions impact of deposits in modern GDI vehicles has been established. IV. Support for streamlining elements. The FATG agrees with the EPA's proposal that detergent certification data will not be required when submitting a certification request, but made available to EPA upon request. The FATG supports eliminating a PFI testing requirement to reduce unnecessary testing. The FATG believes that if an additive meets IVD performance requirements, it would also meet all the PFI performance requirements at the same treat rate8. [EPA-HQ-OAR-2018-0227-0043-A1, pp.1-4] 2 ACC FATG Additive Certification Information_EPA_July 2019 3 61 Fed. Reg. 35,310, 35,314 (1996). 4 Crosby, T., Ahmadi, M., Schiferl, E., Arters, D., et al., "A Statistical Review of Available Data Correlating the BMW and Ford Intake Valve Deposit Tests," SAE Technical Paper 981365, 1998, https://doi.org/10.4271/981365. 388 ------- 5 Keller, G., Shimcoski, D., and Blatz, F., "Intake Valve Deposit Testing Using and Engine Dynamometer Procedure," SAE Technical Paper 922261, 1992, https://doi.org/10.4271/922261. 6 Canadian General Standards Board, National Standard of Canada- Automotive gasoline, CAN/CGSB-3.5-2016. 7 61 Fed. Reg. 130, (1996). 8 ACC FATG feedback_EPA Potential Fuel Standard Update_June 2017 Response: We proposed to transfer the part 80 gasoline detergent provisions to appropriate sections of part 79 and part 1090. In so doing we proposed a number of actions to streamline, update, and reduce the compliance burden associated with these provisions. We received a number of comments supporting various aspects of this proposal as well as comments objecting to certain aspects or requesting additional changes. By far the majority of the comments objecting to our proposal were directed at the proposal to drop the BMW IVD (ASTM D5500) certification option for new detergent certifications. This would have left only the CARB and Top Tier options. A number of commenters noted that these options require a significantly higher level of detergency, resulting in increased costs that would be passed on to consumers. One commenter claimed that the increased costs would exceed the cost savings of this streamlining proposal. Another commenter suggested that EPA needs to evaluate the emissions benefit from the increased costs. Commenters strongly recommended that the BMW option be retained until a new test procedure, now under industry development, could be evaluated as a suitable replacement. This new procedure could take into account changes in engine technology and gasoline since the regulations were promulgated in 1996. If EPA were to finalize the removal of the BMW option, some commenters asked that EPA allow a Ford 2.3L ASTM D6201 test option (an option used for detergent additive certifications in Canada) to certify new detergent additives as EPA LAC until the new IVD test is ready. We believe that removing the BMW certification option could result in increased costs to industry and consumers. As such, we are retaining the BMW option, in addition to the other 3 options proposed, until a suitable replacement test has been developed. Therefore, we are not finalizing our proposal to remove the BMW option at this time. We received comments requesting that we modernize the test fuel for the BMW test to better reflect today's in-use fuel. While we appreciate the differences between the required test fuel and in-use fuels today, we are not changing the test fuel at this time, as that would constitute a change to the stringency of the standard, which we have not evaluated. Instead, as discussed above, we are leaving the BMW test intact. We may consider updating the required test fuels when we revise the test procedures and associated detergency requirements. The third of the three methods proposed for the gasoline deposit control test procedures in §1090.1395 allowed for a method that is correlated either to one of the other two methods or to the EPA BMW test method. We received comment supporting this, but also that we should consider finalizing a correlation between the existing ASTM D5500 detergent certification test and the ASTM D6201 test utilized by the voluntary Top Tier detergent standard using the 389 ------- correlations from SAE 981365 (greater than 310 mg/valve on average IVD for unadditized fuel and less than 135 mg/valve on average IVD for additized fuel). While we are finalizing this third method, we are not at this time establishing any correlation using this method. Our understanding is that work continues by industry in developing a modern test procedure, and therefore it would be premature for us to do so. We received comments supporting our proposal to remove the PFI requirement as well as a comment requesting that we also remove the requirement for the PFI test as part of our acceptance of CARB detergent certification. We are finalizing the provisions as proposed, and will accept CARB detergent certification as is so as not to create yet another form of detergent certification. We received comments suggesting that we adopt a detergency requirement for GDI injector deposits when such a test becomes available. We may consider doing so when the time comes. We also received comments supporting our proposal to require only retention, as opposed to submission, of the certification data so that it can be made available to EPA upon request, as well as our proposal to streamline the process of allowing future updates to the test through an industry consensus-based administrative process. We are finalizing these and other changes designed to ease the burden and/or facilitate compliance as proposed. Comment: > Alliance for Automotive Innovation Auto Innovators supports EPA's proposal [...] to remove the requirement that the gasoline portion of E85 must contain a certified detergent. [EPA-HQ-OAR-2018-0227-0051-A1, p.l] Auto Innovators also supports EPA removing the requirement that the gasoline portion of E85 contain detergent. As EPA states in the proposed streamlining: "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 increased dilution from the additional ethanol." [EPA-HQ-OAR- 2018-0227-0051-A1, p.2] > bp America Inc. (bp) §1090.640 §1090.640 would exempt gasoline used to manufacture E85 from the deposit control requirements. Under the definition of E85, the gasoline component can be almost 50% of the gasoline/ethanol blend. There is nothing inherent in the gasoline/ethanol blending process that would reduce the risk to motor vehicle engines from the formation of deposits in the absence of a detergent additive. Also, flex fuel vehicles have the capability of using E10 fuels which could be commingled with the E85. The E10 would have the detergent additive while the E85 would not. In that case the 390 ------- consumer could be confused as to the cause of any deposit formation that may occur in flex fuel engine intake valves. Furthermore, there is nothing inherent in flex fuel vehicles that would keep them from forming deposits on intake valves and other components if a detergent additive is not used. Lack of a detergent additive in E85 leading to engine performance problems may in the long-term lead to consumer rejection of the flex fuel option, in part related to engine problems that could occur from a lack of detergent additive. EPA noted at page 29084 of the preamble that it was not aware of data on the deposit control needs of flex-fuel vehicles operating on E85. The agency referenced some stakeholder comments that claimed there is a point where the presence of detergent ceases to be beneficial and can contribute to deposit formation. However, EPA did not reference any actual data to support this claim nor does the record include information that flex-fuel vehicles have been subject to deposit formation from the presence of detergent additives when blended with higher concentrations of ethanol. At a minimum the agency should explore this issue more thoroughly before removing the detergent requirement for E85. [EPA-HQ-OAR-2018-0227-0046-A1, p.6] > Renewable Fuels Association (RFA) Detergency Requirements We strongly support the long-awaited and necessary proposal to remove the certified detergency requirements for the gasoline portion of E85. This is something we have been encouraging EPA to do for many years. Certain detergents are not completely soluble in high ethanol content blends. Further, there is evidence that detergents may not provide any benefit and may even exacerbate deposit formation. More work needs to be done in this detergent additive area as related to higher ethanol blend fuels. Moving forward, we would like to see a higher minimum ethanol content for detergency certification requirements to assure increasing ethanol contents do not cause solubility problems with these additives. [EPA-HQ-OAR-2018-0227-0037-A1, p.2] Response: We thank the commenters for their support. 391 ------- 21.3. In-line Blending Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) The Associations support many major elements of the proposal, including: • a one-year extension of current in-line blending waivers; [EPA-HQ-OAR-2018-0227-0074-A1, p.6] We support allowing refiners to operate under existing in-line blending waivers approved under 40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0074-A1, pp.32-33] > International Liquid Terminals Association PROVISIONS THAT ILTA SUPPORTS ILTA supports most of the provisions included in the proposal. This includes: 10. Allowing refiners to operate under their existing Part 80 in-line blending waivers through January 1, 2022. [EPA-HQ-OAR-2018-0227-0061-A1, p.2] > Marathon Petroleum Company LP (MPC) In-line Blending waiver MPC also supports allowing refiners to operate under existing in-line blending waivers approved under 40 CFR Part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A1, p.5] MPC supports the allowing refiners to operate under existing in-line blending waivers approved under 40 CFR part 80 until January 1, 2022. [EPA-HQ-OAR-2018-0227-0048-A2, p.l] > Valero Energy Corporation A. New Inline Blending Requirements 1. Declaration of Invalidity Proposed §1090.1315(b) states that "Waivers granted under 40 CFR Part 80 are no longer valid." The provision goes on to provide for facilities currently operating under previously approved waivers to continue doing so until January 1, 2022; however, this basically serves as an exercise 392 ------- of enforcement discretion to temporarily relieve facilities from regulatory liability for an operation that will no longer be explicitly authorized as of the effective date of the rule. Because commercial agreements for sales of gasoline typically include broad representations of compliance with laws, including the federal fuel regulations, characterizing the waivers as invalid creates a risk that facilities using inline blending waivers through December 31, 2021 may inadvertently breach commercial agreements for the sale of products produced in conformance with previously approved inline blending waivers. This commercial risk could be avoided by restating the provision as follows: "Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of a revised inline blending waiver petitions meeting the requirements listed below, or by January 1, 2022, whichever is sooner." Response: We have revised §1090.1315(b) to specify that inline blending waivers granted under part 80 will expire upon EPA's approval of a revised inline blending waiver petitions meeting the requirements listed below, or by January 1, 2022, whichever is sooner. Comment: > American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API) Appendix 2 - Additional Topics Preamble Language or Regulatory Language: Fuel manufacturers using in-line blending equipment may qualify for a waiver from the requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel manufacturing facility as follows: (a) The waiver in this section applies if you use or intend to use in-line blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also applies for fuel manufacturers that produce batches of fuel that are too large to contain in available storage tanks. (b) Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of revised inline blending waiver petitions meeting the requirements listed below, or by January 1, 2022, whichever is sooner. Any party who received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under the waiver until January 1, 2022. To obtain a waiver under this part, submit a request signed by the RCO to EPA with the following information: Comment: 393 ------- The rule states in-line blending waivers are not allowed for locations blending to tanks. It may be necessary for refineries to include the ability of blending into tanks as part of their in-line blending waivers requests. In-line blend waivers approved under 40 CFR part 80 currently allow composite sampling for certification of gasoline blending into tanks. This sampling process provides a representative sample of a batch of gasoline blended into a tank or multiple tanks, so it is unclear why this is not allowed. If a composite sampling approach conforms to the requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, it provides the representative sample required to demonstrate compliance with regulatory requirements. [EPA- HQ-OAR-2018-0227-0074-A1, pp.32-33] > Marathon Petroleum Company LP (MPC) In-line Blending waiver Section 1090.1315(a) states, "The waiver in this section applies if you use or intend to use in-line blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also applies to fuel manufacturers that produce batches that are too large to contain in available storage tanks." There are scenarios in which blending into tankage, due to logistical constraints or batch timing, would be necessary. Without the ability to blend into a tank, blenders would be forced to shutdown blending operations, significantly impacting the overall facility operation. The in-line blend waivers, approved under 40 CRF Part 80, currently allows composite sampling for certification of gasoline blending into tanks. Such sampling would provide a representative sample of a batch of gasoline blended into a tank, or multiple tanks. It remains unclear why EPA did not propose continuation of this practice in Part 1090. If a composite sampling approach conforms to the requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, then a representative sample is provided that demonstrates compliance with the regulatory requirements. MPC recommends the language in this section be revised to include the option to blend into a tank. [EPA-HQ-OAR-2018-0227-0048-A1, p.5] In-line blending Fuel manufacturers using in-line blending equipment may qualify for a waiver from the requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel manufacturing facility as follows: 1090.1315(a) The waiver in this section applies if you use or intend to use in-line blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also applies for fuel manufacturers that produce batches of fuel that are too large to contain in available storage tanks. 394 ------- (b) Waivers granted under 40 CFR part 80 are no longer valid. Any party who received an in-line blending waiver granted under 40 CFR part 80 may continue to operate under the waiver until January 1, 2022. To obtain a waiver under this part, submit a request signed by the RCO to EPA with the following information: The rule states in-line blending waivers are not allowed for locations blending to tanks. It may be necessary for refineries to include the ability to blend into tanks as part of their in-line blending waiver requests. In-line blend waivers approved under 40 CFR part 80 currently allow composite sampling for certification of gasoline blending into tanks. This sampling process provides a representative sample of a batch of gasoline blended into a tank or multiple tanks, so it is unclear why this is not allowed. If a composite sampling approach conforms to the requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, it provides the representative sample required to demonstrate compliance with regulatory requirements. [EPA-HO-OAR-2018- 0227-0048-A2, p.l] > Suncor Energy (U.S.A.) Inc. New In-Line Blending Waiver Applicability. Subpart M (Sampling, Testing, Retention) states that in-line blending waivers do not apply to locations blending to tanks unless the batch is too large to contain in available storage tanks: 1090.1315 (a) The waiver in this section applies if you use or intend to use in-line blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel It also applies for fuel manufacturers that produce batches of fuel that are too large to contain in available storage tanks. The current version of Part 80 did not specify the type of facilities or blending process necessary to request an in-line blending waiver. It allowed a fuel manufacturer to request a waiver only if it did not want to test certain fuel parameters before releasing it to commerce. The proposed revision is a substantial change in the regulation and will significantly impact those facilities that do not meet the "new" criteria. In-line blend waivers already approved under 40 CFR Part 80 currently allow composite sampling for certification of gasoline blending into tanks, regardless of whether the batch size is larger than the tank. This sampling process provides a representative sample of a batch of gasoline blended into a tank or multiple tanks, so it is unclear why this would not continue to be allowed. If a composite sampling approach conforms to the requirements of ASTM D4177, whether the batch is delivered into a tank or pipe, it provides the representative sample required to demonstrate compliance with regulatory requirements. Suncor suggests the criteria for requesting an in-line blend waiver align with the requirements in Part 80 such that there is no significant change in the regulation. [EPA-HQ-OAR-2018-0227- 0067-A1, p.3] 395 ------- Response: We have removed the provisions proposed at §1090.1315(a) that would not have allowed facilities to apply for ILB waivers for blending into tanks. Comment: > Phillips 66 Company In-line blend waivers We ask EPA to modify the language in §1090.1315 for clarity and §1090.1335(c) (as mentioned above under Automatic Sampling). We are supportive of EPA providing additional time to modify existing inline blend waivers and submit for approval. EPA has indicated that parties may continue to operate under the waivers granted under 40 CFR Part 80 until a new waiver is approved under Part 1090, with a deadline of January 1, 2021. The existing reformulated gasoline in-line blend waivers under Part 80 may specify testing for properties that will no longer be required under Part 1090; for example, aromatics, olefins, E200 and E300. The existing reformulated gasoline waivers under Part 80 also require annual audits. Therefore, continuing to operate under the existing Part 80 waivers could mean the refinery would have to monitor and test for properties no longer required under Part 1090. We suggest EPA include language that would clarify that refineries can continue to operate under their existing reformulated gasoline in-line blend waivers, however, are only required to monitor and test for sulfur, benzene, and summer RVP. This additional language could be used to inform the auditors that testing for the other properties, although included in the existing waiver, are not required. Here is some suggested language §1090.1315 In-line blending. Fuel manufacturers using in-line blending equipment may qualify for a waiver from the requirement in §1090.1310(b) to test every batch of fuel before the fuel leaves the fuel manufacturing facility as follows: (a) The waiver in this section applies if you use or intend to use in-line blending equipment to supply fuel directly into a pipeline, marine vessel, or other type of distribution that does not involve collecting fuel in a tank or other type of storage for creating a batch of fuel. It also applies for fuel manufacturers that produce batches of fuel that are too large to contain in available storage tanks. Composite samples may also be used in the instance where the batch was contained in the storage tank (for example small batches that occur occasionally). (b) Waivers granted under 40 CFR Part 80 will expire upon EPA's approval of revised inline blending waiver petitions meeting the requirements listed below, or by January 1. 2022. whichever is sooner. Any party who received an in-line blending waiver granted under 40 CFR 396 ------- part 80 may continue to operate under the waiver until January 1, 2022. Parties operating with reformulated in-line blend waivers under Part 80 after January 1. 2021 are only required to monitor and test for sulfur, benzene, and summer RVP and can discontinue monitoring and testing for other properties that may be included in their existing waiver. To obtain a waiver under this part, submit a request signed by the RCO to EPA with the following information: [EPA-HQ-OAR-2018-0227-0060-Al.pp.6-7] Response: We have revised the allowance for RFG manufacturers to use ILB waivers under part 80 until January 1, 2022, to clarify that RFG manufacturers are only responsible for the sulfur, benzene, and RVP (during the summer) portions of their approved part 80 ILB waiver. Other RFG Complex Model parameters are no longer required to be monitored or tested beginning January 1, 2021. Comment: > Valero Energy Corporation A. New Inline Blending Requirements 2. Additional time needed to implement ASTM D4177-16el EPA proposes in §1090.1315(b) (2) that new or updated blending waiver requests must include procedures conforming to the requirements of ASTM D4177-16el. It should be noted that ASTM D4177-16el is fundamentally different from the version currently applicable under 40 CFR Part 80 (D4177-95). ASTM has stated that this method is substantially different than prior versions (the introduction to the standard states "Extensive revisions have been made to the prior version of D4177"). These differences are not merely procedural; the newer version of the method contemplates use of new and different types of sampling equipment. Valero expects that meeting the standard will require capital projects to engineer, procure, and retrofit sampling systems and thus, more time may be necessary to fully implement. Valero requests that EPA revise §1090.1315(b) (2) as follows: "...Your procedures need to describe how you will conform to the sampling specifications in ASTM D4177... by and after January 1, 2022." Response: We are allowing parties that use automatic sampling to collect samples for batch certification to use the provisions for automatically sampling under part 80 until January 1, 2022. We believe it is appropriate to provide the same amount of time for parties that use automatic sampling as those that have an ILB waiver who would de facto get more time with the newer version ASTM D4177 by virtue of EPA allowing fuel manufacturers with an ILB waiver to operate the waiver under part 80 until January 1, 2022. 397 ------- Comment: > bp America Inc. (bp) Subpart M—Sampling. Testing, and Retention Requirements §1090.1315(d) states "You must update your in-line blending waiver request 60 days prior to making any material change to your in-line blending process." bp asks that EPA clarify that companies must update and submit the update to EPA for approval, bp recommends the update be submitted 60 days before making the change. A 60 day wait after designing, finalizing, and submitting an update request could be problematic for changes critical to a safe operation. The term "material change" is unclear given the broad scope of the in-line blending petition. For example, in-line waiver petitions provide a description of the refinery as a whole which is subject to ongoing changes, most of which are not relevant to the objective of the petition. The draft regulation does not address the meaning of that term, bp requests that EPA clarify that term either in the in-line blending regulation or in the Federal Register preamble to the final rule either by elaborating on what is meant by "material" and/or providing examples of both material and nonmaterial changes. This section does not address important details concerning the petition approval process. It is unclear whether EPA will send an approval letter that outlines the conditions of its approval. Furthermore, the regulation does not specify a timeframe within which the approval needs to be accomplished and communicated to the fuel manufacturer. Fuel manufacturers will make substantial investments in in-line blending equipment and create detailed, structured plans around their implementation that are dependent on having certainty about the date the equipment can be put into use. bp suggests that the regulations require EPA to respond to a petition within 60 days or less and in the absence of a timely response, the petition becomes automatically approved. That added detail becomes especially important with regards to the January 1, 2022 deadline specified in §1090.1315(b). Many fuel manufacturers have obtained in-line blending waivers which under the Streamlining Rule may be relied upon until that date. It is unclear whether that is the deadline for submission of the in-line blending petition or the date by which the fuel manufacturer needs to receive approval of its new petition under the Streamlining Rule. If EPA intends the latter, it becomes even more important for fuel manufacturers to be informed of the timing and other aspects of the approval process noted above. We would appreciate clarification on all those details when the final rule is issued. [EPA-HQ-OAR-2018-0227-0046-A1, pp.19-20] > Valero Energy Corporation A. New Inline Blending Requirements 3. Process for approval of ILB waivers 398 ------- The proposed rule provides neither a clear target date for submission of waiver petitions, nor a commitment for EPA to act on waiver petitions in any particular time frame, nor clear criteria for approval, nor a process to address what happens if for any reason EPA has not approved a waiver petition by January 1, 2022 for a facility operating under a grandfathered blending waiver. Taken together, these uncertainties create an unacceptable risk that a facility may promptly submit a waiver request including the information set forth in the rule and nevertheless be forced to abruptly discontinue inline blending, and potentially all gasoline production, if EPA does not act timely on a waiver petition and/or seeks to impose conditions in the waiver that the facility cannot or will not meet. In order to continue gasoline production, the facility may have little alternative but to build additional product tanks, but these require significant lead time to design, engineer, permit, and construct as well as significant capital investment. Valero requests that EPA supplement the proposed rule to specify a clear process for submission of waiver applications and for EPA's review and final decision. Further, the rule should provide that EPA may not impose conditions of approval beyond the information set forth in the rule. Finally, Valero recommends that the rule provide for a reasonable transition period if a facility's ILB waiver is not approved on or before December 31, 2021. Response: We added examples to §1090.1315(d) of some changes that we would consider material and some that we would not. While we cannot outline all changes that we would consider material, as ILB waivers are inherently facility specific and must be evaluated on a case-by-case basis, we believe the examples provide more clarity for fuel manufacturers with ILB waivers as to when they need to update their ILB waivers. Unfortunately, we cannot commit to a deadline by which we will respond to ILB waiver requests as the length of time it takes for EPA to review and approve an ILB waiver request largely depends on the completeness and accuracy of the fuel manufacturer's waiver request. The completeness and accuracy of waiver requests vary significantly between fuel manufacturers and as such fuel manufacturers should submit their waiver requests to allow for the submission of any missing or inaccurate information. However, EPA will send an approval letter to the fuel manufacturer if the waiver is approved. We are also not providing for an approval process that grants an ILB waiver request via operation of law after a time period has elapsed. Based on our past history processing ILB waiver requests, allowing such a process would result in the automatic approval of ILB waivers that do not adhere to the regulatory requirements, which would in turn create disparity between parties that have approved waiver that meet the regulatory requirements and those that did not but were automatically granted via operation of law. This disparity can create a competitive advantage and would promote the submission of poor quality waiver requests at the deadline to attempt to have a poor quality waiver automatically approved. Furthermore, automatic approval of poor quality waiver requests would likely result in the release of fuels that do not meet applicable EPA fuel quality standards. We believe providing an additional year of lead time gives fuel manufacturers with existing ILB waivers ample opportunity to submit a new ILB waiver request and encourage fuel manufacturers that need new ILB waivers to begin the process early enough for EPA to approve their ILB waiver request. 399 ------- As noted earlier, ILB waivers granted under part 80 will expire by January 1, 2022, or upon EPA's approval of a revised ILB waiver under part 1090, whichever is sooner. 400 ------- 22. Other Comments 22.1. Statutory and Executive Orders Comment: > Urban Air Initiative C. The proposed rule violates the Regulatory Flexibility Act. The new definition of gasoline is unlawful for another reason: EPA has not satisfied its obligations under the Regulatory Flexibility Act (RFA) and the Small Business Regulatory Enforcement Fairness Act (SBREFA) with respect to its proposed definition of gasoline in the Fuels Regulatory Streamlining rule. Under the RFA, when an agency publishes a notice of proposed rulemaking as required by the Administrative Procedure Act, it must "prepare and make available for comment an initial regulatory flexibility analysis," which "shall describe the impact of the proposed rule on small entities."56 This requirement does not apply "if the head of the agency certifies that the rule will not, if promulgated, have a significant economic impact on a substantial number of small entities" and "publish[es] such certification in the Federal Register ... at the time of publication of general notice of proposed rulemaking for the rule . . . , along with a succinct statement explaining the reasons for such certification."57 [EPA-HQ-OAR-2018- 0227-0071-A1, p.15] Under the SBREFA, "a small entity that is adversely affected or aggrieved by final agency action is entitled to judicial review of agency compliance with" certain of the RFA's requirements, including the requirements of § 605(b).58 Upon review, the agency's certification decision stands if the agency made a "reasonable, good-faith effort" to satisfy the RFA's mandate.59 The agency must support its decision with a minimum of analysis and evidence; a "conclusoiy statement with no evidentiary support in the record does not prove compliance with" the RFA.60 [EPA-HQ-OAR-2018-0227-0071-A1, p. 15] EPA has certified that its action would not have a "significant economic impact on a substantial number of small entities" under the RFA, claiming that the proposed rule merely "consolidate [s] EPA's existing fuel regulations" and that "the proposed requirements on small entities are largely the same as those already included in the existing . . . regulations."61 While it acknowledges that its action does make changes to existing regulations, EPA describes these changes as "relatively minor corrections and modifications," and then makes the conclusory statement, unsupported by analysis or evidence, that these proposed changes, including the new, expansive definition of "gasoline," "have no net regulatory burden for all directly regulated small entities."62 However, as stated in Section I.B above, the proposed rule's definition of gasoline will impose major new compliance burdens on ethanol plants, terminal blenders, and fuel retailers, many of which are small businesses. EPA has failed to consider these burdens, and its § 605(b) certification was therefore improper. [EPA-HQ-OAR-2018-0227-0071-A1, p.16] 401 ------- 56 5 U.S.C. § 603(a). 57 Id. § 605(b). 58 Id. §611(a)(1). 59 Council for Urological Interests v. Burwell, 790 F.3d 212, 227 (D.C. Cir. 2015) (quoting U.S. Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir. 2001)). 60 Nat'l Truck Equip. Ass'nv. Nat'l Highway Traffic Safety Admin., 919 F.2d 1148, 1157 (6th Cir. 1990). 61 Proposed Rule, 85 Fed. Reg. at 29,088. 62 Id. Response: We disagree with the commenter that our certification under the Regulatory Flexibility Act was improper. As discussed in Section 4.6 of this document, the definition of gasoline in part 1090 will not impose requirements on ethanol plants, terminal blenders, and fuel retailers that they are not already subject to under part 80. Furthermore, as discussed in Sections XIV.C and XV.D of the preamble, the cost analysis supporting this rulemaking supports the conclusion that this action will not have a substantial economic impact on a significant number of small entities. Comment: > Urban Air Initiative D. The proposed rule does not comply with Executive Order 13.771. Apart from failing to comply with the law, EPA may have also improperly labeled the proposed rule "deregulatoiy" under Executive Order 13,771.63 According to guidance from the Office of Information and Regulatory Affairs (OIRA), an agency action is only "deregulatory" if it "has total costs less than zero."64 While the rule has an estimated annual cost savings of $32.9 million,65 nothing in the proposed rule accounts for the significant costs of the new expansive ambit of "gasoline." If EPA finalizes the proposed rule, it must quantify these costs if feasible, and if total costs exceed zero, it must recognize that the rule is regulatory. [EPA-HQ-OAR-2018- 0227-0071-A1, p.16] 63 85 Fed. Reg. 29,087 ("This action is expected to be an Executive Order 13771 deregulatory action."). The rule has an estimated annual cost savings of $32.9 million. Id. at 29,086, at Table XIV.C-1; EPA, Economic Analysis: Fuels Regulatory Streamlining Proposed Rule 2, EPA-HQ-OAR-2018-0227-0016. 64 See Dominic J. Mancini, Acting Administrator, Office of Info. & Regulatory Affairs, M-17-21, Guidance Implementing Executive Order 13771, Titled "Reducing Regulation and Controlling Regulatory Costs" 4, M-17-21 (April 5, 2017), https://www.whitehouse.gov/sites/whitehouse.gov/files/omb/ memoranda /2017/M 17 21 .pdf. 402 ------- 65 85 Fed. Reg. at 29,086, at Table XIV.C-1; EPA, Economic Analysis: Fuels Regulatory Streamlining Proposed Rule 2, EPA HQ-OAR-2018-0227-0016. Response: We disagree with the commenter that we have failed to comply with EO 13771. As discussed in Section 4.6 of this document, the definition of gasoline in part 1090 will not impose new costs on regulated entities as it does not expand the scope of fuel regulated as gasoline and does not include E85. As such, this rule is properly designated as "deregulatory" because it results in an annual cost savings. 403 ------- 22.2. Beyond the Scope Commenters that provided comment on this topic include but are not limited to: 0034, 0037, 0047, 0053, 0054, 0057, 0063, 0072, 0074, 0077, 0078, 0082. Comment: Several commenters addressed numerous additional topics, including but not limited to the following: • Changes to the El5 misfueling mitigation plans (e.g., El5 label) • Creating new flexibilities for biobutanol • Natural gasoline and provisions related to higher-level ethanol blends (e.g., E85) • Introduction of new mid- and higher-level ethanol blends into the market • Impacts of ethanol on engines • Changes to provisions of the RFS program other than those proposed Response: These comments are all beyond the scope of this rulemaking. We did not propose any of the changes described above or otherwise seek comment on these issues. These topics are not further addressed in this document. 404 ------- |