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Proposed Rule

Regulation of Fuel and Fuel Additives: Reformulated Gasoline Terminal Receipt Date

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Information about this document as published in the Federal Register.

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Start Preamble

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Notice of proposed rulemaking.

SUMMARY:

With today's action the Environmental Protection Agency (EPA) is proposing to establish April 15 as a new annual compliance date for reformulated gasoline (RFG) and reformulated blendstock for oxygenate blending (RBOB), on or after which no persons except retailers and wholesale purchaser consumers would be able to accept receipt of any RFG other than summer grade RFG. This action is intended to help ease the annual spring transition from winter grade RFG to summer grade RFG by increasing RFG inventories during the transition period. Requiring all terminals to receive summer grade RFG by a fixed date should help reduce the competitive pressure that keeps terminals from accepting summer grade RFG for as long as possible, and may provide for a smoother transition in certain geographic areas by lengthening the turnover time for terminal tanks. We are also proposing to simplify the existing blendstock accounting requirements. This action will allow refineries more flexibility to transfer gasoline blendstocks from one refinery to another. Finally, we are proposing to update certain ASTM designated analytical test methods for reformulated and conventional gasoline to their most recent ASTM version, and also update several sampling methods to their most recent ASTM version. These updates will allow improvements in the test method procedures and sampling procedures that would ensure better operation for the user of the test methods and sampling procedures.

DATES:

Comments. All public comments must be received on or before January 2, 2002. To request a public hearing, contact Chris McKenna at (202) 564-9037 or mckenna.chris@epa.gov. If a hearing is requested within 20 days of the date of publication of this document in the Federal Register, a hearing will be held on December 24, 2001 at the location indicated in the ADDRESSES section below. Persons wishing to testify at a public hearing must contact Chris McKenna at (202) 564-9037, and submit copies of their testimony to the docket and to Chris McKenna at the addresses below, no later than 10 days prior to the hearing. After the hearing, the docket for this rulemaking will remain open for an additional 30 days to receive comments. If a hearing is held, EPA will publish a document in the Federal Register extending the comment period for 30 days after the hearing.

ADDRESSES:

Any person wishing to submit comments should send them (in duplicate, if possible) to the docket address listed below and to Chris McKenna (6406J), Chemical Engineer, U.S. Environmental Protection Agency, Office of Transportation and Air Quality, Transportation and Regional Programs, 1200 Pennsylvania Ave., NW., Washington, DC 20460. Materials relevant to this have been placed in docket (A-2001-21) located at U.S. Environmental Protection Agency, Air Docket Section, Room M-1500, 401 M Street, SW., Washington, DC 20460. The docket is open for public inspection from 8:00 a.m. until 5:30 p.m., Monday through Friday, except on Federal holidays. A reasonable fee may be charged for photocopying services.

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FOR FURTHER INFORMATION CONTACT:

For further information about this proposed rule, contact Chris McKenna, Chemical Engineer, Office of Transportation and Air Quality, Transportation and Regional Programs Division, at (202) 564-9037 or mckenna.chris@epa.gov.

End Further Info End Preamble Start Supplemental Information

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities potentially affected by this action include those involved with the production, importation, distribution, sale and storage of gasoline motor fuel.

The table below gives some examples of entities that may have to comply with the regulations. However, since these are only examples, you should carefully examine these and other existing regulations in 40 CFR part 80. If you have any questions, please call the person listed in the FOR FURTHER INFORMATION CONTACT section above.

CategoryNAICSs codes aSIC codes bExamples of potentially regulated parties
Industry3241102911Petroleum refiners.
Industry4227105171Gasoline marketers and distributors.
4227205172
a North American Industry Classification System (NAICS).
b Standard Industrial Classification (SIC) system code.

Outline

I. New Terminal Receipt Date for Summer Grade Reformulated Gasoline

A. Background

B. What is EPA Proposing?

C. How Will This Proposal Help the Transition Period?

D. What Is the Cost of Today's Proposal?

II. On What Issues Is EPA Requesting Comment?

A. Inventory Build Before April 15

B. Eliminate or Delay May 1 Compliance Date

C. Establish April 1 Terminal Receipt Date

D. Two Step RVP Phase-In

E. Limit Applicability of Terminal Receipt Date to Chicago/Milwaukee areas

F. Reduce Allowable Minimum RVP to 6.0 psi

III. Eliminate Current Blendstock Accounting Regulation 40 CFR 80.102

IV. Updating ASTM Designated Analytical Test Methods for Reformulated and Conventional Gasoline to Their Most Recent ASTM Version

V. Corrections to Gasoline and Diesel Sample Testing Methodology

VI. Administrative Requirements

A. Executive Order 12866

B. Executive Order 13132 (Federalism)Start Printed Page 60164

C. Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments)

D. Regulatory Flexibility Act (RFA), as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 USC 601 et. seq.

E. Paperwork Reduction Act

F. Unfunded Mandates Reform Act

G. Executive Order 13045: Children's Health Protection

H. National Technology Transfer and Advancement Act of 1995 (NTTAA)

I. Executive Order 13211 (Energy Effects)

VII. Statutory Provisions and Legal Authority

I. New Terminal Receipt Date for Summer Grade Reformulated Gasoline

A. Background

The purpose of the reformulated gasoline (RFG) program is to improve air quality in certain specified ozone nonattainment areas. Gasoline sold in RFG covered areas must achieve certain reductions in emissions of ozone forming volatile organic compounds (VOCs) and toxic air pollutants, pursuant to 211(k) of the Clean Air Act (CAA or the Act), as amended [1] . The Act requires RFG in the ten metropolitan areas with the worst summertime ozone problems, and certain other areas have opted into the program.

Phase I of the RFG program ran from 1995 through 1999, and more stringent Phase II RFG standards began in 2000. During the summer ozone season EPA's Phase II RFG regulations require a 29 percent reduction in VOC emissions from RFG in southern (class B) areas, and a 27.4 percent reduction in such emissions from RFG in northern (class C) areas (representing approximately an additional 10 percent reduction in VOC emissions beyond the Phase I requirements).

One significant way of reducing VOC emissions from RFG is to decrease the Reid Vapor Pressure (RVP) of the RFG during summer months. As a result, summer grade RFG has a significantly lower RVP than winter grade RFG. RVP is a measure of a gasoline's volatility, or the tendency for a gasoline to evaporate. As gasoline RVP increases, the tendency of the gasoline to emit volatile material also increases. Higher emissions of volatile material increase pollution. Therefore, gasoline RVP is permitted to be relatively high during colder months because colder temperatures reduce the tendency of gasoline to evaporate and reduce emissions of volatile material. During hotter months, refiners must reduce gasoline RVP by removing the most volatile portion of the gasoline in order to reduce evaporative emissions from the gasoline.

Each spring, refiners and importers must reduce the RVP of the gasoline that they produce or import in order to comply with federal summer emissions requirements, and refiners, gasoline terminal facilities and retail stations must replace high RVP winter grade RFG in storage tanks with lower RVP summer grade RFG. EPA regulations stipulate that gasoline retailers must be selling only summer grade RFG by June 1 of each year. In order to meet the June 1 compliance date, EPA regulations stipulate that by May 1 the RFG at terminals and all other facilities upstream of the retailer must meet the summertime RFG requirements. Refineries typically begin producing lower RVP RFG in March or April in order for terminals to meet the May 1 compliance date.

Storage terminals use different methods for meeting the applicable compliance dates. Some terminals completely convert their tanks from high to low RVP gasoline by starting to blend summer gasoline into the terminal tank prior to May 1, so that by May 1 the gasoline in the terminal tank meets summer specifications—the “blend down” method. Alternatively, some terminals draw down their inventory of winter gasoline by continuing to make deliveries of winter gasoline, but not replacing it. When the tank is sufficiently low, the terminal begins accepting summer gasoline in order to meet the May 1 compliance date. This method is called the “draw down” method.

Because low RVP summer grade RFG is more expensive than high RVP winter grade RFG, distributors have incentive to delay terminal receipt of more expensive summer grade fuel, and draw down tanks as much as possible before refilling. Then, with the tank about empty, the last minute addition of summer grade fuel allows terminal tanks to quickly come into compliance with summer grade RFG requirements. This practice minimizes the cost of converting the tank from winter grade RFG to summer grade RFG. This economic incentive increases the likelihood that terminals will use the draw down method for the transition to summer fuel. Terminals practicing the draw down method only wish to receive summer grade RFG just before May 1 when their tanks are low. This practice delays production and importation of summer RFG. This practice may also lead to low gasoline inventories and increased supply pressure, particularly if there are any disruptions to the production or distribution system during this period. Additionally, during the past two spring transition periods, refiners have also tried to keep RFG inventories low in the expectation that future crude oil prices would decrease and RFG inventories could be replenished by processing less expensive crude in the future. The effort to increase inventories by establishing a new terminal receipt date might be limited by the conditions in the broader crude oil and petroleum product market.

EPA has no regulations governing the methods by which terminal operators turn over their tanks from winter to summer grade RFG. Terminal operators choose whether to use the blend down method or the draw down method to turn over their tanks. Although EPA has heard anecdotal comments about difficulties with tank turnover, primarily in the Midwest, no refiner or terminal operator has contacted EPA with specific problems.

In response to concerns about tight RFG supplies in the Midwest during spring 2000 and spring 2001, EPA met with midwestern producers and distributors of RFG in March, 2001 and asked that anyone experiencing difficulty with tank turnover contact EPA for help in addressing their problem. No refiners, importers or terminal operators contacted EPA during the transition months regarding difficulties with tank turnover. Nonetheless, we believe that the practice of drawing down terminal tanks in connection with the transition from winter to summer grade RFG can have an adverse impact on spring RFG inventories and potentially on gasoline supply. Therefore, we believe it is appropriate for EPA to proceed with today's proposed rule, and for EPA to ask for comment on several potential actions, many of which have been suggested to EPA by fuel producers and distributors, that address this issue. EPA believes that today's proposed action would have a positive impact on distribution and supply, and would help to assure a smoother transition from summer to winter grade RFG.

B. What Is EPA Proposing?

We are proposing to establish a new April 15 date on or after which no persons except retailers and wholesale purchaser consumers would be able to accept receipt of any RFG or RBOB other than summer grade RFG or RBOB. While this restriction would apply to Start Printed Page 60165both terminals and pipelines, barges or other companies transporting fuel to terminals, effectively the restriction applies most directly to terminals so for ease of discussion the April 15 date will be referred to as a terminal receipt date. Also for ease of discussion, since the April 15 date applies to both RFG and RBOB, all references to RFG in connection with the April 15 date will apply to both RFG and RBOB. Batch report information submitted to EPA for 2000 indicates that approximately 181 million gallons of winter grade RFG was produced by refiners or imported from April 15, 2000 through April 30, 2000, all of which was produced or imported in PADDs 1, 2, and 3. The average RVP of this volume was 8.04 psi. Thus, establishing an April 15 summer RFG receipt date would require the RVP of at least 181 million gallons of RFG to be reduced from an average of 8.04 psi to a nominal 6.8 psi to meet the summer RFG specifications.

One suggested alternative to establishing a new April 15 receipt date was to instead establish a new refinery production date for summer grade RFG. For example, a refinery production date of April 1 could be established in place of an April 15 receipt date. The receipt date option being proposed will give a refiner more flexibility in deciding when to begin production of summer grade RFG based on its particular situation. For example, an RFG batch produced at a Gulf Coast refinery would take 2-3 weeks to be transported to terminals in the Midwest or Northeast. However, a refinery located in the Midwest or Northeast may take only one or two days to transport its RFG to local terminals.

Establishing a receipt date for summer grade RFG means that refineries must begin producing summer grade RFG batches early enough that the RFG arrives at its destined terminal by April 15. A 1986 study commissioned by EPA estimated an average national transit time of approximately 7 days between refinery and terminal for gasoline produced in May [2] . Subtracting this transit time from April 15 means that, on average, RFG batches produced or imported from April 8 through April 30 would need to be produced or imported as summer grade RFG. Batch report information submitted to EPA for 2000 indicates that 315.6 million gallons of winter grade RFG was produced by refiners or imported from April 8, 2000 through April 30, 2000, all of which was produced or imported in PADDs 1, 2, and 3. The average RVP of this volume was 8.34 psi. Winter grade RFG volumes produced or imported in each PADD from April 8, 2000 through April 30, 2000 are summarized in Table 1, along with the corresponding average RVP.

Table 1.—RFG Batch Information from April 8, 2000 through April 30, 2000

PADDWinter grade RFG produced from April 8, 2000 through April 30, 2000 million gallonsAverage RVP of RFG produced from April 8, 2000 through April 30, 2000 psi
1132.89.06
2160.77.52
322.19.97
Total315.68.34

C. How Will This Proposal Help the Transition Period?

This proposal should help to provide for a smoother transition from winter to summer RFG by requiring some terminals to begin turning over their tanks from winter grade RFG to summer grade RFG earlier than they currently do. Because some terminals draw down their gasoline storage tanks to very low levels in late April to drain as much winter grade RFG as possible from their tanks before refilling the tanks with summer grade RFG, in order to minimize cost, there is the potential for very low inventories of RFG during this transitional period which increases the likelihood of supply problems. Requiring all terminals to begin receiving summer grade RFG by a fixed date will remove much of the incentive for terminals to draw down their tanks to very low levels all at the same time. We expect instead that it will encourage a blend down of their tanks to meet summer RFG requirements and increase volumes of RFG at terminals during the transition, allowing terminals to more gradually turn over their tanks from winter to summer grade RFG, and help spread the transition period out over the last two weeks in April. This should help to avoid situations where many terminals draw down their inventories and turn over their tanks simultaneously at the end of April.

Establishing an April 15 terminal receipt date for summer grade RFG will not reduce the market pressure for refiners to delay production of summer gasoline until it is required. However, the April 15 date will reduce the market pressure that causes terminals to delay accepting summer grade RFG for as long as possible. Terminals would be required to begin receiving summer grade RFG on April 15 and would, at the latest, turn their tanks over between April 15 and May 1. Turnover times would vary with terminal storage capacity and throughput of RFG at the terminal. Terminals would not be economically encouraged to draw down the winter gasoline in their tanks prior to April 15. The April 15 date applies to gasoline supplies received on or after that date, but does not require that the gasoline in the tanks be in compliance with summer specifications on April 15. This should lead to greater use of the blend down method to meet the May 1 date by which all RFG in terminal storage tanks must meet the summertime RFG standards [3] . EPA requests comment on the premise that an April 15 terminal receipt date will encourage greater use of the blend down method.

D. What Is the Cost of Today's Proposal?

The total estimated cost of establishing an April 15 receipt date is estimated to be between $1.5 million per year and $2.3 million per year. Dividing these costs by the 315.6 million gallons per year of gasoline which would need to be produced as summer grade RFG instead of winter grade RFG produces an equivalent cost range of 0.49 cents per gallon RFG to 0.73 cents per gallon RFG. Both of these estimates include the operational cost of removing sufficient butane to reduce the RVP of 315.6 million gallons per year of winter grade RFG from an average RVP of 8.34 psi to a nominal summer grade RFG RVP of 6.8 psi. Assuming an RVP decrease of 1 psi for every 1.5 volume % decrease in butane, 7.3 million gallons per year of butane must be removed from 315.6 million gallons per year of RFG.

The lower cost estimate ($1.5 million per year or 0.49 cents per gallon RFG) includes the cost of new tankage to store all the butane until the butane can be used the following winter. The higher cost estimate ($2.3 million per year or 0.73 cents per gallon RFG) assumes that all the additional butane removed is directly sold to the spot butane market. Thus, the higher cost estimate includes the effect of directly selling 7.3 million gallons per year of product as relatively less valuable butane instead of more valuable RFG.

The cost, in cents per gallon affected RFG, of producing more summer grade Start Printed Page 60166RFG and less winter grade RFG from April 8 through April 30 is less than the cost differential between typical winter grade RFG and summer grade RFG. Based on data obtained from DOE, winter grade RFG prices were approximately 6 cents per gallon less than summer grade RFG during Phase I, and 9 cents per gallon less than summer grade RFG during Phase II [4] . These price differences are due to two factors, the additional cost to produce summer grade RFG, and demand. The cost difference is due to blending more butane, a relatively inexpensive gasoline blendstock, into winter grade RFG in place of more expensive blendstocks required for summer grade RFG, especially alkylate blendstock needed to produce very low RVP RBOB for ethanol blended RFG. DOE has estimated the cost differential between winter and summer RFG at approximately 3 cents per gallon, which does not include demand induced price effects [5] .

Typical winter grade RFG may have an RVP as high as 15 psi, compared to an average RVP of 8.34 psi for all winter grade RFG produced between April 8, 2000 and April 30, 2000. EPA's cost estimate includes only the cost of reducing the RVP of winter grade RFG produced from April 8 through April 30 to summer grade RVP levels. However, we are aware there may be other costs associated with the production of more summer grade RFG and less winter grade RFG from April 8 through April 30, in addition to the cost of reducing RVP.

II. On What Issues Is EPA Requesting Comment?

A. Inventory Build Before April 15

While EPA believes that establishing an April 15 terminal receipt date for summer grade RFG should result in greater use of the blend down method to meet the May 1 date by which all RFG in terminal storage tanks must meet the summertime RFG standard, we are concerned about the possibility of strategic behavior that may undermine this result. Since winter grade gasoline is cheaper than summer grade, there is an incentive under today's proposal for distributors to stockpile as much winter grade gasoline as possible before the April 15 deadline and simply defer purchases of summer grade gasoline for as long as possible as supplies of winter gasoline are drawn down. Depending on tank and pipeline capacity, this could theoretically result in the same reliance on the “draw down” method for meeting the May 1 compliance date as exists today. EPA therefore requests comment on the effects of today's proposal on gasoline inventories during the winter to summer transition.

B. Eliminate or Delay May 1 Compliance Date

In connection with today's proposal to establish a new April 15 terminal receipt date, we request comment on the impact and feasibility of also eliminating the existing May 1 compliance date, or, in the alternative, moving the May 1 compliance date to May 15. Under any such approach, the existing June 1 compliance date for retail stations would remain in its current form. Under the proposed April 15 terminal receipt requirement, we anticipate that most, if not all, terminals will turn over their RFG to summer grade specifications by May 1 based on the normal throughput of fuel at the terminal. The May 1 compliance date currently provides retail stations with one month to turn over their tanks from winter grade to summer grade RFG after all upstream facilities have made the transition. Discussions to date with retailers, terminals and refiners have indicated that many retail stations may actually need less time to turn over their tanks. Eliminating or delaying the May 1 compliance date would further widen the window of time following the proposed April 15 receipt date that terminals would have to turn all their tanks over from winter to summer grade RFG. This improved flexibility could allow, for example, a specific tank to still be in the blend down process on May 1, selling fuel with an RVP approaching, but not yet meeting summer grade requirements, a fuel which would be anticipated to be purchased by consumers prior to June 1. This would reduce the need for terminals to draw their RFG inventories down to very low levels during the spring transition. Feedback received thus far has been that if the May 1 compliance date is maintained, some terminals may still need to draw down their inventories in at least some of their tanks to very low levels to achieve the seasonal transition.

While we in general believe supplies of compliant summer grade RFG will be sufficiently available to meet retail needs, it is possible that some markets, particularly with low demand such as premium fuel, might be slow to turn over at both the retail outlet and the terminal. In such a case, without the need for terminals to meet summer fuel requirements for all their fuel, it may be more difficult for retail outlets to find sufficient fuel to meet that niche need early enough in May to allow for orderly transition to summer requirements. Comments are specifically requested on this issue of assuming sufficient supply to slow turnover markets without a certain May 1 terminal compliance date.

C. Establish April 1 Terminal Receipt Date

We also request comment on establishing April 1 instead of April 15 as an annual starting date for receipt of summer grade RFG; an April 1 date would further assure the availability of summer grade RFG prior to the June 1 retail compliance requirement to further reduce the potential for sudden drawdowns in RFG stocks. However, to the extent April 1 requires earlier production of summer grade RFG batches, refinery processing costs will increase perhaps with little or no real benefit to the retail outlet or to the environment (the increased environmental benefit due to summer grade RFG would largely parallel the increase). Second, an April 1 receipt date will be more likely to impact vehicle driveability in the event of cold weather late in the early spring.

Establishing an April 1 receipt date and allowing an average transit time of 7 days for transport of RFG from refinery to terminal means that shipment of summer grade RFG batches from refineries would need to start March 24. Batch report information submitted to EPA for 2000 indicates that 738.6 million gallons of winter grade RFG was produced by refiners or imported from March 24, 2000 through April 30, 2000, all of which was produced or imported in PADDs 1, 2, and 3. The average RVP of this volume was 9.28 psi. Winter grade RFG volumes produced or imported in each PADD from March 24, 2000 through April 30, 2000 are summarized in Table 2, along with the corresponding average RVP.

Table 2.—RFG Batch Information From March 24, 2000 Through April 30, 2000

PADDWinter grade RFG produced from March 24, 2000 through April 30, 2000 million gallonsAverage RVP of RFG produced from March 24, 2000 through April 30, 2000 psi
1378.89.65
2283.08.52
Start Printed Page 60167

Table 2.—RFG Batch Information From March 24, 2000 Through April 30, 2000—Continued

PADDWinter grade RFG produced from March 24, 2000 through April 30, 2000 million gallonsAverage RVP of RFG produced from March 24, 2000 through April 30, 2000 psi
377.110.27
Total738.69.28

The total estimated cost of establishing an April 1 receipt date is estimated to be between $4.9 million per year and $7.6 million per year. Dividing these costs by the 738.6 million gallons per year of gasoline which must be produced as summer grade RFG instead of winter grade RFG produces an equivalent cost range of 0.65 cents per gallon RFG to 1.04 cents per gallon RFG. Both of these estimates include the operational cost of removing sufficient butane to reduce the RVP of 738.6 million gallons per year of winter grade RFG from an average RVP of 9.28 psi to a nominal summer grade RFG RVP of 6.8 psi. Assuming an RVP decrease of 1 psi for every 1.5 volume % decrease in butane, 27.5 million gallons per year of butane must be removed from 738.6 million gallons per year of RFG.

The lower cost estimate ($4.8 million per year or 0.65 cents per gallon RFG) includes the cost of new tankage to store all the butane until the butane can be used the following winter. The higher cost estimate ($7.6 million per year or 1.04 cents per gallon RFG) assumes that all the additional butane removed is directly sold to the spot butane market. Thus, the higher cost estimate includes the effect of directly selling 27.5 million gallons per year of product as relatively less valuable butane instead of more valuable RFG.

As discussed in Section I.D. our cost estimate includes only the cost of reducing the RVP of winter grade RFG produced from March 24 through April 30 to summer grade RVP levels. However, we are aware there may be other costs associated with the production of more summer grade RFG and less winter grade RFG from March 24 through April 30, in addition to the cost of reducing RVP. A full discussion of the cost estimate can be found in the Draft Technical Support Document for this proposed rule, which is available in the docket for this rulemaking (A-2001-21; Item II-B-1) and on the web at: www.epa.gov/​otaq/​rfg.

D. Two Step RVP Phase-In

We also request comment on a two step phase-in process, as an alternative to the proposed terminal receipt date, which gradually reduces RFG RVP by establishing an intermediate terminal compliance date and intermediate target RVP. We request comment on the following four sub-options for this two step phase-in option.

1. Terminals must have their RFG tanks completely turned over to an intermediate RVP of 8.0 psi by April 15 and completely turned over to summer grade RFG by May 1.

2. Terminals must have their RFG tanks completely turned over to an intermediate RVP of 9.0 psi by April 15 and completely turned over to summer grade RFG by May 1.

3. Terminals must have their RFG tanks completely turned over to an intermediate RVP of 8.0 psi by May 1 and completely turned over to summer grade RFG by May 15.

4. Terminals must have their RFG tanks completely turned over to an intermediate RVP of 9.0 psi by May 1 and completely turned over to summer grade RFG by May 15.

The two step phase-in is intended to reduce the degree to which terminals must draw down their tanks to meet the final terminal compliance date by turning tanks over in two smaller steps instead of one large step. Using sub-option 1 above as an example, in step 1 a tank containing 19,000 barrels of winter grade RFG with a 13.0 psi RVP could be blended with 81,000 barrels of summer grade RFG with a 6.8 psi RVP to produce 100,000 barrels of RFG with an 8.0 psi RVP, using linear blending. In step 2, the volume of RFG in the tank with an 8.0 psi RVP would only have to be reduced to 25,000 barrels. This residual volume of 25,000 barrels of RFG with an 8.0 psi RVP could then be blended with 75,000 barrels of summer grade RFG with a 6.4 psi RVP to produce 100,000 barrels of summer grade RFG with a 6.8 psi RVP, using linear blending.

In contrast, to accomplish the same turnover in one step would require the volume of 13.0 psi RVP winter grade RFG in the tank to be reduced to 6,000 barrels. Then 94,000 barrels of 6.4 psi RVP summer grade RFG would have to be blended with this 6,000 barrels of winter grade RFG to produce 100,000 barrels of summer grade RFG with a 6.8 psi RVP, using linear blending. The net effect of the two step phase-in is that RFG inventory does not have to be reduced as greatly in order to achieve the winter to summer RVP transition. A terminal using the two step phase-in from the example above would only have to reduce its tankage volume to a minimum of 19,000 barrels instead of 6,000 barrels in order to achieve its RVP transition.

Thus far, feedback on the idea of a two step phase-in option has been mixed. Some parties with whom EPA has spoken prefer a phase-in approach to a terminal receipt date. Others have expressed concern that the addition of a second transitional RVP compliance date would increase record keeping requirements and would not significantly reduce the current practice of drawing down tanks to very low levels. EPA requests comment on the two step phase-in approaches listed above, as well as any alternatives to help accomplish a smooth phase-in.

E. Limit Applicability of Terminal Receipt Date to Chicago/Milwaukee Areas

We also request comment on the option of limiting the applicability of the proposed terminal receipt date to the Chicago and Milwaukee metropolitan areas. These two areas have been most severely impacted by low gasoline inventories during the past two spring transitions from winter to summer grade gasoline.

F. Reduce Allowable Minimum RVP to 6.0 psi

We also request comment on the option of decreasing the allowable minimum RVP for RFG at the refinery gate to 6.0 psi from 6.4 psi, as an addition to the proposed terminal receipt date, to further help ease the winter to summer RVP transition. Under the emissions model used to measure RFG performance, the lowest allowable RVP for RFG is 6.4 psi. Reducing the RVP of gasoline at the refinery gate gives terminals the flexibility to maintain slightly higher inventories of winter grade RFG during the transition period by allowing sub-RVP RFG to be blended with winter grade RFG during the tank turnover process. For example, if a tank contained 6,000 barrels of winter grade RFG with a 13.0 psi RVP, this volume could be blended with 94,000 barrels of summer grade RFG with a 6.4 psi RVP to produce a 100,000 barrel mix with an RVP of 6.8 psi, using linear blending. However, if the minimum allowable RVP of summer grade RFG were decreased, a greater volume of winter grade RFG could be blended with the sub-RVP summer grade RFG to produce an acceptable blend of summer grade RFG. For example, the tank volume of winter grade RFG with a 13.0 psi RVP would only have to be reduced to 11,000 barrels during the RVP Start Printed Page 60168transition. This 11,000 barrels could then be blended with 89,000 barrels of 6.0 psi RVP RFG to produce a 100,000 barrel mix with an RVP of 6.8 psi, using linear blending. The net effect of reducing the minimum allowable RVP is that RFG inventory does not have to be reduced as greatly in order to achieve the winter to summer RVP transition.

We have identified two potential concerns related to reducing the minimum allowable RVP for RFG at the refinery gate. First, reducing RVP also reduces the driveability index of RFG. In the event of late cold weather, vehicles could experience driveability problems if fueled with RFG with an RVP less than 6.4 psi. A potential solution would be to relax the minimum RVP only at the refinery gate, and not allow terminals to release RFG with an RVP lower than 6.4 psi. Second, refiners may be reluctant to use this option due to the additional processing costs associated with reducing RVP below 6.4 psi.

III. Eliminate Current Blendstock Accounting Regulation 40 CFR 80.102

Today's action proposes to replace the current blendstock accounting requirements at 40 CFR 80.102 with simpler, less restrictive requirements. These requirements are a part of the anti-dumping regulations for conventional gasoline (CG).

The Clean Air Act required EPA to establish the anti-dumping regulations as part of the RFG program to prevent increases in oxides of nitrogen ( NOX) and toxics air emissions from conventional gasoline as a result of RFG production. Thus, the anti-dumping regulations prevent a refinery from transferring, or “dumping,” the relatively dirty components that it removes from its RFG (such as benzene) into its CG. Specifically, the anti-dumping regulations require that the CG produced or imported by each refinery and importer must be at least as clean with respect to NOX and toxics emission performance, on an annual average basis, as the gasoline produced or imported by that refinery or importer in 1990. Under these regulations, refineries and importers are required to develop individual baselines for these emissions based on the quality of the gasoline they produced or imported in 1990. Refiners and importers who are not able to develop an individualized baseline are subject to a predetermined baseline that is representative of the average exhaust toxics and NOX emission performance of 1990 gasoline, referred to as the anti-dumping statutory baseline. A refinery's or importer's individual 1990 baseline, or alternatively the statutory baseline, functions as the refinery's or importer's anti-dumping “standard.”[6]

Requirements for blendstock accounting were included in the anti-dumping regulations out of a concern that refineries with 1990 baselines cleaner than the anti-dumping statutory baseline would transfer dirty blendstocks to refineries with dirtier baselines because such refineries would be better able to use the dirty blendstocks while still meeting their anti-dumping baseline. Under the blendstock accounting provisions, if a cleaner refinery transfers large quantities of dirty gasoline blendstocks to another refinery, the cleaner refinery must account for all of the blendstocks it produces and transfers in its anti-dumping compliance calculations in specified subsequent annual averaging periods. Thus, the cleaner refinery could not benefit from such a transfer. The regulations require significant additional reporting by a refinery with a baseline cleaner than the anti-dumping statutory baseline that transfers ten percent or more blendstocks than it transferred in 1990 relative to its total production.

EPA now believes that the current blendstock accounting requirements are unnecessary. When refineries produce more total gasoline than that produced in 1990, the additional gasoline over and above the 1990 baseline volume must meet the statutory baseline for all refineries regardless of the refinery's individual baseline. Since nearly all refineries currently produce significantly more gasoline than they produced in 1990, EPA believes that the blendstock transfers that are likely to occur today will be between donor and recipient refineries whose total production is well above 1990 baseline volume levels with or without a transfer. If transfers under these conditions occur between refiners producing only CG, there will be no net change in the quality of their combined CG pool because the donor refiner's gallons at the statutory baseline would be replaced by the recipient refiner's gallons at this same baseline. Thus, there would likely be no motivation or opportunity for “gaming the system” under these circumstances. Where either or both refiners make RFG and CG, there is some potential for meeting a slightly lower baseline by transferring blendstocks.[7] However, it is unlikely that there would ever be any impact more significant than a small decrease in the stringency of compliance requirements, meaning that the gaming possibilities of such a transfer are very small, and thus any such transfers would produce only very small economic benefits which may be more than offset by the transactional costs associated with the transfer. As a result, the shifting of blendstocks from one refinery to another where both refineries produce more gasoline than they did in 1990 has very little potential to cause any adverse environmental impact.

Additionally, EPA has carefully examined individual refinery situations and has concluded that for the very limited number of refineries producing volumes where a transfer could result in some increased emissions, there is little possibility for gaming since clean/dirty refinery baseline pairs within a specific emission category ( NOX or toxics) are very uncommon. (i.e, for NOX and toxics, almost all members of this refinery subset are clean for one pollutant and dirty for the other leaving little chance of gaming for either.) [8]

Finally, the recently promulgated Mobile Source Air Toxics rule [9] requires each refinery to meet a performance standard for toxic air emissions for CG and RFG equivalent to the performance of that refinery's CG or RFG during the baseline years 1998, 1999, and 2000. Because this new baseline performance is better than 1990 baselines, refineries with dirty baselines would be even less likely to be able to accept dirty blendstocks since these blendstocks would potentially degrade performance relative to these years.

We believe the current blendstock accounting provisions create significant additional compliance and reporting requirements, and, in some cases, may have the effect of deterring refiners or importers from transferring gasoline blendstocks that they otherwise would transfer in the normal course of business in response to legitimate supply concerns and other refinery needs. Moreover, we believe that eliminating these requirements will help to improve the responsiveness of the gasoline supply system by increasing refiners' flexibility to transfer gasoline Start Printed Page 60169blendstocks.[10] Consequently, today's rule proposes to eliminate the current blendstock accounting requirements.

There remains some concern about the possibility that a refiner with a clean baseline could create an off-site terminal blending facility acting as a refinery for the sole purpose of certifying gasoline at the less stringent statutory baseline. To gain a significant compliance advantage the clean refiner would have to transfer a great deal of its gasoline production such that the original clean refinery would be making less gasoline than in 1990. Otherwise, the clean refinery would be producing incremental gasoline at approximately the statutory baseline and the transfer would not result in any significant compliance advantage. To address the limited situations in which blendstock transfers could possibly be undertaken for the purpose of evading a more stringent baseline, today's rule proposes provisions which would require a refinery with a baseline that is cleaner than the anti-dumping statutory baseline, and that produces less gasoline than its 1990 baseline volume during the annual averaging period, to petition EPA for approval to transfer specified “applicable” (i.e., “dirty”) blendstocks in excess of 5% of the refinery's annual production. The refinery would be required to demonstrate that such blendstock transfers were for a legitimate operational purpose and not for the purpose of evading a more stringent baseline.

We believe that most blendstock transfers needed for operational purposes, for example during desulfurization unit turnarounds (which are projected to take approximately two weeks), are likely not to exceed 5% of the refinery's annual production. While we believe that 5% is the upper limit for necessary transfers of dirty blendstocks in most situations, the petition process would be available for unusual situations where desulfurization unit turnarounds or other such legitimate operational needs require blendstock transfers in excess of 5%. This petition processwould requires refineries to forecast total production for the entire year averaging period to be less than 1990 baseline volumes. The requirement to petition EPA for approval to transfer dirty blendstocks in excess of 5% of the refinery's annual production applies only to the highly unusual situation where a refinery possesses a baseline cleaner than the statutory baseline and produces less than its 1990 baseline volume during the annual averaging period. Other refineries would not be required to petition EPA for approval to transfer blendstocks even when in excess of 5% of their annual production. EPA requests comment on the practicality of this approach and on whether 5% is an appropriate trigger.[11]

IV. Updating ASTM Designated Analytical Test Methods for Reformulated and Conventional Gasoline to Their Most Recent ASTM Version

Refiners, importers and oxygenate blenders producing gasoline and diesel fuel are required to test RFG, CG and diesel fuel for RVP, aromatics, benzene, and various other parameters. During the federal RFG rulemaking, and in response to comments by the regulated industry, EPA designated analytical test methods that the Agency would use for enforcement and compliance purposes. See 40 CFR 80.46. On July 11, 1997, the Agency proposed to update the designated test methods that were ASTM standards in § 80.46 (a) through (g) to their most recent version, as well as replace the designated test methods for RVP and oxygenates with the ASTM version.[12] This proposal was never finalized by the Agency, and since the time of the proposal, these designated test methods have been updated by ASTM.

Since the July 11, 1997, proposal was published, newer versions of several designated test methods have been published by ASTM. We have reviewed these newer versions of the ASTM test methods. The Agency believes that the revisions in the newer versions of the ASTM designated test methods are not significant changes that would cause a user of an older version of the same method to incur significant costs. All of the revisions were deemed necessary by ASTM so that improvements in the test method's procedures would ensure better operation for the user of the test method. Therefore, today the Agency is proposing to update each designated test method for gasoline that is an ASTM standard, excluding the measurement of sulfur and aromatics in gasoline, at § 80.46 to its most recent ASTM version, as well as replace the designated test methods for RVP and oxygenates with the ASTM version. Table 3 lists the designated analytical test methods for each parameter measured under the RFG and CG fuels program under today's proposal.

Table 3.—Designated Analytical Test Method Under the RFG and CG Fuel Programs

Fuel parameterDesignated analytical test method
OlefinsASTM D-1319-98, entitled “Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Absorption”
Reid Vapor PressureASTM D 5191-99, entitled “Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method), except that the following correlation equation be used with ASTM D 5191-99:
RVP psi = (0.956*X)−0.347
RVP kPa = (0.956*X)−2.39
Start Printed Page 60170
Where:
X = total measured vapor pressure in psi or kPa
DistillationASTM D-86-00a, entitled “Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure”
Oxygen and Oxygenate content analysisASTM D 5599-00, entitled “Standard Test Method for Determination of Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection1
1 Prior to September 1, 2004, and when oxygenates present are limited to MTBE, ETBE, TAME, DIPE, tertiary-amyl alcohol, and C1 and C4 alcohols, any refiner, importer, or oxygenate blender may determine oxygen and oxygenated content using ASTM standard method D-4815-99, entitled “Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, tertiary-amyl Alcohol and C1 and C4 Alcohols in Gasoline by Gas Chromatography provided the result is correlated to ASTM D 5599-00.

V. Corrections to Gasoline and Diesel Sample Testing Methodology

40 CFR Part 80, Appendices D and G, specify sampling procedures for gasoline and diesel fuel for all motor vehicle fuel programs under 40 CFR Part 80, including the programs for unleaded gasoline, gasoline volatility, diesel sulfur, RFG, and anti-dumping. Today's proposal would replace the sampling procedures in Appendices D and G with the following ASTM standard practices:

  • D 4057-95(2000), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products;”
  • D 4177-95(2000), “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products;”
  • D 5842-95(2000), “Standard Practice for Sampling and Handling of Fuels for Volatility Measurements;” and
  • D 5854-96(2000), “Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products.”

These changes were formerly proposed in “Regulation of Fuels and Fuel Additives: Modifications to Standards and Requirements for Reformulated and Conventional Gasoline—Proposed Rule,” 62 FR 37338 (July 11, 1997), although these provisions were never finalized. Since we are proposing to update various other test methods via this notice, it is logical to consider sampling methodologies here as well.

Appendices D and G of 40 CFR Part 80 were adopted from the 1981 version of D 4057. Over time, however, ASTM has updated D 4057, and these changes are not reflected in Appendices D and G. For example, Appendix D addresses the collection of samples from a “tap” in the shell of a petroleum storage tank. The current requirement under Appendix D, reflective of D 4057-81, requires that taps extend at least three feet into the storage tank. See 11.3.1.1 of Appendix D. However, tap extensions are necessary only for heavy petroleum products (and not for gasoline and diesel fuel), and, furthermore, tap extensions are not possible with floating roof storage tanks that are commonly used today. As a result, EPA and regulated parties currently agree to waive the tap extension requirement on a case-by-case basis. Under D 4057-95(2000) sampling tap extensions are not required for light petroleum products such as gasoline and diesel fuel, so that if this ASTM procedure were adopted the tap extension issue would be resolved for all cases.

EPA is proposing to adopt three ASTM methods in addition to D 4057-95(2000) in order to include procedures that address a broad scope of sampling situations that are relevant to EPA's motor vehicle fuels programs. D 4177-95(2000) deals with automatic sampling of petroleum products, which is relevant under the anti-dumping regulations for refiners who produce conventional gasoline using an in-line blending operation where automatic sampling is necessary. Similarly, D 5842-95(2000) deals with sampling and sample handling for volatility measurement, which is relevant to determining compliance with the volatility standards in § 80.27 and the RFG standards in § 80.41. Last, D 5854-96(2000) deals with the creation of composite samples, which is relevant under the RFG and anti-dumping programs in certain situations involving imported gasoline where the gasoline from multiple ship compartments is treated as a single batch.

EPA believes it is appropriate to replace Appendices D and G with ASTM standard practices. The current ASTM practices reflect up to date procedures, which if followed would result in improved sample quality for regulatory purposes. In addition, the adoption of industry standard procedures would reduce regulatory burden because parties would be able to follow their customary practices when meeting regulatory requirements.

VI. Administrative Requirements

A. Executive Order 12866

Under Executive Order 12866, (58 FR 51735 (October 4, 1993)) the Agency must determine whether the regulatory action is “significant” and therefore subject to OMB review and the requirements of the Executive Order. The Order defines “significant regulatory action” as one that is likely to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or State, local, or tribal governments or communities;

(2) Create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

(3) Materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the rights and obligations of recipients thereof; or

(4) Raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.”

EPA has determined that this regulation is a significant regulatory action under item (4) above. Pursuant to the terms of Executive Order 12866, OMB has notified EPA that it considers this a “significant regulatory action” within the meaning of the Executive Order. EPA has submitted this action to OMB for review. Changes made in response to OMB suggestions or recommendations will be documented in the public record.

B. Executive Order 13132 (Federalism)

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in Start Printed Page 60171the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”

This proposed rule does not have federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. The proposed rule would establish a new April 15 receipt date by which terminals must physically begin receiving summer grade RFG, and is intended to help stabilize the supply of RFG during the spring RVP transition. This proposed rule also simplifies the existing blendstock accounting requirements at 40 CFR 80.102 and updates ASTM test methods to their most recent version. Thus, Executive Order 13132 does not apply to this proposed rule.

In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicits comment on this proposed rule from State and local officials.

C. Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments)

On January 1, 2001, Executive Order 13084 was superseded by Executive Order 13175. However, this proposed rule was developed during the period when Executive Order 13084 was still in force, and so tribal considerations were addressed under Executive Order 13084. Development of the final rule will address tribal considerations under Executive Order 13175. Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments” (65 FR 67249, November 6, 2000), requires EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.” “Policies that have tribal implications” is defined in the Executive Order to include regulations that have “substantial direct effects on one or more Indian tribes, on the relationship between the Federal government and the Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes.”

This RFG terminal receipt date rule does not have tribal implications. It will not have substantial direct effects on tribal governments, on the relationship between the Federal government and Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in Executive Order 13175. This proposed rule applies to gasoline refiners, blenders and importers that supply gasoline to RFG areas. Today's action proposes some changes that would modify the Federal RFG requirements, and does not impose any enforceable duties on communities of Indian tribal governments. Thus, Executive Order 13175 does not apply to this rule.

D. Regulatory Flexibility Act (RFA), as Amended by the Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq.

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business that has not more than 1,500 employees (13 CFR 121.201); (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. We have determined that no small entities will experience an impact from this proposal. RFG batch results reported for 2000 indicate that no winter grade RFG produced or imported from April 8 through April 30 was supplied by small businesses.

Although this proposed rule will not have a significant impact on a substantial number of small entities, EPA has nonetheless tried to reduce the impact of this rule on small entities. We continue to be interested in the potential impacts of the proposed rule on small entities and welcome comments on issues related to such impacts.

E. Paperwork Reduction Act

The information collection requirements in this proposed rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An Information Collection Request (ICR) document has been prepared by EPA (OMB # 2060-0277, EPA ICR No. 1591.14) and a copy may be obtained from Susan Auby by mail at Collection Strategies Division; U.S. Environmental Protection Agency (2822); 1200 Pennsylvania Ave., NW, Washington, DC 20460, by e-mail at farmer.sandy@epamail.epa.gov, or by calling (202) 260-2740. A copy may also be downloaded off the Internet at http://www.epa.gov/​icr.

Under today's proposed rule, EPA is requiring refiners to keep certain records associated with the supply of RFG. However, EPA believes that this requirement will be met using documents created and kept for commercial business purposes; i.e., documents that show the movement of RFG to storage tanks and volume and parameter measurements. This requirement, therefore, is not expected to impose additional recordkeeping burdens on regulated parties.

Today's action also proposes to eliminate the current blendstock accounting provisions and instead requires only a small subset of refiners, and only under unusual situations, to submit a petition to EPA in order to transfer certain blendstocks. The information collection hour burden associated with the current blendstock accounting requirements is estimated to be 24 hours to track blendstock transfers and prepare each blendstock accounting report, and 80 hours to prepare a request for a waiver of the blendstock accounting requirements (under extreme or unusual circumstances). These burdens would be eliminated under this action. The petition requirement proposed under this action is estimated to be 3 hours to prepare each petition. The respondent cost associated with the current blendstock accounting requirement is estimated to be $60 per hour for blendstock tracking and preparation of each blendstock accounting report and blendstock accounting waiver request. The respondent cost per petition under this action is also estimated to be $60 per hour. The total information collection hour burden associated with the current blendstock provisions is estimated to be 4,880 hours per year. This is based on an estimate of 200 respondents at 24 hours for blendstock tracking and Start Printed Page 60172preparation of blendstock accounting reports, and one respondent at 80 hours for preparation of blendstock accounting waiver requests. These burdens would be eliminated under this action. The information collection hour burden associated with the petition requirement potentially applicable to the small subset of refiners under this action is estimated to be a total of 15 hours, based on an estimated 5 respondents at 3 hours per petition. The total information collection hour burden, therefore, would be reduced by 4,865 hours (4,880−15). Based on previous experience with the RFG/anti-dumping program, EPA believes the estimates of the number of respondents both under the current rule and this action are likely to be the maximum number of respondents during an annual averaging period. The total cost burden associated with the current blendstock provisions is estimated to be $292,800 (4,880 hours × $60 per hour). This cost would be eliminated under this action. The total cost burden associated with the petition requirement applicable to the small subset of refiners included in today's rule is estimated to be $900 (15 hours × $60 per hour). As a result, today's rule would provide an overall reduction in cost burden of approximately $291,900 ($292,800−$900). We request comment on this change in the information collection burden associated with anti-dumping compliance.

Regarding recordkeeping and reporting burdens, in a letter dated December 12, 2000, the National Petrochemical & Refiners Association (NPRA) commented on EPA's draft Information Collection Request for reformulated and conventional gasoline reporting. 65 FR 60939 (October 13, 2000). In the letter, NPRA made several requests relating to the RFG program's current information collection burden. Although today's proposed action does not address all of NPRA's requests, as discussed above, today's action would eliminate all of the current burden associated with the RFG program's anti-dumping blendstock accounting requirements. The current blendstock provisions impose substantial recordkeeping and reporting burdens on refiners who transfer blendstocks. These recordkeeping and reporting burdens may have had the effect of deterring refiners from transferring such blendstocks. Today's action would eliminate these burdens for all refiners. The information collection burden on the small subset of refiners who would be required to petition EPA under today's action would be minimal. We believe this reduction in information collection burden would result in a more free exchange of blendstocks.

OMB has approved the information collection requirements contained in the final RFG/anti-dumping rulemaking (See 59 FR 7716 (February 16, 1994) and has assigned OMB control number 2060-0277 (EPA ICR No. 1591.13). Upon promulgation of a final rule, ICR 1591.14 associated with this rule will be encompassed in the next renewal of ICR 1591.13.

Burden means the total time, effort, or financial resources expended by persons to generate, maintain, retain, or disclose or provide information to or for a Federal agency. This includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes of collecting, validating, and verifying information, processing and maintaining information, and disclosing and providing information; adjust the existing ways to comply with any previously applicable instructions and requirements; train personnel to be able to respond to a collection of information; search data sources; complete and review the collection of information; and transmit or otherwise disclose the information. An Agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations are listed in 40 CFR part 9 and 48 CFR Chapter 15. Comments are requested on the Agency's need for this information, the accuracy of the provided burden estimates, and any suggested methods for minimizing respondent burden, including through the use of automated collection techniques. Send comments on the ICR to the Director, Collection Strategies Division; U.S. Environmental Protection Agency (2822); 1200 Pennsylvania Ave., NW, Washington, DC 20460; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th St., N.W., Washington, DC 20503, marked “Attention: Desk Officer for EPA.” Include the ICR number in any correspondence. Since OMB is required to make a decision concerning the ICR between 30 and 60 days after December 3, 2001, a comment to OMB is best assured of having its full effect if OMB receives it by January 2, 2002. The final rule will respond to any OMB or public comments on the information collection requirements contained in this proposal.

F. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures to State, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more in any one year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least costly, most cost-effective or least burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least costly, most cost-effective or least burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.

Today's proposed rule contains no Federal mandates (under the regulatory provisions of Title II of the UMRA) for State, local or tribal governments or the private sector. The proposed rule would impose no enforceable duty on any State, local or tribal governments or the private sector. This proposed rule applies to gasoline refiners, blenders and importers that supply gasoline to RFG areas.

G. Executive Order 13045: Children's Health Protection

Executive Order 13045: “Protection of Children from Environmental health Risks and Safety Risks” (62 FR 19885, April 23, 1997) applies to any rule that: (1) is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a Start Printed Page 60173disproportionate effect on children. If the regulatory action meets both criteria, the Agency must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives considered by the Agency.

EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or safety risks, such that the analysis required under section 5-501 of the Order has the potential to influence the regulation. This proposal is not subject to Executive Order 13045 because it does not establish an environmental standard intended to mitigate health or safety risks.

H. National Technology Transfer and Advancement Act of 1995 (NTTAA)

Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113, section 12(d) (15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards (e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. The NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.

This proposed rulemaking involves environmental monitoring or measurement. Consistent with the Agency's Performance Based Measurement System (“PBMS”), EPA proposes not to require the use of specific, prescribed analytic methods. Rather, the Agency plans to allow the use of any method that meets the prescribed performance criteria. The PBMS approach is intended to be more flexible and cost-effective for the regulated community; it is also intended to encourage innovation in analytical technology and improved data quality. EPA is not precluding the use of any method, whether it constitutes a voluntary consensus standard or not, as long as it meets the performance criteria specified.

This proposed rule would update certain designated analytical test methods to their most recent ASTM version for the RFG program. Today's proposed action does not establish new technical standards or analytical test methods, although it does update certain ASTM test methods and sampling methods to their current versions. To the extent that this proposed action would allow the use of standards developed by voluntary consensus bodies (such as ASTM) this action would further the objectives of the NTTAA. The Agency plans to address the objectives of the NTTAA more broadly in an upcoming rulemaking to establish performance-based criteria for qualification of alternative analytical test methods.

I. Executive Order 13211 (Energy Effects)

This rule is not an economically “significant energy action” as defined in Executive Order 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use” (66 FR 28355 (May 22, 2001)) because it does not have a significant adverse effect on the supply, distribution, or use of energy. Although this rule will slightly decrease the volume of summer grade RFG produced from April 8 through April 30 by approximately 0.4 percent due to earlier production of summer grade RFG, the annual cost associated with this rule is less than $100 million. Also, this rule will provide for a smoother annual transition to summer RFG, which should help to alleviate seasonal pressures on gasoline supply. Moreover, EPA is allowing additional flexibility for refiners to transfer blendstocks, which should allow refiners to better respond to fluctuations in gasoline supply or demand.

VII. Statutory provisions and Legal Authority

Statutory authority for today's final rule comes from sections 211(c) and 211(k) of the CAA (42 U.S.C. 7545(c) and (k)). Section 211(c) allows EPA to regulate fuels that contribute to air pollution which endangers public health or welfare, or which impairs emission control equipment. Section 211(k) prescribes requirements for RFG and conventional gasoline and requires EPA to promulgate regulations establishing these requirements. Additional support for the procedural aspects of the fuels controls in today's rule comes from sections 114(a) and 301(a) of the CAA.

Start List of Subjects

List of Subjects in 40 CFR Part 80

End List of Subjects Start Signature

Dated: November 20, 2001.

Christine Todd Whitman,

Administrator.

End Signature

For the reasons set forth in the preamble, part 80 of title 40 of the Code of Federal Regulations is proposed to be amended as follows:

Start Part

PART 80—REGULATION OF FUELS AND FUEL ADDITIVES

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

Start Authority

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

End Authority

2. Section 80.8 is added to subpart A to read as follows:

Sampling methods for gasoline and diesel fuel.

The sampling methods specified in this section shall be used to collect samples of gasoline and diesel fuel for purposes of determining compliance with the requirements of this part.

(a) Manual sampling. Manual sampling of tanks and pipelines shall be performed according to the applicable procedures specified in American Society for Testing and Materials (ASTM) method D 4057-95(2000), entitled “Standard Practice for Manual Sampling of Petroleum and Petroleum Products.”

(b) Automatic sampling. Automatic sampling of petroleum products in pipelines shall be performed according to the applicable procedures specified in ASTM method D 4177-95(2000), entitled “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products.”

(c) Sampling and sample handling for volatility measurement. Samples to be analyzed for Reid Vapor Pressure (RVP) shall be collected and handled according to the applicable procedures in ASTM method D 5842-95(2000), entitled “Standard Practice for Sampling and Handling of Fuels for Volatility Measurement.”

(d) Sample compositing. Composite samples shall be prepared using the applicable procedures in ASTM method D 5854-96(2000), entitled “Standard Practice for Mixing and Handling of Liquid Samples of Petroleum and Petroleum Products.”

(e) Incorporations by reference. ASTM standard practices D 4057-95(2000), D 4177-95(2000), D 5842-95(2000), and D 5854-96(2000), are incorporated by reference. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 100 Barr Harbor Dr., West Start Printed Page 60174Conshohocken, PA 19428. Copies may be inspected at the Air Docket Section (LE-131), room M-1500, U.S. Environmental Protection Agency, Docket No. A-97-03, 401 M Street, SW, Washington, DC 20460, or at the Office of the Federal Register, National Archives and Records Administration, Washington, DC 20408, (202) 523-4534.

3. Section 80.27 is amended by revising paragraphs (b) and (d)(2) to read as follows:

Controls and prohibitions on gasoline volatility.
* * * * *

(b) Determination of compliance. Compliance with the standards listed in paragraph (a) of this section shall be determined by the use of the sampling methodologies specified in § 80.8 and the testing methodology specified in § 80.46(c).

* * * * *

(d) * * *

(2) In order to quality for the special regulatory treatment specified in paragraph (d)(1) of this section, gasoline must contain denatured, anhydrous ethanol. The concentration of the ethanol, excluding the required denaturing agent, must be at least 9% and no more than 10% (by volume) of the gasoline. The ethanol content of the gasoline shall be determined by the use of one of the testing methodologies specified in § 80.46(g). The maximum ethanol content shall not exceed any applicable waiver conditions under section 211(f) of the Clean Air Act.

* * * * *

4. Section 80.28 is amended by revising paragraphs (g)(2)(ii) and (g)(4)(i) to read as follows:

Liability for violations of gasoline volatility controls and prohibitions.
* * * * *

(g) * * *

(2) * * *

(ii) Test results using the sampling methodology set forth in § 80.8 and the testing methodology set forth in § 80.46(c), or any other test method where adequate correlation to § 80.46(c) of this part is demonstrated, which show evidence that the gasoline determined to be in violation was in compliance with the applicable standard when it was delivered to the next party in the distribution system.

* * * * *

(4) * * *

(i) Test results using the sampling methodology set forth in § 80.8 and the testing methodology set forth in § 80.46(c), or any other test method where adequate correlation to § 80.46(c) is demonstrated, which show evidence that the gasoline determined to be in violation was in compliance with the applicable standard when transported from the refinery.

* * * * *

5. Section 80.40 is amended by revising paragraph (c)(1) to read as follows:

Fuel certification procedures.
* * * * *

(c)(1) “Adjusted VOC gasoline” for purposes of the general requirements in § 80.65(d)(2)(ii), and the certification procedures in this section is gasoline that contains 10 volume percent ethanol, or RBOB intended for blending with 10 volume percent ethanol, that is intended for use in the areas described at § 80.70(f) and (i), and is designated by the refiner as adjusted VOC gasoline subject to less stringent VOC standards in § 80.41(e) and (f). In order to for “adjusted VOC gasoline” to qualify for the regulatory treatment specified in § 80.41(e) and (f), reformulated gasoline must contain denatured, anhydrous ethanol. The concentration of the ethanol, excluding the required denaturing agent, must be at least 9% and no more than 10% (by volume) of the gasoline. The ethanol content of the gasoline shall be determined by use of one of the testing methodologies specified in § 80.46(g).

* * * * *

6. Section 80.46 is amended by revising paragraphs (b), (c), (d), (e)(1), (f)(2), (g) and (h) to read as follows:

Measurement of reformulated gasoline fuel parameters.
* * * * *

(b) Olefins. Olefin content shall be determined using ASTM standard method D 1319-98, entitled “Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption.”

(c) Reid vapor pressure (RVP). Reid vapor pressure (RVP) shall be determined using ASTM standard method D 5191-99, entitled “Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method),” except that the following correlation equation must be used:

RVP psi = (0.956 * X) −0.347

RVP kPa = (0.956 * X) −2.39

Where

X = total measured vapor pressure in psi or kPa

(d) Distillation. Distillation parameters shall be determined using ASTM standard method D 86-00a, entitled” Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure.”

* * * * *

(f) * * *

(2)(i) Prior to September 1, 2004, any refiner or importer may determine aromatics content using ASTM standard method D 1319-99, entitled “Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Flourescent Indicator Adsorption,” for purposes of meeting any testing requirement involving aromatics content; provided that

(ii) The refiner or importer test result is correlated with the method specified in paragraph (f)(1) of this section.

* * * * *

(g) Oxygen and oxygenate content analysis. (1) Oxygen and oxygenate content shall be determined using ASTM standard method D 5599-00, entitled “Standard Test Method for Determination of Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection.”

(2)(i) Prior to September 1, 2004, and when the oxygenates present are limited to MTBE, ETBE, TAME, DIPE, tertiary-amyl alcohol, and C1 to C4 alcohols, any refiner, importer, or oxygenate blender may determine oxygen and oxygenate content using ASTM standard method D 4815-99 entitled “Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, tertiary-Amyl Alcohol, and C1 to C4 Alcohols in Gasoline by Gas Chromatography,” for purposes of meeting any testing requirement; provided that

(ii) The refiner or importer test result is correlated with the method specified in paragraph (g)(1) of this section.

(h) Incorporations by reference. ASTM standard methods D 3606-99, entitled “Standard Test Method for Determination of Benzene and Toluene in Finished Motor and Aviation Gasoline by Gas Chromatography;” D 1319-98, entitled “Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption;” D 1319-99, entitled “Standard Test Method for Hydrocarbon Types in Liquid Petroleum Products by Fluorescent Indicator Adsorption;” D 4815-99, entitled “Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE, tertiary-Amyl Alcohol and C1 to C4 Alcohols in Gasoline by Gas Chromatography;” D 2622-98, entitled “Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-Ray Fluorescence Spectrometry;” D 5453-00, entitled “Standard Test Start Printed Page 60175Method for Determination of Total Sulfur in Light Hydrocarbons, Motor Fuels, and Oils by Ultraviolet Fluorescence;” D 4045-99, entitled “Standard Test Method for Sulfur in Petroleum Products by Hydrogenolysis and Rateometric Colorimetry;” D 6428-98, entitled “Test Method for Total Sulfur in Liquid Aromatic Hydrocarbons and Their Derivatives by Oxidative Combustion and Electrochemical Detection;” D 3120-96 entitled “Standard Test Method for Trace Quantities of Sulfur in Light Petroleum Hydrocarbons by Oxidative Microcoulometry;” D 3246-96, entitled “Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry;” D 4468-85 (Re-approved 1995), entitled “Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry;” D 1266-98, entitled “Standard Test Method for Sulfur in Petroleum Products (Lamp Method),” D 6334-98, entitled “Standard Test Method for Sulfur in Gasoline by Wavelength Dispersive X-Ray Fluorescence;” D 5191-99, entitled, “Standard Test Method for Vapor Pressure of Petroleum Products (Mini Method);” D 5599-00, entitled, “Standard Test Method for Determination of Oxygenates in Gasoline by Gas Chromatography and Oxygen Selective Flame Ionization Detection;” and D 86-00a, entitled, “Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure;” are incorporated by reference in this section. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society of Testing and Materials, 1916 Race Street, Philadelphia. PA 19103. Copies may be inspected at the Air Docket Section (LE-131), room M-1500, U.S. Environmental Protection Agency, Docket Nos. A-97-03, A-99-06, and A-2001-21, 401 M Street, SW, Washington DC 20460 or at the Office of the Federal Register, 800 North Capitol Street, NW, Suite 700, Washington, DC.

7. Section 80.65 is amended by revising paragraph (d)(3) to read as follows:

General requirements for refiners, importers, and oxygenate blenders.
* * * * *

(d) * * *

(3) Every batch of reformulated or conventional gasoline or RBOB produced or imported at each refinery or import facility shall be assigned a number (the “batch number”), consisting of the EPA-assigned refiner, importer or oxygenate blender registration number, the EPA facility registration number, the last two digits of the year in which the batch was produced, and a unique number for the batch, beginning with the number one for the first batch produced or imported each calendar year and each subsequent batch during the calendar year being assigned the next sequential number (e.g., 4321-54321-95-000001, 4321-54321-95-000002, etc.).

* * * * *

8. Section 80.78 is amended by adding paragraph (a)(11) to read as follows:

Controls and prohibitions on reformulated gasoline.
* * * * *

(a) * * *

(11) No persons except retailers and wholesale purchaser-consumers may take physical custody of reformulated gasoline or reformulated blendstock for oxygenate blending (RBOB) that is not VOC-controlled during the period April 15 through September 15 of each year.

* * * * *

9. Section 80.91 is amended by removing paragraph (a)(1)(iii) and removing the “; and” at the end of paragraph (a)(1)(ii) and replacing it with a period.

10. Section 80.92 is amended by revising the first sentence of paragraph (a)(1) to read as follows:

Baseline auditor requirements.

(a) * * *

(1) Each refiner or importer is required to have its individual baseline determination methodology, resulting baseline fuel parameter, volume and emissions values verified by an auditor which meets the requirements described in this section. * * *

* * * * *

11. Section 80.101 is amended by removing and reserving paragraphs (d)(2) and (e)(2), and removing paragraph (h)(2)(iii), and revising paragraphs (h)(2)(i) and (ii) to read as follows:

Standards applicable to refiners and importers.
* * * * *

(h) * * *

(2) * * *

(i) Be made as part of the report for the 1995 averaging period required by § 80.105; and

(ii) Apply for the 1995 averaging period and for each subsequent averaging period, and may not thereafter be changed.

* * * * *

12. Section 80.102 is revised to read as follows:

Restrictions on transferring applicable blendstocks

(a) The following petroleum products are considered “applicable blendstocks” for purposes of this subpart E:

(1) Reformate;

(2) Light coker naphtha;

(3) FCC naphtha;

(4) Benzene/toluene/xylene;

(5) Pyrolysis gas;

(6) Aromatics;

(7) Polygasoline; and

(8) Dimate.

(b)(1) No refinery or importer whose 1990 baseline value for any emission performance, as determined in accordance with §§ 80.91 and 80.92, is more stringent than the anti-dumping statutory baseline value for that emission performance may transfer applicable blendstock(s) under paragraph (a) of this section to others in excess of five per cent of the refinery's or importer's total gasoline production (including conventional gasoline, reformulated gasoline and RBOB) during an annual averaging period, unless the refiner for the refinery or the importer petitions for and obtains approval from EPA to transfer such blendstock(s).

(2) A petition under paragraph (b)(1) of this section must include a demonstration that the transfer of blendstock(s) is for a legitimate operational purpose and not for the purpose of evading a more stringent baseline.

(3) The provisions of paragraph (b)(1) of this section do not apply in the case of a refinery or importer whose total gasoline production (including conventional gasoline, reformulated gasoline and RBOB) during the entire annual averaging period in which the blendstock transfers are made is equal to or greater than the refinery's or importer's 1990 baseline volume.

(c) Applicable blendstocks under paragraph (a) of this section may be excluded from the requirements of this section where the refiner or importer has sufficient evidence in the form of documentation that the blendstocks are:

(1) Exported;

(2) Used for other than gasoline blending purposes;

(3) Transferred to a refiner that used the blendstock as a “feedstock” in a refining process during which the blendstock underwent a substantial chemical or physical transformation; or

(4) Transferred between refineries that have been grouped pursuant to § 80.101(h) by a refiner for the purpose of determining compliance under this subpart;Start Printed Page 60176

(5) Used to produce California gasoline as defined in § 80.81(a)(2).

13. Section 80.104 is amended by revising paragraph (a)(1)(i) and removing and reserving paragraph (a)(2)(ix) to read as follows:

Recordkeeping requirements.
* * * * *

(a) * * *

(1) * * *

(i) Each batch of conventional gasoline; and

* * * * *

14. Section 80.105 is amended by removing and reserving paragraphs (a)(2) and (a)(3).

15. Section 80.106 is amended by removing and reserving paragraph (b).

16. Section 80.128 is amended by removing paragraphs (h) and (i).

Appendix D—[Reserved.]

17. Appendix D is removed and reserved.

Appendix E to Part 80—[Reserved.]

18. Appendix E is removed and reserved.

Appendix F to Part 80—[Reserved.]

19. Appendix F is removed and reserved.

Appendix G to Part 80—[Reserved.]

20. Appendix G is removed and reserved.

End Part End Supplemental Information

Footnotes

1.  Section 211(k) also includes compositional specifications for reformulated gasoline including a 2.0 weight percent oxygen minimum, a 1.0 volume percent benzene maximum, and a prohibition on heavy metal content, as well as a requirement that emissions of oxides of nitrogen (NOX) from RFG not increase compared to baseline emissions (baseline emissions are the emissions of 1990 model year vehicles operated on 1990 baseline gasoline).

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2.  “Petroleum Storage and Transport Times” by Jack Faucett Associates under contract to EPA, September, 1986.

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3.  Note that while we are not proposing eliminating this May 1 terminal compliance requirement, we are interested in the continuing need for a May 1 terminal compliance requirement to ensure adequate and timely supplies of summer RFG to meet the existing requirement of June 1 for retail station compliance.

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4.  EIA Memo: Potential Gasoline Price Impacts Due to Winter-Summer Transition, November, 8, 2001.

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5.  EIA Memo: Potential Gasoline Price Impacts Due to Winter-Summer Transition, November, 8, 2001.

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6.  Refiners producing CG at several facilities have the option of meeting the antidumping standards on an aggregate basis with an aggregated baseline. 40 CFR 80.101(h).

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7.  This is due to the concept of “equivalent CG volume” contained in the compliance baseline equation under the anti-dumping regulations in § 80.101(f). For a full discussion of this concept and the effects of RFG production on anti-dumping compliance, see “Technical Support Document for RFG Terminal Receipt Date Rule” in the docket for this rulemaking.

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8.  Refinery-specific information is submitted to EPA as confidential business information under the RFG and anti-dumping reporting requirements and cannot be made public.

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9.  66 FR 17230 (March 29, 2001)

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10.  EPA is aware that refiners have concerns regarding blendstock transfers under the newly promulgated gasoline sulfur reduction regulations. During maintenance periods for sulfur removal units or “turnarounds”, refineries may have to transfer fairly large amounts of low-sulfur blendstocks into refineries during maintenance periods. Refiners have indicated that these transfers could trip the current complicated blendstock accounting requirements. We believe that today's proposal resolves this concern by removing the current blendstock accounting requirements. Discussions with refiners have also indicated that the 5% trigger for the petition process is sufficiently high so as to be unlikely to interfere with such transfers, especially considering that the 5% trigger is only applicable to refiners making less gasoline than produced in 1990.

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11.  Two trigger mechanisms contained in today's action (the 5% trigger mechanism and annual gasoline production volumes less than 1990 volumes) would result in the petition process. These triggers essentially replace two criteria that, under the current regulations, would trigger blendstock accounting. These current criteria include a 3% transfer of blendstocks and a 10 percent increase in a multi-year ratio of blendstock transfers to total production for a facility relative to baseline years in the early 1990s. The 10% criteria required a fairly complex ongoing multi-year calculation of blendstock ratios which we believe is unnecessary. (These criteria are discussed more completely in “Technical Support Document for RFG Terminal Receipt Date Rule” included in the docket for this rulemaking.) EPA believes that the 5% trigger mechanism is sufficient to allow free transfer of blendstocks, without a petition, for most or all refiners in most or all situations. Additionally, the petition process would not be tripped even if more than 5% of blendstocks, relative to total production, are transferred unless a refinery is making less total volume than in 1990. Thus, for the petition process, we are proposing to eliminate the two criteria in the current regulations for blendstock accounting and substituting the new 5% trigger for the petition process.

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12.  62 FR 37338, July 11, 1997.

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[FR Doc. 01-29777 Filed 11-30-01; 8:45 am]

BILLING CODE 6560-50-P