United States Air and Radiation EPA420-D-01-005
Environmental Protection November 2001
Agency
<&EPA Draft Technical Support
Document:
Analysis of Regulation to
Establish New Date for
Receipt of Summer Grade
RFC at Terminals
y&o Printed on Recycled
Paper
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EPA420-D-01-005
November 2001
of to for
of RFC at
Transportation and Regional Programs Division
Office of Transportation and Air Quality
U.S. Environmental Protection Agency
Docket A-2001-21
Document Number II-B-1
NOTICE
This technical report does not necessarily represent final EPA decisions or positions.
It is intended to present technical analysis of issues using data that are currently available.
The purpose in the release of such reports is to facilitate the exchange of
technical information and to inform the public of technical developments which
may form the basis for a final EPA decision, position, or regulatory action.
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TABLE OF CONTENTS
I. INTRODUCTION 1
II. COST SUMMARY 5
IE. ESTIMATE OF OPERATING COSTS 10
IV. ESTIMATE OF COST TO SELL BUTANE DIRECTLY TO SPOT MARKET ... 15
V. ESTIMATE OF COSTS TO STORE AND SELL BUTANE 18
VI. SIMPLIFY BLENDSTOCK ACCOUNTING REGULATION 40 CFR § 80.102 22
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LIST OF TABLES
Table 1: RFG Batch Information from April 8, 2000 through April 30, 2000 in Support of an
April 15 Receipt Date 6
Table 2: RFG Batch Information from March 24, 2000 through April 30, 2000 in Support of an
April 1 Receipt Date 7
Table 3: Process Operations Information for Debutanizer and Depentanizer 11
Table 4: Summary of Energy Costs Taken from EIA and NPC Data Tables 1999 11
Table 5: Fraction FCC Gasoline to Total Refinery Gasoline 12
Table 6: Summer and Winter Prices for Butane and RFG 16
Table 7: Cost Summary for Selling All Butane to Spot Market, cents per gallon RFG
17
Table 8: Offsite and Location Factors Used for Estimating Capital Costs 19
Table 9: Economic Cost Factors Used in Calculating the Capital Amortization Factor
20
Table 10: Cost summary for Storing and Blending Butane in Winter Gasoline, cents per gallon
RFG 21
Table 11: Effect of Additional Gallons of CG Production on Compliance Baseline 37
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I. INTRODUCTION
A. Background
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 are proceeding with a rulemaking that will help to ensure a smoother seasonal
transition from winter to summer RFG.
B. Description of proposal
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 other
than summer grade RFG. While this restriction would apply to terminals, pipelines, barges and
other companies transporting fuel to terminals, effectively the restriction applies most directly to
terminals, so for ease of discussion the proposed April 15 compliance date will be referred to as a
1
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terminal receipt date. In order to comply with this new terminal receipt date, refiners would, on
average, need to begin shipping summer grade RFG on April 8 to ensure its receipt before April
15. 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 315.6 million gallons of RFG were produced or imported in PADDs 1, 2, and 3, and
the average RVP of this volume was 8.34 psi. Thus, establishing an April 15 summer RFG receipt
date would require the RVP of 315.6 million gallons of RFG to be reduced from an average of
8.34 psi to a nominal 6.8 psi to meet the summer RFG specifications.
C. How the proposed rule will help the transition period
EPA believes that the proposed rule will help provide 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 current practice. 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 terminal tanks to meet summer RFG requirements and increase volumes of RFG at
terminals during the transition. This will allow 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
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weeks in April. This will 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 by April 15 and would, at the latest, turn their tanks over between April 15 and May 1.
Turnover times will vary with terminal storage capacity and throughput of RFG at individual
terminals. 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 gradual tank blend down to meet the
May 1 date by which all RFG in terminal storage tanks must meet the summertime RFG
standards1.
D. Cost of the proposed rule
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 cent per gallon RFG to 0.73 cent per gallon
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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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 percent decrease in butane2, 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 cent 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 cent 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.
This document provides the supporting analysis for the cost, as well as a thorough
discussion of the blendstock accounting system.
This correlation between volume percent butane and RVP is taken from the study, "The Refining Economics
and Modeling Ban of MTBE" by PACE Consultants under contract to EPA , contract # 68-C-98-169, April,
2001.
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II. COST SUMMARY
Establishing a new date for receipt of summer grade RFG will require some refineries to
begin producing summer grade RFG earlier than they currently do. Summer grade RFG is more
expensive to produce than winter grade RFG due to the cost of removing additional butanes and
pentanes for RVP control and either selling or storing the removed butanes. Typically, during the
winter gasoline production season, refiners directly add purchased and refinery generated butanes
to their gasoline pool to increase RVP to a maximum allowable limit. Refiners also allow more
butanes and pentanes to remain in winter gasoline by decreasing the debutanization and
depentanization of gasoline blendstocks. Butanes removed from gasoline in order to reduce RVP
can either be sold to the spot butane market or stored and later added to the winter gasoline pool.
Pentanes removed for RVP control are assumed to be moved from RFG to the conventional
summer gasoline market. Because we are uncertain how much of the removed butane will be sold
directly to the spot market vs. stored, we have developed two cost estimates for an April 15
terminal receipt date and two cost estimates for an April 1 terminal receipt date. The first, highest
cost estimate for each date assumes that all of the removed butanes generated by a new terminal
receipt date are sold directly to the spot butane market. The second, lowest cost estimate for each
date assumes that new tankage is built to store all of the removed butanes generated by a new
terminal receipt date, and the butanes are later blended into the wintertime gasoline pool.
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The tables below summarize the volumes and average RVP of winter grade RFG from
2000 batch reports, by PADD, that would need to be produced or imported as summer grade RFG
for each terminal receipt date. Table 1 summarizes the volumes and RVP for an April 15 terminal
receipt date and Table 2 summarizes the volumes and RVP for an April 1 terminal receipt date.
Both tables include winter grade RFG produced 7 days before the terminal receipt date to account
for average transportation time of RFG from refinery to terminal.
Table 1: RFG Batch Information from April 8, 2000 through April 30, 2000 in Support of
an April 15 Receipt Date
PADD
1
2
3
total
Winter grade RFG produced
from April 8, 2000 through
April 30, 2000
(million gallons)
132.8
160.7
22.1
315.6
Average RVP of RFG
produced from April 8, 2000
through April 30, 2000
(psi)
9.06
7.52
9.97
8.34
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Table 2: RFC Batch Information from March 24, 2000 through April 30, 2000 in Support
of an April 1 Receipt Date
PADD
1
2
3
total
Winter grade RFG produced
from March 24, 2000 through
April 30, 2000
(million gallons)
378.5
283.0
77.1
738.6
Average RVP of RFG
produced from March 24,
2000 through April 30, 2000
(psi)
9.65
8.52
10.27
9.28
Based on the information in Table 1, we estimate the maximum total costs for an April 15
receipt date to be $2.3 million per year for direct sale of all additional butane production to spot
market or 0.73 cent per gallon RFG for 315.6 million gallons RFG. We estimate the minimum
total costs to be $1.5 Million per year for storing all butanes and blending into the winter gasoline
pool or 0.49 cent per gallon RFG for 315.6 million gallons RFG. Capital costs are 24 million
dollars. For both costs, butane volume is that necessary to reduce RVP of 315.6 million gallons
RFG from an RVP of 8.34 psi to 6.8 psi.
Based on the information in Table 2, we estimate the maximum total costs for an April 1
receipt date to be $7.6 million per year for direct sale of all additional butane production to spot
market or 1.04 cents per gallon for 738.6 million gallons RFG. We estimate minimum total costs
to be $4.8 million per year for storing all butanes and blending into the winter gasoline pool or
0.65 cent per gallon RFG for 738.6 million gallons RFG. Capital costs are 92 million dollars.
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For both costs, butane volume is that necessary to reduce RVP of 738.6 million gallons RFG from
an RVP of 9.28 psi to 6.8 psi.
The cost, in cents per gallon affected RFG, of producing more summer grade RFG 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 n3. 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 doesn't include demand induced price effects4.
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
EIA Memo: Potential Gasoline Price Impacts Due to Winter-Summer Transition, November, 8, 2001.
EIA Memo: Potential Gasoline Price Impacts Due to Winter-Summer Transition, November, 8, 2001.
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from April 8 through April 30, in addition to the cost of reducing RVP.
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III. ESTIMATE OF OPERATING COSTS
All of EPA's cost estimates include operational distillation costs for removal of butanes
and pentanes from gasoline blendstocks. Refiners would use two strategies to reduce the RVP of
the affected volumes of RFG. First, they would reduce the amount of purchased and generated
butanes that they add to these volumes of winter RFG. Second, they would perform additional
distillation of this gasoline in debutanizers and depentanizers. For this cost analysis, we assume
that refiners achieve all removal of butanes through additional debutanization of gasoline
blendstocks. Distillation vendors confirmed that refiners primarily achieve RVP reduction
through the additional debutanization and depentanization of FCC gasoline, and to a lesser extent
by debutanization of other gasoline blendstocks.
According to distillation vendors, 20 percent additional energy is typically required in an
FCC debutanizer to reduce gasoline RVP from 9 tolO psi to 6.8 psi. FCC debutanizer operating
costs were determined using 20 percent of Oak Ridge National Laboratory (ORNL) naphtha
splitter energy factors shown in Table 3, and the energy costs shown in Table 4. FCC depentanizer
operating costs to reduce RVP from 6.8 to 5.5 psi for RBOB production were calculated using the
energy factors from the ORNL FCC fractionator model for pentane removal from gasoline shown
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in Table 3, and the energy costs shown in Table 4. FCC depentanizer operating costs were
multiplied by the PADD 2 fractional production of RFG relative to the aggregate RFG gasoline
production of PADDs 1 through 3. FCC debutanizer operating costs and FCC depentanizer
operating costs were added together to produce a total operating cost of 0.46 cent per gallon FCC
gasoline.
Table 3: Process Operations Information for Debutanizer and Depentanizer
Electricity
(Kw-hr/bbl)*
Steam
(lb/bbl)*
Other Variable Operating Costs
($/bbl)
Debutanizer
0.02
11.6
0.012
Depentanizer
0.17
98
0.045
* Kw-hr/bbl is kilowatt hour per barrel, lb/bbl is pound per barrel. $/bbl is dollar per barrel. Steam
and electricity usage for the debutanizer are 20 percent of ORNL naphtha splitter model values
and represent required incremental usage. Steam rate of 98 Ibs/bbl used for the new depentanizer
taken from ORNL FCC fractionator model value for separation of pentanes from gasoline.
Table 4: Summary of Energy Costs Taken from EIA and NPC Data Tables 1999
Electricity
(0/KwH)*
Fuel Gas
($/FOE)*
PADD1
5.9
22.5
PADD 2
3.9
22.5
PADDS
4.2
18
PADD 'sl-3
Average
4.4
20
* 0/KwH is cents per kilowatt-hour, $/FOE is dollars per fuel oil equivalent. PADDs 1 through 3
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average obtained by volume weighting each PADD's total refinery gasoline to PADDs 1 through
3 aggregate total refinery gasoline production multiplied by the cost of electricity or fuel gas in
each PADD.
FCC gasoline is 39 percent of the average refiner's total gasoline production based on
1996 API/NPRA data5. From the API/NPRA data in Table 5, the fraction of FCC gasoline in each
PADD was calculated by dividing the average FCC gasoline production for each PADD by the
average refinery total gasoline production for each PADD. The FCC gasoline fraction of each
PADD was then volume weighted by each PADD's percent contribution to the aggregate gasoline
production of PADDs 1 through 3 to produce an overall average of 39 percent.
Table 5: Fraction FCC Gasoline to Total Refinery Gasoline6
Factor
Aggregate
Gasoline
Production
(bbl/day)
Fraction of
Aggregate
Gasoline
Production
Avg. Refinery
Total Gasoline
(bbl/day)
PADD 1
998,082
0.16
46,345
PADD 2
1,763,419
0.28
66,348
PADD 3
3,579,334
0.56
75,907
PADDs 1-3
6,340,836
1.00
62,866
Final Report, 1996 American Petroleum Institute/National Petroleum Refiners Association, Survey of
Refining Operations and Product Quality, July 1997.
Final Report, 1996 American Petroleum Institute/National Petroleum Refiners Association, Survey of
Refining Operations and Product Quality, July 1997.
12
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Factor
Avg. FCC
Gasoline
(bbl/day)
Fraction of FCC
Gasoline to
Total Refinery
Gasoline
PADD 1
21,452
0.46
PADD 2
17,622
0.27
PADD 3
33,335
0.44
PADDs 1-3
24,136
0.39
Multiplying the 0.46 cent per gallon operating cost to debutanize and depentanize FCC
gasoline by the 0.39 volume fraction of FCC gasoline produces a cost of 0.18 cent per gallon
RFG. This is the cost for lowering the RVP of FCC gasoline blendstock per RFG gallon.
We also assumed that additional debutanization is required for all other gasoline
blendstocks except alkylate and reformate. The RVP of alkylate and reformate is typically less
than 6.5 psi so we assumed that these two blendstocks do not require additional debutanization.
According to a study by PACE consultants for EPA, alkylate and reformate are approximately 36
percent of the total gasoline pool for PADDs 1 through 3 7. Subtracting the sum of 39 percent
FCC gasoline and 36 percent alkylate and reformate from 100 percent (representing the total
gasoline pool) leaves 25 percent of the blendstocks in the total gasoline pool, such as light straight
run gasoline or light coker gasoline, which must also be debutanized. The debutanizer cost factors
from Table 3 were used to produce a cost of 0.15 cent per gallon for removing butanes from this
25 percent volume of the pool. Multiplying the 0.15 cent per gallon operating cost by the 0.25
"The Refining Economics and Modeling Ban of MTBE" by PACE Consultants under contract to EPA .
contract # 68-C-98-169, April, 2001.
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volume fraction of the pool produces a cost of 0.03 cent per gallon RFG to debutanize the total
volumes in Tables 1 and 2. Total operating cost to debutanize and depentanize the total RFG
volumes in Tables 1 and 2 is 0.18 + 0.03 = 0.21 cent per gallon RFG.
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IV. ESTIMATE OF COST TO SELL BUTANE DIRECTLY TO SPOT MARKET
In addition to operating cost, the costs of selling all additional butane production directly
to the spot market include the price differential between summertime gasoline and summertime
butane. To estimate the cost of reducing the RVP of the total volumes of RFG in Tables 1 and 2
to 6.8 psi, we calculated the equivalent volume of butane that such reduction would generate,
assuming a 1.5 volume percent reduction in butane for every 1.0 psi reduction in RVP. For an
April 15 terminal receipt date (see Table 1) reducing the RVP for 315.6 million gallons of RFG
from 8.34 to 6.8 psi would generate an equivalent butane volume of 7.3 million gallons. For an
April 1 terminal receipt date (see Table 2) reducing the RVP of 738.6 million gallons of RFG
from 9.28 to 6.8 psi would generate an equivalent butane volume of 27.5 million gallons.
Total cost for sales of butanes directly to the market is the difference in average prices
between summertime RFG (US Gulf Coast unleaded; octane equal to 87) and summertime butane
(Mt Belvieu spot price) multiplied by the additional butane volume. Table 6 summarizes the
averages of years 2000 and 2001 for the winter and summer prices of butane and gasoline.
Multiplying the price differential between summer RFG and summer butane, 34.5 cents per
gallon, by the equivalent butane volume generated for each receipt date and dividing by the total
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volumes of RFG in Tables 1 and 2 results in a cost of 0.80 cent per gallon RFG for an April 15
receipt date and 1.29 cents per gallon RFG for an April 1 receipt date.
Table 6: Summer and Winter Prices for Butane and Gasoline
Butane price, cents/gallon
(Mt. Belvieu spot price)*
Gasoline price, cents/gallon
(US Gulf Coast RFG - regular
unleaded)*
Summer
56
90.5
Winter
74
83
* Prices are averages of year 2000 and 2001 data.
Costs for selling the butanes directly to the spot market in the transition period are partially
offset by the societal benefit of increasing the energy density in the remaining gasoline volume.
Since butane has a lower energy density than gasoline, the average energy density of the gasoline
pool will increase as relatively less energy-dense butane is removed from the pool. Dividing the
total societal benefit by the total volumes in Tables 1 and 2 results in a benefit of 0.28 cents per
gallon RFG for an April 15 terminal receipt date and 0.46 cents per gallon RFG for an April 1
terminal receipt date.
Table 7 summarizes the costs of selling all additional butane production directly to the
spot market, in cents per gallon RFG for the total volumes in Tables 1 and 2.
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Table 7: Cost Summary for Selling All Butane to Spot Market, cents per gallon RFG
Operating Cost
Downgrade Cost
Societal Benefit
Total
April 1 5 receipt date
0.21
0.80
-0.28
0.73
April 1 receipt date
0.21
1.29
-0.46
1.04
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V. ESTIMATE OF COSTS TO STORE AND SELL BUTANE
The costs of storing additional butane until winter include the capital cost to build new
tanks for butane storage, the interest paid to store butane at a rate of interest of 7.5 percent for 168
days, and price adjustments to the stored butane to account for summer and winter seasonal price
changes in butane and RFG in addition to operating cost. Total capital costs for butane storage
are $90/bbl (based on year 1992)8 and include all pumps, piping and associated equipment.
Capital costs were calculated for an average refinery to build new butane storage capacity for 15
days of incremental butane production from additional RVP reduction. The average refinery's
daily additional butane production for Table 1 was estimated to be 68,678 gallons/day or 1,635
BPSD and 110,598 gallons/day or 2,633 BPSD for Table 2. Thus, the average refinery would
need new butane tank storage for 1.03 million gallons, or 24,528 bbls, of additional butane for
Table 1 and 1.66 million gallons, or 39,499 bbls for Table 2.
The average refinery's additional butane production was calculated using an average
refinery gasoline production of 70,724 BPSD and assuming a 1.5 volume percent butane reduction
for every 1.0 psi RVP reduction. The average refinery's gasoline production was calculated by
Gary, James and Handwerk, Glenn. Petroleum Refining Technology and Economics, 1992.
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multiplying the average refinery gasoline production of 62,866 BPSD for PADDs 1 through 3 in
2000 by a factor of 1.125 to account for growth in gasoline production through 2006. Thus, for
Table 1, approximately 7 average refineries would need to build additional butane storage
capacity and for Table 2, approximately 17 average refineries would need to build additional
butane storage capacity.
Butane capital costs were scaled by a factor of approximately 1.1 to adjust capital prices to
year 2000 using a Marshall and Swift index of 993 for year 1992 and 1089 for year 2000.
Butane capital cost were also multiplied by an average refinery offsite factor of 1.11 and location
factor of 1.16 representative of PADDs 1 through 3. These factors, shown in Table 8, were used
to adjust capital costs to reflect the regional differences of costs for labor, location, etc. Average
factors were calculated based on the sum of each PADD's gasoline production fraction times each
PADD's respective factor. The offsite factor was cut in half to account for utilization of existing
offsite facilities at the refinery. Capital costs were then multiplied by a factor of 1.1 to account for
unknown contingencies in building the storage facilities to calculate final capital costs.
Table 8: Offsite and Location Factors Used for Estimating Capital Costs
Factor
Offsite
Location
PADD 1
1.25
1.5
PADD 2
1.25
1.3
PADD 3
1.2
1.0
PADDs 1-3
Average
1.22
1.16
Capital costs were amortized by multiplying the average refinery's capital cost by an
amortization factor of 0.11, then divided by the average refinery's gasoline production rate and
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divided by the time the storage facilities would be in service. Economic cost factors used to
calculate the amortization factor are shown in Table 9, and the storage facilities are assumed to be
in service only 168 days a year (168 days is the summer gasoline season). The amortized capital
cost for an April 15 terminal receipt date is 0.08 cent per gallon RFG for 315.6 million gallons
RFG and the amortized capital cost for an April 1 terminal receipt date is 0.12 cent per gallon
RFG for 738.6 million gallons RFG.
Table 9: Economic Cost Factors Used in Calculating the Capital Amortization Factor
Amortization
Scheme
Societal Cost
Depreciation
Life
10 Years
Economic
and Project
Life
15 Years
Federal and
State Tax
Rate
0%
Return on
Investment
(ROI)
7%
Resulting
Capital
Amortization
Factor
0.11
Interest cost for storing butane is 0.02 cent per gallon RFG for an April 15 terminal receipt
date and 0.04 cent per gallon RFG for an April 1 terminal receipt date. The stored butanes
gasoline blending value is reduced by 7.5 cents per gallon based on average price data from years
2000 and 2001 to account for summer/winter price changes in butane and RFG. This corrects for
the decreased economic benefit of blending butanes in gasoline in the winter. Multiplying the
stored butanes blending price adjustment by the total additional volume of butane removed and
dividing by the total volumes of RFG in Tables 1 and 2 produces a cost of 0.17 cent per gallon
RFG for an April 15 terminal receipt date and 0.28 cent per gallon RFG for an April 1 terminal
receipt date.
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Table 10 summarizes the costs of storing all additional butane production and blending it
in winter, in cents per gallon RFG for the total volumes in Tables 1 and 2.
Table 10: Cost summary for Storing and Blending Butane in Winter Gasoline, cents per
gallon RFG
Operating Cost
Capital Cost
Interest Cost
Downgrade Cost
Total
April 1 5 receipt date
0.21
0.08
0.02
0.17
0.49
April 1 receipt date
0.21
0.12
0.04
0.28
0.65
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VI. SIMPLIFY BLENDSTOCK ACCOUNTING REGULATION 40 CFR § 80.102
A. Background
1. Anti-Dumping Standards
Section 21 l(k) of the Clean Air Act (CAA or Act) directed EPA to establish standards for
RFG to be used in specified ozone nonattainment areas. The CAA also directed EPA to establish
regulations which require conventional gasoline (CG) used in the rest of the country to be as clean
as the gasoline produced or imported in 1990. CAA § 21 l(k)(8). The requirements for CG are
called the anti-dumping requirements. The regulations implementing the anti-dumping
requirements are contained in 40 CFR Subpart E.
RFG is formulated to produce relatively low levels of emissions compared to CG. The
anti-dumping regulations prevent a refinery from transferring, or "dumping," from RFG to CG
significant amounts of gasoline blendstocks, such as benzene, which produce relatively high
levels of emissions. That is, the anti-dumping regulations prevent CG from becoming higher in
emissions due to the extensive use of clean blendstocks in RFG.
To be in compliance with the anti-dumping regulations, the exhaust toxics and NOx
emissions performance of a refinery's or importer's CG production must be no "dirtier" than the
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refinery's or importer's 1990 exhaust toxics and NOx emissions performance, on an annual
average basis. Accordingly, the regulations require each refiner and importer of CG to establish
an individual baseline for exhaust toxics and NOx based on their 1990 gasoline production. 40
CFR § 80.91. This individual 1990 baseline is the refinery's or importer's anti-dumping
"standard."9 Exhaust toxics and NOx emissions of gasoline produced or imported during a given
annual averaging period, up to the refinery's or importer's 1990 production volume (baseline
volume), must be no dirtier than the refinery's or importer's 1990 baseline emissions.
The anti-dumping regulations provide that gasoline produced or imported during the
annual averaging period in excess of the refinery's or importer's baseline volumes, must be no
dirtier than the anti-dumping statutory baseline emissions for exhaust toxics and NOx. The anti-
dumping statutory baseline is an estimate of the average quality of gasoline sold in 1990
nationwide. Requiring compliance with the anti-dumping statutory baseline for gasoline
production or imports exceeding the refinery's or importer's 1990 baseline volume is intended to
prevent the overall emissions performance of the CG pool from deteriorating compared to the
average quality of 1990 gasoline. Refineries and importers who do not have the data necessary to
establish an individual 1990 baseline are required to comply with the anti-dumping statutory
baseline for exhaust toxics and NOx for all of their gasoline production or imports during each
annual averaging period.
C)
Refiners producing CG at several facilities have the option of meeting the antidumping standards on an
aggregate basis with an aggregated multi-refinery baseline. 40 CFR 80.101(h).
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When a refinery's or importer's annual gasoline volume (including RFG, CG and
reformulated gasoline blendstock for oxygenate blending, or RBOB) exceeds its 1990 baseline
volume, the regulations require the use of a specified "compliance baseline"equation. 40 CFR
80.101(f). This equation was intended to adjust the refinery's or importer's individual baseline
such that the volume of the refinery's or importer's total annual gasoline production or imports
which is in excess of the refinery's or importer's 1990 baseline volume would be subject to the
anti-dumping statutory baseline rather than the refinery's or importer's individual baseline. This
adjusted compliance baseline then is the refinery's or importer's anti-dumping "standard" for that
annual averaging period, and the total volume of conventional gasoline produced or imported by
that refinery or importer during the annual averaging period must meet that average standard.
2. Blendstock Accounting Requirements
In certain situations, refiners and importers are required to account for blendstocks that
they produce (or import) and transfer. 40 CFR § 80.102. Because some refineries have baselines
with much lower emissions than the 1990 average ("cleaner" baselines), and some have baselines
much higher than the 1990 average ("dirtier" baselines), there were concerns that refineries with
cleaner baselines would have an incentive to transfer dirty blendstocks to refineries with dirtier
baselines, since these refineries would be better able to absorb dirty blendstocks for purposes of
anti-dumping compliance. A refinery with a cleaner baseline could, in effect, transfer the
"production" of gasoline to a refining facility with a dirtier baseline through the transfer of
blendstocks, and thereby comply with a less stringent baseline for the gasoline produced at the
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refinery. For example, a refinery with a baseline cleaner than the statutory baseline could
establish a blending facility as a new business, which would be subject to the anti-dumping
statutory baseline, and transfer its blendstocks to the new facility to be blended into finished
gasoline. The new business would be acting as a new refinery and the finished gasoline at this
terminal refining facility would then be subject to the less stringent anti-dumping statutory
baseline.
To ensure that each refinery meets the anti-dumping standards using the baseline that
properly applies to the refinery, EPA included in the anti-dumping regulations provisions for
tracking and accounting for certain blendstocks, called "applicable blendstocks."10 Under these
blendstock accounting provisions, refineries and importers are required to establish a baseline of
the volume of applicable blendstocks produced or imported and transferred to other facilities
relative to the volume of gasoline produced or imported. This is called the "blendstock-to-
gasoline ratio." A refinery or importer establishes its baseline blendstock-to-gasoline ratio by
determining the volume of gasoline produced or imported and the volume of applicable
blendstocks produced or imported and transferred during each calendar year 1990 through 1993,
Applicable blendstocks are blendstocks that have properties that are "dirtier" than the 1990 CAA anti-
dumping average fuel parameters. These blendstocks include reformate, light coker naphtha, FCC naphtha,
benzene/toluene/xylene, pyrolysis gas, aromatics, polygasoline, and dimate.
Certain applicable blendstocks are exempted from the blendstock tracking and accounting requirements.
Exempted blendstocks include those that are: exported; used for other than gasoline blending purposes;
transferred to a refinery that uses the blendstock as "feedstock" in a refining process during which the
blendstock undergoes a substantial chemical or physical transformation; transferred between refineries that
are aggregated under § 80.101(h) for purposes of anti-dumping compliance; and used to produce California
gasoline as defined in § 80.81(a)(2). These blendstocks are exempted from the blendstock requirements
because transfers of such blendstocks would not be indicative of an attempt by a refiner to circumvent the
anti-dumping requirements.
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and calculating the annual and four-year average blendstock-to-gasoline ratios. Refineries and
importers also determine a blendstock-to-gasoline ratio for each annual compliance period, and a
running cumulative four-year average of the annual ratios, which is then compared to the baseline
ratio. If the running cumulative compliance period ratio exceeds the baseline ratio by ten percent
or more, the refinery or importer must include the volume and properties of all blendstocks it
produces (or imports) and transfers in its anti-dumping compliance calculations for the
subsequent two annual averaging periods. The refinery or importer also must notify any recipients
of the blendstocks that the blendstocks have been accounted for, and the recipient must exclude
those blendstocks from its compliance calculations. If the ten percent threshold is again exceeded
in a subsequent year, blendstock accounting is required for four years following the subsequent
exceedance.
In addition to the criterion discussed in the previous paragraph, there are certain situations
in which the blendstock accounting requirements do not apply. The requirements do not apply in
the case of a refinery or importer whose averaging period blendstock-to-gasoline ratio is equal to
or less than 0.0300. This exemption was included because of the limited environmental effects
and economic advantage that would result where small amounts of blendstock are transferred.11
The blendstock accounting requirements also do not apply in the case of a refinery or
importer whose 1990 baseline values for exhaust toxics and NOx are less stringent than the anti-
The regulations also provide that EPA may grant a waiver of the blendstock accounting requirements if the
level of blendstock production was the result of extreme or unusual circumstances (e.g., a natural disaster or
act of God). §80.102(f)(2)((i).
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dumping statutory baseline values for these emissions.12 (However, if the refinery's or importer's
1990 baseline value for either exhaust toxics or NOx is more stringent than the anti-dumping
statutory baseline value for that emissions performance, the refinery or importer is not exempt
from the blendstock tracking and accounting requirements.) This exemption was included in the
regulations because a refiner would have little or no incentive to transfer blendstocks where the
refinery's 1990 baseline is less stringent than the anti-dumping statutory baseline. A refinery with
a baseline less stringent than the anti-dumping statutory baseline could not circumvent the anti-
dumping requirements by shifting blendstocks to a refinery with the more stringent anti-dumping
statutory baseline. A refinery with a baseline less stringent than the anti-dumping statutory
baseline also would likely be unable to circumvent the anti-dumping requirements by shifting
blendstock to a refinery with an even less stringent baseline, because the volume of gasoline that
may be produced against a refinery's individual baseline is limited to that refinery's 1990 baseline
volume. Gasoline produced in excess of the refinery's 1990 volume is measured against the anti-
dumping statutory baseline. As a result, if blendstocks are shifted by one refinery to another
refinery with a more lenient baseline, the shifted blendstock would likely have to meet the more
stringent anti-dumping statutory baseline emissions standards.
B. Discussion
In a Question and Answer Guidance document dated May 9, 1995, EPA extended this exemption to
refineries and importers whose 1990 baseline values for exhaust toxics and NOx are equal to, as well as less
stringent than, the anti-dumping statutory baseline values for exhaust toxics and NOx. This approach is
reflected in today's proposed changes to the regulations in determining which parties may be affected by the
much more limited applicability of the petition procedures described below.
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In order to more fully understand how blendstock transfers could result in degradation of
conventional gasoline quality it is necessary to consider the concept of compliance baselines. The
complex model standards applicable to conventional gasoline require that annual average levels of
exhaust toxics emissions and NOx emissions, weighted by volume for each batch shall not
exceed the refiner's or importer's compliance baseline for exhaust toxics and NOx emissions,
respectively. The compliance baseline for each emissions performance standard (CB;) is
currently defined by the following equation:13
Equation 1
(1)
B; is the refiner's or importer's individual baseline value, representing the emissions of that
refiner or importer's gasoline in 1990. DB; is the 1990 statutory baseline, the emissions of a fuel
formulation specified in the Clean Air Act. V1990 is the refiner's or importer's 1990 baseline
volume and Va is the refiner's or importer's total volume produced or imported during the
averaging period (i.e., the total CG and RFG volume).14
13 See40CFR80.101(f)
14 See 40 CFR 80.102(f) for the precise regulatory definition of these terms.
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This equation applies only when a refiner or importer's total volume is greater than its
1990 baseline volume. If the total volume is less than or equal to the 1990 baseline volume the
compliance baseline is equal to the refiner's individual baseline.
To illustrate this, consider a hypothetical case in which a refiner has a 1990 baseline
volume of 10 gallons, and currently produces only CG. If this refiner produces 10 or fewer
gallons of gasoline, the compliance baseline is equal to the refiner's individual baseline. Thus, if
the refiner produces each of these gallons with an emissions performance exactly equal to this
individual baseline, the refiner's average would be exactly equal to the compliance baseline. If
the refiner produced any more than 10 gallons, the compliance baseline is determined by the
above equation. If the refiner produced 10 gallons with an emissions performance equal to its
individual baseline and each additional gallon with an emissions performance equal to the
statutory baseline, the refiner's volume weighted average performance would be always exactly
equal to the compliance baseline determined by the above equation. For example, if this refiner
produced 15 gallons of gasoline with 10 gallons at the individual baseline and 5 gallons at the
statutory baseline, the volume weighted average would be equal to (B^lO+DB^syiS. This is
exactly equal to the compliance baseline described in equation (1). Substituting 10 gallons for
V1990 and 15 gallons for Va in the compliance baseline equation demonstrates that the compliance
equation reduces to the volume weighted average for this case:
15 15 15
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As described above, refiners comply with anti-dumping standards by meeting an
individual baseline for volumes up to 1990 production levels but, for production levels over 1990
levels, meet a different compliance baseline based upon a combination of an individual baseline
and the statutory baseline. As shown in the previous example, a "CG only" refiner's current
production volume relative to its 1990 baseline volume determines whether it can produce
incremental volume of gasoline at its individual baseline or at the statutory baseline. If both the
refinery that transfers the blendstock and the refinery that receives the blendstock are meeting the
statutory baseline for incremental volumes of additional CG, then it would appear that no
economic or compliance benefit may be accrued from shifting blendstocks from a clean refinery
to a dirty refinery. Additionally, since all refineries are today producing substantially more
gasoline than produced in 1990, it appears that most refineries would gain little compliance
advantage by blendstock transfers. However, as is explained below, the situation is somewhat
more complicated, at least for refiners producing both CG and RFG, because of the equivalent CG
volume concept found in the compliance baseline equation (1).
In addition to total production volume relative to 1990 baseline production, we have found
that whether a refinery produces only CG or a combination of CG and RFG also plays a key role
in determining if a compliance advantage may occur with the transfer of blendstocks from a clean
refinery to a dirty refinery. To illustrate both of these factors, we look at several different
scenarios described below.
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1. Case 1: Both Refiners Produce Less Gasoline than in 1990
Take the case where both the transferring refiner and the receiving refiner are producing
yearly gasoline volumes less than 1990 baseline volumes. If blendstocks are transferred from the
"clean" refinery to the "dirty" refinery, this could result in increases in the overall average
emission level of their combined CG production. For example, a one gallon transfer from the
"clean" to the "dirty" refinery could allow the "clean" refinery to produce one less gallon at its
individual cleaner baseline and the "dirty" refinery to produce one more gallon at its individual
dirtier baseline. This is the classic blendstock accounting situation which the regulations were
meant to prevent and which results in the most significant compliance or "gaming" advantage.
However, EPA's data indicated that all refineries are currently producing more gasoline than in
1990, with the vast majority producing considerably more.15 Thus, the situation described in
Case 1 does not now exist in the normal course of refinery operations.
2. Case 2: Both Refiners Produce Only CG and One Refiner Produces Less CG than in
1990
Another case is where the clean refiner is producing a yearly gasoline volume less than its
1990 baseline volume and the dirty refiner is producing a gasoline volume greater than its 1990
baseline volume and both refiners produce only CG. If blendstocks are transferred from the
"clean" refinery to the "dirty" refinery, this could result in increases in the overall average
Detailed refinery production data are collected as a requirement of 40 CFR 80.75 and 40 CFR 80.105 and are
confidential business information.
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emission level of their combined CG production. For example, a one gallon transfer from the
"clean" to the "dirty" refinery could allow the "clean" refinery to produce one less gallon at its
individual baseline and the "dirty" refinery to produce one more gallon at the statutory baseline.
In the case where the clean refinery is producing a yearly gasoline volume more than its 1990
baseline volume and the dirty refiner is producing a gasoline volume less than its 1990 baseline
volume, the transfer would allow the "clean" refiner to produce one less gallon at the statutory
baseline and the "dirty" refiner to produce one more gallon at its individual baseline. Thus, when
either of the two refineries is producing less CG than it produced in 1990, an overall degradation
of gasoline quality can result. Because the vast majority of refineries are producing considerably
more gasoline than they were in 1990, however, we would expect that the scenario described here
in Case 2 is unlikely to occur in the real world.
3. Case 3: Both Refiners Produce only CG and Both Produce More CG than in 1990
Any pair of "CG only" refineries that could conceivably exchange blendstocks would both
be operating well into the range where each produces more CG than in 1990 and additional
increments of CG produced in the case of either refiner would be produced at the statutory
baseline. This would result in a decrease in one refiner's CG volume produced at the statutory
baseline offset by an equal increase in the other refiner's volume produced at the statutory
baseline; i.e. there would be no net effect on the overall average CG quality for the two refiners
together and no net compliance advantage in transferring the blendstocks.
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4. Case 4: One or Both Refiners Produce CG and RFG and Produce More Gasoline
(CG+RFG) than in 1990
The situation becomes more complex when one or both refiners also produce RFG. This
results from the calculation of the compliance baseline. It can best be understood by considering
the origin of, and rationale for the compliance baseline equation and the concept of equivalent CG
volume.
It was EPA's intent that the refiner's individual baseline would apply to all CG production
except for the growth in production which was allocatedio CG.16 This calculated growth in CG
production would have to meet the statutory baseline. Consequently, EPA initially developed the
following equation to define the compliance baseline: 17
Equation 2
Vc
In this equation CB;, B; and DB; are as defined as in equation 1. Vc is the refiner's CG production
for the averaging period. Veq is the 1990 equivalent CG volume. For a refiner currently
producing both CG and RFG, this equivalent volume represents, in effect, the amount of CG that
the refiner would have made in 1990 had the refiner been producing both CG and RFG. Such a
16 57 FR 13481 (April 16, 1992)
17 59 FR 7871 (February 16, 1994)
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value is only hypothetical and thus must be calculated. Once calculated, the amount of CG
produced up to the equivalent volume would be subject to the refiner's individual baseline, while
that produced over the equivalent volume (i.e., the growth in production allocated to CG) would
be subject to the statutory baseline. Thus, equation 2 represents a volume weighted baseline made
up of the individual baseline weighted by the equivalent volume and the statutory baseline
weighted by the allocated growth in CG production.
EPA's regulation provided a method for calculating the equivalent CG volume or CG that
would have been produced in 1990 ifRFGwas also being produced. This hypothetical 1990 CG
production is back-calculated by first calculating a hypothetical growth in CG production. The
hypothetical growth in production attributed to CG is taken as a portion of total growth in gasoline
production ((Vr+Vc)-V1990) using the ratio of current CG production to current total production
(Vc/(Vr+Vc)). This hypothetical growth in CG production is then subtracted from the current
actual CG production to determine the hypothetical 1990 CG production or equivalent volume.
The formula is as follows:
Equation 3
° (3)
.
\V r + V c)
where Vr is the volume of RFG made during the averaging period. Thus Veq, the estimate of how
much CG that a "CG and RFG" refiner would have made in 1990 depends on the amount of CG
and RFG made during the current averaging period (Vc and Vr). In other words, to exactly
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maintain compliance for any volume of CG produced, such a refiner could not make a fixed
volume of CG at the individual baseline and every additional gallon at the statutory baseline
because the equivalent volume of CG (Veq) changes with each additional gallon of gasoline made.
EPA's current regulations do not require the direct calculation of Veq in order to calculate the
compliance baseline because the separate formulas for CB; and Veq (equations 2 and 3) were
combined into a single simpler formula (equation I).18 However, since this formula is
mathematically identical, the idea of equivalent volume is built into the current regulation.
To illustrate the above concept, consider a refiner with a 1990 baseline volume of 10
gallons, who makes 6 gallons of RFG during the current averaging period. (Table 11, which
follows, summarizes this example.) For simplicity, assume that this "clean" refiner has an
individual baseline value of 0.8 emission units for an emissions performance standard, where 1.0
is the statutory baseline. The refiner could make 4 gallons of CG at its individual baseline and
maintain compliance. If the refiner makes a 5th gallon of CG (plus 6 gallons of RFG so that total
production volume is 11 gallons), the compliance baseline calculated from equation 1 would be
0.8*10/11+1.0*(1/11)=0.818 emission units. For the refiner to maintain an average performance
of 0.818 for the 5 gallons of CG, the performance of the fifth gallon would have to be at 0.891
emission units (i.e, 0.818=(0.8*4+0.891)75). If the refiner makes a sixth gallon of CG (i.e. 12
gallons total), the compliance baseline from equation 1 would be 0.833 emission units. To
18 59 FR 36954 (July 20, 1994)
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maintain an average performance of 0.833 for the 6 gallons of CG (with 4 gallons at 0.8 and 1
gallon at 0.891), the performance of the sixth gallon would have to be at 0.909 emission units.
As the refiner makes more and more CG, the emissions performance of the last CG gallon
approaches the statutory baseline but will always, in theory, be cleaner than the statutory baseline.
In reality, the required performance of the last CG gallon would be indistinguishably close to the
statutory baseline as the production gets much larger than the 1990 baseline volume.
A similar situation occurs if a refiner has an individual baseline above the statutory
baseline. If a "dirty" refiner with an individual baseline of 1.2 emission units had a 1990 baseline
volume of 10 gallons and made 6 gallons of RFG, it could make 4 gallons of CG at its individual
baseline and maintain compliance. Again, the required performance of each succeeding CG
gallon more closely approaches the statutory baseline. Each succeeding gallon could, in theory,
still be dirtier than the statutory baseline, but would become indistinguishably close to the
statutory baseline as production volume gets large.
The relationships described in the preceding paragraphs can be seen more clearly in the
following table which shows the compliance baseline and quality of the last (incremental) CG
gallon for these two hypothetical refiners over a total production volume ranging from 10 gallons
to 20 gallons (100 to 200 percent of 1990 volume):
Table 11: Effect of Additional Gallons of CG Production on Compliance Baseline
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Total
Gallons
10
11
12
13
14
15
16
17
18
19
20
Total
RFC
Gallons
6
6
6
6
6
6
6
6
6
6
6
Total CG
Gallons
4
5
6
7
8
9
10
11
12
13
14
Gallons
Over 1990
Baseline
0
1
2
3
4
5
6
7
8
9
10
Clean Refiner
Compliance
Baseline
0.800
0.818
0.833
0.846
0.857
0.867
0.875
0.882
0.889
0.895
0.900
Quality Needed
for Last Gallon
0.800
0.891
0.909
0.923
0.934
0.943
0.950
0.956
0.961
0.965
0.968
Dirty Refiner
Compliance
Baseline
1.200
1.182
1.167
1.154
1.143
1.133
1.125
1.118
1.111
1.105
1.100
Quality Needed
for Last Gallon
1.200
1.109
1.091
1.077
1.066
1.057
1.050
1.044
1.039
1.035
1.032
Thus, each gallon of additional CG produced by an "RFG and CG" refiner with a clean
baseline must be slightly cleaner than the statutory baseline. And for a refiner in this same
situation but with a dirty baseline, incremental gallons of CG can be slightly dirtier than baseline.
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Thus, for refiners making RFG but also making more total gasoline than 1990, a blendstock
transfer from a clean refiner to a "dirty" refiner does not necessarily result in "no net change" in
emissions as is the case when the refiners are making only CG. Instead, blendstock transfers from
a "clean" refiner to a "dirty" refiner may have slightly greater potential to degrade their combined
average CG quality if one or both of these refiners makes RFG as well as CG. If production
volumes for the vast majority of refiners are significantly larger than 1990 baseline volumes, such
transfers result in little potential for gaming and any economic benefit resulting from a transfer of
blendstock in order to meet a less stringent baseline would be very small when compared to the
risks associated with the illegality of the activity19 and the logistical and transact!onal costs
associated with such activity.
Currently, transfers from a "clean" to a "dirty" refiner would be subject to blendstock
accounting requirements if the criteria specified in 40 CFR 80.102 are met. These blendstock
accounting requirements are intended to mitigate the effects of blendstock transfers that might
result in degradation of CG quality and to deter refiners from agreeing to transfer blendstocks in
order to produce a combined pool of CG of poorer quality at lower cost (i.e. "gaming the
system").
In conclusion, EPA now believes that the current blendstock accounting requirements are
unnecessary. When refineries produce more total gasoline than that produced in 1990, the
19 It is important to note that today's proposal would still prohibit blendstock transfers conducted in
order to meet less stringent standards ("gaming") even though the specific blendstock accounting
requirements currently found in 40 CFR 80.102 would be eliminated. This prohibition would be
applicable to all refiners/importers without regard to any other criteria.
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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.20 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
transact!onal 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.
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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