specifically after 2020.  This approach meant that the ABT program
modeling did not consider the impact on gasoline sulfur levels of
delayed compliance for small refiners and small volume refineries, nor
did it consider the generation and use of any early sulfur credits.
Moreover, our ABT modeling considered only gasoline sold for use outside
of California, and only gasoline produced by domestic refineries (not
imports).

Since the cost information available for this NPRM was limited to the
costs of reducing sulfur to either 10 ppm or 5 ppm (under which FCC
gasoline sulfur levels would be reduced to either 25 or 10 ppm,
respectively), we were not able to estimate refinery-specific costs of
reducing sulfur to other levels.  As a result, our ABT modeling could
not account for scenarios in which a refinery makes some capital
investments to lower sulfur to some interim level, such as 20 ppm, and
then obtains credits in order to demonstrate compliance with the 10-ppm
standard.  Our ABT analysis also could not account for credit generation
at sulfur levels other than 5 ppm.  Our ABT analysis, then, most likely
underestimates the cost savings that could occur due to ABT since the
greatest efficiencies are achieved when every refinery has the option of
using any combination of capital investments and credits generation or
use.  For the final rule, we may investigate methods for expanding our
ABT analysis to examine these types of scenarios.

We evaluated two ABT scenarios designed to bound the likely outcomes.
In the first scenario, we assumed perfect nationwide credit trading in
which all credit generators make their credits available to any refinery
that needs them, regardless of their ownership.  As described in Section
V.E.1 of the preamble, the proposed ABT program is designed such that it
could operate in this way.  However, such perfect nationwide trading may
not be realistic.  Under Tier 2 today, there is still a considerable
amount of inter-company trading occurring, but a significant fraction of
Tier 2 sulfur credits are bought and sold within companies.  Under Tier
3, it will be more difficult to generate credits, and also more
difficult to make up for deficits.  Consequently, we also investigated a
second ABT scenario in which trading between companies does not occur
and averaging would only occur within companies that own more than one
refinery.  Under this second scenario, individual companies might decide
to bank credits for their own use, declining to make credits that they
generate at one of their facilities available to other companies.  They
might do this, for instance, to address unplanned equipment downtime or
other circumstances that could make future compliance more difficult.
While we do anticipate some trading to occur between companies, we
believe that this second, more limited scenario more closely represents
how our proposed ABT program might actually operate.  As a result, the
within-company credit trading scenario is the primary scenario that we
used to estimate overall costs for our proposed program.  It represents
a somewhat conservative scenario with respect to estimation of costs.
The results of both scenarios are described in Sections   REF
_Ref308083693 \w  <IP_ADDRESS>  and   REF _Ref308083698 \w  <IP_ADDRESS>  below.

Since an ABT program would allow some refineries to continue producing
gasoline with an average sulfur level above 10 ppm, we also investigated
whether any areas of the country might experience inordinately high
sulfur levels as a result, and if so whether those higher sulfur levels
might be problematic in terms of either vehicle performance or local air
quality.  While we were not able to model the distribution of all
gasoline from the point of production to the point of consumption, we
did compare average sulfur levels at each refinery's location to the
location of nearby ozone nonattainment areas (based on the designation
status with respect to the 1997 ozone NAAQS).  A discussion of our
analysis of sulfur levels by refinery and location can be found in
Section 5.2.1 below.

Estimated Tier 3 Sulfur Control Costs

Sulfur Cost Results

Cost of the Sulfur Program without ABT

Without ABT, all refineries would be required to meet the 10-ppm annual
average sulfur standard.  We estimate that 13 refineries are already at
or below 10 ppm, and thus their costs of compliance would be zero.  The
remaining refineries would incur ¢/gal costs at various levels
depending on their particular configurations and the steps they would
need to take.  While we estimate that the nationwide average cost of
compliance would be 0.97 ¢/gal under this scenario, two refineries
would incur costs above 6 ¢/gal.  The distribution of costs is shown in
  REF _Ref308083854  Figure 5-1  as a function of the number of
refineries.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  1  Distribution
of Compliance Costs by Refinery for 10 ppm without ABT Program

In order to enable evaluation of the costs of the program with ABT, we
also needed to estimate the costs for each refiner to reach 5 ppm.  The
distribution of costs for this scenario is shown below.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  2  Distribution
of Compliance Costs by Refinery for 5 ppm without ABT Program

Cost of Sulfur Control Program with ABT

Under a scenario in which credit trading only occurs between refineries
within the same company, we determined that about 23 percent of
refineries would be involved in either generating or consuming credits.
  REF _Ref308084037  Table 5-33  summarizes our estimate of the amount
of credit trading that would occur under this scenario.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  33  Impacts of ABT
Program with Intra-Company Credit Transfers

Number of refineries whose sulfur is already below 10 ppm, and which
generate creditsa	3

Number of refineries which lower their sulfur to 5 ppm and generate
credits	15

Number of refineries that do not lower their sulfur but instead consume
credits	8

Number of refineries that lower sulfur to 10 ppm and neither generate
nor consume credits	85

a Additional refineries also have sulfur levels below 10 ppm, but do not
generate credits under this scenario.

The nationwide average cost of compliance with the 10-ppm sulfur
standard would be reduced from 0.97 ¢/gal without ABT to 0.89 ¢/gal
under company-only trading.  However, there would continue to be a
significant variation in costs by refinery as illustrated in   REF
_Ref308084154  Figure 5-3 .

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  3  Distribution
of Compliance Costs by Refinery for 10-ppm Average Standard with ABT
Program and Intra-Company Credit Transfers

 In this figure, refineries with negative costs are those whose sulfur
levels were already below 10 ppm and who would generate and sell
credits.  While there are several refineries with costs above 3 ¢/gal
in this scenario, in practice we would expect such refineries to incur
lower costs by pursuing some combination of lowering their gasoline
sulfur to some level above 10 ppm and also purchasing credits to cover
the remaining sulfur reductions needed to reach 10 ppm.  The analysis we
conducted for this draft RIA was unable to capture such nuances, but we
will be investigating them for the final rule.

  REF _Ref308084237  Figure 5-4  illustrates how the cumulative
distribution of costs by volume would change under this scenario.  In
general, the distribution would shift downward slightly in comparison to
a scenario in which there was a 10 ppm average standard but no ABT
program.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  4  Distribution
of Costs by Volume for 10-ppm Average Standard with ABT Program and
Intra-Company Credit Transfers

Since we estimate that 85 out of 111 refineries would meet the 10-ppm
sulfur standard without the use of credits under the intra-company
trading scenario, only about 5 percent of gasoline would continue to
have an annual average sulfur level above 10 ppm.  These refineries tend
to be smaller than average.  The distribution of sulfur levels under
this scenario is shown in   REF _Ref308084298  Figure 5-5 .

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  5  Distribution
of Sulfur Levels by Refinery with ABT Program and Intra-Company Credit
Transfers

Of the 5 percent of gasoline volume that would have average sulfur
levels above 10 ppm under this scenario, nearly half would be below 20
ppm, and a majority would be below 30 ppm.  Moreover, as noted above, we
would expect refineries with the highest sulfur levels to pursue some
combination of lowering their gasoline sulfur to some level above 10 ppm
and also purchasing credits to cover the remaining sulfur reductions
needed to attain the 10-ppm standard.

We also investigated whether the existence of refineries producing
gasoline with average sulfur levels higher than 10 ppm after 2020 might
contribute to local areas where the average sulfur level is higher than
10 ppm, and whether this might be problematic in terms of either vehicle
performance/emissions or local air quality.  To do this, we compared the
location of refineries with sulfur levels higher than 10 ppm to the
location of other refineries serving similar areas.  We also compared
the location of refineries to areas that have historically been in
nonattainment for ozone.

As shown above in   REF _Ref308084037  Table 5-33 , we estimated that
eight refineries would have annual average sulfur levels above 10 ppm
under company-only credit trading.  Three of these refineries serve
areas that are, at a minimum, several hundred miles away from historical
ozone nonattainment areas.  The remaining five refineries with average
sulfur levels above 10 ppm supply areas that are also supplied by other
refineries whose average sulfur levels would be 10 ppm or lower.  As a
result, gasoline with higher sulfur levels would likely be diluted by
gasoline with lower sulfur levels, and we would not expect any ozone
non-attainment area to receive gasoline with an average sulfur level
higher than 20 ppm.

Cost of Sulfur Control Program with ABT and Nationwide Credit Transfers

Although we believe that credit trading will occur primarily between
refineries within the same company, we also investigated a scenario in
which credit transfers would occur between all refineries regardless of
location or company.  For this scenario, we determined that more than 60
percent of refineries would be involved in either generating or
consuming credits.    REF _Ref308084524  Table 5-34  summarizes our
estimate of the amount of credit trading that would occur under this
scenario.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  34  Impacts of ABT
Program with Nationwide Credit Transfers

Number of refineries whose sulfur is already below 10 ppm, and which
generate credits	12

Number of refineries which lower their sulfur to 5 ppm and generate
credits	34

Number of refineries that do not lower their sulfur but instead consume
credits	25

Number of refineries that lower sulfur to 10 ppm and neither generate
nor consume credits	40

The nationwide average cost of compliance with the 10-ppm sulfur
standard would be reduced from 0.97 ¢/gal without any ABT program to
0.79 ¢/gal under nationwide trading.  There would continue to be some
variation in costs by refinery as illustrated in   REF _Ref308084621
Figure 5-6 , though the distribution would not be as wide as under the
intra-company credit transfer scenario.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  6  Distribution
of Refinery Compliance Costs with ABT Program and Nationwide Credit
Transfers

  REF _Ref308084678  Figure 5-7  illustrates how the cumulative
distribution of costs by volume would change under this scenario.  In
comparison to a scenario wherein credit trading occurs only between
refineries within the same company, the downward shift in the
distribution would be more pronounced.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  7  Distribution
of Compliance Costs by Volume with ABT Program and Nationwide Credit
Transfers

Under a scenario in which credit transfers occur nationwide, we estimate
that 25 out of 111 refineries, or about 23 percent, would not lower
their sulfur levels and would instead obtain credits.  These refineries
tend to be smaller than average, and represent about 17 percent of
gasoline volume.  The distribution of sulfur levels under this scenario
is shown in   REF _Ref308084748  Figure 5-8 .

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  8  Distribution
of Sulfur Levels by Refinery with ABT Program and Nationwide Credit
Transfers

Of the 17 percent of gasoline volume that would have average sulfur
levels above 10 ppm under this scenario, the vast majority would be
below 30 ppm.

As for the previous scenario under which credit transfers would occur
only within companies, we investigated the localized impact of higher
sulfur levels under a scenario in which credit transfers occur
nationwide and thus there are more refineries with average sulfur levels
above 10 ppm.  Under this scenario, most refineries with average sulfur
levels higher than 10 ppm supply areas that are also supplied by
refineries with sulfur levels at 10 ppm or below.  We expect the
dilution of higher sulfur with lower sulfur in such areas to result in
annual average sulfur levels no higher than about 20 ppm.  Of those
refineries projected to have average sulfur levels higher than 10 ppm
under this scenario and which are the primary or only suppliers of
gasoline to a particular area, none of the affected areas have
historically been in nonattainment for ozone.

Other Cost Studies

Other other cost studies were recently conducted to estimate the cost of
additional reduction in gasoline sulfur.  We evaluated each of these
studies and compare them to our own cost analysis.

The International Council for Clean Transportation (ICCT) retained
Mathpro in October 2011 to study the cost of a 10 ppm average gasoline
sulfur standard as well as a 1 psi reduction in RVP.  Since the lower
RVP standard was modeled as a separate step from the low sulfur
standard, we were able to isolate the gasoline sulfur reduction costs
from the low RVP costs.

ICCT’s estimated cost for a 10 ppm average gasoline sulfur standard is
0.8 cents per gallon which reflects the capital costs amortized assuming
a before-tax 7 percent rate of return on investment.  This cost reflects
an assumption that the capital cost for revamps of FCC postreaters is 30
percent of the capital costs for a grassroots FCC postreater .  Mathpro
also analyzed costs assuming that the capital cost for revamps of FCC
postreaters are 50 percent of a grassroots FCC postreaters, which is 1.1
cents per gallon.  ICCT’s cost estimate for complying with a 10 ppm
average gasoline sulfur standard is very close to ours.

In 2008 The Alliance retained Mathpro to use its LP refinery cost model
to estimate the costs of what they termed National Clean Gasoline (NCG)
in PADDs 1, 2 and 3 (generally speaking, this is the part of the U.S.
east of the Rocky Mountains).  Achieving NCG would entail reducing
gasoline sulfur to 5 ppm under a 10-ppm cap standard and the reduction
of gasoline RVP to 7 psi.  For the low-RVP standard, a 1-psi waiver was
allowed for conventional gasoline, but not for current low-RVP areas.
The study also evaluated two sensitivity cases which increases the
stringency of the distillation index (DI) from 1250 to 1200.  The
Alliance study also evaluated crude oil price as a second sensitivity
case, evaluating crude oil prices at $51 /bbl and $125/bbl.

The Alliance studied three different cases.  The first case applied the
10-ppm sulfur cap to RFG.  The second case applied the 10-ppm sulfur cap
and the 7.0-psi low-RVP standard to RFG as well as 7.0- and 7.8-psi
low-RVP gasoline.  The third case applies the 10-ppm sulfur cap and
7.0-psi RVP standard to all RFG and CG.  Of these three cases, the first
case is most relevant because applying the fuels changes to RFG solely
applies the 10-ppm sulfur cap to RFG and does not involve any changes in
RVP.  However, the 10-ppm sulfur cap standard studied by the Alliance is
still 5 ppm more stringent than the 10-ppm average standard that we are
proposing.

The Alliance cost estimate for Case 1 is 1.6 cents per gallon for RFG in
PADDs 1, 2 and 3.  This cost estimate is based on amortizing the capital
costs on a 10 percent after-tax return on investment (ROI).  We adjusted
the cost estimate to amortize the capital costs based on a before tax 7
percent ROI and adjusted the costs to 2010 dollars which increases the
costs to 1.75 cents per gallon.  The 1.75 ¢/gal cost estimate is based
on a crude oil price of $51/bbl.  The Alliance estimated the cost of a
10-ppm sulfur cap standard on RFG assuming that crude oil is priced at
$125/bbl.  At the $125/bbl crude oil price, the Alliance study estimates
that it costs 2.50 ¢/gal to require that RFG comply with a 10-ppm
sulfur cap standard.  Adjusting the Alliance costs to reflect a 7
percent before tax ROI and 2010 dollars increases the Alliance costs
based on a $125/bbl crude oil price to 2.69 ¢/gal.

For our cost analysis we analyzed the cost of sulfur control assuming
that crude oil is priced at $91.8/bbl.  We can interpolate between the
Alliance costs based on $51 and $125 per barrel crude oil prices, which
results in a single cost which is 2.3 cents per gallon.  We also
estimated a cost for refiners lowering their gasoline sulfur to 5 ppm
using the refinery-by-refinery cost model and our cost is 1.38 ¢/gal.

In response to the Alliance study, API retained Baker and O’Brien
(BOB) in 2010 to study the cost of additional gasoline sulfur control
and an increase in RVP using a refinery-by-refinery cost approach with
BOB’s Prism model.  The Prism model is largely a spreadsheet cost
model with blending optimization.  The primary case analyzed by the API
study is the cost of reducing gasoline sulfur to an average of 10 ppm
and reducing gasoline RVP to 7.0 psi without a 1-psi waiver for blending
10 percent ethanol.  The study also analyzed three other sensitivity
cases:  1) a 5-ppm average gasoline sulfur standard with 7 psi RVP limit
on conventional gasoline without a 1-psi waiver; 2) a 10-ppm average
gasoline sulfur standard and a 7.8-psi RVP limit on conventional
gasoline without a 1-psi waiver; and 3) a 10-ppm average gasoline sulfur
standard with a 7.8-psi RVP limit on all conventional gasoline with a
1-psi waiver.

In an addendum to its fuels study report released in 2011, API
contracted with Baker and O’Brien to study a sensitivity case 4, which
is a sulfur only case, using its PRISM refinery model.  From our
understanding of the study, the study parameters seemed to be about the
same as the original study, except that API solely studied a 10 ppm
average gasoline sulfur standard (not including any RVP control), the
same sulfur standard that we are proposing.  However, API also assumed
that a 20 ppm cap standard would also be in place which would not allow
the application of an averaging, banking and trading (ABT) program to
optimize refinery investments and minimize overall costs.

API made a series of conclusions based on the study.  Perhaps the most
important difference with the original study is that API concluded that
not a single refinery would shut down as a result of the proposed 10 ppm
gasoline sulfur control standard, even though API did not study the
flexibilities of an ABT program and used excessively high capital costs
for a grassroots FCC postreater (see below).  Like the original study,
API did not report average costs, but reported the marginal costs for
the cost study.  Marginal costs reflect the cost of the program to the
refinery or refineries which would incur the highest costs, assuming
that the highest cost refineries would set the price (or in this case,
the price increase) of gasoline.  The report concluded that marginal
costs after the imposition of a 10 ppm gasoline sulfur program would
increase the price of gasoline by 6 to 9 cents per gallon in most
markets.  API did not define how its statement “in most markets”
would apply to the US gasoline supply.  API also did not provide any
justification why it assumed that the refineries that would experience
the highest desulfurization cost under Tier 3 would also be the same
refineries which sets the gasoline price in the gasoline market today.

Although API did not provide an average gasoline desulfurization cost in
its report, we could calculate an average cost based on the gasoline
volume and total annual costs provided.  The total cost reported in the
report for the 10 ppm average gasoline sulfur standard is $2390MM/yr and
the non-California gasoline volume is 7343 thousand barrels per day.
This results in an average per-gallon desulfurization cost of $0.89/bbl
or 2.12 c/gal.  The difference between the average cost and marginal
cost (price increase) that API is projecting is profit.  API is
projecting that the oil industry would profit from 10 ppm low sulfur
standard by the roughly 4 to 7 cents per gallon difference between the
average cost and the two marginal price values.  That per-gallon profit
translates into $4 to $8 billion dollars per year in profit.

 The average cost of the 10 ppm average gasoline sulfur standard was
calculated using API’s methodology for amortizing capital investments.
 To facilitate a fairer comparison between the API cost study and our
cost study, we adjusted the API costs to be on a similar basis as our
costs.  We adjusted the API costs to reflect a before-tax 7 percent
return on investment (ROI) for capital invested for the hydrotreaters
and hydrogen plants instead of the after-tax 15 percent ROI used by API.
 This lowered the API estimated costs from 2.12 c/gal to 1.58 c/gal.
API’s 1.58 cents per gallon cost is still higher than our 0.89 c/gal
cost with an ABT program that assumes intercompany trading of credits,
and higher than our 0.97 c/gal for the case which assumes no ABT
program.  Thus comparing “apples-to-apples” to the to the extent
possible, API’s 1.58 c/gal estimated cost for complying with a 10 ppm
average gasoline sulfur standard compares very favorably with our own
cost estimates, and not at all near the 25 c/gal value that was
sometimes quoted from the first API study.  The remaining cost
difference between our estimated costs and those by API are the capital
cost assumptions that API used, as discussed below.  While little detail
is is provided by API about what hardware comprises their
desulfurization units, the inside battery limits (ISBL) and total
capital costs for the FCC postreaters and FCC pretreaters are provided
in API’s report.  API’s FCC pretreaters capital costs are consistent
with the capital costs that we have used for this unit.  However, the
FCC postreater costs used by API are much higher than what we used and
have been used in the past by others.  API’s capital cost for a
grassroots FCC postreater is $228 million for a 35,000 bbl/day unit, or
$6540 per/bbl per day.  API’s capital cost includes the outside
battery limit (OSBL) costs.  In contrast, the ISBL capital cost that we
used for a grassroots FCC postreater is $1500/bbl-day for a 30,000
bbl/day grassroots unit, which increases to $1875/bbl/day when the
offsite costs are added on.  Thus, the API capital costs are about 3 ½
times higher than the capital costs that we are using for a grassroots
FCC postreater.  To check our capital costs, we found other capital cost
estimates to which we could compare our costs, including the capital
costs used by the National Petroleum Council when it studied the cost of
gasoline desulfurization prior to Tier 2.    REF _Ref308540950  Table
5-35  contains a cost comparison of ISBL, and ISBL and OSBL FCC
postreater capital costs.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  35  Capital Cost
Comparison

Technology	EPA (Tier 3)	API	Mathpro (ICCT)	Jacobs	Exxon Scanfining (NPC)
IFP Prime G (NPC)	CDTech (NPC)	Phillips S-Zorb (NPC)

ISBL Capital Cost ($/bbl/day)	1500	-	-	2440	1045	1410	960	860

ISBL and OSBL Capital Cost ($/bbl/day)	1875	6540	1800	3538	1360	1833
1248	1118

  REF _Ref308540950  Table 5-35  shows that, compared to the average of
the rest of the capital cost estimates, the API capital cost for FCC
postreater is about four times higher.  Compared to the next highest
cost estimate, which is the FCC postreater capital cost from the Jacobs
data base in the Haverly refinery cost model that we use, the API
capital costs are almost two times higher.

An important distinction must be made with respect to the severity of
desulfurization for the capital cost comparison made in   REF
_Ref311717674 \h  Table 5-27 .  For complying with the Tier 2 gasoline
sulfur standard (Jacobs and NPC costs), a typical refinery would have
installed an FCC postreater to desulfurize the FCC naphtha from about
800 ppm down to about 75 ppm, a 725 ppm, or a 91 percent sulfur
reduction.  In the case of a grassroots postreater that would be
installed for Tier 3, the postreater would treat FCC naphtha already low
in sulfur due to the pretreater installed before the FCC unit (these
refineries are currently complying with Tier 2 using an FCC pretreater).
Thus, the new grassroots FCC postreater would only have to reduce the
FCC naphtha from 100 ppm to 25 ppm, a much smaller 75 ppm or 75 percent
sulfur reduction.  A grassroots FCC postreater installed for Tier 2
would typically remove 10 times more sulfur than one installed for Tier
3.  This is important because a significant portion of the FCC
postreater capital cost is devoted to avoiding the recombination
reactions which occur when hydrogen sulfide concentrations are high and
react with the olefins contained in the FCC naphtha.  Thus, a grassroots
FCC postreater installed for Tier 3 would be expected to be
significantly lower in capital cost compared to a Tier 2 FCC postreater.
 When API presented the costs to us, they stated that their grassroots
capital costs were based on an actual installation for the Tier 2
program.  This could be one reason why the capital costs used by API for
its cost study of the Tier 3 program are so high.  Another way to assess
the API capital cost for the FCC postreaters is to compare it to the FCC
pretreater cost that API is using.  FCC pretreaters are much higher
pressure units and use more expensive metallurgy than FCC postreaters
and, for these two reasons, are much more expensive than FCC postreaters
on a per-barrel basis.  However, API’s FCC postreater capital costs
are about 50 percent more expensive than its FCC pretreater capital
costs, which is inconsistent with the design requirements of the units.

API’s estimated range of capital cost for revamping an FCC postreater
is also higher than our range of capital cost for revamping an FCC
postreater, when assessing the revamped costs as a percentage of the
capital cost for a grassroots unit.  API estimates that revamping an FCC
postreater would cost 30 to 70 percent of the capital cost for a
grassroots FCC unit.  Our capital cost estimate for revamping an FCC
naphtha postreaters from 17 to 50 percent of the capital cost for a
grassroots FCC postreater, however, most of the revamps are estimated to
cost at the lower end of that range.

The Emissions Control Technology Association (ECTA) retained personnel
within Navigant Economics to study the costs of a 10 ppm average
gasoline sulfur standard and assess the ICCT and API cost studies.  The
authors made a number of conclusions.  After reviewing both the ICCT and
API studies, the authors found that a primary difference in estimated
costs between the two studies was the capital costs.  The authors
contacted vendor companies that license FCC postreater technologies and
surveyed the companies to find out what the capital costs are for a FCC
postreater.  As a result of the survey, the report authors concluded
that API’s capital costs were too high, and those used in the ICCT
study were about right.  The authors found that Baker and O’Brien has
a history of exaggerating the economic impacts of EPA rules, citing the
costs and other impacts of its analysis of the 2007 on-highway
heavy-duty proposed rulemaking.  The authors concluded that the impact
of a 10 ppm gasoline sulfur standard on the average refining cost would
likely be closer to the 1 cent per gallon estimate by the ICCT study.
Furthermore, the report’s authors also pointed out that the marginal
cost analysis conducted by API did not consider the proposed averaging
banking and trading (ABT) program that we were expected to propose,
which would reduce the marginal costs of the Tier 3 proposed rule.
Because API’s addendums to its original report came out many months
after its original report, we originally assessed the most similar case
to our proposal from API’s original study.  This was sensitivity case
3, which studied a 10-ppm average gasoline sulfur standard with a
7.8-psi RVP limit on all conventional gasoline with a 1-psi waiver.  One
of the most important conclusions by API with respect to sensitivity
case 3 was the projected 623 thousand barrels per day (about 6.5 percent
of total gasoline demand) reduction in U.S. gasoline production due to
reduced blending of light hydrocarbons in response to RVP control and
the closure of 4 refineries caused by the investment hurdle of complying
with both the sulfur and RVP standards evaluated.  Because of API’s
significant projected impacts, which differed from those made by the
Alliance and by ECTA in their studies, we looked closely at this
projected impact.  We found that this projection for a large shortfall
in supply is similar to previous projections made by API for earlier
rulemakings.  Baker and O’brien made a very dire projection for diesel
fuel supply when analyzing the final highway and proposed nonroad diesel
fuel sulfur regulations for the proposed nonroad diesel rulemaking back
in 2003.  API’s projection was that 12 refineries would be shutdown
and that U.S. refiners would exit the diesel market resulting in a
shortage of diesel fuel supply of 639 thousand barrels per day and to
make up the shortfall, the distillate market would need to be supplied
by imports.  Since that projection was made back in 2003 and the highway
diesel fuel program is fully implemented and the nonroad diesel fuel
program is mostly implemented, we can look at the impacts to see how
well API’s projection played out.

First, with respect to imports, the distillate import/export market was
fairly stable at about 200 thousand barrels per day of net imports
during the period 2003 to 2005, before the highway and nonroad programs
started.  If we add the expected increase in imports estimated by API
caused by the ULSD highway rule, API projected the imports to increase
to 549 thousand barrels per day in 2006.  When the temporary compliance
option of the ULSD highway rule ended in 2010 and nonroad diesel
(excluding locomotive and marine diesel because those requirements
don’t start until 2012) must comply with the ULSD nonroad diesel rule
in 2010, API estimated that imports will increase to 829 thousand
barrels per day including the baseline imports.  However, what actually
occurred is that imports not only did not increase, but they actually
decreased to the point that the U.S. became net exporters of 428
thousand barrels per day of distillate.   Thus, API was off by over 1200
thousand barrels per day in its estimate of distillate production in
2010 by U.S. refiners.    REF _Ref309215910 \h  Figure 5-9  summarizes
the imports and exports of diesel fuel and gasoline during the period
when the clean fuels regulations were being phased in.

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  9  Petroleum
Product Imports and Exports During the Implementation of Clean Fuels
Regulations

One reason why API was so far off in its projection that U.S. distillate
supply would decrease significantly is that it had projected that 12
refineries would shut down due to the highway and nonroad rulemakings,
but, in fact, there were very few refinery shutdowns.  Between 2003 and
2011 when the highway and nonroad diesel fuel ULSD programs were phasing
in (as well as Tier 2, MSAT2, RFS1 and RFS2), there was a total of 5
refinery shutdowns of refineries which produce transportation fuels.
However, also during this time period there were reactivations of three
previously shutdown transportation fuel producing refineries.
Considering both the shutdown refineries and reactivated refineries,
there was a net shutdown of two transportation fuel producing refinery
closures.  It is unclear why those 5 transportation fuel producing
refineries shutdown, but there is no evidence to suggest they were
caused by the diesel rules.  There are many factors which cause refinery
shutdowns.

To understand these factors it is necessary to revisit the history of
the U.S. refining industry.  During the second crude oil embargo which
occurred during the Carter Administration, subsidies were established
that incentivized the construction of many small refineries.  After
crude oil prices dropped, those subsidies ended and many of those
refineries were not economically competitive with larger refineries.
Over time the number of refineries decreased and the remaining
refineries were expanded to supply the U.S. market.  This is part of a
rationalization that most any industry experiences as the industry
matures.    REF _Ref309303921 \h  Figure 5-10  and   REF _Ref312057882
\h  Table 5-36  summarize the changes in the number of refineries, the
average size of refineries, and the total production capacity of the
U.S. refining industry based on data from the Energy Information
Administration (EIA).

Figure   STYLEREF 1 \s  5 -  SEQ Figure \* ARABIC \s 1  10   Refining
Industry Statistics

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  36  U.S. Refinery
Industry Statistics

Year	1982 - 1992	1993 – 2002	2003 - 2011

Net Change in the Number of Operable Refineries	-102	-50	-2

Change in Average Refinery Size (kbbl/day)	+18,400	+31,800	+11,000

Change in Total U.S. Operating Refinery Capacity (MMbbl/day)	-1.2	+1.6
+0.4

  REF _Ref309303921 \h  Figure 5-10  and   REF _Ref312057882 \h  Table
5-36  show that there were many refinery closures during the 1980s and
1990s, although over time the number of refinery closures was
diminishing.  Therefore, the refinery closures which occurred during the
2003 to 2011 time frame could very well be due to this rationalization
process reflecting a maturing industry.  In fact, examining the trend,
the number of net refinery shutdowns is virtually flat during the 2003
to 2011 time frame relative to the previous periods.  This is clearly a
rationalization of the refining industry because as refineries were
closing, the average refinery size increased over each of the periods.
Finally, the total U.S. refinery capacity decreased and increased back
to its 1982 levels during the 1980s and early 90s (decrease was likely
due to the corporate average fuel economy standards), but showed a
modest increase from the late 1990’s through 2011.

Projected Energy Impacts and Impacts on Permitting

Our refinery-by-refinery model was also used to determine the impact the
Tier 3 standards would have on the energy related CO2 emissions and
permitting of existing refineries.  While the Tier 3 proposal will
reduce emissions from vehicles, the addition of grass roots units and
revamping of existing units which we project will happen as a result of
the Tier 3 sulfur standards are likely to result in some increased
emissions of regulated air pollutants at refineries.  Refinery projects
designed to meet the new fuel standards could trigger preconstruction
air permitting requirements under the Clean Air Act and EPA’s New
Source Review (NSR) regulations.  To address this concern, we used our
refinery-by-refinery model to estimate the likely process and equipment
changes that may be required to meet the Tier 3 gasoline standards.
This information was submitted to EPA’s Office of Air Quality Planning
and Standards (OAQPS) to provide the inputs that are necessary for the
modeling and analysis of the refinery emissions and permitting impacts
of the Tier 3 fuel standards.

Using our refinery-by-refinery model we generated refinery-specific
estimates of the increased energy, hydrogen, and gasoline octane demands
that we estimate will result from the proposed Tier 3 standards.  We
also estimated the increase in sulfur plant recovery unit (SRU)
loading/operations for the 111 U.S. refineries that we modeled in our
analysis.  Energy demand includes fuel that is needed to generate
refinery process heat, steam and electricity.  Hydrogen demand is
associated with increased hydrotreating of Fluid Catalytic Cracking
(FCC) naphtha and light straight run (LSR) streams.  Increased gasoline
octane demand results from refineries having to replace octane that is
lost due to increased FCC naphtha hydrotreating.  Increased SRU loading
results from the increased fuel desulfurization and associated H2S
generation.  All of these incremental demands will be referred to as
“demands” in the following sections.  We used our
refinery-by-refinery model to calculate the increase in these various
demands for several scenarios where sulfur averaging, banking, and
trading (ABT) was not allowed and each refinery had to meet the 10ppm
standard, as well as scenarios that allowed ABT between refineries owned
by the same parent company to minimize the cost of compliance with the
Tier 3 standards.

Emissions Impacts of Different Production Volumes

In addition to considering scenarios with and without ABT we also
considered the impacts on emissions and permitting of different gasoline
production volumes for each refinery.  In the first case, called the
normal case, we considered the incremental demands for each refinery
assuming no change in gasoline production volume.  We also considered a
case, called the maximum demand case, where each refinery maximized
gasoline production based on currently existing refinery capacity and
equipment.

Normal Case

The normal case was estimated using each refinery’s predicted yields
of FCC naphtha and LSR from our refinery-by-refinery model, along with
each refinery’s total gasoline production volume from EPA’s RFG
database.  For each refinery the refinery-by-refinery model generated
specific Tier 3 demands for hydrogen, steam, fuel gas, electricity and
gasoline octane based on the desulfurization technology used by each
refinery for any FCC postreating and LSR hydrotreating.  To determine
the FCC postreating demands the model considers each refinery’s volume
of FCC naphtha under normal operations, the FCC naphtha sulfur level at
the refinery prior to postreating, and the process requirements of the
FCC postreater technology used by that refinery.  The demands are
calculated by multiplying the FCC naphtha volume by the demands from the
use of the associated FCC postreating technology.    REF _Ref311717664
Table 5-26  through   REF _Ref312134882  Table 5-29  show the FCC
postreater technology demand averages as applied to refineries on a
national basis for the 5 and 10 ppm gasoline sulfur standards.  Note
that the demands vary significantly with the FCC naphtha sulfur level
prior to postreating.

Similarly, the normal case demands for any LSR blendstocks that require
additional hydrotreating as a result of the Tier 3 standards were
determined based on each refinery’s yield of LSR blendstock under
normal operations and the demands for the additional LSR hydrotreating.
These demands, on a national average basis, are listed in   REF
_Ref309142410  Table 5-31 .  The normal case demands for FCC postreating
and LSR hydrotreating were then summed to determine the increase in
energy, hydrogen, and octane demand.  To determine the additional sulfur
removed from gasoline we first calculated the difference between the
current gasoline sulfur level of the gasoline produced at each refinery
according to their compliance reports to EPA and the proposed Tier 3
standard.  This difference was multiplied by the refinery’s gasoline
production volume and divided by the number of days of operation to
calculate the additional sulfur removal level at each refinery.  This
sulfur removal information was then used to determine the increase in
SRU loading on a fractional basis by dividing the additional sulfur
removal as a result of the Tier 3 standards (in tons of sulfur per day)
by the refineries SRU process capacity.

Maximum Case

We also considered a second demand case, called the maximum case, in
which we calculated the demands that result from the Tier 3 standards if
each refinery maximizes gasoline production based on currently existing
refinery capacity.  For this case we first determined each refiners FCC
unit process capacity utilization rate in the normal case.  The annual
FCC unit feedstock charge rate for each refinery as reported in the 2009
EIA data was divided by the FCC unit design capacity as reported in the
Oil and Gas Journal (OGJ) to calculate the capacity utilization rate for
the normal case.  These normal capacity utilization rates were then
scaled up to reflect maximum capacity utilization rates, and further
adjusted using an overdesign factor.

For refineries projected to meet the proposed Tier 3 standards by
revamping existing FCC postreating units we assumed that their maximum
gasoline production rate was equal to the rate produced running the FCC
unit at 92% of the refinery’s maximum FCC design capacity.  There were
several refineries that are currently operating their FCC unit greater
than a 92% capacity utilization rate.  We assumed that these refineries
were already operating at their maximum annual capacity utilization
rate.  For refineries projected to install a new FCC postreater we
similarly assumed that the new unit would be scaled to process the
output of the FCC unit operating with a 92% utilization rate.  For new
FCC postreaters, however, we increased the results by 15% as an
overdesign factor and adjusted the results accordingly.  A similar
sizing approach was taken for refineries we projected would revamp or
add new LSR hydrotreating capacity to comply with the proposed Tier 3
standards.

The results represent a “maximum” annual gasoline production case
for each refinery under the Tier 3 standards based on each refiners FCC
unit design capacity.  These cases represent a scenario where each
refinery projects emissions based on the maximum achievable annual
production rate for their existing processing units.  These cases
reflect each refiner’s potential emissions impacts as a result of the
proposed Tier 3 standards, rather than the existing Tier 2 standards,
when operating at maximum FCC rates as opposed to normal operation more
indicative of national gasoline demand.

Refinery Demand Sourcing

After determining the increased demands for each refinery as a result of
the proposed Tier 3 regulations we next developed cases for each
refinery demand scenario that represented different options for sourcing
these demands.  Some refiners may choose to produce all of the required
hydrogen and electricity, as well as make up for all of the lost octane
at their refinery.  Others may choose to purchase some or all of the
hydrogen, electricity, and high octane blendstocks that they would need
to comply with the Tier 3 standards from external suppliers.  These
decisions have a significant impact on the emissions and permitting
impacts of the proposed Tier 3 regulations.  In order to bound all
possible scenarios we considered both high and low impact cases for each
refinery demand scenario.  In the high impact scenarios we assume that
each refinery produces all of the required hydrogen, and electricity
needs while making up for any gasoline octane loss at their refinery.
In the low impact scenarios we assume that all the necessary hydrogen,
electricity, and high octane blendstocks are purchased from an external
supplier.

In both cases we assumed that fuel gas demands would increase to meet
the increased thermal demands at the refinery.  In the high impact
scenarios the refinery’s fuel gas needs would be further increased to
produce the needed hydrogen and electricity while replacing the lost
octane in their gasoline.  We consulted literature sources to determine
the conversion factors from MBTU fuel gas to 1,000 standard cubic feet
(scf) of hydrogen and 1,000 pounds of steam that are typical for
refineries.  We also assumed a standard conversion efficiency from fuel
gas to electricity for our modeling.  These conversion factors are shown
in   REF _Ref315775997  Table 5-37  below.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  37  Fuel Gas
Required to Produce Hydrotreater Utilities

Utility	Fuel Gas Required (M BTU)

Hydrogen (1,000 SCF)	239

Steam (1,000 lbs)	1530

Electricity (1 kWh)	5.1

We also had to determine the fuel gas demands that would be required to
make up for lost octane in our high impacts scenario.  For this analysis
we assumed that all lost octane in the gasoline that results from
increased FCC postreating to meet the proposed Tier 3 standards would be
recovered by running the reformers at the refineries at a higher
severity as opposed to sourcing it from ethanol or other means.  This
would increase the octane of the reformate and offset the octane losses
from the FCC naphtha, resulting in no change in the octane of the
overall gasoline pool.  Running the reformer at a higher severity
requires a higher reactor processing temperature and an increased
volumetric rate for the pumps and compressors.  These changes further
increase the fuel gas and electricity demands of the refinery.  We
estimated these demands using information we obtained from our Jacob’s
refinery LP modeling analysis.  The estimates we used for the fuel gas
and electricity demands for increasing gasoline octane are shown in
REF _Ref315774510  Table 5-38  below.  These demand increases were only
used for the high impact scenarios.  For the low impact scenarios we
assumed that lost octane was recovered by purchasing high octane
blendstocks resulting in no fuel gas or electricity demand increases at
the refinery.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  38  Energy
Required to Increase Gasoline Octane

Utility	Amount Required to Increase Octanea 1 Point (per barrel
gasoline)

Fuel Gas (M BTU)	1.87

Electricity (kWh)	0.057

Note:

a (R + M)/2 method

Refinery Demand Impacts

Using our refinery-by-refinery model, along with the technology vendor
data for new and revamped FCC postreating and LSR hydrotreating data
(shown in   REF _Ref311717664  Table 5-26  through   REF _Ref312134882
Table 5-29  and   REF _Ref309142410  Table 5-31 ) we were able to
calculate the increases in refinery demands as a result of our proposed
Tier 3 regulations for each of the various scenarios outlined in the
previous sections.  This information is summarized in   REF
_Ref315774433  Table 5-39  and   REF _Ref315774442  Table 5-40  below.
The refineries have been identified by randomly assigned numbers to
protect confidential business information (CBI).  This information was
submitted to OAQPS to serve as the basis for their emissions and
permitting analysis of the Tier 3 regulations.  Based on the data
provided by EPA, OAQPS determined that the increased demands that result
from the Tier 3 regulations would exceed the permitting thresholds under
the New Source Review (NSR) regulations, including the Prevention of
Significant Deterioration (PSD) and/or the Nonattainment New Source
Review (NA NSR) for 16 refineries in the low impact scenarios and 22
refineries in the high impact scenarios.  An additional 7 refineries in
the low impacts scenarios, and 13 refineries in the high impact
scenarios, would exceed the threshold to trigger reviews for greenhouse
gas emissions only.  A technical memorandum describing the OAQPS
analysis and results is in the public docket for this proposal.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  39  Tier 3
Refinery Energy, Hydrogen and Sulfur Plant Demand Increases (10 ppm, No
ABT Cases)

Refinery Number	Demand Estimates

	Fuel Gas Demands	Sulfur Plant Production	Hydrogen

	Low Impact Cases (Million BTU/Yr)	High Impact Cases (Million BTU/Yr)
Sulfur Production Increase (Tons Sulfur/Day)	Sulfur Plant Capacity
Increase (Percent of Existing Facility)	Hydrogen Demand Increase
(million scf/year)

	Normal Volumes	Maximum Volumes	Normal Volumes	Maximum Volumes

	1	117,423	117,423	243,241	243,241	0.28	0.02	426

2	0	0	0	0	0.00	0.00	0

3	2,239,110	2,739,637	2,566,562	3,140,286	0.00	0.00	863

4	173,672	173,672	569,009	569,009	0.43	0.03	1,628

5	46,380	58,279	261,528	328,624	0.13	0.04	655

6	4,433	7,291	14,523	23,888	0.04	1.96	42

7	60,923	69,776	199,605	228,609	0.10	0.03	571

8	23,941	29,792	134,995	167,988	0.17	0.07	338

9	107,543	135,777	222,775	281,262	0.20	0.18	390

10	25,924	29,812	146,179	168,106	0.10	0.08	366

11	13,984	16,250	78,855	91,630	0.09	0.05	198

12	76,663	92,786	251,175	303,997	0.43	0.07	719

13	51,432	51,432	168,509	168,509	0.47	1.18	482

14	0	0	6,444	6,444	0.00	0.00	27

15	16,876	16,876	89,463	89,463	0.07	0.13	219

16	831,027	1,244,900	899,341	1,347,235	0.26	0.22	218

17	31,964	31,964	82,442	82,442	2.19	0.96	206

18	150,568	150,568	311,900	311,900	0.22	0.03	547

19	27,087	44,061	152,736	248,452	0.26	a	383

20	43,909	46,106	143,861	151,058	0.37	0.08	412

21	165,539	212,719	343,091	440,875	0.17	0.04	538

22	14,886	16,690	38,395	43,048	0.01	0.02	96

23	83,222	83,222	272,663	272,663	0.41	0.12	780

24	190,870	210,535	206,560	227,841	0.33	0.29	50

25	702,808	702,808	798,012	798,012	0.10	0.09	256

26	20,503	22,001	67,175	72,082	0.90	0.60	192

27	0	0	0	0	0.00	0.00	0

28	3,145,454	3,528,532	3,223,899	3,616,532	0.31	0.07	201

29	0	0	0	0	0.00	0.00	0

30	64,080	66,959	165,279	172,703	0.15	0.01	414

31	0	0	0	0	0.00	0.00	0

32	62,002	62,002	159,918	159,918	0.35	3.46	400

33	1,693,620	1,948,219	1,832,841	2,108,370	0.27	0.03	444

34	16,574	24,879	93,456	140,290	0.15	0.21	234

35	10,469	10,469	12,340	12,340	0.04	0.96	6

36	337,961	411,915	365,743	445,776	0.15	a	89

37	5,175	5,175	29,180	29,180	0.13	3.30	73

38	0	0	2,907	2,907	0.00	0.00	12

39	21,773	21,773	71,336	71,336	0.58	0.93	204

40	19,171	23,883	91,207	113,621	0.04	0.01	214

41	177,093	203,657	636,542	732,024	0.30	0.03	1,288

42	3,288	4,683	10,773	15,343	0.03	0.97	31

43	41,705	43,146	107,567	111,284	0.52	0.26	269

44	3,609,133	4,265,613	3,905,818	4,616,262	0.66	0.22	946

45	27,946	41,431	105,829	156,897	0.06	a	221

46	6,846	8,054	38,603	45,416	0.05	0.55	97

47	1,416,139	1,416,139	1,532,550	1,532,550	0.25	0.03	371

48	21,918	41,206	45,403	85,358	0.02	0.01	80

49	7,024	7,191	18,116	18,547	0.19	2.16	45

50	2,170,692	2,170,692	2,349,131	2,349,131	0.61	0.23	569

51	0	0	0	0	0.00	0.00	0

52	3,945,526	3,984,109	4,269,863	4,311,617	0.61	0.03	1,034

53	102,473	124,044	264,305	319,941	0.46	a	662

54	40,155	51,299	108,185	138,209	0.11	0.09	236

55	21,405	26,758	120,695	150,884	0.16	0.13	302

56	26,807	28,515	70,005	74,463	0.04	0.13	144

57	91,964	107,033	518,563	603,534	0.00   	0.03	1,299

58	0	0	0	0	0.00	0.00	0

59	52,160	62,683	108,050	129,848	0.10	0.03	189

60	109,050	109,050	357,285	357,285	0.62	0.11	1,022

61	23,773	23,773	36,151	36,151	0.04	0.00	52

62	9,233	9,655	30,251	31,632	0.04	1.96	87

63	136,167	175,790	282,068	364,148	0.08	0.01	494

64	54,151	60,794	165,033	185,278	0.24	0.12	221

65	360,695	402,762	390,346	435,870	0.05	0.19	95

66	8,113	8,589	20,926	22,152	0.04	0.39	52

67	26,289	34,157	67,806	88,100	0.19	0.17	170

68	89,955	103,448	507,237	583,323	0.20	0.02	1,271

69	30,259	33,479	99,139	109,690	0.14	0.14	284

70	9,369	20,299	61,521	133,298	0.20	0.03	103

71	37,188	37,188	121,841	121,841	1.31	0.44	349

72	1,079,231	1,299,822	1,167,948	1,406,672	0.09	0.14	283

73	15,845	17,618	51,915	57,724	0.03	0.00	149

74	38,525	40,291	101,764	106,429	0.09	0.04	215

75	0	0	0	0	0.00	0.00	0

76	14,588	14,588	47,795	47,795	0.03	0.00	137

77	16,875	20,135	43,524	51,932	0.13	0.70	109

78	139,558	139,558	289,093	289,093	0.16	0.02	507

79	0	0	0	0	0.00	0.00	0

80	64,517	76,071	65,729	77,500	0.07	0.10	234

81	2,009,982	2,009,982	2,280,122	2,280,122	0.24	0.05	729

82	58,475	60,441	191,583	198,026	0.26	a	548

83	2,008,357	2,021,700	2,173,451	2,187,891	0.48	0.09	526

84	0	0	0	0	0.00	0.00	0

85	23,472	27,526	132,354	155,214	0.27	0.14	332

86	20,570	24,731	115,988	139,454	0.00	0.00	291

87	97,698	112,353	363,505	418,031	0.35	0.10	752

88	4,171	5,743	27,391	37,710	0.08	0.12	46

89	147,823	147,823	306,331	306,331	0.13	0.01	495

90	786,104	984,013	850,725	1,064,903	0.30	0.18	206

91	786,104	984,013	850,725	1,064,903	0.41	1.47	206

92	25,608	25,608	53,152	53,152	0.03	0.08	56

93	35,993	47,565	36,669	48,459	0.05	a	131

94	4,151,496	4,231,505	4,606,346	4,695,121	0.65	0.08	1,307

95	1,232	2,692	8,090	17,675	0.01	0.03	14

96	2,457	3,308	13,417	18,060	0.02	a	33

97	28,695	28,695	74,012	74,012	0.52	a	185

98	0	0	0	0	0.00	0.00	0

99	46,468	50,408	152,246	165,155	0.26	0.66	436

100	2,591,010	2,708,025	2,804,001	2,930,635	0.83	0.13	679

101	0	0	0	0	0.00	0.00	0

102	32,339	57,437	111,894	198,734	0.12	0.06	221

103	0	0	0	0	0.00	0.00	0

104	74,538	74,538	154,710	154,710	0.00	0.00	162

105	5,400	5,668	35,458	37,218	0.00	0.00	59

106	139,029	139,029	455,507	455,507	0.25	0.02	1,303

107	0	0	11,540	11,540	0.05	a	48

108	8,314	8,879	17,223	18,393	0.00	0.00	30

109	1,485,414	1,704,414	1,607,521	1,844,524	0.32	0.05	389

110	122,762	122,762	279,765	279,765	0.22	0.06	515

111	27,548	33,475	155,338	188,757	0.10	0.07	389

a The refinery did not have published information on the capacity of the
existing sulfur plant.

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  40  Tier 3
Refinery Energy, Hydrogen and Sulfur Plant Demand Increase

(10 ppm, ABT Cases)

Refinery Number	Demand Estimates

	Fuel Gas Demands	Sulfur Plant Production	Hydrogen

	Low Impact Cases (Million BTU/Yr)	High Impact Cases (Million BTU/Yr)
Sulfur Production Increase (Tons Sulfur/Day)	Sulfur Plant Capacity
Increase (Percent of Existing Facility)	Hydrogen Demand Increase
(million scf/day)

	Normal Volumes	Maximum Volumes	Normal Volumes	Maximum Volumes

	1	20,503	22,001	67,175	72,082	0.90	0.60	192

2	64,080	66,959	229,725	240,045	0.22	0.02	467

3	323,504	388,955	476,338	572,710	0.00	0.00	528

4	89,955	103,448	507,237	583,323	0.20	0.02	1,271

5	0	0	0	0	0.00	0.00	0

6	426,001	692,966	627,257	1,020,346	0.29	a	696

7	0	0	0	0	0.00	0.00	0

8	26,807	28,515	70,005	74,463	0.04	0.13	144

9	117,423	117,423	243,241	243,241	0.28	0.02	426

10	5,400	5,668	35,458	37,218	0.00	0.00	59

11	1,525,387	1,525,387	1,558,831	1,558,831	0.51	1.28	64

12	8,113	8,589	20,926	22,152	0.04	0.39	52

13	7,024	7,191	18,116	18,547	0.19	2.16	45

14	74,538	74,538	154,710	154,710	0.00	0.00	162

15	0	0	0	0	0.00	0.00	0

16	2,591,010	2,708,025	2,804,001	2,930,635	0.83	0.13	679

17	177,093	203,657	636,542	732,024	0.30	0.03	1,288

18	0	0	0	0	0.00	0.00	0

19	19,171	23,883	91,207	113,621	0.04	0.01	214

20	26,289	34,157	67,806	88,100	0.19	0.17	170

21	2,239,110	2,739,637	2,566,562	3,140,286	0.00	0.00	863

22	83,222	83,222	272,663	272,663	0.41	0.12	780

23	147,823	147,823	306,331	306,331	0.13	0.01	495

24	0	0	2,907	2,907	0.00	0.00	12

25	2,273,706	2,751,864	2,323,556	2,812,199	0.50	0.08	96

26	0	0	0	0	0.00	0.00	0

27	107,543	135,777	222,775	281,262	0.20	0.18	390

28	16,875	20,135	43,524	51,932	0.13	0.70	109

29	150,568	150,568	311,900	311,900	0.22	0.03	547

30	0	0	0	0	0.00	0.00	0

31	30,259	33,479	99,139	109,690	0.14	0.14	284

32	0	0	0	0	0.00	0.00	0

33	139,558	139,558	289,093	289,093	0.16	0.02	507

34	9,369	20,299	61,521	133,298	0.20	0.03	103

35	0	0	6,444	6,444	0.00	0.00	27

36	0	0	0	0	0.00	0.00	0

37	109,050	109,050	357,285	357,285	0.62	0.11	1,022

38	0	0	0	0	0.00	0.00	0

39	10,469	10,469	12,340	12,340	0.04	0.96	6

40	210,772	269,511	319,729	408,832	0.07	0.00	379

41	173,672	173,672	569,009	569,009	0.43	0.03	1,628

42	21,773	21,773	71,336	71,336	0.58	0.93	204

43	3,145,454	3,528,532	3,223,899	3,616,532	0.31	0.07	201

44	337,961	411,915	365,743	445,776	0.15	a	89

45	3,945,526	3,984,109	4,269,863	4,311,617	0.61	0.03	1,034

46	97,698	112,353	363,505	418,031	0.35	0.10	752

47	1,416,139	1,416,139	1,532,550	1,532,550	0.25	0.03	371

48	16,876	16,876	89,463	89,463	0.07	0.13	219

49	433,258	526,468	637,943	775,189	0.14	0.09	707

50	4,433	7,291	14,523	23,888	0.04	1.96	42

51	58,475	60,441	191,583	198,026	0.26	a	548

52	2,170,692	2,170,692	2,349,131	2,349,131	0.61	0.23	569

53	8,497	8,497	12,247	12,247	0.00	0.00	16

54	31,964	31,964	82,442	82,442	2.19	0.96	206

55	336,635	420,834	495,673	619,649	0.19	0.15	550

56	32,339	57,437	111,894	198,734	0.12	0.06	221

57	38,525	40,291	101,764	106,429	0.09	0.04	215

58	54,151	60,794	165,033	185,278	0.24	0.12	221

59	0	0	0	0	0.00	0.00	0

60	23,773	23,773	36,151	36,151	0.04	0.00	52

61	190,870	210,535	206,560	227,841	0.33	0.29	50

62	3,288	4,683	10,773	15,343	0.03	0.97	31

63	0	0	0	0	0.00	0.00	0

64	2,008,357	2,021,700	2,173,451	2,187,891	0.48	0.09	526

65	2,457	3,308	13,417	18,060	0.02	a	33

66	41,705	43,146	149,509	154,676	0.63	0.31	304

67	46,468	50,408	152,246	165,155	0.26	0.66	436

68	1,079,231	1,299,822	1,167,948	1,406,672	0.09	0.14	283

69	3,071	3,325	7,294	7,896	0.00	0.00	17

70	4,123,377	4,123,377	4,213,781	4,213,781	0.38	0.03	174

71	786,104	984,013	850,725	1,064,903	0.30	0.18	206

72	37,188	37,188	121,841	121,841	1.31	0.44	349

73	0	0	0	0	0.00	0.00	0

74	40,155	51,299	108,185	138,209	0.11	0.09	236

75	1,485,414	1,704,414	1,607,521	1,844,524	0.32	0.05	389

76	122,762	122,762	279,765	279,765	0.22	0.06	515

77	102,473	124,044	264,305	319,941	0.46	a	662

78	0	0	0	0	0.00	0.00	0

79	3,609,133	4,265,613	3,905,818	4,616,262	0.66	0.22	946

80	43,909	46,106	143,861	151,058	0.37	0.08	412

81	1,693,620	1,948,219	1,832,841	2,108,370	0.27	0.03	444

82	0	0	0	0	0.00	0.00	0

83	60,923	69,776	199,605	228,609	0.10	0.03	571

84	4,171	5,743	27,391	37,710	0.08	0.12	46

85	4,151,496	4,231,505	4,606,346	4,695,121	0.65	0.08	1,307

86	8,314	8,879	17,223	18,393	0.00	0.00	30

87	5,175	5,175	29,180	29,180	0.13	3.30	73

88	96,113	113,326	98,454	116,085	0.13	0.17	543

89	988,379	1,480,617	1,109,185	1,661,587	0.31	0.26	412

90	0	0	0	0	0.00	0.00	0

91	9,233	9,655	30,251	31,632	0.04	1.96	87

92	21,918	41,206	45,403	85,358	0.02	0.01	80

93	14,886	16,690	38,395	43,048	0.01	0.02	96

94	35,993	47,565	36,669	48,459	0.05	a	131

95	202,851	261,880	506,929	654,442	0.15	0.01	1,146

96	786,104	984,013	850,725	1,064,903	0.41	1.47	206

97	25,924	29,812	146,179	168,106	0.10	0.08	366

98	1,232	2,692	8,090	17,675	0.01	0.03	14

99	369,152	432,912	543,551	637,434	0.30	0.15	603

100	0	0	0	0	0.00	0.00	0

101	28,695	28,695	74,012	74,012	0.52	a	185

102	828,747	828,747	965,965	965,965	0.13	0.11	412

103	0	0	11,540	11,540	0.06	a	48

104	13,984	16,250	78,855	91,630	0.09	0.05	198

105	62,002	62,002	159,918	159,918	0.35	3.46	400

106	260,661	391,286	383,805	576,142	0.17	0.25	426

107	194,048	194,048	294,359	294,359	0.07	0.00	349

108	0	0	0	0	0.00	0.00	0

109	428,992	479,023	481,425	537,572	0.08	0.27	179

110	52,160	62,683	108,050	129,848	0.10	0.03	189

111	0	0	0	0	0.00	0.00	0

a The refinery did not have published information on the capacity of the
existing sulfur plant.

Chapter 5 Appendix

LP Refinery Modeling Output Tables

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  41  Volume and
Cost Information Used for Estimating the Cost of Octane

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  42  PADD 1 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  43  PADD 2 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  44  PADD 3 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  45  PADD 4 and
PADD 5OC Unit Capacity and Throughput Volumes from LP Refinery Modeling
(Thousand bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  46  U.S. (except
CA) Unit Capacity and Throughput Volumes from LP Refinery Modeling
(Thousand bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  47  PADD 1
Gasoline Qualities Estimated by LP Refinery Modeling

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  48  PADD 2
Gasoline Qualities Estimated by LP Refinery Modeling

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  49  PADD 3
Gasoline Qualities Estimated by LP Refinery Modeling

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  50  PADD 4 and 5OC
Gasoline Qualities Estimated by LP Refinery Modeling

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  51  U.S. (except
CA) Gasoline Qualities Estimated by Refinery Modeling

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  52  PADD 1 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  53  PADD 2 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  54  PADD 3 Unit
Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  55  PADD 4 and 5OC
Unit Capacity and Throughput Volumes from LP Refinery Modeling (Thousand
bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  56  U.S. (except
CA) Unit Capacity and Throughput Volumes from LP Refinery Modeling
(Thousand bbl/day)

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  57  PADD 1
Gasoline Qualities for the E10 and E15 Cases relative to the Reference
Case

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  58  PADD 2
Gasoline Qualities for the E10 and E15 Cases relative to the Reference
Case

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  59  PADD 3
Gasoline Qualities for the E10 and E15 Cases relative to the Reference
Case

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  60  PADD 4 and 5OC
Gasoline Qualities for the E10 and E15 Cases relative to the Reference
Case

Table   STYLEREF 1 \s  5 -  SEQ Table \* ARABIC \s 1  61  U.S. (except
CA) Gasoline Qualities for the E10 and E15 Cases relative to the
Reference Case

References

  Normally we conduct the refinery modeling assuming an after-tax 15%
ROI and adjust the costs to reflect a before-tax 7% ROI to report the
costs.  However, in this case because the new capital investments were
so minimal, we omitted the capital cost amortization adjustment because
its effect on costs was judged to be negligible.

 Since we completed the LP refinery modeling to estimate the cost for
recovering the lost octane and the associated changes in gasoline
quality, we found that other Tier 3 refinery modeling studies did not
show the same increase in aromatics and decrease in E300 (see also
<IP_ADDRESS>).  We then discovered that the LP refinery model that we have
licensed to use required some improvements in how the refinery model was
characterizing both the light-cut and the heavy-cut naphtha from the
reformer streams to more accurately estimate the E300 and aromatics
content of these streams.  We have subsequently worked with a contractor
to make these improvements to the LP refinery model and will reassess
the changes in gasoline quality for the final rule analysis.  Thus,
while our modeling results shown in Table 5.3 show a meaningful impact
on aromatics and E300, we believe there will in fact be little or no
change.  Note that these improvements are not expected to have any
impact on the cost estimates made by the refinery model.

 Since we conducted the cost analysis for the proposed rulemaking, we
put in place an additional round of greenhouse emission reductions (2017
– 2025) for light duty cars and trucks that will reduce future
gasoline demand.  When we model the costs for the final rulemaking, we
will incorporate this reduction in gasoline demand in our costs
analyses.

 We did not account for any undercutting of the heavy FCC naphtha into
jet and diesel fuel, nor did we account for the removal of any pentanes
that might be occurring in refineries to comply with stringent
summertime RVP standards, therefore our analysis is likely somewhat
conservative and overestimates the costs.

 Naphtha Splitter towers separate the naphtha feed stream into a light
and heavy streams, whereby the heavy stream is typically  reformer
feedstock, while the light stream is blend stock lighter than reformer
feed.

 After we completed our cost analysis, we met with UOP staff, including
those who market their Merox technology for removing mercaptans from
gasoline streams.  The UOP staff said that pretty much all butanes are
already being treated by Merox (or similar) extraction units.  Thus,
there would be no additional cost for treating butanes for complying
with Tier 3.  We will update our cost analysis to reflect this for the
final rule cost analysis.

 In our Tier 3 cost analysis, we inadvertently only accounted for the
ethanol volumes that are contained in the 2009 RFG database, not those
mandated by RFS 2.  For our final rulemaking cost analyiss, we will
adjust our model to account for higher ethanol use in the future, which
will slightly reduce our Tier 3 cost estimates, due to the dilution
effects of ethanol.

 No refinery compliance margins were included in this analysis.

 Based on Tier 2 sulfur compliance data, of the 26 companies that
purchased sulfur credits in 2010, eight bought credits only from their
own company, and another five bought credits both from their own company
and from other companies. The remainder bought credits only from other
companies.

  Approximately 55% of this desululfurization cost is comprised of the
variable cost, and the majority of that is due to the cost of recovering
the octane lost when the hydrotreater unit saturates the octane-rich
olefins contained in the FCC naphtha.  Another 30% of the cost is due to
the capital cost amortized over the volume of gasoline.  Finally, about
15% of the cost is due to the fixed operating cost which includes the
maintenance of the new equipment and taxes.

  The installed capital cost for an FCC postreater from the Jacobs data
base was adjusted to current year dollars.  This estimated installed
capital cost is several years old and may not represent Jacobs current
cost estimate for a FCC postreater.

Chapter 1

*** E.O. 12866 Review – Revised Version – Do Not Cite, Quote, or
Release During Review ***

Page   PAGE  2

  PAGE   \* MERGEFORMAT  5-1

 Annual Energy Outlook 2006, Energy Information Administration,
Department of Energy

 Worldwide Report, Oil and Gas Journal.    HYPERLINK
"http://www.ogjonline.com"  www.ogjonline.com , December 22, 2005.

 Petroleum Supply Annual 2004, Volume 1, Table 38.  Energy Information
Administration, Department of Energy.

 Petroleum Supply Annual 2004, Volume 1, Tables 22 – 25.  Energy
Information Administration, Department of Energy.

 Petroleum Supply Annual 2005, Volume 1, Table 17.  Energy Information
Administration, Department of Energy.

 Petroleum Refining Technology and Economics 4th Edition.  James Gary
and Glenn Handerwork.  Page 65, Table 4.7

 The Challenges & Opportunities of 10 ppm Sulfur Gasoline.  Jay Ross,
Delphine Largeteau,  Marc Laborde, Larry Wisdom.  NPRA Annual Meeting,
AM-11-57, March, 2011, page 6

 The Benefits of Cat Feed Hydrotreating and the Impact of Feed Nitrogen
on Catalyst Stability.  Brian Moyse at Haldor Topso.  NPRA Annual
Meeting, AM-10-167, March 2010, Page 2

 Handbook of Petroleum Refining Processes, Third Edition.  Robert
Meyers, page 11.39

 Refining Economics of a National Low Sulfur, Low RVP Gasoline Standard,
Performed for The International Council for Clean Transportation by
Mathpro, October 25, 2011.

 Refining Economics of a National Clean Gasoline Standard for PADDs 1-3;
for The Alliance of Automobile Manufacturers by Mathpro, June 27, 2008.

 Potential Supply and Cost Impacts of Lower Sulfur, Lower RVP Gasoline;
prepared for The American Petroleum Institute by Baker and O’Brien;
July 2011.

 Schink, George R., Singer, Hal J., Economic Analysis of the
Implications of Implementing EPA’s Tier 3 Rules, prepared for the
Emissions Control Technology Association, June 14, 2012.

 An Assessment of the Impact of Nonroad Diesel Fuel Sulfur Regulation on
Distillate Fuel Production and Availability in the U.S., prepared for
the American Petroleum Institute by Baker and O’Brien, July 2003.

 Petroleum Supply Annual 2003 – 2010; Table 24,  Imports of Crude Oil
and Petroleum Products, Energy Information Administration.

 Petroleum Supply Annual 2003 – 2010; Table 31, Exports of Crude Oil
and Petroleum Products by PAD Destination.

 Petroleum Supply Annual 2011, Refinery Capacity Report, Table 13
Refineries Permanently Shutdown by PAD District Between January 1, 1990
and January 1, 2010; Energy Information Administration.

 Petroleum Supply Annual 2003 – 2011, Refinery Capacity Report, Table
11 New, Shutdown and Reactivated Refineries During 2010; Energy
Information Administration.

 Petroleum and Other Liquids; Number and Capacity of Petroleum
Refineries, Data, Total Number of Operable Refineries and Total Number
of Operating Refineries, 1990 – 2010; Energy Information
Administration.

 Gary, J., & Handewerk, G. (2001). Petroleum Refining: Technology and
Economics. (4th ed.). CRC Press. p 256.

 Gary, J., & Handewerk, G. (2001). Petroleum Refining: Technology and
Economics. (4th ed.). CRC Press. p 337.

 Keller, P. (2012, January). New Source Review Permitting Impact
Analysis for Proposed Tier 3 Gasoline Program. Memorandum to the docket.


[Federal Register: July 26, 2007 (Volume 72, Number 143)]
[Notices]
[Page 41066]
[DOCID:fr26jy07-39]

=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RP99-301-161]

ANR Pipeline Company; Notice of Negotiated Rate Filing Amendement

July 18, 2007.
    Take notice that on July 10, 2007, ANR Pipeline Company (ANR)
tendered for filing and approval amendments to three negotiated rate
agreements between ANR and Wisconsin Public Service Corporation. The
amendments are being filed to reduce the MDQ's on two contracts and
increase the MDQ on one contract.
    ANR requests that the Commission accept and approve the subject
filing to be effective August 1, 2007.
    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211 and 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed in accordance with the provisions of
Section 154.210 of the Commission's regulations (18 CFR 154.210).
Anyone filing an intervention or protest must serve a copy of that
document on the Applicant. Anyone filing an intervention or protest on
or before the intervention or protest date need not serve motions to
intervene or protests on persons other than the Applicant.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://www.ferc.gov.
 Persons unable to file electronically should submit an

original and 14 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the

``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For

TTY, call<PHONE_NUMBER>.

Kimberly D. Bose,
Secretary.
[FR Doc. E7-14412 Filed 7-25-07; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register: January 4, 2007 (Volume 72, Number 2)]
[Notices]
[Page 355-357]
[DOCID:fr04ja07-58]

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

SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-54990; File No. SR-CBOE-2006-108]

Self-Regulatory Organizations; Chicago Board Options Exchange,
Incorporated; Notice of Filing and Immediate Effectiveness of Proposed
Rule Change To Amend CBOE Rules in Connection With CBOE's Determination
To Trade Certain Option Classes on Hybrid

December 21, 2006.
    Pursuant to Section 19(b)(1) of the Securities Exchange Act of 1934
(``Act''),\1\ and Rule 19b-4 thereunder,\2\ notice is hereby given that
on December 15, 2006, the Chicago Board Options Exchange, Incorporated
(``Exchange'' or ``CBOE'') filed with the Securities and Exchange
Commission (``Commission'') the proposed rule change as described in
Items I and II below, which Items have been prepared by the Exchange.
The Exchange filed the proposal as a ``non-controversial'' proposed
rule change pursuant to Section 19(b)(3)(A)(iii) of the Act \3\ and
Rule 19b-4(f)(6) thereunder.\4\ The Commission is publishing this
notice to solicit comments on the proposed rule change from interested
persons.
---------------------------------------------------------------------------

    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ 15 U.S.C. 78s(b)(3)(A)(iii).
    \4\ 17 CFR 240.19b-4(f)(6).
---------------------------------------------------------------------------

I. Self-Regulatory Organization's Statement of the Terms of Substance
of the Proposed Rule Change

    CBOE proposes amend its rules relating to CBOE's determination to
trade certain option classes on Hybrid. The text of the proposed rule
change is available on CBOE's Web site (http://www.cboe.com), at the

CBOE's Office of the Secretary, and at the Commission's public
reference room.

II. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

    In its filing with the Commission, the Exchange included statements
concerning the purpose of and basis for the proposed rule change and
discussed any comments it received on the proposed rule change. The
text of these statements may be examined at the places specified in
Item IV below. The Exchange has prepared summaries, set forth in
sections A, B, and C below, of the most significant aspects of such
statements.

A. Self-Regulatory Organization's Statement of the Purpose of, and
Statutory Basis for, the Proposed Rule Change

1. Purpose
    The purpose of this rule change is to amend CBOE Rules 8.3 and 8.4
in connection with CBOE's determination to trade options on the Russell
2000 Index (RUT) on the Hybrid 2.0 Platform. Additionally, CBOE
proposes to amend Rule 8.3 in connection with CBOE's determination to
trade options on the iShares Russell 2000 Index Fund (IWM) on the
Hybrid Trading System, and options on the NASDAQ 100 Index (NDX) on the
Hybrid Trading System.\5\
---------------------------------------------------------------------------

    \5\ CBOE Rule 1.1(aaa) defines Hybrid Trading System and Hybrid
2.0 Platform.
---------------------------------------------------------------------------

    RUT options currently has an appointment cost of .25, and CBOE
intends to maintain that appointment cost when RUT options trade on the
Hybrid 2.0 Platform. As a result, RUT options would be classified as an
A+ Tier option class. CBOE intends to trade RUT options on the Hybrid
2.0 Platform beginning on December 19, 2006.
    CBOE proposes to amend Rule 8.3(c)(ii) to specifically reference
IWM options and NDX options as option classes trading on the Hybrid
Trading System. IWM options would have an appointment cost of .50, and
NDX options would have an appointment cost of 1.0.\6\ CBOE proposes to
amend CBOE Rule 8.3(c)(iv) to delete reference to IWM options and NDX
options in the table listing the non-Hybrid option classes and their
related appointment costs. CBOE notes that the new appointment cost for
IWM is lower than its current non-Hybrid appointment cost of .85. CBOE
intends to trade IWM options on the Hybrid Trading System beginning on
December 19, 2006, and NDX options on the Hybrid Trading System
beginning on January 9, 2007.
---------------------------------------------------------------------------

    \6\ Because not all option classes traded on the Hybrid Trading
System have an appointment cost of .01, CBOE proposes to modify Rule
8.85(e)(ii) to state that the appointment cost for option classes
traded on the Hybrid Trading System is as set forth in Rule
8.3(c)(ii). Currently, Rule 8.85(e)(ii) states that the appointment
cost of Hybrid option classes is .01.
---------------------------------------------------------------------------

    Finally, CBOE proposes to amend Rule 8.3A to expressly include a
reference to the ``AA'' tier in Interpretation and Policy .01.
Currently, Interpretation .01 references the ``A+'' tier, but not the
``AA'' tier. Products designated as ``A+'' tier products have a class
quoting limit (``CQL'') of 40 as provided in Interpretation .01 of Rule
8.3A. By including reference to the ``AA'' tier option in
Interpretation.01, products designated as ``AA'' tier products
(presently options on the CBOE Volatility Index (VIX)), would have a
CQL of 40, which is consistent with the current CQL for VIX options.
2. Statutory Basis
    The Exchange believes the proposed rule change is consistent with
the Act and the rules and regulations under the Act applicable to a
national securities exchange and, in particular, the requirements of
Section 6(b) of the Act.\7\ Specifically, the Exchange believes the
proposed rule change is consistent with the Section 6(b)(5) of the
Act,\8\ which requires that the rules of an exchange be designed to
promote just and equitable principles of trade, to prevent fraudulent
and manipulative acts and, in general, to protect investors and the
public interest.
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    \7\ 15 U.S.C. 78f(b).
    \8\ 15 U.S.C. 78f(b)(5).
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B. Self-Regulatory Organization's Statement on Burden on Competition

    CBOE does not believe that the proposed rule change will impose any
burden on competition that is not necessary or appropriate in
furtherance of the purposes of the Act.

C. Self-Regulatory Organization's Statement on Comments on the Proposed
Rule Change Received From Members, Participants or Others

    No written comments were solicited or received with respect to the
proposed rule change.

III. Date of Effectiveness of the Proposed Rule Change and Timing for
Commission Action

    The foregoing rule change has become effective pursuant to Section
19(b)(3)(A)(iii) of the Act \9\ and subparagraph (f)(6) of Rule 19b-4
\10\ thereunder because it does not: (i) Significantly affect the
protection of investors or the public interest; (ii) impose any
significant burden on competition; (iii) become operative for 30 days
from the date on which it was filed, or such shorter time as the
Commission may designate; and the Exchange has given the Commission
written notice of its intention to file the proposed rule change at
least five business days prior to filing. At any time within 60 days of
the filing of such proposed rule change, the Commission may summarily
abrogate such rule change if it appears to the Commission that such
action is necessary or appropriate in the public interest, for the
protection of investors, or otherwise in furtherance of the purposes of
the Act.
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    \9\ 15 U.S.C. 78s(b)(3)(A)(iii).
    \10\ 17 CFR 240.19b-4(f)(6).
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    Under Rule 19b-4(f)(6) of the Act,\11\ the proposal does not become
operative for 30 days after the date of its filing, or such shorter
time as the Commission may designate if consistent with the protection
of investors and the public interest. The Exchange has requested that
the Commission waive the 30-day operative date, so that the proposal
may take effect on December 19, 2006 with respect to IWM options and
RUT options, and January 9, 2007, with respect to NDX options. The
Exchange believes that the proposed rule change does not raise any new
regulatory issues. The Commission agrees and, consistent with the
protection of investors and the public interest, has determined to
waive the 30-day operative date, which renders the proposal effective
on December 19, 2006 with respect to IWM options and RUT options, and
January 9, 2007, with respect to NDX options.\12\
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    \11\ Id.
    \12\ For purposes only of accelerating the operative date of
this proposal, the Commission has considered the proposed rule's
impact on efficiency, competition and capital formation. 15 U.S.C.
78c(f).
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IV. Solicitation of Comments

    Interested persons are invited to submit written data, views, and
arguments concerning the foregoing, including whether the proposed rule
change is consistent with the Act. Comments may be submitted by any of
the following methods:

Electronic Comments

     Use the Commission's Internet comment form (http://www.sec.gov/rules/sro.shtml.
); or     Send an e-mail to<EMAIL_ADDRESS>Please include

File Number SR-CBOE-2006-108 on the subject line.

Paper Comments

     Send paper comments in triplicate to Nancy M. Morris,
Secretary, Securities and Exchange Commission, 100 F Street, NE.,
Washington, DC 20549-1090.
    All submissions should refer to File Number SR-CBOE-2006-108. This
file number should be included on the subject line if e-mail is used.
To help the Commission process and review your comments more
efficiently, please use only one method. The Commission will post all
comments on the Commission's Internet Web site (http://www.sec.gov/rules/sro.shtml
). Copies of the submission, all subsequent amendments,

all written statements with respect to the proposed rule change that
are filed with the Commission, and all written communications relating
to the proposed rule change between the Commission and any person,
other than those that may be withheld from the public in accordance
with the provisions of 5 U.S.C. 552, will be available for inspection
and copying in the Commission's Public Reference Section, 100 F Street,
NE., Washington, DC 20549. Copies of such filing also will be available
for inspection and copying at the principal office of the CBOE. All
comments received will be posted without change; the Commission does
not edit personal identifying information from submissions. You should
submit only information that you wish to make available publicly. All
submissions should refer to File Number SR-CBOE-2006-108 and should be
submitted on or before January 25, 2007.

    For the Commission, by the Division of Market Regulation,
pursuant to delegated authority.\13\
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    \13\ 17 CFR 200.30-3(a)(12).
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Jill M. Peterson,
Assistant Secretary.
 [FR Doc. E6-22544 Filed 1-3-07; 8:45 am]

BILLING CODE 8011-01-P