[Federal Register: May 13, 1999 (Volume 64, Number 92)]
[Proposed Rules]
Page 26053-26102
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr13my99-29]
Control of Air Pollution From New Motor Vehicles: Proposed Tier 2
Motor Vehicle Emissions Standards and Gasoline Sulfur Control
Requirements
[[continued from page 26052]]
our ultimate goal of the 30 ppm standard in an orderly fashion, while
limiting the negative environmental consequences. The temporary nature
of the ABT program would ensure that any negative consequences for Tier
2 vehicles of these higher sulfur levels (120 ppm average in 2004, 90
ppm in 2005) would be minimal. By the time that the majority of new
vehicles sales would be required to meet the Tier 2 standards (2006 and
beyond), average sulfur levels in gasoline would meet the 30 ppm annual
average standard.
We are interested in comment on the corporate pool average values,
and their associated caps. A higher pool average would obviously ease
implementation (e.g., 150 ppm average with an appropriate cap in 2004,
for example), but we have not proposed a higher average because of our
concerns that higher in-use sulfur levels after 2004 are undesirable
for emissions from Tier 2 vehicles. We request that commenters
supporting higher corporate pool average values discuss how such higher
values would affect in-use emission levels of Tier 2 vehicles, as well
as NLEV and Tier 1 vehicles.
We also ask for comment on an alternative approach that would
implement the corporate average requirement for 2004 (120 ppm) but not
require compliance with the 30 ppm standard (with or without credit
use) until 2005. The 120 ppm corporate pool average would continue in
2005 and the 90 ppm corporate pool average would be implemented in
2006, with the requirement to meet the 30 ppm standard (with or without
credits) beginning in 2005 and extending indefinitely, consistent with
the proposed program.
Finally, we request comment on whether refiners should be allowed
to comply with the corporate average standards through the use of
sulfur credits generated under the ABT program (within the limits of
the proposed caps). This would likely render the refinery-specific
standards in 2004 and 2005 unnecessary, and thus refiners would only
have to comply with the per-gallon caps and corporate averages in 2004
and 2005. However, in 2006 and beyond refiners would have to meet the
30 ppm average at every refinery (with limited use of sulfur credits,
to the extent that the 80 ppm cap permits).
We have proposed per-gallon caps of 300 ppm in 2004 and 180 ppm in
2005 at the refinery gate, with slightly higher caps imposed downstream
(as explained in Section VI.B below). We believe that downstream caps
would be necessary to ensure compliance and protect Tier 2 vehicles. At
the same time, we believe caps at the refinery gate would be necessary
to guarantee that the environmental goals of this program were met; the
corporate and refinery averages alone wouldn't provide the full
emissions reductions and environmental benefits we have estimated
because, by themselves, they could allow gasoline with high sulfur
levels in the system as long as the refiner offset any such high sulfur
batches with very low sulfur gasoline. However, there are some
arguments for eliminating the per-gallon standard at the refinery gate
and simply enforcing a per-gallon cap at the retail level (or some
intermediate point downstream). This approach would give refiners and
blenders greater flexibility in blending occasional batches of gasoline
that exceed the proposed cap standards. These refiners/blenders could
sell and transport these high sulfur batches to another party who would
blend down the sulfur level to make gasoline meeting the downstream
caps. One shortcoming of such an approach (removing the per-gallon cap
at the refinery) is that not all gasoline passes through multiple
parties before ending up at the retail level; some refiners ship part
or all of their production directly from refinery to retail outlet. We
welcome comment on whether caps at both the refinery gate and
downstream are appropriate. We also encourage your input on whether the
caps we have proposed to coincide with the corporate average standards
are appropriate. Keep in mind that we need some limitation on sulfur
levels to protect the first Tier 2 vehicles that would begin entering
the marketplace as early as the fall of 2003.
b. Proposed Standards for Small Refiners. As explained in the
regulatory flexibility analysis discussion in Section VIII.B. of this
document, we have considered the impacts of these proposed regulations
on small businesses. As part of this process, we convened a Small
Business Advocacy Review Panel for this proposed rulemaking, as
required under the Small Business Regulatory Enforcement Fairness Act
of 1996 (SBREFA). The Panel was charged with reporting on the comments
of small business representatives regarding the likely implications of
possible control programs, and to make findings on a number of issues,
including:
<bullet> A description and estimate of the number of small entities
to which the proposed rule would apply;
<bullet> A description of the projected reporting, recordkeeping,
and other compliance requirements of the proposed rule;
<bullet> An identification of other relevant federal rules that may
duplicate, overlap, or conflict with the proposed rule; and
<bullet> A description of any significant alternatives to the
proposed rule that accomplish the objectives of the proposal and that
may minimize any significant economic impact of the proposed rule on
small entities.
The final report of the Panel is available in the docket. The Panel
concluded that small refiners were the group most likely to be
negatively impacted by the proposed program. (The Panel noted that
small gasoline marketers would also have to comply with some portions
of a gasoline sulfur program, but did not recommend any regulatory
relief for this group of small businesses.) Many of the small refiners
the Panel met with indicated their belief that their businesses may
close if relief were not considered due to the substantial capital and
other costs required to reduce sulfur levels to the 30/80 standard. The
Panel recommended that EPA solicit comments on a number of options to
provide relief to small refiners, which include some or all of these
provisions:
<bullet> Providing small refiners a four-to six-year period during
which less stringent gasoline sulfur requirements would apply; comment
was also recommended on extending this period for up to a total of 10
years.
<bullet> Basing each small refinery's gasoline sulfur limit on its
individual average sulfur level based on the most recent report(s) to
EPA; and
<bullet> Granting temporary hardship relief on a case-by-case
basis, following the four-to six-year period of relief common to all
small refiners, based on a showing of economic need.
The Panel stated its belief that additional time would allow
sulfur-reduction technologies to be proven out by larger refiners,
thereby reducing the risks to be incurred by small refiners who choose
to incorporate these technologies. The added time would likely allow
for costs of these desulfurization units to drop, thereby limiting the
economic consequences for small refiners. Nationally, giving small
refiners more time to comply would help ensure that cross-industry
engineering and construction resources would be available. Finally,
extending the compliance deadlines would provide small refiners with
additional time to raise capital for infrastructure changes.
i. What Standards Would Small Refiners Have to Meet Under Today's
Proposal?
[[Page 26054]]
Upon evaluating the impacts of our proposed gasoline sulfur
requirements on small refiners and careful review of the Panel's
recommendations, we have determined that regulatory relief in the form
of delayed compliance dates is appropriate to allow small refiners to
comply without disproportionate burdens. We propose that, for a period
of four years after other refiners must start meeting the standards
proposed in Table IV.C-2, refiners meeting clearly defined company size
criteria be allowed to comply with somewhat less stringent requirements
than those just described for refiners and gasoline importers. We
propose to define a small refiner as any company employing no more than
1,500 employees throughout the corporation, including any subsidiaries,
regardless of the number of individual gasoline-producing refineries
owned by the company or the number of employees at any one refinery.
This number is based on the Small Business Administration definition of
a small refiner for the purposes of regulation.<SUP>49</SUP> The
proposed annual average small refiner standards beginning with 2004 are
shown in Table IV.C-3 below, although the cap standards begin October
1, 2003.
---------------------------------------------------------------------------
\49\ SBA uses a different definition of small refiner for the
purposes of federal procurements of petroleum products, and EPA in
the past has used criteria based on the processing capacity of the
individual refinery and of all refineries owned by one company.
Table IV.C-3.--Proposed Temporary Gasoline Sulfur Requirements for Small
Refiners in 2004-2007
------------------------------------------------------------------------
Temporary sulfur standards
Refinery baseline sulfur level (ppm) (ppm)
------------------------------------------------------------------------
0 to 30................................ Average: 30.
Cap: 80.<SUP>a</SUP>
31 to 80............................... Average: no requirement.
Cap: 80.<SUP>a</SUP>
81 to 200.............................. Average: baseline level. Cap:
Factor of 2 above the
baseline.<SUP>a</SUP>
201 and above.......................... Average: 200 ppm minimum, or
50% of baseline, whichever is
higher, but in no event
greater than 300 ppm.
Cap: Factor of 1.5 above
baseline level.<SUP>a</SUP>
------------------------------------------------------------------------
<SUP>a</SUP> The cap standard takes effect at the refinery gate October 1, 2003.
We also propose to apply these provisions to any foreign refiner
that can establish that they meet this same definition of small. Since
few if any foreign refiners send all of their gasoline production to
the U.S., allowing eligible small foreign refiners to meet these less
restrictive standards, even on a temporary basis, would be a less
restrictive requirement than it will be for small domestic gasoline
producers since they may be able to send lower sulfur gasoline to the
U.S. without having to incur capital expenses. Furthermore, in many
cases foreign refiners are not subject to the same stringent permitting
and other regulatory requirements that domestic refiners face. At the
same time, we believe many foreign refiners will be installing gasoline
desulfurization equipment because of the various international
requirements that have been proposed and/or finalized (for example, in
Europe, Canada, Japan) that require gasoline sulfur levels to be
reduced to levels similar to our proposed standards and thus these
companies will not avoid all of these costs. In addition, in most cases
we expect importers to be the party responsible for the sulfur level of
imported gasoline, and importers are not eligible for the less
stringent standards applied to small refiners. Hence, the number of
foreign refiners who could benefit (financially and otherwise) from
gaining small refiner status is likely to be very small. However, we
welcome comments on the competitive and other marketplace implications
of this proposal.
We believe that these proposed small refiner standards are
reasonable and that they would not conflict with our overall goals of
reducing gasoline sulfur levels nationwide as soon as possible and of
reducing gasoline sulfur levels sufficiently to enable and protect the
emissions performance of Tier 2 vehicles. Our conclusions are based in
part on the fact that only a very small volume of gasoline will be
eligible for these lesser standards. We have estimated that small
refiners produce approximately 2.5 percent of all gasoline in the U.S.
Furthermore, of the 17 refineries that we have identified as meeting
SBA's definition of small business, nine already have gasoline sulfur
levels less than 90 ppm. Hence, only a very small fraction of the
gasoline sold in the U.S. would take advantage of the higher small
refiner standards through 2007. By the time that a large number of Tier
2 vehicles could have been impacted by residing in or traveling to
areas where higher sulfur fuel is sold, the temporary exemptions for
small refiners would have expired. Furthermore, in most cases, gasoline
produced by small refiners is mixed with substantial amounts of other
gasoline prior to retail distribution (due to the functioning of the
gasoline distribution system), likely resulting in only marginal
increases in overall sulfur levels. Thus, the sulfur level of gasoline
actually used by Tier 2 vehicles should generally be much lower than
that produced by individual small refineries who receive unique
compliance standards through 2007.
As explained above, we are proposing that compliance under the
proposed standards be based on a refiner's being able to show that it
meets specific criteria. If a refiner were able to qualify as a small
refiner under our definition, it would need to then establish a sulfur
baseline for each participating refinery. For small refiners,
compliance with the proposed sulfur regulations would be determined on
the basis of the sulfur baseline for each refinery owned by that
company. The following sections explain these proposed requirements in
more detail, to supplement the information be presented above. We also
explain how small refiners could obtain an additional two-year
exemption upon establishing a hardship case, as well as how small
foreign refiners could establish eligibility for compliance under the
small refiner provisions.
ii. Application for Small Refiner Status.
We are proposing that refiners seeking small refiner status under
our gasoline sulfur program would have to apply to us in writing no
later than June 1, 2002, requesting this status. In this application,
the refiner must demonstrate that as of January 1, 1999, the business
and any subsidiaries, including all refining, distribution, and
marketing activities, as well as any other activities worldwide,
employed 1,500 or fewer employees. We are proposing that in the case of
refineries owned by joint ventures, the total employment of both (all)
companies would be considered in determining whether the 1,500 employee
limit is reached. If a refiner that is not small as of January 1, 1999
subsequently sells part of its business and as a result has fewer than
1500 employees, it would not be eligible for a small refiner status.
These provisions would provide stability to the regulated and
regulatory parties and ensure that no ``gaming'' of the program occurs.
However, we are also proposing that any new refinery built between
January 1, 1999 and January 1, 2001, or a refinery that was not
operational as of January 1, 1999, owned by a refiner that meets our
proposed definition, could apply for small refiner status no later than
June 1, 2002. In this case, we would consider carefully the history of
the refinery and
[[Page 26055]]
the company in determining whether it is appropriate to grant this
refiner small refiner status.
We are also proposing that if a refiner with approved small refiner
status later exceeds the 1,500 employee threshold without merger or
acquisition, its refineries could keep their individual refinery
standards. This is to avoid stifling normal company growth and is
subject to our finding that the refiner did not apply for and receive
the small refiner status in bad faith. An example of an inappropriate
application for small refiner status would be a refiner that
temporarily reduced its workforce from 1,600 employees to 1,495
employees prior to January 1, 1999, and then rehired employees after
the cutoff date. This would be a bad faith attempt to avoid the intent
of the rule. We are requesting comment on this provision.
At any time after June 1, 2002, a refiner with approved small
refiner status could elect to cease complying with the small refiner
standards and, in the next calendar year, begin complying with the
standards specified in Table IV.C-2 and related provisions. However,
this decision would apply to all refineries owned by that refiner and
once a refiner dropped its small refiner status, it would not be
eligible to be reinstated as a small refiner at some later date.
iii. Application for a Small Refiner Sulfur Baseline.
A qualifying small refiner could apply for an individual sulfur
baseline by June 1, 2002 for any refinery owned by the company by
providing a calculation of its sulfur baseline using its average
gasoline sulfur level based on 1997 and 1998 production data, and the
average volume of gasoline produced in these two years. The proposed
regulations specify the information to be submitted to support the
baseline application. The baseline calculations should include any
oxygen added to the gasoline at the refinery. This application would be
submitted at the same time that the refiner applied for small business
status; confirmation of small business status would not be required to
apply to EPA for an individual sulfur baseline. If the baseline were
approved, we would assign standards to each of the company's refineries
in accordance with Table IV.C.-2.
Blenders would not be eligible for the small refiner individual
baselines and standards because they would not have the burden of
capital costs to install desulfurization equipment, which is the
primary reason for allowing small refiners to have a relaxed compliance
schedule.
iv. Volume Limitation on Use of a Small Refinery Standard.
We are proposing that the volume of gasoline subject to the small
refinery's individual standards would be limited to the volume of
gasoline the refinery produced from crude oil, excluding the volume of
gasoline produced using blendstocks produced at another
refinery.<SUP>50</SUP>
---------------------------------------------------------------------------
\50\ In addition to gasoline produced from crude oil, a small
refinery's baseline volume would include gasoline produced from
purchased blendstocks where the blendstocks are substantially
transformed using a refinery processing unit.
---------------------------------------------------------------------------
Under this approach, the baseline volume for a small refinery would
reflect only the volume of gasoline produced from crude oil during the
baseline years. In addition, use of the refinery's individual baseline
sulfur level during each calendar year averaging period (beginning with
2004) would be limited to the volume of gasoline that is the lesser of:
(1) 105% of the baseline volume, or (2) the volume of gasoline produced
during the year from crude oil. Any volume of gasoline produced during
an averaging period in excess of this limitation would be subject to
the standards applicable to refiners not subject to a small refiner
standard. In this case, the small refiner's annual average standard
would be adjusted based on the excess volume in a manner similar to the
compliance baseline equation for conventional gasoline under Section
80.101(f) of Part 40 of the Code of Federal Regulations. However, the
small refiner's per-gallon cap standard would not be adjusted.
This limitation would assure that small refiners receive relief
only for gasoline produced from crude oil, the portion of the refinery
operation requiring capital investment to meet lower sulfur standards.
We are requesting comment on this provision and whether an alternative
approach may be more appropriate for the stated purpose.
v. Hardship Extensions Beyond 2007 for Small Refiners.
Beginning January 1, 2008, all small companies' refineries would
have to meet the permanent national sulfur standard of 30 ppm on
average and the 80 ppm cap, except small refineries that apply for and
receive a hardship extension. A hardship extension would provide the
small refiner an additional two years to comply with these national
standards. A hardship extension would need to be requested in writing
and would specify the factors that qualify the refiner for such an
extension. Factors considered for a hardship extension could include,
but would not be limited to, the refiner's financial position; its
efforts to procure necessary equipment and to obtain design and
engineering services and construction contractors; the availability of
desulfurization equipment, and any other relevant factors.
By January 1, 2010 all refiners would be required to meet the
permanent national average standard and cap. We are requesting comment
on the proposed hardship extension, including the factors to be
considered in petitions for extension, and the proposed time periods.
vi. What Alternative Provisions for Small Refiners Are Possible?
We have proposed one type of program to address the needs of small
refiners. We solicit comment on other options so that we can consider
these options as we finalize this rule. We encourage comments. We
request comment on a range of alternatives, including those listed
below, which could be considered when developing unique regulatory
requirements for small refiners. We specifically request that the
comments address not only the economic but also the environmental
implications of the alternative, relative to the program we've
proposed.
<bullet> Are there alternative or additional criteria that could/
should be used to define a small refiner, such as the volume of crude
oil processed or the volume of gasoline produced (since the gasoline
sulfur standard applies specifically to gasoline)? Other criteria may
also be acceptable, such as a different employee number for
qualification as a small entity, or basing the count on employees
employed in gasoline production only. We welcome your recommendations.
Our desire is to limit the number of companies meeting the small
refiner definition in order to provide regulatory relief only to those
companies that have the economic concerns unique to small businesses.
If you recommend criteria other than number of employees, please
comment on how those criteria can be shown to limit the number of
refineries that will be eligible for the proposed relief.
<bullet> Are the caps and averages of the proposed interim
standards for small refiners (see Table IV.C.-3) appropriate for the
corresponding individual sulfur baseline levels?
<bullet> What is an appropriate and sufficient time period for the
proposed small refiner interim standards? Would most qualifying small
refiners be able to meet the 30/80 standards within four years (six if
a hardship extension is granted, which is dependent on the case made by
the individual refiner), as proposed? The Panel report suggested that a
period of six to ten years could
[[Page 26056]]
be desirable to provide sufficient time for small refiners to comply
with the proposed standards. What are the arguments for granting more
than four years of additional time and what are the environmental
implications (and implications for Tier 2 vehicles) of such an
extension?
<bullet> Should small refineries of multi-refinery companies
(companies too large to meet the proposed small refiner criteria) be
eligible for small refiner interim standards? Should refineries not
producing gasoline as a major product (for example, refineries engaged
primarily in the production of lubricants where gasoline is a small
volume by-product) be eligible for small refiner interim standards
regardless of corporate size/employment?
<bullet> If a small refiner operates more than one refinery (while
still meeting our proposed small refiner criteria), should that refiner
be permitted to aggregate the sulfur baselines and comply with the
small refiner standards applicable to that aggregate baseline? Under
the sulfur ABT program described below, we are proposing to require
refiners to aggregate data from all of their refineries when
determining compliance with the 2004 and 2005 corporate average
standards (Table IV.C.-2) (but not the refinery gate standards,
although we seek comment on that alternative).
<bullet> Rather than providing unique standards for qualifying
small refiners, would the need for separate small refiner provisions be
addressed if we were to adopt a regional sulfur program? In Section
IV.C.1. above, we explained our concerns that a regional sulfur program
would not achieve the same emission reductions we project for our Tier
2/gasoline sulfur program. However, some have suggested to us that a
regional program would address the need for small refiner provisions
since the majority of small refiners are thought to sell gasoline in
the West. We know of several refiners that appear to meet our proposed
criteria for being small that sell at least some of their gasoline
production in the eastern U.S. (as defined by the oil industry's
proposed program) and thus a regional program would not cover all small
refiners. We encourage comments on this alternative, particularly from
refiners who could be impacted by such a decision.
<bullet> Would a more general hardship provision that would be
based on a showing of substantial economic hardship, such a discussed
in Section IV.C.4.c., provide sufficient compliance flexibility to
address the needs of small refiners?
4. Compliance Flexibilities
In addition to the basic standards applicable to refiners that were
explained above, we are proposing two additional programs that will
provide flexibility for refiners when complying with the proposed
standards. The first is the sulfur ABT program mentioned previously.
The second is a program to streamline the construction permitting
process so that refiners can make the required process modifications by
2004.
a. Sulfur Averaging, Banking, and Trading (ABT) Program. We are
proposing that any refiner or importer be allowed to generate, bank,
and trade sulfur credits. A sulfur ABT program would accelerate the
reduction of sulfur in gasoline and provide refiners with additional
flexibility in achieving compliance with the 30 ppm standard in 2004
and beyond. The following paragraphs provide additional information
about our proposed sulfur ABT program, to supplement that presented in
Section IV.C.-3.a above. We encourage comments on the design elements
we have proposed for the sulfur ABT program. If you believe alternative
approaches would make the program more useful to the refining industry,
please share your specific recommendations with us.
i. Why Are We Proposing a Sulfur Averaging, Banking, and Trading
Program?
A sulfur ABT program, if properly implemented, would provide the
opportunity for a win for both the refining industry and the
environment. The flexibility provided by an ABT program could provide
refiners more lead time to bring all of their refineries into
compliance with the 30 ppm standard, by allowing them to use credits
generated at one refinery to delay having to desulfurize gasoline from
another refinery. ABT would provide the opportunity for reduced costs
by allowing the industry the flexibility to average sulfur levels among
different refineries, between companies, and across time. Since, under
banking, early reductions have a value during program implementation,
ABT provides an incentive for technological innovation and the early
implementation of refining technology.
The ABT program could provide meaningful early benefits for the
environment because it would allow the Tier 2 standards to be
implemented earlier than might otherwise have been possible, and
because it would provide direct environmental benefits. The first
direct benefit relates to atmospheric sulfur loads. This benefit is
largely independent of when credits are generated and used. However,
atmospheric deposition and transformation rates of sulfur compounds
tend to vary geographically and seasonally and thus we must consider
whether a broad averaging program would have different pollutant
effects when compared to a more constrained averaging program or a
program without averaging. Any potential negative effects of a broad
ABT program should be mitigated by the geographic distribution of
refineries, the widespread distribution pipelines, and the fungible
nature of gasoline. All of these factors, taken together, lead us to
believe that any negative effect on atmospheric sulfur levels from ABT
(relative to a single 30 ppm average/80 ppm cap in 2004) would be
negligible. It should be noted that this situation is further moderated
by the pool averages and caps proposed for 2004 and 2005, since these
averages and caps would reduce actual gasoline sulfur levels as the ABT
program phases in.
Another environmental benefit is related to the effect of gasoline
sulfur on catalyst performance, as discussed in the draft RIA. Since
catalyst performance depends in part on gasoline sulfur levels, we must
consider whether the emissions benefits (measured in g/mi-per-ppm) of
early sulfur reductions when credits are generated are essentially the
same as the g/mi-per-ppm benefits when the credits are used. The effect
of sulfur on emissions from Tier 0 and Tier 1 vehicles, which will
dominate the fleet in 2000-2005, is approximately the same when sulfur
levels increase from 30 to 150 ppm as it is when sulfur levels increase
from 150 ppm to 330 ppm. In other words, for each ppm increase in
sulfur levels, approximately the same effect on emissions results
regardless of whether the increase is from low levels (e.g., from 30
ppm up to 150 ppm) or from higher levels (e.g., from 150 ppm up to
current average levels). Therefore, the emissions benefits from credits
generated before 2004 would essentially offset the emissions effects of
those credits being used in 2004 and beyond, especially since corporate
pool average sulfur levels could not exceed 120 ppm in 2004 and 90 ppm
in 2005, and sulfur levels will be capped at 80 ppm in 2006 and beyond.
Nonetheless, there remains concern about the sensitivity of later
models (NLEV and Tier 2) to sulfur and about the reversibility of the
effect of higher sulfur levels on catalyst efficiency. More explicitly,
the relatively few Tier 2 vehicles that would see somewhat higher
sulfur levels than 30 ppm in 2004 and 2005 (about three-quarters of
[[Page 26057]]
a model year of production) would not be able to fully recover the loss
in emissions performance due to the higher sulfur levels. Hence, the
corporate averages and caps would be necessary in these interim years.
In 2006 and beyond, the 80 ppm cap and the 30 ppm average refinery
standard, even with the ongoing use of credits to comply with the 30
ppm standard, would keep in-use sulfur levels very close to 30 ppm.
Thus, Tier 2 vehicles sold in 2006 and beyond would receive appropriate
protection from gasoline sulfur.
ABT programs must be designed and implemented carefully to be
certain that they are sensitive to equity and competitive issues in the
industry and do not create the potential for inadvertent emission
increases. In the context of gasoline sulfur control, concerns about
different baseline sulfur levels and different technological
capabilities among refiners must be considered. Even with the proposed
lead time, some refiners would find it easier to achieve reductions
than would others. This is due to a number of factors, including
refinery configuration, product mix (gasoline versus distillates),
crude oil sulfur levels, and the ability to generate capital to fund
the investment. At the same time the program must be designed to
eliminate the possibility of windfall credits and to be sure that the
environmental benefits associated with early sulfur reductions offset
the potential forgone benefits when the credits are used.
The program we are proposing today attempts to strike a balance
among all of these factors. Some of the elements and design features
(such as the eligibility trigger and the baseline requirement) were
included to address concerns such as timing, disparate capabilities
among refineries, and the potential for excessive (``windfall'')
credits. We are seeking comment on options for dealing with all of the
issues we have identified.
The ABT program is voluntary. No refiner or importer qualifying for
credits is required to generate them, use them, or make them available
to others (except as discussed in Section IV.C.4.a.vi. below). The
process for establishing a sulfur baseline and generating and using
credits is outlined below.
ii. How Would Refiners Establish a Sulfur Baseline?
To establish a sulfur baseline against which credits would be
calculated, we propose that by July 1, 2000, each refiner or importer
that wants to generate credits submit two pieces of information to the
Agency. One would be the volume-weighted average sulfur content for
conventional gasoline (CG) for each refinery (or imported by that
importer) for 1997 and 1998. The second would be the annual average
volume of CG produced by that refinery (or imported by the importer) in
those years. <SUP>51</SUP> <SUP>52</SUP>
---------------------------------------------------------------------------
\51\ Since participation in the sulfur ABT program is voluntary,
refines opting not to generate or use sulfur credits do not have to
establish a sulfur baseline for this program.
\52\ We believe that variations in specific gravity, which could
affect the sulfur content of gasoline as determined on a mass basis,
will average out over the year and need not be included in the
calculations. However, we request comment on whether specific
gravity should be considered in the calculation of sulfur baselines
(including whether such data exists for 1997-98) and subsequently,
in calculating credits generated relative to this baseline.
---------------------------------------------------------------------------
Since we expect summer RFG sulfur levels to decrease in 2000 to
approximately 150 ppm (due to the actions refiners will take to meet
the Phase II NO<INF>X</INF> standards for RFG), we are proposing to set
the individual refinery sulfur baseline for summer RFG at 150 ppm,
regardless of volume produced in 1997 and 1998. Winter RFG production
would be assigned the same sulfur baseline as the refinery's
conventional gasoline, without regard to the volume of winter RFG
produced in 1997-98. Hence, no reporting of RFG sulfur levels or
volumes would be required in setting a sulfur baseline. We encourage
comments on the use of different sulfur baselines for summer and winter
RFG, particularly regarding whether this could create a disincentive to
produce RFG in the summer months. We do not want to jeopardize our RFG
program, but at the same time, we want sulfur credits to reflect
actions taken by refiners above and beyond their current operations
and/or regulatory obligations.
Conventional gasoline produced in 2000 and beyond that exceeded
105% of the CG baseline volume produced at that refinery would be
assigned a sulfur baseline (from which credits would be generated) of
150 ppm. This provision is intended to prevent increases in average
sulfur levels resulting from increases in CG production. A refiner/
importer of conventional gasoline to which oxygenate is added
downstream during 1997-1998 could include the downstream oxygenate
volume in that refinery's CG baseline, if the refiner can substantiate
that oxygenate was added to that gasoline.
A refinery/importer that did not produce/import gasoline during
1997-1998 would be assigned a baseline of 150 ppm each for CG and RFG
for the purposes of sulfur credit generation in 2000 and beyond. This
provision would also apply to blenders of natural gasoline, butane, or
similar non-oxygenated blending components. Such parties would be
considered refiners and would need to meet all requirements, such as
analyzing each batch of the blending component for sulfur prior to its
addition to gasoline. Credits would be based only on the volume of the
blending components. We encourage comments on alternative provisions
for establishing baselines for refiners/importers that could not
establish a 1997-98 sulfur baseline as described above. In particular
would 150 ppm be appropriate, or would a greater or lesser sulfur
content be most equitable and most environmentally neutral? Should this
baseline be tied in some way to the trigger for credit generation in
(as discussed below) 2000-2003?
We request comment on several aspects of this baseline provision.
The 1997-1998 years for the baseline represent the latest available
data and thus best reflects the present state of each refinery's
gasoline sulfur levels. However, we already have established baseline
sulfur levels for 1990 for most refineries. Except for changes related
to RFG, average gasoline sulfur levels have changed little since 1990.
Hence, we request comment on whether that 1990 baseline would be a
suitable substitute. Alternately, we request comment on whether 1997
and 1998 are the appropriate years to average when establishing a
sulfur baseline, given that mandatory use of the Complex Model starting
in 1998 could have led to changes in sulfur levels between 1997 and
1998. Since our purpose in proposing to establish sulfur baselines is
to try to capture current sulfur levels (within a reasonable date of
the 2000 start date for credits to be generated), the sulfur baseline
could be based on a single year's data (for example, 1998) rather than
a two-year average. We proposed a two-year average to try to capture
and accommodate operational fluctuations and changes. However, a single
year's data may adequately capture current sulfur levels.
We are not proposing a formal baseline review and/or approval
process since the proposal envisions a self-certifying process.
Refiners would submit their 1997 and 1998 sulfur baseline data for each
refinery to us, and then would generate credits from that baseline in
2000-2003. If we determined, through a refinery audit or other action,
that the sulfur baseline was calculated with incorrect data, we would
establish a new sulfur baseline and the refinery would subject to that
baseline, even if it meant recalculating
[[Page 26058]]
the number of credits generated in subsequent years. We have used this
baseline review process in other mobile source programs and believe it
works well, but we request comment this approach.
We considered the possibility that, since refiners report annual
production information to EPA, we could issue baselines for each
refinery rather than refiners having to submit them to us. However, we
do not think this is a possible solution because many refiners comply
with our RFG and CG requirements by aggregating the data from all of
their refineries. Thus, the data we currently receive from refiners
would not allow us to establish an individual baseline for every
refinery in the U.S. (unless we went back to 1990 data). However, we
would like comment on whether a more formal sulfur baseline approval
process (say, a letter from the Agency or a date by which approval can
be assumed unless the refiner hears otherwise) would be desirable. Keep
in mind that even with a more formal baseline approval process, the
baseline could be changed at a later date if we found, during an audit
of refinery records, errors in compliance with the proposed baseline
requirements. Hence, any up-front approval would only provide certainty
that, based on the data reported to us, we believe the refiner had
correctly applied the mathematical equations proposed today for
establishing a sulfur baseline.
Some have raised the concern that if imported gasoline were allowed
to be used for credit generation, as we propose today, foreign refiners
might be able to gain an unfair advantage. For example, it is possible
that foreign refiners could simply re-blend their gasoline (without
installing new capital equipment) and send their lowest-sulfur refinery
streams to the U.S. at a lower cost than gasoline produced by domestic
refiners that had to reduce overall sulfur levels through
desulfurization. Since importers, not foreign refiners, would be the
parties assigned a sulfur baseline and eligible for generating credits,
we do not believe foreign refiners would have a strong incentive to
send lower sulfur gasolines to the U.S. We believe that the benefits of
allowing importers to participate in the sulfur ABT program (more
players in the credit trading field, more chance for early reductions
in gasoline sulfur levels) outweigh the potential detriments. However,
we encourage comment on the implications of the decision to allow
imported gasoline to be used for credit generation.
Oxygenate blenders would not be able to participate in this
proposed credit program because they would not be subject to the sulfur
standard. Special provisions would exempt them from having to measure
the sulfur content of the oxygenate they blend and from the
recordkeeping and reporting requirements of the sulfur program, other
than the requirements that apply to all parties that handle gasoline
and gasoline blendstocks downstream of the refinery.
iii. How Would Refiners Generate Credits?
During the period 2000-2003, credits could be generated annually by
any refinery that produced conventional gasoline averaging 150 ppm
sulfur or less on an annual, volume-weighted basis. Credits would be
calculated based on the amount of reduction from the refinery's CG
sulfur baseline.<SUP>53</SUP> Credits could also be generated from
winter RFG based on reductions from the sulfur baseline, if the winter
RFG sulfur level averaged 150 ppm or less (on a seasonal volume-
weighted basis). Similarly, summer RFG would need to have a seasonal
volume-weighted average sulfur level below 150 ppm to be eligible for
credit generation, although credits would only be created based on the
difference between 150 ppm and the summer RFG sulfur average. Thus,
credits would need to be generated separately for conventional gasoline
and RFG. Conventional gasoline produced in excess of 105% of the
baseline volume could only generate credits for sulfur reductions below
150 ppm, not for the cumulative reduction from the baseline sulfur
level. Winter RFG would not be subject to any volume limitations, and
thus refineries could generate credits for any volume of winter RFG
that contains 150 ppm sulfur or less.
---------------------------------------------------------------------------
\53\ If a refinery's baseline average were 150 ppm or less,
credits could only be generated for annual average reduction's below
the baseline level.
---------------------------------------------------------------------------
For example, if in 2002 a refinery reduced its annual average
sulfur level for conventional gasoline from a baseline of 450 ppm to
150 ppm, its sulfur credits would be determined based on the difference
in annual sulfur level (450-150=300 ppm) multiplied by the volume of
conventional gasoline produced (up to 105% of the baseline CG volume).
If this refinery produced more CG than 105% of the baseline volume, it
would only generate credits from that incremental volume if the
incremental gasoline were below 150 ppm. (For example, if the
refinery's 2002 average CG sulfur level were 100 ppm, it would get 150-
100=50 ppm sulfur credits on any volume in excess of 105% of its
baseline CG volume, as well as 450-100=350 ppm for the baseline volume
up to 105%.)
If this same refinery also produced RFG with an annual average
sulfur content of 90 ppm in 2002, it could also receive sulfur credits
calculated based on the difference between 150 ppm and 90 ppm (60 ppm)
times the volume of summer RFG produced plus 360 ppm (450-90) times the
volume of winter RFG produced. A refinery with a sulfur baseline lower
than 150 ppm sulfur would only generate credits relative to reductions
from its baseline, for either CG or winter RFG. Credits from summer RFG
would be based on reductions from 150 ppm.
Several states have implemented or are considering gasoline sulfur
control programs. To avoid double-counting of emission benefits, lower
sulfur gasoline produced to comply with these state programs would not
be eligible for early banking credits under this program.
In 2004 and beyond we propose that credits could only be generated
for actual annual sulfur averages below the 30 ppm standard (combining
conventional and reformulated gasolines), and only for the difference
between the standard and the actual annual sulfur average. (For
example, a refinery producing gasoline in 2004 that averaged 25 ppm
could generate 30-25=5 ppm, while a refinery producing gasoline that
averaged 40 ppm would not be eligible for any credits.)
We encourage comments on this credit generation concept. In
particular, would these formulas permit sufficient credits to be
generated industry-wide to provide adequate credits for use in
compliance in 2004 and beyond? If not, what are the limitations on
credits and what changes could be made to improve the likelihood that
sufficient credits would be generated?
Our proposal to cap volumes on which credits could be generated at
105 percent of baseline levels is intended to preclude the possibility
of closely-located refineries generating credits by moving blendstocks.
This could occur if a refinery with a relatively low baseline level
moved blendstocks to a refinery with relatively higher levels, thus
allowing the somewhat artificial generation of credits. We request
comment on whether such a provision is necessary and whether the 5
percent cap should be increased to as high as 10 percent to reasonably
accommodate normal growth in volume. We raise some potential
alternatives to these provisions in Section IC.C.4.a.vi. below, and
encourage your consideration of all of these issues in your comments.
[[Page 26059]]
iv. How Would Refiners Use Credits?
Credits generated prior to 2004 would have to be used or
transferred by 2007. Credits generated in 2004 and beyond would have to
be used or transferred within five years of the year in which they were
generated. If these credits were traded to another party, they would
have to be used by the new owner within five years of the year of
transfer. Since the transfer could occur any time within five years of
generation, some credits could have a life of up to ten years.
Our proposed ABT program is designed to ease implementation of the
new standards and credits would be of their greatest value during
phase-in periods. ABT is not necessarily intended to permit a refinery
to operate above the standard for a protracted time period. While
limiting credit life might reduce the incentive to generate credits and
could create a ``use or lose'' mentality, the credit program would seem
to be of relatively small value to any refiner/importer that held
credits for five years and did not need to use them. We believe that
limiting credit life is appropriate since we must also consider the
basic reason for ABT and address concerns about our ability and the
ability of the refiners to maintain the integrity of the credit system
over many years. EPA requests comment on credit life including options
such as limiting life by depreciating their value over a period of
years as well as longer or shorter periods of fixed credit value.
We propose that credits could be withdrawn from a refinery's/
importer's credit bank or purchased from another refinery/importer to
bring the annual sulfur average for each refinery down to the 30 ppm
standard beginning in 2004. There would be no geographic constraints on
credit trades. However, as explained in Section IV.C.3.a above, in 2004
no batch of domestically produced or imported gasoline could exceed 300
ppm, and a refinery's/importer's actual annual corporate pool average
sulfur level could not exceed 120 ppm. (A refiner owning more than one
refinery would have to aggregate the respective sulfur levels of
gasoline produced at those refineries for determining compliance with
the 120 ppm standard.) In 2005, gasoline sulfur would be capped at 180
ppm and the corporate pool average could not exceed 90 ppm. The
aggregation requirement would also apply in 2005. As described above,
credits would apply only to compliance with the 30 ppm refinery
standard, not to the corporate pool average or the cap.
A refiner or importer choosing to participate in the ABT program
would be required to file annual reports with the Agency indicating the
applicable baselines or standard(s) in ppm sulfur, the annual
average(s) in ppm sulfur, and the annual volume(s) in gallons (for each
refinery). These calculations would be reported, along with an
accounting of credits banked, transferred (sold), or acquired (bought).
(For 2000-2003, the reports would only cover credits banked and
traded.) The credits would be in units of ppm-gallons.
Thus, for each purchase of credits, as reported on the buyer's
annual report, there should be a corresponding entry on the seller's
annual report. Through the report, refiners would have to demonstrate
that their average sulfur levels (with the use of credits, if
necessary) comply with the 30 ppm standard at each refinery. Refiners
would also have to demonstrate that the combined production from all
refineries meets the corporate average standard. As mentioned above,
the actual corporate averages could not exceed 120 ppm in 2004 and 90
ppm in 2005. The identity of refiners/refineries and importers involved
in these transactions would be reported, along with the registration
numbers assigned to them by the Agency under the RFG/CG program (40 CFR
part 80, Subparts D, E, and F).
In addition, we are concerned that the potential exists for credits
to be generated by one party and subsequently purchased or used in good
faith by another, and later found to have been calculated or created
improperly or otherwise determined to be invalid. In this case, both
the seller and purchaser would have to adjust their sulfur calculations
to reflect the proper credits and either party (or both) could be
deemed in violation of the standards and other requirements if the
adjusted calculations demonstrate noncompliance with an applicable
standard. We have taken this approach in our other fuels enforcement
programs. We welcome comments on this provision. In particular, we
request comment on whether our program should be designed such that
only the seller should be deemed in violation if that party sold
invalid credits and, upon correction for this error, was found to have
violated one or more standards. In general, mobile source ABT programs
hold both parties liable.
For the duration of the credit program, each participating refinery
and importer could make deposits to and withdrawals from its ``bank
account''. All transactions would have to be concluded by the last day
of February after the close of the annual compliance period (2004,
2005, etc.). It would be up to the industry to establish any mechanisms
for linking buyers and sellers. The Agency does not intend to become
involved in this marketplace activity.
We are also proposing to allow refiners to miss the 30 ppm standard
for an individual refinery and to carry forward the credit debt that
would have brought that refinery into compliance in the year the
deficit occurred. This is very similar to provisions proposed today for
auto manufacturers in complying with the averaging provisions Tier 2
standards. Under this provision, the refiner would have to make up the
credit deficit and bring that refinery into compliance with the 30 ppm
standard the next calendar year, or face penalties. This program would
in no way absolve the refiner from having to meet the applicable per-
gallon cap standard. This provision would provide some relief for
refiners faced with an unexpected shutdown or that otherwise were
unable to obtain sufficient credits to meet the 30 ppm standard. We
welcome comment on this provision.
The following Table IV.C.-4 summarizes the compliance dates and
program requirements of this proposed sulfur ABT program. See Section
VI for more specific information, particularly about the dates that the
sulfur caps would apply and the standards that would apply downstream
of the refinery.
BILLING CODE 6560-50-P
[[Page 26060]]
[GRAPHIC] [TIFF OMITTED] TP13MY99.003
BILLING CODE 6560-50-C
v. Could Small Refiners Participate in the ABT Program?
We believe that refiners complying under the small refiner
provisions outlined in the previous section should not be permitted to
use sulfur credits to meet the average standard applicable to their
refineries. We are proposing to exclude small refiners from using
credits to meet the small refiner standards because the small refiner
standards are generally more lenient than the 30 ppm standard and thus
these refiners should have less need for a credit trading program than
the rest of the industry. Furthermore, small refiners, even those
currently producing gasoline near the 30 ppm average, are given an
additional two years (until 2008) to meet the 30 ppm standard compared
to refiners complying under the sulfur ABT program. We want to ensure
that the sulfur levels of the majority of gasoline are reduced on
average, and overall, in 2004 and 2005; permitting small refiners to
meet the more lenient standards through the purchase of credits could
jeopardize that goal by resulting in in-use sulfur levels that are even
greater than the maximum small refiner standard (300 ppm average). If a
small refiner believed it could generate sufficient sulfur credits in
2000-2003, or obtain such credits through purchases from other
refiners, to be able to meet the 30 ppm average and the corporate
averages of 120 ppm in 2004 and 90 ppm in 2005, it should choose not to
participate in the small refiner program and take full advantage of the
sulfur ABT program.
However, small refiners would be permitted to generate and trade
sulfur credits if they reduced sulfur levels early in 2000-2003, per
the requirements outlined above. Furthermore, a small refiner could
sell credits that were generated in 2000-2003 in 2004 and 2005 while at
the same time meeting the small refinery standards. A small refiner
wishing to generate and sell credits would have to establish the
individual refinery sulfur baseline by the deadline specified above for
the ABT program (July 1, 2000) but could wait until June 1, 2002 to
apply for small refiner status. However, the standards assigned to that
refinery (as presented in Table IV.C-3) would be based on the sulfur
level from which credits were generated, not the 1997-98 baseline
sulfur level, since the refiner would have already demonstrated the
ability to meet the lower sulfur level (in this case, 150 ppm or lower
on an annual average basis).
At any time, a small refiner could ``opt out'' of the small refiner
program and, beginning the next calendar year, comply with the
standards in Table IV.C-2. The refiner would have to notify us of this
change in compliance program. Once a small refiner left the small
refiner program, however, we propose that it would not be eligible to
re-enter the small refiner program. We encourage comments on this
provision.
The sulfur ABT program could provide an alternative to offering any
small refiner standards, if small refiners were capable of complying
with the proposed pool average standards and caps in 2004 and 2005 just
as larger refiners could. In this case, all refiners, large or small,
could obtain credits necessary to meet the 30 ppm average standard for
the two intervening years. However, EPA recognizes that this may not be
the best response to the needs of small refiners, and has proposed, as
a result of the SBREFA Panel process, alternate standards in section
IV.C.3.b of this document. Indeed many small refiners expressed concern
during the Panel process that an ABT program would not address their
needs. However, we welcome comments on the pros and cons of using the
sulfur ABT program to provide regulatory relief for small refiners in
lieu of additional regulatory standards unique to small refiners.
vi. What Alternative Implementation Approaches Are Possible?
As we were developing this proposal, members of the oil industry
and others expressed concern that the ABT program as described above
may not be of great value in providing flexibility in complying with
the 30 ppm standard in 2004. Several different concerns have been
expressed.
Industry representatives have asserted that the opportunity to
generate early credits is limited because the proposed lead time would
be too short to implement enough of the refinery operational changes
and capital investments needed to achieve sulfur reductions before
2004. Additionally, the industry is concerned that relying on early
credits generated with what is perhaps the best long-term
technology(ies) is problematic because the preferred technology(ies) is
new and
[[Page 26061]]
does not yet have a proven performance record. Their concern is further
exacerbated by the uncertainty in the diesel fuel sulfur
picture, the MTBE /oxygenates situation developing in California, and
the DI petition discussed below, as well as ongoing state initiatives
to reduce sulfur in gasoline before this action is decided upon.
When credits are generated, there is a fear that those that
generate them will hoard them, particularly refiners that operate
several refineries. And when credits are made available for trade, they
may not become publicly available in enough time for them to be
considered by others in their capital investment planning, so
essentially all refineries would have to take steps to implement 30 ppm
technology by 2004. These issues may be of special concern to those
moderate sized refiners that are too large to qualify as small entities
but do not have enough refineries or refineries of the right gasoline
production volume to internally optimize their operations under the ABT
program.
Given these uncertainties about credit availability, the refiners
may need additional flexibility as a means to provide relief to those
that make a good faith effort to comply but are precluded by
circumstances beyond their control. These may include unanticipated
technological and commercial concerns, credit availability problems, or
force majeure type events.
We have examined this issue of credit availability and our
analysis, which is presented in the Draft RIA, indicates that credits
should be available by 2004 for the 2004/5 phase-in. This is based on
the fact that the 300 ppm cap in 2004 would require that all refineries
with a baseline above 300 ppm reduce sulfur by 2004. And, while they
could choose to just achieve 300 ppm, some would need greater
reductions to comply with the 120 ppm corporate pool average standard
and all would be facing increasingly more stringent requirements in
2005 and beyond. Quite simply, we believe that good business sense
would dictate that once a hardware investment is made the refinery
would shoot for 30 ppm or less. As the analysis shows, this approach
implemented over just three years would yield compliance with the 120
ppm corporate pool average and would generate ample credits. We
requested comment on our analysis in the Draft RIA and the underlying
analytical approach.
EPA is proposing the ABT program described above in order to
increase the refiners'/importers' confidence that they could comply in
2004. And, while our analysis indicates that credits would be available
for 2004/2005 compliance, we realize that the ABT program might not
meet its objective if the industry did not have confidence that credits
would be available in enough time and in sufficient quantities to
enable them to make economically efficient investment decisions. It is
our desire to provide the industry as much flexibility as possible to
ease implementation and phase-in while still meeting the objectives of
the program as described above. Toward that end we are asking for
comment on several variations on the above proposal that might increase
its overall value as a means to provide flexibility in meeting the
proposed standards. These can be divided into four categories: (1)
Modifications to the design elements of the proposed ABT program, (2) a
compliance supplement pool, (3) an allowance-based system, and (4)
reserved credits. As constructed below, the compliance supplement pool,
an allowance-based system, and reserved credits could be implemented in
varying ways to complement the early ABT program. EPA asks comments on
the cost and air quality impact implications of these concepts, which
are described in more detail below.
Potential Modifications to Proposed ABT Program
Modifications to the base program to increase the potential
availability of credits and the time over which these credits could be
used might increase the effectiveness of the proposed ABT program.
These changes could potentially affect both the near-term when the
program was phasing-in and the long term when the 30 ppm standard was
fully implemented.
The 150 ppm trigger value is designed to ``level the playing
field'' between companies with relatively low baselines and those with
relatively high baselines. Those with high baselines could potentially
generate more credits than those with lower baselines, but at a
somewhat greater cost since achieving 150 ppm or less becomes
increasing more difficult with higher sulfur gasoline. Those with
baselines closer to 150 ppm may be able to generate fewer credits, but
generate them more easily.
However, requiring that gasoline be below 150 ppm before credits
could be generated might preclude credit generation from higher sulfur
gasolines that could achieve large, real reductions in sulfur. The size
of the potential credit pool could be increased, perhaps dramatically,
if the trigger were relaxed or eliminated. We would like comment on
trigger values higher than 150 ppm for CG and winter RFG. We would also
request comment on expressing the trigger as a percent reduction from
baseline levels (e.g., 10-25%) rather than as an absolute value. In
addition, we request comment on a hybrid concept under which credits
would be generated for CG and winter RFG depending on initial 1997/1998
baseline sulfur levels (gasoline less than 150 ppm sulfur would
qualify, gasoline between 150 ppm and 350 ppm sulfur would need a 10-15
percent reduction, and gasoline greater than 350 ppm sulfur would need
a 15-20 percent reduction to qualify.) It would be helpful for those
suggesting the ``no-trigger'' approach to also address the issue of
equity among refiners with different baselines.
In combination with comments on the trigger, we also ask for
comment on the proposed phase-in approach. The 300 ppm cap effective
October 1, 2003 and the timing for the 30 ppm average standard would
both be important factors affecting the transition to low-sulfur
gasoline. Our analysis of the potential availability of credits
(discussed above and presented in the Draft RIA) indicates that most of
the credits needed to smooth out the transition would be generated by
low-sulfur winter RFG. Our analysis also assumes that a substantial
number of credits would be generated by refiners investing in
technology capable of producing 30 ppm gasoline prior to 2004 to ensure
compliance with the 300 ppm cap. If refiners take another approach to
meeting the 300 ppm cap (i.e., one that does not result in significant
credit generation), fewer excess credits would be available. However,
as long as some refiners invest in 30 ppm technology before 2004, we
believe sufficient credits would be available. We encourage comment on
our proposed phase-in approach.
Specifically, should the interim phase-in program be extended by an
additional year to provide an even smoother transition to the 30 ppm
standard (e.g., 120/300, 105/210, 90/180 for 2004, 2005, and 2006)?
Should the time frame for the 30 ppm average standard be shifted to
2005, for example, while retaining the 120/300 ppm caps for 2004, to
provide more time for transition to the 30 ppm standard? Should credits
expire after 2007 (as proposed) or would a shorter (or longer) credit
life be appropriate?
We are also seeking comment on a concept that would provide an
incentive to introduce clean technology early. Under this concept, any
sulfur credits generated before 2004 would be banked at a rate of 1.5
to 2.0 times the amount generated, if the annual average for that
[[Page 26062]]
refinery were equal to or less than 30 ppm and if the credits resulted
from the implementation of gasoline sulfur reduction technology
(hardware) not previously used at that refinery. This multiplier would
not be available for credits generated from modest operational changes
or product separation at the refinery or downstream. Calculation of the
un-multiplied credits would be at the refinery level. Neither domestic
refiners nor importers could qualify by segregating product or product
streams either from their refinery(ies) or in the case of importers
from one or more offshore refineries. Also, while refiners/importers
could get sulfur credits under ABT through the use of allowable
oxygenates, these could not be used as part of the basis for achieving
the 30 ppm average. EPA seeks comment on the need for and utility of
such an approach and on whether it is appropriate to encourage
implementation of sulfur control technology in this manner.
Compliance Supplement Pool
To address concerns about credit supply and the timeliness of the
availability of credits, and as a way of providing additional
flexibility, particularly to refiners that encounter unexpected
problems in complying, we are considering the concept of a government-
created and -operated compliance supplement pool for the sulfur ABT
program. Under this concept, the government would create a pool of
additional credits that could be provided to refiners/importers. This
pool would build refiner confidence that a supply of credits would be
available in the market and that credits could in fact be considered as
part of the business plan for 2004-2005 compliance. Credits from this
pool could first be made available in the 2000-2001 time frame and
perhaps in subsequent years and could only be used in 2004-2005. This
program would supplement the 2000-2003 early credit approach under ABT.
There are a number of issues related to implementing such a
program. The size of the pool potentially available for use in 2004 and
2005 would be a critical issue. A larger pool would lower the chance
that a refiner/importer could not get credits, but would reduce the
environmental benefits of the overall program. Clear rules on the
availability of credits would need to be established at the outset so
that refiners/importers could make correct investment decisions. In
addition, EPA would not want a compliance supplement pool to supplant
the need for each refiner to make aggressive efforts to comply in the
appropriate time or for a pool to create a disincentive for refiners to
generate early credits. If credits from early reductions were available
at a reasonable price, EPA would prefer that refiners/importers
purchase such credits rather than looking to a compliance supplement
pool. EPA seeks comment on the appropriate size of a compliance
supplement pool in light of these factors.
The conditions under which a refiner/importer would be eligible for
credits are important. For example, the pool could be made available
only to refiners that had demonstrated that they had made a good faith
effort to comply with the 2004 requirements, but, due to circumstances
beyond their control could not do so. Providing credits to a refiner
that failed to make good faith efforts to procure and install the
technology would create the wrong incentives and could be unfair to
competitors that had invested resources to comply.
Options for distributing credits in the pool might include granting
credits as rewards to those that generated some early reductions,
distribution based primarily or solely on need, equal distribution to
all, pro-rata distribution based on volume, making credits available at
a fixed price, or a credit auction. These approaches could be
considered singly or in combination. For example, the majority of the
compliance supplement pool could be distributed based on need, with due
consideration of the effect of lack of credits on gasoline supply in a
given area. In this case, the remaining portion might be set aside and
auctioned off to provide a price signal and a certain source of
credits.
It would seem that any such compliance pool should be administered
by the government or its agent, but decisions on credit applications
would include a public process. As part of our deliberations on this
concept we need to decide whether credits could be used to meet the
interim corporate pool averages (120/90 ppm) or just the 30 ppm
standard or both. Unlike credits generated by refiners/importers
reducing actual sulfur levels, any credits under this program would
expire after 2005.
Credits from the compliance supplement pool would be government-
created and not derived from actual reductions in gasoline sulfur. If
credits from the compliance supplement pool were distributed at little
or no cost to the receiver, such an approach might create an inequity
between those using credits and those who invested in technology to
reduce sulfur. As a means to address the potential environmental
effects of these government credits and to correct financial inequities
among refiners/importers, we seek comment on a provision that would
require those awarded these credits from the compliance supplement pool
to repay them. The credits to be used for repayment could be generated
internally in 2004-2006, purchased surplus credits from other refiners/
importers, or simply unused credits originally distributed from the
compliance supplement pool. These credits would have to be repaid by
the expiration of the period to close credit balances under the interim
program (2006, taking into account the one-year credit debt carry-
forward provision).
If, as mentioned above, credits were sold at a fixed price or
auction, several issues would arise. Should payment be through monetary
means? If so, what is EPA's authority to engage in such monetary
transactions, and what would be done with any proceeds? There is also
an issue with regard to a requirement to both buy credits for cash and
then also repay with credits. Alternatively, credits could be allocated
based on a determination that a refiner/importer needs the credits, in
conjunction with a determination regarding the refiner's/importer's
ability and willingness to repay the credits to the pool in the future
at a rate greater than 1:1. A credit auction could be held in a similar
way, that being the willingness of the bidder to repay the credits in
the future at a rate greater than 1:1. In these approaches, a refiner/
importer seeking credits might be willing to repay them at a rate of
say 1.2:1, thus essentially offering or bidding a 20 percent premium.
This could be done as a one-time premium or perhaps as a discount at
the time the credits are issued from the pools. Under this system no
money exchange would be required. This would simplify set-up of the
compliance supplement pool, allow refiners to conserve capital for
purposes of capital investment, and create an environmental return for
the compliance supplement pool. In addition, it would result in credits
being provided to refiners/importers that need them, and that are
expected to achieve additional environmental benefits in the future by
generating or purchasing excess credits.
The ``reasonableness'' of the price of credits is critical to any
approach requiring repayment from those entities using these credits.
We request comment and suggestions on ways to establish reasonable
credit prices. For example, as an upper bound, EPA might
[[Page 26063]]
set a credit price based on information received during the rulemaking
on the cost of sulfur removal for different technologies.
EPA also seeks comment on whether refiners/importers that used
credits from the compliance supplement pool should be excused from the
repayment of some or all of the credits if they could demonstrate that
it was not feasible for them to generate credits themselves and
insufficient credits were available at a reasonable price. Finally, EPA
seeks comment on how to ensure that refiners/importers that used
credits from the compliance supplement pool would in fact repay those
credits. One option would be to hold such refiners/importers liable for
failure to meet the sulfur standards over the averaging period during
which they relied on credits from the compliance supplement pool, if
such credits were not repaid in time. EPA seeks comment on this option,
as well as other alternatives that would ensure that compliance
supplement pool credits were repaid.
EPA has some experience with the compliance supplement pool
approach as part of the NO<INF>X</INF> SIP Call (ROTR) discussed in
Section III above. In this process, a compliance supplement pool was
created to address concerns raised by industry about how the
requirements might affect the reliability of the supply of electric
power. The size of the NO<INF>X</INF> compliance supplement pool was
created based on an EPA projection of what compliance shortfalls might
result if problems developed in implementing the control technology.
The NO<INF>X</INF> SIP Call pool may be allocated through direct
distribution based on need or as a reward for early reductions.
Allowance-Based System
In the context of gasoline sulfur, a traditional allowance program
would provide more confidence in the availability of ``credits''
(surplus allowances) by creating sulfur budgets that the industry
(refiners and importers) would be required to meet during the 2004-5
phase-in and perhaps beyond. This budget would be created on a mass
basis using gasoline volume and the applicable regulatory standard.
This budget would then have to be allocated to individual refiners and
importers. If an individual refinery or importer had sulfur levels
below its allocation this would create surplus allowances that could be
traded. Allowances for 2004 and later would be made available in 2001.
This would facilitate the development of a market in allowances, since
those planning to beat the requirements for 2004/5 could market their
allowances early. This could significantly contribute to the certainty
that surplus allowances would be available in time for consideration by
others in their 2004 business planning.
While there are other possibilities, it would seem reasonable to
allocate the budgets to individual refiners/importers in the 2004 and
later time period based upon their individual percentages of the
gasoline market. To be consistent with other aspects of this proposal
this could be done at the corporate level in 2004/5 and at the
individual refinery/importer level in 2006 and later.
One major benefit of such an approach is that refiners/importers
could trade part or all of their 2004 and later allowances for future
use without EPA involvement and those purchasing these allowances could
do so early enough to allow a more orderly and reasoned set of capital
investment decisions. Also, since it would be allowances, not credits,
that would be traded, the seller could be held solely responsible for
failure to meet its budget without involving the buyer. The trading of
allowances would be relatively unencumbered. Allowances could be used
to meet the budgets allocated under the regulatory standard.
This approach would provide increased flexibility and certainty, it
is not clear that a large number of surplus allowances would be
created, since surplus allowances would only exist relative to a budget
based on the 30 ppm standard. Obviously the number of allowances
created in 2004 and 2005 could be increased if the budget were based on
a value higher than the 30 ppm regulatory standard, but this would
require a fundamental change in overall program design. Alternatively,
the number of surplus allowances might be increased if the allowances
program were started earlier. For example, refiners/importers could be
allocated budgets beginning in 2001 based on the product of their 1997/
1998 sulfur baselines in ppm (with appropriate adjustments for RFG
Phase II) and their gasoline volume. Any reductions in the average
sulfur levels or volume from the baseline level during that 2001-2003
time period would result in surplus allowances.
While the idea of pre-2004 allowances has merit, it requires the de
facto implementation of a standard before 2004 (since each refiner's/
importer's budget would in effect be a standard), in order to establish
allowances. And, in contrast to the ABT program where participation is
voluntary and no requirements exist before 2004, an allowance system
would require refiners subject to the allowance program to hold
sufficient allowances to cover their calculated mass emissions starting
in 2001.
In principle, an allowance system could be designed to incorporate
all of the features of an ABT credit system as described above. We are
interested in comment on the viability of such an allowance program as
an alternative to the traditional ABT program and whether such a
program would have to be mandatory for all refiners/importers in order
to be effective. For example, could we structure an allowance program
such that the refiner opts into if it intends to generate or use
allowances or opts out of if it does not? We are also interested in
comment on the parameters of such a program, including the appropriate
budget levels, methods for distributing the budgets to refiners/
importers, and whether allowances could be used to meet the corporate
pool averages, the regulatory standard, or both. As with the ABT
program, we would like to hear your views on the years over which such
a program should apply (e.g., should it start in 2001?, should it
extend beyond 2005?), as well as the other regulatory requirements that
should apply in each year.
We also request comment on whether the allowance program could be
established as a supplement to the credit program. If an allowance
program is implemented along with a compliance supplement pool and/or
early ABT we are interested in comments on how to make credits fully
exchangeable among the programs. We are also interested in comments on
how the programs could/should be integrated. For example, could we let
a refiner/importer generate early ABT credits and at the same time sell
2004-2005 allowances?
Reserved Credits
EPA is also aware of concerns regarding whether refiners that
earned or received credits would make them available in a timely manner
to those that needed them, particularly to small- to mid-sized
refiners/importers. If an adequate number of credits were not available
in a timely manner and for a reasonable price, small- to mid-size
refiners would have no choice but to pursue near term capital
investment to comply in 2004. This might be the appropriate course for
many of these refineries, but we do not think it is appropriate for
them to be precluded from the same flexibility as larger refineries.
We are seeking comment on whether we should require that a set
percentage (e.g., 1015%) of all credits generated in early ABT (2000-
2003), awarded
[[Page 26064]]
through the compliance supplement pool, or earned through the
allowance-based approach either must be retired or offered for trade
outside of the refining company that originally generated or was
granted them. Under such a provision, refiners/importers would be
required to set aside a percentage of credits/allowances they generate,
but could choose whether to retire them or offer them for sale at a
fair market price to another refiner/importer. Regardless of which
option the refiner/importer chose, the results would be beneficial--the
environment would benefit if credits are retired, and credit
availability would improve if the refiner chose to sell credits. We are
also interested in your views as to how this objective might be
accomplished.
EPA also asks comment on the disposition of credits that were put
up for trade one or more times during the period 2004-2006 but did not
sell during that period. This could be the case if a credit owner
offered credits for sale at a price in excess of fair market value and
thus they were not purchased by another party or if credit supply
significantly exceed demand. In this kind of situation, should the
credits be retired or revert to the generator at a full or reduced rate
(e.g., 50%) for future use in compliance determinations? We request
comment on whether such a provision for reserved credits would be
needed by small- to mid-sized refiners and whether the reservation of
10-15 percent of credits would be sufficient to address the concerns.
We also seek comment on whether such a pool should be supplemented by
the government through an auction to ensure that the pool size is
adequate and whether such a pool could be useful in helping to
establish a market price for company owned credits.
b. Refinery Air Pollution Permitting Requirements. As discussed
previously in this document, this proposed program would result in
significant emission reductions from reducing sulfur in gasoline
nationally, through the emission reductions from the current fleet of
vehicles and ensuring the efficacy of new technologies in future
vehicles. In order to achieve this environmental benefit as soon as
possible, we want to be sure the public is aware of the full range of
available methods for expediting permits required for refinery process
changes to reduce gasoline sulfur. Expedited permitting also will
facilitate refiners' ability to generate sulfur credits, under today's
proposed sulfur Averaging, Banking and Trading program, described in
the previous section.
There are two key Clean Air Act permitting programs that refiners
must comply with when making changes at their existing facilities to
implement gasoline sulfur control--the New Source Review (NSR) program
and the Title V operating permit program. Typically, both of these
programs are administered by state/local permitting agencies, with EPA
oversight. While the basic requirements of these programs are dictated
by the Clean Air Act and EPA regulations, the specific requirements of
each state/local permitting program may vary.
We recognize that compliance with these air permitting requirements
is an integral component in any plan to implement the gasoline sulfur
control program under the schedule proposed today. To help refiners
meet the permit requirements, below we discuss the possible mechanisms
to address the substantive requirements of the major NSR and Title V
programs, including possible opportunities to streamline and expedite
the processing of permit applications. Finally, we conclude this
section by discussing possible tools that we are currently testing in
the experimental Pollution Prevention in Permitting Program (P4), which
promotes permit streamlining and flexibility for Title V operating
permits, along with increased pollution prevention activities. We
encourage commenters to provide suggestions for additional
opportunities to streamline the permitting process to accommodate the
implementation of the proposed gasoline desulfurization requirements
for the refining industry sector.
The American Petroleum Institute (API) has sent a letter to EPA
outlining its concerns about the potential impact of various permitting
requirements on the industry's ability to meet future gasoline sulfur
standards, as well as their suggested options for permit
streamlining.<SUP>54</SUP> This letter is included in the docket for
this rulemaking. We are aware that individual refineries are in
different situations regarding the modification to current operation
that would be needed to meet the proposed sulfur standard and the
regulatory requirements applicable to those modifications. Based on the
limited information available at present, some refineries may not
increase emissions significantly, and others may find it most
economical to make on-site emission reductions at the plant to avoid
emission increases. Accordingly, we request comment on the extent to
which the various mechanisms to streamline the permitting process
discussed in this section are in fact needed or useful. We request that
commenters supporting such streamlining describe the specific refiner
situations in which they believe streamlining is needed, and encourage
them to provide any suggestions for additional opportunities to
streamline the permit process to expedite refineries' preparation to
meet the proposed sulfur standards.
---------------------------------------------------------------------------
\54\ Letter from William F. O'Keefe, Executive Vice President,
American Petroleum Institute, to Bruce Jordan, U.S. EPA, Office of
Air Quality Planning and Standards, dated February 12, 1999 (Docket
item IIG-304).
---------------------------------------------------------------------------
i. New Source Review Program.
The New Source Review (NSR) program,<SUP>55</SUP> as it applies to
existing major sources of air pollution, requires that a
preconstruction permit be issued before a source begins construction of
any project that would result in a significant net emissions increase.
With respect to NSR, we anticipate that refineries will fall into one
of two categories if the proposed sulfur standards are implemented. The
first category consists of those refineries that would be able to avoid
major NSR by demonstrating that the physical and operational changes
needed to reduce gasoline sulfur do not result in a net emission
increase of the quantity that would require a major NSR permit. Major
NSR would not apply where: (1) The proposed changes would not result in
an emissions increase at the refinery; (2) the increase is, in and of
itself, less than ``significant'' <SUP>56</SUP>; or (3) the refinery
``nets'' the project out of review. In most cases, even where a
refinery change to accommodate the production of lower sulfur gasoline
does not trigger the major source NSR program, the project still will
be subject to a state's general, or ``minor,'' NSR
program.<SUP>57</SUP> The second category consists of those refineries
that would experience a significant net emissions increase as a result
of process changes necessary to accommodate gasoline sulfur control
and, therefore, will trigger major NSR applicability and the attendant
permit process (e.g., nonattainment NSR or Prevention of Significant
Deterioration). Accordingly, such facilities must obtain a major source
preconstruction permit prior to making these process changes.
---------------------------------------------------------------------------
\55\ See 40 CFR 51.165, 40 CFR 51.166, 40 CFR 52.21, 42 U.S.C.
7475, and 42 U.S.C. 7503.
\56\ EPA's and state/local regulations for major NSR define
``significance'' levels for various pollutants.
\57\ This permitting program applies to the construction or
modification of any stationary source. See 40 CFR 51.160 and 42
U.S.C. 7410(a)(2)(C).
---------------------------------------------------------------------------
As described previously in today's document, there are several
types of process changes refineries could make to meet the proposed
gasoline sulfur
[[Page 26065]]
levels. Traditional sulfur removal technologies include installing a
hydrocracker upstream, or a hydrotreater upstream or downstream, of the
fluidized catalytic cracker (FCC) unit, the unit that produces the
largest fraction of gasoline. There also are improved desulfurization
technologies, CDHydro and CDHDS (licensed by the company CDTECH) and
OCTGAIN 220 (licensed by Mobil Oil). These technologies use
conventional refining processes combined in new ways, with either
improved catalysts or other design changes to maximize gasoline
desulfurization effectiveness with minimal negative effects, such as
octane loss. To different degrees, all these technologies involve the
use of a furnace and, thus, have the potential to increase pollutants
associated with combustion, such as NO<INF>X</INF>, VOCs, PM, CO, and
SO<INF>2</INF>. The addition of these technologies also could result in
equipment leaks of petroleum compounds, which could increase emissions
of VOCs and other pollutants. It also is possible that the increased
removal of sulfur from the gasoline stream might require increased
capacity of a number of refinery processes, such as the sulfur recovery
unit (SRU), which converts hydrogen sulfide into elemental sulfur and
is associated with SO<INF>2</INF> emissions. The emission increase
associated with a desulfurization project will vary from refinery to
refinery, depending on a number of source-specific factors, such as the
specific refinery configuration, choice of desulfurization technology,
amount of gasoline production, and type of fuel used to fire the
furnace.
While we do not have sufficient information at this time to
estimate the number of refineries nationwide that will trigger major
NSR, we believe it could be substantial, given that over 100 refineries
in the country would be required to make desulfurization process
changes under today's proposal. Estimates from one vendor indicate that
its desulfurization process could result in emission increases that are
considered ``significant'' in severe ozone nonattainment areas (i.e.,
greater than 25 tons/year of NO<INF>X</INF> and VOC), which would
trigger major source nonattainment NSR review. Since the significance
threshold generally is lower in certain nonattainment areas (i.e.,
those nonattainment areas classified as serious and above for ozone),
refineries located in those nonattainment areas may be the most likely
to trigger major NSR review. There are many refineries located in ozone
nonattainment areas (e.g., parts of the Gulf Coast).
NSR Applicability Principles
A refiner's ability to avoid triggering major NSR by keeping
emission increases below the major NSR applicability cutoffs will
depend primarily on the case-by-case circumstances of each refinery.
Nevertheless, numerous means by which a source can otherwise legally
avoid major NSR permitting are available to all refineries for
consideration and possible use. In addition, as discussed below, the
Agency is prepared to work with refineries to explore the use of
certain NSR applicability mechanisms (i.e., plant wide applicability
limits or ``PALs''), where appropriate.
To the extent needed, we intend to work with state/local permitting
authorities to provide assistance with the proper application of the
NSR rules on an expedited basis for permits involving refinery
desulfurization projects. We want to ensure that applicability
decisions are made at the earliest possible opportunity and consider
the full spectrum of options available so that a refiner can adjust, or
possibly reconfigure, planned desulfurization projects so as to prevent
significant emission increases and thereby avoid major NSR within the
framework of the current regulations. In addition, timely applicability
decisions will provide added certainty as to the applicable NSR
requirements and, where a major NSR permit is needed, how to best to
expedite the issuance of a permit.
Depending on the nature of the physical or operational changes
necessary to accommodate desulfurization projects, the NSR
applicability process for major modifications can be a complex and time
consuming exercise. The NSR regulatory provisions require that a
proposed physical change result in a significant net emissions increase
in order for the change to be considered a modification and therefore
subject to NSR. We expect that there likely will be questions regarding
which, and how, existing emission units are affected by the change,
including how to calculate the magnitude of the emissions change for
major NSR applicability purposes. We are committed to working with
refiners and state/local air pollution control agencies to clarify and
ensure that, in applicability analyses for gasoline desulfurization
projects, only those emissions increases resulting from the physical or
operational changes necessary to comply with gasoline desulfurization
requirements are included in the applicability analysis.
In doing an applicability analysis for major NSR, refineries should
analyze their past, current, and future operations and emissions to
determine whether it is possible to avoid major NSR based upon their
facility-specific circumstances, including the use of previous emission
reductions at the facility to ``net'' out of NSR. Similarly, sources
might avoid NSR by using Plantwide Applicability Limits (PALs) to cap
emissions. Emissions netting is a term that refers to the process of
considering certain previous and prospective emission changes at an
existing major source to determine if a net emissions increase will
result from the proposed new project. Where the sum total of creditable
increases and decreases across the refinery is less than significant,
major NSR would not apply. In addition, if the proposed emissions
increase from a proposed project (in this case, a project undertaken to
reduce gasoline sulfur levels) is by itself, without considering any
decreases, less than significant, major NSR would also not apply.
PALs may provide another opportunity for refineries to avoid
triggering major NSR applicability. The voluntary, source-specific PAL
is a straightforward, flexible approach to determine whether changes at
an existing major source of air pollution result in a significant net
emissions increase. By restricting (or ``capping'') a facility's
emissions to a level representative of current actual emissions, a PAL
allows a source to change operations and equipment without having to
undergo major NSR permitting. For example, as long as refinery
activities do not result in emissions above the PAL cap level, the
refinery would not be subject to major NSR, regardless of the nature of
the activity. Under a PAL, instead of a case-by-case assessment of
whether a proposed change is subject to or excluded from major NSR, the
refinery manager knows that as long as the refinery stays within its
emissions cap, major NSR will not be triggered. Production units may be
started and stopped, production lines reconfigured, and products
changed and revamped without delay from major NSR permitting.
Because of these advantages, the Agency previously has proposed to
incorporate PALs in all of its NSR regulations (see 61 FR 38250, 38264,
July 23, 1996), and has worked with state permitting authorities to
develop PALs for individual sources. Likewise, the Agency is committed
to exploring the propriety of authorizing PALs for refineries subject
to the final gasoline
[[Page 26066]]
sulfur control rules. We are examining our authorities to assure they
support these approaches. Should it be necessary, EPA stands prepared
to issue final regulations to make PALs available to sources making
changes to comply with these gasoline sulfur control requirements.
We are further committed to investigating with affected refineries
whether a PAL might be a valuable tool for managing a number of other
Clean Air Act requirements. For instance, depending on the relevant
state rules, a PAL also could include terms that allow facility changes
to be made without triggering minor NSR. It is our experience that, in
the cases where PALs have been applied, both industry and air pollution
regulators have benefitted from the regulatory certainty and simplicity
a PAL provides. The use of a PAL can enhance a refinery's ability to
make appropriately designated changes quickly, without having to
evaluate a baseline for each modification, determine the
contemporaneous increases and decreases, and engage in other time-
consuming netting procedures required under the major NSR program on a
case-by-case basis. A PAL also can encourage a source to reduce
emissions voluntarily (e.g., from pollution prevention or other
emission reduction efforts), so that it has sufficient room for growth
(under the PAL) to accommodate increased emissions from future process
changes.
Approaches to Expedite the Processing of NSR Permit Applications
Notwithstanding the availability of the major NSR applicability
principles and mechanisms discussed above, we anticipate that it will
not be possible for all refineries subject to the gasoline
desulfurization requirements to prevent significant emission increases
and avoid major NSR. Additionally, even those facilities that are able
to avoid major NSR likely will be required to obtain a state minor NSR
permit. For facilities subject to major NSR, the timing of permit
issuance could vary depending on many factors, including the complexity
of process changes, the type of permit required, air quality impact,
control technology reviews, and the state's overall permit workload. It
is not uncommon for issuance of a major source preconstruction permit
to take six to 12 months from the receipt of a source's complete permit
application. In addition, determining the applicable permitting
requirements for refineries is often complex, due to the wide array of
emission points and processes.
To help expedite the NSR permitting process, we suggest the
following streamlining approaches. Since state/local governments
typically are the lead permitting agencies, we will work closely with
them on any of these efforts. We solicit comments on the efficacy of
these approaches and opportunities for additional streamlining. We are
particularly interested in understanding whether these permit
streamlining approaches could enable refineries to begin voluntarily
producing lower-sulfur gasoline earlier than the compliance dates
proposed today, so that the environmental benefits may be realized
sooner than 2004 and ABT credits (see previous Section) could be
generated.
<bullet> Federal guidance on streamlining certain major NSR
permitting requirements, such as control technology and compliance
parameters. Although the major NSR permit is a case- and source-
specific evaluation, we could provide guidance on certain aspects of
refinery projects designed to reduce fuel sulfur that share a common
requirement or circumstance. For example, for refinery projects
permitted in the same time frame, the Lowest Achievable Emission Rate
(LAER) requirement should be the same for identical emissions units
regardless of the location of the individual refinery. In this case, we
could define for the industry what emissions levels would be expected
to meet LAER and provide model permit conditions, including appropriate
monitoring, record keeping, and reporting. Although Best Available
Control Technology (BACT) determinations require case-by-case
considerations, we also could issue guidance setting out a level of
emissions that, in our view, satisfies BACT for the class or category
of emission units associated with refinery desulfurization. We expect
that providing BACT and LAER guidance would help to expedite major
source permitting and add more certainty to the permit process.
Consequently, for any applications processed within a discrete time
frame, a presumptive federal LAER and/or BACT could be established.
<bullet> Availability of offsets. The major NSR permitting
provisions require that a significant emissions increase of
nonattainment pollutants must be offset by emission reductions from
other sources. We solicit comment on the need for offsets by refineries
making modifications to meet the proposed sulfur standards, and the
expected size or volume of any offsets that may be necessary. In
addition, to the extent offsets may be useful or necessary, EPA
requests comment on whether on-site emissions reductions at the
refinery could be used to avoid the expected emissions increases that
would otherwise occur. We will work with refiners and state/local air
pollution control agencies to explore options and possible new
approaches that would help ensure the availability of offsets. For
example, it may be possible to establish pre-funded offset pools,
designed specifically for offsetting emissions increases resulting from
gasoline desulfurization projects. We believe that the establishment of
preapproved offset banks or pools could greatly expedite permitting in
nonattainment areas.
To help give certainty that offsets will be available, we seek
comment on how and whether emission reductions resulting from vehicles
operated on low sulfur gasoline could be used as offsets by refineries
implementing gasoline sulfur controls. For example, it may be possible
for a state, within a given nonattainment area, to set aside a portion
of the emission reductions expected from vehicles operating on low
sulfur gasoline and dedicate those reductions for use as offsets by
refineries. These offsets would have to meet all the criteria currently
established for being creditable, and could not be ``double-counted''
by the state for other SIP planning purposes. We request comment on the
ability of emission reductions from the use of low sulfur gasoline to
meet the Clean Air Act's criteria for creditable offsets for NSR
purposes. Since securing offsets can be a significant challenge to
sources undergoing major NSR permitting in nonattainment areas, we
believe this approach could substantially speed up, and add certainty
to, the permitting process. We believe this approach is worth
evaluating, given the enormous emission reductions resulting from the
use of low sulfur gasoline, and given that some refineries will trigger
major NSR solely as a result of the process changes needed to produce
this new gasoline. Finally, EPA seeks comment on whether providing the
ability to use the emissions reductions resulting from the use of low
sulfur gasoline in vehicles as offsets for refineries producing low
sulfur gasoline can be limited to this specific situation.
Specifically, EPA requests comment on the concern that providing this
option to refineries would allow the use of such emissions reductions
as offsets for other stationary sources.
As discussed above, we believe that refineries in ozone
nonattainment areas could be the most likely to trigger major NSR
review, based on net emission increases of NO<INF>X</INF> and/or VOCs.
The proposed Tier 2/gasoline sulfur control program is expected to
result in over
[[Page 26067]]
500,000 tons of NO<INF>X</INF> reductions and over 100,000 tons of VOC
reductions nationwide in 2004 (the first year of implementation), as
well as substantial reductions in particulate matter and sulfur
dioxide, as described elsewhere in this document and the draft
Regulatory Impact Analysis.<SUP>58</SUP> In a given nonattainment area,
the program could result in hundreds to thousands of tons of
NO<INF>X</INF> and VOC reductions, depending on the inventory of cars
and light-trucks in the area. For example, for the New York
metropolitan area, EPA projects NO<INF>X</INF> emission reductions of
7,344 tons and VOC emission reductions of 1,285 tons in 2004 resulting
from the proposed Tier 2/gasoline sulfur control program.<SUP>59</SUP>
We anticipate that only a small fraction of these total emission
reductions in a given area would be needed for use as offsets for
refineries implementing gasoline sulfur control projects.
---------------------------------------------------------------------------
\58\ Although these emission reduction estimates are for the
combined Tier 2 emission standards/gasoline sulfur control program,
in 2004, nearly all these emission reductions would be attributed
solely to vehicles fueled by low sulfur gasoline, since vehicles
meeting the Tier 2 emission standards would comprise only a small
fraction of the vehicle fleet.
\59\ See draft Regulatory Impact Analysis, Chapter III.
---------------------------------------------------------------------------
<bullet> Model permits and permit applications. It may be possible
to develop an individual, or series of, model permits or permit
applications for gasoline desulfurization projects. Rather than each
individual refinery having to develop its own permit application from
scratch, a generic permit application form could be developed to
address common issues. To file a major source application, a refinery
would only need to fill in the blanks as they may relate to case-
specific assessments, such as air quality impacts. Similarly, a model
permit could contain all necessary compliance measures avoiding the
time spent in developing individual permit conditions. Model permits or
permit applications would serve as templates, thereby eliminating much
of the time and uncertainty associated with processing each
application.
<bullet> EPA refinery permitting teams. We could establish a team
of experts to be available as a resource, as needed, to refineries and
state/local agencies to troubleshoot permitting issues that may develop
with individual applications. The team could be made up of EPA
permitting experts empowered to make decisions and resolve issues
quickly.
In addition to the above opportunities to streamline the permitting
process, we encourage states to process a refinery's request to
implement changes at a facility to meet gasoline desulfurization
requirements as a priority and on an expedited basis. Priority
treatment, in combination with the above opportunities to streamline
the process, would ensure that permit applications associated with
gasoline desulfurization changes are processed as expeditiously as
possible. Given the enormous environmental benefits that we estimate
would be achieved as a result of the proposed gasoline sulfur control
requirements, we believe such expedited and special processing is
appropriate.
ii. Title V Operating Permit Program.
We recognize that the changes to be made by refiners to implement
gasoline sulfur controls typically would involve not only NSR
preconstruction permitting requirements but also those of the title V
operating permit program. Title V requires owners or operators of
``major'' and certain other sources to obtain an operating permit--a
document that identifies all emissions units, their applicable
requirements as developed in accordance with the Clean Air Act, and
monitoring and other permit conditions to provide a reasonable
assurance of compliance with each of the applicable requirements on an
ongoing basis. Most of the refiners likely are ``major'' sources
subject to title V, due to their plant-wide level of emissions. As with
other process changes, prior to implementing gasoline sulfur controls,
refiners would need to work with their state, local, or tribal
permitting agency to determine what requirements apply and what changes
might be required to the source's title V permit application or permit
(if one has been issued).
A critical element of any successful title V permitting strategy to
accomplish the necessary desulfurization is how best to integrate the
procedural and substantive requirements of the title V and NSR permit
programs. We believe the title V permitting process provides an
excellent opportunity to accomplish this integration and to impart
greater certainty into the ultimate approvability of a gasoline
desulfurization project under both permit programs. Depending on a
specific permitting authority's program and when the desulfurization
activity would occur relative to the issuance of the refinery's initial
title V permit, the NSR preconstruction permit and the title V permit
processes might be done in parallel or in sequence.
Where the title V permit is issued before the desulfurization
activity commences, this permit must be updated before operation of the
changes that would also be subject to NSR. In this case, we suggest
that the preconstruction permit review process, managed by the
permitting authority, be merged with the title V permit revision
process so as to satisfy the procedural safeguards and the same
substantive requirements of the NSR and title V programs at the same
time.<SUP>60</SUP> If this is done, the title V permit may be
administratively amended to incorporate the contents of the NSR permit
prior to operation of the desulfurization process changes. Where the
appropriate NSR action (major or minor) approving the desulfurization
changes precedes the issuance of a source's initial title V permit, the
applicable NSR process can still be ``enhanced'' to address title V
obligations. Here, in order to determine approvability under both title
V and NSR, the permitting authority can issue a separate title V permit
specifically for the desulfurization project in advance of the title V
permit that will be issued subsequently for the rest of the site.
Finally, if issuance of the title V permit issuance for the entire
source would precede the NSR construction, depending on several
factors, the permitting authority could conduct simultaneous permit
processes to accomplish preconstruction approval of the desulfurization
project and title V approval for the operation of the project in
conjunction with the entire refinery source.
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\60\ The concept of a merged NSR/title V process refers to the
combination of the title V review process with any otherwise
applicable state preconstruction review process, where such process
satisfies the procedural requirements of the title V's permit
revision, permit review, and public participation provisions.
Example state review processes that may be eligible for merger
include, but are not limited to, preconstruction review of major or
minor NSR, source-specialized State Implementation Plan revisions,
and procedures implementing section 112(g) of the Clean Air Act.
Under a merged process, activities are only presented in a public
forum once, rather than in sequence, to avoid duplication of
process. Upon completion of the merged process, a successful project
would have met all federal permitting requirements, including review
by the public, EPA and affected States, and opportunities for EPA
objection and public petition, and can implement both processes
without delay. Qualifying activities that have received
preconstruction review permits meeting the requirements of 40 CFR
70.7(d)(1)(v) may be incorporated into title V permits as
administrative permit amendments.
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Beyond synchronizing when the two permit programs would be
implemented, we recommend that permitting authorities take approaches
in the substantive permitting of the desulfurization projects that will
both assure compliance with all applicable air requirements and result
in a more flexible and efficient permit design. We encourage that the
approaches in the
[[Page 26068]]
title V ``White Papers'' <SUP>61</SUP> be considered to focus both the
content of title V applications and permits. In particular, we
recommend that permitting authorities and owners or operators of
refineries consider the ``streamlining'' of multiple applicable
requirements applying to the same project. Under the streamlining
concept, where multiple applicable requirements apply to the same
emission unit(s), the permitting authority may develop one emission
limit (with associated monitoring, recordkeeping, and reporting) that
assures compliance with all applicable requirements. For example,
several aspects of the control requirements necessary to implement our
maximum available control technology (MACT) and new source performance
standards (NSPS) requirements, State Implementation Plan (SIP), and NSR
programs (including both major and minor NSR, as applicable) could be
considered for streamlining per White Paper Number 2. Where successful,
this streamlining will result in a single control requirement (or
emission limit), coupled with appropriate monitoring, recordkeeping,
reporting, and testing requirements that yield a reasonable assurance
of compliance for all subsumed requirements.<SUP>62</SUP>
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\61\ White Paper for Streamlined Development of Part 70 Permit
Applications, Lydia N. Wegman, Deputy Director, Office of Air
Quality Planning and Standards, U.S. EPA, July 10, 1995 and White
Paper Number 2 for Improved Implementation of the Part 70 Operating
Permits Program, Lydia N. Wegman, Deputy Director, Office of Air
Quality Planning and Standards, U.S. EPA, March 5, 1996.
\62\ See Section II.A. of White Paper Number 2.
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We also are willing to explore applying to the varying situations
of sulfur removal at refineries certain permit design approaches that
have previously been limited to some permitting pilot projects. In
particular, in partnership with permitting authorities, we have been
working with selected industries at specific sites to conduct Pollution
Prevention in Permitting Project (P4) pilots. These projects respond to
the Administration's goals for reinvention in order to implement
environmental permit programs in a more streamlined fashion, while
assuring required levels of environmental protection. Based on our
prior experience with these regulatory reinvention projects, permit
design options for refiners implementing gasoline desulfurization
projects might include, but are not limited to, any of the following
approaches:
<bullet> Advance approvals of certain types of changes in title V,
including those subject to minor NSR.# <SUP>63</SUP>
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\63\ Advance approval means that a particular project (or class
of projects) like one to accomplish gasoline desulfurization and its
support activities would be preapproved for title V purposes before
its actual construction, provided that the terms of the title V
permit governing the advance approval are met. The Agency has a
possible non-binding interpretation of the Title V regulations that
would provide for the advance approval of certain new emission units
and control devices. See 63 FR 50279, 50315-20 (Sept. 21, 1998)
(Section IV.L., Permitting and Compliance Options/Change Management
Strategy, in National Emission Standards for Hazardous Air
Pollutants for Source Categories: Pharmaceuticals Production).
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<bullet> Provisions that where met would prevent another
requirement from applying (e.g., plant wide applicability limits (as
noted above) to address potential major NSR applicability).
<bullet> Model permit conditions, such as a presumptive,
streamlined approach to meet all applicable control technology
requirements to expedite permitting decisions, where applicable.
<bullet> Adding terms to a title V permit so as to preauthorize a
faster permit revision process where one is necessary to add further
details within an approved approach (e.g., the minor instead of
significant permit modification process).
<bullet> Permitting the worst-case emissions scenario to address
all applicable requirements applying in a range of possible operating
scenarios or to prevent certain requirements from applying.
<bullet> Permitting alternative compliance options where an owner
or operator of a source needs the flexibility to vary the compliance
approach with changing refinery conditions.
<bullet> Using pollution prevention approaches to facilitate
compliance with applicable requirements and/or required permit terms.
We recognize that the situations for refineries affected by the
proposed gasoline sulfur control program can vary widely (e.g., sulfur
level in the gasoline, size of the stream, air quality status of the
area, etc.), and that the actual permit approach for an individual
refinery may be a combination of certain options outlined above and
previously for streamlining NSR. Any title V approach must, however,
assure compliance with all applicable requirements linked to the
necessary construction and provide a meaningful opportunity for all
affected parties to review the appropriateness of a proposed approach
as it would apply to a particular site. For example, where new
desulfurization units would be required and would be well controlled so
as to result in emissions below the threshold for triggering major NSR,
then an advance approval of minor NSR requirements in combination with
certain operationally limiting conditions might be an appropriate
strategy. Where the addition of such a unit would trigger major NSR,
then the strategies that combine the reviews and streamline the
requirements of both title V and major NSR offer promise. In a few
cases, reblending of high sulfur gasoline blend stocks, blending in low
sulfur oxygenates, or using sweeter crude oil might be sufficient to
achieve the necessary sulfur reductions and require few, if any,
additional title V permit terms to implement.
iii. EPA Assistance to Explore Permit Streamlining Options and
Solicitation of Comment.
We are committed to exploring the possible approaches described
above. Accordingly, if there is sufficient interest and need, as
expressed in comments on this proposed rule, within the refining
industry and among state permitting authorities, we will hold a P4/
flexible permit workshop focused on the permitting of the refining
industry arising from the gasoline desulfurization program.
Additionally, should a permitting authority and owners or operators of
affected facilities within a common jurisdiction express a desire for a
specific flexible permit project aimed at the development of permit
language to facilitate refinery activities to reduce gasoline sulfur,
then in accordance with already established principles for initiating
similar permit projects, we would be willing to work with a designated
refinery. We intend that the approaches derived from such efforts could
then serve as a template as needed for use by other refineries and
state permitting authorities, provided the approaches are modified to
conform with all applicable state title V and NSR requirements.
We believe that application of one or more of the approaches
described in today's document would reduce any burden of meeting NSR
permit requirements and revisions to title V permit applications or
permits to incorporate the gasoline desulfurization requirements
adopted in the final rule. However, the use of one or more of these
approaches would have accompanying resource requirements. For example,
it is possible that the initial resources required to establish a PAL,
and the attendant monitoring, recordkeeping and reporting requirements,
could involve as much time and resources as associated with a typical
NSR permit. However, once established, a PAL could provide more
flexibility and minimize future resource demands than more traditional
permit approaches. Accordingly, we request that permitting authorities,
owners or operators of affected facilities, and the public comment on
whether use of the
[[Page 26069]]
approaches described in today's document will achieve appropriate
streamlining of controls and requirements arising out of this rule and
meet the objectives of the NSR and title V permitting programs.
c. Should Hardship Relief Be Available? Elsewhere in this document
(Section IV.C.3.b.), we propose a hardship provision that would apply
to small refiners. EPA seeks additional comment on whether it should
adopt a hardship provision allowing for compliance with standards less
stringent than those proposed today during the early years of the
program. While EPA believes that it is feasible for most refiners to
meet the proposed standard by 2004, the Agency is seeking comment on
whether it may be appropriate to allow refiners with substantial
economic hardship circumstances to apply for relief from compliance
with the sulfur standard for a limited time period.
Such a hardship provision would need to contain appropriate
criteria to limit the provision to a narrowly drawn set of
circumstances. This might include criteria such as ability to raise
capital to make necessary refinery investments in time for 2004, given
the current size and ownership of the refinery, the physical
characteristics of the refinery, the volume of gasoline at issue,
ability to purchase credits to comply, and any efforts by the refiner
to limit sulfur that are already underway or have been attempted. The
provision would also need to contain criteria to ensure that it would
not undermine the emissions reduction goals of the Tier 2/sulfur
program and would not allow large amounts of gasoline with sulfur
levels significantly above 30 ppm into the market. For example, this
might include a volume limit on the use of less stringent standards in
hardship circumstances. It would also need to include an endpoint, so
that the relief is short-term and the refinery would then have to meet
the same standard as all other refineries. For example, EPA would not
expect that hardship relief will be needed beyond 2009.
Under such a provision, we expect that refiners would be subject to
a reasonable level of control, albeit less stringent than the proposed
standards. At a minimum, sulfur levels at a particular refinery should
not be permitted to be higher than 1997-1998 baseline levels and in no
event should the average sulfur level be greater than 300 ppm. EPA also
seeks comment on the appropriate time frame for allowing relief in
hardship circumstances. EPA solicits comments on whether any refiners
would encounter significant hardship in meeting the proposed standard.
EPA solicits comment on the implications of any such hardship provision
on small refiners and its relationship to the small refiner provisions
proposed in this document. Finally, EPA seeks comment on the
implications of a hardship provision on the proposed ABT program.
5. Consideration of Diesel Fuel Control
As explained in Section IV.B. above, the proposed Tier 2 standards
would apply to both gasoline- and diesel fuel-fueled vehicles.
Currently very few light-duty vehicles operate on diesel fuel. Given
what we know about gasoline vehicles, we believe it is reasonable to
anticipate that the use of exhaust aftertreatment devices may be
required, and that these technologies may have similar sensitivities to
sulfur that the catalysts used on gasoline engines have. However, we do
not yet have enough information to be able to conclude that diesel
sulfur levels need to be reduced in the same time frame that Tier 2
vehicles are introduced. A decision to require reductions in diesel
sulfur levels could have significant implications for the refining
industry, both because it would likely require capital expenditures
over and above the significant costs that would be incurred in
controlling gasoline sulfur, and because for some refiners concurrent
control of gasoline and diesel sulfur may be the most economical
solution. Hence, due to the implications for automotive manufacturers
and for diesel fuel producers, a decision on whether to require diesel
fuel sulfur reductions needs to be made as soon as possible.
Automobile and diesel engine manufacturers and state air quality
agencies have recently asked us to set new fuel quality requirements
for diesel fuel used in highway vehicles.<SUP>64</SUP> The
manufacturers believe that such requirements, especially controlling
diesel fuel sulfur content to very low levels, could produce large
environmental benefits by enabling dramatically lower-emitting diesel
engines equipped with exhaust aftertreatment devices. The viability of
such technologies would, of course, affect the feasibility of the
proposed Tier 2 emission standards for diesel vehicles. Currently,
highway diesel fuel is regulated under standards we set in 1990. These
standards, which became effective in 1993, limit the concentration of
sulfur in diesel fuel to a maximum of 500 ppm; they also control the
amount of aromatic compounds in the fuel (55 FR 34120, August 21,
1990).
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\64\ See the following contained in the docket for this
rulemaking: Letter from Robert J. Eaton, Chrysler Corporation, Alex
Trotman, Ford Motor Company and John F. Smith, Jr., General Motors
Corporation, to Vice President Al Gore, July 16, 1998; ``STAPPA/
ALAPCO Resolution on Sulfur in Diesel Fuel,'' October 13, 1998;
Letter from S. William Becker, Executive Director of STAPPA/ALAPCO,
to Carol Browner, Administrator of U.S. EPA, October 16, 1998;
Letter from Jed R. Mandel, Engine Manufacturers Association, to
Margo T. Oge, Director, Office of Mobile Sources, EPA, November 6,
1998.
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Diesel engine manufacturers have argued that implementing Tier 2
standards without concurrent diesel fuel changes would be unfair to
diesels because diesel fuel quality is worse than gasoline fuel
quality, especially considering that the Tier 2 rulemaking includes
proposed improvements in gasoline quality to enable advanced three-way
catalytic converters. Some argue that, beyond fuel-neutrality
considerations, diesel fuel quality improvement is needed to combat
global warming because it will facilitate the marketing of more diesel
vehicles and, in their opinion, thereby reduce emissions of global
warming gases. Others counter that such benefits are illusory and that
diesel vehicles should be discouraged because diesel exhaust is a
serious health hazard, a hazard that improvements in fuel quality would
do little to mitigate.
To address the issue of diesel fuel changes, we will issue an
Advance Notice of Proposed Rulemaking (ANPRM) in the near future. We
encourage interested parties to review and comment on the issues raised
in the ANPRM. On the basis of this information, if appropriate, we plan
to publish a proposal on standards for diesel fuel in the next several
months. This would provide some degree of clarity regarding our plans
in this area in time to help affected industries to then make their own
plans without undue disruption. This is especially important for the
petroleum refining industry in planning capital outlays to accomplish
sulfur reduction in gasoline, and potentially diesel fuel, at the most
economical point in the refining process.
Several diesel vehicle manufacturers have raised the concern that
unless or until lower sulfur diesel fuel is available, the sulfate
component of diesel PM may be particularly difficult to control to very
low emission levels. They have encouraged us to expr