Control of Emissions of Air Pollution From Nonroad Diesel Engines
and Fuel [[pp. 28427-28476]]
[Federal Register: May 23, 2003 (Volume 68, Number 100)]
[Proposed Rules]
[Page 28427-28476]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr23my03-38]
[[pp. 28427-28476]]
Control of Emissions of Air Pollution From Nonroad Diesel Engines
and Fuel
[[Continued from page 28426]]
[[Page 28427]]
than 10 ppm sulfur. Refiners producing only high sulfur distillate
today should have an added advantage in meeting a 15 ppm sulfur cap for
nonroad fuel over that for highway fuel. They would be able to design
their hydrotreater from the ground up, while most refiners producing 15
ppm diesel fuel for highway use will be trying to utilize their
existing 500 ppm hydrotreaters, which may not be designed to be
revamped to produce 15 ppm fuel in the most efficient manner.
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\260\ ``Highway Diesel Progress Review,'' EPA, June 2002,
EPA420-R-02-016.
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Based on our review of the limited catalyst performance data in the
published literature and the one set of confidential data submitted, we
believe that the projections of the more optimistic vendors are the
most accurate for the 2010 timeframe given this additional leadtime.
For example, the confidential commercial data indicated that five ppm
sulfur levels could be achieved with two-stage hydrotreating at
moderate hydrogen pressure despite the presence of a significant amount
of light cycle oil (LCO). The key factor was the inclusion of a
hydrogenation catalyst in the second stage, which saturated many of the
poly-nuclear, aromatic rings in the diesel fuel, allowing the removal
of sulfur from the most sterically hindered compounds. In addition,
refiners that are able to defer production of 15 ppm highway diesel
fuel through the purchase of credits, as well as refiners producing 15
ppm nonroad in 2010, would have the added benefit of being able to
observe the operation of those hydrotreating units starting up in 2006.
This should allow these refiners to be able to select from the best
technologies which are employed in the highway program.
In addition, a number of alternative technologies are presently
being developed which could produce 15 ppm fuel at lower cost.
ConocoPhillips, for example, has developed a version of their S-Zorb
technology for diesel fuel desulfurization. This technology utilizes a
catalytic adsorbent to remove the sulfur atom from hydrocarbon
molecules. It then sends the sulfur-laden catalyst to a separate
reactor, where the sulfur is removed and the catalyst is restored.
Unipure is developing a process which selectively oxidizes the sulfur
contained in diesel fuel. This process have the advantage that the
sulfur containing compounds which are most difficult to desulfurize via
hydrotreating are quite easily desulfurized via oxidation. Finally,
Linde has developed a method which greatly improves the concentration
of hydrogen on hydrotreating catalysts. This process promises to
greatly reduce the reactor volume necessary to produce 15 ppm diesel
fuel.
These three new technologies are at various stages of development.
This is discussed in more detail in the next section. Due to the
projected ability of these technologies to reduce the cost of meeting a
15 ppm sulfur cap and the leadtime available between now and 2010, we
project that 80% of the new volume of 15 ppm nonroad diesel fuel would
be produced using advanced technologies.
7. Has Technology to Meet a 15 ppm Cap Been Commercially Demonstrated?
EPA just completed a review of refiners' progress in preparing to
produce 15 ppm highway diesel fuel.\261\ The information we obtained
during that review confirm the projections we made in the HD 2007
program--refiners are technically capable of producing 15 ppm sulfur
diesel fuel using extensions of conventional technology and, in fact,
they are moving forward with their plans to comply with the program.
Thus, we believe there are no technological hurdles to producing 15 ppm
diesel fuel.
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\261\ Ibid.
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The European Union has also determined that diesel fuel can be
desulfurized to meet a sulfur cap in the range of 10-15 ppm. Europe has
established a 10 ppm sulfur cap on highway diesel fuel, effective in
2009, with plans underway for a 10 ppm sulfur cap for nonroad diesel
fuel soon thereafter. As with our standards, Europe's 10 ppm cap
applies throughout the distribution system. However, fuel tends to be
transported much shorter distances in Europe. Therefore, we believe
that both the 10 and 15 ppm sulfur caps will require refiners to meet
the same 7-8 ppm sulfur target at the refinery gate. Given this, the
European standard will require the same technology as that required in
the U.S. Most European diesel fuel must meet a higher cetane number
specification than U.S. diesel fuel, which causes it to be
predominantly comprised of straight run material. This material is
easier to desulfurize to sub-15 ppm levels using conventional
hydtrotreating technology. In some European countries, nonroad diesel
fuel is the same as heating oil and contains significant amounts of
cracked material. Thus, on average, it should be easier for European
refiners to meet a 10 ppm sulfur cap with their highway diesel fuel
than in the U.S. As the 10 ppm cap is extended to nonroad diesel fuel,
the stringency of the European standard will be much closer to that of
a 15 ppm cap here in the U.S.
We have met with a number of diesel fuel refiners to learn about
their plans to produce 15 ppm highway diesel fuel by the June 2006
program compliance date. Since the 15 ppm diesel fuel sulfur standard
was established based on the use of extensions of conventional diesel
desulfurization technologies, diesel fuel refineries are well
positioned to make firm plans for implementation by 2006. Our review
has found that this is exactly what refiners are doing. We are very
encouraged by the actions some refiners have already taken in terms of
announcing specific plans for low sulfur diesel fuel production. It may
still be early in the process, but virtually all refiners are already
in the stage of planning their approach for compliance. Thus, the
refining industry is where we anticipated it would be at this point in
time. Moreover, some refining companies are ahead of schedule and will
be capable of producing significant quantities of 15 ppm sulfur diesel
fuel as early as next year. Thus, we expect that the capability of
conventional hydrotreating to produce 15 ppm diesel fuel in refinery-
scale quantities will be demonstrated in the U.S. by the end of 2003.
Phillips Petroleum is currently in the process of designing and
constructing a commercial sized S-Zorb unit to produce sub-15 ppm
diesel fuel at their Sweeney, Texas refinery. This plant is scheduled
to begin commercial operation in 2004. This would provide refiners with
roughly 3 years of operating data before they would have to decide
which technology to use to meet the 15 ppm nonroad sulfur cap in 2010.
This should be enough operating experience for most refiners to have
sufficient confidence in this advanced process to include it in their
options for 2010 compliance. Based on information received from
Phillips Petroleum, we estimate that this technology could reduce the
cost of meeting the 15 ppm cap for many refiners by 25 percent.
Linde has also developed a new approach for improving the contact
between hydrogen, diesel fuel and conventional desulfurization
catalysts. Linde projects that their Iso-Therming process could reduce
the hydrotreater volume required to achieve sub-15 ppm sulfur levels by
roughly a factor of 2. Linde has already built a commercial-sized
demonstration unit at a refinery in New Mexico and has been operating
the equipment since September 2002. Thus, refiners would have 4-5 years
of operating data available on this process before they would have to
decide which technology to use to meet the 15 ppm nonroad sulfur cap in
2010. This should be ample operating experience for
[[Page 28428]]
essentially all refiners to include this process in their options for
2010. Based on information received from Linde, we estimate that this
technology could reduce the cost of meeting the 15 ppm cap for many
refiners by 40 percent.
Finally, Unipure Corporation is developing a desulfurization
process which oxidizes the sulfur atom in diesel fuel molecules,
facilitating its removal. This process operates at low temperatures and
ambient pressure, so it avoids the need for costly, thick walled,
pressure vessels and compressors. It also consumes no hydrogen. Thus,
it could be particularly advantageous for refiners who lack an
inexpensive supply of hydrogen (e.g., isolated or smaller refineries
who cannot construct a world scale hydrogen plant based on inexpensive
natural gas). However, the oxidant is very powerful, so specialized,
oxidation resistant materials are needed. Unipure has demonstrated its
process at the pilot plant level, but has yet to build a commercial
sized demonstration unit. However, time still remains for this to be
done before refiners need to make final decisions for their 2010
compliance plans. Thus, while more uncertain than the other two
advanced processes, the Unipure oxidation process could be selected by
a number of refiners to meet the 2010 15 ppm cap. Based on inputs from
Unipure, we estimate that their process could reduce the cost of
meeting the 15 ppm cap for roughly one-fourth of all refineries by 25-
35 percent.
The savings associated with each technology varies with the size,
location and complexity of the refinery. However, on average the Linde
process appears to have the potential reduce the cost of desulfurizing
500 ppm diesel fuel to 15 ppm by 35-40 percent. The savings associated
with the Phillips and Unipure processes appear to be more refinery
specific. For about 25 refineries, the Phillips process appears to have
the potential to reduce these desulfurization costs by 20-40 percent.
The primary advantage of the Unipure process is its lower capital
costs. For about 30 refineries, the Unipure process appears to have the
potential to reduce the capital investment related to produce 15 ppm
fuel from 500 ppm diesel fuel by an average of 40 percent.
8. Availability of Leadtime To Meet the 2010 15 ppm Sulfur Cap
If we promulgate this proposal one year from today, this would
provide refiners and importers with more than six years before they
would have to begin complying with the 15 ppm cap for nonroad diesel
fuel on June 1, 2010. Our leadtime analysis, which is presented in the
draft RIA, projects that 30-39 months are typically needed to design
and construct a diesel fuel hydrotreater.\262\ Thus, refiners would
have about 3 years before they would have to begin detailed design and
construction. This would allow them time to observe the performance of
the hydrotreaters being used to produce 15 ppm highway diesel fuel for
at least one year. While not a full catalyst cycle, any unusual
degradation in catalyst performance over time should be apparent within
the first year. Thus, we project that the 2010 start date would allow
refiners to be quite certain that the designs they select in mid-2007
will perform adequately in 2010.
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\262\ ``Highway Diesel Progress Review,'' USEPA, EPA420-R-02-
016, June 2002.
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In addition, we expect that most of the advanced technologies will
be demonstrated on a commercial scale by the end of 2004. Thus,
refiners would have at least two and a half years to observe the
performance of these technologies before having to select a technology
to meet the 2010 15 ppm cap. This should be more than adequate to fully
access the costs and capabilities of these technologies for all but the
most cautious refiners.
9. Feasibility of Distributing Nonroad, Locomotive and Marine Diesel
Fuels That Meet the Proposed Sulfur Standards
There are two considerations with respect to the feasibility of
distributing non-highway diesel fuels meeting the proposed sulfur
standards. The first pertains to whether sulfur contamination can be
adequately managed throughout the distribution system so that fuel
delivered to the end-user does not exceed the specified maximum sulfur
concentration. The second pertains to the physical limitations of the
system to accommodate any additional segregation of product grades.
a. Limiting Sulfur Contamination
With respect to limiting sulfur contamination during distribution,
the physical hardware and distribution practices for non-highway diesel
fuel do not differ significantly from those for highway diesel fuel.
Therefore, we do not anticipate any new issues with respect to limiting
sulfur contamination during the distribution of non-highway fuel that
would not have already been accounted for in distributing highway
diesel fuel. Highway diesel fuel has been required to meet a 500 ppm
sulfur standard since 1993. Thus, we expect that limiting contamination
during the distribution of 500 ppm non-highway diesel engine fuel can
be readily accomplished by industry.
In the highway diesel rule, EPA acknowledged that meeting a 15 ppm
sulfur specification would pose a substantial new challenge to the
distribution system. Refiners, pipelines and terminals would have to
pay careful attention to and eliminate any potential sources of
contamination in the system (e.g., tank bottoms, deal legs in
pipelines, leaking valves, interface cuts, etc.) In addition, bulk
plant operators and delivery truck operators would have to carefully
observe recommended industry practices to limit contamination,
including practices as simple as cleaning out transfer hoses, proper
sequencing of fuel deliveries, and parking on a level surface. Due to
the need to prepare for compliance with the highway diesel program, we
anticipate that issues related to limiting sulfur contamination during
the distribution of 15 ppm nonroad diesel fuel will be resolved well in
advance of the proposed 2010 implementation date for nonroad fuel. We
are not aware of any additional issues that might be raised unique to
nonroad fuel. If anything we anticipate limiting contamination will
become easier as batch sizes are allowed to increase and potential
sources of contamination decrease. We request comment on whether there
are unique considerations regarding the transition to a 15 ppm standard
for nonroad diesel fuel and what actions we should take beyond those
that are already underway in preparation for the 15 ppm highway diesel
program.
b. Potential Need for Additional Product Segregation
As discussed in sub-section B, we have designed the proposed
program to minimize the need for additional product segregation and the
associated feasibility and cost issues associated with it. This
proposal would allow for the fungible distribution of 500 ppm highway
and 500 ppm NRLM diesel fuel in 2007, and 15 ppm highway and 15 ppm
nonroad diesel fuel in 2010, up until the point where NRLM or nonroad
fuel must be dyed for IRS excise tax purposes. Heating oil would be
required to be segregated as a separate pool beginning in 2007 through
the use of a new marker, and locomotive and marine fuel by use of the
same marker beginning in 2010. With this program design, we believe we
have eliminated any potential feasibility issues associated with the
need for product segregation. This is not to say that steps will not
have to be taken. We have
[[Page 28429]]
identified only a single instance where it seems likely that the
adoption of this proposal would result in entities in the distribution
system choosing to add new tankage due to new product segregation. Bulk
plants in areas of the country where heating oil is expected to remain
in the market will have to decide whether to add tankage to distribute
both heating oil and 500 ppm NRLM fuel. In all other cases we
anticipate segments of the distribution system will choose to avoid any
fuel segregation costs by limiting the range of sulfur grades they
choose to carry, just as they do today. Regardless, however, the costs
and impacts of these choices are small. We request comment on this
assessment. A more detailed explanation of this assessment can be found
in Chapter 5.6 of the draft RIA.
G. What Are the Potential Impacts of the 15 ppm Sulfur Diesel Program
on Lubricity and Other Fuel Properties?
1. What Is Lubricity and Why Might it Be a Concern?
Engine manufacturers and owner/operators depend on diesel fuel
lubricity properties to lubricate and protect moving parts within fuel
pumps and injection systems for reliable performance. Unit injector
systems and in-line pumps, commonly used in diesel engines, are
actuated by cams lubricated with crankcase oil, and have minimal
sensitivity to fuel lubricity. However, rotary and distributor type
pumps, commonly used in light and medium-duty diesel engines, are
completely fuel lubricated, resulting in high sensitivity to fuel
lubricity. The types of fuel pumps and injection systems used in
nonroad diesel engines are the same as those used in highway diesel
vehicles. Consequently, nonroad and highway diesel engines share the
same need for adequate fuel lubricity to maintain fuel pump and
injection system durability.
Diesel fuel lubricity concerns were first highlighted for private
and commercial vehicles during the initial implementation of the
Federal 500 ppm sulfur highway diesel program and the state of
California's diesel program. The Department of Defense (DoD) also has a
longstanding concern regarding the lubricity of distillate fuels used
in its equipment as evidenced by the implementation of its own fuel
lubricity improver performance specification in 1989.\263\ The diesel
fuel requirements in the state of California differed from the federal
requirements by substantially restricting the content of diesel fuel
requires more severe hydrotreating than reducing the sulfur content to
meet a 500 ppm standard.\264\ Consequently, concerns regarding diesel
fuel lubricity have primarily been associated with California diesel
fuel and some California refiners treat their diesel fuel with a
lubricity additive as needed. Outside of California, hydrotreating to
meet the current 500 ppm sulfur specification does not typically result
in a substantial reduction of lubricity. Diesel fuels outside of
California seldom require the use of a lubricity additive. Therefore,
we anticipate only a marginal increase in the use of lubricity
additives in NRLM diesel fuel meeting the proposed 500 ppm sulfur
standard for 2007.\265\ This proposal would require diesel fuel used in
nonroad engines to meet a 15 ppm sulfur standard in 2010. Based on the
following discussion, we believe that the increase in the use of
lubricity additives in 15 ppm nonroad diesel fuel would be the same as
that estimated for 15 ppm highway diesel fuel.
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\263\ DoD Performance Specification, Inhibitor, Corrosion/
Lubricity Improver, Fuel Soluble, , MIL-PRF-25017F, 10 November
1997, Superseding MIL-I-25017E, 15 June 1989.
\264\ Chevron Products Diesel Fuel Technical Review provides a
discussion of the impacts on fuel lubricity of current diesel fuel
compositional requirements in California versus the rest of the
nation. http://www.chevron.com/prodserv/fuels/bulletin/diesel/l2%5F7%5F2%5Frf.htm.
\265\ The cost from the increased use of lubricity additives in
500 ppm NRLM diesel fuel in 2007 and in 15 ppm nonroad diesel fuel
in 2010 is discussed in section V of today's preamble.
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The state of California currently requires the same standards for
diesel fuel used in nonroad equipment as in highway equipment. Outside
of California, highway diesel fuel is often used in nonroad equipment
when logistical constraints or market influences in the fuel
distribution system limit the availability of high sulfur fuel. Thus,
for nearly a decade nonroad equipment has been using federal 500 ppm
sulfur diesel fuel and California diesel fuel, some of which may have
been treated with lubricity additives. During this time, there has been
no indication that the level of diesel lubricity needed for fuel used
in nonroad engines differs substantially from the level needed for fuel
used in highway diesel engines.
Blending small amounts of lubricity-enhancing additives increases
the lubricity of poor-lubricity fuels to acceptable levels. These
additives are available in today's market, are effective, and are in
widespread use around the world. Among the available additives,
biodiesel has been suggested as one potential means for increasing the
lubricity of conventional diesel fuel. Indications are that low
concentrations of biodiesel would be sufficient to raise the lubricity
to acceptable levels.
Considerable research remains to be performed to better understand
which fuel components are most responsible for lubricity. Consequently,
it is unclear whether and to what degree the proposed sulfur standards
for non-highway diesel engine fuel will impact fuel lubricity.
Nevertheless, there is evidence that the typical process used to remove
sulfur from diesel fuel--hydrotreating--can impact lubricity depending
on the severity of the treatment process and characteristics of the
crude. We expect that hydrotreating will be the predominant process
used to reduce the sulfur content of non-highway diesel engine fuel to
meet the 500 ppm sulfur standard during the first step of the proposed
program. The highway diesel program projected that hydrotreating would
be the process most frequently used to meet the 15 ppm sulfur standard
for highway diesel fuel. The 2010 implementation date for the proposed
15 ppm standard for nonroad diesel fuel would allow the use of new
technologies to remove sulfur from fuel.\266\ These new technologies
have less of a tendency to affect other fuel properties than does
hydrotreating.
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\266\ See section IV.F for a discussion of which desulfurization
processes we expect will be used to meet the 15 ppm standard for
nonroad diesel fuel.
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Based on our comparison of the blendstocks and processes used to
manufacture non-highway diesel fuels, we believe that the potential
decrease in the lubricity of these fuels from hydrotreating that might
result from the proposed sulfur standards should be approximately the
same as that experienced in desulfurizing highway diesel fuel.\267\ To
provide a conservative, high cost estimate, we assumed that the
potential impact on fuel lubricity from the use of the new
desulfurization processes would be the same as that experienced when
hydrotreating diesel fuel to meet a 15 ppm sulfur standard. We request
comment on the potential impact of these new desulfurization
technologies on lubricity (as well as other fuel properties) that might
help us to improve our estimate of the potential impacts of this
proposal on fuel properties other than sulfur. Given that the
requirements for fuel lubricity in highway and non-highway engines are
the same, and the potential decrease in lubricity from desulfurization
of non-highway diesel engine would be no greater than that experienced
in desulfurizing highway diesel fuel, we
[[Page 28430]]
estimate that the potential need for lubricity additives in non-highway
diesel engine fuel under this proposal would be the same as that for
highway diesel fuel meeting the same sulfur standard.
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\267\ See chapter 5 of the RIA for a discussion of the potential
impacts on fuel lubricity of this proposal.
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2. A Voluntary Approach on Lubricity
In the United States, there is no government or industry standard
for diesel fuel lubricity. Therefore, specifications for lubricity are
determined by the market. Since the beginning of the 500 ppm sulfur
highway diesel program in 1993, refiners, engine manufacturers, engine
component manufacturers, and the military have been working with the
American Society for Testing and Materials (ASTM) to develop protocols
and standards for diesel fuel lubricity in its D-975 specifications for
diesel fuel. ASTM is working towards a single lubricity specification
that would be applicable to all diesel fuel used in any type of engine.
Although ASTM has not yet adopted specific protocols and standards,
refiners that supply the U.S. market have been treating diesel fuel
with lubricity additives on a batch to batch basis, when poor lubricity
fuel is expected. Other examples include the U.S. military, Sweden, and
Canada. The U.S. military has found that the traditional corrosion
inhibitor additives used in its fuels have been highly effective in
reducing fuel system component wear. Since 1991, the use of lubricity
additives in Sweden's 10 ppm sulfur Class I fuel and 50 ppm sulfur
Class II fuel has resulted in acceptable equipment durability.\268\
Since 1997, Canada has required that its 500 ppm sulfur diesel fuel not
meeting a minimum lubricity be treated with lubricity additives.
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\268\ Letter from L. Erlandsson, MTC AB, to Michael P. Walsh,
dated October 16, 2000. EPA air docket A-99-06, docket item IV-G-42.
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The potential need for lubricity additives in diesel fuel meeting a
15 ppm sulfur specification was evaluated during the development of
EPA's highway diesel rule. In response to the proposed highway diesel
rule, all comments submitted regarding lubricity either stated or
implied that the proposed sulfur standard of 15 ppm would likely cause
the refined fuel to have lubricity characteristics that would be
inadequate to protect fuel injection equipment, and that mitigation
measures such as lubricity additives would be necessary. However, the
commenters suggested varied approaches for addressing lubricity. For
example, some suggested that we need to establish a lubricity
requirement by regulation while others suggested that the current
voluntary, market based system would be adequate. The Department of
Defense recommended that we encourage the industry (ASTM) to adopt
lubricity protocols and standards before the 2006 implementation date
of the 15 ppm sulfur standard for highway diesel fuel.
The final highway diesel rule did not establish a lubricity
standard for highway diesel fuel. We believe the issues related to the
need for diesel lubricity in fuel used in non-highway diesel engines
are substantially the same as those related to the need for diesel
lubricity for highway engines. Consequently, we expect the same
industry-based voluntary approach to ensuring adequate lubricity in
non-highway diesel fuels that we recognized for highway diesel fuel. We
believe the best approach is to allow the market to address the
lubricity issue in the most economical manner, while avoiding an
additional regulatory scheme. A voluntary approach should provide
adequate customer protection from engine failures due to low lubricity,
while providing the maximum flexibility for the industry. This approach
would be a continuation of current industry practices for diesel fuel
produced to meet the current federal and California 500 ppm sulfur
highway diesel fuel specifications, and benefits from the considerable
experience gained since 1993. It would also include any new
specifications and test procedures that we expect would be adopted by
the American Society for Testing and Materials (ASTM) regarding
lubricity of NRLM diesel fuel quality.
Regardless, this is an issue that will be resolved to meet the
demands of the highway diesel market, and whatever resolution is
reached for highway diesel fuel could be applied to non-highway diesel
engine fuel with sufficient advance notice. We are continuing to
participate in the ASTM Diesel Fuel Lubricity Task Force \269\ and will
assist their efforts to finalize a lubricity standard in whatever means
possible. We are hopeful that ASTM can reach a consensus early this
summer at the next meeting of the ASTM's Lubricity Task Force. We
request comment on what actio ns EPA should take to ensure adequate
lubricity of non-highway diesel engine fuel beyond those already
underway for highway diesel fuel.
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\269\ ASTM sub committee D02.E0.
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3. What Other Impact Would Today's Actions Have on the Performance of
Diesel and Other Fuels?
We do not expect that the proposed fuel program would have any
negative impacts on the performance of diesel engines in the existing
fleet which would use the fuels regulated today. In the early 1990's,
California lowered the maximum allowable level of sulfur content of
highway and nonroad diesel fuel to 500 ppm, and at the same time
California significantly lowered the aromatic content of diesel fuel.
California required a cap on total aromatics of 10 percent by volume,
while the in-use average at the time was on the order of 35 percent.
The lowering of the total aromatic content resulted in some problems
with leaks from the fuel pump O-ring seals in some diesel engines due
to a change specifically in the polynuclear aromatics content (PNA). In
the process of meeting California's 10 percent total aromatic content
requirement, the end result typically lowered PNA's from approximately
10-15 percent by volume to near-zero. In the early 1990's, some diesel
engine manufacturers used a certain material (Nitrile) for O-rings in
diesel fuel pumps. The Nitrile seals were found to be susceptible to
leakage with the use of diesel fuel with very low PNA content.
Normally, the PNA in the fuel penetrated the Nitrile material and cause
it to swell, thereby providing a seal with the throttle shaft. When
very low PNA fuel is used after conventional fuel has been used, the
PNA already in the swelled O-ring would leach out into the very low PNA
fuel. Subsequently, the Nitrile O-ring would shrink and pull away, thus
causing leaks, or the stress on the O-ring during the leaching process
would cause it to crack and leak. Not all 500 ppm sulfur fuels caused
this problem, because the amount and type of aromatics varied, and the
in-use seal problems were focused in California due to the 10 percent
aromatic requirements and the resulting very low PNA content. This was
not a wide-spread issue for the rest of the U.S. where highway diesel
fuel also had a 500ppm sulfur cap because the federal requirements did
not include a lower aromatic cap. While the process of lowering sulfur
levels to 500ppm does lower PNA, it does not achieve the near-zero
levels seen in California. Since the 1990's, diesel engine
manufacturers have switched to alternative materials (such as Viton),
which do not experience leakage. We believe that no issues with leaking
fuel pump O-rings would occur with the changes in diesel fuel sulfur
levels
[[Page 28431]]
contained in this proposal (both the 500 ppm requirement in 2008 and
the 15 ppm requirement in 2010) because while we do believe PNA content
will be reduced, we are not predicting it will achieve the near-zero
level experienced in California.
We expect that this proposal would have no negative impacts on
other fuels, such as jet fuel or heating oil. We do expect that the
sulfur levels of heating oil would decrease because of this proposal.
Beginning in mid-2007, we expect that controlling NRLM diesel fuel to
500 ppm would lead many pipelines to discontinue carrying high sulfur
heating oil as a separate grade. In areas served by these pipelines,
heating oil users would likely switch to 500 ppm diesel fuel. This
would reduce emissions of sulfur dioxide and sulfate PM from furnaces
and boilers fueled with heating oil. The primary exception to this
would likely be the Northeast and some areas of the Pacific Northwest,
where a distinct higher sulfur heating oil would still be distributed
as a separate fuel. Also, we expect that a small volume of high sulfur
distillate fuel would be created during distribution from the mixing of
low sulfur diesel fuels and higher sulfur fuels, such as jet fuel in
the pipeline interface. Such high sulfur distillate would likely be
sold by the terminal as high sulfur heating oil or reprocessed by
transmix processors.
H. Refinery Air Permitting
Prior to making diesel desulfurization changes, some refineries may
be required to obtain a preconstruction permit, under the New Source
Review (NSR) program, from the applicable state/local air pollution
control agency.\270\ We believe that the proposed program provides
sufficient lead time for refiners to obtain any necessary NSR permits
well in advance of the compliance date.
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\270\ Hydrotreating diesel fuel involves the use of process
heaters, which have the potential to emit pollutants associated with
combustion, such as NOX, PM, CO and SO3. In
addition, reconfiguring refinery processes to add desulfurization
equipment could increase fugitive VOC emissions. The emissions
increases associated with diesel desulfurization would vary widely
from refinery to refinery, depending on many source-specific
factors, such as crude oil supply, refinery configuration, type of
desulfurization technology, amount of diesel fuel produced, and type
of fuel used to fire the process heaters.
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Given that today's diesel sulfur program would provide roughly
three years of lead time before the 500 ppm standard would take effect,
we believe refiners would have time to obtain any necessary
preconstruction permits. Nevertheless, we believe it is reasonable to
continue our efforts under the Tier 2 and highway diesel fuel programs,
to help states in facilitating the issuance of permits under the NRLM
diesel sulfur program. For example, the guidance on Best Available
Control Technology (BACT) and Lowest Achievable Emission Rate (LAER)
control technology that was developed for the gasoline sulfur program
should have application for diesel desulfurization (highway and NRLM)
projects as well. Similarly, we believe the concept of EPA permit teams
for gasoline sulfur projects could readily be extended to permits
related to diesel projects as well. These teams, as needed, would track
the overall progress of permit issuance and would be available to
assist state/local permitting authorities, refineries and the public
upon request to resolve site-specific permitting questions. In
addition, these teams would be available, as necessary, to assist in
resolving case specific issues to ensure timely issuance of permits.
Finally, to facilitate the processing of permits, we encourage
refineries to begin discussions with permitting agencies and to submit
permit applications as early as possible.
V. Program Costs and Benefits
In this section, we present the projected cost impacts and cost
effectiveness of the proposed nonroad Tier 4 emission standards and
low-sulfur fuel requirement. We also present a benefit-cost analysis
and an economic impact analysis. The benefit-cost analysis explores the
net yearly economic benefits to society of the reduction in mobile
source emissions likely to be achieved by this rulemaking. The economic
impact analysis explores how the costs of the rule will likely be
shared across the manufacturers and users of the engines, equipment and
fuel that would be affected by the standards.
The results detailed below show that this rule would be highly
beneficial to society, with net present value benefits through 2030 of
$550 billion, compared to a net present value of social cost of only
about $16.5 billion (net present values in the year 2004). The impact
of these costs on society should be minimal, with the prices of goods
and services produced using equipment and fuel affected by the proposal
being expected to increase about 0.02 percent.
Further information on these and other aspects of the economic
impacts of our proposal are summarized in the following sections and
are presented in more detail in the Draft RIA for this rulemaking. We
invite the reader to comment on all aspects of these analyses,
including our methodology and the assumptions and data that underlie
our analysis.
A. Refining and Distribution Costs
As described above, the fuel-related requirements associated with
this proposed rule would be implemented in two steps. Nonroad,
locomotive and marine diesel fuel would be subject to a 500 ppm sulfur
cap beginning June 1, 2007, while nonroad diesel fuel would be subject
to a 15 ppm sulfur cap beginning June 1, 2010. Meeting these standards
would generally require refiners adding hydrotreating equipment and
possibly new or expanded hydrogen and sulfur plants in their refineries
for desulfurizing their nonroad diesel fuel and dispensing of the
removed sulfur. Using information provided by vendors of
desulfurization equipment and through discussions with distributors of
nonroad diesel fuel, we estimated the desulfurization and associated
distribution and additive cost for complying with this two step
desulfurization program. Except for the costs presented at the end of
this section, the costs below reflect a fully phased in fuels program
without the proposed small refiner exemption. Costs are in 2002
dollars. We request comment on the cost estimates presented below and
the methodologies used to develop them. You can refer to the Draft RIA
for details.
The cost to provide nonroad, locomotive and marine diesel fuel
under the proposed fuel program is summarized in Table V-A-1 below. The
costs shown (and all of the costs described in the rest of this
section) only apply to the roughly 65 percent of current nonroad,
locomotive and marine diesel fuel that contains more than 500 ppm
sulfur (hereafter referred to as the affected volume). We estimate that
the other 35 percent of this fuel is actually fuel certified to the
highway diesel fuel standards and project that this will continue.
Thus, the proposed fuel program would not affect this fuel and no
additional costs would be incurred by its refiners or distributors. The
costs and benefits of desulfurizing this highway fuel which spills over
into the non-highway markets was already included in EPA's 2007 highway
diesel fuel rule.
[[Page 28432]]
Table V-A-1.--Increased Cost of Providing Nonroad, Locomotive and Marine Diesel Fuel
----------------------------------------------------------------------------------------------------------------
Cents per gallon of affected fuel Affected fuel
------------------------------------------------ volume
(million
Refining Lubricity and Total gallons/year)
distribution a
----------------------------------------------------------------------------------------------------------------
Step One--500 ppm NRLM diesel fuel.............. 2.2 0.3 2.5 9,504
Step Two--5 ppm Nonroad diesel fuel............. 4.4 0.4 4.8 7,803
Step Two--500 ppm Locomotive and Marine diesel 2.2 b 0.2 2.4 4,093
fuel...........................................
----------------------------------------------------------------------------------------------------------------
Notes:
a 2008 for Step One (without consideration of small refiner provisions), 2015 for Step Two.
b 0.4 cent per gallon from mid-2010 to mid-2014 due to need for marker.
The majority of the fuel-related cost of the proposal is refining-
related. These costs include required capital investments amortized at
7 percent per annum before taxes. The derivation of these costs is
discussed in more detail below and in the Draft RIA. We request comment
on the estimated cost of meeting the 15 ppm and 500 ppm sulfur caps.
We also project that the increased cost of refining and
distributing 15 ppm and 500 ppm fuel would be substantially offset by
reductions in maintenance costs. These savings would apply to all
diesel engines in the field, not just new engines. Refer to section V.
B for a more complete discussion on the projected maintenance savings
associated with lower sulfur fuels.
1. Refining Costs
Our process for estimating the refining costs associated with the
proposed fuel program consisted of four steps. One, we estimated the
volume of 500 and 15 ppm nonroad, locomotive and marine diesel fuel
which had to be produced in each PADD \271\ in each phase of the
program. This step utilized diesel fuel and heating oil use estimates
from the Energy Information Administration's (EIA) Fuel Oil and
Kerosene Survey for 2000, shipments of diesel fuel between PADDs,
projected loss of 15 and 500 ppm volume due to contamination during
distribution and small refiner provisions. This nonroad diesel fuel
consumption in 2000 is lower than that inherent in the emission
estimates described above, which are based directly on the results of
EPA's NONROAD emission model. We are investigating ways to make the two
estimates more consistent.
---------------------------------------------------------------------------
\271\ Petroleum Administrative for Defense Districts.
---------------------------------------------------------------------------
Growth in distillate fuel use off this year 2000 base was estimated
using projections from EIA's Annual Energy Outlook, with one exception.
This exception was that the growth in nonroad diesel fuel use was taken
from EPA's NONROAD emission model (roughly three percent per year), as
opposed to EIA's projected growth of roughly one percent per year. The
higher growth rate is consistent with that inherent in the emission
estimates described above.
Refinery production of low and high sulfur distillate fuel in the
year 2000 was based on actual reports provided to EIA by all U.S.
refiners and importers. Refinery production of low and high sulfur
distillate fuel was assumed to grow at the same rate as consumption of
the two types of fuel, respectively. These rates were roughly three
percent and one and a half percent for low and high sulfur distillate
fuel production, respectively. The specific volumes of highway,
nonroad, locomotive, and marine diesel fuel by calendar year are
presented in chapter 7 of the Draft RIA.
Two, we estimated the cost for each refinery to desulfurize its
high sulfur fuel to 500 and 15 ppm. This was based on their historical
production volume of high sulfur diesel fuel and estimates of the
composition of this fuel (straight run, light cycle oil, etc.).\272\ We
also considered whether these refineries would be modifying or building
hydrotreating capacity in order to meet the 15 ppm highway cap.
---------------------------------------------------------------------------
\272\ The composition of nonroad diesel fuel in each PADD was
based on a survey conducted by API and NPRA in 1996. Crude oils
processed by domestic refiners have been becoming heavier over time,
necessitating greater use of coking and hydrocracking to convert the
heavy material into lighter, saleable products. Thus, the
contributions of coker and hydrocracked distillate to the overall
distillate pool are rising. Coker distillate is somewhat more
difficult to desulfurize than average distillate, but hydrocracked
distillate is much easier to desulfurize. Overall, this trend could
increase projected desulfurization costs slightly. We plan to update
these compositions to reflect trends in crude oil quality and
refinery configuration in our analysis for the final rule to the
extent that more recent data allow.
---------------------------------------------------------------------------
Three, we estimated which refineries would find it difficult to
market all of their current high sulfur diesel fuel as heating oil, due
to their location relative to major pipelines and the size of the
heating oil market in their area. Those not located in major heating
oil markets and not connected to pipelines serving these areas were
projected to have to meet the 500 ppm cap in 2007.
Four, we determined the additional refineries which would produce
500 ppm and 15 ppm fuel to satisfy demand during each phase of the fuel
program. Refineries projected to have the lowest compliance costs in
each PADD were projected to produce the lower sulfur fuels until demand
was met. PADD 3 refineries were allowed to ship low sulfur fuel to the
Northeast, but no other inter-PADD transfers were assumed. Imports of
500 ppm highway diesel fuel were assumed to increase at the rate of
highway diesel fuel consumption and be converted to 15 ppm diesel fuel,
80 percent in 2006 and 100 percent in 2010. Imports of high sulfur
distillate fuel were assumed to increase at the rate of high sulfur
distillate fuel consumption, but were assumed to remain entirely high
sulfur heating oil even after today's NRLM fuel proposal. In other
words, all 15 ppm and 500 ppm NRLM fuel produced under this proposal
was assumed to be produced by domestic refineries. This assumption
increased the projected costs of the proposal described above more than
would have been the case had we assumed that domestic production and
imports of high sulfur distillate fuel would each keep their respective
shares of the NRLM diesel fuel and heating oil markets in response to
this proposal. The relative costs of producing 15 ppm nonroad diesel
fuel by domestic and overseas refiners is discussed further in section
V.A.6. below.
With the onset of a 2007 500 ppm sulfur cap for nonroad, locomotive
and marine diesel fuel, we project that the market for high sulfur
diesel fuel and heating oil would become so small that high sulfur fuel
would no longer be shipped through common carrier pipelines in most
areas. The prime exception to this would be the Northeast, where the
heating oil market is very large. Thus, refiners located in the
Northeast and those along the major pipelines serving the Northeast,
namely the Colonial and Plantation pipelines, could continue to produce
high sulfur
[[Page 28433]]
heating oil. Other refineries would shift the production of high sulfur
diesel fuel and heating oil to the 500 ppm NRLM market. The second
exception would be refiners granted special provisions due to the small
size of their business (i.e., SBREFA refiners) or economic hardship, as
discussed in section IV above. The high sulfur distillate production
levels of these refineries is small enough that they can sell into more
local nonroad, locomotive and marine markets or the heating oil market
without using pipelines and so they could continue to produce high
sulfur distillate.
Based on refinery distillate production data from the Energy
Information Administration (EIA), there are 122 refineries currently
producing highway diesel fuel and 105 refineries producing high sulfur
diesel fuel or heating oil. Using the methodology described above,
absent this proposal, we project that roughly 114 refineries will
invest in additional desulfurization equipment to produce 15 ppm
highway diesel fuel; 74 refineries in 2006 and 40 in 2010.\273\ These
114 refineries include 109 of the 122 refineries which currently
produce highway diesel fuel, plus 5 refineries which currently only
produce high sulfur distillate fuel today. Again absent the proposed
NRLM diesel fuel program, we project that roughly 13 refineries
currently producing highway diesel fuel will shift to producing high
sulfur distillate fuel. This would leave a total of 113 refineries
still producing high sulfur distillate after full implementation of the
2007 highway diesel fuel program.
---------------------------------------------------------------------------
\273\ These (and the subsequent) estimates of the number of
refineries investing in new equipment to produce diesel fuels of
various sulfur levels should be understood as rough estimates which
assist us in projecting costs and other impacts related to this
proposal. They are most reasonable when evaluating the total number
of refineries investing in a particular year or region. We are not
indicating that we believe that we can predict which specific
refineries would invest in desulfurization equipment in response to
this proposal.
---------------------------------------------------------------------------
The number of these 113 domestic refineries expected to produce
either 500 ppm of 15 ppm NRLM diesel fuel in response to this proposal
is summarized in Table V-A-2.
Table V-A-2 Refineries Projected to Produce NRLM Diesel Fuel Under This Proposal
----------------------------------------------------------------------------------------------------------------
500 ppm diesel fuel 15 ppm diesel fuel
---------------------------------------------------------------
Year of Program Small Small
All refineries refineries All refineries refineries
----------------------------------------------------------------------------------------------------------------
2007-2010....................................... 42 0 0 0
2010-2014....................................... 37 19 25 0
2014+........................................... 25 12 37 7
----------------------------------------------------------------------------------------------------------------
As shown in this table, we project that 42 of the 113 refineries
currently producing some high sulfur distillate would desulfurize their
high sulfur diesel fuel in response to the proposed 500 ppm standard in
2007. The remainder would continue producing either high sulfur NRLM
diesel fuel under the proposed small refiner provisions, or high sulfur
heating oil. As explained in section IV.F, we project that these
refiners would use conventional hydrotreating technology to meet this
standard. Of these 42 refineries, we project that 32 would build new
hydrotreaters to meet the 500 ppm sulfur cap. We project that three of
the remaining ten refineries would be able to meet the 500 ppm cap with
their existing hydrotreater which is currently being used to produce
highway diesel fuel. These three refineries are projected to build a
new hydrotreater to produce 15 ppm highway diesel fuel in 2006, so
their existing highway fuel hydrotreater could process their current
high sulfur diesel fuel. The remaining seven refineries currently
produce relatively small amounts of high sulfur diesel fuel compared to
their highway diesel fuel production. We project that these refiners
would be able to economically revamp their existing highway
hydrotreater to process their non-highway diesel fuel.
We project that the capital cost involved to meet the 2007 500 ppm
sulfur cap would be $600 million, or $9.7 million per refinery building
a new hydrotreater. The bulk of this capital would be invested in 2007
($500 million), with the remainder being invested in 2010.\274\
Operating costs would be about $3 million per year for the average
refinery. We request comment on the number of refiners who would need
to build new equipment to meet the 500 ppm sulfur cap, the capital cost
for this new equipment and the cost of operating this equipment.
---------------------------------------------------------------------------
\274\ Some refineries would be able to delay production of 500
ppm NRLM fuel until 2010 due to the proposed small refiner
provisions. Likewise, some refineries would be able to delay
production of 15 ppm nonroad diesel fuel until 2014.
---------------------------------------------------------------------------
Starting in mid-2010, we project that 25 refineries would add or
revamp equipment to meet the 15 ppm cap on nonroad diesel fuel, while
20 refineries (nearly all of them small refiners) would add or revamp
equipment to produce 500 ppm nonroad or locomotive and marine diesel
fuel. Finally, an additional 12 refineries (again nearly all of them
small refiners) would begin producing 15 ppm nonroad diesel fuel in
2014.
We project that 80 percent of the 15 ppm nonroad diesel fuel volume
would be desulfurized by advanced technologies, while the remaining 20
percent would be desulfurized by conventional hydrotreaters. Since the
bulk of the hydrotreating capacity being used to meet the 2007 500 ppm
standard for NRLM diesel fuel would have just been built in 2007 or
2010, we expect that it would have been designed to facilitate further
processing to 15 ppm sulfur and the added 15 ppm facilities would be
revamps. However, those refiners who used their existing highway diesel
fuel hydrotreaters to meet the proposed 500 ppm cap in 2007 would
likely have to construct new equipment in 2010 or 2014 to meet the 15
ppm cap on nonroad diesel fuel, since these hydrotreaters could not be
revamped in 2006 to produce 15 ppm highway diesel fuel. When the
proposed NRLM diesel fuel program would be fully implemented in 2014,
roughly 51 refineries are still projected to produce high sulfur
heating oil and thus, would not face any refining costs related to this
proposal.
Our projection that 80 percent of refineries would utilize some
form of advanced technology to meet the proposed 15 ppm nonroad fuel
sulfur cap is based on the fact that this 15 ppm cap would follow the
production of 15 ppm highway diesel fuel by four years. Several firms
are expending significant research and development resources to bring
such advanced technologies to the market for the highway diesel fuel
[[Page 28434]]
program. We developed cost estimates for two such technologies: Linde
Iso-Therming and Phillips S-Zorb. The development of cost estimates for
these two advanced technologies, as well as conventional hydrotreating,
is described in detail in Chapter 7 of the Draft RIA. We request
comment on the potential viability and cost savings associated with
advanced desulfurization technologies, particularly in the 2010
timeframe.
The total capital cost of new equipment and revamps related to the
proposed 2010 sulfur standard would be $640 million, or $17 million per
refinery adding or revamping equipment. Total operating costs would be
about $5 million per year for the average refinery. The total refining
cost, including the amortized cost of capital, would be 4.4 cents per
gallon of new 15 ppm nonroad fuel. This cost is relative to the cost of
producing high sulfur fuel today, and includes the cost of meeting the
500 ppm standard beginning in 2007. We request comment on the number of
refiners who would need to build new equipment to meet the 15 ppm
sulfur cap, the capital cost for this new equipment and the cost of
operating this equipment. The average cost of continuing to meet the
500 ppm standard for locomotive and marine fuel would continue at 2.2
cents per gallon.
The above costs reflect national averages for the fully phased in
program for each control step. Some refiners would face lower costs
while others would face higher costs. Excluding small refiners because
they are able to take advantage of the proposed small refiner
provisions, the average refining costs by refining region are shown in
the table below. Combined costs are shown for PADDs 1 and 3 because of
the large volume of diesel fuel which is shipped from PADD 3 to PADD 1.
Table V-A-3.--Average Refining Costs by Region (cents per gallon)
------------------------------------------------------------------------
2007 500 ppm Cap 2010 15 ppm Cap
------------------------------------------------------------------------
PADDs 1 and 3............... 1.4 2.6
PADD 2...................... 2.9 5.7
PADD 4...................... 4.0 8.5
PADD 5...................... 2.6 5.4
Nationwide.................. 2.2 4.4
------------------------------------------------------------------------
We request comment on the range of estimated refining costs for the
various regions for both the proposed 500 and 15 ppm sulfur caps.
2. Cost of Lubricity Additives
Hydrotreating diesel fuel tends to reduce the natural lubricating
quality of diesel fuel, which is necessary for the proper functioning
of certain fuel system components. There are a variety of fuel
additives which can be used to restore diesel fuel's lubricating
quality. These additives are currently used to some extent in highway
diesel fuel. We expect that the need for lubricity additives that would
result from the proposed 500 ppm sulfur standard for off-highway diesel
engine fuel would be similar to that for highway diesel fuel meeting
the current 500 ppm sulfur cap standard.\275\ Industry experience
indicates that the vast majority of highway diesel fuel meeting the
current 500 ppm sulfur cap does not need lubricity additives.
Therefore, we expect that the great majority of off-highway diesel
engine fuel meeting the proposed 500 ppm sulfur standard would also not
need lubricity additives. In estimating lubricity additive costs for
500 ppm diesel fuel, we assumed that fuel suppliers would use the same
additives at the same concentration as we projected would be used in 15
ppm highway diesel fuel. Based on our analysis of this issue for the
2007 highway diesel fuel program, the cost per gallon of the lubricity
additive is about 0.2 cent. This level of use is likely conservative,
as the amount of lubricity additive needed increases substantially as
diesel fuel is desulfurized to lower levels. We also project that only
5 percent of all 500 ppm NRLM diesel fuel would require the use of a
lubricity additive. Thus, we project that the cost of additional
lubricity additives for the affected 500 ppm NRLM diesel fuel would be
0.01 cent per gallon. See the Draft RIA for more details on the issue
of lubricity additives.
---------------------------------------------------------------------------
\275\ Please refer to section IV in today's preamble for
additional discussion regarding our projections of the potential
impact on fuel lubricity of this proposed rule.
---------------------------------------------------------------------------
We project that all nonroad diesel fuel meeting a 15 ppm cap would
require treatment with lubricity additives. Thus, the projected cost
would be 0.2 cent per affected gallon of 15 ppm nonroad diesel fuel.
3. Distribution Costs
The proposed fuel program is projected to impact distribution costs
in three ways. One, we project that more diesel fuel would have to be
distributed under the proposal than without it. This is due to the fact
that some of the desulfurization processes reduce the fuel's volumetric
energy density during processing. Total energy is not lost during
processing, as the total volume of fuel is increased. However, a
greater volume of fuel must be consumed in the engine to produce the
same amount of power. We assumed that the current cost of distributing
diesel fuel of 10 cents per gallon (see Draft RIA for further details)
would stay constant (i.e., a 1 percent increase in the amount of fuel
distributed would increase total distribution costs by 1 percent).
We project that desulfurizing diesel fuel to 500 ppm would reduce
volumetric energy content by 0.7 percent. This would increase the cost
of distributing fuel by 0.07 cent per gallon. We project that
desulfurizing diesel fuel to 15 ppm would reduce volumetric energy
content by an additional 0.35 percent. This would increase the cost of
distributing fuel by an additional 0.04 cent per gallon, or a total
cost of 0.11 cent per gallon of affected 15 ppm nonroad diesel fuel.
Two, while this proposal minimizes the segregation of similar
fuels, some additional segregation of products in the distribution
system would still be required. The proposed allowance that highway and
off-highway diesel engine fuel meeting the same sulfur specification
can be shipped fungibly until it leaves the terminal obviates the need
for additional storage tankage in this segment of the distribution
system.\276\ This proposal would also allow 500 ppm NRLM diesel fuel to
be mixed with high-sulfur NRLM diesel fuel once the fuels are dyed to
meet IRS requirements. This provision would ease the last part of the
distribution of high-sulfur NRLM diesel fuel.
---------------------------------------------------------------------------
\276\ Including the refinery, pipeline, marine tanker, and barge
segments of the distribution system.
---------------------------------------------------------------------------
However, we expect that the implementation of the proposed 500 ppm
standard for NRLM diesel fuel in 2007 would compel some bulk plants in
those parts of the country still
[[Page 28435]]
distributing heating oil as a separate fuel grade to install a second
diesel storage tank to handle this 500 ppm nonroad fuel. These bulk
plants currently handle only high-sulfur fuel and hence would need a
second tank to continue their current practice of selling fuel into the
heating oil market in the winter and into the nonroad market in the
summer.\277\ We believe that some of these bulk plants would convert
their existing diesel tank to 500 ppm fuel in order to avoid the
expense of installing an additional tank. However, to provide a
conservatively high estimate we assumed that 10 percent of the
approximately 10,000 bulk plants in the U.S. (1,000) would install a
second tank in order to handle both 500 ppm NRLM diesel fuel and
heating oil. The cost of an additional storage tank at a bulk plant is
estimated at $90,000 and the cost of de-manifolding their delivery
truck at $10,000.\278\ If all 1,000 bulk plants were to install a new
tank, the total one-time capitol cost would be $100,000,000. Amortizing
the capital costs over 20 years, results in a estimated cost for
tankage at such bulk plants of 0.1 cent per gallon of affected NRLM
diesel fuel supplied. Although the impact on the overall cost of the
proposed program is small, the cost to those bulk plant operators who
need to put in a separate storage tank may represent a substantial
investment. Thus, as discussed in section IV.F., we believe many of
these bulk plants could make other arrangements to continue servicing
both heating oil and NRLM markets.
---------------------------------------------------------------------------
\277\ See section IV.E.9. of this proposal and chapter 5 of the
RIA for additional discussion of the potential impacts of the
proposed sulfur standards on the distribution system.
\278\ This estimated cost includes the addition of a separate
delivery system on the tank truck.
---------------------------------------------------------------------------
Due to the end of the highway program temporary compliance option
(TCO) in 2010 and the disappearance of high-sulfur diesel fuel from
much of the fuel distribution system due to the implementation of this
proposed rule, we expect that storage tanks at many bulk plants which
were previously devoted to 500 ppm TCO highway fuel and high-sulfur
fuel would become available for dyed 15 ppm nonroad diesel service.
Based on this assessment, we do not expect that a significant number of
bulk plants would need to install an additional storage tank in order
to provide dyed and undyed 15 ppm diesel fuel to their customers
beginning in 2010 (the proposed implementation date for the 15 ppm
nonroad standard).\279\ There could potentially be some additional
costs related to the need for new tankage in some areas not already
carrying 500 ppm fuel under the temporary compliance option of the
highway diesel program and which continue to carry high sulfur fuel.
However, we expect them to minimal relative to the above 0.1 cent per
gallon cost. Thus, we estimate that the total cost of additional
storage tanks that would result from the adoption of this proposal
would be 0.1 cent per gallon of affected off-highway diesel engine fuel
supplied.
---------------------------------------------------------------------------
\279\ See section IV of today's preamble for additional
discussion of our rational for this conclusion.
---------------------------------------------------------------------------
Three, the proposed requirement that high sulfur heating oil be
marked between 2007 and 2010 and that locomotive and marine diesel fuel
be marked from 2010 until 2014 would increase the cost of distributing
these fuels slightly. Based on input from marker manufacturers, we
estimate that marking these fuels would cost no more than 0.2 cent per
gallon and could cost considerably less. There should be no capital
cost associated with this requirement, as we are proposing to remove
the current requirement that refiners dye all high sulfur distillate at
the refinery. The current dyeing equipment should work equally well for
the marker. Because heating oil is being marked to prevent its use in
NRLM engines, we have spread the cost for this marker over NRLM diesel
fuel. Thus, from a regulatory point of view, the heating oil marker
would increase the cost of NRLM diesel fuel between 2007 and 2010 by
0.16 cent per gallon. We attribute the cost of marking 500 ppm
locomotive and marine diesel fuel directly to this fuel, so the marker
cost is simply 0.2 cent per gallon of locomotive and marine diesel fuel
between 2010 and 2014.
We do not project any additional downgrade of 15 ppm diesel fuel
would result from the proposed fuel program. In our analysis of the 15
ppm highway fuel program, we also projected additional distribution
costs due to the need to downgrade more volume of highway diesel fuel
to a lower value product. This is a consequence of the large difference
between the sulfur content of 15 ppm fuel and other distillate
products, like high sulfur diesel fuel, heating oil and jet fuel.\280\
We do not project that these costs would increase with this proposed
rule. Highway diesel fuel meeting a 15 ppm cap will already be being
distributed in all major pipeline and terminal networks. Thus, we
expect that 15 ppm nonroad fuel would be added to batches of 15 ppm
already being distributed. In this situation, the total interface
volume needing to be downgraded would not increase. At the same time,
we are not projecting that interface volume would decrease, as high
sulfur fuels, such as jet fuel, would still be in the system.
---------------------------------------------------------------------------
\280\ Off-highway diesel fuel sulfur content is currently
unregulated and is approximately 3,400 ppm on average. The maximum
allowed sulfur content of heating oil is 5,000 ppm. The maximum
allowed sulfur content of kerosene (and jet fuel) is 3,000 ppm.
---------------------------------------------------------------------------
Thus, overall, we estimate that the total additional distribution
would be 0.3 cent per gallon of nonroad, locomotive and marine fuel
during the first step of the proposed program (from 2007 through 2010).
We project that distribution costs would increase to 0.4 cent gallon
for 500 ppm locomotive and marine diesel fuel from 2010 to 2014, but
decrease to 0.2 cent per gallon thereafter. Finally, we project that
distribution costs for 15 ppm nonroad diesel fuel would be 0.2 cent
gallon.
4. How EPA's Projected Costs Compare to Other Available Estimates
We used two different methods for evaluating how well our cost
estimates reflect the true costs for complying with the two step
nonroad fuel program. The first method compared our costs with the
incremental market price of diesel fuel meeting a 15 or 500 ppm
standard. The second method compared our cost estimate to that from an
engineering analysis analogous to the one we performed.
Beginning with market prices, highway diesel fuel meeting a 500 ppm
sulfur cap has been marketed in the U.S. for almost ten years. Over the
five year period from 1995-1999, its national average price has
exceeded that of high sulfur diesel fuel by about 2.4 cent per gallon
(see chapter 7 of the Draft RIA). While fuel prices are a often a
function of market forces which might not reflect the cost of producing
the fuel, the comparison of the price difference over a fairly long
period such as 5 years would tend to reduce the effect of the market on
the prices and more closely reflect the cost of complying with the 500
ppm cap standard. Thus, we feel that this is a sound basis for
evaluating our cost estimate. This price difference is essentially the
same as our estimated cost for refining and distributing 500 ppm non-
highway diesel fuel, thus the price difference for producing and
distributing 500 ppm highway fuel corroborates our cost analysis.
Some 15 ppm diesel fuel is marketed today. However, it is either
being produced in very limited quantities using equipment designed to
meet less
[[Page 28436]]
stringent sulfur standards or with other properties which make it
unrepresentative of typical U.S. NRLM diesel fuel. Thus, current market
prices are not a good indication of the long term price impact of the
proposed 15 ppm cap.
Regarding engineering studies, the Engine Manufactures Association
(EMA) commissioned a study by Mathpro to estimate the cost of
controlling the sulfur content of highway and nonroad diesel fuel to
levels consistent with both 500 ppm and 15 ppm cap standards.\281\
Mathpro used a higher rate of return on new capital so we adjusted
their per-gallon costs to reflect our own amortization methodology.
Also, the Mathpro study was completed in 1999 so we adjusted their
costs for inflation to year 2002 dollars. After these two adjustments,
Mathpro's cost to desulfurize the high sulfur non-highway pool to 500
ppm is 2.5 cents per gallon, while that for a 15 ppm cap is 5.8 cents
per gallon.\282\ The 500 ppm cost estimate compares quite favorably
with our own estimate of 2.2 cents per gallon cost. One reason for our
somewhat lower estimate for complying with the 500 ppm standard is that
our refinery-specific analysis has only the lowest cost refineries
complying as many more expensive refineries can continue to produce
heating oil. It is likely that the refineries which our analysis show
would comply are more optimized for desulfurizating diesel fuel than
the average refinery used by Mathpro. This reason applies even more for
15 ppm cap standard as fewer, more optimized refineries need to comply
to produce nonroad diesel fuel which complies with a 15 ppm sulfur cap
standard. Furthermore, we considered the use of advanced
desulfurization technologies for complying with the 15 ppm standard,
while Mathpro did not. Since the Mathpro study was performed in 1999,
cost estimates were not available for either of the two technologies
which we included. The adjustment of the Mathpro costs and the
comparison with our own cost estimates are discussed in detail in the
Draft RIA. We request comment on the degree that the results of the
Mathpro study for EMA and the comparison with real-world prices support
our own cost estimates.
---------------------------------------------------------------------------
\281\ Hirshfeld, David, MathPro, Inc., ``Refining economics of
diesel fuel sulfur standards,'' performed for the Engine
Manufactuers Association, October 5, 1999.
\282\ The Mathpro costs cited reflect their case where current
diesel fuel hydrotreaters are revamped with a new reactor in series,
which is the most consistent with our technology projection.
---------------------------------------------------------------------------
5. Supply of Nonroad, Locomotive and Marine Diesel Fuel
EPA has developed the proposed fuel program to minimize its impact
on the supply of distillate fuel. For example: we have proposed to
transition the fuel sulfur level down to 15 ppm in two steps, providing
an estimated 6 years of leadtime for the final step; we are proposing
to provide flexibility to refiners through the availability of banking
and trading provisions; and we have provided relief for small refiners
and hardship relief for any qualifying refiner. In order to evaluate
the effect of this proposal on supply, EPA evaluated four possible
cases: (1) whether the proposed standards could cause refiners to
remove certain blendstocks from the fuel pool, (2) whether the proposed
standards could require chemical processing which loses fuel in the
process, (3) whether the cost of meeting the proposed standards could
lead some refiners to leave that market, and (4) whether the cost of
meeting the proposed standards could lead some refiners to stop
operations altogether (i.e., shut down). In all cases, as discussed
below, we have concluded that the answer is no. Therefore, consistent
with our findings made during the 2007 highway diesel rule, we do not
expect this proposed rule to cause any supply shortages of nonroad,
locomotive and marine diesel fuel. The reader is referred to the draft
RIA for a more detailed discussion of the potential supply impact of
this proposed rule.
Blendstock Shift: There should be no long term reduction in the
amount of material derived from crude oil available for blending into
diesel fuel or heating oil as a result of this proposal. Technology
exists to desulfurize any commercial diesel fuel to less than 10 ppm
sulfur. This technology is just now being proven on a commercial scale
with a range of no. 2 diesel fuel blendstocks, as a number of refiners
are producing 15 ppm fuel for diesel fleets which have been retro-
fitted with PM traps or for pipeline testing. Therefore, there is no
technical necessity to remove certain blendstocks from the diesel fuel
pool. It costs more to process certain blendstocks, such as light cycle
oil, than others. Therefore, there may be economic incentives to move
certain blendstocks out of the diesel fuel market to reduce compliance
costs. However, that is an economic issue, not a technical issue and
will be addressed below when we consider whether refiners might choose
to exit the NRLM diesel fuel market.
Processing Losses: The impact of the proposed rule on the total
output of liquid fuel from refineries would be negligible. Conventional
desulfurization processes do not reduce the energy content of the input
material. However, the form of the material is affected slightly. With
conventional hydrotreating, about 98 percent of the diesel fuel fed to
a hydrotreater producing 15 ppm sulfur product leaves as diesel fuel.
Of the 2 percent loss, three-fourths, or about 1.5 percent leaves the
unit as naphtha (i.e., gasoline feedstock). The remainder is split
evenly between liquified petroleum gas (LPG) and refinery fuel gas.
Both naphtha and LPG have higher valuable uses as liquid fuels. Naphtha
can be used to produce gasoline. Refiners can adjust the relative
amounts of gasoline and diesel fuel which they produce, especially to
this small degree. This additional naphtha can displace other gasoline
blendstocks, which can then be shifted to the diesel fuel pool. LPG, on
the other hand, is primarily used in heating, where it competes with
heating oil. Thus, additional LPG can be used to displace gasoline and
heating oil, which in turn can be shifted to the diesel fuel pool.
Thus, there should be little or no direct impact of desulfurization on
refinery fuel production. The shift from diesel fuel to fuel gas is
very small (0.25 percent) and this fuel gas can be used to reduce
consumption of natural gas within the refinery. These figures apply to
the full effect of the proposed standards (i.e., the reduction in
sulfur content from 3400 ppm to 15 ppm). For the first step of the
proposed fuel program and that portion of the diesel fuel pool which
would remain at the 500 ppm level indefinitely, the impacts would only
be about 40 percent of those described above.
The use of advanced desulfurization technologies would further
reduce these impacts. These technologies are projected to be used in
the second step of reducing 500 ppm diesel fuel to 15 ppm sulfur. We
project that the Linde process would reduce the above losses for the
second step by 55 percent, while the Phillips SZorb process would have
no loss in diesel fuel production.
Exit the NRLM Diesel Fuel Market: While the cost of meeting the
proposed standards might cause some individual refiners to consider
reducing their production of NRLM fuel or leave the market entirely, we
do not believe that across the entire industry such a shift is possible
or likely. As mentioned above, all diesel fuels and heating oil are
essentially identical both chemically and physically, except for sulfur
level. Thus, if a refiner could shift his high
[[Page 28437]]
sulfur distillate material from the nonroad, locomotive and marine
diesel fuel markets to the heating oil market starting in mid-2007, it
would avoid the need to invest in new desulfurization equipment.
Likewise, starting in mid-2010, a refiner could focus his 500 ppm
diesel fuel in the locomotive and marine diesel fuel markets or shift
this material to the heating oil market. The problem would be a
potential oversupply of heating oil starting in 2007 and locomotive and
marine diesel fuel and heating oil starting in 2010. An oversupply
could lead to a substantial drop in market price, significantly
increasing the cost of leaving the nonroad, locomotive and marine
diesel fuel markets. Or, it may be necessary to export the higher
sulfur fuel in order to sell it. This could entail transportation costs
and overseas prices no higher than existed in the U.S. before the
oversupply (and possibly lower due to these imports now entering these
overseas markets).
We addressed this same issue during the development of 2007 highway
diesel fuel program. There, the issue was whether refiners would shift
some or all of their current highway diesel fuel production to either
domestic or overseas markets for high sulfur diesel fuel or heating oil
in order to avoid investing to meet the 15 ppm cap for highway diesel
fuel. A study by Charles River Associates, et al., sponsored by API
projected that there could be a near-term shortfall in highway diesel
fuel supply of as much as 12 percent.\283\ However, supported by a
study by Muse, Stancil, we concluded that refiners would incur greater
economic loss in trying to avoid meeting the 15 ppm highway diesel fuel
cap than they would by complying at current production levels even if
the market did not allow them to recover their capital investment. A
study by Mathpro, Inc. for AAM and EMA also criticized the conclusions
of the Charles River study, particularly their assumption that
compliance costs alone would drive investment decisions and that there
was essentially a single highway diesel fuel market nationwide.\284\
Mathpro demonstrated that smaller refineries located, for example, in
the Rocky Mountain region, likely faced higher per gallon compliance
costs, but also had been more profitable over the past 15 years than
larger refiners in other areas with lower overall costs. This was due
to their market niches and the inability for lower cost refiners to
ship large volumes of fuel economically to their market.
---------------------------------------------------------------------------
\283\ ``An Assessment of the Potential Impacts of Proposed
Environmental Regulations on U.S. Refinery Supply of Diesel Fuel,''
Charles River Associates and Baker and O'Brien, for API, August
2000.
\284\ ``Prospects for Adequate Supply of Ultra Low Sulfur Diesel
Fuel in the Transition Period (2006-2007), An Analysis of Technical
and Economic Driving Forces for Investment in ULSD Capacity in the
U.S. Refining Sector,'' MathPro, Inc., for AAM and EMA, December 7,
2001.
---------------------------------------------------------------------------
We believe that the same conclusions apply to the proposed fuel
program for six reasons. One, the alternative markets for high sulfur
diesel fuel and heating oil would be even more limited after the
proposed sulfur caps on nonroad, locomotive and marine diesel fuel than
they will be in 2006, as half of the current U.S. market for high
sulfur, no. 2 distillate would disappear. We expect that high sulfur
heating oil would not even by carried be common carrier pipelines
except those serving the Northeast. Therefore, refiners' sale of high
sulfur distillate may be limited to markets serviceable by truck. Two,
the desulfurization technology to meet a 500 ppm cap has been
commercially demonstrated for over a decade. The desulfurization
technology to meet a 15 ppm cap will have been commercially
demonstrated in mid-2006, a full four years prior to the implementation
of the 15 ppm cap on nonroad diesel fuel. Three, the volume of fuel
affected by the 15 ppm nonroad diesel fuel standard would be only one-
seventh of that affected by the highway diesel fuel program. This
dramatically reduces the required capital investment. Four, both Europe
and Japan are implementing sulfur caps for highway and nonroad diesel
fuel in the range of 10-15 ppm, eliminating these markets as a sink for
high sulfur diesel fuel. Five, refineries outside of the U.S. and
Europe are operating at a lower percentage of their capacity than U.S.
refineries. Thus, U.S. refineries would not be able to obtain
attractive prices for high sulfur diesel fuel overseas. Finally,
refinery profit margins were much higher during the last part of 2000
and most of 2001 than over the past ten years, indicating a potential
long-term improvement in profitability. Margins decreased again during
most in 2002, but recovered during the last few months of that year and
in early 2003.
Once refiners have made their investments to meet the proposed NRLM
diesel fuel standards, or have decided to produce high sulfur heating
oil, we expect that the various distillate markets would operate very
similar to today's markets. When fully implemented in 2014, there will
be three distillate fuels in the market, 15 ppm highway and nonroad
diesel fuel, 500 ppm locomotive and marine diesel fuel and high sulfur
heating oil. The market for 500 ppm locomotive and marine diesel fuel
is much smaller than the other two, particularly considering that it is
nationwide and the heating oil market is geographically concentrated.
Therefore, the vast majority of refiners are expected to focus on
producing either 15 ppm or high sulfur distillate, which is similar to
today, where there are two fuels, 500 ppm and high sulfur distillate.
In this case, refiners with the capability of producing 15 ppm diesel
fuel have the most flexibility, since they can sell their fuel to any
of the three markets. Refiners with only 500 ppm desulfurization
capability can supply two markets. Those refiners only capable of
producing high sulfur distillate would not be able to participate in
either the 15 or 500 ppm markets. However, this is not different from
today. Generally, we do not expect one market to provide vastly
different profit margins than the others, as high profit margins in one
market will attract refiners from another via investment in
desulfurization equipment.
Refinery Closure: There are a number of reasons why we do not
believe that refineries would completely close down under this proposed
rule. One reason is that we have included provisions to provide relief
for small refiners, as well as any refiner facing unusual financial
hardship. Another reason is that nonroad, locomotive and marine diesel
fuel is usually the third or fourth most important product produced by
the refinery from a financial perspective. A total shutdown would mean
losing all the revenue and profit from these other products. Gasoline
is usually the most important product, followed by highway diesel fuel
and jet fuel. A few refineries do not produce either gasoline or
highway diesel fuel, so jet fuel and high sulfur diesel fuel and
heating oil are their most important products. The few refiners in this
category likely face the biggest financial challenge in meeting the
proposed requirements. However, those refiners would also presumably be
in the best position to apply for special hardship provisions,
presuming that they do not have readily available source of investment
capital. The additional time afforded by these provisions should allow
the refiner to generate sufficient cash flow to invest in the required
desulfurization equipment. Investment here could also provide them the
opportunity to expand into more profitable (e.g., highway diesel)
markets.
A quantitative evaluation of whether the cost of the proposed fuel
program could cause some refineries to cease operations completely
would be very difficult, if not impossible to perform. A
[[Page 28438]]
major factor in any decision to shut down is the refiner's current
financial situation. It is very difficult to assess an individual
refinery's current financial situation. This includes a refiner's debt,
as well as its profitability in producing fuels other than those
affected by a particular regulation. It can also include the
profitability of other operations and businesses owned by the refiner.
Such an intensive analysis can be done to some degree in the
context of an application for special hardship provisions, as discussed
above. However, in this case, EPA can request detailed financial
documents not normally available. Prior to such application, as is the
case now, this financial information is usually confidential. Even when
it is published, the data usually apply to more than just the operation
of a single refinery.
Another factor is the need for capital investments other than for
this proposed rule. EPA can roughly project the capital needed to meet
other new fuel quality specifications, such as the Tier 2 or highway
diesel sulfur standards. However, we cannot predict investments to meet
local environmental and safety regulations, nor other investments
needed to compete economically with other refiners.
Finally, any decision to close in the future must be based on some
assumption of future fuel prices. Fuel prices are very difficult to
project in absolute terms. The response of prices to changes in fuel
quality specifications, such as sulfur content, as is discussed in the
next section, are also very difficult to predict. Thus, even if we had
complete knowledge of a refiner's financial status and its need for
future investments, the decision to stay in business or close would
still depend on future earnings, which are highly dependent on the
prices of all products produced by that refinery.
Some studies in this area point to fuel pricing over the past 15
years or so and conclude that prices will only increase to reflect
increased operating costs and will not reflect the cost of capital. In
fact, the rate of return on refining assets has been poor over the past
15 years and until recently, there has been a steady decline in the
number of refineries operating in the U.S. However, this may have been
due to a couple of circumstances specific to that time period. One,
refinery capacity utilization was less than 80 percent in 1985. Two, at
least regarding gasoline, the oxygen mandate for reformulated gasoline
caused an increase in gasoline supply despite low refinery utilization
rates. While this led to healthy financial returns for oxygenate
production, it did not help refining profit margins.
Today, refinery capacity utilization in the U.S. is generally
considered to be at its maximum sustainable rate. There are no
regulatory mandates on the horizon which will increase production
capacity significantly, even if ethanol use in gasoline increases
substantially.\285\ Consistent with this, refining margins have been
much better over the past two and a half years than during the previous
15 years and the refining industry itself is projecting good returns
for the foreseeable future.
---------------------------------------------------------------------------
\285\ Both houses of the U.S. Congress are considering bills
which would require the increased use of renewables, like ethanol,
in gasoline and diesel fuel. While the amount of renewables could be
considerable, it is well below the annual growth in transportation
fuel use.
---------------------------------------------------------------------------
6. Fuel Prices
It is well known that it is difficult to predict fuel prices in
absolute terms with any accuracy. The price of crude oil dominates the
cost of producing gasoline and diesel fuel. Crude oil prices have
varied by more than a factor of two in the past year. In addition,
unexpectedly warm or cold winters can significantly affect heating oil
consumption, which affects the amount of gasoline produced and the
amount of distillate material available for diesel fuel production.
Economic growth, or its lack, affects fuel demand, particularly for
diesel fuel. Finally, both planned and unplanned shutdowns of
refineries for maintenance and repairs can significantly affect total
fuel production, inventory levels and resulting fuel prices.
Predicting the impact of any individual factor on fuel price is
also difficult. The overall volatility in fuel prices limits the
ability to determine the effect of a factor which changed at a specific
point in time which might have led to the price change, as other
factors continue to change over time. Occasionally, a fuel quality
change, such as reformulated gasoline or a 500 ppm cap on diesel fuel
sulfur content, only affects a portion of the fuel pool. In this case,
an indication of the impact on price can be inferred by comparing the
prices of the two fuels at the same general location over time.
However, this is still only possible after the fact, and cannot be done
before the fuel quality change takes place.
Because of these difficulties, EPA has generally not attempted to
project the impact of its rules on fuel prices. However, in response to
Executive Order 13211, we are doing so for this proposed rule. To
reflect the inherent uncertainty in making such projections, we
developed three projections for the potential impact of the proposed
fuel program on fuel prices. The range of potential long-term price
increases are shown in Table V-A-4. Short-term price impacts are highly
volatile, as are short-term swings in absolute fuel prices, and much
too dependent on individual refiners' decisions, unexpected shutdowns,
etc. to be predicted even with broad ranges.
Table V-A-4.--Range of Possible Total Diesel Fuel Price Increases (cents per gallon) a
----------------------------------------------------------------------------------------------------------------
Lower Limit Mid-Point Maximum
----------------------------------------------------------------------------------------------------------------
2007 500 ppm Sulfur Cap: Nonroad, Locomotive and Marine Diesel Fuel
-------------------------------------------------------------------------------------------------
PADDs 1 and 3................................................... 0.9 1.5 3.4
PADD 2.......................................................... 2.3 3.0 4.8
PADD 4.......................................................... 1.7 4.1 5.8
PADD 5.......................................................... 1.0 2.8 4.3
-----------------------------------------------------------------
2010 15 ppm Sulfur Cap: Nonroad Diesel Fuel
-------------------------------------------------------------------------------------------------
PADDs 1 and 3................................................... 1.8 3.0 5.4
PADD 2.......................................................... 2.9 6.1 7.4
PADD 4.......................................................... 3.0 8.9 9.3
PADD 5.......................................................... 1.7 5.9 8.4
----------------------------------------------------------------------------------------------------------------
Notes:
a At the current wholesale price of approximately $1.00 per gallon, these values also represent the percentage
increase in diesel fuel price.
[[Page 28439]]
The lower end of the range assumes that prices within a PADD
increased to reflect the highest operating cost increase faced by any
refiner in that PADD. In this case, this refiner with the highest
operating cost would not recover any of his invested capital, but all
other refiners would recover some or all of their investment. In this
case, the price of nonroad, locomotive and marine diesel fuel would
increase in 2007 by 1-2 cents per gallon, depending on the area of the
country. In 2010, the price of nonroad diesel fuel would increase a
total of 2-3 cents per gallon. Locomotive and marine diesel fuel prices
would continue to increase by 1-2 cents per gallon.
The mid-range estimate of price impacts assumes that prices within
a PADD increase by the average refining and distribution cost within
that PADD, including full recovery of capital (at 7 percent per annum
before taxes). Lower cost refiners would recover more than their
capital investment, while those with higher than average costs recover
less. Under this assumption, the price of nonroad, locomotive and
marine diesel fuel would increase in 2007 by 2-4 cents per gallon,
depending on the area of the country. In 2010, the price of nonroad
diesel fuel would increase a total of 3-9 cents per gallon. Locomotive
and marine diesel fuel prices would continue to increase by 2-4 cents
per gallon.
The upper end estimate of price impacts assumes that prices within
a PADD increase by the maximum total refining and distribution cost of
any refinery within that PADD, including full recovery of capital (at 7
percent per annum before taxes). All other refiners would recover more
than their capital investment. Under this assumption, the price of
nonroad, locomotive and marine diesel fuel would increase in 2007 by 3-
6 cents per gallon, depending on the area of the country. In 2010, the
price of nonroad diesel fuel would increase a total of 5-9 cents per
gallon. Locomotive and marine diesel fuel prices would continue to
increase by 3-6 cents per gallon.
In addition to the differences noted above, there are a number of
assumptions inherent in all three of the above price projections.
First, both the lower and upper limits of the projected price impacts
described above assume that the refinery facing the highest compliance
costs is currently the price setter in their market. This is a worse
case assumption which is impossible to validate. Many factors affect a
refinery's total costs of fuel production. Most of these factors, such
as crude oil cost, labor costs, age of equipment, etc., are not
considered in projecting the incremental costs associated with lower
NRLM diesel fuel sulfur levels. Thus, current prices may very well be
set in any specific market by a refinery facing lower incremental
compliance costs than other refineries. This point was highlighted in a
study by the National Economic Research Associates (NERA) for AAM of
the potential price impacts of EPA's 2007 highway diesel fuel
program.\286\ In that study, NERA criticized the above referenced study
performed by Charles River Associates, et al. for API, which projected
that prices would increase nationwide to reflect the total cost faced
by the U.S. refinery with the maximum total compliance cost of all the
refineries in the U.S. producing highway diesel fuel. To reflect the
potential that the refinery with the highest projected compliance costs
under the maximum price scenario is not the current price setter, we
included the mid-point price impacts above. It is possible that even
the lower limit price impacts are too high, if the conditions exist
where prices are set based on operating costs alone. However, these
price impacts are sufficiently low that considering even lower price
impacts was not considered critical to estimating the potential
economic impact of this rule.
---------------------------------------------------------------------------
\286\ ``Potential Impacts of Environmental Regulations on Diesel
Fuel Prices,'' NERA, for AAM, December 2000.
---------------------------------------------------------------------------
Second, we assumed that a single refinery's costs could affect fuel
prices throughout an entire PADD. While this is a definite improvement
over analyses which assume that a single refinery's costs could affect
fuel prices throughout the entire nation, it is still conservative.
High cost refineries are more likely to have a more limited
geographical impact on market pricing than an entire PADD.
Third, by focusing solely on the cost of desulfurizing NRLM diesel
fuel, we assume that the production of NRLM diesel fuel is independent
of the production of other refining products, such as gasoline, jet
fuel and highway diesel fuel. However, this is clearly not the case.
Refiners have some flexibility to increase the production of one
product without significantly affecting the others, but this
flexibility is quite limited. It is possible that the relative
economics of producing other products could influence a refiner's
decision to increase or decrease the production of NRLM diesel fuel
under the proposed standards. This in turn could increase or decrease
the price impact relative to those projected above.
Fourth, all three of the above price projections are based on the
projected cost for U.S. refineries of meeting the proposed NRLM diesel
fuel sulfur caps. Thus, these price projections assume that imports of
NRLM fuel, which are currently significant in the Northeast, are
available at roughly the same cost as those for U.S. refineries in
PADDs 1 and 3. We have not performed any analysis of the cost of lower
sulfur caps on diesel fuel produced by foreign refiners. However, there
are reasons to believe that imports of 500 and 15 ppm NRLM diesel fuel
would be available at prices in the ranges of those projected for U.S.
refiners.
One recent study analyzed the relative cost of lower sulfur caps
for Asian refiners relative to those in the U.S., Europe and
Japan.\287\ It concluded that costs for Asian refiners would be
comparatively higher, due to the lack of current hydrotreating capacity
at Asian refineries. This conclusion is certainly valid when evaluating
lower sulfur levels for highway diesel fuels which are already at low
levels in the U.S., Europe and Japan and for which refineries in these
areas have already invested in hydrotreating capacity. It would appear
to be less valid when assessing the relative cost of meeting lower
sulfur standards for nonroad diesel fuels and heating oils which are
currently at much higher sulfur levels in the U.S., Europe and Japan.
All refineries face additional investments to remove sulfur from these
fuels and so face roughly comparable control costs on a per gallon
basis.
---------------------------------------------------------------------------
\287\ ``Cost of Diesel Fuel Desulfurization In Asian
Refineries,'' Estrada International Ltd., for the Asian Development
Bank, December 17, 2002.
---------------------------------------------------------------------------
One factor arguing for competitively priced imports is the fact
that refinery utilization rates are currently higher in the U.S. and
Europe than in the rest of the world. The primary issue is whether
overseas refiners will invest to meet tight sulfur standards for U.S.,
European and Japanese markets. Many overseas refiners will not invest,
instead focusing on local, higher sulfur markets. However, many
overseas refiners focus on exports. Both Europe and the U.S. are moving
towards highway and nonroad diesel fuel sulfur caps in the 10-15 ppm
range. Europe is currently and projected to continue to need to import
large volumes of highway diesel fuel. Thus, it seems reasonable to
expect that a number of overseas refiners would invest in the capacity
to produce some or all of their diesel fuel at these levels. Overseas
refiners also have the flexibility to produce 10-15 ppm diesel fuel
from their cleanest blendstocks, as
[[Page 28440]]
most of their available markets have less stringent sulfur standards.
Thus, there are reasons to believe that some capacity to produce 10-15
ppm diesel fuel would be available overseas at competitive prices. If
these refineries were operating well below capacity, they might be
willing to supply complying product at prices which only reflect
incremental operating costs. This could hold prices down in areas where
importing fuel is economical. However, it is unlikely that these
refiners could supply sufficient volumes to hold prices down
nationwide. Despite this expectation, to be conservative, in the
refining cost analysis conducted earlier in this chapter, we assumed no
imports of 500 ppm or 15 ppm NRLM diesel fuel. All 500 ppm and 15 ppm
nonroad diesel fuel was produced by domestic refineries. This raised
the average and maximum costs of 500 ppm and 15 ppm NRLM diesel fuel
and increased the potential price impacts projected above beyond what
would have been projected had we projected that 5-10 percent of NRLM
diesel fuel would be imported at competitive prices.
B. Cost Savings to the Existing Fleet from the Use of Low Sulfur Fuel
We estimate that reducing fuel sulfur to 500 ppm would reduce
engine wear and oil degradation to the existing nonroad diesel
equipment fleet and that a further reduction to 15 ppm sulfur would
result in even greater reductions. This reduction in wear and oil
degradation would provide a dollar savings to users of nonroad
equipment. The cost savings would also be realized by the owners of
future nonroad engines that are subject to the standards in this
proposal. As discussed below, these maintenance savings have been
conservatively estimated to be greater than 3 cents per gallon for the
use of 15 ppm sulfur fuel when compared to the use of today's
unregulated nonroad diesel fuel. A summary of the benefits of low-
sulfur fuel is presented in Table V.B-1.\288\
---------------------------------------------------------------------------
\288\ See Heavy-duty 2007 Highway Final RIA, Chapter V.C.5, and
``Study of the Effects of Reduced Diesel Fuel Sulfur Content on
Engine Wear'', EPA report # 460/3-87-002, June 1987.
Table V.B-1--Engine Components Potentially Affected by Lower Sulfur
Levels in Diesel Fuel
------------------------------------------------------------------------
Effect of Lower Potential Impact on
1Affected Components Sulfur Engine System
------------------------------------------------------------------------
Piston Rings.................. Reduced corrosion Extended engine life
wear. and less frequent
rebuilds.
Cylinder Liners............... Reduced corrosion Extended engine life
wear. and less frequent
rebuilds.
Oil Quality................... Reduced deposits, Reduce wear on piston
reduced acid ring and cylinder
build-up, and liner and less
less need for frequent oil
alkaline changes.
additives.
Exhaust System (tailpipe)..... Reduced corrosion Less frequent part
wear. replacement.
Exhaust Gas Recirculation Reduced corrosion Less frequent part
System. wear. replacement.
------------------------------------------------------------------------
The monetary value of these benefits over the life of the equipment
will depend upon the length of time that the equipment operates on low-
sulfur diesel fuel and the degree to which engine and equipment
manufacturers specify new maintenance practices and the degree to which
equipment operators change engine maintenance patterns to take
advantage of these benefits. For equipment near the end of its life in
the 2008 time frame, the benefits will be quite small. However, for
equipment produced in the years immediately preceding the introduction
of 500 ppm sulfur fuel, the savings would be substantial. Additional
savings would be realized in 2010 when the 15 ppm sulfur fuel would be
introduced.
We estimate the single largest savings would be the impact of lower
sulfur fuel on oil change intervals. The draft RIA presents our
analysis for the oil change interval extension which would be realized
by the introduction of 500 ppm sulfur fuel in 2007, as well as the
additional oil extension which would be realized with the introduction
of 15 ppm sulfur nonroad diesel fuel in 2010. As explained in the draft
RIA, these estimates are based on our analysis of publically available
information from nonroad engine manufacturers. Due to the wide range of
diesel fuel sulfur which today's nonroad engines may see around the
world, engine manufacturers specify different oil change intervals as a
function of diesel sulfur levels. We have used this data as the basis
for our analysis. Taken together, when compared to today's relatively
high nonroad diesel fuel sulfur levels, we estimate the use of 15 ppm
sulfur fuel will enable an oil change interval extension of 35 percent
from today's products.
We present here a fuel cost savings attributed to the oil change
interval extension in terms of a cents per gallon operating cost. We
estimate that an oil change interval extension of 31 percent, as would
be enabled by the use of 500 ppm sulfur fuel in 2007, results in a fuel
operating costs savings of 3.0 cents per gallon for the nonroad fleet.
We project an additional cost savings of 0.3 cents per gallon for the
oil change interval extension which would be enabled by the use of 15
ppm sulfur beginning in 2010. Thus, for the nonroad fleet as a whole,
beginning in 2010 nonroad equipment users can realize an operating cost
savings of 3.3 cents per gallon compared to today's engine. This means
that the end cost to the typical user for 15ppm sulfur fuel is
approximately 1.5 cents per gallon (4.8 cent per gallon cost for fuel
minus 3.3 cent per gallon maintenance savings). For a typical 100
horsepower nonroad engine this represents a net present value lifetime
savings of more than $500.
These savings will occur without additional new cost to the
equipment owner beyond the incremental cost of the low-sulfur diesel
fuel, although these savings are dependent on changes to existing
maintenance schedules. Such changes seem likely given the magnitude of
the savings. We have not estimated the value of the savings from the
other benefits listed in Table V.B-1, and therefore we believe the 3.3
cents per gallon savings is conservative as it only accounts for the
impact of low sulfur fuel on oil change intervals.
C. Engine and Equipment Cost Impacts
The following sections briefly discuss the various engine and
equipment cost elements considered for this proposal and present the
total costs we have estimated; the reader is referred to the draft RIA
for a complete discussion. Estimated engine and equipment costs depend
largely on both the size of the piece of equipment and its engine, and
on the technology package being added to the engine to ensure
compliance with the proposed standards. The wide size variation (e.g.,
<4 horsepower engines through £2500 horsepower engines) and
[[Page 28441]]
the broad application variation (e.g., lawn equipment through large
mining trucks) that exists in the nonroad industry makes it difficult
to present here an estimated cost for every possible engine and/or
piece of equipment. Nonetheless, for illustrative purposes, we present
some example per engine/equipment cost impacts throughout this
discussion. This analysis is presented in detail in Chapter 6 of the
draft RIA. We are also considering doing a sensitivity analysis on
cost/engine data, which would be put into the docket for comment.
It is important to note that the costs presented here do not
reflect any savings that are expected to occur because of the engine
ABT program and the equipment manufacturer transition program, both of
which are discussed in Section VII. As discussed in the draft RIA,
these optional programs have the potential to provide significant
savings for both engine and equipment manufacturers. We request comment
with supporting data and/or analysis on the cost estimates presented
here and the underlying analysis presented in chapter 6 of the draft
RIA.
1. Engine Cost Impacts
Estimated engine costs are broken into fixed costs (for research
and development, retooling, and certification), variable costs (for new
hardware and assembly time), and life-cycle operating costs. Total
operating costs include the estimated incremental cost for low-sulfur
diesel fuel, any expected increases in maintenance costs associated
with new emission control devices, any costs associated with increased
fuel consumption, and any decreases in operating cost (i.e.,
maintenance savings) expected due to low-sulfur fuel. Cost estimates
presented here represent an expected incremental cost of engines in the
model year of their introduction. Costs in subsequent years would be
reduced by several factors, as described below. All engine and
equipment costs are presented in 2001 dollars.
a. Engine Fixed Costs
i. Engine and Emission Control Device R&D
The technologies described in section III represent those
technologies we believe will be used to comply with the proposed Tier 4
emission standards. These technologies are part of an ongoing research
and development effort geared toward compliance with the 2007 heavy-
duty diesel highway emission standards. The engine manufacturers making
R&D expenditures toward compliance with highway emission standards will
have to undergo some additional R&D effort to transfer emission control
technologies to engines they wish to sell into the nonroad market.
These R&D efforts will allow engine manufacturers to develop and
optimize these new technologies for maximum emission-control
effectiveness with minimum negative impacts on engine performance,
durability, and fuel consumption. Many nonroad engine manufacturers are
not part of the ongoing R&D effort toward compliance with highway
emissions standards because they do not sell engines into the highway
market. These manufacturers are expected to benefit from the R&D work
that has already occurred and will continue through the coming years
through their contact with highway manufacturers, emission control
device manufacturers, and the independent engine research laboratories
conducting relevant R&D.
Several technologies are projected for complying with the proposed
Tier 4 emission standards. We are projecting that NOX
adsorbers and catalyzed diesel particulate filters (CDPFs) would be the
most likely technologies applied by industry to meet our proposed
emissions standards for £75 horsepower engines. The fact that
these technologies are being developed for implementation in the
highway market prior to the implementation dates in this proposal, and
the fact that engine manufacturers would have several years before
implementation of the proposed Tier 4 standards, ensures that the
technologies used to comply with the nonroad standards would undergo
significant development before reaching production. This ongoing
development could lead to reduced costs in three ways. First, we expect
research will lead to enhanced effectiveness for individual
technologies, allowing manufacturers to use simpler packages of
emission control technologies than we would predict given the current
state of development. Similarly, we anticipate that the continuing
effort to improve the emission control technologies will include
innovations that allow lower-cost production. Finally, we believe that
manufacturers would focus research efforts on any drawbacks, such as
fuel economy impacts or maintenance costs, in an effort to minimize or
overcome any potential negative effects.
We anticipate that, in order to meet the proposed standards,
industry would introduce a combination of primary technology upgrades.
Achieving very low NOX emissions would require basic
research on NOX emission control technologies and
improvements in engine management to take advantage of the exhaust
emission control system capabilities. The manufacturers are expected to
take a systems approach to the problem of optimizing the engine and
exhaust emission control system to realize the best overall
performance. Since most research to date with exhaust emission control
technologies for nonroad applications has focused on retrofit programs,
there remains room for significant improvements by taking such a
systems approach. The NOX adsorber technology in particular
is expected to benefit from re-optimization of the engine management
system to better match the NOX adsorber's performance
characteristics. The majority of the dollars we have estimated for
research is expected to be spent on developing this synergy between the
engine and NOX exhaust emission control systems. Therefore,
for engines requiring both a CDPF and a NOX adsorber (i.e.,
£75 horsepower), we have attributed two-thirds of the R&D
expenditures to NOX control, and one-third to PM control.
In the 2007 HD highway rule, we estimated that each engine
manufacturer would expend $35 million for R&D to redesign their engines
and apply catalyzed diesel particulate filters (CDPF) and
NOX adsorbers. For their nonroad R&D efforts on engines
requiring CDPFs and NOX adsorbers (i.e., £75
horsepower), engine manufacturers selling into the highway market would
incur some level of R&D effort but not at the level incurred for the
highway rule. In many cases, the engines used by highway manufacturers
in nonroad products are based on the same engine platform as those used
in highway products. However, horsepower and torque characteristics are
often different so some effort will have to be expended to accommodate
those differences. For these manufacturers, we have estimated that they
would incur an R&D expense of $3.5 million. This $3.5 million R&D
expense would allow for the transfer of R&D knowledge from their
highway experience to their nonroad engine product line. Two-thirds of
this R&D is attributed to NOX control and one-third to PM
control.
For those manufacturers that sell engines only into the nonroad
market, and where those engines require a CDPF and a NOX
adsorber, we believe that they will incur an R&D expense nearing that
incurred by highway manufacturers for the highway rule, although not at
the level incurred by highway manufacturers for the highway rule.
Nonroad manufacturers would be able to learn from the R&D efforts
already
[[Page 28442]]
under way for both the highway rule and for the Tier 2 light-duty
highway rule (65 FR 6698). This learning could be done via seminars,
conferences, and contact with highway manufacturers, emission control
device manufacturers, and the independent engine research laboratories
conducting relevant R&D. Therefore, for these manufacturers, we have
estimated an expenditure of $24.5 million. This lower number--$24.5
million versus $35 million in the highway rule--reflects the transfer
of knowledge to nonroad manufacturers that would occur from the many
stakeholders in the diesel industry. Two-thirds of this R&D is
attributed to NOX control and one-third to PM control.
Note that the $3.5 million and $24.5 million estimates represent
our estimate of the average R&D expected by manufacturers. These
estimates would be different for each manufacturer--some higher, some
lower--depending on product mix and the ability to transfer knowledge
from one product to another.
For those engine manufacturers selling engines that would require
CDPF-only R&D (i.e., 25 to 75 horsepower engines in 2013), we have
estimated that the R&D they would incur would be roughly one-third that
incurred by manufacturers conducting CDPF/NOX adsorber R&D.
We believe this is a good estimate because CDPF technology is further
along in its development than is NOX adsorber technology
and, therefore, a 50/50 split would not be appropriate. Using this
estimate, the R&D incurred by manufacturers that have already done
selling any engines into both the highway and the nonroad markets would
be $1.2 million, and the R&D for manufacturers selling engines into
only the nonroad market would be roughly $8 million. All of this R&D is
attributed to PM control.
For those engine manufacturers selling engines that would require
DOC-only or some engine-out modification R&D (i.e., <75 horsepower
engines in 2008), we have estimated that the R&D they would incur would
be roughly one-half the amount estimated for their CDPF-only R&D. Using
this estimate, the R&D incurred by manufacturers selling any engines
into both the highway and nonroad markets would be roughly $600,000,
and the R&D for manufacturers selling engines into only the nonroad
market would be roughly $4 million. All of this R&D is attributed to PM
control.
Some manufacturers of engines produce engines to specifications
developed by other manufacturers. Such joint venture manufacturers do
not conduct engine-related R&D but simply manufacture an engine
designed and developed by another manufacturer. For such manufacturers,
we have assumed no R&D expenditures given that we believe they will
conduct no R&D themselves and will rely on their joint venture partner.
This is true unless the parent company has no engine sales in the
horsepower categories covered by the partner company. Under such a
situation, we have accounted for the necessary R&D by attributing it to
the parent company. We have also estimated that some manufacturers will
choose not to invest in R&D for the U.S. nonroad market due to low
volume sales that probably cannot justify the expense. More detail on
these assumptions and the number of manufacturers assumed not to expend
R&D is presented in Chapter 6 of the draft RIA. We welcome comments and
supporting documentation.
We have assumed that all R&D expenditures occur over a five year
span preceding the first year any emission control device is introduced
into the market. Where a phase-in exists (e.g., for NOX
standards on £75 horsepower engines), expenditures are
assumed to occur over the five year span preceding the first year
NOX adsorbers would be introduced, and then to continue
during the phase-in years; the expenditures would be incurred in a
manner consistent with the phase-in of the standard. All R&D
expenditures are then recovered by the engine manufacturer over an
identical time span following the introduction of the technology. We
assume a seven percent rate of return for all R&D. We have apportioned
these R&D costs across all engines that are expected to use these
technologies, including those sold in other countries or regions that
are expected to have similar standards. We have estimated the fraction
of the U.S. sales to this total sales at 42 percent. Therefore, we have
attributed this amount to U.S. sales.
Using this methodology, we have estimated the total R&D
expenditures attributable to the proposed standards at $199 million.
ii. Engine-Related Tooling Costs
Once engines are ready for production, new tooling will be required
to accommodate the assembly of the new engines. In the 2007 highway
rule, we estimated approximately $1.6 million per engine line for
tooling costs associated with CDPF/NOX adsorber systems. For
the proposed nonroad Tier 4 standards, we have estimated that nonroad-
only manufacturers would incur the same $1.6 million per engine line
requiring a CDPF/NOX adsorber system and that these costs
would be split evenly between NOX control and PM control.
For those systems requiring only a CDPF, we have estimated one-half
that amount, or $800,000 per engine line. For those systems requiring
only a DOC or some engine-out modifications, we have applied a one-half
factor again, or $400,000 per engine line. Tooling costs for CDPF-only
and for DOC engines are attributed solely to PM control.
For those manufacturers selling into both the highway and nonroad
markets, we have estimated one-half the baseline tooling cost, or
$800,000, for those engine lines requiring a CDPF/NOX
adsorber system. We believe this is reasonable since many nonroad
engines are produced on the same engine line with their highway
counterparts. For such lines, we believe very little to no tooling
costs would be incurred. For engine lines without a highway
counterpart, something approaching the $1.6 million tooling cost would
be applicable. For this analysis, we have assumed a 50/50 split of
engine product lines for highway manufacturers and, therefore, a 50
percent factor applied to the $1.6 million baseline. These tooling
costs would be split evenly between NOX control and PM
control. For engine lines <75 horsepower, we have used the same tooling
costs as the nonroad-only manufacturers because these engines tend not
to have a highway counterpart. Therefore, for those engine lines
requiring only a CDPF (i.e., those between 25 and 75 horsepower), we
have estimated a tooling cost of $800,000. Similarly, the tooling costs
for DOC and/or engine-out engine lines has been estimated to be
$400,000. Tooling costs for CDPF-only and for DOC engines are
attributed solely to PM control.
We expect engines in the 25 to 50 horsepower range to apply EGR
systems to meet the proposed NOX standards for 2013. For
these engines, we have included an additional tooling cost of $40,000
per engine line, consistent with the EGR-related tooling cost estimated
for 50-100 horsepower engines in our Tier 2/3 rulemaking. This tooling
cost is applied equally to all engine lines in that horsepower range
regardless of the markets into which the manufacturer sells. We have
applied this tooling cost equally because engines in this horsepower
range do not tend to have highway counterparts. Tooling costs for EGR
systems are attributed solely to NOX control.
We have applied all the above tooling costs to all manufacturers
that appear to actually make engines. We have not
[[Page 28443]]
eliminated joint venture manufacturers because these manufacturers
would still need to invest in tooling to make the engines even if they
do not conduct any R&D. We have assumed that all tooling costs are
incurred one year in advance of the new standard and are recovered over
a five year period following implementation of the new standard; all
tooling costs are marked up seven percent to reflect the time value of
money. As done for R&D costs, we have attributed a portion of the
tooling costs to U.S. sales and a portion to sales in other countries
expected to have similar levels of emission control. More information
is contained in Chapter 6 of the draft RIA and we request comment on
how we have applied our tooling cost estimates and to whom we have
applied them.
Using this methodology, we estimate the total tooling expenditures
attributable to the proposed standards at $67 million.
iii. Engine Certification Costs
Manufacturers will incur more than the normal level of
certification costs during the first few years of implementation
because engines will need to be certified to the new emission
standards. Consistent with our recent standard setting regulations, we
have estimated engine certification costs at $60,000 per new engine
certification to cover testing and administrative costs. To this we
have added the proposed certification fee of $2,156 per new engine
family. This cost, $62,156 per engine family was used for <75
horsepower engines certifying to the 2008 standards. For 25 to 75
horsepower engines certifying to the 2013 standards, and for
£75 horsepower engines certifying to their proposed
standards, we have added costs to cover the proposed test procedures
for nonroad diesel engines (i.e., the transient test and the NTE);
these costs were estimated at $10,500 per engine family. These
certification costs--whether it be the $62,156 or the $72,656 per
engine family--apply equally to all engine families for all
manufacturers regardless of into what markets the manufacturer sells.
We have applied these certification costs to only the US sold engines
because the certification conducted for US sales is not presumed to
fulfill the certification requirements of other countries.
Applying these costs to each of the 665 engine families as they are
certified to a new emissions standard results in total costs of $72
million expended during implementation of the proposed standards. These
costs are attributed to NOX and PM control consistent with
the phase-in of the new emissions standards--where new NOX
and PM standards are introduced together, the certification costs are
split evenly; where only a new PM standard is introduced, the
certification costs are attributed to PM only; where a NOX
phase-in becomes 100% in a year after full implementation of a PM
standard, the certification costs are attributed to NOX
only. All certification costs are assumed to occur one year prior to
the new emission standard and are then recovered over a five year
period following compliance with the new standard; all certification
costs are marked up seven percent to reflect the time value of money.
b. Engine Variable Costs
This section summarizes the detailed analysis presented in the
draft RIA for this proposed rule. We encourage the reader to refer to
chapter 6 of that draft RIA for the details of what is presented here
and encourage comments and supporting data and/or analysis regarding
those details. Of particular interest are comments regarding the costs
of precious metals, or platinum group metals (PGM). The PGM costs are a
significant fraction of the total costs for aftertreatment devices. For
our analysis, we have used the 2002 annual average costs for platinum
and rhodium (the two PGMs we expect will be used) because we believe
they represent a better estimate of the cost for PGM than other
metrics. We request comment on this approach and whether an alternative
approach would be more appropriate. Specifically, we request comment
regarding the use of a five year average in place of the one year
average we have used. Additionally, EPA invites comment on the impacts,
if any, that this rulemaking would have in the context of a variety of
rulemakings on the market impacts on precious metals.
i. NOX Adsorber System Costs
The NOX adsorber system that we are anticipating would
be applied for Tier 4 would be the same as that used for highway
applications. In order for the NOX adsorber to function
properly, a systems approach that includes a reductant metering system
and control of engine A/F ratio is also necessary. Many of the new air
handling and electronic system technologies developed in order to meet
the Tier 2/3 nonroad engine standards can be applied to accomplish the
NOX adsorber control functions as well. Some additional
hardware for exhaust NOX or O2 sensing and for
fuel metering will likely be required. The cost estimates include a DOC
for clean-up of hydrocarbon emissions that occur during NOX
adsorber regeneration events. We have also assumed that warranty costs
would increase due to the application of this new hardware. Chapter 6
of the draft RIA contains the details for how we estimated costs
associated with the new NOX control technologies required to
meet the proposed Tier 4 emission standards. These costs are estimated
to increase engine costs by roughly $670 in the near-term for a 150
horsepower engine, and $2,070 in the near-term for a 500 horsepower
engine. In the long-term, we estimate these costs to be $550 and $1,670
for the 150 horsepower and 500 horsepower engines, respectively. Note
that we have estimated costs for all engines in all horsepower ranges,
and these estimates are presented in detail in the draft RIA.
Throughout this discussion of engine and equipment costs, we present
costs for a 150 and a 500 horsepower engine for illustrative purposes.
ii. Catalyzed Diesel Particulate Filter (CDPF) Costs
CDPFs can be made from a wide range of filter materials including
wire mesh, sintered metals, fibrous media, or ceramic extrusions. The
most common material used for CDPFs for heavy-duty diesel engines is
cordierite. We have based our cost estimates on the use of silicon
carbide (SiC) even though it is more expensive than other filter
materials. We request comment on our assumption that SiC will be used
in favor of cordierite. We estimate that the CDPF systems will add $780
to engine costs in the near-team for a 150 horsepower engine and $2,770
in the near-term for a 500 horsepower engine. In the long-term, we
estimate these CDPF system costs to be $590 and $2,110 for the 150
horsepower and the 500 horsepower engines, respectively.
iii. CDPF Regeneration System Costs
Application of CDPFs in nonroad applications is expected to present
challenges beyond those of highway applications. For this reason, we
anticipate that some additional hardware beyond the diesel particulate
filter itself may be required to ensure that CDPF regeneration occurs.
For some engines this may be new fuel control strategies that force
regeneration under some circumstances, while in other engines it might
involve an exhaust system fuel injector to inject fuel upstream of the
CDPF to provide necessary heat for regeneration under some operating
conditions. We estimate the near-term costs of a CDPF regeneration
system to be $190 for a 150
[[Page 28444]]
horsepower engine and $320 for a 500 horsepower engine. In the long-
term, we estimate these costs at $140 and $240, respectively.
iv. Closed-Crankcase Ventilation System (CCV) Costs
We are proposing to eliminate the exemption that allows turbo-
charged nonroad diesel engines to vent crankcase gases directly to the
environment. Such engines are said to have an open crankcase system. We
project that this requirement to close the crankcase on turbo-charged
engines would force manufacturers to rely on engineered closed
crankcase ventilation systems that filter oil from the blow-by gases
prior to routing them into either the engine intake or the exhaust
system upstream of the CDPF. We have estimated the initial cost of
these systems to be roughly $40 for low horsepower engines and up to
$100 for very high horsepower engines. These costs are incurred only by
turbo-charged engines because today's naturally aspirated engines
already have CCV systems.
v. Variable Costs for Engines Below 75 Horsepower and Above 750
Horsepower
This proposal includes standards for engines <25 horsepower that
begin in 2008, and two sets of standards for 25 to 75 horsepower
engines--one set that begins in 2008 and another that begins in 2013.
The 2008 standards for all engines <75 horsepower are of similar
stringency and are expected to result in similar technologies (i.e.,
the addition of a DOC). The 2013 standards for 25 to 75 horsepower
engines are considerably more stringent than the 2008 standards and are
expected to force the addition of a CDPF along with some other engine
hardware to enable the proper functioning of that new technology. More
detail on the mix of technologies expected for all engines <75
horsepower is presented in section III. As discussed there, if changes
are needed to comply, we expect manufacturers to comply with the 2008
standards through either engine improvements or through the addition of
a DOC. From a cost perspective, we have projected that engines would
comply by either adding a DOC or by making some engine modifications
resulting in engine-out emission reductions. Presumably, the
manufacturer would choose the least costly approach that provided the
necessary reduction. If engine-out modifications are less costly than a
DOC, our estimate here is conservative. If the DOC proves to be less
costly, then our estimate is representative of what most manufacturers
would do. Therefore, we have assumed that, beginning in 2008, all
engines below 75 horsepower add a DOC. Note that this is a conservative
estimate in that we have assume this cost for all engines when, as
discussed in section IV, some engines <75 horsepower already meet the
proposed PM standards. We have estimated this added hardware to result
in an increased engine cost of $150 in the near-term and $140 in the
long-term for a 30 horsepower engine.
We have also projected that some engines in the 25 to 75 horsepower
range would have to upgrade their fuel systems to accommodate the CDPF.
We have estimated the incremental costs for these fuel systems at
roughly $740 in the 25-50 horsepower range, and around $430 in the 50-
75 horsepower range. This difference reflects a different base fuel
system, with the smaller engines assumed to have mechanical fuel
systems and the larger engines assumed to already be electronic. The
electronic systems will incur lower costs because they already have the
control unit and electronic fuel pump. Also, we have assumed these fuel
changes would occur for only direct injection (DI) engines; indirect
injection engines (IDI) are assumed to remain IDI but to add more
hardware as part of their CDPF regeneration system to ensure proper
regeneration under all operating conditions. Such a regeneration
system, described above, is expected to cost roughly twice that
expected for DI engines, or around $320 for a 30 horsepower IDI engine
versus $160 for a DI engine.
We have also projected that engines in the 25-50 horsepower range
would add cooled EGR to comply with their new NOX standard.
We have estimated that this would add $90 in the near-term and $70 in
the long-term to the cost of a 30 horsepower engine.
We believe there are factors that would cause variable hardware
costs to decrease over time, making it appropriate to distinguish
between near-term and long-term costs. Research in the costs of
manufacturing has consistently shown that as manufacturers gain
experience in production, they are able to apply innovations to
simplify machining and assembly operations, use lower cost materials,
and reduce the number or complexity of component parts.\289\ Our
analysis, as described in more detail in the draft RIA, incorporates
the effects of this learning curve by projecting that the variable
costs of producing the low-emitting engines decreases by 20 percent
starting with the third year of production. For this analysis, we have
assumed a baseline that represents such learning already having
occurred once due to the 2007 highway rule (i.e., a 20 percent
reduction in emission control device costs is reflected in our near-
term costs). We have then applied a single learning step from that
point in this analysis. We invite comment on this methodology to
account for the learning curve phenomenon and also request comment on
whether learning is likely to reduce costs even further in this
industry (e.g., should a second learning step be applied to our near-
term costs?). Additionally, manufacturers are expected to apply ongoing
research to make emission controls more effective and to have lower
operating costs over time. However, because of the uncertainty involved
in forecasting the results of this research, we conservatively have not
accounted for it in this analysis.
---------------------------------------------------------------------------
\289\ ``Learning Curves in Manufacturing,'' Linda Argote and
Dennis Epple, Science, February 23, 1990, Vol. 247, pp. 920-924.
---------------------------------------------------------------------------
c. Engine Operating Costs
We are projecting that a variety of new technologies will be
introduced to enable nonroad engines to meet the proposed Tier 4
emissions standards. Primary among these are advanced emission control
technologies and low-sulfur diesel fuel. The technology enabling
benefits of low-sulfur diesel fuel are described in section III, and
the incremental cost for low-sulfur fuel is described in section V.A.
The new emission control technologies are themselves expected to
introduce additional operating costs in the form of increased fuel
consumption and increased maintenance demands. Operating costs are
estimated in the draft RIA over the life of the engine and are
expressed in terms of cents/gallon of fuel consumed. In section V.C.3,
we present these lifetime operating costs as a net present value (NPV)
in 2001 dollars for several example pieces of equipment.
Total operating cost estimates include the following elements: the
change in maintenance costs associated with applying new emission
controls to the engines; the change in maintenance costs associated
with low sulfur fuel such as extended oil change intervals; the change
in fuel costs associated with the incrementally higher costs for low
sulfur fuel, and the change in fuel costs due to any fuel consumption
impacts associated with applying new emission controls to the engines.
This latter cost is attributed to the CDPF and its need for periodic
regeneration which we estimate may result in a one percent fuel
consumption increase where a NOX
[[Page 28445]]
adsorber is also applied, or a two percent fuel consumption increase
where no NOX adsorber is applied (refer to chapter 6,
section 6.2.3.3). Maintenance costs associated with the new emission
controls on the engines are expected to increase since these devices
represent new hardware and, therefore, new maintenance demands. For
CDPF maintenance, we have used a maintenance interval of 3,000 hours
for smaller engines and 4,500 hours for larger engines and a cost of
$65 through $260 for each maintenance event. For closed-crankcase
ventilation (CCV) systems, we have used a maintenance interval of 675
hours for all engines and a cost per maintenance event of $8 to $48 for
small to large engines. Offsetting these maintenance cost increases
would be a savings due to an expected increase in oil change intervals
because low sulfur fuel would be far less corrosive than is current
nonroad diesel fuel. Less corrosion would mean a slower acidification
rate (i.e., less degradation) of the engine lubricating oil and,
therefore, more operating hours between needed oil changes. As
discussed in section V.B, the use of 15 ppm sulfur fuel can extend oil
change intervals by as much as 35 percent for both new and existing
nonroad engines and equipment. We have used a 35 percent increase in
oil change interval along with costs per oil change of $70 through $400
to arrive at estimated savings associated with increased oil change
intervals.
These operating costs are expressed as a cent/gallon cost (or
savings). As a result, operating costs are directly proportional to the
amount of fuel consumed by the engine. We have estimated these
operating costs, inclusive of fuel-related costs, to be 3.4 cents/
gallon for a 150 horsepower engine and 4.2 cents/gallon for a 500
horsepower engine. More detail on operating costs can be found in
chapter 6 of the draft RIA.
The existing fleet will also benefit from lower maintenance costs
due to the use of low sulfur diesel fuel. The operating costs for the
existing fleet are discussed in Section V.B.
2. Equipment Cost Impacts
In addition to the costs directly associated with engines that
incorporate new emission controls to meet new standards, we expect cost
increases due to the need to redesign the nonroad equipment in which
these engines are used. Such redesigns would probably be necessary due
to the expected addition of new emission control systems, but could
also occur if the engine has a different shape or heat rejection rate,
or is no longer made available in the configuration previously used.
Based on their past experiences, equipment manufacturers have told EPA
that a major concern with a new standard is their ability to redesign a
large number of applications in a short period of time. Therefore, we
have provided equipment manufacturers transition flexibility provisions
to help them avoid business disruptions resulting from the changes
associated with new emission standards. These flexibility provisions
are presented in detail in Section III.E.4.
In assessing the economic impact of the new emission standards, EPA
has made a best estimate of the modifications to equipment that relate
to packaging (installing engines in equipment engine compartments). The
incremental costs for new equipment would be comprised of fixed costs
(for redesign to accommodate new emission control devices) and variable
costs (for new equipment hardware and for labor to install new emission
control devices). Note that the fixed costs do not include
certification costs, as did the engine fixed costs, because equipment
is not certified to emission standards. We have attributed all changes
in operating costs (e.g., additional maintenance) to the cost estimates
for engines. Included in section V.C.3 is a discussion of several
example pieces of equipment (e.g., skid/steer loader, dozer, etc.) and
the costs we have estimated for these specific example pieces of
equipment. Full details of our equipment cost analysis can be found in
chapter 6 of the draft RIA. All costs are presented in 2001 dollars.
a. Equipment Fixed Costs
The most significant changes anticipated for equipment redesign are
changes to accommodate the physical changes to engines, especially for
those engines that add PM traps and NOX adsorbers. The costs
for engine development and the emission control devices are included as
costs to the engines, as described above. What remains to be quantified
for equipment manufacturers is the effort to integrate the engine and
emissions control devices into the overall functioning of the
equipment. What remains to be quantified for equipment manufacturers is
the effort to integrate the engine and emissions control devices into
the overall functioning of the equipment. We have allocated extensive
engineering time for this effort.
The costs we have estimated are based on engine power and whether
an application is non-motive (e.g., a generator set) or motive (e.g., a
skid steer loader). The designs we have considered to be non-motive are
those that lack a propulsion system. In addition, the proposed emission
standards for engines rated under 25 horsepower and the proposed 2008
standards for 25-75 horsepower engines are projected to require no
significant equipment redesign beyond that done to accommodate the Tier
2 standards. We expect that these engines would comply with the
proposesd Tier 4 standards through either engine modifications to
reduce engine-out emissions or through the addition of a DOC. We have
projected that engine modifications would not affect the outer
dimensions of the engine and that a DOC would replace the existing
muffler. Therefore, either approach taken by the engine manufacturer
should have minimal to no impact on the equipment design. Nonetheless,
we have conservatively estimated their redesign costs at $50,000 per
model.
A number of equipment manufacturers have shared detailed
information with us regarding the investments made for Nonroad Tier 2
equipment redesign efforts, as well as redesign estimates for
significant changes such as installing a new engine design. These
estimates range from approximately $50,000 for some lower powered
equipment models to well over $1 million dollars for high horsepower
equipment with very challenging design constraints. Based on that
input, for the proposed Tier 4 standards, we have estimated that
equipment redesign costs would range from $50,000 per model for 25
horsepower equipment up to $750,000 per model for 300 horsepower
equipment and above. We have attributed only a portion of the equipment
redesign costs to U.S. sales in a manner consistent with that taken for
engine R&D costs and engine tooling costs. In addition, we expect
manufacturers to incur some fixed costs to update service and operation
manuals to address the maintenance demands of new emission control
technologies and the new oil service intervals which we estimate to be
between $2,500 and $10,000 per equipment model.
These equipment fixed costs (redesign and manual updates) were then
allocated appropriately to each new model to arrive at a total
equipment fixed cost of $697 million. We have assumed that these costs
would be recovered over a ten year period at a seven percent interest
rate.
b. Equipment Variable Costs
Equipment variable cost estimates are based on costs for additional
materials to mount the new hardware (i.e., brackets and bolts required
to secure the
[[Page 28446]]
aftertreatment devices) and additional sheet metal assuming that the
body cladding of a piece of equipment (i.e., the hood) might change to
accommodate the aftertreatment system. Variable costs also include the
labor required to install these new pieces of hardware. For engines
£75 horsepower--those expected to incorporate CDPF and
NOX adsorber technology--the amount of sheet metal is based
on the size of the aftertreatment devices.
For equipment of 150 horsepower and 500 horsepower, respectively,
we have estimated the costs to be roughly $60 to $140. Note that we
have estimated costs for equipment in all horsepower ranges, and these
estimates are presented in detail in the draft RIA. Throughout this
discussion of engine and equipment costs, we present costs for a 150
and a 500 horsepower engine for illustrative purposes.
3. Overall Engine and Equipment Cost Impacts
To illustrate the engine and equipment cost impacts we are
estimating for the proposed standards, we have chosen several example
pieces of equipment and presented the estimated costs for them. Using
these examples, we can calculate the costs for a specific piece of
equipment in several horsepower ranges and better illustrate the cost
impacts of the proposed standards. These costs along with information
about each example piece of equipment are shown in Table V.C-1. Costs
presented are near-term and long-term costs for the final standards to
which each piece of equipment would comply. Long-term costs are only
variable costs and, therefore, represent costs after all fixed costs
have been recovered and all projected learning has taken place.
Included in the table are estimated prices for each piece of equipment
to provide some perspective on how our estimated control costs relate
to existing equipment prices.
Table V.C-1--Near-Term and Long-Term Costs for Several Example Pieces of Equipmenta
($2001, for the final emission standards to which the equipment must comply)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Skid/steer Off-highway
GenSet loader Backhoe Dozer Ag tractor Dozer truck
--------------------------------------------------------------------------------------------------------------------------------------------------------
Horsepower 9 hp 33 hp 76 hp 175 hp 250 hp 503 hp 1,000 hp
Incremental engine & equipment cost
Long-term $120 $760 $1,210 $2,590 $2,000 $4,210 $6,780
Near-term $170 $1,100 $1,680 3,710 $2,950 $6,120 $10,100
Estimated equipment price when new b $3,500 $13,500 $50,000 $235,000 $130,000 $575,000 $700,000
Incremental operating costs c -$90 $40 $370 $1,550 $1,320 $4,950 $12,550
Baseline operating costs (fuel & oil $940 $2,680 $7,960 $77,850 $23,750 $77,850 $179,530
only) c
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
a Near-term costs include both variable costs and fixed costs; long-term costs include only variable costs and represent those costs that remain
following recovery of all fixed costs.
b ``Estimated Price of New Nonroad Example Equipment,'' memorandum from Zuimdie Guerra to docket A-2001-28.
c Present value of lifetime costs.
More detail and discussion regarding what these costs and prices
mean from an economic impact perspective can be found in section V.E.
D. Annual Costs and Cost Per Ton
One tool that can be used to assess the value of the proposed
standards for nonroad fuel and engines is the costs incurred per ton of
emissions reduced. This analysis involves a comparison of our proposed
program to other measures that have been or could be implemented.
We have calculated the cost per ton of our proposed program based
on the net present value of all costs incurred and all emission
reductions generated over a 30 year time window following
implementation of the program. This approach captures all of the costs
and emissions reductions from our proposed program including those
costs incurred and emissions reductions generated by the existing
fleet. The baseline (i.e., the point of comparison) for this evaluation
is the existing set of fuel and engine standards (i.e., unregulated
fuel and the Tier 2/Tier 3 program). The 30 year time window chosen is
meant to capture both the early period of the program when very few new
engines that meet the proposed standards would be in the fleet, and the
later period when essentially all engines would meet the proposed
standards.
As discussed in section IV, the proposal contains two separate fuel
programs. We are proposing a 500 ppm sulfur cap on nonroad, locomotive,
and marine fuels beginning in 2007. This fuel program, the first step
in our two step fuel program, provides significant air quality benefits
through reduced SO2 and PM emissions from both new and
existing nonroad, locomotive, and marine engines. In sections V.D.1 and
2, we summarize the cost for this program as if it remained in place
for 30 years, even though it would be supplanted by the second step of
our fuel program in 2010. We also provide an analysis of the cost per
ton for the SO2 reductions that would be realized by the 500
ppm fuel program for the same 30 year time window. In this way, the
cost per ton of the SO2 reductions realized by the 500 ppm
fuel program can be compared to other available means to control
SO2 emissions. The significant PM reductions are not
accounted for in the relative cost per ton estimate, but are accounted
for in our inventory analysis presented in section II and in the
benefits analysis presented later in this section. Additional detail
regarding all of the estimates presented here are available in the
draft RIA.
We are proposing a second step in the fuel program that would cap
nonroad fuel sulfur levels at 15 ppm beginning in 2010. This fuel
program enables the introduction of advanced emission control
technologies including CDPFs and NOX adsorbers. The
combination of the two-step fuel program and the new diesel engine
standards represents the total Tier 4 program for nonroad diesel
engines and fuel proposed today. In sections V.D.3 and 4, we present
our estimate of the annual and total costs for
[[Page 28447]]
this complete program beginning in 2007 and continuing for 30 years.
Also included is an estimate of the cost per ton of emissions
reductions realized by this program for NMHC+NOX, PM, and
SO2.
1. Annual Costs for the 500 ppm Fuel Program
Cent per gallon costs for the proposed 500 ppm fuel program (i.e.,
the reduction to a 500 ppm sulfur cap) were presented in section V.A.
Having this fuel would result in maintenance savings associated with
increased oil change intervals for both the new and the existing fleet
of nonroad, locomotive, and marine engines. These maintenance savings
were discussed in section V.B. There are no engine and equipment costs
associated with the 500 ppm fuel program because new emission standards
are not part of that proposed program. Figure V.D-1 shows the annual
costs associated with the 500 ppm fuel program.
As can be seen in Figure V.D-1, the costs for refining and
distributing the 500 ppm fuel range from $250 million in 2008 to nearly
$400 million in 2036. These control costs are largely offset by the
maintenance savings that range from $200 million in 2008 to $380
million in 2036. Despite the fact that the costs of the 500 ppm fuel
for nonroad diesel fuel is 2.5 cents/gallon and the maintenance savings
are 3 cents per gallon, the net costs are positive because of the costs
for the locomotive and marine fuel is not off-set by the maintenance
savings. As a whole, the net cost of the program in each year is
essentially zero, ranging from $50 million in the early years to only
$18 million in 2036. The net present value of the net costs and savings
associated with the proposed 500 ppm fuel program during the years 2007
to 2036 is estimated at $510 million.
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TP23MY03.009
2. Cost Per Ton for the 500 ppm Fuel Program
The 2007 fuel program would result in large reductions of both
SO2 and PM emissions. Roughly 98 percent of fuel sulfur is
converted to SO2 in the engine with the remaining two
percent being exhausted as sulfate PM. Because the majority of the
emissions reductions associated with this program would be
SOX, we have attributed all the control costs to
SOX in calculating the cost per ton associated with this
program. However, we have modeled both the SOX and PM
reductions so that our inventory and benefits analysis fully account
for them.
As noted above, we have calculated both the costs and emission
reductions of the 500 ppm fuel program as if it were to remain in place
indefinitely. Figure V.D-1 shows the costs in each year of the program,
the net present value of which is estimated at $510 million. We have
estimated the 30 year net present value of the SOX emission
reductions at 5.6 million tons.
Table V.D-1 shows the cost per ton of emissions reduced as a result
of the proposed 500 ppm fuel program. The cost per ton numbers include
costs and emission reductions that would occur from both the new and
the existing fleet (i.e., those pieces of nonroad equipment that were
sold into the market prior to the proposed emission standards) of
[[Page 28448]]
nonroad, locomotive, and marine engines.
Table V.D-1--500 ppm Fuel Program Aggregate Cost per Ton and Long-Term
Annual Cost per Ton ($2001)
------------------------------------------------------------------------
2004-2036
Discounted Long-term
Pollutant lifetime cost per
cost per ton in 2036
ton
------------------------------------------------------------------------
SOX........................................... $90 $50
------------------------------------------------------------------------
We also considered the cost per ton of the 500 ppm fuel program
without taking credit for the expected maintenance savings associated
with low sulfur fuel. Without the maintenance savings, the cost per ton
of SOX reduced would be $990 per ton for each year of the
program. More detail on how the costs and cost per ton numbers
associated with the 500 ppm fuel program were calculated can be found
in the draft RIA.
3. Annual Costs for the Proposed Two-Step Fuel Program and Engine
Program
The costs of the total proposed engine and fuel program include
costs associated with both steps in the fuel program--the reduction to
500 ppm sulfur in 2007 and the reduction to 15 ppm sulfur in 2010. Also
included are costs for the proposed 2008 engine standards for <75
horsepower engines, the proposed 2013 standards for 25 to 75 horsepower
engines, and costs for the proposed engine standards for £75
horsepower engines. Included are all maintenance costs and savings
realized by both the existing fleet (nonroad, locomotive, and marine)
and the new fleet of engines complying with the proposed standards.
Figure V.D-2 presents these results. All capital costs for fuel
production and engine and equipment fixed costs have been amortized.
The figure shows that total annual costs are estimated to be $120
million in the first year the new engine standards apply, increasing to
a peak of $1.7 billion in 2036 as increasing numbers of engines become
subject to the new standards and an ever increasing amount of fuel is
consumed. The net present value of the annualized costs over the period
from 2007 to 2036 is $20.7 billion.
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TP23MY03.010
4. Cost per Ton of Emissions Reduced for the Total Program
We have calculated the cost per ton of emissions reduced associated
with the proposed engine and fuel program. We have done this using the
net present value of the annualized costs of the program through 2036
and the net present value of the annual emission reductions through
2036. We have also calculated the cost per ton of emissions in the year
2036 using the annual costs
[[Page 28449]]
and emission reductions in that year alone. This number represents the
long-term cost per ton of emissions reduced after all fixed costs of
the program have been recovered by industry leaving only the variable
costs of control. The cost per ton numbers include costs and emission
reductions that would occur from the existing fleet (i.e., those pieces
of nonroad equipment that were sold into the market prior to the
proposed emission standards). These results are shown in Table V.D-2.
We did the cost analysis using a 3% discount rate. We will also be
conducting a similar analysis using a 7% discount rate and including
this information in the docket.
Table V.D-2--Total Proposed Fuel and Engine Program Aggregate Cost per
Ton and Long-Term Annual Cost Per Ton ($2001)
------------------------------------------------------------------------
2004-2036
Discounted Long-term
Pollutant lifetime cost per
cost per ton in 2036
ton
------------------------------------------------------------------------
NOX+NMHC...................................... $810 $530
PM............................................ 8,700 6,900
SOX........................................... \a\ 200 170
------------------------------------------------------------------------
Notes:
\a\ This result does not match that in Table 8.4-2 because the nonroad
portion of the fuel is reduced to 15 ppm and does not stay at 500
(locomotive and marine portions are kept at 500ppm). The costs to
reduce fuel sulfur from uncontrolled to 15ppm were assigned 50/50 to
NOX+NMHC and PM for the reduction to 15 ppm is to enable
aftertreatment technology.
5. Comparison With Other Means of Reducing Emissions
In comparison with other programs to control these pollutants, we
believe that the proposed programs represent a cost effective strategy
for generating substantial NOX+NMHC, PM, and SO2
reductions. This can be seen by comparing the 2007 fuel program (i.e.,
a sulfur cap of 500 ppm) cost per ton and the total program cost per
ton with a number of standards that EPA has adopted in the past. Table
V.D-3 summarizes the cost per ton of several past EPA actions for
NOX+NMHC. Table V.D-4 summarizes the cost per ton of several
past EPA actions for PM.
Table V.D-3--Cost per Ton of Previous Mobile Source Programs for NOX +
NMHC
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Tier 2 Nonroad Diesel................................... 630
Tier 3 Nonroad Diesel................................... 430
Tier 2 vehicle/gasoline sulfur.......................... 1,410-2,370
2007 Highway HD......................................... 2,260
2004 Highway HD......................................... 220-430
Off-highway diesel engine............................... 450-710
Tier 1 vehicle.......................................... 2,160-2,930
NLEV.................................................... 2030
Marine SI engines....................................... 1,230-1,940
On-board diagnostics.................................... 2,430
Marine CI engines....................................... 30-190
------------------------------------------------------------------------
Note: Costs adjusted to 2001 dollars using the Producer Price Index for
Total Manufacturing Industries.
Table V.D-4.--Cost per Ton of Previous Mobile Source Programs for PM
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Tier 1/Tier 2 Nonroad Diesel........................... 2,410
2007 Highway HD........................................ 14,280
Marine CI engines...................................... 5,480-4,070
1996 urban bus......................................... 12,870-20,590
Urban bus retrofit/rebuild............................. 31,740
1994 highway HD diesel................................. 21,930-25,670
------------------------------------------------------------------------
Note: Costs adjusted to 2001 dollars using the Producer Price Index for
Total Manufacturing Industries.
To compare the cost per ton of SO2 emissions reduced, we
looked at the cost per ton for the Title IV SO2 trading
programs. This information is found in EPA report 430/R-02-004,
``Documentation of EPA Modeling Applications (V.2.1) Using the
Integrated Planning Model'', in Figure 9.11 on page 9-14 (
www.epa.gov/airmarkets/epa-ipm/index.html#documentation). The SO2 cost
per ton results of the proposed program presented in Table V.D-2
compare very favorably with the program shown in Table V.D-5.
Table V.D-5--Cost per Ton of SO2 From EPA Base Case 2000 for the Title
IV SO2 Trading Programs
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Title IV SO2 Trading Programs............. $490 in 2010 to $610 in
2020.
------------------------------------------------------------------------
Note: Costs adjusted to 2001 dollars using the Producer Price Index for
Total Manufacturing Industries.
E. Do the Benefits Outweigh the Costs of the Standards?
Our analysis of the health and welfare benefits to be expected from
this proposal are presented in this section. Briefly, the analysis
projects major benefits throughout the period from initial
implementation of the rule through 2030, the last year analyzed. As
described below, thousands of deaths and other serious health effects
would be prevented, yielding a net present value in 2004 of those
benefits we could monetize of approximately $550 billion dollars. These
benefits exceed the net present value of the social cost of the
proposal ($17 billion) by a factor of over 30 to one.
1. What Were the Results of the Benefit-Cost Analysis?
Table V.E-1 presents the primary estimate of reduced incidence of
PM-related health effects for the years 2020 and 2030. In interpreting
the results, it is important to keep in mind the limited set of effects
we are able to monetize. Specifically, the table lists the PM-related
benefits associated with the reduction of several health effects.\290\
In 2030, we estimate that there will be 9,600 fewer fatalities per year
associated with fine PM, and the rule will result in about 5,700 fewer
cases of chronic bronchitis, 8,300 fewer hospitalizations (for
respiratory and cardiovascular disease combined), and result in
significant reductions in days of restricted activity due to
respiratory illness (with an estimated 5.7 million fewer cases). We
also estimate substantial health improvements for children from reduced
upper and lower respiratory illness, acute bronchitis, and asthma
attacks.\291\
---------------------------------------------------------------------------
\290\ Based upon recent preliminary findings by the Health
Effects Institute, the concentration-response functions used to
estimate reductions in hospital admissions may over or underestimate
the true concentration-response relationship. See letter from Dan
Greenberg, President, Health Effects Institute, May 30, 2002,
attached to letter from Dr. Hopke, dated August 8, 2002. Docket A-
2000-01, Document IV-A-145.
\291\ Our estimate incorporates significant reductions of
150,000 fewer cases of lower respiratory symptoms in children ages 7
to 14 each year, 110,000 fewer cases of upper respiratory symptoms
(similar to cold symptoms) in asthmatic children each year, and
14,000 fewer cases of acute bronchitis in children ages 8 to 12 each
year. In addition, we estimate that this rule will reduce almost
6,000 emergency room visits for asthma attacks in children each year
from reduced exposure to particles. Additional incidents would be
avoided from reduced ozone exposures. Asthma is the most prevalent
chronic disease among children and currently affects over seven
percent of children under 18 years of age.
---------------------------------------------------------------------------
Table V.E-2 presents the total monetized benefits for the years
2020 and 2030. This table also indicates with a ``B'' those additional
health and environmental effects which we were unable to quantify or
monetize. These effects are additive to estimate of total benefits, and
EPA believes there is
[[Page 28450]]
considerable value to the public of the benefits that could not be
monetized. A full listing of the benefit categories that could not be
quantified or monetized in our estimate are provided in Table V.E-5.
In summary, EPA's primary estimate of the benefits of the rule are
approximately $81 + B billion in 2030. In 2020, total monetized
benefits are approximately $43 + B billion. These estimates account for
growth in real gross domestic product (GDP) per capita between the
present and the years 2020 and 2030. As the table indicates, total
benefits are driven primarily by the reduction in premature fatalities
each year, which account for over 90 percent of total benefits.
Table V.E-1.--Reductions in Incidence of PM-Related Adverse Health
Effects Associated With the Proposed Nonroad Diesel Engine and Fuel
Standards
------------------------------------------------------------------------
Avoided incidence \a\ (cases/
year)
Endpoint -------------------------------
2020 2030
------------------------------------------------------------------------
Premature mortality \b\--Base estimate: 5,200 9,600
Long-term exposure (adults, 30 and
over)..................................
Chronic bronchitis (adults, 26 and over) 3,600 5,700
Non-fatal myocardial infarctions 9,200 16,000
(adults, 18 and older).................
Hospital admissions--Respiratory 2,400 4,500
(adults, 20 and older) \c\.............
Hospital admissions--Cardiovascular 1,900 3,800
(adults, 20 and older) \d\.............
Emergency Room Visits for Asthma (18 and 3,600 5,700
younger)...............................
Acute bronchitis (children, 8-12)....... 8,400 14,000
Lower respiratory symptoms (children, 7- 92,000 150,000
14)....................................
Upper respiratory symptoms (asthmatic 77,000 110,000
children, 9-11)........................
Work loss days (adults, 18-65).......... 650,000 960,000
Minor restricted activity days (adults, 3,900,000 5,700,000
age 18-65).............................
------------------------------------------------------------------------
Notes:
\a\ Incidences are rounded to two significant digits.
\b\ Premature mortality associated with ozone is not separately included
in this analysis
\c\ Respiratory hospital admissions for PM includes admissions for COPD,
pneumonia, and asthma.
\d\ Cardiovascular hospital admissions for PM includes total
cardiovascular and subcategories for ischemic heart disease,
dysrhythmias, and heart failure.
Table V.E-2.--EPA Primary Estimate of the Annual Quantified and
Monetized Benefits Associated With Improved PM Air Quality Resulting
From the Proposed Nonroad Diesel Engine and Fuel Standards
------------------------------------------------------------------------
Monetary Benefits\a,\ \b\
(millions 2000$, adjusted for
Endpoint income growth)
-------------------------------
2020 2030
------------------------------------------------------------------------
Premature mortality \c\ Long-term $39,000 $74,000
exposure (adults, 30 and over).........
Chronic bronchitis (WTP valuation; 1,600 2,600
adults, 26 and over)...................
Non-fatal myocardial infarctions........ 750 1,300
Hospital Admissions from Respiratory 38 74
Causes \d\.............................
Hospital Admissions from Cardiovascular 40 80
Causes \e\.............................
Emergency Room Visits for Asthma........ 1 2
Acute bronchitis (children, 8-12)....... 3 5
Lower respiratory symptoms (children, 7- 2 3
14)....................................
Upper respiratory symptoms (asthmatic 2 3
children, 9-11)........................
Work loss days (adults, 18-65).......... 90 130
Minor restricted activity days (adults, 210 320
age 18-65).............................
Recreational visibility (86 Class I 1,200 1,900
Areas).................................
-----------------
Total Monetized Benefits \f\........ 43,000 + B 81,000 + B
------------------------------------------------------------------------
Notes:
\a\ Monetary benefits are rounded to two significant digits.
\b\ Monetary benefits are adjusted to account for growth in real GDP per
capita between 1990 and the analysis year (2020 or 2030).
\c\ Valuation assumes the 5 year distributed lag structure described
earlier. Results reflect the use of two different discount rates; a 3%
rate which is recommended by EPA's Guidelines for Preparing Economic
Analyses (US EPA, 2000a), and 7% which is recommended by OMB Circular
A-94 (OMB, 1992).
\d\ Respiratory hospital admissions for PM includes admissions for COPD,
pneumonia, and asthma.
\e\ Cardiovascular hospital admissions for PM includes total
cardiovascular and subcategories for ischemic heart disease,
dysrhythmias, and heart failure.
\f\ B represents the monetary value of the unmonetized health and
welfare benefits. A detailed listing of unquantified PM, ozone, CO,
and NMHC related health effects is provided in Table V.E-5.
The estimated social cost (measured as changes in consumer and
producer surplus) in 2030 to implement the final rule from Table V.F-2
is $1.5 billion (2000$). Thus, the net benefit (social benefits minus
social costs) of the program at full implementation is approximately
$79 + B billion. In 2020, partial implementation of the program yields
net benefits of $42 + B billion. Therefore, implementation of the final
rule is expected to provide society with a net gain in social welfare
based on economic efficiency criteria. Table V.E-3 presents a summary
of the benefits,
[[Page 28451]]
costs, and net benefits of the proposed rule. Figure VE.1 displays the
stream of benefits, costs, and net benefits of the Nonroad Land-based
Diesel Vehicle Rule from 2007 to 2030. In addition, Table V-E.4
presents the net present value of the stream of benefits, costs, and
net benefits associated with the rule for this 23 year period (using a
three percent discount rate). The total net present value in 2004 of
the stream of net benefits (benefits minus costs) is $530 billion.
Table V.E-3.--Summary of Benefits, Costs, and Net Benefits of the Proposed Nonroad Diesel Engine and Fuel
Standards
----------------------------------------------------------------------------------------------------------------
2020 \a\ (billions of 2000 2030 \a\ (billions of 2000
dollars) dollars)
----------------------------------------------------------------------------------------------------------------
Social Costs \b\...................... $1.4............................... $1.5.
Social Benefits \b,\ \c,\ \d\:
CO, VOC, Air Toxic-related Not monetized...................... Not monetized.
benefits.
Ozone-related benefits............ Not monetized...................... Not monetized.
PM-related Welfare benefits....... $1.2............................... $1.9.
PM-related Health benefits........ $42+ B............................. $79 + B.
Net Benefits (Benefits-Costs) \c\. $42 + B............................ $79 + B.
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ All costs and benefits are rounded to two significant digits.
\b\ Note that costs are the total costs of reducing all pollutants, including CO, VOCs and air toxics, as well
as NOX and PM. Benefits in this table are associated only with PM, NOX and SO3 reductions.
\c\ Not all possible benefits or disbenefits are quantified and monetized in this analysis. Potential benefit
categories that have not been quantified and monetized are listed in Table V.E-5. B is the sum of all
unquantified benefits and disbenefits.
[[Page 28452]]
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TP23MY03.011
Table V.E-4.--Net Present Value in 2004 of the Stream of Benefits,
Costs, and Net Benefits for the Proposed Nonroad Diesel Engine and Fuel
Standards
[Billions of 2000$]
------------------------------------------------------------------------
------------------------------------------------------------------------
Social Costs............................................ $17
Social Benefits......................................... 550
Net Benefits............................................ \a\ 530
------------------------------------------------------------------------
Notes:
\a\ Numbers do not add due to rounding.
2. What Was Our Overall Approach to the Benefit-Cost Analysis?
The basic question we sought to answer in the benefit-cost analysis
was, ``What are the net yearly economic benefits to society of the
reduction in mobile source emissions likely to be achieved by this
proposed rulemaking?'' In designing an analysis to address this
question, we selected two future years for analysis (2020 and 2030)
that are representative of the stream of benefits and costs at partial
and full-implementation of the program.
To quantify benefits, we evaluated PM-related health effects
(including directly emitted PM, SO3, and NOX
contributions to fine particulate matter). Our approach requires the
estimation of changes in air quality expected from the rule and then
estimating the resulting impact on health. In order to characterize the
benefits of today's action, given the constraints on time and resources
available for the analysis, we adopted a benefits transfer technique
that relies on air quality and benefits modeling for a preliminary
control option for nonroad diesel engines and fuels. Results from the
modeled preliminary control option in 2020 and 2030 are then scaled and
transferred to the emission reductions expected from the proposed rule.
We also transferred modeled results by using scaling factors associated
with time to examine the stream of benefits in years other than 2020
and 2030.
More specifically, our health benefits assessment is conducted in
two phases. Due to the time requirements for running the sophisticated
emissions and air quality models needed to obtain estimates of the
benefits expected to result from implementation of the rule, it is
often necessary to select an example set of emission reductions to use
for the purposes of emissions and air quality modeling. In phase one,
we evaluate the PM and ozone related health effects associated with a
modeled preliminary control option that was a close approximation of
the proposed standards in the years 2020 and 2030. Using information
from the modeled preliminary control option on the changes in ambient
concentrations of PM and ozone, we then conduct a
[[Page 28453]]
health assessment to estimate the number of reduced incidences of
illnesses, hospitalizations, and premature fatalities associated with
this scenario and estimate the total economic value of these health
benefits. The standards we are proposing in this rulemaking, however,
are slightly different in the amount of emission reductions expected to
be achieved in 2020 and 2030 relative to the modeled scenario. Thus, in
phase two of the analysis we apportion the results of the phase one
analysis to the underlying NOX, SO3, and PM
emission reductions and scale the apportioned benefits to reflect
differences in emissions reductions between the modeled preliminary
control option and the proposed standards. The sum of the scaled
benefits for the PM, SO3, and NOX emission
reductions provide us with the total benefits of the rule.
The benefit estimates derived from the modeled preliminary control
option in phase one of our analysis uses an analytical structure and
sequence similar to that used in the benefits analyses for the Heavy
Duty Engine/Diesel Fuel final rule and in the ``section 812 studies''
to estimate the total benefits and costs of the full Clean Air
Act.\292\ We used many of the same models and assumptions used in the
Heavy Duty Engine/Diesel Fuel analysis as well as other Regulatory
Impact Analyses (RIAs) prepared by the Office of Air and Radiation. By
adopting the major design elements, models, and assumptions developed
for the section 812 studies and other RIAs, we have largely relied on
methods which have already received extensive review by the independent
Science Advisory Board (SAB), by the public, and by other federal
agencies. In addition, we will be working through the next section 812
study process to enhance our methods.\293\ Interested parties will
therefore be able to obtain further information from the section 812
study on the kinds of methods we are likely to use for estimating
benefits and costs in the final nonroad diesel rule.
---------------------------------------------------------------------------
\292\ The section 812 studies include: (1) US EPA, Report to
Congress: The Benefits and Costs of the Clean Air Act, 1970 to 1990,
October 1997 (also known as the ``Section 812 Retrospective
Report''); and (2) the first in the ongoing series of prospective
studies estimating the total costs and benefits of the Clean Air Act
(see EPA report number: EPA-410-R-99-001, November 1999). See Docket
A-99-06, Document II-A-21.
\293\ We anticipate a public SAB meeting June 11-13, 2003, in
Washington, DC, regarding components of our analytical blueprint.
Interested parties may want to consult the Web page:
http://www.epa.gov/science1.
---------------------------------------------------------------------------
The benefits transfer method used in phase two of the analysis is
similar to that used to estimate benefits in the recent analysis of the
Nonroad Large Spark-Ignition Engines and Recreational Engines standards
(67 FR 68241, November 8, 2002). A similar method has also been used in
recent benefits analyses for the proposed Industrial Boilers and
Process Heaters NESHAP and the Reciprocating Internal Combustion
Engines NESHAP.
On September 26, 2002, the National Academy of Sciences (NAS)
released a report on its review of the Agency's methodology for
analyzing the health benefits of measures taken to reduce air
pollution. The report focused on EPA's approach for estimating the
health benefits of regulations designed to reduce concentrations of
airborne particulate matter (PM).
In its report, the NAS said that EPA has generally used a
reasonable framework for analyzing the health benefits of PM-control
measures. It recommended, however, that the Agency take a number of
steps to improve its benefits analysis. In particular, the NAS stated
that the Agency should:
? Include benefits estimates for a range of regulatory
options;
? Estimate benefits for intervals, such as every five years,
rather than a single year;
? Clearly state the projected baseline statistics used in
estimating health benefits, including those for air emissions, air
quality, and health outcomes;
? Examine whether implementation of proposed regulations
might cause unintended impacts on human health or the environment;
? When appropriate, use data from non-U.S. studies to broaden
age ranges to which current estimates apply and to include more types
of relevant health outcomes;
? Begin to move the assessment of uncertainties from its
ancillary analyses into its Base analyses by conducting probabilistic,
multiple-source uncertainty analyses. This assessment should be based
on available data and expert judgment.
Although the NAS made a number of recommendations for improvement
in EPA's approach, it found that the studies selected by EPA for use in
its benefits analysis were generally reasonable choices. In particular,
the NAS agreed with EPA's decision to use cohort studies to derive
benefits estimates. It also concluded that the Agency's selection of
the American Cancer Society (ACS) study for the evaluation of PM-
related premature mortality was reasonable, although it noted the
publication of new cohort studies that should be evaluated by the
Agency.
EPA has addressed many of the NAS comments in our analysis of the
proposed rule. We provide benefits estimates for each year over the
rule implementation period for a wide range of regulatory alternatives,
in addition to our proposed emission control program. We use the
estimated time path of benefits and costs to calculate the net present
value of benefits of the rule. In the RIA, we provide baseline
statistics for air emissions, air quality, population, and health
outcomes. We have examined how our benefits estimates might be impacted
by expanding the age ranges to which epidemiological studies are
applied, and we have added several new health endpoints, including non-
fatal heart attacks, which are supported by both U.S. studies and
studies conducted in Europe. We have also improved the documentation of
our methods and provided additional details about model assumptions.
Several of the NAS recommendations addressed the issue of
uncertainty and how the Agency can better analyze and communicate the
uncertainties associated with its benefits assessments. In particular,
the Committee expressed concern about the Agency's reliance on a single
value from its analysis and suggested that EPA develop a probabilistic
approach for analyzing the health benefits of proposed regulatory
actions. The Agency agrees with this suggestion and is working to
develop such an approach for use in future rulemakings. EPA plans to
hold a meeting of its Science Advisory Board (SAB) in early Summer 2003
to review its plans for addressing uncertainty in its analyses. Our
likely approach will incorporate short-term elements intended to
provide interim methods in time for the final Nonroad rule to address
uncertainty in important analytical parameters such as the
concentration-response relationship for PM-related premature mortality.
Our approach will also include longer-term elements intended to provide
scientifically sound, peer-reviewed characterizations of the
uncertainty surrounding a broader set of analytical parameters and
assumptions, including but not limited to emissions and air quality
modeling, demographic projections, population health status,
concentration-response functions, and valuation estimates.
3. What Are the Significant Limitations of the Benefit-Cost Analysis?
Every benefit-cost analysis examining the potential effects of a
change in
[[Page 28454]]
environmental protection requirements is limited to some extent by data
gaps, limitations in model capabilities (such as geographic coverage),
and uncertainties in the underlying scientific and economic studies
used to configure the benefit and cost models. Deficiencies in the
scientific literature often result in the inability to estimate
quantitative changes in health and environmental effects, such as
potential increases in premature mortality associated with increased
exposure to carbon monoxide. Deficiencies in the economics literature
often result in the inability to assign economic values even to those
health and environmental outcomes which can be quantified. While these
general uncertainties in the underlying scientific and economics
literatures, which can cause the valuations to be higher or lower, are
discussed in detail in the Regulatory Support Document and its
supporting documents and references, the key uncertainties which have a
bearing on the results of the benefit-cost analysis of this final rule
include the following:
? The exclusion of potentially significant benefit categories
(such as health and ecological benefits of reduction in CO, VOCs, air
toxics, and ozone);
? Errors in measurement and projection for variables such as
population growth;
? Uncertainties in the estimation of future year emissions
inventories and air quality;
? Uncertainties associated with the scaling of the results of
the modeled benefits analysis to the proposed standards, especially
regarding the assumption of similarity in geographic distribution
between emissions and human populations and years of analysis;
? Variability in the estimated relationships of health and
welfare effects to changes in pollutant concentrations;
? Uncertainties in exposure estimation;
? Uncertainties associated with the effect of potential
future actions to limit emissions.
Despite these uncertainties, we believe the benefit-cost analysis
provides a reasonable indication of the expected economic benefits of
the proposed rulemaking in future years under a set of assumptions.
One significant limitation to the benefit transfer method applied
in this analysis is the inability to scale ozone-related benefits.
Because ozone is a homogeneous gaseous pollutant, it is not possible to
apportion ozone benefits to the precursor emissions of NOX
and VOC. Coupled with the potential for NOX reductions to
either increase or decrease ambient ozone levels, this prevents us from
scaling the benefits associated with a particular combination of VOC
and NOX emissions reductions to another. Because of our
inability to scale ozone benefits, we do not include ozone benefits as
part of the monetized benefits of the proposed standards. For the most
part, ozone benefits contribute substantially less to the monetized
benefits than do benefits from PM, thus their omission will not
materially affect the conclusions of the benefits analysis. Although we
expect economic benefits to exist, we were unable to quantify or to
value specific changes in ozone, CO or air toxics because we did not
perform additional air quality modeling.
There are also a number of health and environmental effects which
we were unable to quantify or monetize. A full appreciation of the
overall economic consequences of the proposed rule requires
consideration of all benefits and costs expected to result from the new
standards, not just those benefits and costs which could be expressed
here in dollar terms. A complete listing of the benefit categories that
could not be quantified or monetized in our estimate are provided in
Table V.E-5. These effects are denoted by ``B'' in Table V.E-3 above,
and are additive to the estimates of benefits.
Table V.E-5.--Additional, Non-monetized Benefits of the Proposed Nonroad
Diesel Engine and Fuel Standards
------------------------------------------------------------------------
Pollutant Unquantified effects
------------------------------------------------------------------------
Ozone Health................. Premature mortality.\a\
Increased airway responsiveness to
stimuli.
Inflammation in the lung.
Chronic respiratory damage.
Premature aging of the lungs.
Acute inflammation and respiratory cell
damage.
Increased susceptibility to respiratory
infection.
Non-asthma respiratory emergency room
visits.
Increased school absence rates.
Ozone Welfare................ Decreased yields for commercial forests
(for example, Western US).
Decreased yields for fruits and
vegetables.
Decreased yields for non-commercial
crops.
Damage to urban ornamental plants.
Impacts on recreational demand from
damaged forest aesthetics.
Damage to ecosystem functions.
PM Health.................... Infant mortality.
Low birth weight.
Changes in pulmonary function.
Chronic respiratory diseases other than
chronic bronchitis.
Morphological changes.
Altered host defense mechanisms.
Cancer.
Non-asthma respiratory emergency room
visits.
PM Welfare................... Visibility in many Class I areas.
Residential and recreational visibility
in non-Class I areas.
Soiling and materials damage.
Damage to ecosystem functions.
[[Page 28455]]
Nitrogen and Sulfate Impacts of acidic sulfate and nitrate
Deposition Welfare. deposition on commercial forests.
Impacts of acidic deposition to
commercial freshwater fishing.
Impacts of acidic deposition to
recreation in terrestrial ecosystems.
Reduced existence values for currently
healthy ecosystems.
Impacts of nitrogen deposition on
commercial fishing, agriculture, and
forests.
Impacts of nitrogen deposition on
recreation in estuarine ecosystems.
Damage to ecosystem functions.
CO Health.................... Premature mortality.\a\
Behavioral effects.
HC Health \b\................ Cancer (benzene, 1,3-butadiene,
formaldehyde, acetaldehyde).
HC Welfare................... Direct toxic effects to animals.
Bioaccumulation in the food chain.
Damage to ecosystem function.
Odor.
------------------------------------------------------------------------
Notes:
\a\ Premature mortality associated with ozone and carbon monoxide is not
separately included in this analysis. In this analysis, we assume that
the ACS/Krewski, et al. C-R function for premature mortality captures
both PM mortality benefits and any mortality benefits associated with
other air pollutants. A copy of Krewski, et al., can be found in
Docket A-99-06, Document No. IV-G-75.
\b\ Many of the key hydrocarbons related to this rule are also hazardous
air pollutants listed in the Clean Air Act.
F. Economic Impact Analysis
An Economic Impact Analysis (EIA) was prepared to estimate the
economic impacts of this proposal on producers and consumers of nonroad
engines and equipment and related industries. The Nonroad Diesel
Economic Impact Model (NDEIM), developed for this analysis, was used to
estimate market-level changes in price and outputs for affected engine,
equipment, fuel, and application markets as well as the social costs
and their distribution across economic sectors affected by the program.
This section presents the results of the economic impact analysis. A
detailed description of the NDEIM, the model inputs, and several
sensitivity analyses can be found in chapter 10 of the Draft Regulatory
Impact Analysis prepared for this proposal.
1. What Is an Economic Impact Analysis?
Regulatory agencies conduct economic impact analyses of potential
regulatory actions to inform decision makers about the effects of a
proposed regulation on society's current and future well-being. In
addition to informing decision makers within the Agency, economic
impact analyses are conducted to meet the statutory and administrative
requirements imposed by Congress and the Executive office. The Clean
Air Act requires an economic impact analysis under section 317, while
Executive Order 12866--Regulatory Planning and Review requires
Executive Branch agencies to perform benefit-costs analyses of all
rules it deems to be ``significant'' (typically over $100 million
annual social costs) and submit these analyses to the Office of
Management and Budget (OMB) for review. This economic impact analysis
estimates the potential market impacts of the proposed rule's
compliance costs and provides the associated social costs and their
distribution across stakeholders for comparison with social benefits
(as presented in Section V.E).
2. What Is EPA's Economic Analysis Approach for This Proposal?
The underlying objective of an EIA is to evaluate the effect of a
proposed regulation on the welfare of affected stakeholders and society
in general. Using information on the expected compliance costs of the
proposed program as presented in the preceding discussion, this EIA
explores how the companies that produce nonroad diesel engines,
equipment, or fuel may change their production behavior in response to
the costs of complying with the standards. It also explores how the
consumers who use the affected products may change their purchasing
decisions. For example, the construction industry may reduce purchases
if the prices of nonroad diesel equipment increase, thereby reducing
the volume of equipment sold (or market demand) for such equipment.
Alternatively, the construction industry may pass along these
additional costs to the consumers of their final goods and services by
increasing prices, which would mitigate the potential impacts on the
purchases of nonroad diesel equipment.
The conceptual approach of the NDEIM is to link significantly
affected markets to mimic how compliance costs will potentially ripple
through the economy. The compliance costs will be directly borne by
engine manufacturers, equipment manufacturers, and petroleum
refineries. Depending on market characteristics, some or all of these
compliance costs will be passed on through the supply chain in the form
of higher prices extending to producers and consumers in the
application markets (i.e., construction, agriculture, and
manufacturing). The NDEIM explicitly models these linkages and
estimates behavioral responses that lead to new equilibrium prices and
output for all related markets and the resulting distribution of costs
across stakeholders.
The NDEIM uses a multi-market partial equilibrium approach to track
changes in price and quantity for 60 integrated product markets, as
follows:
? 7 diesel engine markets (less than 25 hp, 26 to 50 hp, 51
to 75 hp, 76 to 100 hp, 101 to 175 hp, 176 to 600 hp, and greater than
600 hp; the EIA includes more horsepower categories than the standards,
allowing more efficient use of the engine compliance cost estimates
developed for this proposal).
? 42 diesel equipment markets (7 horsepower categories within
7 application categories: agricultural, construction, general
industrial, pumps and compressors, generator and welder sets,
refrigeration and air conditioning, and lawn and garden; there are 7
horsepower/application categories that did not have sales in 2000 and
are not included in the model, so the total number of diesel equipment
markets is 42 rather than 49).
? 3 application markets (agricultural, construction, and
manufacturing).
? 8 nonroad diesel fuel markets (2 sulfur content levels of
15 ppm and 500 ppm for each of 4 PADDs; PADDs 1 and
[[Page 28456]]
3 are combined for the purpose of this analysis). It should be noted
that PADD 5 includes Alaska and Hawaii. Because those two states are
geographically separate from the rest of PADD 5, we seek comment on
whether they should be considered as separate fuel markets.
The NDEIM uses an intermediate run time frame and assumes perfect
competition in the market sectors. It is a computer model comprised of
a series of spreadsheet modules that define the baseline
characteristics of the supply and demand for the relevant markets and
the relationships between them. A detailed description of the model
methodology, inputs, and parameters is provided in chapter 10 of the
draft RIA prepared for this proposal. The model methodology is firmly
rooted in applied microeconomic theory and was developed following the
OAQPS Economic Analysis Resource Document.\294\ Based on the specified
market linkages, the model is shocked by applying the engineering
compliance cost estimates to the appropriate market suppliers and then
numerically solved using an iterative auctioneer approach by ``calling
out'' new prices until a new equilibrium is reached in all markets
simultaneously.
---------------------------------------------------------------------------
\294\ U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards, Innovative Strategies and Economics
Group, OAQPS Economic Analysis Resource Document, April 1999. A copy
of this document can be found in Docket A-2001-28, Document No. II-
A-14.
---------------------------------------------------------------------------
The actual economic impacts of the proposed rule will be determined
by the ways in which producers and consumers of the engines, equipment,
and fuels affected by the proposal change their behavior in response to
the costs incurred in complying with the standards. In the NDEIM, these
behaviors are modeled by the demand and supply elasticities. The supply
elasticities for the engine and equipment markets and the demand
elasticities for the application markets were estimated using
econometric methods. The procedures and results are reported in
Appendix 10.1 of the draft RIA. Literature-based estimates were used
for the supply elasticities in the application and fuel markets.
There are two ways to handle the demand elasticities for the
engine, equipment, and fuel markets. In the approach used in NDEIM,
these demand elasticities are internally derived based on the specified
market linkages, i.e., the demand for engines, equipment, and fuel are
modeled as directly related to the supply and demand of goods and
services supplied by the final application markets. In other words, the
supply of those goods and services determines the demand for equipment
and fuel, and the supply of equipment determines the demand for
engines. Using this approach, the NDEIM predicts that engine and
equipment production will decrease by only a small amount: 0.013% and
0.014% respectively (see Table V.F-1). Also, please see draft RIA
Appendices 10A and 10B for more detailed estimates on the price
increase estimates. Because the application markets are modeled with
inelastic or unit elastic demand and supply elasticities (quantity
supplied/demanded is expected to be fairly insensitive to price changes
or they will vary directly with price changes), the model predicts that
engine and equipment manufacturers will pass along virtually all of
their costs to end users.
An alternative approach could be used in which the demand
elasticities for the equipment, engine, and fuel markets are not
derived as part of the model. They could be estimated separately or a
sensitivity analysis could be conducted that assumes more elastic
values than those generated by the NDEIM. We are continuing to
investigate this matter and will be placing additional information
about elasticities in the docket during the comment period for this
rule. We request comment on that information as well as on the
methodology and other aspects of this EIA.
The estimated engine and equipment market impacts are based solely
on the expected increase in variable costs associated with the proposed
standards. Fixed costs associated with the engine emission standards
are not included in the market analysis reported in Table IV-F-1. This
is because in an analysis of competitive markets the industry supply
curve is based on its marginal cost curve, and fixed costs are not
reflected in changes in the marginal cost curve. In addition, fixed
costs are primarily R&D costs associated with design and engineering
changes, and firms in the affected industries currently allocate funds
for these costs. Therefore, fixed costs are not likely to affect the
prices of engines or equipment. This assumption is described in greater
detail in section 10.2 of the draft RIA. R&D costs are a long-run
concern and decisions to invest or not invest in R&D are made in the
long run. If funds have to be diverted from some other activity into
R&D needed to meet the environmental regulations, then these costs
represent a component of the social costs of the rule. Therefore, fixed
costs are included in the welfare impact estimates reported in Table
V.F-2 as additional costs on producers. We also performed a sensitivity
analysis, included in chapter 10 of the draft RIA for this proposal,
that includes fixed costs as part of the model. This results in a
transfer of welfare losses from engine and equipment markets to the
application markets, but does not change the overall welfare losses
associated with the proposal.
Economic theory indicates that, in the long run, prices are
expected to reflect the average total costs of the marginal producer in
a market and not just variable costs. This suggests that it may be
necessary to treat fixed costs differently for a long-run analysis. We
will continue to investigate this effect and intend to place additional
information in the docket during the comment period for this rule. We
request comment on that information as well as on how fixed costs and
R&D expenditures are handled in the NDEIM.
In addition to the variable and fixed costs described above, there
are three additional costs components that are included in the total
social cost estimates of the proposed regulation but that are not
explicitly included in the NDEIM. These are operating savings (costs),
fuel marker costs, and spillover from 15 ppm fuel to higher sulfur
fuel. We request comment on how best to incorporate each of these costs
in the analysis.
Operating savings (costs) refers to changes in operating costs that
are expected to be realized by users of both existing and new nonroad
diesel equipment as a result of the reduced sulfur content of nonroad
diesel fuel. These include operating savings (cost reductions) due to
fewer oil changes, which accrue to nonroad engines, and marine and
locomotive engines, that are already in use as well as new nonroad
engines that will comply with the proposed standards (see section
V.B.). These savings (costs) also include any extra operating costs
associated with the new PM emission control technology which may accrue
to new engines that use this new technology. These savings (costs) are
not included directly in the model because some of the savings accrue
to existing engines and because these savings (costs) are not expected
to affect consumer decisions with respect to new engines. Instead, they
are added into the estimated welfare impacts as additional costs to the
application markets, since it is the users of these engines that will
see these savings (costs). Nevertheless, a sensitivity analysis was
also performed in which these savings (costs) are included as inputs to
the NDEIM, where they are modeled as benefits accruing to the
application producers. The results of
[[Page 28457]]
this analysis are presented in Chapter 10 of the draft RIA.
Fuel marker costs refers to costs associated with marking high
sulfur diesel fuel in the locomotive, marine, and heating oil markets
between 2007 and 2014. Marker costs are not included in the market
analysis because locomotive, marine, and heating oil markets are not
explicitly modeled in the NDEIM. Similar to the operating savings
(costs), marker costs are added into the estimated welfare impacts
separately.
The costs of fuel that spills over from the 15 ppm market to higher
grade sulfur fuel are also not included in the NDEIM but, instead, are
added into the estimated welfare impacts separately. As described in
section IV above, refiners are expected to produce more 15 ppm fuel
than is required for the nonroad diesel fuel market. This excess 15 ppm
fuel will be sold into markets that allow fuel with a higher sulfur
level (e.g., locomotive, marine diesel, or home heating fuel). Because
this spillover fuel will meet the 15 ppm limit, it is necessary to
count the costs of sulfur reduction processes against those fuels.
Consistent with the engine and equipment cost discussion in section
V.C. of this preamble, the EIA does not include any cost savings
associated with the proposed equipment transition flexibility program
or the proposed nonroad engine ABT program. As a result, the results of
this EIA can be viewed as somewhat conservative, in this respect.
3. What Are the Results of this Analysis?
The economic analysis consists of two parts: a market analysis and
welfare analysis. The market analysis looks at expected changes in
prices and quantities for directly and indirectly affected market
commodities. The welfare analysis looks at economic impacts in terms of
annual and present value changes in social costs. For this proposed
rule, the social costs are computed as the sum of market surplus offset
by operating cost savings. Market surplus is equal to the aggregate
change in consumer and producer surplus based on the estimated market
impacts associated with the proposed rule. Operating cost savings are
associated with the decreased sulfur content of diesel fuel. These
include maintenance savings (cost reductions) and changes in fuel
efficiency. Increased maintenance costs may also be incurred for some
technologies. Operating costs are not included in the market analysis
but are instead listed as a separate category in the social cost
results tables.
Economic impact results for 2013, 2020, and 2030 are presented in
this section. The first of these years, 2013, corresponds to the first
year in which the standards affect all engines, equipment, and fuels.
It should be noted that, as illustrated in Table V.D-2, above,
aggregate program costs peak in 2014; increases in costs after that
year are due to increases in the population of engines over time. The
other years, 2020 and 2030, correspond to years analyzed in our
benefits analysis. Detailed results for all years are included in
Appendix 10.E. for this chapter.
a. Expected Market Impacts
The market impacts of this rule suggest that the overall economic
impact of the proposed emission control program on society is expected
to be small, on average. According to this analysis, the average prices
of goods and services produced using equipment and fuel affected by the
proposal are expected to increase by about 0.02 percent. The estimated
price increases and quantity reductions for engines and equipment vary
depending on compliance costs. In general, we would expect for price
increases to be higher (lower) as a result of a high (low) relative
level of compliance costs to market price. We would also expect the
change in price to be highest when compliance costs are highest.
The estimated market impacts for 2013, 2020, and 2030 are presented
in Table V.F-1. The market-level impacts presented in this table
represent production-weighted averages of the individual market-level
impact estimates generated by the model: the average expected price
increase and quantity decrease across all of the units in each of the
engine, equipment, fuel, and final application markets. For example,
the model includes seven individual engine markets that reflect the
different horsepower size categories. The 23 percent price change for
engines shown in Table V.F-1 for 2013 is an average price change across
all engine markets weighted by the number of production units.
Similarly, equipment impacts presented in Table V.F-1 are weighted
averages of 42 equipment-application markets, such as small (< 25hp)
agricultural equipment and large (£600hp) industrial
equipment. It should be noted that price increases and quantity
decreases for specific types of engines, equipment, application
sectors, or diesel fuel markets are likely to be different. But the
data in this table provide a broad overview of the expected market
impacts that is useful when considering the impacts of the proposal on
the economy as a whole. The individual market-level impacts are
presented in Chapter 10 of the draft RIA for this proposal.
Engine Market Results: Most of the variable costs associated with
the proposed rule are passed along in the form of higher prices. The
average price increase in 2013 for engines is estimated to be about 23
percent. This percentage is expected to decrease to about 19.5 percent
for 2020 and later. This expected price increase varies by engine size
because compliance costs are a larger share of total production costs
for smaller engines. In 2013, the year of greatest compliance costs
overall, the largest expected percent price increase is for engines
between 25 and 50 hp: 34 percent or $852; the average price for an
engine in this category is about $2,500. However, this price increase
is expected to drop to 26 percent, or about $647, for 2016 and later.
The smallest expected percent price increase in 2013 is for engines in
the greater than 600 hp category. These engines are expected to see
price increases of about 3 percent increase in 2013, increasing to
about 5.6 percent in 2014 and beyond. The expected price increase for
these engines is about $4,211 in 2013, increasing to about $6,950 in
2014 and later, for engines that cost on average about $125,000.
The market impact model predicts that even with these increases in
engine prices, total demand is not expected to change very much. The
expected average change in quantity is only about 69 engines per year
in 2013, out of total sales of more than 500,000 engines. The estimated
change in market quantity is small because as compliance costs are
passed along the supply chain they become a smaller share of total
production costs. In other words, firms that use these engines and
equipment will continue to purchase them even at the higher cost
because the increase in costs will not have a large impact on their
total production costs. Diesel equipment is only one factor of
production for their output of construction, agricultural, or
manufactured goods. The average decrease in the quantity of all engines
produced as a result of the regulation is estimated to be about 0.013
percent. This decrease ranges from 0.010 percent for engines less than
25 hp to 0.016 percent for engines 175 to 600 hp.
Equipment Market Results: Estimated price changes for the equipment
markets reflect both the direct costs of the proposed standards on
equipment production and the indirect cost through increased engine
prices. In 2013, the average price increase for nonroad diesel
equipment is estimated
[[Page 28458]]
to be about 5.2 percent. This percentage is expected to decrease to
about 4.5 percent for 2020 and beyond. The range of estimated price
increases across equipment types parallels the share of engine costs
relative to total equipment price, so the estimated percentage price
increase among equipment types also varies. The market price in 2013
for agricultural equipment between 175 and 600 hp is estimated to
increase about 1.4 percent, or $1,835 for equipment with an average
cost of $130,000. This compares with an estimated engine price increase
of about $1,754 for engines of that size. The largest expected price
increase in 2013 for equipment is $4,335, or 4.9 percent, for pumps and
compressors over 600 hp. This compares with an estimated engine price
increase of about $4,211 for engines of that size. The smallest
expected price increase in 2013 for equipment is $125, or 3.6 percent,
for construction equipment less than 25 hp. This compares with an
estimated engine price increase of about $124 for engines of that size.
The price changes for the equipment are less than that for engines
because the engine is only one input in the production of equipment.
The output reduction for nonroad diesel equipment is estimated to
be very small and to average about 0.014 percent for all years. This
decrease ranges from 0.005 percent for general manufacturing equipment
to 0.019 percent for construction equipment. The largest expected
decrease in quantity in 2013 is 13 units of construction equipment per
year for construction equipment between 100 and 175 hp, out of about
62,800 units. The smallest expected decrease in quantity in 2013 is
less than one unit per year in all hp categories of pumps and
compressors.
Table V.F-1.--Summary of Market Impacts ($2001)
----------------------------------------------------------------------------------------------------------------
Engineering Change in price Change in quantity
cost ---------------------------------------------------------------
Market ---------------- Absolute
Per unit ($million) Percent Absolute Percent
----------------------------------------------------------------------------------------------------------------
2013
----------------------------------------------------------------------------------------------------------------
Engines......................... $1,087 $840 22.9 -69 a -0.013
Equipment....................... 1,021 1,017 5.2 -118 -0.014
Application Markets b........... .............. .............. 0.02 .............. -0.010
No. 2 Distillate Nonroad........ 0.039 0.038 4.1 -1.38 c -0.013
---------------------------------
2020
----------------------------------------------------------------------------------------------------------------
Engines......................... $1,028 $779 19.5 -79 a -0.013
Equipment....................... 1,018 1,013 4.4 -135 -0.014
Application Markets b........... .............. .............. 0.02 .............. -0.010
No. 2 Distillate Nonroad........ 0.039 0.039 4.1 -1.58 c -0.014
---------------------------------
2030
----------------------------------------------------------------------------------------------------------------
Engines......................... $1,027 $768 19.4 -92 a -0.013
Equipment....................... 1,004 999 4.5 -156 -0.014
Application Markets b........... .............. .............. 0.02 .............. -0.010
No. 2 Distillate Nonroad........ 0.039 0.039 4.1 -1.84 c -0.014
----------------------------------------------------------------------------------------------------------------
Notes:
a The absolute change in the quantity of engines represents only engines sold on the market. Reductions in
engines consumed internally by integrated engine/equipment manufacturers are not reflected in this number but
are captured in the cost analysis. For this reason, the absolute change in the number of engines and equipment
does not match.
b The model uses normalized commodities in the application markets because of the great heterogeneity of
products. Thus, only percentage changes are presented.
c Units are in million of gallons.
Application Market Results: The estimated price increase associated
with the proposed standards in all three of the application markets is
very small and averages about 0.02 percent for all years. In other
words, on average, the prices of goods and services produced using the
engines, equipment, and fuel affected by this proposal are expected to
increase only negligibly. This is because in all of the application
markets the compliance costs passed on through price increases
represent a very small share of total production costs. For example,
the construction industry realizes an increase in production costs of
approximately $468 million in 2013 because of the price increases for
diesel equipment and fuel. However, this represents only 0.03 percent
of the $1,392 billion value of shipments in the construction industry
in 2001. The estimated average commodity price increase in 2013 ranges
from 0.06 percent in the agricultural application market to about 0.01
percent in the manufacturing application market. The percentage change
in output is also estimated to be very small and averages about 0.01
percent. This reduction ranges from less than a 0.01 percent decrease
in manufacturing to about a 0.02 percent decrease in construction. Note
that these estimated price increases and quantity decreases are average
for these sectors and may vary for specific subsectors. Also, note that
absolute changes in price and quantity are not provided for the
application markets in Table V.F-1 because normalized commodity values
are used in the market model. Because of the great heterogeneity of
manufactured or agriculture products, a normalized commodity ($1 unit)
is used in the application markets. This has no impact on the estimated
percentage change impacts but makes interpretation of the absolute
changes less informative.
Fuel Markets Results: The estimated average price increase across
all nonroad diesel fuel is about 4 percent for all years. For 15 ppm
fuel, the estimated price increase for 2013 ranges from 3.2 percent in
the East Coast region (PADD 1&3) to 9.3 percent in the mountain region
(PADD 4). The average
[[Page 28459]]
national output decrease for all fuel is estimated to be about 0.01
percent for all years, and is relatively constant across all four
regional fuel markets.
b. Expected Welfare Impacts
Social cost impact estimates are presented in Table V.F-2. A time
series of social costs from 2007 through 2030 is presented in Table
IV.F-3. As described above, the total social cost of the regulation is
the sum of the changes in producer and consumer surplus estimated by
the model plus engine maintenance savings (negative costs) resulting
from using fuel with a lower sulfur content. Total social costs in 2013
are projected to be 1,202.4 million ($2001). About 82 percent of the
total social costs is expected to be borne by producers and consumers
in the application markets, indicating that the majority of the costs
are expected to be passed on in the form of higher prices. When these
estimated impacts are broken down, 58 percent are expected to be borne
by consumers in the application markets and 42 percent are expected to
be borne by producers in the application markets. Equipment
manufacturers are expected to bear about 10 percent of the total social
costs. Engine manufacturers and diesel fuel refineries are expected to
bear 2.5 percent and 0.5 percent, respectively. The remaining 5.0
percent is accounted for by fuel marker costs and the additional costs
of 15 ppm fuel being sold in to markets such as marine diesel,
locomotive, and home heating fuel that do not require it.
In 2030, the total social costs are projected to be about $1,509.6
million ($2001). The increase is due to the projected annual growth in
the engine and equipment populations. As in earlier years, producers
and consumers in the application markets are expected to bear the large
majority of the costs, approximately 94 percent. This is consistent
with economic theory, which states that, in the long run, all costs are
passed on to the consumers of goods and services.
The present value of total social costs through 2030 is estimated
to be $16.5 billion ($2001). This present value is calculated using a
social discount rate of 3 percent from 2004 through 2030. We also
performed an analysis using an alternative 7 percent social discount
rate. Using that discount rate, the present value of the social costs
through 2030 is estimated to be $9.9 billion ($2001).
Table V.F-2.--Summary of Social Costs Estimates Associated With Primary Program: 2013, 2020, and 2030
[$million]a,b
--------------------------------------------------------------------------------------------------------------------------------------------------------
Maximum cost year (2013) Year 2020 Final year (2030)
-----------------------------------------------------------------------------------------------------------
Market Operating Market Operating Market Operating
surplus savings Total surplus savings Total surplus savings Total
($10\6\) ($10\6\) ($10\6\) ($10\6\) ($10\6\) ($10\6\)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Engine Producers Total...................... 30.2 ............ 30.2 0.1 ............ 0.1 0.1 ............ 0.1
Equipment Producers Total................... 116.1 ............ 116.1 102.6 ............ 102.6 5.3 ............ 5.3
Agricultural Equipment.................. 39.9 ............ 39.9 33.2 ............ 33.2 1.3 ............ 1.3
Construction Equipment.................. 53.0 ............ 53.0 48.2 ............ 48.2 3.8 ............ 3.8
Industrial Equipment.................... 23.2 ............ 23.2 21.2 ............ 21.2 0.2 ............ 0.2
Application Producers and Consumers Total... 1,231.8 (241.9) 989.8 1,386.5 (190.1) 1,196.3 1,598.9 (174.5) 1,424.5
Total Producer.......................... 515.7 ............ ......... 583.4 ............ ......... 672.9 ............ .........
Total Consumer.......................... 716.1 ............ ......... 803.1 ............ ......... 926.0 ............ .........
Agriculture............................. 348.7 (44.7) 304.0 339.2 (35.2) 364.0 416.5 (32.3) 429.2
Construction............................ 468.3 (77.9) 390.4 550.4 (61.2) 489.3 635.7 (56.1) 579.5
Manufacturing........................... 414.8 (119.3) 295.5 436.8 (93.8) 343.0 501.8 (86.0) 415.7
Fuel Producers Total........................ 7.8 ............ 7.8 9.0 ............ 9.0 10.5 ............ 10.5
PADD I&III.............................. 3.6 ............ 3.6 4.1 ............ 4.1 4.8 ............ 4.8
PADD II................................. 2.9 ............ 2.9 3.3 ............ 3.3 3.9 ............ 3.9
PADD IV................................. 0.8 ............ 0.8 0.9 ............ 0.9 1.0 ............ 1.0
PADD V.................................. 0.5 ............ 0.5 0.6 ............ 0.6 0.8 ............ 0.8
Nonroad Spillover........................... ......... 51.2 ......... ......... 58.6 ......... ......... 69.2
Marker Costs................................ ......... 7.3 ......... ......... ............ ......... ......... ............ .........
------------
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
\a\ Figures are in 2001 dollars.
\b\ Operating savings are shown as negative costs.
[[Page 28460]]
Table IV.F-3--National Engineering Compliance Costs and Social Costs
Estimates for the Proposed Rule: 2004-2030
[$10 \6\]
a
------------------------------------------------------------------------
Engineering Total
Year compliance social
costs costsb
------------------------------------------------------------------------
2004....................................... 0.00 0.00
2005....................................... 0.00 0.00
2006....................................... 0.00 0.00
2007....................................... 39.61 39.61
2008....................................... 130.41 130.40
2009....................................... 132.25 132.25
2010....................................... 262.02 262.01
2011....................................... 641.12 641.07
2012....................................... 1,010.37 1,010.27
2013....................................... 1,202.52 1,202.40
2014....................................... 1,329.14 1,329.01
2015....................................... 1,260.74 1,260.62
2016....................................... 1,298.40 1,298.27
2017....................................... 1,318.75 1,318.62
2018....................................... 1,325.02 1,324.89
2019....................................... 1,339.30 1,339.16
2020....................................... 1,366.79 1,366.66
2021....................................... 1,351.08 1,350.94
2022....................................... 1,349.58 1,349.44
2023....................................... 1,365.53 1,365.38
2024....................................... 1,371.60 1,371.45
2025....................................... 1,395.98 1,395.83
2026....................................... 1,419.79 1,419.64
2027....................................... 1,442.91 1,442.76
2028....................................... 1,465.41 1,465.26
2029....................................... 1,487.68 1,487.53
2030....................................... 1,509.77 1,509.61
--------------------------------------------
NPV at 3%.................................. 16,524.29 16,522.66
NPV at 7%.................................. 9,894.02 9,893.06
------------------------------------------------------------------------
Notes:
a Figures are in 2001 dollars.
b Figures in this column do not include the human health and
environmental benefits of the proposal.
VI. Alternative Program Options
Our proposed emission control program consists of a two-step
program to reduce the sulfur content of nonroad diesel fuel in
conjunction with the proposed Tier 4 engine standards. As we developed
this proposal, we evaluated a number of alternative options with regard
to the scope, level, and timing of the standards. This section presents
a summary of our analysis of several alternative control scenarios. A
complete discussion of all the alternatives, their feasibility, and
their inventory, benefits, and cost impacts can be found in Chapter 12
of the draft Regulatory Impact Analysis for this proposal.
While we are interested in comments on all of the alternatives
presented, we are especially interested in comments on two alternative
scenarios which EPA believes merit further consideration in developing
the final rule: a program in which sulfur levels are required to be
reduced to 15 ppm in essentially a single step, and a variation on the
proposed two-step fuel control program, in which the second step of
sulfur control to 15 ppm in 2010 would apply to locomotive and marine
diesel fuel in addition to nonroad diesel fuel. This section describes
these two options in greater detail; additional information can be
found in Chapter 12 of the draft Regulatory Impact Analysis for this
proposal.
A. Summary of Alternatives
We developed emissions, benefits, and cost analyses for a number of
alternatives. The alternatives we considered can be categorized
according to the structure of their fuel requirements: whether the 15
ppm fuel sulfur limit is reached in two-steps, like the proposed
program, or one-step.
One-step alternatives are those in which the fuel sulfur standard
is applied in a single step: there are no fuel-based phase-ins. We
evaluated three one-step alternatives. Option 1 is described in detail
in Section VI.B, below. We considered two other one-step alternatives
which differ from Option 1 in the timing of the fuel option (2006 or
2008) and the engines standards (level of the standards and when they
are introduced). As described in Table IV-1, Option 1b differs from
Option 1 regarding the timing of the fuel standards, while Option 1a
differs from Option 1 in terms of the engine standards. Both Option 1a
and 1b would also extend the 15 ppm fuel sulfur limit to locomotive and
marine diesel fuel as well.
Two-step alternatives are those in which the fuel sulfur standard
is set first at 500 ppm and then is reduced to 15 ppm. The two-step
alternatives vary from the proposal in terms of both the timing and
levels of the engine standards and the timing of the fuel standards.
Option 2a is the same as the proposed program except the 500 ppm fuel
standard is introduced a year earlier, in 2006. Option 2b is the same
as the proposed program except the 15 ppm fuel standard is introduced a
year earlier in 2009 and the trap-based PM standards begin earlier for
all engines. Option 2c is the same as the proposed program except the
15 ppm fuel standard is introduced a year earlier in 2009 and the trap-
based PM standards begin earlier for engines 175-750 hp. Option 2d is
the same as the proposed program except the NOX standard is
reduced to 0.30 g/bhp-hr for engines 25-75 hp, and this standard is
phased in. Finally, Option 2e is the same as the proposed program
except there are no new Tier 4 NOX limits.
Options 3 and 4 are identical to the proposed program, except
Option 3 would exempt mining equipment over 750 hp from the Tier 4
standards, and Option 4 would include applying the 15 ppm sulfur limit
to both locomotive and marine diesel fuel. Option 4 is discussed in
detail in Section IV.C, below.
Option 5a and 5b are identical to the proposal except for the
treatment of engines less than 75 hp. Option 5a is identical to the
proposal except that no new program requirements would be set in Tier 4
for engines under 75 hp. Instead Tier 2 standards and testing
requirements for engines under 50 hp, and Tier 3 standards and testing
requirements for 50-75 hp engines, would continue indefinitely. The
Option 5b program is identical to the proposal except that for engines
under 75 hp only the 2008 engine standards would be set. There would be
no additional PM filter-based standard in 2013 for 25-75 hp engines,
and no additional NOX+NMHC standard in 2013 for 25-50 hp
engines.
Table VI-1 contains a summary of a number of these alternatives and
the expected emission reductions, costs, and monetized benefits
associated with them in comparison to the proposal. These alternatives
cover a broad range of possible approaches and serve to provide insight
into the many other program design alternatives not expressly evaluated
further. The analysis was done using a 3% discount rate. If we were to
use another rate, the values would change but not to such a degree as
to change our conclusions regarding the various options. A complete
discussion of all the alternatives, their feasibility, and their
inventory, benefits, and cost impacts can be found in Chapter 12 of the
draft Regulatory Impact Analysis for this proposal.
[[Page 28461]]
[GRAPHIC]
[TIFF OMITTED]
TP23MY03.012
[[Page 28462]]
[GRAPHIC]
[TIFF OMITTED]
TP23MY03.013
[[Page 28463]]
B. Introduction of 15 ppm Nonroad Diesel Sulfur Fuel in One Step
EPA carefully evaluated and is seeking comment on alternative
regulatory approaches. Instead of the proposed two-step reduction in
nonroad diesel sulfur, one alternative would require that the nonroad
diesel sulfur level be reduced to 15ppm beginning June 1, 2008. This
alternative would have the advantage of enabling use of high efficiency
exhaust emission control technology for nonroad engines as early as the
2009 model year. It also would have several disadvantages which have
prompted us not to propose it. The disadvantages in comparison to the
proposal include inadequate lead-time for engine and equipment
manufacturers and refiners, leading to increased costs and potential
market disruptions. In this section, we describe this alternative in
greater detail and discuss potential engine and fuel impacts. We also
present our estimated emission and benefit impacts. Two other one-step
fuel options which are variations of the alternative discussed in this
section, Options 1a and 1b in Table VI-1, are presented in Chapter 12
of the draft RIA for this proposal.
1. Description of the One-Step Alternative
While numerous engine standards and phase-in schedules are
possible, we considered the standards shown in Tables VI-2 and VI-3 as
being the most stringent one-step program that could be considered
potentially feasible considering cost, lead-time, and other factors.
These standards are similar to those in our proposed option, the
primary difference being the generally earlier phase-in dates for the
PM standards.
Table VI-2.--PM Standards for 1-Step Fuel Scenario
[g/bhp-hr]
----------------------------------------------------------------------------------------------------------------
Model year
Engine power -----------------------------------------------------------------
2009 2010 2011 2012 2013 2014
----------------------------------------------------------------------------------------------------------------
hp < 25....................................... 0.30 ......... ......... ......... ......... .........
25 <= hp <50.................................. 10.22 ......... ......... ......... 0.02 .........
50 <= hp <75.................................. ......... ......... ......... ......... 0.02 .........
75 <= hp <175................................. ......... ......... 0.01 ......... ......... .........
......... \a\ 50% \a\ 50% \a\ 100% ......... .........
175 <= hp <750................................ ......... 0.01 ......... ......... ......... .........
\a\ 50% \a\ 50% \a\ 100% ......... ......... .........
hp £= 750........................... ......... ......... ......... ......... 0.01 .........
......... ......... \a\ 50% \a\ 50% \a\ 50% \a\ 100%
----------------------------------------------------------------------------------------------------------------
Notes:
\a\ Percentages are the model year sales required to comply with the indicated standard.
Table VI-3.--NOX and NMHC Standards for 1-Step Fuel Scenario
[g/bhp-hr]
----------------------------------------------------------------------------------------------------------------
Model year
Engine power ---------------------------------------------
2011 2012 2013 2014
----------------------------------------------------------------------------------------------------------------
25 <= hp < 75..................................................... ......... ......... a 3.5 ...........
------------
0.30 NOX
75 <= hp <175..................................................... 0.14 NMHC
------------
b 50% b 50% b 100%
------------
0.30 NOX
175 <= hp <750.................................................... 0.14 NMHC
------------
b 50% b 50% b 50% b 100%
------------
0.30 NOX
hp £=750................................................ 0.14 NMHC
------------
b 50% b 50% b 50% b 100%
----------------------------------------------------------------------------------------------------------------
Notes:
a A 3.5 NMHC + NOX standard would apply to the 25-50 hp engines. Engines greater than 50hp are already subject
to this standard in 2008 under the existing Tier 3 program.
b Percentages are the model year sales required to comply with the indicated standards.
2. Engine Emission Impacts
The main advantage associated with this one-step approach is
pulling ahead the long-term PM engine standards. By making 15 ppm
sulfur fuel widely available by late 2008, we could accelerate the
long-term PM engine standards, leading to the introduction of precious
metal catalyzed PM traps as early as 2009, two years earlier than
possible under the two-step sulfur reduction approach. Some
stakeholders have expressed the concern that a two-step approach leads
to later than desired introduction of high-efficiency exhaust emissions
controls on nonroad diesels because this cannot happen until the 15 ppm
fuel standard goes into effect. As shown in Table VI-1, there would be
additional public health benefits associated with this one-step
approach. However, in comparison to the proposal, the additional
benefits are
[[Page 28464]]
relatively small, less than one percent or about $3 billion more than
the proposed program.\295\
---------------------------------------------------------------------------
\295\ A variation on this one-step approach would be to also
require the sulfur content of locomotive and marine fuel to meet the
15 ppm standard in 2008. The decision of whether or not to require
the sulfur content of locomotive and marine fuel to also be reduced
to 15 ppm, however, is not unique to the one step approach, and, as
discussed below is an alternative also being evaluated under our
proposed 2-step program. Were we to require locomotive and marine
diesel fuel to also meet the 15 ppm standard in 2008 under a one-
step approach, there would be additional inventory reductions of
about 10,000 tons of PM and 128,000 tons of SO3 (NPV 3%
through 2030).
---------------------------------------------------------------------------
Even though 15 ppm fuel would be available beginning June 1, 2008
under this one-step approach, we do not believe it would be feasible to
propose an aggressive turnover of new engines to trap-equipped versions
in 2009. Nor would it be possible to introduce NOX controls
any earlier than we are already proposing, model year 2011. The
proposed standards need to be coordinated with Tier 3 standards, and
with the heavy duty highway diesel standards. The coordination of Tier
4 standards with Tier 3 standards and with the development of emissions
control technology for highway diesel engines is of critical importance
to successful implementation of the Tier 4 standards. Even those
manufacturers who do not make highway engines are expected to gain
substantially from the highway PM and NOX control
development work, provided they can plan for standards set at a similar
level of stringency and timed in a way to allow for the orderly
migration of highway engine technology to nonroad applications.
Thus, although the application of high-efficiency exhaust PM
emission controls to nonroad diesels would be enabled with the
introduction of 15 ppm sulfur nonroad fuel in 2008 under a one-step
program, we believe that to require the application of PM controls
across the wide spectrum of nonroad engines shortly thereafter would
raise serious feasibility concerns that could only be resolved, if at
all, through a very large additional R&D effort undertaken roughly in
parallel with the similarly large highway R&D effort, a duplication of
effort we wish to avoid for reasons discussed in Section III. Nonroad
engine designers would need to accomplish much of this development well
before the diesel experience begins to accumulate in earnest in 2007,
in order to be ready for a 2009 first introduction date. Waiting until
2007 before initiating 2009 model year design work would risk the
possibility of product failures, limited product availability and major
market disruptions. At the same time, for those engine manufacturers
who participate in both the highway and nonroad diesel engine markets,
attempting to have concurrent engine product developments for highway
and nonroad, could result in the possibility of product failures,
limited product availability and major disruptions for the highway
market as well. Thus, in balancing their costs and burden, many
manufacturers may be forced to choose which products would be available
for 2009 and which products would be delayed for release. Manufacturers
would also incur large additional costs to redesign hundreds of engine
models and thousand of machine types to meet Tier 4 standards only one
to three years after Tier 3 standards take effect in 2006-2008. These
cost impacts are reflected in Table VI-1 and their derivation is
explained in chapter 12 of the draft RIA. This extra expenditure could
only be modestly mitigated by phasing in the standards, since a crash
R&D effort with limited benefit from highway experience would still be
necessary.
Moreover, with respect to NOX, it would be impractical
or simply infeasible to pull the standards ahead on the same schedule.
This is because EPA's highway diesel program allows manufacturers to
phase in NOX technology over 2007-2010. As a result, we do
not expect that the high-efficiency NOX control technology
could reasonably be applied to nonroad engines any earlier under a one-
step program than under a two-step program (i.e., beginning in 2011).
In summary, this option would lead us to apply PM and
NOX standards in two different model years, or else forgo
any opportunity to apply PM traps in 2009. Redesigning engines and
emission controls for early PM control and then again a couple of years
later for NOX control, on top of shortened Tier 3 stability
periods, would likely add substantial costs to the program. As
manufacturers attempt to avoid these costs and optimize their
development they may simply have to restrict product offerings for some
period, leading to price spikes and shortages due to lack of product
availability. Having the NOX and PM standards phase in
simultaneously under our proposed approach avoids cost and design
stability issues for both engine and equipment manufacturers. In
addition, the longer leadtime for the engine standards under our
proposed program will allow greater economic efficiencies for engine
manufacturers as they transfer highway emission reduction technology to
nonroad engines.
3. Fuel Impacts
In addition to the challenges associated with pulling ahead the PM
standards described above, there are also some concerns regarding the
practicality of an early 15 ppm nonroad diesel sulfur standard. A one-
step approach may result in several economic inefficiencies that would
increase the cost of the program. For example, refiners will have
little opportunity to take advantage of the newer desulfurization
technologies currently being developed. As described in sections IV and
V, refiners will only begin to be able to take advantage of these new
technologies in 2008. By 2010, the ability to incorporate them into
their refinery modifications is expected to double. If refiners have to
take steps to reduce the sulfur content of nonroad diesel fuel earlier,
they will likely have to use more expensive current technology. The
cost impacts of this decision will persist, since the choice of
technology is a long term decision. If a refiner is forced by the
effective date of the standards to employ a more expensive technology,
that choice will affect that refiner's output indefinitely, since the
cost of upgrading to the new technologies will be prohibitive. As
presented in section 5.2 of the Draft RIA, we estimate that the costs
of achieving a 15 ppm standard in 2008 is approximately 0.4 c/gal
greater than for the proposal. While difficult to quantify there are
also considerable advantages to allowing refiners some operating time
in producing 15 ppm diesel fuel for the highway program prior to
requiring them to solidify their designs for producing nonroad diesel
fuel to 15 ppm. The primary advantage is that the design of
desulfurization equipment used to produce 15 ppm nonroad diesel fuel
can reflect the operating experience of the equipment used to produce
15 ppm highway diesel fuel starting in 2006. This extra time would also
provide current refiners of high sulfur diesel fuel with highly
confident estimates of the cost of producing 15 ppm diesel fuel,
reducing uncertainty and increasing their likelihood of investing to
produce this fuel. With a start date of June 1, 2008 refiners would
have to solidify their designs and start construction prior to getting
any data on the performance of their highway technology. This would
increase the cost of producing 15 ppm nonroad diesel fuel for the life
of the new desulfurization equipment, as well as potentially delaying
some refiners' decision to invest in new desulfurization equipment due
to uncertainties in cost, performance, etc.
[[Page 28465]]
4. Emission and Benefit Impacts
We used the nonroad model to estimate the emission inventory
impacts associated with this one-step option, as well as the other
options listed in Table VI-1. As for all the alternatives, we then used
the benefits transfer method to estimate the monetized benefits of the
alternative.\296\ The results are shown in Table VI-1. As is evidenced
by the values in Table VI-1, the one-step alternative would achieve
slightly greater PM and NOX emission reductions through 2030
than the proposed 2-step program, with 6,000 and 11,000 additional tons
reduced, respectively (or less than 0.5 percent). Unlike the proposed
2-step program, however, there would be no SO2 emission
reductions in 2007 due to the delay in fuel sulfur control, although
2009 and later emission are slightly greater due primarily to the
earlier introduction of engines using PM filters. Nevertheless, the
SO2 benefits of the one-step program are slightly less than
the proposed 2-step program in the long run, by about 191,000 tons
(about 4 percent) through 2030.
---------------------------------------------------------------------------
\296\ The results that were obtained for Option 1a were
extrapolated based on the emission inventory changes to the proposed
program and were obtained for the other alternatives by assuming the
air quality changes between the alternative and the actual case run
were small enough to allow for such extrapolation. An explanation of
the benefits transfer method is contained in Chapter 9 of the draft
RIA.
---------------------------------------------------------------------------
After careful consideration of these matters, we have decided to
propose the two-step approach in today's notice. The two-step program
avoids adverse risks to the smooth implementation of the entire Tier 4
nonroad program that could be caused by the significantly shortened
lead-time and stability of the one-step program. There are also
concerns about the potential negative impacts the one-step option may
have on the 2007 highway program, including the implications of the
overlap of implementation schedules (see above and Chapter 12 of the
draft RIA). Nevertheless, we believe that the one-step approach is a
regulatory alternative worth considering. In addition to seeking
comment on our proposed program, we also seek comment on the relative
merits and shortcomings of a one-step approach to regulating nonroad
diesel fuel and the associated schedule for implementing the engine
standards.
C. Applying 15 ppm Requirement to Locomotive and Marine Diesel Fuel
To enable the high efficiency exhaust emission control technology
to begin to be applied to nonroad diesel engines beginning with the
2011 model year, we are proposing that all nonroad diesel fuel produced
or imported after June 1, 2010 would have to meet a 15 ppm sulfur cap.
Although locomotive and marine diesel engines are similar in size to
some of the diesel engines covered in this proposal, there are many
differences that have caused us to treat them separately in past EPA
programs.\297\ These include differences in duty cycles and exhaust
system design configurations, size, and rebuild and maintenance
practices. Because of these differences, we are not proposing new
engine standards today for these engine categories. Since we are not
proposing more stringent emission standards, we are also not proposing
that the second step of sulfur control to 15 ppm in 2010 be applied to
locomotive and marine diesel fuel. Instead, we are proposing to set a
sulfur fuel content standard of 500 ppm for diesel fuel used in
locomotive and marine applications. This fuel standard is expected to
provide considerable sulfate PM and SO2 benefits even
without establishing more stringent emission standards for these
engines. We estimate that, cumulatively through 2030, reducing the
sulfur content of locomotive and marine diesel fuel would eliminate
about 102,000 tons of sulfate PM (net present value, based on a 3
percent discount rate).
---------------------------------------------------------------------------
\297\ Locomotives, in fact, are treated separately from other
nonroad engines and vehicles in the Clean Air Act, which contains
provisions regarding them in section 213(a)(5). Less than 50 hp
marine engines were included in the 1998 final rule for nonroad
diesel engines, albeit with some special provisions to deal with
marine-specific engine characteristics and operating cycles.
---------------------------------------------------------------------------
As discussed in section IV, we are seriously considering the option
of extending the 15 ppm sulfur standard to locomotive and marine fuel
as early as June 1, 2010, including them in the second step of the
proposed two-step program. There are several advantages associated with
this alternative. First, as reflected in Table VI-1, it would provide
important additional sulfate PM and SO2 emission reductions
and the estimated benefits from these reductions would outweigh the
costs by a considerable margin. Second, in some ways it would simplify
the fuel distribution system and the design of the fuel program
proposed today since a marker would not be required for locomotive and
marine diesel fuel. Furthermore, the prices for locomotive and marine
diesel fuel may be virtually unaffected. Under the proposal, we expect
that a certain amount of marine fuel will be 15 ppm sulfur fuel
regardless of the standard due to limitations in the production and
distribution of unique fuel grades. Where 500 ppm fuel is available,
the possible suppliers of fuel will likely be more constrained,
limiting competition and allowing prices to approach that of 15 ppm
fuel. If we were to bring locomotive and marine fuel to 15 ppm, the
pool of possible suppliers could expand beyond those today, since
highway diesel fuel will also be at the same standard. Third, it would
help reduce the potential opportunity for misfueling of 2007 and later
model year highway vehicles and 2011 and later model year nonroad
equipment with higher sulfur fuel. Finally, it would allow refiners to
coordinate plans to reduce the sulfur content of all of their nonroad,
locomotive, and marine diesel fuel at one time. While in many cases
this may not be a significant advantage, it may be a more important
consideration here since it is probably not a question of whether
locomotive and marine fuel must meet a 15 ppm cap, but merely when. As
discussed in section IV, it is the Agency's intention to propose action
in the near future to set new emission standards for locomotive and
marine engines that could require the use of high efficiency exhaust
emission control technology, and thus, also require the use of 15 ppm
sulfur diesel fuel.\298\ We anticipate that such engine standards would
likely take effect in the 2011-13 timeframe, requiring 15 ppm
locomotive and marine diesel fuel in the 2010-12 timeframe. We intend
to publish an advance notice of proposed rulemaking for such standards
by the Spring of 2004 and finalize those standards by 2007.
---------------------------------------------------------------------------
\298\ EPA established the most recent new standards for
locomotives and marine diesel engines (including those under 50 hp)
in separate actions (63 FR 18977, April 16, 1998, and 67 FR 68241,
November 8, 2002).
---------------------------------------------------------------------------
However, discussions with refiners have suggested there are
significant advantages to leaving locomotive and marine diesel fuel at
500 ppm, at least in the near-term and until we set more stringent
standards for those engines. The locomotive and marine diesel fuel
markets could provide an important market for off-specification
product, particularly during the transition to 15 ppm for highway and
nonroad diesel fuel in 2010. Waiting just a year or two beyond 2010
would address the critical near-term needs during the transition. In
addition, waiting just another year or two beyond 2010 is also
projected to allow virtually all refiners to take advantage of the new
lower cost technology.
After careful consideration of these matters, we have decided not
to propose
[[Page 28466]]
to apply the second step of sulfur control of 15 ppm to locomotive and
marine diesel fuel at this time. Nevertheless, for the reasons
described above, we are carefully weighing whether it would be
appropriate to do so. Therefore, we seek comment on this alternative
and the various advantages, disadvantages, and implications of it.
D. Other Alternatives
We have also analyzed a number of other alternatives, as summarized
in Table VI-1. Some of these focus on control options more stringent
than our proposal while others reflect modified engine requirements
that result in less stringent control. EPA has evaluated these options
in terms of the feasibility, emissions reductions, costs, and other
relevant factors. EPA believes the proposed approach is the proper one
with respect to these factors, and believes the options discussed above
while having possible merit in some areas, raise what we believe are
different and significant concerns with respect to these factors
compared to the proposed approach. Hence we did not include these
options. These concerns are discussed in more detail in Chapter 12.
These concerns are discussed in more detail in Chapter 12 of the draft
RIA. Hence, we did not include these options as part of our proposal
for nonroad fuel and engine controls. We are interested in comment on
these alternatives, especially information regarding their feasibility,
costs, and other relevant concerns.
VII. Requirements for Engine and Equipment Manufacturers
This section describes the regulatory changes proposed for the
engine and equipment compliance program. First, the proposed
regulations for Tier 4 engines have been written in plain language.
They are structured to contain the provisions that are specific to
nonroad CI engines in a new proposed part 1039, and to apply the
general provisions of existing parts 1065 and 1068. The proposed plain
language regulations, however, are not intended to significantly change
the compliance program, except as specifically noted in today's notice
(and we are not soliciting comment on any part of the rule that remains
unchanged substantively). As proposed, these plain language regulations
would only apply for Tier 4 engines. The changes from the existing
nonroad program are described below along with other notable aspects of
the compliance program.
A. Averaging, Banking, and Trading
1. Are We Proposing To Keep the ABT Program for Nonroad Diesel Engines?
EPA has included averaging, banking, and trading (ABT) programs in
most mobile source emission control programs adopted in recent years.
Our existing regulations for nonroad diesel engines include an ABT
program (Sec. 89.201 through Sec. 89.212). We are proposing to retain
the basic structure of the existing nonroad diesel ABT program with
today's notice, though we are proposing a number of changes to
accommodate implementation of the proposed emission standards. Behind
these changes is the recognition that the proposed standards represent
a major technological challenge to the industry. The proposed ABT
program is intended to enhance the ability of engine manufacturers to
meet the stringent standards proposed today. The proposed program is
also structured to limit production of very high-emitting engines and
to avoid unnecessary delay of the transition to the new exhaust
emission control technology.
We view the proposed ABT program as an important element in setting
emission standards that are appropriate under CAA section 213 with
regard to technological feasibility, lead time, and cost. The ABT
program helps to ensure that the stringent standards we are proposing
are appropriate under section 213(a) given the wide breadth and variety
of engines covered by the standards. For example, if there are engine
families that will be particularly costly or have a particularly hard
time coming into compliance with the standard, this flexibility allows
the manufacturer to adjust the compliance schedule accordingly, without
special delays or exceptions having to be written into the rule.
Emission-credit programs also create an incentive (for example, to
generate credits in early years to create compliance flexibility for
later engines) for the early introduction of new technology, which
allows certain engine families to act as trailblazers for new
technology. This can help provide valuable information to manufacturers
on the technology before they apply the technology throughout their
product line. This early introduction of clean technology improves the
feasibility of achieving the standards and can provide valuable
information for use in other regulatory programs that may benefit from
similar technologies. Early introduction of such engines also secures
earlier emission benefits.
In an effort to make information on the ABT program more available
to the public, we intend to issue periodic reports summarizing use of
the proposed ABT program by engine manufacturers. The information
contained in the periodic reports would be based on the information
submitted to us by engine manufacturers, and summarized in a way that
protects the confidentiality of individual engine manufacturers. We
believe this information will also be helpful to engine manufacturers
by giving them a better indication of the availability of credits.
Again, our periodic reports would not contain any confidential
information submitted by individual engine manufacturers, such as sales
figures. Also, the information would be presented in a format that
would not allow such confidential information to be determined from the
reports.
2. What Are the Provisions of the Proposed ABT Program?
The following section describes the changes proposed to the
existing ABT program. In addition to those areas specifically
highlighted, we are soliciting comments on all aspects of the proposed
ABT changes, including comments on the need for and benefit of these
changes to manufacturers in meeting the proposed emission standards.
The ABT program has three main components. Averaging means the
exchange of emission credits between engine families within a given
engine manufacturer's product line. (Engine manufacturers divide their
product line into ``engine families'' that are comprised of engines
expected to have similar emission characteristics throughout their
useful life.) Averaging allows a manufacturer to certify one or more
engine families at levels above the applicable emission standard, but
below a set upper limit. However, the increased emissions must be
offset by one or more engine families within that manufacturer's
product line that are certified below the same emission standard, such
that the average emissions from all the manufacturer's engine families,
weighted by engine power, regulatory useful life, and production
volume, are at or below the level of the emission standard. (The
inclusion of engine power, useful life, and production volume in the
averaging calculations is designed to reflect differences in the in-use
emissions from the engines.) Averaging results are calculated for each
specific model year. The mechanism by which this is accomplished is
certification of the engine family to a ``family emission limit'' (FEL)
set by the manufacturer, which may be above or below the standard. An
FEL that is established
[[Page 28467]]
above the standard may not exceed an upper limit specified in the ABT
regulations. Once an engine family is certified to an FEL, that FEL
becomes the enforceable emissions limit for all the engines in that
family for purposes of compliance testing. Averaging is allowed only
between engine families in the same averaging set, as defined in the
regulations.
Banking means the retention of emission credits by the engine
manufacturer for use in future model year averaging or trading. Trading
means the exchange of emission credits between nonroad diesel engine
manufacturers which can then be used for averaging purposes, banked for
future use, or traded to another engine manufacturer.
The existing ABT program for nonroad diesel engines covers
NMHC+NOX emissions as well as PM emissions. With today's
notice we are proposing to make the ABT program available for the
proposed NOX standards and proposed PM standards. (For
engines less than 75 horsepower where we are proposing combined
NMHC+NOX standards, the ABT program would continue to be
available for the proposed NMHC+NOX standards as well as the
proposed PM standards.) ABT would not be available for the proposed
NMHC standards for engines above 75 horsepower or for the proposed CO
standards for any engines.
As noted earlier, the existing ABT program for nonroad diesel
engines includes FEL caps--limits on how high the emissions from
credit-using engine families can be. No engine family may be certified
above these FEL caps. These limits provide the manufacturers compliance
flexibility while protecting against the introduction of unnecessarily
high-emitting engines. When we propose new standards, we typically
propose new FEL caps for the new standards. In the past, we have
generally set the FEL caps at the emission levels allowed by the
previous standard, unless there was some specific reason to do
otherwise. We are proposing to do otherwise here because the proposed
standard levels in today's notice are so much lower than the current
standards levels, especially the Tier 4 standards for engines above 75
horsepower. The transfer to new technology is feasible and appropriate.
Thus, to ensure that the ABT provisions are not used to continue
producing old-technology high-emitting engines under the new program,
the proposed FEL caps would not, in general, be set at the previous
standards. An exception is for the proposed NMHC+NOX
standard for engines between 25 and 50 horsepower effective in model
year 2013, where we are proposing to use the previously applicable
NMHC+NOX standard for the FEL cap since the gap between the
previous and proposed standards is approximately 40 percent (rather
than 90 percent for engines above 75 horsepower).
For engines above 75 horsepower certified during the phase-in
period, there would be two separate sets of engines with different FEL
caps. For engines certified to the existing (Tier 3)
NMHC+NOX standards during the phase-in, the FEL cap would
necessarily continue to be the existing FEL caps as adopted in the
October 1998 rule. For engines certified to the proposed Tier 4
NOX standard during the phase-in, the FEL cap would be 3.3
g/bhp-hr for engines between 75 and 100 horsepower, 2.8 g/bhp-hr for
engines between 100 and 750 horsepower, and 4.6 g/bhp-hr for engines
above 750 horsepower. These proposed NOX FEL caps represent
an estimate of the NOX emission level that is expected under
the combined NMHC+NOX standards that apply with the existing
previous tier standards. Beginning in model year 2014 when the proposed
Tier 4 NOX standard for engines above 75 horsepower take
full effect, we are proposing a NOX FEL cap of 0.60 g/bhp-hr
for engines above 75 horsepower. (As described below, we are proposing
to allow a small number of engines greater than 75 horsepower to have
NOX FELs above the 0.60 g/bhp-hr cap beginning in model year
2014.) Given the fact that the proposed Tier 4 NOX standard
is approximately a 90 percent reduction from the existing standards for
engines above 75 horsepower, we do not believe the previous standard
would be appropriate as the FEL cap for all engines once the Tier 4
standards are fully phased-in. We believe that the proposed
NOX FEL caps will ensure that manufacturers adopt
NOX aftertreatment technology across all of their engine
designs (with the exception of a limited number) but will also allow
for some meaningful use of averaging during the phase-in period. When
compared to the proposed 0.30 g/bhp-hr NOX standard, the
proposed NOX FEL cap of 0.60 g/bhp-hr (effective when the
Tier 4 standards are fully phased-in) is consistent with FEL caps set
in previous rulemakings.
For the transitional PM standards being proposed for engines
between 25 and 75 horsepower effective in model year 2008 and for the
Tier 4 PM standards for engines below 25 horsepower, we are proposing
the previously applicable Tier 2 PM standards (which do vary within the
25 to 75 horsepower category) for the FEL caps since the gap between
the previous and proposed standards is approximately 50 percent (rather
than in excess of 90 percent for engines above 75 horsepower). For the
proposed Tier 4 PM standard effective in model year 2013 for engines
between 25 and 75 horsepower, we are proposing a PM FEL cap of 0.04 g/
bhp-hr, and for the proposed Tier 4 PM standard effective in model
years 2011 and 2012 for engines between 75 and 750 horsepower, we are
proposing a PM FEL cap of 0.03 g/bhp-hr. (As described below, we are
proposing to allow a small number of Tier 4 engines greater than 25
horsepower to have PM FELs above these caps.) Given the fact that the
proposed Tier 4 PM standards for engines above 25 horsepower are less
than 10 percent of the previous standards, we do not believe the
previous standards would be appropriate as FEL caps once the Tier 4
standards take effect. We believe that the proposed PM FEL caps will
ensure that manufacturers adopt PM aftertreatment technology across all
of their engine designs (except for a limited number of engines), yet
will still provide substantial flexibility in meeting the standards.
For the proposed Tier 4 PM standards for engines above 750
horsepower there is a phase-in period during model years 2011 through
2013. During the phase-in period, there would be two separate sets of
engines with different FEL caps. For engines certified to the existing
Tier 2 PM standard, the FEL cap would continue to be the existing PM
FEL cap adopted in the October 1998 rule. For engines certified to the
proposed Tier 4 PM standard during the phase-in, the FEL cap would be
0.15 g/bhp-hr (the PM standard for the previous tier). Beginning in
model year 2014, when the proposed Tier 4 PM standard for engines above
750 horsepower takes full effect, consistent with the proposed caps for
lower horsepower categories, we are proposing a PM FEL cap of 0.03 g/
bhp-hr. (As described below, we are proposing to allow a small number
of engines greater than 750 horsepower to have PM FELs above the 0.03
g/bhp-hr cap beginning in model year 2014.) We believe that the
proposed PM FEL caps for engines above 750 horsepower will ensure that
manufacturers adopt PM aftertreatment technology across all of their
engine designs once the standard is fully phased-in (with the exception
of a limited number) while allowing for some meaningful use of
averaging during the phase-in period.
Table VII.A-1 contains the proposed FEL caps and the effective
model year
[[Page 28468]]
for the FEL caps (along with the associated standards proposed for Tier
4). We request comment on the need for and the levels of these proposed
FEL caps. It should be noted that for Tier 4, where we are proposing a
new transient test, as well as retaining the current steady-state test,
the FEL established by the engine manufacturer would be used as the
enforceable limit for the purpose of compliance testing under both test
cycles. In addition, under the NTE requirements, the FEL times the
appropriate multiplier would be used as the enforceable limit for the
purpose of such compliance testing.
Table VII.A-1.--Proposed FEL Caps for the Proposed Tier 4 Standards in the ABT Program
[g/bhp-hr]
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX
Power category Effective model year standard NOX FEL cap PM standard PM FEL cap
--------------------------------------------------------------------------------------------------------------------------------------------------------
hp < 25 (kW < 19)..................... 2008+........................... (\a\) (\a\).................................. \b\ 0.30 0.60
25 <= hp < 50 (19 <= kW < 37)......... 2008-2012....................... (\a\) (\a\).................................. 0.22 0.45
25 <= hp < 50 (19 <= kW < 37)......... 2013+\d\........................ \e\ 3.5 5.6 \e\................................ 0.02 \f\ 0.04
50 <= hp < 75 (37 <= kW < 56)......... 2008-2012....................... (\a\) (\a\).................................. 0.22 0.30
50 <= hp < 75 (37 <= kW < 56)......... 2013+........................... (\a\) (\a\).................................. 0.02 \f\ 0.04
75 <= hp <175 (56 <= kW <130)......... 2012-2013 \g\................... 0.30 3.3 for hp < 100 2.8 for hp = 100.
75 <= hp <175 (56 <= kW <130)......... 2014+........................... 0.30 0.60 \f\............................... 0.01 \f\ 0.03
175 <= hp <=750 (130 <= kW <=560)..... 2011-2013....................... 0.30 2.8.................................... 0.01 \f\ 0.03
175 <= hp <=750 (130 <= kW <=560)..... 2014+........................... 0.30 0.60 \f\............................... 0.01 \f\ 0.03
hp £750 (kW £560). 2011-2013....................... 0.30 4.6.................................... 0.01 0.15
hp £750 (kW £560). 2014+........................... 0.30 0.60 \f\............................... 0.01 \f\ 0.03
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
\a\ The existing NMHC+NOX standard and FEL cap apply (see CFR Title 40, section 89.112).
\b\ A PM standard of 0.45 g/bhp-hr would apply to air-cooled, hand-startable, direct injection engines under 11 horsepower, effective in 2010.
\c\ The proposed FEL caps do not apply if the manufacturer elects to comply with the optional standards. The existing FEL caps continue to apply.
\d\ FEL caps apply in model year 2012 if the manufacturer elects to comply with the optional standards.
\e\ These are a combined NMHC+NOX standard and FEL cap.
\f\ As described in this section, a small number of engines are allowed to exceed these FEL caps.
\g\ This period would extend through the first nine months of 2014 under the alternative, reduced phase-in requirement (see Section III.B.1. for a
description of the proposed alternative).
As noted above, we are proposing to allow a limited number of
engines to have a higher FEL than the caps noted in Table VII.A-1 in
certain instances. Under this proposal, the allowance to certify up to
these higher FEL caps would apply to Tier 4 engines at or above 25
horsepower. The provisions are intended to provide some limited
flexibility for engine manufacturers as they transition to the
stringent standards while ensuring that the vast majority of engines
are converted to the advanced low-emission technologies expected under
the Tier 4 program. This additional lead time appears appropriate,
given the potential that a limited set of nonroad engines may face
especially challenging difficulties in complying, and considering
further that the same amount of overall emission reductions would be
achieved through the need for credit-generating nonroad engines.
Beginning the first year Tier 4 standards apply in each power
category above 25 horsepower, an engine manufacturer would be allowed
to certify up to ten percent of its engines in each power category with
PM FELs above the caps shown in Table VII.A-1. The PM FEL cap for such
engines would instead be the applicable previous tier PM standard. The
ten percent allowance would be available for the first four years the
Tier 4 standards apply. For the power categories in which we are
proposing a phase-in requirement for the Tier 4 NOX
standards, the allowance to use a higher FEL cap would apply only to PM
during the phase-in years. Once the phase-in period is complete, the
allowance would apply to NOX as well. (For engines above 750
horsepower, where we are proposing a phase-in for both NOX
and PM, the allowance to use a higher FEL cap would not take effect
until model year 2014 when the phase-in was complete.)
After the fourth year the Tier 4 standards apply, the allowance to
certify engines using the higher FEL caps would still be available but
for no more than five percent of a manufacturer's engines in each power
category. (For the power category between 25 and 75 horsepower, this
allowance would apply beginning with the 2013 model year and would
apply to PM. The allowance to use the higher FEL caps is not necessary
for the 2008 proposed standards or the 2013 proposed
NMHC+NOX standards because the FEL caps for those standards
are set at the previously applicable tier standards.)
Table VII.A-2 presents the model years, percent of engines, and
higher FEL caps that would apply under this allowance. Because the
engines certified with the higher FEL caps are certified to the Tier 4
standards (albeit through the use of credits), they would be considered
Tier 4 engines and all other requirements for Tier 4 engines would also
apply, including the Tier 4 NMHC standard. We invite comment on whether
additional provisions may be necessary for the limited number of
engines certified to the higher FELs, including whether an averaging
program for NMHC would be needed.
[[Page 28469]]
Table VII.A-2.--Allowance for Limited Use of an FEL Cap Higher Than the Tier 4 FEL Caps
--------------------------------------------------------------------------------------------------------------------------------------------------------
Engines
allowed to
Power category Model years have higher NOX FEL cap (g/bhp-hr) PM FEL cap (g/bhp-hr)
FELs
--------------------------------------------------------------------------------------------------------------------------------------------------------
25 <= hp <75 (19 <= kW < 56)......... 2013-2016....................... 10 Not applicable......... 0.22.
2017+........................... 5 ......................................
--------------------------------------
75 <= hp <175 (56 <= kW <130)........ 2012-2013a...................... 10 Not applicable......... 0.30 for hp <100.
---------------------------------------------------------------------------
2014-2015....................... 10 3.3 for hp <100........ 0.22 for hp £=100.
--------------------------------------------------
2016+........................... 5 2.8 for hp =100.
--------------------------------------
175 <= hp <=750 (130 <= kW <= 560)... 2011-2013....................... 10 Not applicable......... 0.15.
--------------------------------------------------
2015+........................... 5 ......................................
--------------------------------------
hp £750 (kW £ 2014-2017....................... 10 4.6.................... 0.15.
560).
--------------------------------------------------
2018+........................... 5 ......................................
--------------------------------------------------------------------------------------------------------------------------------------------------------
a This period would extend through the first nine months of 2014 under the alternative, reduced phase-in requirement (see Section III.B.1. for a
description of the proposed alternative).
We request comment on the proposed provisions to allow higher FELs
on a limited number of Tier 4 engines, including whether the proposed
allowance limits of 10 percent and 5 percent have been set at the right
levels and whether the allowance to use a higher FEL cap is appropriate
for the Tier 4 program. We also request comment on allowing
manufacturers to use the allowances in a slightly different manner over
the first four years. Instead of allowing manufacturers to certify up
to ten percent for each of the first four years, manufacturers could
certify up to 40 percent of one year's production but spread it out
over four years in an unequal manner (e.g., 15 percent in the first and
second years, and 5 percent in the third and fourth years). Last of
all, we request comment on whether the allowance should be available
for NOX during the years we a proposing a phase-in for the
Tier 4 NOX standards. As proposed, we would not cover
NOX during the phase-in years because manufacturers already
can certify up to 50 percent of their engines to the Tier 3
NMHC+NOX standards.
Under the proposed Tier 4 program, for engines above 75 horsepower
there will be two different groups of engines during the phase-in
period. In one group, engines would certify to the applicable Tier 3
NMHC+NOX standard (or Tier 2 standard for engines above 750
horsepower), and would be subject to the ABT restrictions and
allowances previously established for those tiers. In the other group,
engines would certify to the 0.30 g/bhp-hr NOX standard, and
would be subject to the restrictions and allowances in this proposed
program. While engines in each group are certified to different
standards, we are proposing to allow manufacturers to transfer credits
across these two groups of engines with the following adjustment. As
proposed, manufacturers could use credits generated during the phase-
out of engines subject to the Tier 3 NMHC+NOX standard (or
Tier 2 NMHC+NOX standard for engines above 750 horsepower)
to average with engines subject to the 0.30 g/bhp-hr NOX
standard, but these credits will be subject to a 20 percent discount.
In other words, each gram of NMHC+NOX credits from the
phase-out engines would be worth 0.8 grams of NOX credits in
the new ABT program. The ability to average credits between the two
groups of engines will give manufacturers a greater opportunity to gain
experience with the low-NOX technologies before they are
required to meet the final Tier 4 standards across their full
production. (The 20 percent discount would also apply to
NMHC+NOX credits generated on less than 75 horsepower
engines and used for averaging purposes with the NOX
standards for engines greater than 75 horsepower.)
We are proposing the 20 percent discount for two main reasons.
First, the discounting addresses the fact that NMHC reductions can
provide substantial NMHC+NOX credits, which are then treated
as though they were NOX credits. For example, a 2010 model
year engine (between 175 and 750 horsepower) emitting at 2.7 g/bhp-hr
NOX and 0.3 g/bhp-hr NMHC meets the 3.0 g/bhp-hr
NMHC+NOX standard in that year, but gains no credits. In
2011, that engine, equipped with a PM trap to meet the new PM standard,
will have very low NMHC emissions because of the trap, an emission
reduction already accounted for in our assessment of the air quality
benefit of this program. As a result, without substantially redesigning
the engine to reduce NOX or NMHC, the manufacturer could
garner a windfall of nearly 0.3 g/bhp-hr of NMHC+NOX credit
for each of these engines produced. (Engines designed at lower
NOX levels than this in 2010 can gain even more credits.)
Allowing these NMHC-derived credits to be used undiscounted to offset
NOX emissions on the phase-in engines in 2011 (for which
each 0.1 g/bhp-hr of margin can make a huge difference in facilitating
the design of engines to meet the 0.30 g/bhp-hr NOX
standard) would be inappropriate. Second, the discounting would work
toward providing a net environmental benefit from the ABT program, such
that the more that manufacturers use banked and averaged credits, the
greater the potential emission reductions overall.
Some foreign engine manufacturers have commented that it is
difficult for them to accurately predict the number of engines that
eventually end up in the U.S., especially when they sell to a number of
different equipment manufacturers who may import equipment. This would
make it difficult for the engine manufacturer to ensure they are
complying with the proposed NOX phase-in requirements for
engines above 75 horsepower and the proposed PM phase-in requirements
for engines above 750 horsepower. Therefore, we are proposing to allow
engine
[[Page 28470]]
manufacturers to demonstrate compliance with the NOX phase
in requirements for engines above 75 horsepower and the PM phase in
requirements for engines above 750 horsepower by certifying ``split''
engine families (i.e., an engine family that is split into two equal-
sized subfamilies, one that generates a number of credits and one that
uses an equal number of credits). In order to facilitate compliance
with the proposed standards, we are proposing that this option be
available to all engine manufacturers (i.e., both foreign and domestic
manufacturers). Manufacturers would be allowed to certify split engine
families with FELs no higher than the levels specified in Table VII.A-
3. The maximum NOX FEL values specified in Table VII.A-3
were set at the level which would result in NOX ABT credits
from engines above the Tier 4 standards offsetting ABT credits from
engines below the previously applicable NMHC+NOX standards,
including the 20 percent discount for using NMHC+NOX credits
on Tier 4 engines. The maximum PM FEL value for engines above 750
horsepower was set at the level halfway between the Tier 2 and proposed
Tier 4 PM standard for engines above 750 horsepower. Manufacturers
certifying split engine families would exclude those engines from end
of the year ABT calculations (and therefore would not need to determine
actual U.S. sales of such engine families for ABT credit calculation
purposes). Manufacturers certifying split engine families would also
exclude those engines from the calculations demonstrating compliance
with the phase-in percentage requirements as well.
Table VII.A-3.--Maximum FEL for Engine Families Certified as ``Split''
Engine Families
------------------------------------------------------------------------
Maximum
Power category Pollutant FEL, g/
bhp-hr
------------------------------------------------------------------------
75 <= hp £175 (56 <= kW NOX.................... \a\ 1.7
<130).
175 <= hp <=750 (130 <= kW <560)... NOX.................... 1.5
hp £750 (kW X.................... 2.3
eq>560).
hp £750 (kW 560).
------------------------------------------------------------------------
Notes:
\a\ A limit of 2.5 g/bhp-hr would apply under the alternative, reduced
phase-in requirement (see Section III.B.1. for a description of the
proposed alternative).
We are proposing one additional restriction on the use of credits
under the ABT program. For the proposed Tier 4 standards we are
proposing that manufacturers may only use credits generated from other
Tier 4 engines or from engines certified to the previous tier of
standards (i.e., Tier 2 for engines below 50 horsepower, Tier 3 for
engines between 50 and 750 horsepower, and Tier 2 engines above 750
horsepower). (As discussed in more detail below, we are proposing
slightly different restrictions on the use of previous tier credits for
engines between 75 and 175 horsepower.) We currently have a similar
provision that prohibits the use of Tier 1 credits to demonstrate Tier
3 compliance, and given the levels of the final Tier 4 standards being
proposed today, we believe it is appropriate to apply a similar
restriction. Otherwise, we would be concerned about the possibility
that credits from engines certified to relatively high standards could
be used to significantly delay the implementation of the final Tier 4
program and its benefits.
For reasons explained in Section III.B.1.b. of today's notice, we
are proposing unique phase-in requirements for engines between 75 and
175 horsepower in order to ensure appropriate lead time for these
engines. Because of these unique phase-in provisions for engines
between 75 and 175 horsepower, we are proposing slightly different
provisions regarding the use of previous-tier credits. Under this
proposal, manufacturers that choose to demonstrate compliance with the
proposed phase-in requirements (i.e., 50 percent in 2012 and 2013 and
100 percent in 2014) would be allowed to use Tier 2 NMHC+NOX
credits generated by engines above 50 horsepower (along with any other
allowable credits) to demonstrate compliance with the Tier 4 standards
for engines between 75 and 175 horsepower during model years 2012, 2013
and 2014 only. These Tier 2 credits would be subject to the power
rating conversion already established in our ABT program, and to the
20% credit adjustment we are proposing for use of NMHC+NOX
credits as NOX credits. Manufacturers that choose to
demonstrate compliance with the optional reduced phase-in requirement
for engines between 75 and 175 horsepower, would not be allowed to use
Tier 2 credits generated by engines above 50 horsepower to demonstrate
compliance with the Tier 4 standards. (Use of credits other than banked
Tier 2 credits from engines above 50 horsepower would still be allowed,
in accordance with other ABT program provisions.) In addition,
manufacturers choosing the reduced phase-in option would not be allowed
to generate NOX credits from engines in this power category
in 2012, 2013, and the first 9 months of 2014, except for use in
averaging within this power category (i.e., no banking or trading, or
averaging with engines in other power categories would be permitted).
This restriction would apply throughout this period even if the reduced
phase-in option is exercised during only a portion of this period. We
believe that this restriction is important to avoid potential abuse of
the added flexibility allowance, considering that larger engine
categories will be required to demonstrate substantially greater
compliance levels with the 0.30 g/bhp-hr NOX standard
several years earlier than engines built under this option.
Under this proposal, we are not proposing any averaging set
restrictions for Tier 4 engines. An averaging set is a group of
engines, defined by EPA in the regulations, within which manufacturers
may use credits under the ABT program. In the current nonroad diesel
ABT program, there are averaging set restrictions. The current
averaging sets consist of engines less than 25 horsepower and engines
greater than or equal to 25 horsepower. The restriction was adopted
because of concerns over the ability of manufacturers to generate
significant credits from the existing engines and use the credits to
delay compliance with the newly adopted standards. (See 63 FR 56977.)
We believe the proposed Tier 4 standards are sufficiently protective to
limit the ability of manufacturers to generate significant credits from
their current engines. In addition, we believe the proposed FEL caps
provide sufficient assurance that low-emissions technologies will be
introduced in a timely manner. Therefore, under this proposal,
averaging would be allowed between all engine power categories without
restriction effective with the Tier 4 standards. The averaging set
restriction placed on credits generated from Tier 2 and Tier 3 engines
would continue to apply if they are used to demonstrate compliance for
Tier 4 engines.
As described in section III.B.1.d.i. of today's notice, we are also
proposing a separate PM standard for air-cooled, hand-startable, direct
injection engines under 11 horsepower. In order to avoid potential
abuse of this standard, engines certified under this proposed
requirement would not be allowed to generate credits as part of the ABT
program. Credit use by these engines
[[Page 28471]]
would be allowed. The restriction should be no burden to manufacturers,
as it would apply only to those air-cooled, hand-startable, direct
injection engines under 11 horsepower that are certified under the
special standard, and the production of credit-generating engines would
be contrary to the standard's purpose.
The current ABT program contains a restriction on trading credits
generated from indirect injection engines greater than 25 horsepower.
The restriction was originally adopted because of concerns over the
ability of manufacturers to generate significant credits from existing
technology engines. (See 63 FR 56977.) Under this proposal, we are not
proposing the restriction which prohibits manufacturers from trading
credits generated on Tier 4 indirect fuel injection engines greater
than 25 horsepower. Based on the certification levels of indirect
injection engines, we do not believe there is the potential for
manufacturers to generate significant credits from their currently
certified engines against the proposed Tier 4 standards. Therefore, we
are not proposing to restrict the trading of credits generated on Tier
4 indirect injection engines to other manufacturers. The restriction
placed on the trading of credits generated from Tier 2 and Tier 3
indirect injection engines would continue to apply in the Tier 4
timeframe.
We are not proposing to apply a specific discount to Tier 3 PM
credits used to demonstrate compliance with the Tier 4 standards. PM
credits generated under the Tier 3 standards are based on testing
performed over a steady-state test cycle. Under the proposed Tier 4
standards, the test cycle is being supplemented with a transient test
(see Section III.C above and VII.F below). Because in-use PM emissions
from Tier 3 engines will vary depending on the type of application in
which the engine is used (some having higher in-use PM emissions, some
having lower in-use PM emissions), the relative ``value'' of the Tier 3
PM credits in the Tier 4 timeframe will differ. Instead of requiring
manufacturers to gather information to estimate the level of in-use PM
emissions compared to the PM level of the steady-state test, we believe
allowing manufacturers to bring Tier 3 PM credits directly into the
Tier 4 time frame without any adjustment is appropriate because it
discounts their value for use in the Tier 4 timeframe (since the
initial baseline being reduced is probably higher than measured in the
Tier 2 test procedure).
3. Should We Expand the Nonroad ABT Program To Include Credits From
Retrofit of Nonroad Engines?
We are considering expanding the scope of the standards by setting
voluntary new engine standards applicable to the retrofit of nonroad
diesel engines, and allowing these nonroad diesel engines to generate
PM and NOX credits available for use by other nonroad diesel
engines. This program could achieve greater emission reductions of
these pollutants than could otherwise be achieved, in a cost-effective
manner. Specifically, we would allow existing in-use nonroad diesel
engines that are retrofitted to achieve more stringent levels of
emissions than are otherwise required to generate credits available for
use in the ABT program by new nonroad engines. Credit-generating
engines electing to participate in the program would be considered new
nonroad diesel engines, subject to the normal compliance mechanisms
applicable to other new nonroad diesel engines. These new nonroad
engines could generate credits that could be used in the ABT program
for other new nonroad diesel engines. Any such program would also have
to ensure that credits are surplus, verifiable, quantifiable, and
enforceable. We request comment on whether such a program would be
feasible and appropriate for the Tier 4 nonroad standards, and on how
such a program might be structured.
We are considering an approach for credit generation based on the
use of advanced exhaust emission control technology/engine system
combinations that would provide significant emissions reductions. To
accomplish this, simple changes that are easy to circumvent
accidentally or to defeat intentionally would not be eligible to
generate credits, and essentially, only changes involving introduction
of post combustion emissions control technology would be eligible.
Thus, we would structure the program such that engine recalibration as
the sole mechanism to reduce emissions would not be eligible for
retrofit credits. Also, as noted, for purposes of a nonroad retrofit
ABT program, in order to generate credits, the manufacturer of the
nonroad retrofit engine system choosing to participate in the program
would accept that the retrofit engine would be considered a new nonroad
engine, subject to enforceable standards and normal certification and
compliance requirements. We have outlined in a memorandum to the docket
our ideas for meeting these objectives, including possible ways to
structure the program.\299\ This memorandum describes potential
procedures for credit generation, credit use, and a number of
compliance, implementation, and enforcement measures.
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\299\ Memorandum to the Docket, Chris Lieske and Joseph
McDonald, EPA, Additional Information on Nonroad Retrofit Engine ABT
Credit Concepts, Docket A-2001-28.
---------------------------------------------------------------------------
We recognize that expanding the ABT program in this way would
introduce new issues and complexities to the nonroad Tier 4 program,
and that there are several ways to structure the program. We are
seeking comment on whether such an expansion of the ABT program is
feasible and appropriate, as well as on the details of how a program
could be structured. We have considered and described a possible
framework for nonroad retrofit credits in an effort to help commenters
provide input. The level of detail provided below and in the memorandum
to the docket does not indicate that we have made any decisions on
whether nonroad retrofit credits are appropriate for the ABT program or
about how the program should function. We invite comment not only on
the provisions described below and in the memorandum to the docket, but
also on alternative approaches that commenters believe would lead to a
better overall program.
We are also seeking comment on the timing of a retrofit credits
approach. We believe that if such a program were adopted, credit
generation could start in 2004 at the earliest, and request comment on
ending the program in the 2015 time frame. We view this as primarily a
transitional program which could be most useful in the early years of
the nonroad program. Ending the program in 2015 may also ease concerns
about long-term impact of such a program on the environment.
We encourage commenters to carefully address all aspects of a
nonroad retrofit credits program including its usefulness, feasibility,
compliance and enforcement measures, environmental benefits, and
potential cost savings. We specifically request comment on the
potential for such a program to provide additional emissions reductions
than would otherwise be obtained and request comment on the potential
impacts such provisions would have on emissions reductions associated
with the proposed nonroad standards. We are also interested in comments
on practical issues and details regarding how the program would operate
and be enforced.
a. What would be the environmental impact of allowing ABT nonroad
retrofit credits?
[[Page 28472]]
We would structure any nonroad credit ABT program in a way that
provides greater overall emissions reductions over the life of the
group of nonroad engines involved than would otherwise be achieved.
These additional overall reductions would be achieved by applying a
discount of 20 percent to ABT retrofit credits that are used to meet
nonroad standards. The result of applying a discount would be that each
ABT retrofit credit generated would translate to less than one nonroad
engine credit available for consumption in the nonroad program. For
example, a discount of 20 percent would reduce the consumable credits
by 20 percent. The discount would provide greater overall net emissions
reductions from the use of an ABT retrofit program, and the amount of
this environmental benefit would increase with increased use of the
program. Also, applying a discount would be consistent with past Agency
actions (see additional discussion in the memorandum to the docket
noted above).
A discount would be an essential element of the nonroad retrofit
credit provisions, since one of our objectives if we promulgated such
an expanded ABT program would be to create greater net emission
reductions. The absence of a discount would result in no net
environmental impact, as the generation of credits would lead to
emissions reductions which would be offset by the increase in emissions
when the credits were used. A discount would also serve to mitigate the
potential for net environmental detriments due to uncertainties in
credit calculation and use.
We request comment on whether a discount of 20 percent would be
appropriate given the expectation that the discount will generate cost-
effective emissions reductions that would otherwise not occur, as well
as the more prevalent uncertainties associated with trading credits
between nonroad retrofits and new nonroad engines.
b. How would EPA ensure compliance with retrofit emissions
standards?
If this program were adopted, we would expect to require the
retrofit manufacturer to specify all emissions related maintenance and
to list the type of fuel used to certify its retrofit-engine system and
whether a particular fuel sulfur level is necessary to meet the
standard and to maintain emissions compliance of the retrofit-engine
system in-use. If such a fuel is necessary to maintain emissions
compliance in-use, EPA would also consider the fuel to be ``critical
emission related scheduled maintenance'' under a retrofit engine
program. As a result of such classification, the manufacturer would be
required to demonstrate that proper fueling will be performed in-use.
Such a demonstration would include a showing that the required fuel is
available to, and would be used by, the ultimate consumer or fleet
operator receiving the retrofitted engines. Such retrofitted engines
would also have to be labeled appropriately to reflect the new engine
family and may also require labeling for the type of fuel to be used.
In general, we would require the manufacturer to submit a plan for
implementing all relevant aspects of the retrofit to ensure proper
installation and emissions compliance throughout the useful life
period. A full discussion of compliance issues and possible compliance
provisions, such as recall, in-use testing, useful life, and warranty
is provided in the memorandum to the docket, noted above. We request
comment on these approaches for ensuring in-use compliance with
possible nonroad retrofit emissions standards and requirements.
c. What is the legal authority for a nonroad ABT retrofit program?
Allowing use by new nonroad engines of credits generated by
retrofit of in-use nonroad engines is justified legally as an aspect of
EPA's standard setting authority. As we envision a program, a retrofit
nonroad engine would be considered to be a new nonroad engine when the
manufacturer opts into a voluntary retrofit program (if established).
Upon such opt-in, this new engine would be subject to enforceable
standards under CAA section 213, somewhat similar to opting into the
voluntary Blue Sky series standards (see Section VII.E.2). Thus, the
generation of credits by nonroad retrofits and their use by new engines
subject to Tier 4 would be similar to conventional ABT. Put another
way, the generation of credits by retrofitting in-use non-road engines
and their subsequent use by new nonroad engines subject to the Tier 4
standards is an averaging program involving emission credits generated
by one type of new nonroad engine and used by other new nonroad
engines, similar to conventional ABT programs. With a nonroad retrofit
credit program, and the emissions reductions associated with it, the
overall emission reductions from Tier 4 nonroad engines and nonroad
retrofit engines, taken together, would be the greatest achievable
considering cost, noise, safety and energy factors, and would also be
appropriate after considering those same factors. See also NRDC v.
Thomas, 805 F.2d 410, 425 (D.C. Cir. 1986) (averaging provisions upheld
against challenge that they are inconsistent with NCP provisions), and
Husqvarna AB v. EPA, 254 F.3d 195, 202 (D.C. Cir 2001) (averaging,
banking, and trading provisions cited as an element supporting EPA's
selection of lead time under section 213(b)). At the same time, we also
note that the proposed standards are the greatest achievable (taking
all statutory factors into account) and appropriate independent of the
nonroad retrofit program, as explained elsewhere in this preamble.\300\
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\300\ There is one minor exception to this analysis. Retrofits
involving use of new nonroad engines as replacement engines in older
nonroad equipment would be justified primarily as an aspect of EPA's
lead time authority under section 213(d). This is because credits
would not be generated from an engine certifying to a more stringent
standard, so that the credit is effectively generated by equipment
rather than by an engine, i.e. generated by something other than a
new non-road engine.
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B. Transition Provisions for Equipment Manufacturers
1. Why Are We Proposing Transition Provisions for Equipment
Manufacturers?
As EPA developed the 1998 Tier 2/3 standards for nonroad diesel
engines, we determined that provisions were needed to avoid unnecessary
hardship for equipment manufacturers. The specific concern is the
amount of work required and the resulting time needed for equipment
manufacturers to incorporate all of the necessary equipment redesigns
into their applications in order to accommodate engines that have been
redesigned to meet the new emission standards. We therefore adopted a
set of provisions for equipment manufacturers to provide them with
reasonable leadtime for the transition process to the newly adopted
standards. The program consisted of four major elements: (1) A percent-
of-production allowance, (2) a small-volume allowance, (3) availability
of hardship relief, and (4) continuance of the allowance to use up
existing inventories of engines. See 63 at FR 56977-56978 (Oct. 23,
1998).
Given the level of the proposed Tier 4 standards, we believe that
there will be engine design changes comparable in magnitude to those
involved during the transition to Tier 2/3. We thus believe that at
least some equipment manufacturers will face comparable challenges
during the transition to the Tier 4 standards. This is confirmed by
comments to EPA by a number of the equipment Small Entity
Representatives during the SBREFA process, which indicated that the
Tier 2/3 transition provisions were proving beneficial in providing
adequate leadtime and urging
[[Page 28473]]
EPA to adopt comparable provisions in a Tier 4 rule. See Report of the
Small Business Advocacy Review Panel, section 8.4.1 (Dec. 23, 2002).
Therefore, with a few exceptions described in more detail below, we are
proposing to adopt transition provisions for Tier 4 in this notice that
are similar to those adopted with the previous Tier 2/3 rulemaking. The
following section describes the proposed transition provisions
available to equipment manufacturers. (Section VII.C. of today's notice
describes all of the proposed provisions that would be available
specifically for small businesses.)
Our experience to date with the transition provisions for the Tier
2/3 standards above 50 horsepower is limited. In the one power category
where manufacturers have been required to submit information on the
number of engines using the allowances (engines between 300 and 600
horsepower), approximately 20 percent of the engines in the category
are relying on the allowances in the first year that the Tier 2
standards apply. (For the power categories below 50 horsepower,
manufacturers are reporting that there are very few engines using
allowances. However, given the level of the Tier 1 standards, we would
not expect there to have been much need for equipment redesign to
handle Tier 1 engines.) While this information is useful, we do not
believe there is enough information available to determine if the level
of the existing allowances should be revised for the Tier 4 proposal.
For this reason, we are primarily relying on the provisions of the Tier
2/3 equipment manufacturer transition provisions for the Tier 4
proposal. However, as described in more detail below, we are proposing
to add notification, reporting, and labeling requirements to the Tier 4
proposal, which are not required in the existing transition provisions
for equipment manufacturers. We believe these additional proposed
provisions are necessary for EPA to gain a better understanding of the
extent to which these provisions will be used and to ensure compliance
with the Tier 4 transition provisions. We are also proposing new
provisions dealing specifically with foreign equipment manufacturers
and the special concerns raised by the use of the transition provisions
for equipment imported into the U.S.
As under the existing provisions, equipment manufacturers would not
be obligated to use any of these provisions, but all equipment
manufacturers would be eligible to do so. Also, as under the existing
program, we are proposing that all entities under the control of a
common entity, and that meet the definition in the regulations of a
nonroad vehicle or nonroad equipment manufacturer contained in the
regulations, would have to be considered together for the purposes of
applying exemption allowances. This would not only provide certain
benefits for the purpose of pooling exemptions, but would also preclude
the abuse of the small-volume allowances that would exist if companies
could treat each operating unit as a separate equipment manufacturer.
2. What Transition Provisions Are We Proposing for Equipment
Manufacturers?
a. Percent-of-Production Allowance
Under the proposed percent-of-production allowance, each equipment
manufacturer may install engines not certified to the proposed Tier 4
emission standards in a limited percentage of machines produced for the
U.S. market. Equipment manufacturers would need to provide written
assurance to the engine manufacturer that such engines are being
procured for the purpose of the transition provisions for equipment
manufacturers. These engines would instead have to be certified to the
standards that would apply in the absence of the Tier 4 standards
(i.e., Tier 2 for engines below 50 horsepower, Tier 3 for engines
between 50 and 750 horsepower,\301\ and Tier 2 for engines above 750
horsepower). This percentage would apply separately to each of the
proposed Tier 4 power categories (engines below 25 horsepower, engines
between 25 and 75 horsepower, engines between 75 and 175 horsepower,
engines between 175 and 750 horsepower, and engines above 750
horsepower) and is expressed as a cumulative percentage of 80 percent
over the seven years beginning when the Tier 4 standards first apply in
a category. No exemptions would be allowed after the seventh year. For
example, an equipment manufacturer could install engines certified to
the Tier 3 standards in 40 percent of its entire 2011 production of
nonroad equipment that use engines rated between 175 and 750
horsepower, 30 percent of its entire 2012 production in this horsepower
category, and 10 percent of its entire 2013 production in this
horsepower category. (During the transitional period for the Tier 4
standards, the fifty percent of engines that would be allowed to
certify to the previous tier NOX standard but meet the Tier
4 PM standard would be considered as Tier 4-compliant engines for the
purpose of the equipment manufacturer transition provisions.) If the
same manufacturer were to produce equipment using engines rated above
750 horsepower, a separate cumulative percentage allowance of 80
percent would apply to these machines during the seven years beginning
in 2011. This proposed percent-of-production allowance is almost
identical to the percent-of-production allowance adopted in the October
1998 final rule, the difference being, as explained earlier, that we
are proposing to have fewer power categories associated with the
proposed Tier 4 standards.
---------------------------------------------------------------------------
\301\ Under this proposal, for engines between 50 and 75
horsepower, the NMHC+NOX standard that would apply in
Tier 4 is the same as the existing Tier 3 NMHC+NOX
standard.
---------------------------------------------------------------------------
The proposed 80 percent exemption allowance, were it to be used to
its maximum extent by all equipment manufacturers, would bring about
the introduction of cleaner engines several months later than would
have occurred if the new standards were to be implemented on their
effective dates. However, the equipment manufacturer flexibility
program has been integrated with the standard-setting process from the
initial development of this proposal, and as such we believe it is a
key factor in assuring that there is sufficient lead time to initiate
the Tier 4 standards according to the proposed schedule.\302\
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\302\ For emissions modeling purposes, we have assumed that
manufacturers take full advantage of the existing allowances under
the transition program for equipment manufacturers in establishing
the emissions baseline. This assumption is based on information
provided to us by engine manufacturers for model year 2001, which
shows that approximately 20 percent of the engines in the 300-600
horsepower category are relying on the allowances in the first year
that the Tier 2 standards apply. In modeling the Tier 4 program,
because the program will not take effect for many years and it is
not possible to accurately forecast use of the proposed transition
program for equipment manufacturers and to assess costs in a
conservative manner, we have assumed that all engines will meet the
Tier 4 standards in the timeframe proposed. As discussed in section
V.C., this is consistent with our cost analysis, which assumes no
use of the proposed transition program for equipment manufacturers.
---------------------------------------------------------------------------
Machines that use engines built before the effective date of the
proposed Tier 4 standards would not be included in an equipment
manufacturer's percent of production calculations under this allowance.
Machines that use engines certified to the previous tier of standards
under our Small Business provisions (as described in Section VII.C. of
this proposal) would not be included in an equipment manufacturer's
percent of production calculations under this allowance. All engines
certified to the Tier 4 standards, including those engines that produce
emissions at higher levels than the
[[Page 28474]]
standards, but for which an engine manufacturer uses ABT credits to
demonstrate compliance, would count as Tier 4 complying engines and
would not be included in an equipment manufacturer's percent of
production calculations. As noted earlier, engines that meet the
proposed Tier 4 PM standards but are allowed to meet the Tier 3
NMHC+NOX standards during the phase-in period would also
count as Tier 4 complying engines and would not be included in an
equipment manufacturer's percent of production calculations. And, as
also noted earlier, all engines used under the percent-of-production
allowance would have to certify to the standards that would be in
effect in the absence of the Tier 4 standards (i.e., the Tier 3
standards for engines between 50 and 750 horsepower and the Tier 2
standards for engines below 50 horsepower and above 750 horsepower).
The choice of a cumulative percent allowance of 80 percent is based
on our best estimate of the degree of reasonable leadtime needed by
equipment manufacturers. We believe the 80 percent allowance responds
to the need for flexibility identified by equipment manufacturers,
while ensuring a significant level of emission reductions in the early
years of the proposed program.
We are also proposing to allow manufacturers to start using a
limited number of the new Tier 4 flexibilities once the seven-year
period for the existing Tier 2/Tier 3 program expires (and so continue
producing engines meeting Tier 1 or Tier 2 standards). In this way, a
manufacturer could potentially continue exempting the most difficult
applications once the seven-year period of the current Tier 2/3
flexibility provisions is finished. (Under the existing transition
program for equipment manufacturers, any unused allowances expire after
the seven year period. We are not reopening this provision with this
proposal.) However, opting to start using Tier 4 allowances once the
seven-year period from the current Tier 2/Tier 3 program expires would
reduce the available percent of production exemptions available from
the Tier 4 standards. We are proposing that equipment manufacturers may
use up to a total of 10 percent of their Tier 4 allowances prior to the
effective date of the proposed Tier 4 standards. (The early use of Tier
4 allowances would be allowed in each Tier 4 power category.) This
percentage of equipment utilizing the early Tier 4 allowances would be
subtracted from the proposed Tier 4 allowance of 80 percent for the
appropriate power category, resulting in fewer allowances once the Tier
4 standards take effect. For example, if an equipment manufacturer used
the maximum amount of early Tier 4 allowances of 10 percent, then the
manufacturer would have a cumulative total of 70 percent remaining when
the Tier 4 standards take effect (i.e., 80 percent production allowance
minus 10 percent). We are also requesting comment on requiring
equipment manufacturers to take a two-for-one loss of Tier 4 allowances
for each allowance used prior to the Tier 4 effective date. This would
reduce the number of overall engines that could be exempted under the
Tier 4 allowance program and result in greater environmental benefits
than would be realized if manufacturers used all of the Tier 4
allowances in the Tier 4 timeframe.
We view this proposed provision on early use of Tier 4 allowances
as providing reasonable leadtime for introducing Tier 4 engines, since
it should result in earlier introduction of Tier 4-compliant engines
(assuming that the 80% allowance would otherwise be utilized) with
resulting net environmental benefit (notwithstanding longer utilization
of earlier Tier engines, due to the stringency of the Tier 4 standards)
and should do so at net reduction in cost by providing cost savings for
the engines that have used the Tier 4 allowances early. As discussed
above, once the Tier 4 implementation model year begins, engines which
use the transition provision allowances must be certified to the
standards that would apply in the absence of the Tier 4 standards.
b. Small-Volume Allowance
The percent-of-production approach described above may provide
little benefit to businesses focused on a small number of equipment
models. Therefore we are proposing to allow any equipment manufacturer
to exceed the percent-of-production allowances described above during
the same seven year period, provided the manufacturer limits the number
of exempted engines to 700 total over the seven years, and to 200 in
any one year. As noted earlier, equipment manufacturers would need to
provided written assurance to the engine manufacturer when it purchases
engines under the transition provisions for equipment manufacturers.
The limit of 700 exempted engines would apply separately to each of the
proposed Tier 4 power categories (engines below 25 horsepower, engine
between 25 and 75 horsepower, engines between 75 and 175 horsepower,
engines between 175 and 750 horsepower, and engines above 750
horsepower). In addition, manufacturers making use of this provision
must limit exempted engines to a single engine family in each Tier 4
power category.
As with the proposed percent-of-production allowance, machines that
use engines built before the effective date of the proposed Tier 4
standards would not be included in an equipment manufacturer's count of
engines under the small-volume allowance. Similarly, machines that use
engines certified to the previous tier of standards under our Small
Business provisions (as described in Section VII.C. of this proposal)
would not be included in an equipment manufacturer's count of engines
under the small-volume allowance. All engines certified to the Tier 4
standards, including those that produce emissions at higher levels than
the standards but for which an engine manufacturer uses ABT credits to
demonstrate compliance, would be considered as Tier 4 complying engines
and would not be included in an equipment manufacturer's count of
engines under the small-volume allowance. Engines that meet the
proposed Tier 4 PM standards but are allowed to meet the Tier 3
NMHC+NOX standards during the phase-in period would also be
considered as Tier 4 complying engines and would not be included in an
equipment manufacturer's count of engines under the small-volume
allowance. All engines used under the small-volume allowance would have
to certify to the standards that would be in effect in the absence of
the Tier 4 standards (i.e., the Tier 3 standards for engines between 50
and 750 horsepower and the Tier 2 standards for engines below 50
horsepower and above 750 horsepower).
In discussions regarding the current small-volume allowance, some
manufacturers expressed the desire to be able to exempt engines from
more than one engine family, but still fall under the number of
exempted engine limit. (Under the current rules, although equipment
manufacturers are allowed to exempt up to 700 units over seven years,
they must all use the same engine family. In many cases, a
manufacturer's largest sales volume model does not even sell 700 units
over seven years. As a result, the maximum number of units a
manufacturer can exempt under the small-volume allowance is less than
the 700 unit limit.) We are concerned, however, that allowing
manufacturers to exempt engines in more than one family, but retaining
the current 700-unit allowance, could lead to significantly higher
numbers of engines being exempted from the Tier 4 program.
[[Page 28475]]
Using data of equipment sales by equipment manufacturers that
qualify as small businesses under Small Business Administration (SBA)
guidelines, we have analyzed the effects of a small-volume allowance
program that would set an exempted engine allowance lower than 700
units over seven years but allow manufacturers to exempt engines from
more than one engine family. Based on sales information for small
businesses, we believe we could revise the small-volume allowance
program to include lower caps and allow manufacturers to exempt more
than one engine family while still keeping the total number of engines
eligible for the allowance at roughly the same overall level as the
700-unit program described above.\303\ Such a program would in general
provide sufficient leadtime for equipment manufacturers, allowing them
to temporarily exempt greater numbers of equipment models from the
proposed Tier 4 standards, but, as noted above, keeping the total
number of engines eligible for the allowance at roughly the same
overall level as the existing program would allow (and so not allow
more leadtime than necessary). Based on our analysis, the small-volume
allowance program could be revised to allow equipment manufacturers to
exempt 525 machines over seven years (with a maximum of 150 in any
given year) for each of the three power categories below 175
horsepower, and 350 machines over seven years (with a maximum of 100 in
any given year) for the two power categories above 175 horsepower.
Concurrent with the revised caps, manufacturers would be allowed to
exempt engines from more than one engine family under the small-volume
allowance program. Table VII.B-1 compares the proposed small-volume
allowance program to the variation described in this paragraph.
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\303\ ``Analysis of Small Volume Equipment Manufacturer
Flexibilities,'' EPA memo from Phil Carlson to Docket A-2001-28.
Table VII.B-1.--Small-Volume Allowance Program Comparison
----------------------------------------------------------------------------------------------------------------
Maximum
exempted
Engines exempted over 7 years engines Single engine family
in one restriction?
year
----------------------------------------------------------------------------------------------------------------
Proposed program........................ --700 for each power category.. 200 --Yes
Variation under consideration........... --525 for power categories < 100 --No
175 hp.
--350 for power categories 175 hp.
----------------------------------------------------------------------------------------------------------------
We request comment on adopting a small-volume allowance program
with the lower caps noted above that allows manufacturers to exempt
more than one engine family in each power category. We specifically
request comment on allowing equipment manufacturers to choose between
the two small-volume allowance programs described above. Alternatively,
we request comment on whether we should replace the current program
(which allows 700 units over seven years with a one engine family
restriction) with this revised small-volume allowance program (which
would allow fewer units over seven years but without the single engine
family restriction). Our analysis of small businesses noted above did
show that there were a very limited number of companies that could
potentially get fewer total allowances under a revised program with the
lower caps compared to the existing program (i.e., a company that sells
an equipment model that utilizes one engine family whose sales over a
seven year period are above the revised limits noted above but less
than 700). Allowing an equipment manufacturer to choose between the two
programs would help to ensure that manufacturers are able to retain the
current level of flexibility they have under the current program.
Because we are proposing fewer power categories for the Tier 4
standards, the proposed equipment flexibility program is designed to
reflect those changes. Therefore, under the proposed small-volume
allowance, the specified unit allowances will apply separately to each
of the five power categories being proposed for the Tier 4 standards.
As noted earlier, we are also proposing to allow manufacturers to
start using a limited number of the new Tier 4 flexibilities once the
seven-year period for the existing Tier 2/Tier 3 program expires (and
so continue producing engines meeting Tier 1 or Tier 2 standards).
Under the proposed small-volume allowance, any engines used by the
manufacturer prior to Tier 4 would be subtracted from the proposed 700
unit allowance (for the appropriate Tier 4 power category), resulting
in fewer allowances once the Tier 4 standards take effect. As with the
proposed percent-of-production allowance, we are proposing to limit the
number of Tier 4 small-volume allowances that can be used prior to the
effective dates of the Tier 4 standards to a total of 100 units in each
of the Tier 4 power categories. We are taking comment on requiring
equipment manufacturers to take a two-for-one loss of Tier 4 small-
volume allowances for each allowance used prior to the Tier 4 effective
date. As explained above, we view this proposal as providing reasonable
leadtime for introduction of Tier 4 engines by providing the
possibility of earlier introduction of such engines with a net cost
savings.
c. Hardship Relief Provision
We are proposing to extend the availability of the ``hardship
relief provision'' with the Tier 4 transition provisions for equipment
manufacturers. Under the proposal, an equipment manufacturer that does
not make its own engines could obtain limited additional relief by
providing evidence that, despite its best efforts, it cannot meet the
implementation dates, even with the proposed equipment flexibility
program provisions outlined above. Such a situation might occur if an
engine supplier without a major business interest in the equipment
manufacturer were to change or drop an engine model very late in the
implementation process. As with other equipment manufacturer transition
provisions, the equipment Small Entity Representatives indicated that
the availability this allowance was useful to them in the transition to
the Tier 2/3 standards, and they urged that it be continued in any Tier
4 rule. Report of the Small Business Advocacy Panel, section 8.4.1.
[[Page 28476]]
Applications for hardship relief would have to be made in writing,
and would need to be submitted before the earliest date of
noncompliance. The application would also have to include evidence that
failure to comply was not the fault of the equipment manufacturer (such
as a supply contract broken by the engine supplier), and would need to
include evidence that serious economic hardship to the company would
result if relief is not granted. We would work with the applicant to
ensure that all other remedies available under the flexibility
provisions were exhausted before granting additional relief, if
appropriate, and would limit the period of relief to no more than one
year. Applications for hardship relief generally will only be accepted
during the first year after the effective date of an applicable new
emission standard.
The Agency expects this provision would be rarely used. This
expectation has been supported by our initial experience with the Tier
2 standards in which only one equipment manufacturer has applied under
the hardship relief provisions. Requests for hardship relief would be
evaluated by EPA on a case-by-case basis, and may require, as a
condition of granting the applications, that the equipment manufacturer
agree (in writing) to some appropriate measure to recover the lost
environmental benefit.
d. Existing Inventory Allowance
The current program for nonroad diesel engines includes a provision
for equipment manufacturers to continue to use engines built prior to
the effective date of new standards, until the older engine inventories
are depleted. It also prohibits stockpiling of previous tier engines.
We are proposing to extend these provisions as manufacturers transition
to the standards contained in this proposal. We are also proposing to
extend the existing provision that provides an exception to the
applicable compliance regulations for the sale of replacement engines.
In proposing to extend this provision, we are requiring that engines
built to replace certified engines be identical in all material
respects to an engine of a previously certified configuration that is
of the same or later model year as the engine being replaced. The term
``identical in all material respects'' would allow for minor
differences that would not reasonably be expected to affect emissions.
3. What Are the Recordkeeping, Notification, Reporting, and Labeling
Requirements Associated With the Equipment Manufacturer Transition
Provisions?
a. Recordkeeping Requirements for Engine and Equipment
Manufacturers
We are proposing to extend the recordkeeping requirements from the
current equipment manufacturer transition program. Under the proposed
requirements, engine manufacturers would be allowed to continue to
build and sell previous tier engines needed to meet the market demand
created by the equipment manufacturer flexibility program, provided
they receive written assurance from the engine purchasers that such
engines are being procured for this purpose. We are proposing that
engine manufacturers would be required to keep copies of the written
assurance from the engine purchasers for at least five full years after
the final year in which allowances are available for each power
category.
Equipment manufacturers choosing to take advantage of the proposed
Tier 4 allowances would be required to: (1) Keep records of the
production of all pieces of equipment excepted under the allowance
provisions for at least five full years after the final year in which
allowances are available for each power category; (2) include in such
records the serial and model numbers and dates of production of
equipment and installed engines, and the rated power of each engine,
(3) calculate annually the number and percentage of equipment made
under these transition provisions to verify compliance that the
allowances have not been exceeded in each power category; and (4) make
these records available to EPA upon request.
b. Notification Requirements for Equipment Manufacturers
We are also proposing some new notification requirements for
equipment manufacturers with the Tier 4 program. Under this proposal,
equipment manufacturers wishing to participate in the Tier 4 transition
provisions would be required to notify EPA prior to their use of the
Tier 4 transition provisions. Equipment manufacturers would be required
to submit their notification before the first calendar year in which
they intend to use the transition provisions. We believe that prior
notification will not be a significant burden to the equipment
manufacturer, but will greatly enhance our ability to ensure
compliance. Indeed, EPA believes that in order for an equipment
manufacturer to properly use either of the allowances provided, it
would already have the information required in the notification. Thus
we are not requiring additional planning or information gathering
beyond that which the equipment manufacturer must already be doing in
order to ensure its compliance with the regulations. Under the proposed
notification requirements, each equipment manufacturer would be
required to notify EPA in writing and provide the following
information:
(1) The nonroad equipment manufacturer's name, address, and contact
person's name, phone number;
(2) the allowance program that the nonroad equipment manufacturer
intends to use by power category;
(3) the calendar years in which the nonroad equipment manufacturer
intends to use the exception;
(4) an estimation of the number of engines to be exempted under the
transition provisions by power category;
(5) the name and address of the engine manufacturer from whom the
equipment manufacturer intends to obtain exempted engines; and
(6) identification of the equipment manufacturer's prior use of
Tier 2/3 transition provisions.
EPA is requesting comment on whether the notification provisions
should also apply to the current Tier 2/Tier 3 transition program, and
if so, how these provisions should be phased in for equipment
manufacturers using the current Tier 2/Tier 3 transition provisions.
EPA believes such a notification provision could be implemented as soon
as 2005 and requests comments on the appropriate start date should we
adopt such a notification provision for equipment manufacturers for the
Tier 2/Tier 3 transition program.
c. Reporting Requirements for Engine and Equipment Manufacturers
As with the current program, engine manufacturers who participate
in the proposed Tier 4 program would be required to annually submit
information on the number of such engines produced and to whom the
engines are provided, in order to help us monitor compliance with the
program and prevent abuse of the program.
We are proposing new reporting requirement for equipment
manufacturers participating in the Tier 4 equipment manufacturer
transition provisions. Under this proposal, equipment manufacturers
participating in the program would be required to submit an annual
written report to EPA that calculates its annual number of exempted
engines under the transition provisions by power category in the
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