Control of Emissions of Air Pollution From Nonroad Diesel Engines
and Fuel [pp. 39107-39156]
[Federal Register: June 29, 2004 (Volume 69, Number 124)]
[Rules and Regulations]
[Page 39107-39156]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr29jn04-24]
[[pp. 39107-39156]]
Control of Emissions of Air Pollution From Nonroad
Diesel Engines and Fuel
[[Continued from page 39106]]
[[Page 39107]]
society, with net present value benefits through 2036 of $805 billion
using a 3 percent discount rate and $352 billion using a 7 percent
discount rate, compared to a net present value of social cost of about
$27 billion using a 3 percent discount rate and $14 billion using a 7
percent discount rate. The impact of these costs on society should be
minimal, with the prices of goods and services produced using equipment
and fuel affected by standards being expected to increase about 0.1
percent.
Further information on these and other aspects of the economic
impacts of this emission control program are summarized in the
following sections and are presented in more detail in the Final RIA
for this rulemaking.
A. Refining and Distribution Costs
Meeting the 500 and 15 ppm sulfur caps will generally require that
refiners add hydrotreating equipment and possibly new or expanded
hydrogen and sulfur plants in their refineries. We have estimated the
cost of building and operating this equipment using the same basic
methodology which was described in the NPRM. We have updated that
analysis with new information obtained from the vendors of advanced
desulfurization technology, to better reflect current crude oil
properties and refinery configurations, as well as future hydrogen
costs. We have also incorporated information received from refiners
regarding their plans to produce 15 ppm highway diesel fuel from 2006-
2010. Finally, we incorporated the 15 ppm cap on locomotive and marine
fuel in 2012, as well as improving our analysis of the impact of this
cap on costs incurred in the distribution system.
The costs to provide NRLM fuel under the two-step fuel program are
summarized in Table VI.A-1 below. All of the following costs estimates
are in 2002 dollars. Capital investments have been amortized at 7
percent per annum before taxes. These estimates do not include costs
associated with fuel sulfur testing, labeling, reporting or record
keeping, which we believe will be small relative to those associated
with refining, distribution and lubricity additives. A more detailed
description of the costs associated with this final rule is presented
in the Final RIA.
Table VI.A-1.--Cost of Providing NRLM Diesel Fuel
(cents per gallon of affected fuel)
----------------------------------------------------------------------------------------------------------------
Affected
fuel volume Distribution
NRLM diesel fuel Years (million Refining (and Total
gallons per lubricity)
year) a
----------------------------------------------------------------------------------------------------------------
500 ppm............................... 2007-2010............... 11,860 1.9 0.2 2.1
2010-2012............... 3,589 2.7 0.6 3.3
2012-2014............... 715 2.9 0.6 3.5
15 ppm................................ 2010-2012............... 8,145 5.0 0.8 5.8
2012-2014............... 12,068 5.6 0.8 6.4
2014 +.................. 13,399 5.8 1.2 7.0
----------------------------------------------------------------------------------------------------------------
Notes: a Volumes shown are for first full year in each period (2008, 2011, 2013, and 2015).
The costs shown (and all of the costs described in the rest of this
section) apply to the 74 percent of current NRLM fuel that currently
contains more than 500 ppm sulfur (hereafter referred to as the
affected volume).
In 2014, the affected volume of NRLM fuel is 14.6 billion gallons
out of total NRLM fuel volume of 19.7 billion gallons. The other 5.1
billion gallons of NRLM fuel is currently spillover from fuel certified
to the highway diesel fuel standards. We expect this to continue under
the 2007 highway diesel fuel program. Thus, 26 percent of NRLM fuel
will already meet at least a 500 ppm sulfur cap by 2007 and a 15 ppm
cap by 2010 and will not be affected by today's rule. The costs and
benefits of desulfurizing this highway fuel which spills over into the
non-highway markets was included in our cost estimates for the 2007
highway diesel fuel rule.
The estimated cost of the first step of the NRLM fuel program is
slightly less than that projected in the NPRM ( cents per gallon).
However, we have increased our estimated cost of the second step
significantly in response to comments. These comments and the changes
to our cost estimates are discussed in more detail in the next two
sections. The combined cost for both steps is therefore somewhat higher
than expected in the NPRM, but nevertheless consistent with projections
for the cost of 15 ppm highway diesel fuel.
We expect that the increased cost of refining and distributing 500
ppm NRLM fuel will be completely offset by reductions in maintenance
costs, while those for 15 ppm NRLM fuel will be significantly offset.
These savings will apply to all diesel engines in the fleet due to the
reduced fuel sulfur content, 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
Methodology: We followed the same process that we used in the NPRM
to project refining costs, though we have broken down the description
into five steps instead of four.
First, we estimate the total volume of NRLM fuel which must be
desulfurized during each step of the program, as well as each
refinery's future total production of distillate fuel. Current and
future demand for all distillate fuels except diesel fuel for land-
based equipment were based on estimates from the Energy Information
Administration's (EIA) Fuel Oil and Kerosene Survey (FOKS) for 2001 and
the 2003 Annual Energy Outlook (AEO). EPA's NONROAD emission model was
used to estimate both current and future fuel consumption by land-based
nonroad equipment to ensure the consistent treatment of both the costs
and benefits associated with this rule. Table VI.A-2 shows our
projections of the volumes of fuel affected by today's rule. These
volumes exclude NRLM fuel expected to be certified to highway diesel
fuel sulfur caps prior to the implementation of this rule. They also
exclude distillate fuel meeting a 500 ppm cap which is produced during
distribution from highway diesel fuel, jet fuel, etc.
[[Page 39108]]
Table VI.A-2.--Volume of NRLM Fuel Affected by Today's Rule
(billion gallons per year)
----------------------------------------------------------------------------------------------------------------
Nonroad Locomotive and Total
------------------ marine -----------------
------------------
500 ppm 15 ppm 500 ppm 15 ppm 500 ppm 15 ppm
----------------------------------------------------------------------------------------------------------------
2008...................................................... 8,406 0 3,454 0 11,860 0
2011...................................................... 614 8,145 2,975 0 3,589 8,145
2013...................................................... 468 8,671 247 3,395 715 12,066
2015...................................................... 0 10,539 ....... 2,860 0 13,399
----------------------------------------------------------------------------------------------------------------
This marks a change from the proposal, where all distillate fuel
volumes were based on EIA FOKS and AEO estimates. Commenters pointed
out that this approach underestimated fuel-related costs relative to
emission reductions and monetized benefits, since the NONROAD fuel
volumes used to estimate the latter were larger. We in fact had
acknowledged this inconsistency in the proposal and had said we would
address it in the final rule. Our approach to address the inconsistency
was to utilize the land-based nonroad fuel volumes estimated by the
NONROAD model for both the costs and monetized benefits. However, we
also conducted a sensitivity analysis whereby both emissions and costs
were estimated using EIA estimates of fuel demand by land-based nonroad
equipment. The results of that analysis are discussed in chapter VII of
the Final RIA.
We made one other revision to the volume of diesel fuel affected by
this rule. In analyzing the impact of the 2007 highway diesel fuel
program for the NPRM analysis, we estimated that 4.4 percent of 15 ppm
highway diesel fuel would be contaminated during shipment and not
available for sale as 15 ppm highway fuel. This increased the volume of
15 ppm highway fuel which had to be produced at refineries before
accounting for the production of additional 500 and 15 ppm NRLM fuel in
response to the NRLM fuel program. Due to comments made on the NRPM
(discussed in section VI.A.3. below), we have improved our analysis to
track the disposition of this contaminated 15 ppm fuel. Much of this
contaminated fuel can be sold as 500 ppm NRLM from 2007-2014 and as L&M
fuel thereafter. Thus, the contaminated 15 ppm fuel reduces the volume
of 500 and 15 ppm NRLM fuel which must be produced at refineries.
Second, total distillate production by individual refineries were
based on their actual production volumes in 2002, as reported to EIA.
This represents a minor revision to the NPRM analysis, which utilized
actual refiner production in 2000. The number of refineries needing to
produce 500 ppm and 15 ppm diesel fuel under today's final rule was
based on the projected diesel fuel and heating oil demand in 2014.\200\
To be consistent, the 2002 distillate production volumes of individual
refiners were increased to 2014 levels using EPA projections of growth
in total distillate production by domestic refiners.
---------------------------------------------------------------------------
\200\ The year 2014 represents a mid-point between the initial
year of today's fuel program and the end of the expected life of
desulfurization equipment (roughly 15 years).
---------------------------------------------------------------------------
Third, we estimated the cost to desulfurize diesel fuel to both 500
ppm and 15 ppm for each domestic refinery. This considered both the
volume of diesel fuel being produced and its composition (e.g.,
percentage of straight run, light cycle oil, etc.). Estimates of the
volumes of diesel fuel already being desulfurized to meet the highway
diesel fuel standards in 2006-2010 prior to the implementation of this
final rule were based on refiners' pre-compliance reports.\201\ This
marks a change from the NPRM analysis, where we assumed that refiners
would continue to produce their current mix of highway and high sulfur
diesel fuel. While many refiners indicated that their plans were
preliminary and subject to change, we consider these projections to be
more probable than assuming that current producers of diesel fuel will
make no change to their product mix in complying with the highway rule.
Meeting the 15 ppm highway diesel fuel cap will require significant
investment, but some refiners will face more than others. Some refiners
will be able to revamp their current hydrotreater, while others will
need to build an entirely new unit. Some refiners will be able to
expand their production of highway fuel at little incremental cost,
while others will be able to reduce their investment substantially by
reducing their production volume. Use of refiners' own projections, as
opposed to our own cost methodology assumptions, allows us to
incorporate as much refinery-specific information as is currently possible.
---------------------------------------------------------------------------
\201\ Under EPA's 2007 highway diesel program, refiners are
required to submit their production plans for highway diesel fuel
for 2006-2010. The first of these reports were due during the summer
of 2003. EPA published a summary of the results this past fall. We
consider these reports to provide a more accurate projection of
individual refinery plans than our projections made during the
highway fuel FRM. The latter was based on cost minimization using
our refinery-specific desulfurization refinery model.
---------------------------------------------------------------------------
In projecting desulfurization costs, we updated a number of the
inputs to our cost estimation methodology. We increased natural gas and
utility costs to reflect those projected in EIA's 2003 AEO. The NPRM
analysis utilized projections from 2002 AEO. Forecasted natural gas
costs in 2003 AEO are considerable higher than in 2002 AEO, though
still lower than current market prices. In response to comments, we
also increased the factor for off-site capital costs to better reflect
the cost of sulfur plant expansions. The NPRM analysis utilized an off-
site factor developed in support of the Tier 2 gasoline and 2007
highway diesel fuel programs, where the amount of sulfur removed per
gallon was a fraction of that occurring here with NRLM fuel. We also
continued to update our cost estimates for advanced desulfurization
technologies, as these technologies continue their evolution. As
discussed in Section IV, the latest information concerning Process
Dynamics's IsoTherming process indicate somewhat higher costs than
earlier estimates. We also reduced our projection of the penetration of
these advanced technologies in 2010 from 80 to 60 percent.
Fourth, we estimated which refineries will likely find it difficult
to stay in the heating oil market after the implementation of the NRLM
sulfur standards, 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
[[Page 39109]]
meet the 500 and 15 ppm caps in 2007 and 2010, respectively.
Fifth, we estimated which of the remaining refineries would likely
produce NLRM fuel under today's program. As was done in the proposal,
we assumed that those refineries with the lowest projected compliance
costs would be the most likely to produce the required fuel until
demand was met. Inter-PADD transfers of fuel between PADD 3 and PADD 1
were not constrained. PADD 3 refineries were also assumed to supply
PADD 2 with 15 ppm NRLM fuel once all PADD 2 refineries were producing
15 ppm distillate fuel. We also assumed that domestic refineries would
preferentially supply the lowest sulfur fuels compared to imports.
Thus, imports of 15 and 500 ppm NRLM fuel were only assumed after all
refineries in a PADD were projected to produce either 15 or 500 ppm
fuel, respectively. The small refiner provisions included in today's
NRLM fuel program were considered, as these provisions temporarily
reduce the volume of 500 and 15 ppm fuel required to be produced in
2007 and 2010, respectively. This portion of the methodology was the
same as that used in the NRPM analysis.
Results: Based on EIA data, in 2002 114 refineries produced highway
diesel fuel and 102 refineries produce high sulfur diesel fuel or
heating oil. Based on refiners' pre-compliance reports, we project that
100 refineries will produce 15 ppm highway diesel fuel; 96 refineries
starting in 2006 and 4 in 2010. Of these 100 refineries, 96 currently
produce some volume of highway diesel fuel, while 4 refineries
currently only produce high sulfur distillate fuel. Also, 18 refineries
will cease to produce highway diesel fuel and shift to producing solely
high sulfur distillate fuel. This will leave a total of 92 refineries
still producing high sulfur distillate after full implementation of the
2007 highway diesel fuel program.
The number of these 92 domestic refineries expected to produce
either 15 or 500 ppm NRLM diesel fuel in response to today's rule is
summarized in Table VI.A-3.
Table VI.A-3.--Refineries Projected To Produce NRLM Diesel Fuel Under This Final Rule
----------------------------------------------------------------------------------------------------------------
500 ppm NRLM diesel fuel 15 ppm NRLM diesel fuel
---------------------------------------------------
Year of program All Small All Small
refineries refineries refineries refineries
----------------------------------------------------------------------------------------------------------------
2007-2010................................................... 36 0 0 0
2010-2012................................................... 26 13 32 2
2012-2014................................................... 15 13 47 2
2014+....................................................... 0 0 63 15
----------------------------------------------------------------------------------------------------------------
During the four periods shown in table VI.A-3, two roughly parallel
sets of standards become effective. For non-small refiners, the 500 ppm
NRLM fuel cap starts in 2007, followed by the 15 ppm nonroad fuel cap
in 2010, in turn followed by the 15 ppm L&M fuel cap in 2012. For small
refiners, the 500 ppm NRLM fuel cap starts in 2010, followed by the 15
ppm nonroad NRLM fuel cap in 2014. As shown, beginning in 2014, 63
refineries are projected to be affected by today's final rule. After
complete implementation of today's rule, 29 refineries are expected to
be able to produce high sulfur heating oil, some as their entire
distillate production, others along with 15 ppm fuel. The number of
refineries estimated to be affected by today's rule is one more than
that projected in the NPRM. There, we estimated that 62 refineries
would have to produce either 15 or 500 ppm NRLM fuel in 2014 and beyond.
We project that the capital cost involved to meet the 2007 500 ppm
sulfur cap will be $310 million. This represents about $10 million for
each of the 30 refineries building a new hydrotreater. Six refineries
are expected to produce 500 ppm NRLM fuel using existing hydrotreaters
no longer being used to produce 500 ppm highway fuel. The total
investment cost is roughly half that projected in the NPRM ($600
million). The decrease is due to a greater volume of 500 ppm NRLM fuel
coming from existing hydrotreaters. This conclusion is based on the
number of refineries leaving the highway diesel fuel market according
to the refiners' highway program pre-compliance reports. The investment
per refinery that we projected in the NPRM ($9.7 million) was
essentially unchanged. Operating costs will be about $4.9 million per
year for the average refinery, or slightly greater than that projected
in the NPRM (due to higher hydrogen costs and a lower percentage of
hydrocrackate in the NRLM pool). The average cost of producing 500 ppm
NRLM fuel in 2007 will be 1.9 cents per gallon, 0.3 cent per gallon
lower than that projected in the NPRM, due primarily to the reduced
capital expenditure.
In 2010, an additional $1170 million will be invested in revamped
and new desulfurization equipment, $1090 million to meet the 15 ppm
nonroad fuel cap and $80 million to produce 500 ppm NRLM fuel no longer
eligible for a small refiner exemption to sell high sulfur NRLM fuel.
In 2012, an additional $590 million will be invested in revamped and
new desulfurization equipment to meet the 15 ppm L&M cap Finally, in
2014 an additional $210 million will be invested in additional 15 ppm
fuel capacity. Thus, total capital cost of new equipment and revamps
related to the NRLM fuel program will be $2280 million, or $36 million
per refinery, roughly 5 percent greater than that projected in the
NPRM. Total operating costs will be about $8.1 million per year for the
average refinery, slightly lower than that projected in the NPRM ($8.3
million per year). The total refining cost, including the amortized
cost of capital, will be 5.0, 5.6 and 5.8 cents per gallon of new 15
ppm NRLM fuel in 2010, 2012, and 2014, respectively.
The 500 pm NRLM fuel being produced in 2010 is projected to cost
2.7 cents per gallon. The cost of this 500 ppm fuel is higher than that
projected in the NPRM, due primarily to a higher cost for natural gas
in the future. The 500 pm, small refiner fuel being produced in 2012 is
projected to cost 2.9 cents per gallon. All of these costs are relative
to the cost of producing high sulfur fuel today, and includes the cost
of meeting the 500 ppm standard beginning in 2007.
The 15 ppm refining costs are significantly higher than the 4.4
cent per gallon cost projected in the NPRM for the option where L&M
fuel was controlled to 15 ppm in addition to nonroad fuel. The increase
is due to the changes in refining cost methodology described above,
particularly the reduced use of advanced desulfurization technology,
reduced synergies with the highway fuel program and increased natural
gas costs.
[[Page 39110]]
The average refining costs by refining region are shown in table
VI.A-4 below. These costs include consideration of the small refiner
provisions. 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 VI.A-4.--Average Refining Costs by Region
[Cents per gallon]
----------------------------------------------------------------------------------------------------------------
500 ppm Cap 15 ppm Cap
-------------------------------------------------------------------------
2007-2010 2010-2012 2012-2014 2010-2012 2012-2014 2014+
----------------------------------------------------------------------------------------------------------------
PADDs 1 & 3........................... 1.6 3.7 2.5 4.6 4.9 5.1
PADD 2................................ 2.8 2.9 3.7 7.1 7.8 7.8
PADD 4................................ 3.3 9.0 9.0 11.6 11.7 11.8
PADD 5................................ 1.2 2.8 3.5 4.3 4.3 5.7
Nationwide............................ 1.8 2.7 2.9 5.0 5.6 5.8
----------------------------------------------------------------------------------------------------------------
Fuel-Only Control Programs: We used the same methodology to
estimate refining costs for stand-alone 500 ppm and 15 ppm NRLM fuel
programs. The fully phased in refining impacts of a 15 ppm NRLM
standard are the same as those described above for the final rule in
2014 and beyond. A fully phased in 500 ppm NRLM fuel program is
projected to affect 63 refineries, cost 2.0 cents per gallon and
require a capital investment of $480 million.
2. Distribution Costs
Today's rule is projected to impact distribution costs in four
ways. First, we project that a slightly greater volume of diesel fuel
will have to be distributed, 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 in the hydrotreater. However, a
greater volume of fuel must be consumed in the engine to produce the
same amount of power. We project that desulfurizing diesel fuel to 500
ppm will reduce volumetric energy content by 0.7 percent. The cost of
which is equivalent to 0.08 cent per gallon of affected NRLM fuel.
\202\ We project that desulfurizing diesel fuel to 15 ppm will reduce
volumetric energy content by an additional 0.52 percent. This will
increase the cost of distributing fuel by an additional 0.05 cents per
gallon, for a total cost of 0.13 cents per gallon of affected 15 ppm
NRLM fuel.
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\202\ See chapter 7 of the RIA for further details regarding our
estimation of distribution costs.
---------------------------------------------------------------------------
The second impact on distribution costs relates to the disposition
of 15 ppm fuel contaminated during pipeline shipment. We received
comments that the control of L&M fuel sulfur content, particularly to
15 ppm, would make it difficult to sell off-specification 15 ppm fuel.
The comments argued that much of this material would have to be shipped
back to refineries and reprocessed to meet the 15 ppm cap. We designed
the program finalized today to allow the continued sale of 500 ppm fuel
into the NRLM market until June 1, 2014, and into the locomotive and
marine market indefinitely. By doing so, we were able to minimize,
though not eliminate, much of the reprocessing and distribution cost
impacts of concern. We have evaluated both the production and potential
sale of distillate interface and estimated the distribution cost
impacts of today's final rule provisions. The details of this analysis
are contained in chapter 7 of the Final RIA.
In our analysis of the 15 ppm highway fuel program, we projected
that the need to protect the quality of 15 ppm highway diesel fuel
would increase the volume of highway diesel fuel downgraded to a lower
value product, such as high sulfur diesel fuel and heating oil, from
its current level of approximately 2.2 percent to 4.4 percent. Under
today's rule, we expect that 15 ppm NRLM fuel will be shipped together
with 15 ppm highway. Thus, the size of each batch of 15 ppm fuel will
increase, but the number of batches will not. As the downgrade occurs
at the interface between batches, the volume being downgraded should
not increase. At the same time, we are not projecting that interface
volume will decrease, as high sulfur fuels, such as jet fuel and, in
some cases heating oil, will still be in the system.
The issue here is the market to which this interface volume can be
sold. When this interface volume meets the specifications of one of the
two fuels being shipped next to each other, the interface is simply
added to the batch of that fuel. For example, the interface between
regular and premium gasoline is added to the regular grade batch. Or,
the interface between jet fuel and heating oil is added to the heating
oil batch. One interface which is never added to either adjacent batch
is a mixture of gasoline and any distillate fuel, such as jet or diesel
fuel. If this interface was added to the distillate batch, the gasoline
content in the interface would result in a violation of the
distillate's flash point specification. If this interface was added to
the gasoline batch, it would cause the gasoline to violate its end
point specification. Therefore, this interface must be shipped to a
transmix processor to separate the mixture into naphtha (a sub-octane
gasoline) and distillate. The 2007 highway diesel fuel program will not
change this practice. The naphtha produced by transmix processors from
gasoline/distillate mixtures is usually blended with premium gasoline
to produce regular grade gasoline. The distillate produced is an
acceptable high sulfur diesel fuel or heating oil, though if the feed
material was primarily low sulfur distillate and gasoline it will
likely also meet the current 500 ppm highway fuel cap.
With the implementation of the highway diesel rule, there is
another incompatible interface, that between jet fuel and 15 ppm diesel
fuel. This interface can not be cut into jet fuel due to end point and
other concerns. However, it can usually be cut into 500 ppm diesel fuel
as long as the sulfur level of the jet fuel is not too high. With the
lowering of the highway standard to 15 ppm, however, this will no
longer be possible. We expect that pipelines minimize this interface by
abutting jet fuel and high sulfur distillate in the pipeline whenever
possible. However, it will be unavoidable under many circumstances. A
substantial part of the pipeline distribution system currently does not
handle high sulfur distillate, and we expect that the highway program
and today's rule will likely cause additional pipeline systems to
discontinue carrying high sulfur distillate. Pipelines that do not
carry high sulfur distillates will generate this
[[Page 39111]]
interface whenever they ship jet fuel.\203\ The highway rule, and
today's rule projects that pipeline operators will segregate this
interface by cutting it into a separate storage tank. Because this
interface can be sold as 500 ppm NRLM fuel or heating oil, and because
these markets exist nationwide, there is little impact beyond the need
for refiners to produce more 15 ppm highway diesel fuel (compared to
the volume of highway diesel fuel produced prior to the implementation
of the 15 ppm standard), which was considered as part of the refining
costs in the highway diesel rule.
---------------------------------------------------------------------------
\203\ We expect that only three types of fuel will be carried by
such pipeline systems: jet fuel, 15 ppm diesel fuel, and gasoline
(premium and regular). Premium and regular gasolines are always
shipped next to each other so the interface between premium and
regular gasoline can be cut into the batch of regular gasoline.
Thus, whenever jet fuel is shipped it will abut 15 ppm diesel fuel
on one end and gasoline on the other.
---------------------------------------------------------------------------
With control of nonroad fuel to 15 ppm sulfur in 2010 and LM fuel
to 15 ppm sulfur in 2012, the opportunities to downgrade interface to
another product become increasing limited. Where limited this will
increase costs due to the need to transport the interface to where it
can be marketed or to a facility for reprocessing. In areas with large
heating oil markets, such as the Northeast and the Gulf Coast, the
control of NRLM sulfur content will still have little impact on the
sale of this interface. However, in areas lacking a large heating oil
market, the sale of this distillate interface will be more restricted.
Because this interface will composed of 15 ppm diesel fuel and jet
fuel, we estimate that the distillate interface created should nearly
always meet a 500 ppm cap.\204\ Thus, this interface can be added to
500 ppm NRLM batches (as well as heating oil, where it is present at
the terminal) through 2014. After 2014, this 500 ppm interface fuel can
only be sold as L&M fuel or heating oil. An exception to this applies
in the Northeast/Mid-Atlantic Area, where this interface cannot be sold
into the nonroad fuel market after 2010, nor into the L&M fuel market
after 2012.
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\204\ See chapter 7.1.7 of the RIA regarding our analysis of the
sulfur levels of this interface material. This analysis indicated
that although the maximum sulfur specification of jet fuel 3,000
ppm, in-use jet fuel sulfur levels are frequently below 500 ppm.
---------------------------------------------------------------------------
In chapter 7 of the Final RIA, we estimate the costs related to
handling this interface fuel during the four time periods (2007-2010,
2010-2012, 2012-2014, and 2014 and beyond). We project that there will
be no additional costs prior to 2010, as 500 ppm fuel will be the
primary NRLM fuel and be widely distributed. Beyond 2010, we estimate
that terminals will have to add a small storage tank for this fuel, as
500 ppm highway diesel fuel and the majority of 500 ppm NRLM disappears
from the distribution system. In many places, this interface will be
the primary, if not sole source of 500 ppm fuel, so existing tankage to
add this interface to will be limited. We have also added shipping
costs to transport this fuel to NRLM and heating oil users. The volume
of this interface is significant, sometimes a sizeable percentage of
the combined NRLM fuel and heating oil markets. In the post-2014
period, the volume of this interface fuel is larger than the combined
L&M fuel and heating oil markets in certain PADDs. Also, the volume of
interface received at each terminal will vary substantially, depending
on where that terminal is on the pipeline. The advantage of this is
that where the interface accumulates it may be of sufficient volume to
justify marketing as a separate grade of fuel. Conversely, the
potential users of this 500 ppm interface fuel may not be located near
the terminals with the fuel necessitating additional transportation costs.
Prior to 2014, 500 ppm fuel can be used as NRLM fuel and heating
oil outside of the Northeast/Mid-Atlantic Area. Additional storage
tanks will be needed in some cases, as this will be the only source of
500 ppm fuel in the marketplace. Amortizing the cost of a range of
storage tank sizes over 15 years of weekly shipments at a seven percent
rate of return before taxes costs produced an amortized cost of 0.2-1.6
cents per gallon. These costs include the carrying cost of the fuel
stored in the tank. We estimate that the average storage cost will be
closer to the lower end of this range, or 0.5 cent per gallon. Nonroad
fuel users are fairly ubiquitous. Thus, increased shipping distances
should be fairly short. We estimated 45 miles at a cost of roughly 1.5
cents per gallon. The distance to L&M fuel users will likely be longer,
roughly 100 miles, but cost the same due to greater efficiencies of
rail transport. It will likely cost more to deliver interface fuel to
heating oil users, as many of these users are smaller, not evenly
dispersed geographically, purchase fuel seasonally, and lack rail
connections. We estimate that transport distances will increase an
average of 85 miles and cost an additional 3.0 cents per gallon over
today's costs to deliver this fuel to the end user, in addition to the
0.5 cent per gallon storage cost. When spread over all the 15 and 500
ppm NRLM fuel being produced from 2010-2014 due to today's rule, the
additional distribution cost from 2010-2014 is 0.4 cents per gallon.
Starting in 2014, this interface fuel can no longer be sold to the
nonroad fuel market. Since the interface volume does not change, this
increases the volume of fuel that must be sold to the L&M and heating
oil markets. Thus, overall, transportation distances and costs will
likely increase. We expect that the transportation cost for fuel sold
to the L&M market will increase from 1.5 to 3.0 cents per gallon, while
that for heating oil will increase to 5.0 cents per gallon, both
including fuel storage. However, in PADD 5, the volume of interface
generated exceeds the total fuel demand of these two markets. Thus, we
estimate that some fuel will have to be shipped back to refineries and
reprocessed to meet a 15 ppm cap and shipped out a second time. We
estimate that the cost of this shipping and reprocessing will cost 10
cents per gallon. When spread over all the 15 ppm NRLM fuel being
produced after 2014 due to today's rule, the additional distribution
cost is 0.8 cent per gallon.
The third impact of today's rule on distribution costs is related
to the need for additional storage tanks to market additional product
grades at bulk plants. While this final rule minimizes the segregation
of similar fuels, some additional segregation of products in the
distribution system will still be required. The allowance that highway
and NRLM diesel fuel meeting the same sulfur specification can be
shipped fungibly until it leaves the terminal obviates the need for
additional storage tanks in this segment of the distribution system
except for the limited tankage at terminals necessary to handle 500 ppm
sulfur interface fuel discussed above.\205\ Today's final rule also
allows 500 ppm NRLM diesel fuel to be mixed with high-sulfur NRLM
(though it can no longer be sold as 500 ppm fuel).
---------------------------------------------------------------------------
\205\ Including the refinery, pipeline, terminal, marine tanker,
and barge segments of the distribution system.
---------------------------------------------------------------------------
However, we expect that the implementation of the 500 ppm standard
for NRLM diesel fuel in 2007 will compel some bulk plants in those
parts of the country still distributing heating oil as a separate fuel
grade to install a second diesel storage tank to handle this 500 ppm
NRLM fuel. These bulk plants currently handle only high-sulfur fuel and
hence will 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. We believe that
[[Page 39112]]
some of these bulk plants will 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) will 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 a delivery truck is estimated
at $10,000.\206\ In the NPRM, we estimated that each bulk plant that
needed to install a new storage tank would need to de-manifold a single
tank truck. Thus, the NPRM estimated the cost per bulk plant would be
$100,000. Fuel distributors stated that the assumptions and
calculations made by EPA in characterizing costs for bulk plant
operators seem reasonable. However, they also stated that our estimate
that a single tank truck would service a bulk plant is probably not
accurate. No suggestion was offered regarding what might be a more
appropriate estimate other than the number is likely to be much
greater. Part of the reason why we estimated that only a single tank
truck would need to be de-manifolded, is that we expected that due to
the seasonal nature of the demand for heating oil versus nonroad fuel,
it would primarily only be at the juncture of these two seasons that
both fuels would need to be distributed in substantial quantities. We
also expected that the small demand for heating oil in the summer and
the small demand for nonroad fuel in the winter could be serviced using
a single de-manifolded truck. The primary fuel distributed during a
given season would be distributed by single compartment tank trucks.
During the crossover between seasons, bulk plant operators would switch
the fuel to which such single compartment tank trucks are used from
nonroad to heating oil and back again.\207\ Nevertheless, we agree that
the subject bulk plant operators would likely be compelled to de-
manifold more that a single tank truck. Lacking additional specific
information, we believe that assuming that each bulk plant operator de-
manifolds three tank trucks will provide a conservatively high estimate
of the cost to bulk plant operators due to today's rule.
---------------------------------------------------------------------------
\206\ This estimated cost includes the addition of a separate
delivery system on the tank truck.
\207\ To avoid sulfur contamination of NRLM fuel, the tank
compartment would need to be flushed with some NRLM fuel prior to
switching from carrying heating oil to NRLM fuel.
---------------------------------------------------------------------------
If all 1,000 bulk plants were to install a new tank and de-manifold
three tank trucks, the cost for each bulk plant would be $120,000, and
the total one-time capital cost would be $120,000,000. To provide a
conservatively high estimate of the costs to bulk plant operators, we
are assuming that all 1,000 bulk plants will do so. Amortizing the
capital costs over 20 years, results in a estimated cost for tankage at
such bulk plants of 0.1 cents per gallon of affected NRLM diesel fuel
supplied. Although the impact on the overall cost of the 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, we
believe many of these bulk plants will search out other arrangements to
continue servicing both heating oil and NRLM markets such as an
exchange agreement between two bulk plants that serve a common area.
As a consequence of the end of the highway program's temporary
compliance option (TCO) in 2010 and the disappearance of high-sulfur
diesel fuel from much of the fuel distribution system resulting from
the implementation of today's rule, we expect that storage tanks at
many bulk plants that were previously devoted to 500 ppm TCO highway
fuel and high-sulfur fuel will become available for dyed 15 ppm nonroad
fuel service. Based on this assessment, we do not expect that a
significant number of bulk plants will 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 implementation date for the 15
ppm nonroad standard).\208\ 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 be minimal relative to the above 0.1 cent
per gallon cost. Thus, we estimate that the total cost of additional
storage tanks at bulk plants that will result from today's rule will be
0.1 cent per gallon of affected NRLM diesel fuel supplied.
---------------------------------------------------------------------------
\208\ See Section IV of today's preamble for additional
discussion of our rational for this conclusion.
---------------------------------------------------------------------------
The fourth impact on fuel distribution costs is a result of the
requirement that high sulfur heating oil be marked beginning June 1,
2007 and that 500 ppm sulfur LM diesel produced by refiners or imported
be marked from 2010 through 2012 outside of the Northeast/Mid-Atlantic
Area and Alaska. The NPRM projected that there would be no capital
costs associated with the proposed marker requirement. We proposed that
the marker would be added at the refinery gate, and that the current
requirement that non-highway fuel be dyed red at the refinery gate be
made voluntary. Thus, we believed that the refiner's additive injection
equipment that is currently used to inject red dye into off-highway
diesel fuel could instead be used to inject the marker as needed. As a
result of the allowance provided in today's final rule that the marker
be added at the terminal rather than the refinery gate, and our
reevaluation of the conditions for dye injection at the refinery, we
are now assessing capital costs for terminals and refiners related to
compliance with the fuel marker requirements.
Except for fuel that is distributed directly from a refiner's rack,
today's final rule allows the marker to be added at the terminal rather
than at the refinery as we proposed (see section IV.D for a discussion
of the fuel marker requirements).\209\ We expect that except for fuel
dispensed directly from the refinery rack, the fuel marker will be
added to at the terminal to avoid the potential for marked fuel to
contaminate jet fuel during distribution by pipeline. Terminals that
need to inject the fuel marker will need to purchase a new injection
system, including a marker storage tank and a segregated line and
injector for each truck loading station at which fuel that is required
to be marked is dispensed. Terminals will still be subject to IRS red
dye requirements, and thus will not be able to rededicate such
injection equipment to inject the fuel marker. Due to concerns
regarding the need to maintain a visible evidence of the presence of
the fuel marker, today's rule also contains a requirement that nay fuel
which contains the fuel marker also contains visible evidence of red
dye. Furthermore, there is little chance to adapt parts of the red dye
injection system (such as the feed lines and injectors) for the
alternate injection of red dye and the fuel marker due to concerns that
NRLM fuel become contaminated with the marker.
---------------------------------------------------------------------------
\209\ A refinery rack functions similar to a terminal in that it
distributes fuel by truck to wholesale purchaser consumers and retailers.
---------------------------------------------------------------------------
Terminal operators expressed concern regarding the potential burden
on terminal operators from the capital costs of adding new additive
injection equipment for heating oil. In response to these comments,
today's rule includes provisions that exempt terminal operators from
the fuel marker requirements in a geographic ``Northeast/Mid-Atlantic
Area'' and
[[Page 39113]]
Alaska.\210\ These provisions provide that any heating oil or 500 ppm
sulfur LM diesel fuel that would otherwise be subject to the fuel
marker requirements which is delivered to a retailer or wholesale-
purchaser consumer inside the Northeast/Mid-Atlantic Area or Alaska
does not need to contain the marker. The costs of the marker
requirements for heating oil beginning in 2007 and for 500 ppm sulfur
LM diesel fuel from 2010 through 2012 are discussed separately below.
---------------------------------------------------------------------------
\210\ Small refiner and credit high sulfur NRLM will not be
permitted to be sold in the area where terminals are not required to
add the fuel marker to heating oil (the ``Northeast/Mid-Atlantic
Area''). See section IV.D.
---------------------------------------------------------------------------
The Northeast/Mid-Atlantic Area was defined to include the region
where the majority of heating oil in the country is projected to
continue to be supplied through the bulk distribution system (the
Northeast and Mid-Atlantic). The vast majority of heating oil
consumption in the U.S. will be within the Northeast/Mid-Atlantic Area.
Outside of the Northeast/Mid-Atlantic Area, we expect that only limited
quantities of heating oil will be supplied, primarily from certain
refiner's racks. We estimate that 30 refineries and transmix processor
facilities outside of the Northeast/Mid-Atlantic Area will distribute
heating oil from their racks (in limited volumes) on a sufficiently
frequent basis to warrant the installation of a marker injection system
at a total one time cost of $1,500,000.
Terminals outside of the Northeast/Mid-Atlantic Area will mostly be
located in areas without continued production and/or bulk shipment of
heating oil. Consequently, any high sulfur diesel fuel they sell will
typically be NRLM. Terminals located within the Northeast/Mid-Atlantic
Area will not need to mark their heating oil, except for those few that
choose to ship heating oil outside of the Northeast/Mid-Atlantic Area.
The terminals most likely to install marker injection equipment will
therefore be those in states outside the Northeast/Mid-Atlantic Area
with modest markets for heating oil after the implementation of this
program. As discussed in chapter 7 of the RIA, in analyzing the various
situations, we project that fewer than 60 terminals nationwide will
choose to install marker injection equipment at a total cost of
$4,150,000. \211\ The total capital cost to refiners and terminals to
install marker injection equipment is estimated to be $5,650,000. Thus,
the Northeast/Mid-Atlantic Area provisions in today's rule minimizes
the number of terminals that will need to install additive injection
equipment and its associated cost to comply with the marker requirement
for heating oil.
---------------------------------------------------------------------------
\211\ The estimated marker injection equipment costs include the
cost of marker storage tanks, lines, and injectors.
---------------------------------------------------------------------------
In the NPRM we estimated that the cost to blenders of the fuel
marker in bulk quantities would translate to 0.2 cents per gallon of
fuel treated with the marker. This estimate was based on the fee
charged by a major pipeline to inject red dye at the IRS concentration
into its customers diesel fuel. We used this estimate because we lacked
specific cost information on the proposed marker, and we believed that
it provided a conservatively high estimate of marker cost. Since the
proposal, we received input from a major distributor of fuel markers
and dyes, regarding the cost of bulk deliveries of the specified fuel
marker to terminals which translates to a cost of 0.03 cents per gallon
of fuel treated with the marker. The volume of heating oil that we
expect will need to be marked has also decreased substantially from
that estimated in the NPRM due to the Northeast/Mid-Atlantic Area
provisions. We estimate that 1.4 billion gallons of heating oil will be
marked annually, for an annual marker cost of $425,000. In the NPRM, we
projected that the cost of marking heating oil would continue for three
years (2007-2010). Under today's final rule, heating oil must be marked
indefinitely beginning in 2007, but only outside of the Northeast/Mid-
Atlantic Area and Alaska.
Because heating oil outside of the Northeast/Mid-Atlantic Area is
being marked to prevent its use in NRLM engines, for the purposes of
estimating the impact of the marker requirement on the cost of the NRLM
program we have spread the cost for the marker for heating oil over
NRLM diesel fuel. Amortizing the capital costs of marker injection
equipment over 20 years, results in an estimated cost of 0.006 cents
per gallon of affected NRLM diesel fuel supplied. Spreading the cost of
the marker over the volume of affected NRLM fuel results in an
estimated cost of 0.003 cents per gallon of affected NRLM fuel. Adding
the amortized cost of the injection equipment necessary to add the
marker to heating oil and the cost or the marker results in a total
estimated cost of the marker requirement for heating oil in today's
rule of 0.01 cents per gallon of affected NRLM fuel.
The final NRLM rule also requires that 500 ppm L&M fuel produced at
refineries or imported be marked from mid-2010 through mid-2012 outside
of the Northeast/Mid-Atlantic Area and Alaska. The adoption of a 15 ppm
sulfur standard for LM diesel fuel in 2012 in today's rule allows us to
require that LM fuel be marked from 2010 through 2012 rather than from
2010 through 2014 as proposed (see section IV.A). In addition, the way
in which the program was crafted to avoid requiring the fuel marker be
added to heating oil in the Northeast/Mid-Atlantic Area and Alaska
allows us to also provide that 500 ppm sulfur LM diesel fuel in these
areas is not subject to the marker requirement (see section IV.D). We
project that only a small number of refiners will produce 500 ppm
sulfur diesel fuel subject to the marker requirements fuel and that it
will not be shipped via pipeline. Thus, most of this fuel can be marked
at the refinery, limiting the number of facilities which need to add
marking equipment in response to this requirement. We estimate that 15
facilities will have to do so, at a cost of $60,000 each, for a total
of $900,000. Amortizing this over the total volume of affected NRLM
fuel produced from mid-2010 to mid-2012 at seven percent per year
before taxes yields a cost for the LM marker requirement of 0.004 cent
per gallon. Including the cost of the marker (0.03 cent per gallon of
marked fuel) increases this cost to 0.01 cent per gallon of NRLM fuel.
We summed these various costs incurred to the distribution system
over four different time periods. As shown in table VI.A-5, the total
additional distribution cost will be 0.2 cent per gallon of NRLM fuel
during the first step of the fuel program (from 2007 through 2010), 0.6
cents per gallon of NRLM fuel from 2010 to 2012 and from 2012 to 2014,
and increase to 1.0 cent per gallon thereafter. A more detailed
description of the costs associated with downgraded jet fuel and 15 ppm
diesel fuel is presented in chapter 7 of the Final RIA.
[[Page 39114]]
Table VI.A-5.--Summary of Distribution Costs
[Cents per gallon]
----------------------------------------------------------------------------------------------------------------
Time period over which costs apply
Cause of increase in distribution costs ---------------------------------------------------
2007-2010 2010-2012 2010-2014 2014+
----------------------------------------------------------------------------------------------------------------
Distribution of additional NRLM volume...................... 0.08 0.1 0.1 0.1
Distillate interface handling............................... 0 0.4 0.4 0.8
Bulk plant storage tanks.................................... 0.1 0.1 0.1 0.1
Heating oil and L&M fuel marker............................. 0.01 0.02 0.01 0.01
---------------
Total................................................... 0.2 0.6 0.6 1.0
----------------------------------------------------------------------------------------------------------------
3. 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 will
result from the proposed 500 ppm sulfur standard for NRLM diesel fuel
will be similar to that for highway diesel fuel meeting the current 500
ppm sulfur cap standard.\212\ 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 NRLM diesel fuel meeting the proposed 500 ppm sulfur
standard will also not need lubricity additives. In estimating
lubricity additive costs for 500 ppm diesel fuel, we assumed that fuel
suppliers will use the same additives at the same concentration as we
projected will 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 cents. 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 five percent of all 500 ppm
NRLM diesel fuel will 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 will be 0.01 cent per gallon. See the
Final RIA for more details on the issue of lubricity additives. We have
no reason to expect that the implementation of today's NRLM sulfur
standards will impact diesel properties other than fuel lubricity in
such a way as to require the use of additives.
---------------------------------------------------------------------------
\212\ 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 NRLM fuel meeting a 15 ppm cap will require
treatment with lubricity additives. Thus, the projected cost will be
0.2 cent per affected gallon of 15 ppm NRLM fuel.
4. How EPA's Projected Costs Compare to Other Available Estimates
Historically, the price of highway diesel fuel meeting a 500 ppm
sulfur cap has exceeded that of high sulfur diesel fuel, ranging from
0-5 cents per gallon from 1995-99 and averaging 2.2 cents per gallon
over this time period (see chapter 7 of the Final RIA). Fuel prices are
often a function of market forces which might not reflect the cost of
producing the fuel. Still, given this is a five-year average price
difference, it is likely a reasonable indication of the cost of
reducing highway diesel fuel sulfur to 500 ppm. Once the small refiner
provisions applicable to 500 ppm fuel expire in 2010, we project that
the total cost of the 500 ppm NRLM fuel cap will be 2.4 cents per
gallon, well within the range of the historical highway-high sulfur
fuel price difference. This similarity exists despite changes in a
number of factors. One, our projection of future natural gas costs are
significantly higher than those existing during the above price
comparison. Two, the refineries producing highway diesel fuel
historically likely did so because they faced lower costs than those
refineries continuing to produce high sulfur distillate. Three,
desulfurization catalyst efficiency has improved dramatically since the
highway units were installed and significant operating experience has
been obtained on highway units. Four, inflation since the early 1990's
will have increased the cost of constructing the same hydrotreater.
Five, and perhaps most importantly, the construction of some new
hydrotreaters to produce 15 ppm highway diesel fuel will allow the
existing hydrotreaters to produce 500 ppm NRLM fuel at no capital cost.
Thus, there are at least five significant factors, two of which would
tend to decrease costs and three of which would tend to increase costs.
It is not surprising that these factors could counter-balance each
other, leading to the conclusion that the 500 ppm cap could be extended
to NRLM fuel at roughly the same cost as for highway diesel fuel.
The only existing market for 15 ppm diesel fuel is a niche market
for fleets and the prices for this fuel likely bear little resemblance
to the costs of the 15 ppm highway or NRLM caps. Thus, the only cost
comparisons which can be made are those between engineering studies.
One such study was performed by Mathpro for the Engine Manufactures
Association (EMA). Mathpro estimated the cost of controlling the sulfur
content of highway and NRLM fuel to levels consistent with both 500 ppm
and 15 ppm cap standards.\213\ A detailed evaluation of the Mathpro
costs is presented in the Final RIA. There are a number of aspects of
the study that make direct comparisons between its estimates and our
cost estimates difficult. Nonetheless, a crude comparison of 15 ppm
costs indicates that our average cost range of 5.7-5.9 cent per gallon
is quite similar to the 5.4-6.6 cents per gallon cost range estimated
by Mathpro.
---------------------------------------------------------------------------
\213\ Hirshfeld, David, MathPro, Inc., ``Refining economics of
diesel fuel sulfur standards,'' performed for the Engine
Manufactuers Association, October 5, 1999.
---------------------------------------------------------------------------
The other available study of 15 ppm fuel costs was performed by
Baker and O'Brien for API and submitted in response to the nonroad
NPRM. Baker and O'Brien analyzed two NRLM fuel control scenarios, but
neither one matched today's final NRLM fuel program. The scenario
closest to today's program assumed that a NRLM fuel would be capped at
15 ppm in 2008. In this case, Baker and O'Brien projected that the
refinery-specific cost of 15 ppm NRLM fuel would range from 4-17 cents
per gallon. This is higher than our projected range of 2-14 cents per
gallon. In addition, as described in the next
[[Page 39115]]
section, Baker and O'Brien projected that the volume of NRLM fuel
produced at these costs would not fully satisfy NRLM fuel demand.
Presumably, totally fulfilling NRLM fuel demand with domestic
production would have cost more.
Baker and O'Brien described portions of their cost methodology and
indicated some general assumptions which they made during the study.
However, the absence of detail prevents any detailed comparisons of
their results to ours. It was clear from their report, though, that
Baker and O'Brien made a number of pessimistic assumptions about
refiners' willingness to invest in desulfurization capacity and that
this limited the number of refineries which they assumed would invest
to meet the NRLM sulfur caps. This inevitably led to higher projected
costs (and lower production volumes), than if all refineries had been
considered. Thus, it is not surprising that they would derive slightly
higher costs for a much smaller volume of fuel. A more detailed
evaluation of the Baker and O'Brien cost estimates can be found in the
Final RIA and RTC.
5. Supply of Nonroad, Locomotive and Marine Diesel Fuel
We have developed today's NRLM fuel program to minimize its impact
on the supply of distillate fuel. For example: We have split the
control of NRLM fuel to 15 ppm sulfur into two steps, providing 8 years
of leadtime for the final step. We are proposing to provide flexibility
to refiners through the availability of banking and trading provisions.
We have provided relief for small refiners and hardship relief for any
qualifying refiner. We are also allowing 500 ppm diesel fuel generated
in the distribution system to be sold as L&M fuel indefinitely.
In the NPRM, we evaluated four possible reasons why refiners might
reduce their production of NRLM fuel: (1) Chemical processing losses
during the desulfurization process, (2) refiners might leave the NRLM
fuel market, (3) refiners might stop operations altogether (i.e., shut
down), and (4) refiners might remove certain blendstocks from the fuel
pool to reduce desulfurization costs. In all four cases, we concluded
that the answer was no, that the supply of NRLM fuel would likely
remain adequate after implementation of the proposed fuel program. All
of these findings started from the position that there would be
adequate supply of diesel fuel after implementation of the 2007 highway
diesel fuel program.
Several commenters, namely API and NPRA, took issue with the above
four sets of arguments, as well as with our conclusion that refiners
would not reduce NRLM fuel production. While not requesting any changes
to the 2007 highway diesel fuel program, they reiterated previous
concerns that supply shortages could occur under the highway diesel
fuel program, even without the added challenge of producing low sulfur
NRLM fuel. The primary basis for their comments was a study they had
sponsored by Baker and O'Brien, which evaluated the costs and likely
supply impacts of the proposal.
Baker and O'Brien evaluated two NRLM fuel scenarios: (1) A 15 ppm
NRLM fuel cap starting in 2008, and (2) a 500 ppm NRLM fuel cap
starting in 2008, followed by a 15 ppm cap only for nonroad fuel in
2010. First, Baker and O'Brien projected that 13 refineries with a
total crude oil capacity of 971,000 barrels per day would close in
response to the 2007 highway rule, roughly half in 2006 and half in
2010. (Total U.S. refining capacity is currently 16 million barrels per
day.) Then Baker and O'Brien projected that adding a 15 ppm NRLM cap
would cause all of the refineries shutting down in 2010 to close in
2008, plus one additional refinery (for a total of 14). Delaying the 15
ppm cap until 2010 and leaving L&M fuel at 500 ppm reduced the number
of refineries projected to close in 2008, but did not change Baker and
O'Brien's projection that 14 refineries would close by 2010. Given the
fact that Baker and O'Brien projected the same number of refinery
closures for scenarios #1 and #2, it is reasonable to
assume that they would project similar results for today's final NRLM
fuel program.
---------------------------------------------------------------------------
\214\ Closure would occur at the beginning of the 15 ppm highway
fuel program, or 2006.
Table VI.A-6.--Projected Refinery Closures: API Sponsored Study by Baker
and O'Brien
------------------------------------------------------------------------
No. of refineries Lost crude capacity
---------------------- (1000 bbl/day)
---------------------
2008 2010 2008 2010
------------------------------------------------------------------------
2007 Highway Fuel Program... \214\ 8 13 504 971
Plus One-Step 15 ppm NRLM 14 14 1043 1043
Program....................
Plus Two-Step NRLM Program.. 12 14 924 1043
------------------------------------------------------------------------
As a result of these refinery closures, Baker and O'Brien projected
shortfalls in 15 and 500 ppm supply domestic refiners. The net
shortfalls are shown in table VI.A-7 below. Baker and O'Brien stated
that imports would have to make up the shortfall, with potentially high
price impacts.
Table VI.A-7.--Projected Shortfall in Near-Term Diesel Fuel Supply
[1000 barrels per day]
------------------------------------------------------------------------
15 ppm Fuel 500 ppm Fuel
-------------------------------------------
2008 2010 2008 2010
------------------------------------------------------------------------
2007 Highway Fuel Program... 359 579 308 22
Plus One-Step 15 ppm NRLM 684 930 165 0
Program....................
Plus Two-Step NRLM Program.. 351 639 481 82
------------------------------------------------------------------------
[[Page 39116]]
To put these projected shortfalls in context, Baker and O'Brien
projects total diesel fuel demand to be 3.3 million barrels per day in
this timeframe (slightly lower than our own projection summarized
above). Thus, these projected shortfalls total roughly 10-20 percent of
total diesel fuel demand, which if true, would be very significant.
We evaluated the Baker and O'Brien study and their findings. Baker
and O'Brien made very pessimistic assumptions regarding the likelihood
that refiners would invest in desulfurization capacity. Their judgment
that a refinery would close rather than invest also was apparently
based only on what they perceived to be excessively high
desulfurization costs. Baker and O'Brien presents no information
regarding the location of these refineries, the competition they face,
costs related to closing down, nor the profits that they would forego
by closing. Baker and O'Brien also makes no mention of EPA's special
provisions for refiners facing economic hardship, nor the small refiner
provisions.
We believe that it is not possible to project refinery closures
without considering these factors. This is supported by comments made
in response to our proposal of the 2007 highway diesel fuel program by
Mathpro and the National Economic Research Associates. While we are
aware of a couple of refineries that are being offered for sale and
whose plans for producing low sulfur fuels are uncertain, we have no
indications of as many as eight refineries closing in 2006 in response
to the highway fuel program. In addition, despite uncertainties at a
few refineries, refiners' pre-compliance reports for the highway fuel
program indicate that they are planning to produce a sufficient supply
of 15 and 500 ppm highway diesel fuel from 2006-2010. Therefore, there
is ample evidence that Baker and O'Brien's projections for the highway
diesel fuel program are overly pessimistic. It therefore appears likely
that their projection that the NRLM fuel program will cause an
additional refinery to close is also overly pessimistic. The reader is
referred to the RTC for a summary of these comments and our detailed
response to them.
In their comments, API also challenged our findings that refiners
would maintain sufficient supply under the proposed NRLM fuel program.
After a careful review of their comments and other information newly
available since the NPRM, we do not believe that the arguments
presented by API and NPRA justify changing our position that (1)
chemical processing losses during the desulfurization process will be
very small, (2) refiners will be unlikely to leave the NRLM fuel
market, and (3) refiners are unlikely to shut down due to this rule.
Regarding point #1, the distillate material lost during
desulfurization, our position is that the amount lost is small (two
percent), and most of it is lost in the form of naphtha which can be
blended into gasoline. Refiners can then adjust their mix of gasoline
and distillate production to compensate. API claimed that in the
winter, refiners were already at maximum distillate production and
could not shift any additional heavy gasoline material into the
distillate pool. API did not present any evidence that this is in fact
the case. The fact that some refiners actually crack distillate
material into gasoline makes it difficult to accept their position.
Regarding point #2, refiners leaving the NRLM fuel market,
we argued that the only high sulfur distillate market remaining after
2007 was heating oil. Heating oil demand is flat or declining over
time. We project that over 30 domestic refiners will still be able to
produce heating oil after 2007, while other refiners will be able to
produce sufficient quantities of NRLM fuel. If more refiners choose to
produce heating oil, this market will be oversupplied and prices will
drop significantly. Exporting high sulfur distillate is a possibility
for some refiners, but this entails both transport costs, as well as
relatively low prices overseas. Thus, a decision to not invest in NRLM
fuel desulfurization has to be compared to the losses involved with the
other options. API argued that some refiners face much higher
desulfurization costs than others and this would lead those refiners to
leave the NRLM fuel market. API did not estimate the losses that
refiners would entail when they left the market. Studies performed for
the highway fuel program indicate that these losses can be quite
significant and inappropriate conclusions can be drawn if they are
ignored. The highway program pre-compliance reports also indicate that
some highway fuel refiners are planning on leaving the highway fuel
market in 2006, while others will enter it for the first time.
Decisions to stay in or leave the NRLM fuel market are analogous. We
have no reason to believe refiners would approach this market any
differently than the highway market.
Regarding point #3, refineries shutting down, API again
pointed towards the high costs faced by some refineries and the fact
that a number of refineries have shut down over the past ten years.
There have been a number of refinery closures over the past decade,
though the trend has slowed considerably. API pointed towards two
specific refineries which identified EPA's gasoline and diesel fuel
sulfur controls as prime reasons for their shutting down. A closer look
at these situations showed that the future capital investment related
to the sulfur controls could have been a contributing factor. However,
these refineries faced many other challenges and the timing of their
closure (2000 and 2001, respectively) showed that the EPA rules were
not the direct cause. The refiner involved did not approach EPA
concerning any relief from the rules' requirements due to economic
hardship. Thus, the connection between their closure and our sulfur
controls appears even more tenuous.
Another example of a refinery closure unrelated to desulfurization
costs was Shell's recent decision to close their refinery in
Bakersfield, California. The reason was an insufficient supply of crude
oil being produced locally.
Analogous to a decision to leave the NRLM fuel market, shutting
down completely involves the total loss of any profit being made on the
production of other fuels. API presented no economic calculations or
projections showing that it would be in the best interest of any
refiner to shut down rather than invest in NRLM fuel desulfurization.
This leaves point #4, that refiners might shift NRLM fuel
blendstocks to other markets. This is really only an issue if the
blendstocks are shifted to a non-distillate market.\215\ The most
likely place that NRLM fuel blendstocks might be shifted is to the
residual fuel market. In particular, heavy (material with high
densities and high distillation temperatures) LCO and LCGO could be
shifted to residual fuel using existing refining equipment. The heavy
portions of these two blendstocks contain the greatest concentrations
of sulfur which is the most difficult to remove. Shifting this material
to residual fuel, which currently does not have a sulfur standard,
would reduce the size and cost of desulfurization equipment needed to
meet a 15 ppm cap. Or, it would increase the volume of 15 ppm NRLM fuel
which could be produced in an existing hydrotreater.
---------------------------------------------------------------------------
\215\ Shifting NRLM fuel blendstocks to heating oil is
essentially the same as leaving the NRLM market, which was discussed
under Point #2 above.
---------------------------------------------------------------------------
To evaluate this possibility, we estimated the cost of processing
LCO (the worse of the two blendstocks) into 15 ppm diesel fuel for each
domestic refinery. On average, desulfurizing LCO to 15 ppm sulfur cost
11.4 cents per
[[Page 39117]]
gallon. However, in some cases, this cost reached 15 cents per gallon.
The cost to process heavy LCO could be twice these amounts, since the
concentration of both total sulfur and the most difficult to remove
sulfur are concentrated in the heaviest molecules.
A review of historic fuel prices showed that residual fuel is
usually priced 25-30 cents per gallon less than diesel fuel. The
highest incremental desulfurization costs for heavy LCO could
potentially exceed this loss. Thus, a few refiners could find it
economical to shift a portion of their LCO to the residual fuel market.
The U.S. residual fuel market is small relative to the distillate fuel
market, flat, and already being fulfilled. Worldwide, the residual fuel
market is shrinking. Thus, it is unlikely that large volumes of LCO
could leave the NRLM fuel market. However, we cannot rule out the
possibility that some LCO, particularly that produced by capital-
strapped refiners, could be shifted to residual fuel. To estimate the
upper limit of this shift, we estimated the volume of heavy LCO
produced by refineries whose LCO processing costs exceeded 12 cents per
gallon and which were not owned by large, integrated oil companies or
small refiners. This costly, heavy LCO represents 0.4 percent of total
NRLM fuel demand, a very small volume. In this case, we would expect
that this loss could easily be made up by increased imports of 15 ppm
diesel fuel or domestic refiners facing lower 15 ppm NRLM fuel costs.
Overall, we expect that domestic refiners will continue to produce
sufficient supplies of NRLM fuel. The greatest potential for near term
loss will be due to the possibility that some refiners might decide to
limit their capital investment in desulfurization capacity by shifting
some heavy LCO to the residual fuel market.
Fuel-Only Control Programs: The potential supply impacts of a long-
term 500 ppm NRLM cap would necessarily be less than those of today's
final NRLM fuel program. In particular, desulfurizing ``difficult''
blendstocks, like LCO, to 500 ppm is not technically challenging and
does not have the potential to cost more than would be lost in shifting
LCO or heavy LCO to residual fuel. The capital investment to meet a 500
ppm cap is also half of that needed to meet a 15 ppm cap or less. Thus,
the likelihood that raising this capital would prove difficult is much
less. Given that we expect the final fuel program to have a very
minimal impact on supply, a 500 ppm NRLM cap would be negligible.
The potential impact of a long-term 15 ppm NRLM cap is the same as
that for today's final fuel program.
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 two years. 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 here.\216\ 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 VI.A-8. (Due to their similarity, we have grouped the
potential price impacts for similar quality fuels in the 2010-2012 and
2012-2014 time periods.) 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.
---------------------------------------------------------------------------
\216\ Executive Order 13211, ``Actions Concerning Regulations
That Significantly Affect Energy Supply, Distribution, or Use'' (66
FR 28355, May 22, 2001).
Table VI.A-8.--Range of Possible Total Diesel Fuel Price Increases
[Cents per gallon]
\a\
----------------------------------------------------------------------------------------------------------------
Maximum Average total Maximum total
operating cost cost cost
----------------------------------------------------------------------------------------------------------------
500 ppm Sulfur Cap: Nonroad, Locomotive and Marine Diesel Fuel (2007-2010)
----------------------------------------------------------------------------------------------------------------
PADDs 1 and 3................................................... 2.9 1.8 4.5
PADD 2.......................................................... 3.0 2.5 3.8
PADD 4.......................................................... 3.7 3.5 6.1
PADD 5.......................................................... 1.2 1.5 1.5
-----------------------------------------------------------------
15 ppm Sulfur Cap: NRLM Fuel (2010-2014)
----------------------------------------------------------------------------------------------------------------
PADDs 1 and 3................................................... 5.6 5.7 9.4
PADD 2.......................................................... 7.3 7.4 10.8
PADD 4.......................................................... 7.9 12.6 13.6
PADD 5.......................................................... 4.5 5.1 5.2
-----------------------------------------------------------------
[[Page 39118]]
15 ppm Sulfur Cap: NRLM Fuel (fully implemented program: 2014 +)
----------------------------------------------------------------------------------------------------------------
PADDs 1 and 3................................................... 7.7 6.3 9.8
PADD 2.......................................................... 7.7 7.9 11.2
PADD 4.......................................................... 8.3 13.0 13.9
PADD 5.......................................................... 5.1 6.9 7.3
----------------------------------------------------------------------------------------------------------------
Notes: \a\ At the current wholesale price of approximately $1.00 per gallon, these values also represent the
percentage increase in diesel fuel price.
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 (please see the Final RIA for details on this
methodology). This refiner with the highest operating cost will not
recover any of his invested capital, but all other refiners will
recover some or all of their investment. In this case, the price of
NRLM fuel will increase in 2007 by 1-3 cents per gallon, depending on
the area of the country. In 2010, the price of 15 ppm NRLM fuel will
increase a total of 3-7 cents per gallon. In 2014, under this pricing
scenario, 15 ppm NRLM fuel prices will increase slightly, to 4-7 cents
per gallon. The increase in 2014 is due to the expiration of the small
refiner provisions, as well as the fact that 500 ppm fuel created in
the distribution system can no longer be sold to the land-based nonroad
market.
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 seven percent per
annum before taxes). Lower cost refiners will recover more than their
capital investment, while those with higher than average costs recover
less. Under this assumption, the price of NRLM fuel will increase in
2007 by 1-3 cents per gallon, depending on the area of the country. In
2010, the price of 15 ppm NRLM fuel will increase a total of 4-11 cents
per gallon. In 2014, under this pricing scenario, 15 ppm NRLM fuel
prices will increase slightly, to 5-11 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
seven percent per annum before taxes). All other refiners will recover
more than their capital investment. Under this assumption, the price of
NRLM fuel will increase in 2007 by 1-4 cents per gallon, depending on
the area of the country. In 2010, the price of 15 ppm NRLM fuel will
increase a total of 4-13 cents per gallon. In 2014, under this pricing
scenario, 15 ppm NRLM fuel prices will increase further to 6-13 cents
per gallon. All these potential price impacts for 500 and 15 ppm fuel,
relative to those projected in the NPRM, reflect the differences in
cost estimates discussed 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.\217\ In that study,
NERA criticized the above referenced study performed by Charles River
Associates, et al. for API, which projected that prices will 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.
---------------------------------------------------------------------------
\217\ ``Potential Impacts of Environmental Regulations on Diesel
Fuel Prices,'' NERA, for AAM, December 2000.
---------------------------------------------------------------------------
Second, we assumed in some cases 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. In many cases, high cost refiners continue to operate simply
because they are in a niche location where transportation costs limit
competition.
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 today's fuel program. It is this price response that causes fuel
supply to match fuel demand. And, this response 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 NRLM 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
[[Page 39119]]
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 will 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.\218\ It concluded that costs for Asian refiners will 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 appears to be
less valid when assessing the relative cost of meeting lower sulfur
standards for NRLM 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.
---------------------------------------------------------------------------
\218\ ``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 will invest in the capacity
to produce some or all of their diesel fuel at these levels. Many
overseas refiners also have the flexibility to produce 10-15 ppm diesel
fuel from their cleanest blendstocks, as 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 will 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 NRLM 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 will be imported at
competitive prices.
Fuel-Only Control Programs: We used the same methodology to
estimate the potential price impacts for stand-alone 500 ppm and 15 ppm
NRLM fuel programs. The potential price impacts of long-term 500 ppm
and 15 ppm NRLM caps would be the same as those shown in table VI.A-8
above for the 500 ppm NRLM cap in 2007 and for the 15 ppm NRLM cap in
2014 and beyond, respectively.
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 range of benefits
from the use of low-sulfur fuel is presented in Table VI.B-1.\219\
Table VI.B-1.--Engine Components Potentially Affected by Lower Sulfur
Levels in Diesel Fuela
------------------------------------------------------------------------
Effect of lower Potential impact
Affected components sulfur on engine system
------------------------------------------------------------------------
Piston Rings.................... Reduced corrosion Extended engine
wear. life and less
frequent
rebuilds.
Cylinder Liners................. Reduced corrosion Extended engine
wear. life and less
frequent
rebuilds.
Oil Quality..................... Reduced deposits, Reduce wear on
reduced acid piston ring and
build-up, and cylinder liner
less need for and less frequent
alkaline oil changes.
additives.
Exhaust System (tailpipe)....... Reduced corrosion Less frequent part
wear. replacement.
Exhaust Gas Recirculation System Reduced corrosion Less frequent part
wear. replacement
------------------------------------------------------------------------
Notes: \a\ The degree to which all of these benefits may occur for any
specific engine will vary. For example, the impact of high sulfur fuel
on piston rings, cylinder liners and oil quality are somewhat
interdependent. To the extent an end-user lengthens the oil drain
interval, the benefit of the low sulfur fuel on piston ring and
cylinder liner wear will be lessened (though not eliminated). For
users who do not alter oil drain intervals, the benefit of low sulfur
fuel on extending piston ring and cylinder liner wear will be greater.
The benefit of low sulfur fuel on reducing exhaust system and EGR
system corrosion are independent of oil drain intervals.
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
[[Page 39120]]
be realized in 2010 when the 15 ppm sulfur fuel would be introduced.
---------------------------------------------------------------------------
\219\ 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.
---------------------------------------------------------------------------
We estimate the single largest savings would be the impact of lower
sulfur fuel on oil change intervals. The 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 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 received comments on our estimated maintenance savings primarily
from a number of end-user groups (e.g., equipment dealers, equipment
rental organizations, farming organizations). Several commenters
believed our estimates were too high, and one commenter believed the
estimate was too low. However, all of the commenters who believed our
cost savings estimates were too high provided no data to support their
comments, beyond unsubstantiated opinions, nor did they comment on
EPA's substantial related technical analysis.
The commenter who suggested the estimates were too low provided an
example cost estimate for existing oil change intervals which, if used
in our analysis, would have resulted in an estimated cost savings 4
times EPA's estimate. We have not changed our estimate based on the
comments we received.
We present here a fuel operating 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 2.9 cents per gallon for the
nonroad fleet. We estimate 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 3.2 cents per gallon compared to today's
engine. This means that the end cost to the typical user for 15 ppm
sulfur fuel is approximately 3.8 cents per gallon (7.0 cent per gallon
cost for fuel minus 3.2 cent per gallon maintenance savings). For a
typical 100 horsepower nonroad engine this represents a net present
value lifetime savings, excluding the higher fuel costs, 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. There are many mechanisms by which end-users could become
aware of the opportunity to extend oil drain intervals. First, it is
typical practice for engine and equipment manufacturers to issue
service bulletins regarding lubrication and fueling guidance for end-
users.\220\ Manufacturers provide these service bulletins to equipment
dealerships and large equipment customers (such as rental companies).
In addition, the equipment and end-user industries have a number of
annual conferences which are used to share information, including
information regarding appropriate engine and equipment maintenance
practices. The end-user conferences are also designed to help specific
industries and business reduce operating costs and maximize profits,
which would include information on equipment maintenance practices.
There are trade journals and publications which provide information and
advice to their users regarding proper equipment maintenance. Finally,
some nonroad users perform routine oil sample analysis in order to
determine appropriate oil drain intervals, and in some cases to monitor
overall engine wear rates in order to determine engine rebuild
needs.\221\ We have not estimated the value of the savings from all of
the benefits listed in table VI.B-1, and therefore we believe the 3.2
cents per gallon savings is conservative as it only accounts for the
impact of low sulfur fuel on oil change intervals. While some of these
benefits are impacted by changes in oil change interval, a number are
independent and not included in our cost savings estimate.
---------------------------------------------------------------------------
\220\ For example, Appendix A of EPA Memorandum ``Estimate of
the Impact of Low Sulfur Fuel on Oil Change Intervals for Nonroad
Diesel Equipment'' contains a service bulletin from a nonroad diesel
engine manufacturer. Copy of memo available in EPA Air Docket A-
2001-28, item II-A-194.
\221\ For example, Appendix C of EPA Memorandum ``Estimate of
the Impact of Low Sulfur Fuel on Oil Change Intervals for Nonroad
Diesel Equipment'', which indicates Caterpillar recommends owners
use Scheduled Oil Sampling analysis as the best means for users to
determine appropriate oil change intervals. Copy of memo available
in EPA Air Docket A-2001-28, item II-A-194.
---------------------------------------------------------------------------
C. Engine and Equipment Cost Impacts
The following sections briefly discuss the various engine and
equipment cost elements considered for this final rule and present the
total costs we have estimated. The reader is referred to the 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 new Tier 4 standards. The wide size variation
(e.g., engines under 4 horsepower through engines above 2500
horsepower) and 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 examples of engine and equipment cost impacts
throughout this discussion. Note that the costs presented here are for
those nonroad engines and equipment that are mobile nonroad equipment
and are, therefore, subject to nonroad engine standards. These costs
would not apply for that equipment that is stationary--some portion of
some equipment segments such as generator sets, pumps, compressors--and
not subject to nonroad engine standards. The analysis summarized here
is presented in detail in chapter 6 of the RIA.
Note that the costs presented here do not reflect any savings that
are expected to occur because of the engine ABT program and/or the
equipment manufacturer transition program, which are discussed in
sections III.A and B. These optional programs have the potential to
provide significant savings for both engine and equipment
manufacturers. As a result, we consider our cost estimates to be
conservative, in the sense that they likely overstate total engine and
equipment costs.
In general, the final engine and equipment cost analysis is the
same as that done for our proposal. We have made the following changes:
? In response to a comment, we have increased our engine
research and development (R&D) costs. In the proposal, we estimated the
R&D expenditure that each engine manufacturer would make to comply with
the Tier 4 standards. In response
[[Page 39121]]
to the comment, we have refined that analysis and increased our
estimate of engine R&D by roughly 50 percent. We did not receive any
other comments with respect to our estimates for engine R&D.
? Because the final standards for engines above 750
horsepower have changed from the proposed standards, we have made
changes to the engine R&D expenditures attributed to those engines. For
costing purposes, the NOX portion of the engine R&D
expenditures are no longer shared by engines above 750 horsepower. This
increases NOX R&D attributed to other engines because a
significant portion of engine R&D costs are costs shared across a wide
range of products. We have also reduced the engine variable costs for
engines above 750 horsepower since we are no longer projecting that
NOX adsorbers will be added to them.\222\ This has no impact
on the engine variable costs for other engines. We have also reduced
the equipment redesign costs for engines above 750 horsepower since
less redesign effort is projected to accommodate only a catalyzed
diesel particulate filter (CDPF). This has no impact on the redesign
costs of other equipment. Lastly, we have decreased the equipment
variable costs for engines above 750 horsepower for the same reason as
was done for engine variable costs.
---------------------------------------------------------------------------
\222\ In order to avoid inconsistencies in the way our emission
reductions, and cost-effectiveness estimates are calculated, our
cost methodology for engines and equipment relies on the same
projections of new nonroad engine growth as those used in our
emissions inventory projections. Our NONROAD emission inventory
model includes estimates of future engine populations that are
consistent with the future engine sales used in our cost estimates.
The NONROAD model inputs include an estimate of what percentage of
generator sets sold in the U.S. are ``mobile'' and, thus, subject to
the nonroad standards, and what percentage are ``stationary'' and
not subject to the nonroad standards. These percentages vary by
power category and are documented in ``Nonroad Engine Population
Estimates,'' EPA Report 420-P-02-004, December 2002. For generator
sets above 750 horsepower, NONROAD assumes 100 percent are
stationary and, therefore, not subject to the new nonroad standards.
For generator sets under 750 horsepower, we have assumed other
percentages of mobile versus stationary. During our discussions with
engine manufacturers after the proposal, it became apparent not only
that our estimate for generator sets above 750 horsepower may not be
correct and many are indeed mobile, but also that some of our
estimates for generator sets above 750 horsepower may also not be
correct and many more than we estimate may indeed be mobile. If
true, this increased percentage of mobile generator sets will be
subject to the new nonroad standards. Unfortunately, we have not
received sufficient data to make a conclusive change to the NONROAD
model to include the potentially increased percentages of mobile
generator sets and, therefore, for the above described purpose of
maintaining consistency, we have not included their costs or their
emissions reductions in our official estimates for this final rule
(costs and emissions reductions for the current percentages in the
NONROAD model are included in our estimates for the final rule).
Instead, we present a sensitivity analysis in Chapter 8 of the RIA
that includes both an estimate of the costs and emissions reductions
that would result from including a higher percentage of generator
sets as mobile equipment and subject to the new standards.
---------------------------------------------------------------------------
? We have changed the engine operating costs for engines
above 750 horsepower to reflect a different fuel economy impact than
was associated with the proposed standards and to reflect the new
timing for adding the CDPF and therefore incurring the maintenance
costs associated with it.
? We have included costs for additional cooling on engines
adding cooled EGR systems (engines of 25 to 50 horsepower and greater
than 750 horsepower). These costs include the larger radiator and/or
engine cooling fan that may be required on engines expected to add
cooled EGR to meet the new standards. In the proposal, we had estimated
the costs for the EGR system but not the costs for additional cooling.
? We have expressed all costs in 2002 dollars for the final
rule rather than the proposal's use of 2001 dollars.
We received comments on other aspects of the proposed engine and
equipment cost analysis that are not reflected in the final analysis.
Some of the comments were:
? Some commenters claimed that we had underestimated costs
for engines under 75 horsepower, and in the 75 to 100 horsepower range.
For the engines under 75 horsepower, one commenter suggested the costs
were higher than EPA estimated. Please see section 5.4.1 of the Summary
and Analysis of Comments for a detailed discussion of the comments and
our response. In the 75 to 100 horsepower range, one commenter
suggested that we were incorrect in our assumption that those engines
would have electronic fuel systems in the NRT4 baseline case,
maintaining the electronic fuel systems would have to be added to these
engines to comply with the Tier 4 standards and, therefore, are a cost
of the Tier 4 rule. From this premise, the commenter argued that the
costs for 75 to 100 horsepower engines will be disproportionately high.
We disagree. In the proposal, we estimated that by 2012, engines in
this power range would already have electronic fuel injection systems.
This estimate was based on our engineering assessment of what
technologies would be required to comply with the Tier 2 and Tier 3
emission standards, as well as technical discussions we had with engine
manufacturers regarding future product plans. Therefore, the costs of
these electronic fuel injection systems are not attributable to the
Tier 4 rule. Our assessment at proposal is consistent with our
projections in the Tier 2/3 rulemaking where we estimated costs for
electronic fuel injection systems as a cost of complying with those
standards. In the preamble to the proposed Tier 4 rule, we presented
estimates of the penetration of various engine technologies into
several power ranges, including 75 to 100 horsepower, based on engine
manufacturers' 2001 model year certification data. See 68 FR 28386, May
23, 2003. Since then, model year certification data for 2004 are
available, and these data substantiate our earlier prediction. These
model year 2004 data represent implementation of the Tier 2 standards
so these data illustrate the technologies engine manufacturers are
using to comply with those standards. These data show that nearly 20
percent of the engines that will be produced in this power range will
have electronically controlled fuel systems, while the model year 2001
data show no engines in this power range had electronic fuel systems.
This dramatic increase in electronics as a result of the Tier 2
standards, let alone the Tier 3 standards, gives us confidence that our
projections regarding 2012 are reasonable. Section 4.1.4 of the RIA
contains a detailed discussion of this information; see also the
discussions in sections II.B.4.b.i and II.B.5 above. Thus, we continue
to believe that we have properly attributed costs of electronic fuel
systems to the Tier 3 rule, or, put another way, that the cost of an
electronic fuel system is not a cost attributable to this Tier 4 rule
for engines in the 75 to 100 horsepower category. Since the cost of
electronic fuel systems is the essential difference in the costs we
attribute to the Tier 4 rule for these engines versus the costs the
commenter would attribute, we therefore disagree with the comment and
believe our estimates to be reasonable. See also section II.A.5 above.
? One commenter took exception to our method of amortizing
fixed costs over a period of years following implementation of the new
standards. The commenter suggested that we used such a method to imply
to the regulated industries that they would not only recover their
investments but would also make a gain on those investments. This is
not the case. We use this method of amortization, briefly described
here and more fully in the RIA, only to reflect the time value of money
so that we can get a more accurate estimate of the cost to the companies.
The Summary and Analysis of Comments document contains the
[[Page 39122]]
details of all comments and our responses.
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 will be
reduced by several factors, as described below. All engine and
equipment costs are presented in 2002 dollars since producer price
indexes for 2003 were not available in time for use in this analysis.
a. Engine Fixed Costs
i. Engine and Emission Control Device R&D
The technologies described in Section II represent those
technologies we believe will be used to comply with the Tier 4 emission
standards. For many manufacturers, 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. Nonetheless, 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.
We project the use of several technologies for complying with the
Tier 4 emission standards. We are projecting that NOX
adsorbers and catalyzed diesel particulate filters (CDPFs) will be the
most likely technologies applied by industry to meet our new emissions
standards for engines above 75 horsepower. The fact that these
technologies are being developed for implementation in the highway
market before the Tier 4 implementation dates, and the fact that engine
manufacturers will have several years before implementation of the Tier
4 standards, ensures that the technologies used to comply with the
nonroad standards will 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 will 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 Tier 4 standards, industry
will introduce a combination of primary technology upgrades. Achieving
very low NOX emissions will require basic research on
NOX exhaust emission control technologies and improvements
in engine management to take advantage of the new exhaust emission
control system capabilities. The manufacturers are expected to address
the challenge by optimizing the engine and new exhaust emission control
system to realize the best overall performance. This will entail
optimizing the engine and emission control system for both emissions
and fuel economy performance in light of the presence of the new
exhaust emission control devices and their ability to control
pollutants previously controlled only via in-cylinder means or with
exhaust gas recirculation. Since most research to date with exhaust
emission control technologies for nonroad applications has focused on
retrofit programs which typically add an exhaust emission control
device without making engine control changes, 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 where we
project use of both a CDPF and a NOX adsorber (i.e., 75 to
750 horsepower), we have attributed two-thirds of the R&D expenditures
to NOX control, and one-third to PM control.
As we mentioned earlier, we have further refined our estimate of
engine R&D costs since our proposal. We have taken these R&D costs and
have broken them into two components. The first of these components
estimates the corporate R&D applicable across all engine lines. The
second of these estimates the engine line by engine line R&D cost. The
estimates of line by line R&D correlate to power range--$1 million for
under 75 horsepower engine lines, $3 million for 75 to 750 horsepower
engine lines, and $6 million for above 750 horsepower engine lines. We
estimated these expenditures based on the confidential information
provided by the commenter and our analysis of that information. The end
result is consistent with the commenter's suggested expenditure levels.
We have applied these engine-line R&D estimates only where CDPFs and/or
CDPF/NOX adsorber systems are expected to be implemented
(i.e., this R&D is not applied for the under 75 horsepower engines in
2008 because the R&D already estimated for complying with those
standards should not require the same effort to tailor it to each
engine). We have also applied these estimates only for those engines
without a highway counterpart (note that only 16 of a total 133 nonroad
engine lines had a highway counterpart).
In the 2007 HD highway rule, we estimated that each engine
manufacturer would expend $36.1 million for R&D to redesign their
engines and apply catalyzed diesel particulate filters (CDPF) and
NOX adsorbers.\223\ For their nonroad R&D efforts on engines
where we project that compliance will require CDPFs and NOX
adsorbers (i.e., 75 to 750 horsepower) and on greater than 750
horsepower engines requiring a CDPF, engine manufacturers that also
sell into the highway market will incur some level of R&D effort but
not at the
[[Page 39123]]
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 will incur an average R&D expense of $3.6
million \224\ not including the nonroad engine line R&D noted above.
This $3.6 million R&D expense will allow for the transfer of R&D
knowledge from their highway experience to their nonroad engine product
line. For the reasons stated above, two-thirds of this R&D is
attributed to NOX control and one-third to PM control for 75
to 750 horsepower engines; for engines above 750 horsepower, all of
this R&D is attributed to PM control.
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\223\ In the 2007 rule, we estimated a value of $35 million in
1999 dollars. Here we have adjusted that value to express it in 2002
dollars.
\224\ In the proposal, we estimated a value of $3.5 million in
1999 dollars. Here we have adjusted that value to express it in 2002
dollars.
---------------------------------------------------------------------------
For those manufacturers that sell larger engines only into the
nonroad market, and where we project those engines will add a CDPF and
a NOX adsorber (75 to 750 horsepower) or a CDPF-only (above
750 horsepower), we believe that they will incur an R&D expense nearing
that incurred by highway manufacturers for the highway rule although
not quite at the same level. Nonroad manufacturers will be able to
learn from the R&D efforts already underway for both the highway rule
and for the Tier 2 light-duty highway rule (65 FR 6698, February 10,
2000). 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 average expenditure of $25.3 million \225\ not including
the nonroad engine line R&D noted above. This lower number--$25.3
million versus $36.1 million in the highway rule--reflects the transfer
of knowledge to nonroad manufacturers that will 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.
---------------------------------------------------------------------------
\225\ In the proposal, we estimated a value of $24.5 million in
1999 dollars. Here we have adjusted that value to express it in 2002
dollars.
---------------------------------------------------------------------------
Note that the $3.6 million and $25.3 million estimates represent
our estimate of the average R&D expected by manufacturers to gain
knowledge about the anticipated emission control devices. These
estimates will be different for each manufacturer--some higher, some
lower--depending on product mix and the number of engine lines in their
product line.
For those engine manufacturers selling smaller engines that we
project will add a CDPF-only (i.e., 25 to 75 horsepower engines in
2013), we have estimated that the average R&D they will incur will 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 is not
appropriate. Using this estimate, the R&D incurred by manufacturers
that already have been selling any engines into both the highway and
the nonroad markets will be $1.2 million not including their nonroad
engine line R&D, and the R&D for manufacturers selling engines into
only the nonroad market will be roughly $8.3 million \226\ not
including their nonroad engine line R&D. All of this R&D is attributed
to PM control.
---------------------------------------------------------------------------
\226\ In the proposal, we estimated values of $1.2 million and
$8 million in 1999 dollars. Here we have adjusted those values to
express them in 2002 dollars.
---------------------------------------------------------------------------
For those engine manufacturers selling engines that we project will
add only a DOC or make some engine-out modifications (i.e., engines
under 75 horsepower in 2008), we have estimated that the average R&D
they will incur will 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 will be
roughly $600,000, and the R&D for manufacturers selling engines into
only the nonroad market will be roughly $4.2 million.\227\ All of this
R&D is attributed to PM control.
---------------------------------------------------------------------------
\227\ In the proposal, we estimated values of $600,000 and $4
million in 1999 dollars. Here we have adjusted those values to
express them in 2002 dollars.
---------------------------------------------------------------------------
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. There is one exception to this assumption in that the
expenditures for DOC-only R&D are assumed to occur over the four year
span between the final rule and the 2008 standards. Where a phase-in
exists (e.g., for NOX standards on 75 to 750 horsepower
engines), expenditures are assumed to occur over the five year span
preceding the first year NOX adsorbers will be introduced,
and then to continue during the phase-in years. The expenditures will
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,
with the exception that expenditures for DOC-only R&D are recovered
over a five year span rather than a four year span. We assume an
opportunity cost of capital of seven percent 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. Note that all
engine R&D costs for engines under 25 horsepower have been attributed
to U.S. sales since other countries are not expected to have similar
standards on these engines.
Using this methodology, we have estimated the total R&D
expenditures attributable to the new standards at $323 million with
$206 million spent on corporate R&D and $118 million spent on engine
line R&D. For comparison, our proposal estimated $199 million for basic
R&D and none for engine line R&D. The amount for corporate R&D is
higher here solely due to the change to 2002 dollars.
ii. Engine-Related Tooling Costs
Once engines are ready for production, new tooling will be required
to accommodate the assembly of the new engines. We have indicated below
where our tooling cost estimates have changed from the proposal. In the
2007 highway rule, we estimated approximately $1.65 million per engine
line for tooling costs associated with CDPF/NOX adsorber
systems.\228\ For the nonroad Tier 4 standards, we have estimated that
nonroad-only manufacturers will incur the same $1.65 million per engine
line requiring a CDPF/NOX adsorber system and that these
costs will be split evenly between NOX control and PM
control. For those systems requiring only a CDPF, we have estimated
one-half that amount, or $825,000 per engine line. For those systems
requiring only a DOC or some engine-out modifications, we have applied
a one-half factor again, or $412,500 per engine line. Tooling costs for
CDPF-only and for DOC engines are attributed solely to PM control. None
of these estimates have changed since our proposal, with the exception
of being
[[Page 39124]]
expressed in 2002 dollars. We received no comments on our tooling cost
estimates.
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\228\ In the 2007 rule, we estimated a value of $1.6 million in
1999 dollars. Here we have adjusted that value to express it in 2002
dollars.
---------------------------------------------------------------------------
For those manufacturers selling into both the highway and nonroad
markets, we have estimated one-half the baseline tooling cost, or
$825,000, 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 will be incurred. For engine lines without a highway counterpart,
something approaching the $1.65 million tooling cost is 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 $1.65 million baseline. These tooling costs will be split evenly
between NOX control and PM control. For engine lines under
75 horsepower and above 750 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 and
those above 750 horsepower), we have estimated a tooling cost of
$825,000. Note that this is a change from the proposal for engines
above 750 horsepower; the proposal used the full $1.65 million since
both a CDPF and a NOX adsorber were being projected. The
tooling costs for DOC and/or engine-out engine lines has also been
estimated to be $412,500. Tooling costs for CDPF-only and for DOC
engines are attributed solely to PM control. With the exception of the
greater than 750 horsepower change, none of these tooling estimates
have changed since our proposal, with the exception of being expressed
in 2002 dollars.
We expect engines in the 25 to 50 horsepower range to apply EGR
systems to meet the Tier 4 NOX standards for 2013. For these
engines, we have included an additional tooling cost of $41,300 per
engine line, consistent with the EGR-related tooling cost estimated for
50-100 horsepower engines in our Tier 2/3 rulemaking. The EGR tooling
costs are 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 tend not to have highway counterparts. Tooling costs for EGR
systems are attributed solely to NOX control.
We have also estimated some tooling costs for engines above 750
horsepower to meet the 2011 standards. We have estimated this amount at
ten times the amount for 25 to 50 horsepower engines, or $413,000 per
engine line. This cost was not in the proposal since NOX
adsorbers were being projected for engines above 750 horsepower. We
have applied this tooling to all engine lines above 750 horsepower,
regardless of what markets into which a manufacturer sells, since such
engines clearly have no highway counterpart. For the purpose of
allocating costs, we have attributed this cost entirely to
NOX control. Note that there is a new 2011 PM standard for
engines above 750 horsepower. However, we believe that PM standard
could be met via engine-out control which would result in no new
tooling costs associated with that standard.
We have applied all the above tooling costs to all manufacturers
that appear to actually make engines. We have not eliminated joint
venture manufacturers because these manufacturers will 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 include
a capital opportunity cost of seven percent. 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. Note that all engine tooling costs for under 25
horsepower engines have been attributed to U.S. sales since other
countries are not expected to have similar standards on these engines.
More information is contained in chapter 6 of the RIA.
Using this methodology, we estimate the total tooling expenditures
attributable to the new Tier 4 standards at $74 million. For
comparison, our proposal estimated $67 million. The higher value here
is a result of: Expressing values in 2002 dollars rather than 2001
dollars; attributing all under 25 horsepower tooling costs to U.S.
sales while the proposal attributed 42 percent of those costs to U.S.
sales; and, above 750 horsepower tooling is slightly higher because of
the proposal's phase-in (50/50/50/100) of one set of standards while
the final rule has two sets of standards.
iii. Engine Certification Costs
The comments we received with respect to our estimated
certification costs noted that we had underestimated costs associated
with new test procedures, especially transient testing for engines
above 750 horsepower. For the final rule, we have tripled the costs
associated with new test procedures. Because we are not finalizing
transient test procedures for engines above 750 horsepower, comments
about the cost of these engines certifying using the transient test are
now moot.
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
using new test procedures (at least in some instances). Consistent with
our recent standard setting regulations, we have estimated engine
certification costs at $60,000 per new engine certification to cover
existing testing and administrative costs.\229\ The $60,000
certification cost per engine family was used for 25 to 75 horsepower
engines certifying to the 2008 standards. For 25 to 75 horsepower
engines certifying to the 2013 standards, and for 75 to 750 horsepower
engines certifying to their new standards, we have added costs to cover
the new test procedures for nonroad diesel engines (e.g., the transient
test, the NTE); \230\ these costs are estimated at $31,500 per engine
family.\231\ For engines under 25 horsepower, we have assumed (for cost
purposes) that all engines will certify to the transient test and the
NTE in 2008. We believe manufacturers may choose to do this rather than
certifying all engines again in 2013 when the transient test and NTE
requirements actually begin for those engines. This assumption results
in higher certification costs in 2008 than if these engines certified
only to the steady-state standard. However, we believe manufacturers
may choose to do this because it would avoid the need to
[[Page 39125]]
recertify all engines under 25 horsepower again in 2013. These
certification costs--whether it be the $60,000 or the $91,500 per
engine family--apply equally to all engine families for all
manufacturers regardless of into what markets the manufacturer sells.
For engines above 750 horsepower, the certification costs used were
$87,000 per family since these engines will not be certifying over the
new transient test procedure. We have applied these certification costs
to all U.S. sold engine families and then spread the total over U.S.
sales. In other words, we have not presumed that certification
conducted for U.S. engines would fulfill the certification requirements
of other countries and have, therefore, not spread total costs over
engine sales outside the U.S.
---------------------------------------------------------------------------
\229\ In the proposal we added a certification fee to this cost.
In the final rule we have not included the certification fee because
that cost will be accounted for in the certification fees rulemaking
(see 67 FR 51402 for the proposed rule). Including in the proposal
was essentially double counting that fee. Similarly, if we were to
include it in this final rule, we would be double counting that fee.
\230\ Note that the transport refrigeration unit (TRU) test
cycle is an optional duty cycle for steady-state certification
testing specifically tailored to the operation of TRU engines.
Likewise, the ramped modal cycles are available test cycles that can
be used to replace existing steady-state test requirements for
nonroad constant-speed engines, generally. Manufacturers of these
engines who opt to use one of these test cycles would incur no new
costs above those estimated here and may incur less cost.
\231\ Note that the proposal incorrectly used a value of $10,500
for costs associated with the new test procedures. Here, we have
corrected this error by using a value of $31,500. Note also that the
proposal erroneously did not include certification costs associated
with transient testing and the NTE for engines under 25 horsepower.
We have corrected that error in the final analysis.
---------------------------------------------------------------------------
Applying these costs to each of the 665 engine families as they are
certified to a new emissions standard results in total costs of $91
million expended during implementation of the Tier 4 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 percent 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 include a capital opportunity cost of seven percent. For
comparison, our proposal estimated certification costs at $72 million.
The increase here is a result of using a higher cost associated with
the new test procedures than was used in the proposal.
We also received comment that we should estimate certification
costs based on use of the ABT program rather than based on the phase-
in. Doing this would result in higher certification costs because all
engine families would be certified in year one of the phase-in and all
families would again be certified in the final year of the phase-in. In
contrast, since we have based certification costs on the phase-in, all
engine families are certified in year one (PM standards have no phase-
in) and only half are again certified in the final year (the 50 percent
not meeting the new NOX standard in year one). We have
chosen not to estimate certification or any costs based on use of the
ABT program (or the TPEM program) since it is so difficult to predict
how this program will be used. Furthermore, we must remain consistent
throughout our cost analysis so that, if we estimated certification
costs based on use of the ABT program, we should also base engine
variable costs and equipment variable costs on use of the ABT program.
Doing so, we believe, would decrease engine variable costs since that
is the primary reason manufacturers choose to make use of the ABT
program. Since engine variable costs, as discussed below, are a much
greater fraction of the overall program costs, we believe that we are
being conservative by generating our costs based on use of the phase-
in. Therefore, we believe that use of the ABT program (and the TPEM
program) will provide substantial net savings to industry even though
widespread use of ABT might cause certification costs to be higher.
b. Engine Variable Costs
This section summarizes the detailed analysis presented in chapter
6 of the RIA. For our analysis, we have used the 2002 annual average
costs for platinum and rhodium (the two platinum group metals (PGMs) we
expect will be used) because we believe they represent a better
estimate of the cost for PGM than other metrics. In the RIA, we present
a cost sensitivity that estimates the recovery value of precious metals
returned to the open market upon retirement of an aftertreatment
device. We present that analysis to gauge the true social cost of these
devices when new.
We have not made any changes to our engine variable costs as a
result of public comments. Some commenters (engine manufacturers)
claimed that we had underestimated these costs but did not provide any
detailed information about where they believed we had erred or what
they believed the costs should be. Other commenters (emission control
device manufacturers) claimed that we had done a fair job with our
estimates. Some commenters (equipment manufacturers) claimed that our
assumptions with respect to baseline engine configurations were not
accurate. However, as discussed earlier, based on our own engineering
judgement and the positive comments of the engine manufacturers--who we
consider a better source for such information than equipment
manufacturers since engine manufacturers are the directly affected
entities--we have maintained our original assumptions for baseline
engine configurations. Further, our assumed Tier 4 baseline engine
configurations are consistent with our assumed compliant technology
packages for T2/3, and those packages included the things equipment
manufacturers are claiming will not be present in the Tier 4 baseline.
As a result, we have already considered the costs associated with
reaching our Tier 4 baseline engine configurations in the context of
the T2/3 rule.
We have made changes to engine variable costs to remain consistent
with the final program--i.e., we have changed our greater than 750
horsepower cost estimates since the final standards differ from those
that were proposed. We have also changed the costs by expressing them
in 2002 dollars rather than 2001 dollars.\232\
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\232\ Note that the change to 2002 dollars had different effects
on different pieces of hardware. We have used two different PPI
adjustments in the analysis: one for motor vehicle catalytic
converters which was used to adjust costs for DOCs, NOX
adsorbers, and CDPFs; and another for motor vehicle parts and
accessories which was used for all other pieces of hardware. The
former of these adjustments actually caused costs to decrease
relative to the proposal while the latter caused costs to increase
slightly.
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i. NOX Adsorber System Costs
The NOX adsorber system that we are anticipating will be
used to comply with Tier 4 engine standards will 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 (these
costs were accounted for in our T2/3 rule). 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 estimated that warranty
costs will increase due to the application of this new hardware.
Chapter 6 of the RIA contains the details for how we estimated costs
associated with the new NOX control technologies required to
meet the 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 $2,040 in the near-term for a 500 horsepower
engine. In the long-term, we estimate these costs to be $550 and $1,650
for the 150 horsepower and 500 horsepower engines, respectively. These
costs may differ slightly from the proposal due to the adjustments to
2002 dollars. Note that we have estimated costs for all engines in all
horsepower
[[Page 39126]]
ranges, and these estimates are presented in detail in the 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. Here we have based our cost estimates on the use of silicon
carbide (SiC) even though it is more expensive than other filter
materials.\233\ We estimate that the CDPF systems will add $760 to
engine costs in the near-team for a 150 horsepower engine and $2,710 in
the near-term for a 500 horsepower engine. In the long-term, we
estimate these CDPF system costs to be $580 and $2,070 for the 150
horsepower and the 500 horsepower engines, respectively. These costs
may differ slightly from the proposal due to the adjustments to 2002
dollars.
---------------------------------------------------------------------------
\233\ This is particularly true with respect to engines above
750 horsepower where we believe that manufacturers may in fact use a
wire mesh substrate rather than the SiC substrate we have costed
and, indeed, we have based the level of the 2015 PM standard on this
use of wire mesh substrates (see section II.B.3.b). We have chosen
to remain conservative in our cost estimates by assuming use of a
SiC substrate for all engines.
---------------------------------------------------------------------------
iii. CDPF Regeneration System Costs
Application of CDPFs in nonroad applications may 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 $200 for a 150 horsepower engine and $330 for a 500
horsepower engine. In the long-term, we estimate these costs at $150
and $250, respectively. These costs may differ slightly from the
proposal due to the adjustments to 2002 dollars.
iv. Closed-Crankcase Ventilation System (CCV) Costs
Today's final rule eliminates 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 will 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 $30 for low horsepower engines and up to $90 for
very high horsepower engines. These costs are incurred only by turbo-
charged engines because today's naturally aspirated engines already
have CCV systems. These costs may differ slightly from the proposal due
to the adjustments to 2002 dollars.
v. Variable Costs for Engines Below 75 Horsepower and Above 750
Horsepower
The Tier 4 program includes standards for engines under 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.\234\ The 2008 standards for all engines under 75 horsepower
are of similar stringency and are expected to result in use of similar
technologies (i.e., the possible 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 under 75 horsepower is presented in section II.B.4 and
5. As discussed there, if changes are needed to comply, we expect
manufacturers to comply with the 2008 standards through either engine-
out improvements or through the addition of a DOC. From a cost
perspective, we have projected that engines will add a DOC. Presumably,
the manufacturer will choose the least costly approach that provides
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 will do. Therefore, we have assumed that, beginning in
2008, all engines below 75 horsepower add a DOC. Note that this
estimate is made more conservative since we have assumed this cost for
all engines when, in fact, some engines below 75 horsepower currently
meet the Tier 4 PM standard (for 2008) and will not, therefore, incur
any incremental costs to meet it. We have estimated this added hardware
to result in an increased engine cost of $143 in the near-term and $136
in the long-term for a 30 horsepower engine. These costs may differ
slightly from the proposal due to the adjustments to 2002 dollars.
---------------------------------------------------------------------------
\234\ We refer here to PM standards. There also is a
NOX+NMHC standard for 25-50 horsepower engines that takes
effect in 2013 and is equivalent to the Tier 3 NOX+NMHC
standard for 50-75 horsepower engines (see section II.A).
---------------------------------------------------------------------------
We have also projected that some engines in the 25 to 75 horsepower
range will have to upgrade their fuel systems to accommodate the CDPF.
We have estimated the incremental costs for these fuel systems at
roughly $870 for a three cylinder engine in the 25-50 horsepower range,
and around $450 for a four cylinder engine 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 will
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. These costs may differ slightly from the proposal due to the
adjustments to 2002 dollars.
We have also projected that engines in the 25-50 horsepower range
will add cooled EGR to comply with their new NOX standard in
2013. Additionally, we have estimated, for cost purposes, that engines
above 750 horsepower will add cooled EGR to comply with their new
NOX standard in 2011. This represents a conservative
estimate since we do not necessarily anticipate that cooled EGR will be
applied to all, if any, engines above 750 horsepower. Nonetheless, we
do expect some changes to be made (most probably some form of engine-
out emission control) and, consistent with our approach to costing DOCs
for engines below 75 horsepower in 2008, we have conservatively costed
cooled EGR for engines above 750 horsepower in 2011. We have estimated
that the EGR system will add $100 in the near-term and $70 in the long-
term to the cost of a 30 horsepower engine, and $550 and $420,
respectively, for engines above 750 horsepower. These costs may differ
slightly from the proposal due to
[[Page 39127]]
the adjustments to 2002 dollars. To these costs, we have added costs
associated with additional cooling that may be needed to reject the
heat generated by the cooled EGR system or other in-cylinder
technologies. These costs were not included in the proposal. Such
additional cooling might take the form of a larger radiator and/or a
larger or more powerful cooling fan. Based on cost estimates from our
Nonconformance Penalty rule (67 FR 51464), we have estimated that the
costs associated with additional cooling will add $40 in the near-term
and $30 in the long-term to the cost of a 30 horsepower engine, and
$710 in the near-term and $560 in the long-term for engine above 750
horsepower. Note that we are also projecting use of a CDPF for engines
above 750 horsepower, as was discussed above.
We believe there are factors that will 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.\235\ Our
analysis, as described in more detail in the 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.
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.
---------------------------------------------------------------------------
\235\ For example, see, ``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 new 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 II, and the
incremental cost for low-sulfur fuel is described in section VI.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
RIA over the life of the engine and are expressed in terms of cents/
gallon of fuel consumed. In section VI.C.3, we present these lifetime
operating costs as a net present value (NPV) in 2002 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 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 of the RIA).
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 will be a savings due to an
expected increase in oil change intervals because low sulfur fuel will
be far less corrosive than is current nonroad diesel fuel. Less
corrosion will 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
VI.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--fuel-related refining and distribution costs,
maintenance related costs, and fuel economy impacts--to be 5.4 cents/
gallon for a 150 horsepower engine and 6.5 cents/gallon for a 500
horsepower engine. More detail on operating costs can be found in
Chapter 6 of the 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 VI.B. We did receive comments
with respect to our oil change maintenance savings estimates. These
comments were address in section VI.B. We received no comments on our
CDPF and CCV maintenance costs or our CDPF regeneration costs.
2. Equipment Cost Impacts
In addition to the costs directly associated with engines that
incorporate new emission controls to meet new standards, costs will
increase due to the need to redesign the nonroad equipment in which
these engines are used. Such redesigns will 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. We
have accounted for these potential changes in establishing the lead
time for the Tier 4 emissions standards. The transition flexibility
provisions for equipment manufacturers that are included in this final
rule are an element of that lead time. These flexibility provisions are
described in detail in section III.B.
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 will be comprised of fixed costs
(for redesign to accommodate new emission control devices) and variable
costs (for new equipment hardware to affix the new emission control
devices and for labor to install those emission control devices). Note
that the fixed costs do not
[[Page 39128]]
include certification costs because the equipment is not certified to
emission standards. The engine is certified by the engine manufacturer;
therefore, the related certification costs are counted as an engine
fixed cost. We have also attributed all changes in operating costs
(e.g., additional maintenance) to the cost estimates for engines.
Included in section VI.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 RIA.
All costs are presented in 2002 dollars.
We have made only limited changes relative to the proposal with
respect to our estimated equipment costs, as discussed below. We did
receive comment that we underestimated costs for equipment redesign and
for markups on equipment variable costs. The commenters making these
claims relative to equipment redesign costs tended to be those that
have relative high equipment sales volumes. Such manufacturers tend to
expend levels higher than we estimated in our proposal for equipment
redesign because they sell into highly competitive markets and they can
spread costs over many units. However, some equipment manufacturers we
have met with, most notably those with small sales volumes, do not
appear to expend nearly the level we estimated in the proposal. These
manufacturers tend to sell into markets with few competitors, produce
machines by hand, and expend less redesign effort relative to a high
sales volume manufacturer.\236\ Our goal in the proposal was to
estimate the redesign costs spent by industry (i.e., the average cost
per piece of equipment multiplied by all equipment resulting in an
estimated total industry cost), rather than estimating the maximum cost
to be spent by any particular manufacturer. As a result, our equipment
redesign estimates per model may be too low for some manufacturers, but
they are also too high for others. We believe this cost methodology
provides as accurate an estimate as can be made. We have used the same
methodology for the final cost estimates presented here.
---------------------------------------------------------------------------
\236\ ``Meeting between Staff of Eagle Crusher Company, Inc.,
and EPA,'' memorandum from Todd Sherwood to Air Docket A-2001-28,
Docket Item IV-E-40, EDOCKET OAR-2003-0012-0868, March 16, 2004.
---------------------------------------------------------------------------
As for the comments with respect to equipment variable costs, we
did indeed include a markup of 29 percent and disagree with the
commenter that a two-to-one markup would be more appropriate. Such a
high markup on equipment variable costs is not sustainable in a
competitive market, at least on average, and the commenter provided no
data nor study that supported the comment.
We have made minor changes to the proposed numbers to express them
in 2002 dollars and to reflect where the program has changed (i.e.,
greater than 750 horsepower mobile machines). We have also attributed
all under 25 horsepower redesign costs to U.S. sales since we do not
expect other countries to have similar emission standards for these
engines/equipment. Lastly, we have corrected some minor errors made in
the proposal in determining motive versus non-motive models and
determining the number of unique equipment models needing redesign. We
now estimate that a total of over 4,500 equipment models will be
redesigned as compared to the proposal's estimate of just over 4,100
equipment models. Further discussion of these changes can be found in
Chapter 6 of the RIA.
a. Equipment Fixed Costs
As we noted in the proposal, 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. Equipment manufacturers must still incur the effort
and expense of integrating the engine and emissions control devices
into the piece of equipment. Therefore, 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 new emission
standards for engines rated under 25 horsepower and the 2008 standards
for 25-75 horsepower engines are projected to require no significant
equipment redesign beyond that done to accommodate the Tier 2
standards. As explained earlier, we expect that these engines will
comply with the new 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 will not affect the
outer dimensions of the engine and that a DOC will replace the existing
muffler. Therefore, either approach taken by the engine manufacturer
should have limited to no impact on the equipment design. Nonetheless,
we have conservatively estimated their redesign costs at $53,100 per
model.\237\
---------------------------------------------------------------------------
\237\ Note that the equipment redesign estimates, and all other
equipment related costs, have been adjusted from the NPRM to express
them in 2002 dollars.
---------------------------------------------------------------------------
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 $53,100 for some lower powered
equipment models to well over $1 million for high horsepower equipment
with very challenging design constraints. We believe that the equipment
redesign efforts undertaken for the T2/3 are representative of the
effort that will be required for Tier 4 because the changes needed are
the same in nature--increasing available space within the machine to
accommodate new hardware. We have based our Tier 4 estimates, in part,
on that industry input and have estimated that equipment redesign costs
will range from $53,100 per model for 25 horsepower equipment up to
$796,500 per model for 300 horsepower equipment and above. For mobile
machines greater than 750 horsepower, we have used a new redesign cost
of $106,000 associated with the 2011 standards which is consistent in
scale with the estimate used for 25 to 50 horsepower equipment that add
both EGR and a CDPF in the 2013 timeframe. This estimate was not in the
proposal. For this larger equipment, we have continued with an estimate
of $796,500 associated with the 2015 standards even though we project
no need to accommodate a NOX adsorber. 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; we estimate these service manual updates to cost
between $2,660 and $10,620 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 $828 million. We have assumed that these costs
will be
[[Page 39129]]
recovered over a ten year period with a seven percent opportunity cost
of capital. By comparison, our proposal estimated equipment fixed costs
at $698 million. The costs are higher now because of the changes
mentioned above--expressing costs in 2002 dollars; attributing all
under 25 horsepower redesign costs to U.S. sales; and, correcting
upward the number of equipment models to be redesigned.
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 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 above 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 $150. Note that we
have estimated costs for equipment in all horsepower ranges, and these
estimates are presented in detail in the 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 Tier 4 standards, we have chosen several example
pieces of equipment and have 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 new standards. These costs along with information
about each example piece of equipment are shown in table VI.C-1. Costs
presented are near-term and long-term costs for the final standards to
which each piece of equipment will 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 VI.C-1.--Near-Term and Long-Term Costs for Several Example Pieces of Equipment a
($2002, for the final emission standards to which the equipment must comply)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gen-Set Skid/ Backhoe Dozer Ag tractor Dozer Off-highway
------------------------------------------------------------------------------- steer -------------------------------------------------- truck
loader ------------
Horsepower 9 hp ----------- 76 hp 175 hp 250 hp 503 hp
33 hp 1000 hp
--------------------------------------------------------------------------------------------------------------------------------------------------------
Incremental Engine & Equipment Cost................................ $120 $790 $1,200 $2,560 $1,970 $4,140 $4,670
Long-Term........................................................ 180 1,160 1,700 3,770 3,020 6,320 8,610
Near-Term........................................................
Estimated Equipment Price when New b............................... 4,000 20,000 49,000 238,000 135,000 618,000 840,000
Incremental Operating Costs c...................................... -80 70 610 2,480 2,110 7,630 20,670
Baseline Operating Costs (Fuel & Oil only) c....................... 940 2,680 7,960 27,080 23,750 77,850 179,530
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 ``Price Database for New Nonroad Equipment,'' memorandum from Zuimdie Guerra to EDOCKET OAR-2003-0012-0960. 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 VI.E.
D. Annual Costs and Cost Per Ton
One tool that can be used to assess the value of the Tier 4
standards for NRLM fuel and nonroad engines is the costs incurred per
ton of emissions reduced. This analysis involves a comparison of our
new program to other measures that have been or could be implemented.
As summarized in this section and detailed in the RIA, the program
being finalized today represents a highly cost effective mobile source
control program for reducing PM, NOX, and SO2
emissions.
We have calculated the cost per ton of our Tier 4 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 (i.e., calendar years 2007 through 2036). This approach
captures all of the costs and emissions reductions from our new program
including those costs incurred and emissions reductions generated by
the existing fleet. The baseline for this evaluation is the existing
set of fuel and engine standards (i.e., unregulated NRLM 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 new standards will be in the fleet, and the later period
when essentially all engines will meet the new standards.
We have analyzed the cost per ton reduced of several different
scenarios. The costs and emissions reductions of each of these
scenarios are presented in detail in chapter 8 of the RIA. Here, we
present information of the cost and cost effectiveness for the
following two scenarios: (1) The full NRLM fuel and nonroad engine
program, meaning two steps of fuel control (to 500 ppm and then to 15
ppm) for both NR and L&M fuel and all of the nonroad engine standards;
and, (2) the NRLM fuel-only program, meaning two steps of fuel control
(to 500 ppm and then to 15 ppm) for both NR and L&M fuel but without
any new nonroad engine standards.\238\ For the first of these
scenarios, the discussion illustrates the costs and relative cost
effectiveness of the final NRT4 program to other programs. For the
second of these scenarios, the discussion illustrates the costs and
cost effectiveness associated with the fuel program as if implemented
as a stand alone program without new engine standards.
---------------------------------------------------------------------------
\238\ We are not analyzing a scenario involving just the engine
standards because the nonroad engine standards involving advanced
emissions control technologies require the use of the 15ppm fuel.
---------------------------------------------------------------------------
In sections VI.D.1 and 2, we present the cost of the full NRLM fuel
and nonroad engine program and the cost per ton of PM,
NOX+NMHC, and SO2 reductions that will be
realized. The analysis presented in sections VI.D.1 and 2 represents
the total Tier 4 program for nonroad diesel engines and NRLM fuel being
finalized today. In sections VI.D.3 and 4, we summarize the
[[Page 39130]]
cost for the NRLM fuel-only scenario and the cost per ton of PM and
SO2 reductions that would be realized.
1. Annual Costs for the Full NRLM Fuel and Nonroad Engine Program
The costs of the full NRLM fuel and nonroad engine program include
costs associated with both steps in the NRLM fuel program--the NR fuel
reduction to 500 ppm sulfur in 2007 and to 15 ppm sulfur in 2010 and
the L&M fuel reduction to 500 ppm sulfur in 2007 and to 15 ppm sulfur
in 2012. Also included are costs for the 2008 nonroad engine standards
for engines less than 75 horsepower, the 2013 standards for 25 to 75
horsepower engines, and costs for the nonroad engine standards for
engines above 75 horsepower. All maintenance and operating costs are
included along with maintenance savings realized by both the existing
fleet (nonroad, locomotive, and marine) and the new fleet of engines
complying with the Tier 4 standards.
Figure VI.D-1 presents these results. All capital costs for NRLM
fuel production and nonroad engine and equipment fixed costs have been
amortized at seven percent. The figure shows that total annual costs
are estimated to be $50 million in the first year the new engine
standards apply, increasing to a peak of $2.2 billion in 2036 as
increasing numbers of engines become subject to the new nonroad
standards and an ever increasing amount of NRLM fuel is consumed. The
net present value of the annualized costs over the period from 2007 to
2036 is $27 billion using a 3 percent discount rate and $14 billion
using a 7 percent discount rate.
[GRAPHIC]
[TIFF OMITTED]
TR29JN04.004
2. Cost per Ton of Emissions Reduced for the Full NRLM Fuel and Nonroad
Engine Program
We have calculated the cost per ton of emissions reduced associated
with the NRT4 engine and NRLM fuel program. The resultant cost per ton
numbers depend on how the costs presented above are allocated to each
pollutant. Therefore, we have carefully allocated costs according to
the pollutants for which they are incurred. Where fuel changes occur in
conjunction with new engine standards (engine standards enabled by
those fuel changes), we allocate one-half of the fuel-related costs to
fuel-derived emissions reductions (PM and SO2, with one-
third of that half allocated to PM and two-thirds to SO2)
and one-half to engine-derived emissions reductions
(NOX+NMHC and PM, with that half split 50/50 between each
pollutant). Where fuel changes occur without new engine standards on
which fuel changes are premised (i.e., 500ppm NRLM fuel and 15ppm L&M
fuel), we have allocated costs associated with fuel-derived emissions
reductions one-third to PM and two-thirds to SO2. We have
allocated costs associated with engine-derived emissions reductions
(i.e., engine/equipment costs) directly to
[[Page 39131]]
the pollutant for which the cost is incurred. These engine and
equipment cost allocations are noted throughout the discussion in
section VI.C, and are detailed in full in chapter 8 of the RIA.
We have calculated the costs per ton 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 reduced in the year 2030 using
the annual costs and emissions reductions in that year alone. This
number represents the long-term cost per ton of emissions reduced. The
cost per ton numbers include costs and emission reductions that will
occur from the existing fleet (i.e., those pieces of nonroad equipment
that were sold into the market prior to the new emission standards).
These results are shown in Table VI.D-1 using both a three percent and
a seven percent social discount rate.
Table VI.D-1.--Total Fuel and Engine Program 30 Year Aggregate Cost per Ton and Long-Term Annual Cost Per Ton
($2002)
----------------------------------------------------------------------------------------------------------------
30 year discounted 30 year discounted
Pollutant lifetime cost per ton lifetime cost per ton Long-term cost per ton
at 3% at 7% in 2030
----------------------------------------------------------------------------------------------------------------
NOX+NMHC............................. $1,010 $1,160 $680
PM................................... 11,200 11,800 9,300
SOX.................................. 690 620 810
----------------------------------------------------------------------------------------------------------------
3. Annual Costs for the NRLM Fuel-only Scenario
Cent per gallon costs for the new 500 ppm NRLM fuel, the new 500
ppm L&M fuel, the new 15 ppm NR fuel, and the new 15 ppm NRLM fuel were
presented in section IV.A. Having this fuel will 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 VI.B. There are no
engine and equipment costs associated with the NRLM fuel-only scenario
because new engine emissions standards are not included in that
scenario. Figure VI.D-2 shows the annual costs associated with the NRLM
fuel-only program.
As can be seen in figure VI.D-1, the costs for refining and
distributing the fuel range from $250 million in 2008 to nearly $1.3
billion in 2036. The increase in fuel costs in 2010 reflect the change
to higher cost 15 ppm NR fuel. Fuel costs continue to grow as more fuel
is consumed by the increasing number of engines and equipment. The fuel
costs are largely offset by the maintenance savings that range from
$250 million in 2008 to $500 million in 2036. As a whole, the net cost
of the program in each year ranges from a small net savings in 2008 to
around $780 million in 2036. The net present value (i.e., the value in
2004) of the net costs associated with the NRLM fuel-only program
during the 30 year period from 2007 to 2036 is estimated at $9.2
billion using a 3 percent discount rate and $4.6 billion using a 7
percent discount rate.
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4. Cost Per Ton of Emissions Reduced for the NRLM Fuel-Only Scenario
The fuel-borne sulfur reduction under the NRLM fuel-only scenario
will result in significant reductions of both SO2 and PM
emissions. Since there are no new engine standards associated with the
NRLM fuel-only scenario, the emissions reductions that result are
entirely fuel-derived. Roughly 98 percent of fuel-borne sulfur is
converted to SO2 in the engine with the remaining two
percent being exhausted as sulfate PM. We have allocated one-third of
the costs of this program to PM control and two-thirds to
SO2 control. This is consistent with the cost accounting we
have used throughout our analysis in that costs associated with fuel-
derived emissions reductions are attributed one-third to PM control and
two-thirds to SO2 control.
As discussed above, the 30 year net present value of costs
associated with the fuel-only program are estimated at $9.2 billion
using 3 percent discounting and $4.6 billion using 7 percent
discounting. We have estimated the 30 year net present value of the
SO2 emission reductions at 5.7 million tons and PM emission
reductions at 462,000 tons using 3 percent discounting, 3.2 million
tons and 255,000 tons, respectively, using 7 percent discounting.
Table VI.D-1 shows the cost per ton of emissions reduced as a
result of the NRLM fuel-only scenario. The cost per ton numbers include
costs and emissions reductions that will 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 new fuel standards) of nonroad,
locomotive, and marine engines.
Table VI.D-2.--NRLM Fuel-Only Scenario--30-year Aggregate Cost per Ton and Long-term Annual Cost per Ton
[$2002]
----------------------------------------------------------------------------------------------------------------
30 year discounted 30 year discounted
Pollutant lifetime cost per ton lifetime cost per ton Long-term cost per ton
at 3% at 7% in 2030
----------------------------------------------------------------------------------------------------------------
PM................................... $6,600 $6,000 $7,900
SO2.................................. 1,070 970 1,270
----------------------------------------------------------------------------------------------------------------
[[Page 39133]]
We also considered the cost per ton of the NRLM fuel-only scenario
without including the expected maintenance savings associated with low
sulfur fuel. Without the maintenance savings, the 30 year discounted
cost per ton of PM reduced would be $11,800 and of SO2
reduced would be $1,900 using 3 percent discounting and $11,200 and
$1,800, respectively, using 7 percent discounting. More detail on how
the costs and cost per ton numbers associated with the NRLM fuel-only
scenario were calculated can be found in the RIA.
5. Comparison With Other Means of Reducing Emissions
In comparison with other emissions control programs, we believe
that the Tier 4 programs represent a cost effective strategy for
generating substantial NOX+NMHC, PM, and SO2
reductions. This can be seen by comparing the cost per ton of emissions
reduced by the NRLM fuel-only scenario (i.e., reducing fuel sulfur to
500 ppm in 2007 and 15 ppm in 2010 without any new nonroad engine
standards) and the cost per ton of emissions reduced by the full NRLM
fuel and nonroad engine program (i.e., fuel control and new engine
standards) with a number of standards that EPA has adopted in the past.
Tables VI.D-3 and VI.D-4 summarize the cost per ton of several past EPA
actions to reduce emissions of NOX+NMHC and PM from mobile
sources, all of which were considered by EPA to be appropriate.
Table VI.D-3.--NRT4 Cost Per Ton Comparison to Previous Mobile Source
Programs for NOX + NMHC
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Tier 4 Nonroad Diesel (full program).................... 1,010
Tier 2 Nonroad Diesel................................... 630
Tier 3 Nonroad Diesel................................... 430
Tier 2 vehicle/gasoline sulfur.......................... 1,400-2,350
2007 Highway HD......................................... 2,240
2004 Highway HD......................................... 220-430
Tier 1 vehicle.......................................... 2,150-2,910
NLEV.................................................... 2,020
Marine SI engines....................................... 1,220-1,930
On-board diagnostics.................................... 2,410
Marine CI engines....................................... 30-190
Large SI Exhaust........................................ 80
Recreational Marine..................................... 670
------------------------------------------------------------------------
Note: Costs adjusted to 2002 dollars using the Producer Price Index for
Total Manufacturing Industries.
Table VI.D-4. `` NRT4 Cost Per Ton Comparison to Previous Mobile Source
Programs for PM
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Tier 4 Nonroad Diesel (full program).................... 11,200
Tier 4 NRLM fuel-only (fuel-only scenario).............. 6,800
Tier 1/Tier 2 Nonroad Diesel............................ 2,390
2007 Highway HD......................................... 14,180
Marine CI engines....................................... 4,040-5,440
1996 urban bus.......................................... 12,780-20,450
Urban bus retrofit/rebuild.............................. 31,530
1994 highway HD diesel.................................. 21,780-25,500
------------------------------------------------------------------------
Note: Costs adjusted to 2002 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 (acid rain) 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 (
http://www.epa.gov/airmarkets/epa-ipm/index.html#documentation).
The SO2 cost per ton results of the full Tier 4 program
presented in table VI.D-2 compare very favorably with the program shown
in table VI.D-5.
Table VI.D-5.--NRT4 Cost Per Ton Comparison to SO2 from both the EPA
Base Case 2000 for the Title IV SO2 Trading Programs and the Proposed
Interstate Air Quality Rule
------------------------------------------------------------------------
Program $/ton
------------------------------------------------------------------------
Tier 4 Nonroad Diesel (full program)...... $690
Tier 4 Nonroad Diesel (fuel-only scenario) 1,070
Title IV SO2 Trading Programs............. 490 in 2010 to 610 in 2020
Interstate Air Quality Rule (average cost) 730 in 2010 to 830 in 2015
------------------------------------------------------------------------
Note: Costs adjusted to 2002 dollars using the Producer Price Index for
Total Manufacturing Industries.
As the above comparisons show, both the NRLM fuel-only scenario,
when viewed by itself, and the combination of NRLM fuel and nonroad
engine standards, are both cost effective strategies to achieve the
associated emissions reductions.
E. Do the Benefits Outweigh the Costs of the Standards?
Our analysis of the health and environmental benefits to be
expected from this final rule are presented in this section. Briefly,
the analysis projects major benefits throughout the period from initial
implementation of the rule over a 30 year period through 2036. 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 $805 billion dollars using
a 3 percent discount rate and $352 billion using a 7 percent discount
rate. These benefits exceed the net present value of the social cost of
the proposal ($27 billion using a 3 percent discount rate and $14
billion using a 7 percent discount rate) by $780 billion using a 3
percent discount rate and $340 billion using a 7 percent discount rate.
1. What Were the Results of the Benefit-Cost Analysis?
Table VI.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. In
2030, we estimate that there will be 12,000 fewer fatalities in adults
\239\ and 20 fewer fatalities in infants per year associated with fine
PM, and the rule will result in about 5,600 fewer cases of chronic
bronchitis, 8,900 fewer hospitalizations (for respiratory and
cardiovascular disease combined), and result in 1 million days per year
when adults miss work because of their respiratory symptoms and 5.9
million days of when adults must restrict their activity due to
respiratory illness. We also estimate substantial health improvements
for children from reduced upper and lower respiratory illness, acute
bronchitis, and asthma
[[Page 39134]]
attacks.\240\ We were unable to quantify the benefits related to ozone
and other pollutants for the final rule, although we do present some
preliminary ozone modeling in Chapter 9 of the RIA.
---------------------------------------------------------------------------
\239\ While we did not include separate estimates of the number
of premature deaths that would be avoided due to reductions in ozone
levels, recent evidence has been found linking short-term ozone
exposures with premature mortality independent of PM exposures.
Recent reports by Thurston and Ito (2001) and the World Health
Organization (WHO) support an independent ozone mortality impact,
and the EPA Science Advisory Board has recommended that EPA
reevaluate the ozone mortality literature for possible inclusion in
the estimate of total benefits. Based on these new analyses and
recommendations, EPA is sponsoring three independent meta-analyses
of the ozone-mortality epidemiology literature to inform a
determination on inclusion of this important health endpoint. Upon
completion and peer-review of the meta-analyses, EPA will make its
determination on whether and how benefits of reductions in ozone-
related mortality will be included in the benefits analysis for
future rulemakings.
\240\ Our PM-related estimate in 2030 incorporates significant
reductions of 160,000 fewer cases of lower respiratory symptoms in
children ages 7 to 14 each year, 120,000 fewer cases of upper
respiratory symptoms (similar to cold symptoms) in asthmatic
children each year, and 13,000 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 VI.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 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 VI.E-6.
In summary, EPA's primary estimate of the benefits of the rule are
$83 + B billion in 2030 using a 3 percent discount rate and $78 + B
billion using a 7 percent discount rate. In 2020, total monetized
benefits are $42 + B billion using a 3 percent discount rate and $41 +
B billion using a 7 percent discount rate. 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 VI.E-1.--Reductions in Incidence of PM-Related Adverse Health
Effects Associated With the Final Nonroad Diesel Engine and Fuel
Standards Full Program
------------------------------------------------------------------------
Avoided incidence a (cases/year)
Endpoint -------------------------------------
2020 2030
------------------------------------------------------------------------
Premature mortality b: Long-term 6,500 12,000
exposure (adults, 30 and over)...
Infant mortality (infants under 15 22
one year)........................
Chronic bronchitis (adults, 26 and 3,500 5,600
over)............................
Non-fatal myocardial infarctions 8,700 15,000
(adults, 18 and older)...........
Hospital admissions--Respiratory 2,800 5,100
(adults, 20 and older) c.........
Hospital admissions-- 2,300 3,800
Cardiovascular (adults, 20 and
older) d.........................
Emergency Room Visits for Asthma 3,800 6,000
(18 and younger).................
Acute bronchitis (children, 8-12). 8,400 13,000
Asthma exacerbations (asthmatic 120,000 200,000
children, 6-18)..................
Lower respiratory symptoms 100,000 160,000
(children, 7-14).................
Upper respiratory symptoms 76,000 120,000
(asthmatic children, 9-11).......
Work loss days (adults, 18-65).... 670,000 1,000,000
Minor restricted activity days 4,000,000 5,900,000
(adults, 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 VI.E-2.--EPA Primary Estimate of the Annual Quantified and
Monetized Benefits Associated With Improved PM Air Quality Resulting
From the Final Nonroad Diesel Engine and Fuel Standards Full Program
------------------------------------------------------------------------
Monetary Benefits a, b (millions
2000$, Adjusted for Income Growth)
Endpoint -------------------------------------
2020 2030
------------------------------------------------------------------------
Premature mortality c: (adults, 30
and over)
3% discount rate.............. $41,000 $77,000
7% discount rate.............. 38,000 72,000
Infant mortality (infants under 97 150
one year)........................
Chronic bronchitis (adults, 26 and 1,500 2,400
over)............................
Non-fatal myocardial infarctions d
3% discount rate.............. 750 1,200
7% discount rate.............. 720 1,200
Hospital Admissions from 49 92
Respiratory Causes e.............
Hospital Admissions from 51 83
Cardiovascular Causes f..........
Emergency Room Visits for Asthma.. 1.1 1.7
Acute bronchitis (children, 8-12). 3.2 5.2
Asthma exacerbations (asthmatic 5.7 9.2
children, 6-18)..................
Lower respiratory symptoms 1.7 2.7
(children, 7-14).................
Upper respiratory symptoms 2.0 3.2
(asthmatic children, 9-11).......
Work loss days (adults, 18-65).... 92 130
Minor restricted activity days 210 320
(adults, age 18-65)..............
Recreational visibility (86 Class 1,000 1,700
I Areas).........................
Monetized Total g.............
3% discount rate.......... 44,000+B 83,000+B
[[Page 39135]]
7% discount rate.......... 42,000+B 78,000+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
of base estimate assumes discounting over the lag structure described
in the RIA Chapter 9. d Estimates assume costs of illness and lost
earnings in later life years are discounted using either 3 or 7
percent. e Respiratory hospital admissions for PM includes admissions
for COPD, pneumonia, and asthma. f Cardiovascular hospital admissions
for PM includes total cardiovascular and subcategories for ischemic
heart disease, dysrhythmias, and heart failure. g 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 VI.E-6.
The estimated social cost (measured as changes in consumer and
producer surplus) in 2030 to implement the final rule from table VI.E-3
is $2.0 billion (2000$). Thus, the net benefit (social benefits minus
social costs) of the program at full implementation is approximately
$81 + B billion using a 3 percent discount rate and $78 + B billion
using a 7 percent discount rate. In 2020, partial implementation of the
program yields net benefits of $42 + B billion using a 3 percent
discount rate and $41 + B billion using a 7 percent discount rate.
Therefore, implementation of the final rule is expected to provide
society with a net gain in social welfare based on economic efficiency
criteria. Table VI.E-3 presents a summary of the benefits, costs, and
net benefits of the final rule's full program. Figure VI-E.1 displays
the stream of benefits, costs, and net benefits of the Nonroad Diesel
Vehicle Rule from 2007 to 2036 using two different discount rates. In
addition, table VI.E-4 presents the net present value of the stream of
benefits, costs, and net benefits associated with the rule for this 30
year period. The total net present value in 2004 of the stream of net
benefits (benefits minus costs) is $780 billion using a 3 percent
discount rate and $340 billion using a 7 percent discount rate.
Table VI.E-3.--Summary of Benefits, Costs, and Net Benefits of the Final
Nonroad Diesel Engine and Fuel Standards Full Program
------------------------------------------------------------------------
2020 \a\ (Billions 2030 \a\ (Billions
of 2000 dollars) of 2000 dollars)
------------------------------------------------------------------------
Social Costs \b\................ $1.8.............. $2.0.
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. $1.0.............. $1.7.
PM-related Health benefits $43 + B........... $81 + B.
[3% discount].
PM-related Health benefits $41 + B........... $78 + B.
[7% discount].
Net Benefits (Benefits-Costs) $44 + B........... $81 + B.
[3% discount]
\c\.
Net Benefits (Benefits-Costs) $42 + B........... $78 + B.
[7% discount]
\c\.
------------------------------------------------------------------------
Notes: \a\ All costs and benefits are calculated using 3 and 7 percent
discount rates and are rounded to two significant digits. Numbers may
appear not to sum due to rounding.
\b\ Note that costs are the total costs of reducing all pollutants,
including CO, VOCs and air toxics, as well as NOX and PM. Costs were
converted to 2000$ using the PPI for Total Manufacturing Industries.
Benefits in this table are associated only with PM endpoints related
to direct PM, NOX and SO2 reductions in 48-states.
\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 VI.E-6. B is the sum
of all unquantified benefits and disbenefits.
[[Page 39136]]
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Table VI.E-4.--Net Present Value in 2004 of the Stream of 30 Years of
Benefits, Costs, and Net Benefits for the Full Nonroad Diesel Engine and
Fuel Standards
[Billions of 2000$]
------------------------------------------------------------------------
3% 7%
discount discount
rate rate
------------------------------------------------------------------------
Social Costs.................................... $27 $14
Social Benefits................................. 805 352
Net Benefits \a\................................ 780 340
------------------------------------------------------------------------
Notes: \a\ Numbers do not add due to rounding. Benefits represent 48-
state benefits and exclude home heating oil sulfur reduction benefits,
whereas costs include 50-state estimates.
In addition, we analyzed the social benefits and costs of the fuel-
only components of the program, as discussed in the RIA. EPA's primary
estimate of the benefits of the fuel-only component of the final rule
are approximately $28 + B billion in 2030 using a 3 percent discount
rate and $25 + B billion using a 7 percent discount rate. In 2020,
total monetized benefits are approximately $18 + B billion using a 3
percent discount rate and $16 + B billion using a 7 percent discount
rate. These estimates account for growth in real gross domestic product
(GDP) per capita between the present and the years 2020 and 2030. We
present the engineering costs of implementing the fuel-only components
of the rule. Engineering compliance costs are very similar to the total
social costs for the entire program. The net benefit (social benefits
minus engineering costs) of the fuel-only program at full
implementation is approximately $330 + B billion using a 3 percent
discount rate and $160 + B billion using a 7 percent discount rate.
Therefore, implementation of the fuel-only components of the final rule
is expected to provide society with a net gain in social welfare based
on economic efficiency criteria. Table VI.E-5 presents a summary of the
social benefits, engineering costs, and net benefits of the final
rule's fuel-only program for a 30 year period.
Table VI.E-5.--Net Present Value in 2004 of the Stream of Benefits,
Costs, and Net Benefits for the Fuel-Only Standards
[Billions of 2000$]
------------------------------------------------------------------------
3% 7%
Discount Discount
rate rate
------------------------------------------------------------------------
Costs........................................... $9.2 $4.6
Social Benefits................................. 340 160
Net Benefits.................................... 330 160
------------------------------------------------------------------------
Notes:
\A\ Results are rounded to two significant digits. Sums may differ
because of rounding.
\B\ Engineering costs are presented instead of social costs. As
discussed in previous chapters, total engineering costs include fuel
costs (refining, distribution, lubricity) and other operating costs
(oil change maintenance savings).
\C\ 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 SO2 reductions. The
estimates do not include the benefits of reduced sulfur in home
heating oil or benefits in Alaska or Hawaii.
2. What Was Our Overall Approach to the Benefit-Cost Analysis?
The basic question we sought to answer in the benefit-cost analysis
was,
[[Page 39137]]
``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 and sulfate, as well as SO2
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 this modeling conducted for 2020 and
2030 are then scaled and transferred to the emission reductions
expected from the final 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, it is often necessary to select an
example set of emission reductions to use for the purposes of emissions
and air quality modeling early in the development of the proposal. 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 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 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. Based on public comment and
other data described in the RIA, the standards we are finalizing in
this rulemaking 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,
SO2, 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, SO2, 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.
\241\ 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. \242\
---------------------------------------------------------------------------
\241\ The section 812 studies include: (1) U.S. 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.
\242\ Interested parties may want to consult the webpage:
http://www.epa.gov/science1 regarding components of our analytical
blueprint.
---------------------------------------------------------------------------
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 PM.
In its report, the NAS panel 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; and
? 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
final rule. We provide benefits estimates for each year over the rule
implementation period for a wide range of regulatory alternatives, in
addition to our final 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
[[Page 39138]]
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 continue to refine its plans for addressing
uncertainty in its analyses. EPA conducted a pilot study to address
uncertainty in important analytical parameters such as the
concentration-response relationship for PM-related premature mortality.
EPA is also conducting 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 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, odor, 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; and
? 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 final rulemaking in future years under a set of assumptions.
Accordingly, we present a primary estimate of the total benefits, based
on our interpretation of the best available scientific literature and
methods and supported by the SAB-HES and the NAS.
Some of the key assumptions underlying the primary estimate for the
premature mortality which accounts for 90 percent of the total benefits
we were able to quantify include the following:
(1) Inhalation of fine particles is causally associated with
premature death at concentrations near those experienced by most
Americans on a daily basis. Although biological mechanisms for this
effect have not yet been definitively established, the weight of the
available epidemiological evidence supports an assumption of causality.
(2) All fine particles, regardless of their chemical composition,
are equally potent in causing premature mortality. This is an important
assumption, because PM produced via transported precursors emitted from
EGUs may differ significantly from direct PM released from diesel
engines and other industrial sources, but no clear scientific grounds
exist for supporting differential effects estimates by particle type.
(3) The impact function for fine particles is approximately linear
within the range of ambient concentrations under consideration. Thus,
the estimates include health benefits from reducing fine particles in
areas with varied concentrations of PM, including both regions that are
in attainment with fine particle standard and those that do not meet
the standard.
(4) The forecasts for future emissions and associated air quality
modeling are valid. Although recognizing the difficulties, assumptions,
and inherent uncertainties in the overall enterprise, these analyses
are based on peer-reviewed scientific literature and up-to-date
assessment tools, and we believe the results are highly useful in
assessing this rule.
We provide sensitivity analyses to illustrate the effects of
uncertainty about key analytical assumptions in the RIA.
In addition, 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 VI.E-6. These effects are denoted by ``B'' in Table VI.E-3 above,
and are additive to the estimates of benefits.
[[Page 39139]]
Table VI.E-6.--Additional, Non-monetized Benefits of the Nonroad Diesel
Engine and Fuel Standards
------------------------------------------------------------------------
Pollutant Unquantified effects
------------------------------------------------------------------------
Ozone Health................. Premature mortality \a\.
Respiratory hospital admissions.
Minor restricted activity days.
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.
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.................... 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.
------------------------------
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.
------------------------------
CO Health.................... Premature mortality \a\.
Behavioral effects.
------------------------------
HC Health \b\................ Cancer (benzene, 1,3-butadiene,
formaldehyde, acetaldehyde).
Anemia (benzene).
Disruption of production of blood
components (benzene).
Reduction in the number of blood
platelets (benzene).
Excessive bone marrow formation
(benzene).
Depression of lymphocyte counts
(benzene).
Reproductive and developmental effects
(1,3-butadiene).
Irritation of eyes and mucus membranes
(formaldehyde).
Respiratory irritation (formaldehyde).
Asthma attacks in asthmatics
(formaldehyde).
Asthma-like symptoms in non-asthmatics
(formaldehyde).
Irritation of the eyes, skin, and
respiratory tract (acetaldehyde).
Upper respiratory tract irritation and
congestion (acrolein).
------------------------------
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 Pope, et al. C-R function for premature mortality
captures both PM mortality benefits and any mortality benefits
associated with other air pollutants.
\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
We prepared a draft Economic Impact Analysis (EIA) for this rule to
estimate the economic impacts of the proposed control program on
producers and consumers of nonroad engines, equipment, fuel, and
related industries.\243\ We received comments on
[[Page 39140]]
our draft analysis from stakeholders representing agricultural
interests, equipment rental and dealer interests, and equipment
manufacturers. The commenters conveyed their concerns about our general
analytic approach and some of the model assumptions. As explained in
our responses to these comments, which can be found in the Summary and
Analysis of Comments document prepared for this final rule, we do not
believe these comments require us to adjust our EIA methodology. We did
adjust the methodology, however, to estimate the economic impacts of
the fuel sulfur content requirements on the locomotive and marine
sectors. As explained below, this revision was necessary to correct an
oversight in the draft EIA. We also revised the price and quantity data
inputs to the model to make them consistent with the revised engine and
fuel cost analyses described earlier in this section.
---------------------------------------------------------------------------
\243\ This analysis is based on an earlier version of the
engineering costs developed for this rule. The final cost estimates
for the engine program are slightly higher ($142 million) and the
final fuel costs are slightly lower ($246 million), resulting in a
30-year net present value of $27.1 billion (30 year net present
values in the year 2004, using a 3 percent discount rate, $2002) or
$104 million less than the engineering costs used in this analysis.
We do not expect that the revised engineering costs would change the
overall results of this economic impact analysis given the small
portion of engine, equipment, and fuel costs to total production
costs for goods and services using these inputs and given the
inelastic value of the estimated demand elasticities for the
application markets.
---------------------------------------------------------------------------
This section briefly describes the methodology we used to estimate
the economic impacts of this final rule, including the model revisions
for the marine and locomotive fuel sectors, and the results of that
analysis. A detailed description of the Nonroad Diesel Economic Impact
Model (NDEIM) prepared for this analysis, the model inputs, and several
sensitivity analyses can be found in Chapter 10 of Final Regulatory
Impact Analysis prepared for this rule.
1. What Is an Economic Impact Analysis?
An Economic Impact Analysis is prepared to inform decision makers
within the Agency about the potential economic consequences of a
regulatory action. The analysis contains estimates of the social costs
of a regulatory program and explores the distribution of these costs
across stakeholders. These estimated social costs can then be compared
with estimated social benefits (as presented in Section VI.E). As
defined in EPA's Guidelines for Preparing Economic Analyses, social
costs are the value of the goods and services lost by society resulting
from (a) the use of resources to comply with and implement a regulation
and (b) reductions in output. \244\ In this analysis, social costs are
explored in two steps. In the first step, called the market analysis,
we estimate how prices and quantities of good directly and indirectly
affected by the emission control program can be expected to change once
the emission control program goes into effect. The estimated price and
quantity changes for engines, equipment, fuel, and goods produced using
these inputs are examined separately. In the second step, called the
economic welfare analysis, we look at the total social costs associated
with the program and their distribution across stakeholders. The
analysis is based on compliance cost estimates and baseline market
conditions for prices and quantities of engines, equipment, and fuel
produced presented earlier in this section.
---------------------------------------------------------------------------
\244\ EPA Guidelines for Preparing Economic Analyses, EPA 240-R-
00-003, September 2000, p 113.
---------------------------------------------------------------------------
In this EIA, we look at price and quantity impacts for engine,
equipment, diesel fuel, and goods produced with these inputs. With
regard to the goods produced with these inputs, we distinguish between
three application markets: agriculture, construction, and
manufacturing. It should be noted from the outset that diesel engines,
equipment, and fuel represent only a small portion of the total
production costs for each of the three application market sectors (the
final users of the engines, equipment and fuel affected by this rule).
Other more significant production costs include land, labor, other
capital, raw materials, insurance, profits, etc. These other production
costs are not affected by this emission control program. This is
important because it means that this rule directly affects only a small
part of total inputs for the relevant markets. Therefore, the rule is
not expected to have a large adverse impact on output and prices of
goods produced in the three application sectors.
It should also be noted that our analysis of the impacts on the
three application markets is limited to market output. The economic
impacts on particular groups of application market suppliers (e.g., the
profitability of farm production units or manufacturing or construction
firms) or particular groups of consumers (e.g., households and
companies that consume agricultural goods, buildings, or durable or
consumer goods) are not estimated. In other words, while we estimate
that the application markets will bear most of the burden of the
regulatory program and we apportion the decrease in application market
surplus between application market producers and application market
consumers, we do not estimate how those social costs will be shared
among specific application market producers and consumers (e.g.,
farmers and households). In some cases, application market producers
may be able to pass most if not all of their increased costs to the
ultimate consumers of their products; in other cases, they may be
obliged to absorb a portion of these costs. While some commenters
requested that we perform a sector-by-sector analysis of application
market producers and consumers, we do not believe this is appropriate.
The focus on market-level impacts in this analysis is appropriate
because the standards in this emission control program are technical
standards that apply to nonroad engines, equipment, and fuel regardless
of how they are used and the structure of the program does not suggest
that different sectors will be affected differently by the
requirements. In addition, the results of our EIA suggest that the
overall burden on the application market is expected to be small:
approximately 0.1 percent increase in prices, on average, and less than
0.02 percent decrease in production, on average. Estimated economic
impacts of this size do not warrant performing a sector-by-sector
analysis to investigate whether some subsectors may be affected
disproportionately.
Finally, as a market-level model, the NDEIM estimates the economic
impacts of the rule on the engine, equipment, and application markets
and the transportation service sector. It is not a firm-level analysis
and therefore the equipment demand elasticity facing any particular
manufacturer may be greater than the demand elasticity of the market as
a whole. This difference can be important, particularly where the rule
affects different firms' costs over different volumes of production.
However, to the extent there are differential effects, EPA believes
that the wide array of flexibilities provided in this rule are adequate
to address any cost inequities that are likely to arise.
2. What Methodology Did EPA Use in This Economic Impact Analysis?
EPA used the same methodology in this final EIA as was used in the
draft EIA. The model was revised to accommodate analysis of the
locomotive and marine fuel sectors.
a. Conceptual Approach
The Nonroad Diesel Economic Impact Model (NDEIM) uses a multi-market
[[Page 39141]]
analysis framework that considers interactions between regulated
markets and other markets to estimate how compliance costs can be
expected to ripple through these markets. In the NDEIM, compliance
costs are directly borne by engine manufacturers, equipment
manufacturers, petroleum refiners and fuel distributors. Depending on
market characteristics, some or all of these compliance costs will be
passed on through the supply chain in the form of higher input prices
for the application markets (in this case, construction, agriculture,
and manufacturing) which in turn affect prices and quantities of goods
produced in those application markets. Producers in the application
markets adjust their demand for diesel engines, equipment, and fuel in
response to these input price changes and consumer demand for
application market outputs. This information is passed back to the
suppliers of diesel equipment, engines, and fuel in the form of
purchasing decisions. The NDEIM explicitly models these interactions
and estimates behavioral responses that lead to new equilibrium prices
and output for all sectors and the resulting distribution of social
costs across the modeled sectors.
b. Markets Examined
The NDEIM uses a multi-market partial equilibrium approach to track
changes in price and quantity for 62 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
to allow more efficient use of the engine compliance costs estimates.
The additional categories also allow estimating economic impacts for a
more diverse set of markets.
? 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 (15
ppm and 500 ppm) for each of 4 PADDs. PADDs 1 and 3 are combined for
the purpose of this analysis. It should be noted that PADD 5 includes
Alaska and Hawaii. Also, California fuel volumes that are not affected
by the program (because they are covered by separate California nonroad
diesel fuel standards) are not included in the analysis.
? 2 transportation service markets: locomotive and marine.
As noted above, this final EIA also estimates the economic impact
on two additional markets that were not included in the draft analysis:
the locomotive and marine diesel transportation service markets. In the
NPRM, we proposed to set fuel sulfur standards for locomotive and
distillate marine diesel as well as for nonroad diesel fuel. We
developed cost estimates for these two types of fuel as well as for
nonroad diesel fuel. In the draft EIA, however, we did not consider the
economic impacts of these fuel costs on the locomotive and marine
sectors separately. Instead, we applied all of these additional fuel
costs to the manufacturing application market.
In preparing the final RIA for this rule, we determined that it
would be more appropriate to consider the impacts of the fuel program
on the diesel marine and locomotive sectors separately. This is because
the locomotive and marine markets are directly affected by the higher
diesel fuel prices associated with the rule. In addition, production
and consumption decisions of downstream end-use markets that use these
services are influenced by the prices of transportation services. At
the same time, locomotive and marine diesel transportation services are
not used solely in the three application markets modeled in the NDEIM.
These services are also provided to electric utilities (transporting
coal to electric power plants), non-manufacturing service industries
(public transportation) and governments. We take this into account and
report impacts on those sectors separately.
c. Model Methodology
A detailed description of the model methodology, inputs, and
parameters used in this economic impact analysis is provided in Chapter
10 of the Final RIA prepared for this rule. The model methodology is
firmly rooted in applied microeconomic theory and was developed
following the OAQPS Economic Analysis Resource Document.\245\
---------------------------------------------------------------------------
\245\ 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 NDEIM 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. The
model is constructed based on the market characteristics and inter-
connections summarized in this section and described in more detail in
Chapter 10 of the RIA. 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. The output of the model is new equilibrium prices and
quantities for all affected markets. This information is used to
estimate the social costs of the model and how those costs are shared
among affected markets.
The NDEIM uses a multi-market partial equilibrium approach to track
changes in price and quantity for the modeled product markets. As
explained in the EPA Guidelines for Preparing Economic Analyses,
``partial'' equilibrium refers to the fact that the supply and demand
functions are modeled for just one or a few isolated markets and that
conditions in other markets are assumed either to be unaffected by a
policy or unimportant for social cost estimation. Multi-market models
go beyond partial equilibrium analysis by extending the inquiry to more
than just a single market. Multi-market analysis attempts to capture at
least some of the interactions between markets.\246\
---------------------------------------------------------------------------
\246\ EPA Guidelines for Preparing Economic Analyses, EPA 240-R-
00-003, September 2000, p. 125-6.
---------------------------------------------------------------------------
The NDEIM uses an intermediate run time frame. The use of the
intermediate run means that some factors of production are fixed and
some are variable. This modeling period allows analysis of the economic
effects of the rule's compliance costs on current producers. The short
run, in contrast, imposes all compliance costs on the manufacturers (no
pass-through to consumers), while the long run imposes all costs on
consumers (full cost pass-through to consumers). The use of the
intermediate run time frame is consistent with economic practices for
this type of analysis.
The NDEIM assumes perfect competition in the market sectors. This
assumption was questioned by one commenter, who noted that the 25 to 75
hp engine category does not appear to be competitive based on the
number of firms in that subsector. Specifically, one
[[Page 39142]]
firm has nearly 29 percent of the market and the top nine firms have
about 88 percent. The remaining twelve percent of this market shared
among nineteen other firms. While the commenter is correct in noting
the limited number of firms in this subsector, we believe it is still
appropriate to rely on the perfect competition assumption in this
analysis. The perfect competition assumption relies not only on the
number of firms in a market but also on other market characteristics.
For example, there are no indications of barriers to entry, the firms
in these markets are not price setters, and there is no evidence of
high levels of strategic behavior in the price and quantity decisions
of the firms. In addition, the products produced within each market are
somewhat homogeneous in that engines from one firm can be purchased
instead of engines from another firm. Finally, according to contestable
market theory, oligopolies and even monopolies will behave very much
like firms in a competitive market if it is possible to enter
particular markets costlessly (i.e., there are no sunk costs associated
with market entry or exit). With regard to the nonroad engine market,
production capacity is not fully utilized. This means that
manufacturers could potentially switch their product line to compete in
another segment of the market without a significant investment. For all
these reasons, the number of firms in a particular engine submarket
does not prevent us from relying on the perfect competition assumption
for that submarket. This is true of other engine and equipment
subsectors as well. In addition, changing the assumption of perfect
competition based on the limited evidence raised by the commenter would
break with widely accepted economic practice for this type of
analysis.\247\
---------------------------------------------------------------------------
\247\ See, for example, EPA Guidelines for Preparing Economic
Analyses, EPA 240-R-00-003, September 2000, p 126. See also the
Final RIA for this rule, Chapter 10, Section 10.2.3.1.
---------------------------------------------------------------------------
d. Model Inputs--Elasticities
The estimated social costs of this emission control program are a
function of the ways in which producers and consumers of the engines,
equipment, and fuels affected by the standards change their behavior in
response to the costs incurred in complying with the standards. As the
compliance costs ripple through the markets, producers and consumers
change their production and purchasing decisions in response to changes
in prices. In the NDEIM, these behavioral changes are modeled by the
demand and supply elasticities (behavioral-response parameters), which
measure the price sensitivity of consumers and producers.
The supply elasticities for the equipment, engine, diesel fuel, and
transportation service markets and the demand and supply elasticities
for the application markets used in the NDEIM were obtained from peer-
reviewed literature sources or were estimated using econometric
methods. These econometric methods are well-documented and are
consistent with generally accepted econometric practice. Appendix 10H
of the RIA contains detailed information on how the elasticities were
estimated.
The equipment and engine supply elasticities are elastic, meaning
that quantities supplied are expected to be fairly sensitive to price
changes. The supply elasticities for the fuel, transportation, and
application markets are inelastic or unit elastic, meaning that the
quantity supplied/demanded is expected to be fairly insensitive to
price changes or will vary one-to-one with price changes. The demand
elasticities for the application markets are also inelastic. This is
consistent with the Hicks-Allen derived demand relationship, according
to which a low cost-share in production combined with limited
substitution yields inelastic demand.\248\ As noted above, diesel
engines, equipment, and fuel represent only a small portion of the
total production costs for each of the three application sectors. The
limited ability to substitute for these inputs is discussed below.
---------------------------------------------------------------------------
\248\ If the elasticity of demand for a final product is less
than the elasticity of substitution between an input and other
inputs to the final product, then the demand for the input is less
elastic the smaller its cost share. Hicks, J.R., 1961. Marshall's
Third Rule: A Further Comment. Oxford Economic Papers 13:262-65;
Hicks, J.R., 1963. The Theory of Wages. St. Martins Press, NY, pp.
233-247. See Docket A-2001-28, Document No. IV-B-25 for relevant
excerpts. See Docket A-2001-28, Document No. IV-B-25 for relevant excerpts.
---------------------------------------------------------------------------
In contrast to the above, the demand elasticities for the engine,
equipment, fuel, and transportation markets are internally derived as
part of the process of running the model. This is an important feature
of the NDEIM, which allows it to link the separate market components of
the model and simulate how compliance costs can be expected to ripple
through the affected economic sectors. In the real world, for example,
the quantity of nonroad equipment units produced in a particular period
depends on the price of engines (the engine market) and the demand for
equipment (the application markets). Similarly, the number of engines
produced depends on the demand for engines (the equipment market) which
depends on the demand for equipment (the application markets). Changes
in conditions in one of these markets will affect the others. By
designing the model to derive the engine, equipment, transportation
market, and fuel demand elasticities, the NDEIM simulates these
connections between supply and demand among all the product markets and
replicates the economic interactions between producers and consumers.
e. Model Inputs--Fixed and Variable Costs
The EIA treats the fixed costs expected to be incurred by engine
and equipment manufacturers differently in the market and social costs
analyses. This feature of the model is described in greater detail in
Section 10.2.3.3 of the RIA. In the market analysis, estimated engine
and equipment market impacts (changes in prices and quantities) are
based solely on the expected increase in variable costs associated with
the standards. Fixed costs are not included in the market analysis
reported in Table VI-F-1 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, the fixed costs associated with the rule are primarily R&D
costs for design and engineering changes. Firms in the affected
industries currently allocate funds for R&D programs and this rule is
not expected to lead firms to change the size of their R&D budgets.
Therefore, changes in fixed costs for engine and equipment redesign
associated with this rule are not likely to affect the prices of
engines or equipment. Fixed costs are included in the social cost
analysis reported in Table VI-F-2, however, as an additional cost to
producers. This is appropriate because even though firms currently
allocated funds to R&D those resources are intended for other purposes
such as increasing engine power, ease of use, or comfort. These
improvements will therefore be postponed for the length of the rule-
related R&D program. This is a cost to society.
One commenter recommended that EPA include engine and equipment R&D
(fixed) costs in the market analysis. This commenter argued that while
in the long run total costs are not determined by changes in fixed
costs, total costs are determined initially by both fixed and variable
costs. This commenter was concerned that by not including fixed costs,
EPA's analysis underestimates the increase in the average price of
goods and services produced using engines affected by the rule. In
fact, we included
[[Page 39143]]
R&D costs in a sensitivity analysis performed for the draft EIA, which
has been updated and can be found in Appendix I to Chapter 10 of the
Final RIA. Including fixed costs results in a transfer of economic
welfare losses from engine and equipment markets to the application
markets (engine and equipment producer surplus losses decrease;
consumer surplus losses increase), but does not change the overall
economic welfare losses associated with the rule.
Unlike for engines and equipment, most of the petroleum refinery
fixed costs are for production hardware. Refiners are expected to have
to make physical changes to their refineries and purchase additional
equipment to produce 500 ppm and then 15 ppm fuel. Therefore, fixed
costs are included in the market analysis for fuel price and quantity
impacts.
f. Model Inputs--Substitution by Application Suppliers
In modeling the market impacts and social costs of this rule, the
NDEIM considers only diesel equipment and fuel inputs to the production
of goods in the applications markets. It does not explicitly model
alternate production inputs that would serve as substitutes for new
nonroad equipment or nonroad diesel fuel. In the model, market changes
in the final demand for application goods and services directly
correspond to changes in the demand for nonroad equipment and fuel
(i.e., in normalized terms there is a one-to-one correspondence between
the quantity of the final goods produced and the quantity of nonroad
diesel equipment and fuel used as inputs to that production). We
believe modeling the market in this manner is economically sound and
reflects the general experience for the nonroad market.
Some commenters suggested that the NDEIM should consider
substitution to alternate means of production such as pre-buying,
delayed buying, extending the life of a current machine, and
substituting with different (e.g., gasoline-powered) equipment. These
commenters did not provide detailed explanations for their comments or
data in support of their substitution arguments. After considering
these comments, we conclude that revising the NDEIM to include these
effects would be inappropriate.
The term ``pre-buying'' appears to refer to the possibility that
the suppliers in the application market may choose to buy additional
unneeded quantities of nonroad equipment prior to the beginning of the
Tier 4 program, thus avoiding the higher cost for the Tier 4 equipment.
It should be noted that this effect is limited to equipment and does
not extend to nonroad diesel fuel. We believe that equipment pre-buying
will not be economically viable in most cases due to the cost of
holding capital (equipment) idle and of maintaining unused equipment.
Such strategic purchases, if they occur at all, would be limited to a
period of a few months before the effective date of the standards. The
NDEIM models market reactions in the intermediate time frame, beyond
the scope of any potential pre-buy. For these reasons, we do not
believe it is appropriate to revise the model to include pre-buy as a
means of substitution in NDEIM.
``Delayed-buying'' appears to refer to the possibility that
suppliers in the application market would defer purchasing new
equipment initially but would eventually make those purchases.
Similarly to pre-buying, this appears to be a short-term effect and
would therefore be inappropriate to include in an economic model
designed to model the intermediate time frame.
Extending the life of a current machine is suggested as another
alternative to purchasing new equipment. We believe this would also be
a short term phenomena that is not relevant for the intermediate time
frame of the NDEIM. Based on our meetings with equipment users and
suppliers, we do not believe that extending the life of nonroad
equipment will prove to be an economically viable substitute in the
near or long term. Most users of nonroad equipment already extend the
life of their equipment to the maximum extent possible and purchase new
equipment only when the existing equipment can no longer perform its
function, when new demand for production requires additional means for
production, or when new equipment offers a cheaper means of production
than existing equipment. This situation is not expected to change as a
result of this rule. In addition, even if it were possible to extend
equipment life even more, this would lower the cost of nonroad
equipment as an input to production (because it would be less expensive
to maintain old equipment than purchase new equipment) and thus would
reduce the economic impact of the Tier 4 program compared to our
estimate. For all of the reasons stated here, we have decided not to
attempt to model an extended equipment life alternative in the NDEIM.
Finally, some commenters noted that equipment users may chose to
substitute with different equipment, particularly gasoline-powered
equipment. We believe substitution to gasoline-powered equipment is an
alternative only for the smaller power categories (below 75 hp). Based
on discussions with equipment manufacturers and users, the dominant
reasons for choosing diesel engines over the substantially less
expensive gasoline engines include better performance from diesel
engines, lower fuel consumption from diesel engines, and the ability to
use diesel fuel. The use of diesel fuel is preferable for two reasons:
it is safer to store and dispense, and it is compatible with the fuel
needed for larger equipment at the same worksite. Where these issues
are not a concern, gasoline engines already enjoy a substantial
economic advantage over diesel. We do not believe that the incremental
increase in new equipment cost associated with this program would
provide the necessary economic incentives for switching to gasoline
equipment. Equipment users who can use gasoline-fueled equipment
already do so, while those who can't due to the high costs of storing
and dispensing gasoline fuel already use diesel engines. Therefore, we
have not attempted to model the possibility of substitution to gasoline
equipment in NDEIM.
g. Model Inputs--Other
Compliance Costs. The NDEIM uses the estimated engine, equipment,
and fuel compliance costs described in above and presented in Chapters
6 and 7 of the RIA. Engine and equipment costs vary over time because
fixed costs are recovered over five to ten year periods while total
variable costs, despite learning effects that serve to reduce costs on
a per unit basis, continue to increase at a rate consistent with new
sales increases. Similarly, engine operating costs also vary over time
because oil change maintenance savings, PM filter maintenance, and fuel
economy effects, all of which are calculated on the basis of gallons of
fuel consumed, change over time consistent with the growth in
nationwide fuel consumption. Fuel-related compliance costs (costs for
refining and distributing regulated fuels) also change over time. These
changes are more subtle than the engine costs, however, as the fuel
provisions are largely implemented in discrete steps instead of phasing
in over time. Compliance costs were developed on a [cent]/gallon basis;
total compliance costs are determined by multiplying the [cent]/gallon
costs by the relevant fuel volumes. Therefore, total fuel costs
increase as the demand for fuel increases. The variable operating costs
are based on the natural gas cost of producing hydrogen and for heating
diesel fuel for the new desulfurization
[[Page 39144]]
equipment, and thus would fluctuate along with the price of natural gas.
Operating Savings. Operating savings 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, marine
and locomotive engines that are already in use as well as new nonroad
engines that will comply with the standards (see Section VI.B). These
also include any extra operating costs associated with the new PM
emission control technology which may accrue to certain new engines
that use this technology. Operating savings are not included in the
market analysis because some of the savings accrue to existing engines
and because, as explained in Section VI.C.1.c, these savings are not
expected to affect consumer decisions with respect to new engines.
Operating savings are included in the social cost analysis, however,
because they accrue to society. They are added into the estimated
social costs as an additional savings to the application and
transportation service markets, since it is the users of these engines
and fuels who will see these savings. A sensitivity analysis was
performed as part of this EIA that includes the operating savings in
the market analysis. The results of this sensitivity analysis are
presented in Appendix 10.I.
Fuel Marker Costs. Fuel marker costs refers to costs associated
with marking high sulfur heating oil to distinguish it from high sulfur
diesel fuel produced after 2007 through the use of early sulfur credits
or small refiner provisions. Only heating oil sold outside of the
Northeast is affected. The higher sulfur NRLM fuel is not allowed to be
sold in most of the Northeast, so the marker need not be added in this
large heating oil market. These costs are expected to be about $810,000
in 2007, increasing to $1.38 million in 2008, but steadily decreasing
thereafter to about $940,000 in 2040 (see Chapter 10 of the RIA).
Because these costs are relatively small, they are incorporated into
the estimated compliance costs for the fuel program (see discussion of
fuel costs, above). They are therefore not counted separately in this
economic impact analysis. This means that the costs of marking heating
fuel are allocated to all users of the fuel affected by this rule
(nonroad, locomotive, and marine) instead of uniquely to heating oil
users. This is a reasonable approach since it is likely that refiners
will pass the marker costs along their complete nonroad diesel product
line and not just to heating oil.
Fuel Spillover. Spillover fuel is highway grade diesel fuel
consumed by nonroad equipment, stationary diesel engines, boilers, and
furnaces. As described in Section 7.1 of Chapter 7 of the final RIA,
refiners are expected to produce more 15 ppm fuel than is required for
the highway diesel market. This excess 15 ppm fuel will be sold into
markets that allow fuel with a higher sulfur level (i.e., nonroad for a
limited period of time, locomotive, marine diesel and heating oil).
This spillover fuel is affected by the diesel highway rule and is not
affected by this regulation. Therefore, it is important to
differentiate between spillover and nonspillover fuel to ensure that
the compliance costs for that fuel pool are not counted twice. In the
NDEIM, this is done by incorporating the impact of increased fuel costs
associated with the highway rule prior to analysis of the final nonroad
rule (see RIA Section 10.3.8).
Compliance Flexibility Provisions. Consistent with the engine and
equipment cost discussion in Section VI.C, the EIA does not include any
cost savings associated with the equipment transition flexibility
program or the nonroad engine ABT program. As a result, the results of
this EIA can be viewed as somewhat conservative.
Locomotive and Marine Fuel Costs. The locomotive and marine
transportation sectors are affected by this rule through the sulfur
limits on the diesel fuel used by these engines. These sectors provide
transportation to the three application markets as well as to other
markets not considered in the NDEIM (e.g., public utilities,
nonmanufacturing service industries, government). As explained in
Section 10.3.1.5 of the RIA, the NDEIM applies only a portion of the
locomotive and marine fuel costs to the three application markets. The
rest of the locomotive and marine fuel costs are added as a separate
item to the total social cost estimates (as Application Markets Not
Included in NDEIM).
3. What Are the Results of this Analysis?
Using the revised cost data described earlier in this section and
the NDEIM described above and in Chapter 10 of the Final RIA, we
estimated the economic impacts of the nonroad engine, equipment and
fuel control program. Economic impact results for 2013, 2020, 2030, and
2036 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 VI-F-3, 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, 2030 and 2036, correspond to years
analyzed in our benefits analysis. Detailed results for all years are
included in the appendices to Chapter 10 of the RIA.
In the following discussion, social costs are computed as the sum
of market surplus offset by operating savings. Market surplus is equal
to the aggregate change in consumer and producer surplus based on the
estimated market impacts associated with the rule. As explained above,
operating savings are not included in the market analysis but instead
are listed as a separate category in the social cost results tables.
In considering the results of this analysis, it should be noted
that the estimated output quantities for diesel engines, equipment, and
fuel are not identical to those estimated in the engineering cost
described in above and presented in Chapters 6 and 7 of the RIA. The
difference is due to the different methodologies used to estimate these
costs. As noted above, social costs are the value of goods and services
lost by society resulting from: (a) the use of resources to comply with
and implement a regulation (i.e., compliance costs); and (b) reductions
in output. Thus, the social cost analysis considers both price and
output (quantity) effects associated with consumer and producer
reaction to increased prices associated with the regulatory compliance
costs. The engineering cost analysis, on the other hand, is based on
applying additional technology to comply with the new regulations. The
engine population in the engineering cost analysis does not reflect
consumer and producer reactions to the compliance costs. Consequently,
the estimated output quantities from the cost analysis are slightly
larger than the estimated output quantities from the social cost analysis.
The results of this analysis suggest that the economic impacts of
this rule are likely to be small, on average. Price increases in the
application markets are expected to average about 0.1 percent per year.
Output decrease in the application markets are expected to average less
than 0.02 percent for all years. The price increases for engines,
equipment, and fuel are expected to be about 20 percent, 3 percent, and
7 percent, respectively (total impact averaged over the relevant
years). The number of engines and equipment produced is expected to
decrease by less
[[Page 39145]]
than 250 units, and the amount of fuel produced annually is expected to
decrease by less than 4 million gallons. With respect to the economic
welfare analysis, producers and consumers in the application markets
are expected to bear about 83 percent of the burden in 2013; this will
increase to about 96 percent in 2030 and beyond. In other words,
despite the almost total pass-through of costs the average price of
goods and services in the application markets is expected to increase
by only 0.1 percent. This outcome reflects the fact that diesel
engines, equipment, and fuel are only a small part of total costs for
the application markets. These results are described in more detail
below and in Chapter 10 of the Final RIA.
a. Expected Market Impacts
The estimated market impacts for 2013, 2020, and 2030 are presented
in Table VI.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
seven different horsepower size categories. The 21.4 percent price
change for engines shown in Table VI.F-1 for 2013 is an average price
change across all engine markets weighted by the number of production
units. Similarly, the equipment impacts presented in Table VI.F-1 are
the weighted averages of 42 equipment-application markets, such as
small (<25hp) agricultural equipment and large (>600hp) industrial
equipment. Note that price increases and quantity decreases for
specific types of engines, equipment, application sectors, or diesel
fuel markets are likely to be different. The aggregated data presented
in this table provide a broad overview of the expected market impacts
that is useful when considering the impacts of the rule on the economy
as a whole. The individual market-level impacts are presented in
Chapter 10 of the Final RIA.\249\
---------------------------------------------------------------------------
\249\ The NDEIM distinguishes between ``merchant'' engines and
``captive'' engines. ``Merchant'' engines are produced for sale to
another company and are sold on the open market to anyone who wants
to buy them. ``Captive'' engines are produced by a manufacturer for
use in its own nonroad equipment line (this equipment is said to be
produced by ``integrated'' manufacturers). The market analysis for
engines includes compliance costs for merchant engines only. The
market analysis for equipment includes equipment compliance costs
plus a portion of the engine compliance costs attributable to
captive engines.
---------------------------------------------------------------------------
The market impacts of this rule suggest that the overall economic
impact of the 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
rule are expected to increase by about 0.1 percent (as noted above),
despite the almost total pass-through of compliance costs to those
markets.
Engine Market Results: This analysis suggests that most of the
variable costs associated with the rule will be passed along in the
form of higher prices. The average price increase in 2013 for engines
is estimated to be about 21.4 percent. This percentage is expected to
decrease to about 18.3 percent by 2020. In 2036, the last year
considered, the average price increase is expected to be about 18.2
percent. 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 largest expected percent price increase
is for engines between 25 and 50 hp: 29 percent or $850; the average
price for an engine in this category is about $2,900. However, this
price increase is expected to drop to 22 percent, or about $645, for
2015 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 7.6 percent in 2015 and then decreasing to about
6.6 percent in 2017 beyond. The expected price increase for these
engines is about $2,240 in 2013, increasing to about $6,150 in 2015 and
then decreasing to $5,340 in 2017 and later, for engines that cost on
average about $80,500.
The market impact analysis predicts that even with these increased
in engine prices, total demand is not expected to change very much. The
expected average change in quantity is less than 150 engines per year,
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).
Equipment Market Results: Estimated price changes for the equipment
markets reflect both the direct costs of the new standards on equipment
production and the indirect cost through increased engine prices. In
general, the estimated percentage price changes for the equipment are
less than that for engines because the engine is only one input in the
production of equipment. In 2013, the average price increase for
nonroad diesel equipment is estimated to be about 2.9 percent.\250\
This percentage is expected to decrease to about 2.5 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. For example, the market price in 2013 for agricultural
equipment between 175 and 600 hp is estimated to increase about 1.2
percent, or $1,740 for equipment with an average cost of $143,700. This
compares with an estimated engine price increase of about $1,700 for
engines of that size. The largest expected price increase in 2013 for
equipment is $2,290, or 2.6 percent, for pumps and compressors over 600
hp. This compares with an estimated engine price increase of about
$2,240 for engines of that size. The smallest expected price increase
in 2013 for equipment is $120, or 0.7 percent, for construction
equipment less than 25 hp. This compares with an estimated engine price
increase of about $120 for engines of that size.
---------------------------------------------------------------------------
\250\ It should be noted that the equipment prices used in this
analysis reflect current market conditions. An increase in equipment
prices associated with the nonroad Tier 3 standards would reduce
size of the percentage increase in price. In this sense, our
Economic Impact Analysis is conservative as it is based on the
impact of the Tier 4 program on Tier 1 and Tier 2 equipment prices
and therefore overestimates the market impacts of the Tier 4 program.
---------------------------------------------------------------------------
Again, the market analysis predicts that even with these increased
equipment prices total demand is not expected to change very much. The
expected average change in quantity is less than 250 pieces of
equipment per year, out of a total sales of more than 500,000 units.
The average decrease in the quantity of nonroad diesel equipment
produced as a result of the regulation is estimated to be about 0.02
percent for all years. The largest expected decrease in quantity in
2013 is 18 units of construction equipment per year for construction
equipment between 100 and 175 hp, out of about 63,000 units. The
smallest expected decrease in quantity in 2013 is less than
[[Page 39146]]
one unit per year in all hp categories of pumps and compressors.
It should be noted that the absolute change in the number of
engines and equipment does not match. This is because 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.
Table VI.F-1.--Summary of Market Impacts ($2002)
----------------------------------------------------------------------------------------------------------------
Engineering Change in price Change in quantity
cost ---------------------------------------------------
Market ------------- Absolute
Per unit ($million) Percent Absolute Percent
----------------------------------------------------------------------------------------------------------------
2013
----------------------------------------------------------------------------------------------------------------
Engines........................................ $1,052 $821 21.4 \a\ -79 -0.014
Equipment...................................... 1,198 975 2.9 -139 -0.017
Loco/Marine Transp \b\......................... ........... ........... 0.009 ........... -0.007
Application Markets \b\........................ ........... ........... 0.097 ........... -0.015
No. 2 Distillate Nonroad....................... 0.06 0.07 6.0 \c\ -2.75 -0.019
------------------------------------------------
2020
----------------------------------------------------------------------------------------------------------------
Engines........................................ 950 761 18.3 \a\ -98 -0.016
Equipment...................................... 1,107 976 2.5 -172 -0.018
Loco/Marine Transp \b\......................... ........... ........... 0.001 ........... -0.008
Application Markets \b\........................ ........... ........... 0.105 ........... -0.017
No. 2 Distillate Nonroad....................... 0.07 0.07 7.0 \c\ -3.00 -0.021
------------------------------------------------
2030
----------------------------------------------------------------------------------------------------------------
Engines........................................ 937 751 18.2 \a\ -114 -0.016
Equipment...................................... 968 963 2.5 -200 -0.018
Loco/Marine Transp \b\......................... ........... ........... 0.010 ........... -0.008
Application Markets \b\........................ ........... ........... 0.102 ........... -0.016
No. 2 Distillate Nonroad....................... 0.07 0.07 7.0 \c\ -3.53 -0.022
------------------------------------------------
2036
----------------------------------------------------------------------------------------------------------------
Engines........................................ 931 746 18.2 \a\ -124 -0.016
Equipment...................................... 962 956 2.5 -216 -0.018
Loco/Marine Transp \b\......................... ........... ........... 0.010 ........... -0.008
Application Markets \b\........................ ........... ........... 0.101 ........... -0.016
No. 2 Distillate Nonroad....................... 0.07 0.07 7.0 \c\ -3.85 -0.022
----------------------------------------------------------------------------------------------------------------
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.
Transportation Market Results: The estimated price increase
associated with the proposed standards in the locomotive and marine
transportation markets is negligible, at 0.01 percent for all years.
This means that these transportation service providers are expected to
pass along nearly all of their increased costs to the agriculture,
construction, and manufacturing application markets, as well as other
application markets not explicitly modeled in the NDEIM. This price
increases represent a small share of total application market
production costs, and therefore are not expected to affect demand for
these services.
Application Market Results: The estimated price increase associated
with the new standards in all three application markets is very small
and averages about 0.1 percent for all years. In other words, on
average, the prices of goods and services produced using the affected
engines, equipment, and fuel are expected to increase negligibly. This
results from the observation that compliance costs passed on through
price increases represent a very small share of total production costs
in all the application markets. For example, the construction industry
realizes an increase in production costs of approximately $580 million
in 2013 because of the price increases for diesel equipment and fuel.
However, this represents less than 0.001 percent of the $820 billion
value of shipments in the construction industry in 2000. The estimated
average commodity price increase in 2013 ranges from 0.08 percent in
the manufacturing application market to about 0.5 percent in the
construction market. The percentage change in output is also estimated
to be very small and averages less than 0.02 percent for all years.
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 VI.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.
[[Page 39147]]
Fuel Markets Results: The estimated average price increase across
all nonroad diesel fuel is about 7 percent for all years. For 15 ppm
fuel, the estimated price increase for 2013 ranges from 5.6 percent in
the East Coast region (PADD 1&3) to 9.1 percent in the mountain region
(PADD 4). The average national output decrease for all fuel is
estimated to be about 0.02 percent for all years, and is relatively
constant across all four regional fuel markets.
b. Expected Economic Welfare Impacts
Estimated social costs are presented in Table VI.F-2. In 2013, the
total social costs are projected to be about $1,510 million ($2002).
About 83 percent of the total social costs is expected to be borne by
producers and consumers in the application markets in 2013, indicating
that the majority of the compliance costs associated with the rule are
expected to be passed on in the form of higher prices. When these
estimated impacts are broken down, about 58.5 percent of the social
costs are expected to be borne by consumers in the application markets
and about 41.5 percent are expected to be borne by producers in the
application markets. Equipment manufacturers are expected to bear about
9.5 percent of the total social costs. Engine manufacturers and diesel
fuel refineries are expected to bear 2.8 percent and 0.5 percent,
respectively. The remaining 4.2 percent of the social costs is expected
to be borne by the locomotive and marine transportation service sector.
In this last sector, about 97 percent of the gross decrease in market
surplus is expected to be borne by the application markets that are not
included in the NDEIM but that use these services (e.g., public
utilities, nonmanufacturing service industries, government) while about
3 percent is expected to be borne by locomotive and marine service
providers. Because of the way the NDEIM is structured, with the fuel
savings added separately, the results imply that locomotive and marine
service provider would see net benefits from the rule due to the
operating savings associated with low sulfur fuel. In fact, they are
likely to pass along some or all of those operating savings to the
users of their services, reducing the size of the welfare losses for
those users.
Total social costs continue to increase over time and are projected
to be about $2,046 million by 2030 and $2,227 million in 2036 ($2002).
The increase is due to the projected annual growth in the engine and
equipment populations. Producers and consumers in the application
markets are expected to bear an even larger portion of the costs,
approximately 96 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 2036, contained in
Table VI.F-3, is estimated to be $27.2 billion ($2002). This present
value is calculated using a social discount rate of 3 percent from 2004
through 2036. We also performed an analysis using a 7 percent social
discount rate. Using that discount rate, the present value of the
social costs through 2036 is estimated to be $13.9 billion ($2002). As
shown in Table VI.F-3, these results suggest that total engineering
costs exceed compliance costs by a small amount. This is due primarily
to the fact that the estimated output quantities for diesel engines,
equipment, and fuel are not identical to those estimated in the
engineering cost analysis, which is due to the different methodologies
used to estimate these costs (see previous discussion in this Section
IV.F.3).
Table VI.F-2.--Summary of Social Costs Estimates Associated With Primary Program 2015, 2020, 2030, and 2036
[2002, $Million]a, b
----------------------------------------------------------------------------------------------------------------
Market Operating
surplus savings Total Percent
($10 \6\) ($10 \6\)
----------------------------------------------------------------------------------------------------------------
2013
----------------------------------------------------------------------------------------------------------------
Engine Producers Total...................................... $42.0 ........... $42.0 2.8
Equipment Producers Total................................... 143.1 ........... 143.1 9.5
Construction Equipment.................................. 64.0 ........... 64.0 ...........
Agricultural Equipment.................................. 51.8 ........... 51.8 ...........
Industrial Equipment.................................... 27.2 ........... 27.2 ...........
Application Producers & Consumers Total..................... 1,496.7 ($243.2) 1,253.5 83.0
Total Producer.......................................... 620.9 ........... ........... 41.5
Total Consumer.......................................... 875.7 ........... ........... 58.5
Construction............................................ 584.3 ($115.2) 469.2 ...........
Agriculture............................................. 430.0 ($78.2) 351.8
Manufacturing........................................... 482.4 ($49.8) 432.5 ...........
Fuel Producers Total........................................ 8.0 ........... 8.0 0.5
PADD I&III.............................................. 4.1 ........... 4.1 ...........
PADD II................................................. 3.3 ........... 3.3 ...........
PADD IV................................................. 0.0 ........... 0.0 ...........
PADD V.................................................. 0.6 ........... 6.0 ...........
Transportation Services, Total.............................. 104.9 ($41.5) 63.4 4.2
Locomotive.............................................. 1.6 ($12.4) ($10.8) ...........
Marine.................................................. 0.9 ($9.9) ($9.0) ...........
Application markets not included in NDEIM............... 102.4 ($19.2) $83.2 ...........
--------------
Total............................................... 1,794.7 ($284.7) $1,510.0 100.0%
=============================================================
2020
----------------------------------------------------------------------------------------------------------------
Engine Producers Total...................................... 0.1 ........... 0.1 0.0
Equipment Producers Total................................... 122.7 ........... 122.7 6.7
Construction Equipment.................................. 57.8 ........... 57.8 ...........
Agricultural Equipment.................................. 39.7 ........... 39.7 ...........
[[Page 39148]]
Industrial Equipment.................................... 25.2 ........... 25.2 ...........
Application Producers & Consumers Total..................... 1,826.1 ($192.3) 1,633.8 89.4
Total Producer.......................................... 762.2 ........... ........... 41.7
Total Consumer.......................................... 1,063.8 ........... ........... 58.3
Construction............................................ 744.0 ($91.1) 653.0 ...........
Agriculture............................................. 524.3 ($61.8) 462.5 ...........
Manufacturing........................................... 557.8 ($39.4) 518.3 ...........
Fuel Producers Total........................................ 11.2 ........... 11.2 0.6
PADD I&III.............................................. 5.6 ........... 5.6 ...........
PADD II................................................. 4.6 ........... 4.6 ...........
PADD IV................................................. 0.2 ........... 0.2 ...........
PADD V.................................................. 0.8 ........... 0.8
Transportation Services, Total.............................. 95.7 ($35.1) 60.6 3.3
Locomotive.............................................. 2.0 ($7.2) ($5.2) ...........
Marine.................................................. 1.1 ($11.6) ($10.5) ...........
Application markets not included in NDEIM............... 92.6 ($16.3) 76.3 ...........
--------------
Total............................................... 2,055.7 ($227.4) $1,828.3 100.0%
=============================================================
2030
----------------------------------------------------------------------------------------------------------------
Engine Producers Total...................................... 0.1 ........... 0.1 0.0
Equipment Producers Total................................... 5.9 ........... 5.9 0.3
Construction Equipment.................................. 4.0 ........... 4.0 ...........
Agricultural Equipment.................................. 1.9 ........... 1.9 ...........
Industrial Equipment.................................... 0.1 ........... 0.1 ...........
Application Producers & Consumers Total..................... 2,112.3 ($154.2) 1,958.1 95.7
Total Producer.......................................... 882.2 ........... ........... 41.7
Total Consumer.......................................... 1,230.1 ........... ........... 58.3
Construction............................................ 863.8 ($73.0) 790.8 ...........
Agriculture............................................. 606.8 ($49.6) 557.2 ...........
Manufacturing........................................... 641.6 ($31.6) 610.0 ...........
Fuel Producers Total........................................ 13.2 ........... 13.2 0.6
PADD I&III.............................................. 6.7 ........... 6.7 ...........
PADD II................................................. 5.2 ........... 5.2 ...........
PADD IV................................................. 0.3 ........... 0.3 ...........
PADD V.................................................. 1.0 ........... 1.0 ...........
Transportation Services, Total.............................. 109.1 ($39.9) 69.2 3.4
Locomotive.............................................. 2.5 ($7.8) ($5.3) ...........
Marine.................................................. 1.4 ($13.6) ($12.2) ...........
Application markets not included in NDEIM............... 105.2 ($18.5) 86.7 ...........
--------------
Total............................................... 2,240.6 ($194.1) $2,046.4 100.0%
=============================================================
2036
----------------------------------------------------------------------------------------------------------------
Engine Producers Total...................................... 0.2 ........... 0.2 0.0
Equipment Producers Total................................... 6.4 ........... 6.4 0.3
Construction Equipment.................................. 4.3 ........... 4.3 ...........
Agricultural Equipment.................................. 2.0 ........... 2.0 ...........
Industrial Equipment.................................... 0.1 ........... 0.1 ...........
Application Producers & Consumers Total..................... 2,287.4 ($155.7) 2,131.7 95.7
Total Producer.......................................... 955.5 ........... ........... 41.7
Total Consumer.......................................... 1,331.9 ........... ........... 58.3
Construction............................................ 936.4 ($50.0) 862.7 ...........
Agriculture............................................. 657.8 ($73.7) 607.8 ...........
Manufacturing........................................... 693.2 ($31.9) 661.3 ...........
Fuel Producers Total........................................ 14.5 ........... 14.5 0.7
PADD I&III.............................................. 7.3 ........... 7.3 ...........
PADD II................................................. 5.8 ........... 5.8 ...........
PADD IV................................................. 0.3 ........... 0.3 ...........
PADD V.................................................. 1.0 ........... 1.0 ...........
Transportation Services, Total.............................. 116.9 ($42.6) 74.3 3.3
Locomotive.............................................. 2.8 ($8.2) ($5.4) ...........
Marine.................................................. 1.6 ($14.6) ($13.0) ...........
Application markets not included in NDEIM............... 112.5 ($19.8) 92.7 ...........
--------------
[[Page 39149]]
Total............................................... $2,425.3 ($198.4) $2,227.0 100.0
----------------------------------------------------------------------------------------------------------------
Notes: a Figures are in 2002 dollars.
b Operating savings are shown as negative costs.
Table VI.F-3.--National Engineering Compliance Costs and Social Costs
Estimates for the Rule (2004-2036)
[$2002; $Million]
------------------------------------------------------------------------
Engineering compliance
Year costs Total social costs
------------------------------------------------------------------------
2004 0 0
2005 0 0
2006 0 0
2007 ($17) ($18)
2008 54 54
2009 54 54
2010 328 327
2011 923 922
2012 1,305 1,304
2013 1,511 1,510
2014 1,691 1,690
2015 1,742 1,741
2016 1,743 1,743
2017 1,763 1,762
2018 1,778 1,778
2019 1,795 1,795
2020 1,829 1,828
2021 1,816 1,815
2022 1,819 1,818
2023 1,844 1,843
2024 1,858 1,857
2025 1,888 1,887
2026 1,921 1,920
2027 1,954 1,952
2028 1,985 1,984
2029 2,017 2,016
2030 2,047 2,046
2031 2,078 2,077
2032 2,108 2,107
2033 2,139 2,137
2034 2,169 2,167
2035 2,198 2,197
2036 2,228 2,227
NPV at 3% 27,247 27,232
NPV at 7% 13,876 13,868
------------------------------------------------------------------------
VII. Alternative Program Options Considered
Our final emission control program for nonroad engines and
equipment consists of a two-step program to reduce the sulfur content
of nonroad diesel fuel in conjunction with Tier 4 engine standards. The
rule also contains limits on sulfur levels in locomotive and marine
diesel fuel. As described in the draft Regulatory Impact Analysis for
the 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 those alternative program options and our reasons for
either adopting or not adopting these options.
A. Summary of Alternatives
For our Notice of Proposed Rulemaking (NPRM), we developed
emissions, benefits, and cost analyses for a number of alternative
program options involving variations in both the fuel and engine
programs. The alternatives we considered can be categorized according
to the structure of their fuel requirements: whether the 15 ppm fuel
sulfur limit for nonroad diesel fuel is reached in two steps, like the
program we are finalizing today, or in one step. Within each of these
two broad fuel program categories, we considered a number of different
engine programs. This section summarizes the alternatives. A more
detailed description of the alternatives can be found in the NPRM and
the draft RIA.
One-step alternatives were those in which the 15 ppm fuel sulfur
standard for nonroad diesel fuel is applied in a single step. We
evaluated three one-step alternatives, summarized in table VII-1.
Option 1 represented an engine program that was similar to that in our
proposed program, the primary difference being the generally earlier
phase-in dates for the PM standards. We considered the Option 1 engine
program as being the most stringent one-step program that could be
considered even potentially feasible considering cost, lead-time, and
other factors. Option 1 also included a June 2008 start date for the 15
ppm sulfur standard applicable to nonroad diesel fuel and the 500 ppm
sulfur standard applicable to locomotive and marine fuel. We also
considered two other one-step alternatives which differ from Option 1.
As described in table VII-1, Option 1b differed from Option 1 regarding
the timing of the fuel standards, while Option 1a differed from Option
1 in terms of the engine standards. Options 1a and 1b also differed
from Option 1 by extending the 15 ppm fuel sulfur limit to locomotive
and marine diesel fuel.
Two-step alternatives were those in which the nonroad diesel fuel
sulfur standard was set first at 500 ppm and then was reduced to 15
ppm. The two-step alternatives varied from the proposed program in
terms of both the timing and levels of the engine standards and the
timing of the fuel standards. Option 2a was the same as the proposed
program except the 500 ppm fuel standard was introduced a year earlier,
in 2006. Option 2b was the same as the proposed program except the 15
ppm fuel standard was introduced a year earlier (in 2009) and the trap-
based PM standards began earlier for all engines. Option 2c was the
same as the proposed program except the 15 ppm fuel standard was
introduced a year earlier in 2009 and the trap-based PM standards began
earlier for engines 175-750 hp. Option 2d was the same as the proposed
program except the NOX standard was reduced to 0.30 g/bhp-hr
for engines of 25-75 hp, and this standard was phased in. Finally,
Option 2e was the same as the proposed program except there were no new
Tier 4 NOX limits.
In the NPRM, option 3 was identical to the proposed program, except
that it would have exempted mining equipment over 750 hp from the Tier
4 standards. We explained in detail in section 12.6.2.2.7 of the draft
RIA that we had very serious reservations regarding the legality of
this option given these engines' high emission rates of PM,
NOX and NMHC and the availability of further emissions
control at reasonable cost. We adhere to these conclusions here. We do
note, however, that we are adopting somewhat different provisions for
this engine category than we proposed. As explained in sections II.A.
and II.B above, although we have adopted aftertreatment-based PM
standards for these engines, the standards are slightly higher than
those proposed to assure their technical feasibility. We also have
deferred a decision on whether to adopt aftertreatment-based standards
for NOX for mobile machines with engines greater than 750
hp. We also have provided ample lead time for these engines to comply
with the Tier 4 standards, both in terms of the rule's compliance dates
(which include a 2015
[[Page 39150]]
date for the final Tier 4 standards, one year later than we proposed)
and the ABT and equipment manufacturer flexibilities. This lead time
takes into account the long design periods, high cost, and low sales
volumes of these engines. Thus, although we strongly disagree with the
option of not adopting Tier 4 standards for these engines, we do
recognize their need for unique standards and compliance dates.
Option 4 included applying the 15 ppm sulfur limit to both
locomotive and marine diesel fuel in addition to nonroad fuel. On the
basis of comments received and additional analyses, we have determined
that a 15ppm sulfur standard for locomotive and marine fuel is
appropriate, though we have included certain options for utilization of
off-specification fuel and transmix not represented in our original
Option 4. This aspect of our final program is discussed in detail in
section IV.
Options 5a and 5b were identical to the proposed program except
with respect to standards for engines less than 75 hp. Option 5a was
identical to the proposed program 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 was identical to the
proposed program except that for engines under 75 hp only the 2008
engine standards would be set, i.e. 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. We are not
adopting Options 5a or 5b in today's action. As explained at 8.2.3 of
the Summary and Analysis of Comments, and in sections 12.6.2.2.9 and
12.6.2.2.10 of chapter 12 of the draft RIA, these options would forego
substantial PM and NOX + NMHC emission reductions (on the
order of hundreds of thousands of tons of each pollutant) which are
feasible at reasonable cost. We note further that many of these smaller
engines operate in populated areas and in equipment without closed
cabs--in mowers, small construction machines, and the like--where
personal exposures to toxic emissions (both PM and air toxics which are
part of the NMHC fraction) may be pronounced well beyond what is
indicated simply by a comparison of nationwide emissions inventory
estimates. We would also emphasize the remarkable growth in recent
sales and usage for these smaller diesel machines, and we expect this
trend to continue, pointing up the need for effective PM emissions
control from these engines. We thus do not see a basis in law or policy
to adopt either of these options.
In response to comments on our NPRM we also investigated a number
of other variations in the engine standards as we developed our final
rule. These variations were generally related to the phase-in of engine
standards in a number of different horsepower categories. A discussion
of these variations is provided in section II as well as in various
background documents.
Table VII-1 contains a summary of a number of these alternatives.
The expected emission reductions, costs, and monetized benefits
associated with them in comparison to the proposed program were
evaluated for the NPRM. Those analyses were not revised for this final
rulemaking to reflect changes in our empirical models or assumptions.
We received no new information that would cause us to believe that the
relative impacts and differences for those alternative program options
relative to our final program would change enough to make an impact on
our assessments of the feasibility or appropriateness of the options.
The remainder of this section will summarize some of the comments we
received on the options and our responses to those comments.
Table VII-1.--Summary of Alternative Program Options
------------------------------------------------------------------------
Option Fuel Standards Engine Standards a
------------------------------------------------------------------------
Final program
-----------------------------------------------
? 500 PPM in 2007 ? <75 hp: PM
for NR, loco/marine. standards in 2008
? 15 ppm in 2010 ? 25-75 hp: PM AT-
for NR. based standards in 2013
? 15 ppm in 2012 ? 75-175 hp: PM
for loco/marine. AT-based standards in
2012
? 175-750 hp: PM
AT-based standards in
2011
? 75-175 hp: NOX
AT-based standards
phase-in 2012-2014
? 175-750 hp: NOX
AT-based standards
phase-in 2011-2014
? >750 hp: PM and
NOX AT phased-in 2011
and 2015
---------------------
1-Step Fuel Options
-----------------------------------------------
1................... ? 15 ppm in 2008 ? <50 hp: PM stds
for NR and loco/marine. only in 2009
? 25-75 hp: PM AT
stds and EGR or
equivalent NOX
technology in 2013; no
NOX AT
? >75 hp: PM AT
stds phasing in
beginning in 2009; NOX
AT phasing in beginning
in 2011
1a.................. ? 15 ppm in 2008 ? PM AT
for NR, loco/marine. introduced in 2009-10
? NOX AT
introduced in 2011-12
1b.................. ? 15 ppm in 2006 Same as 1a
for NR, loco/marine.
---------------------
2-Step Fuel Options
-----------------------------------------------
2a.................. Same as proposed program Same as proposed program
except--.
? 500 ppm in 2006
for NR, loco/marine.
2b.................. Same as proposed program Same as proposed program
except--. except--
? 15 ppm in 2009 ? Move PM AT up 1
for NR and loco/marine. year for all engines
>25 hp (phase in starts
2010)
2c.................. Same as proposed program Same as proposed program
except--. except--
? 15 ppm in 2009 ? Move PM AT up 1
for NR and loco/marine. year for all engines
175-750 hp (phase in
starts 2010)
2d.................. ? Same as Same as proposed program
proposed program. except--
[[Page 39151]]
? Phase-in NOX AT
for 25-75hp beginning
in 2013
---------------------
Other Options
-----------------------------------------------
3................... ? Same as Same as proposed program
proposed program. except--
? Mining
equipment over 750 hp
left at Tier 2
4................... Same as proposed program Same as proposed program
except--.
? Downgrade
flexibilities for loco/
marine not included.
5a.................. ? Same as Same as proposed program
proposed program. except--
? No Tier 4
standards < 75 hp
5b.................. ? Same as Same as proposed program
proposed program. except--
? No new <75hp
standards after 2008
(i.e., no CDPFs in
2013)
------------------------------------------------------------------------
Notes: a AT = aftertreatment.
B. Introduction of 15 ppm Nonroad Diesel Sulfur Fuel in One Step
EPA carefully evaluated an alternative which would require that the
nonroad diesel sulfur level be reduced to 15ppm in a single step,
beginning June 1, 2008. The one-step fuel options, including the three
variations Option 1, Option 1a, and Option 1b, were presented and
discussed in detail in the NPRM and in the draft RIA.
Many comments were received about a one step diesel fuel sulfur
control approach taking effect in 2008. Refiners commented that they
did not think that they could reduce both the highway and nonroad
diesel fuel pools down to 15 ppm in the same timeframe while
maintaining the supply of these two diesel fuel pools. The refiners
went on to say that having a 500 ppm outlet for off-specification
material in the nonroad diesel fuel pool is critical in the years after
reducing the highway diesel fuel pool to 15 ppm to ensure supply of
highway fuel. The refining industry further commented that the one step
program would provide fewer environmental benefits and also provide the
refining industry less time and flexibility to make the transition to
the 15 ppm sulfur level for nonroad diesel fuel compared to a two step
approach. While many environmental organizations and the Engine
Manufacturers Association (EMA) commented that they preferred a 15 ppm
standard as soon as possible, EMA also pointed out that a quick
transition to 500 ppm would provide important fleet-wide emission
reductions, reduce maintenance costs and enable the use of certain
emission control technology such as exhaust gas recirculation and
oxidation catalysts. Commenters generally said little about the engine
standards associated with the one-step options, other than to point out
that earlier introduction of 15 ppm sulfur fuel means that
aftertreatment-based standards and nonroad engine retrofits can also be
introduced earlier.
The reasons provided in the NPRM for choosing the two step program
over the one-step program still apply and generally address the
comments received (see section 12.6.2 of the draft RIA). Although there
would be greater PM and NOX emission reductions with the
one-step approach due to earlier introduction of aftertreatment
technology enabled by the 15 ppm sulfur diesel fuel, the SO2
emission benefits for the two-step approach are greater due to the
earlier adoption of the 500 ppm sulfur standard. Thus, even assuming
that the one-step approach would not jeopardize implementation of the
highway diesel emission rule, the emission impacts of these two options
are mixed. Moreover, the costs for achieving the second step (15 ppm)
of the two step approach are likely to be lower than under the one step
approach. This is because advanced desulfurization technologies are
much more likely to be used in 2010 after additional testing and
demonstration, while they may hardly be considered at all if they would
have to be installed for 2008. One advanced desulfurization technology,
Process Dynamics Isotherming, is expected to lower the cost of
complying with the 15 ppm step by about one cent per gallon. This cost
discrepancy is expected to persist since it is associated with the
investment of significant capital which cannot be modified or replaced
without significant additional expense. Additionally, under the two
step program, refiners will be able to use their experience in
complying with 15 ppm highway diesel fuel sulfur standard to better
design their nonroad hydrotreaters needed for 2010.
After careful consideration of these matters, we have decided to
finalize the two-step approach in today's action.
C. Applying the 15 ppm Sulfur Cap to Locomotive and Marine Diesel Fuel
In the NPRM, we requested comment on extending the 15 ppm cap to
locomotive and marine diesel fuel in 2010 or some later year as part of
this rule. The costs and inventory impacts of this alternative were
explored in the context of Option 4 in the NPRM. A 15ppm sulfur cap for
locomotive and marine fuel would increase the long-term PM and
SO2 benefits of the rule and would reduce the number of
fuels being carried in the distribution system after 2014, when the
small refiner provisions of this rule expire. It would also allow
refiners to plan to comply with the 15 ppm cap for locomotive and
marine diesel fuel at the same time as they plan to comply with the 500
ppm cap for NRLM fuel and the 15 ppm cap for nonroad fuel.
As a result of comments received and additional analyses performed
since the NPRM, we are finalizing a 15 ppm sulfur cap for locomotive
and marine fuel in today's notice. A full discussion of the feasibility
and benefits of a 15 ppm sulfur cap for locomotive and marine fuel can
be found in section IV, along with a summary of the comments we
received and our responses to those comments. In addition, we are
planning a separate rule to implement new emission standards for
locomotive and marine diesel engines that will build upon the 15 ppm
sulfur standard applicable to fuel used by these engines. We are
publishing an Advanced Notice of Proposed Rulemaking in another section
of today's Federal Register describing our plans in this area.
D. Other Alternatives
We also analyzed a number of other alternatives in the NPRM, as
summarized in table VII-1. Some of these focused on control options
more stringent than our final program while others reflect modified engine
[[Page 39152]]
requirements that result in less stringent control. In the NPRM we
presented our assessment of these options in terms of the feasibility,
emission reductions, costs, and other relevant factors. Few comments
were received on these other alternatives, and no new information arose
to alter what we believe are significant concerns with respect to these
Options compared to the final program. Hence, with the exception of the
few alternative program elements that we did incorporate into our final
program as described earlier in this section, we did not include these
options into our final program. Our detailed responses to all the
comments received on the other alternatives can be found in section 8
of the Summary and Analysis of Comments document.
VIII. Future Plans
The above discussion describes the contents of this final rule.
This section addresses a variety of areas not addressed by this rule.
In these several areas, we expect to continue our efforts to improve
our compliance programs and achieve further reductions in emissions
from nonroad engines.
A. Technology Review
As we described in sections III.E and G of the proposal, there are
some technology issues that warrant our planning a future review of
emissions control technology for engines under 75 hp. Under our
implementation schedule presented in section II.A, standards based on
the use of PM filter technology will take effect in the 2013 model year
for 25-75 hp engines (or in the 2012 model year for manufacturers
opting to skip the transitional standards for 50-75 hp engines).
However, at this time we have not decided what long-term PM standards
for engines under 25 hp are appropriate. No PM filter-based standards
are being adopted for these under 25 hp engines in this final rule.
Likewise, we have not decided what the long-term NOX
standards for engines under 75 hp should be, and no NOX
adsorber-based standards are being set for these engines in this final
rule. As part of the technology review, we plan to thoroughly evaluate
progress made toward applying advanced PM and NOX control
technologies to these smaller engines.
We plan to conduct the technology review in 2007, and to conclude
it by the end of that year, to give manufacturers lead time should an
adjustment in the program be considered appropriate. We do not intend
to include in the technology review a reassessment of PM filter
technology needed to meet the optional 0.02 g/hp-hr PM standard for 50-
75 hp engines in 2012. We assume that manufacturers would only choose
this option if they had confidence that they could meet the 0.02 g/hp-
hr standard in 2012, a year earlier than otherwise required.
Numerous commenters expressed support for the planned technology
review. MECA and STAPPA/ALAPCO stressed that the review should not be
limited to considering the need to relax PM filter-based standards for
small engines, but should also consider technology innovations that
would justify increasing the stringency of small engine standards that
are not currently aftertreatment-based. This is indeed our intent.
Yanmar suggested that the review be deferred to 2010 or later, because
NOX control experience from highway diesels will not be
sufficient by 2007. On the contrary, based on the rate of technology
development progress to date for highway engines, we believe that there
will be a very large amount of pertinent new information available by
2007, even though widespread field experience may be lacking. Waiting
longer to conduct the technology review would, we believe, provide
insufficient leadtime to the industry should an adjustment to the 2013
standards be found appropriate. Some engine and equipment manufacturers
called for expanding the technology review to other power categories.
As discussed in the proposal, we do not believe that a generalized
technology review of the sort being conducted for the heavy-duty
highway engine program is warranted, primarily due to the very fact
that the nonroad standards are modeled on the highway program, and the
highway program does include this comprehensive review. We also do not
see the specific technical issues for engines above 75 hp that have
been identified for smaller engines, such as might warrant our
expanding the review at this time. Engine manufacturers also expressed
interest in a consultative process in the near future that would
establish the scope, outputs, and criteria for the review, possibly
including assigning responsibility for the review to an independent
entity. Although we plan and hope to have the active participation of
all interested parties in the review process, assigning responsibility
for the review to groups or individuals outside the Agency would be
inappropriate. As the review would be closely tied to potential
subsequent rulemaking action by the Agency, it is essential that it
adequately cover the relevant issues. To ensure this, it is imperative
that we retain overall responsibility for the review. We have not yet
worked out process details for the review, but will do so at some later
date.
Several commenters strongly stressed the need for EPA to work with
governmental standards-setting bodies in other countries to harmonize
future standards. As discussed in section II.A.8, we recognize the
importance of harmonizing nonroad diesel standards and have worked
diligently with our colleagues responsible for setting such standards
outside the U.S., thus far with good success. The March 2004 Directive
that sets future nonroad diesel standards in the European Union (EU)
will very closely align the EU program with our program in the Tier 4
timeframe. \251\ Further enhancing prospects for close harmonization,
the Directive includes plans for a future technical review: ``There are
still some uncertainties regarding the cost effectiveness of using
after-treatment equipment to reduce emissions of particulate matter
(PM) and of oxides of nitrogen (NOX). A technical review
should be carried out before 31 December 2007 and, where appropriate,
exemptions or delayed entry into force dates should be considered.''
---------------------------------------------------------------------------
\251\ Council of the European Union, Directive of the
European Parliament and of the Council amending Directive 97/68/
EC, March 15, 2004.
---------------------------------------------------------------------------
Note that the timing for this review coincides with that of our own
planned review. Among other things, both our review and the EU review
will consider the appropriate long-term standards for engines between
25 and 50 hp, engines for which we have set PM-filter based standards
and for which the EU has not. Furthermore, in addition to re-evaluating
the standards, the EU technical review will consider the need to
introduce standards for engines below 25 hp and above 750 hp, the two
categories for which the EU has not yet set emission standards, and for
which harmonization is thus most lacking. We are greatly encouraged by
the degree of harmonization achieved thus far, and, given our common
interests, issues and planned timing, expect to work closely with
Commission staff in carrying out the 2007 technology review, with an
aim of preserving and enhancing harmonization of standards.
In response to comments received on the proposal, we wish to
clarify that the technology review for engines under 75 hp will be a
comprehensive undertaking that may result in adjustments to standards,
implementation dates, or other provisions (such as flexibilities) in
either direction ( that is, toward more or less stringency), depending
on conclusions reached in the review about
[[Page 39153]]
appropriate standards under the Clean Air Act. All relevant factors
including technical feasibility and commercial viability of engines and
machines designed to meet the standards will be taken into account.
B. Test Procedure Issues
Section III describes two issues related to test procedures that
warrant further attention in the future. First, we are adopting
transient test procedures for engines subject to Tier 4 emission
standards, but we intend to collect data that would help us adopt a
duty cycle that would appropriately test constant-speed engines.
Second, we are adopting cold-start test procedures, but are interested
in collecting additional data that could be used to revise those
procedures if appropriate.
C. In-Use Testing
Although this final rule does not include an in-use testing program
for nonroad diesel engines, we expect to establish such a program for
the future in a separate rulemaking action. The goal of this program
will be to ensure that emissions standards are met throughout the
useful life of the engines, under conditions normally experienced in-
use. The Agency expects to pattern the in-use testing requirements for
nonroad diesel engines after a program that is being developed for
heavy-duty diesel highway vehicles. This program will be funded and
conducted by the manufacturer's of heavy-duty diesel highway engines
with our oversight. We expect it will incorporate a two-year pilot
program. The pilot program will allow the Agency and manufacturers to
gain the necessary experience with the in-use testing protocols and
generation of in-use test data using portable emission measurement
devices prior to fully implementing program. A similar pilot program is
expected to be part of any manufacturer-run, in-use NTE test program
for nonroad engines.
The Agency plans to promulgate the in-use testing requirements for
heavy-duty highway vehicles in the December 2004 time frame. We
anticipate proposing a manufacturer-run, in-use testing program for
nonroad diesel engines by 2005 or earlier. As mentioned above, the
nonroad diesel engine program is expected to be patterned after the
heavy-duty highway program.
D. Engine Diagnostics
We are also in the process of defining diagnostic requirements that
would apply to highway diesel engines. Once we have adopted
requirements for highway engines, we would aim to adapt the
requirements as needed to appropriately address diagnostic needs for
nonroad diesel engines. These programs would likely be very similar,
but the diagnostics for nonroad engines my need to differ in some ways,
depending on the technologies used by different types and sizes of
engines and on an assessment of an appropriate level of information and
control for engines used in nonroad applications.
E. Future NOX Standards for Engines in Mobile Machinery Over
750 hp
In section II.A.4, we explain that we are not, at this time,
setting Tier 4 NOX standards for mobile machinery over 750
hp based on the performance of high-efficiency aftertreatment, although
we note that the 2.6 g/bhp-hr NOX standard taking effect for
these engines in 2011 represents a more than 60% NOX
reduction from the 6.9 g/bhp-hr Tier 1 level in effect today, and a
more than 40% reduction from the 4.8 g/bhp-hr NOX+NMHC Tier
2 standard level that takes effect in 2006. We are still evaluating the
issues involved for these engines to achieve a more stringent
NOX standard, and believe that these issues are resolvable.
We intend to continue evaluating the appropriate long-term
NOX standard for mobile machinery over 750 hp and expect to
announce further plans regarding these issues, perhaps as early as 2007.
F. Emission Standards for Locomotive and Marine Diesel Engines
This final rule adopts limited requirements to limit sulfur levels
in distillate fuels used in locomotive and many marine diesel engines,
which will help reduce PM emissions from these engines. In an upcoming
rulemaking, we will consider an additional tier of NOX and
PM standards for marine diesel engines less than 30 liters per cylinder
and for locomotive engines. These standards would reflect the
application of advanced emission-control technology, including the
potential to use the high-efficiency catalytic emission-control devices
like those described elsewhere in this preamble. In developing these
new standards, we will consider the substantial overlap in engine
technology between the locomotive and marine engines and the nonroad
engines covered by this final rule. We will also take into account the
unique features associated with locomotive and marine engines (and
their respective markets) and the extent to which these differences may
constrain the feasibility of applying advanced emission control
technologies to those engines.
We are concurrently publishing an Advance Notice of Proposed
Rulemaking that describes the emission-control program we are
contemplating for these engines. After consideration of comments
submitted on the Advance Notice, we will publish a Notice of Proposed
Rulemaking. Our proposal will be subject to comment before its expected
completion in the 2006 time frame.
The engine emission control program to be described in the Advance
Notice will cover all locomotive engines subject to 40 CFR part 92 and
all marine diesel engines with displacement below 30 liters per
cylinder. Note that the rule will therefore cover marine diesel engines
below 37 kW, which are currently regulated through Tier 3 with land-
based nonroad engines in 40 CFR part 89. The rule will also address
both recreational and commercial marine diesel engines with
displacement below 30 liters per cylinder. Marine engines at or above
30 liters per cylinder typically use a different kind of fuel, residual
fuel, and will be considered in a separate rulemaking to be finalized
by April 27, 2007, pursuant to a regulatory provision adopted in our
recent rule setting standards for those engines (68 FR 9783, February
28, 2003).
G. Retrofit Programs
In the proposal, we requested comment on setting voluntary new
engine emission standards applicable to the retrofit of nonroad diesel
engines. As described in section III.A, we are not adopting a retrofit
credit program with today's action. We believe it is important to more
fully consider the details of a retrofit credit program and work with
interested parties in determining whether a viable program can be
developed. EPA intends to explore the possibility of a voluntary
nonroad retrofit credit program through future action.
H. Reassess the Marker Specified for Heating Oil
As discussed in sections IV and V, we are requiring that the
chemical marker solvent yellow 124 (SY-124) be added to heating oil
outside of the Northeast/Mid-Atlantic Area. We received comments from
the American Society of Testing and Materials (ASTM), the Coordinating
Research Council (CRC), the Department of Defense (DoD), and the
Federal Aviation Administration (FAA) requesting that we delay
finalizing the selection of a specific marker for use in this final
rule due to concerns for jet fuel contamination. ASTM withdrew its
request for a postponement in the regulation, given
[[Page 39154]]
that this final rule requires addition of the marker at the terminal,
rather than the refinery gate as proposed. This eliminates most of the
concern regarding jet fuel contamination. However, ASTM stated that
some concern remains regarding jet fuel contamination downstream of the
terminal. Nevertheless, ASTM related that these concerns need not delay
finalization of the marker requirements in this rule, since a CRC
program to evaluate these concerns is expected to be completed well
before SY-124 must be added to heating oil. FAA is also undertaking an
effort to identify fuel markers that would be compatible for use in jet
fuel.
We also received comments from the heating oil industry and the
Department of Defense, which expressed concerns regarding the potential
health effects and maintenance impacts on heating oil equipment from
the use of SY-124 in heating oil. As discussed in section V, we believe
these concerns have been adequately addressed for us to specify the use
of SY-124 in this final rule. The EU has required the use of SY-124 in
heating oil since August 2002. The EU intends to re-evaluate the use of
SY-124 after December 2005 or earlier if they learn of any health,
safety, or environmental concerns from their in-use experience with SY-124.
We will keep abreast of the ASTM, CRC, FAA, IRS, and EU activities
and commit to a review of our use of SY-124 under today's rule based on
these findings. If alternative markers are identified that do not raise
concerns regarding the potential contamination of jet fuel, we will
initiate a rulemaking to evaluate the use of one of these markers in
place of SY-124.
IX. Public Participation
Many interested parties provided their input on the proposed
rulemaking during our public comment period. This comment period, along
with the three public hearings that were held in New York, Chicago, and
Los Angeles, provided ample opportunity for public participation.
Throughout the rulemaking process, EPA met with stakeholders including
representatives from the fuel refining and distribution industry,
engine and equipment manufacturing industries, emission control
manufacturing industry, environmental organizations, states,
agricultural interests, and others.
A detailed Response to Comments document was prepared for this
rulemaking that describes the comments that we received on the proposal
along with our response to each of these comments. The Response to
Comments document is available in the air docket and e-docket for this
rule, as well as on the Office of Transportation and Air Quality
homepage. In addition, comments and responses for many key issues are
included throughout this preamble.
X. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to review by the Office of Management and Budget
(OMB) and the requirements of this Executive Order. The Executive Order
defines a ``significant regulatory action'' as any regulatory action
that is likely to result in a rule that may--
? Have an annual effect on the economy of $100 million or
more or adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, Local, or Tribal governments or communities;
? Create a serious inconsistency or otherwise interfere with
an action taken or planned by another agency;
? Materially alter the budgetary impact of entitlements,
grants, user fees, or loan programs, or the rights and obligations of
recipients thereof; or
? Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
A final Regulatory Impact Analysis has been prepared and is
available in the docket for this rulemaking and at the internet address
listed under ``How Can I Get Copies of This Document and Other Related
Information?'' above. This action was submitted to the Office of
Management and Budget for review under Executive Order 12866. Estimated
annual costs of this rulemaking are estimated to be $2 billion per
year, thus this proposed rule is considered economically significant.
Written comments from OMB and responses from EPA to OMB comments are in
the public docket for this rulemaking.
B. Paperwork Reduction Act
The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The
information collection requirements are not enforceable until OMB
approves them. The OMB control number for engine-related information
collection is 2060-0460 (EPA ICR number 1897.07) and for fuel-related
information collection is 2060-0308 (EPA ICR number 1718.07).
We will use the engine-related information to ensure that new
nonroad diesel engines comply with emission standards through
certification requirements and various subsequent compliance
provisions. This information collection is mandatory under the
provisions of 42 U.S.C. 7401-7671(q). We will use the fuel-related
information to ensure that diesel fuel meets the sulfur limits and
corresponding requirements related to marking and segregating the
different types and grades of diesel fuel. This information collection
is mandatory under the provisions of 42 U.S.C. 7545(c), (g) and (i),
and 7625-1.
In addition, this notice announces OMB's approval of the
information collection requirements for other programs, as summarized
in Table X.B-1.
Table X.B-1--Approved Information Collection Requests From Other Programs
----------------------------------------------------------------------------------------------------------------
OMB control
Program Final rule cite number EPA ICR number OMB approval
----------------------------------------------------------------------------------------------------------------
Nonroad spark-ignition engines November 8, 2002 (67 2060-0460 1897.04 January 31, 2003.
over 19 kW. FR 68242).
Recreational vehicles............. November 8, 2002 (67 2060-0460 1897.04 January 31, 2003.
FR 68242).
Rebuilders of various types of November 8, 2002 (67 2060-0104 0783.46 June 11, 2003.
engines. FR 68242).
Highway motorcycles............... January 15, 2004 (69 2060-0104 0783.46 March 26, 2004.
FR 2398).
----------------------------------------------------------------------------------------------------------------
[[Page 39155]]
The estimated annual public reporting and recordkeeping burden for
collecting information from all these programs is shown in Table X.B-2.
Burden means the total time, effort, or financial resources expended by
persons to generate, maintain, retain, or disclose or provide
information to or for a Federal agency. This includes the time needed
to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
Table X.B-2.--Information Collection Burdens
--------------------------------------------------------------------------------------------------------------------------------------------------------
Operating and
Hours per Hours for all Capital costs maintenance Total costs
Engine type Respondents respondent respondents for all costs for all for all
respondents respondents respondents
--------------------------------------------------------------------------------------------------------------------------------------------------------
Nonroad diesel engine manufacturers..................... 75 3,304 247,783 $0 $5,894,802 $18,661,614
Diesel fuel suppliers................................... 2,615 75 196,288 1,800,000 1,800,000 18,371,600
Nonroad spark-ignition engine manufacturers............. 12 1,832 21,986 174,419 2,507,790 3,617,683
Recreational vehicle manufacturers...................... 39 684 26,669 1,627,907 2,137,115 4,869,253
Highway motorcycles..................................... 46 32 1,449 0 23,686 79,428
Importers............................................... 40 13 529 0 150,000 169,223
Rebuilders.............................................. 200 6 1,200 0 0 38,800
--------------------------------------------------------------------------------------------------------------------------------------------------------
An agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule. EPA received various comments on the rulemaking provisions
covered by the ICRs, but no comments on the paperwork burden or other
information in the ICRs. All comments that were submitted to EPA are
considered in the relevant Summary and Analysis of Comments, which can
be found in the docket. A copy of any of the submitted ICR documents
may be obtained from Susan Auby, Collection Strategies Division, U.S.
Environmental Protection Agency (2822-T), 1200 Pennsylvania Ave., NW.,
Washington, DC 20460 or by e-mail at auby.susan@epa.gov.
To comment on the Agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, including the use of automated collection
techniques, EPA has a public docket for this rule, which includes this
ICR, under Docket ID number OAR-2003-0012. Submit any comments related
to the ICR for this rule to EPA and OMB. Address comments to OMB by e-
mail to drostker@omb.eop.gov or fax to (202) 395-7285. Please do not
send comments to OMB via U.S. Mail.
C. Regulatory Flexibility Act (RFA), as Amended by the Small Business
Regulatory Enforcement Fairness Act of 1996 (SBREFA), 5 U.S.C. 601 et seq.
EPA has decided to prepare a Regulatory Flexibility Analysis (RFA)
in connection with this final rule. For purposes of assessing the
impacts of today's rule on small entities, a small entity is defined
as: (1) A small business that is primarily engaged in the manufacturing
of nonroad diesel engines and equipment that meets the definitions
based on the Small Business Administration's (SBA) size standards (see
table X.C.-1 below); (2) a small governmental jurisdiction that is a
government of a city, county, town, school district, or special
district with a population of less than 50,000; and (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
Table X.C-1.--Small Business Administration Size Standards for Various
Business Categories
------------------------------------------------------------------------
Defined as small
Industry entity by SBA Major SIC a Codes
if:
------------------------------------------------------------------------
Engine manufacturers.......... Less than 1,000 Major Group 35.
employees.
Equipment manufacturers:
--Construction equipment.. Less than 750 Major Group 35.
employees.
--Industrial truck Less than 750 Major Group 35.
manufacturers (i.e. employees.
forklifts).
--All other nonroad Less than 500 Major Group 35.
equipment manufacturers. employees.
Fuel refiners................. Less than 1500 2911.
employees b.
Fuel distributors............. ........
------------------------------------------------------------------------
Notes:
a Standard Industrial Classification.
b EPA has included in past fuels rulemakings a provision that, in order
to qualify for the small refiner flexibilities, a refiner must also
have a company-wide crude refining capacity of no greater than 155,000
barrels per calendar day. EPA has included this criterion in the small
refiner definition for a nonroad diesel sulfur program as well.
[[Page 39156]]
Pursuant to 5 U.S.C. 603, EPA prepared an Initial Regulatory
Flexibility Analysis (IRFA) for the proposed rule and convened a Small
Business Advocacy Review Panel (SBAR Panel, or ``the Panel'') to obtain
advice and recommendations of representatives of the regulated small
entities pursuant to 5 U.S.C. 609(b) (see 68 FR 28518-28521, May 23,
2003). A detailed discussion of the Panel's advice and recommendations
can be found in the Panel Report (Docket A-2001-28, Document No. II-A-
172). See also section III.C above.
We have also prepared a Regulatory Flexibility Analysis for today's
rule. The Regulatory Flexibility Analysis addresses the issues raised
in public comments on the IRFA, which was part of the proposal of this
rule. The Regulatory Flexibility Analysis is available for review in
the docket and is summarized below. The key elements of a regulatory
flexibility analysis include--
--The need for, and objectives of, the rule;
--The significant issues raised by public comments, a summary of the
Agency's assessment of those issues, and a statement of any changes
made to the proposed rule as a result of those comments;
--The types and number of small entities to which the rule will apply;
--The reporting, recordkeeping and other compliance requirements of the
rule; and
--The steps taken to minimize the impact of the rule on small entities,
consistent with the stated objectives of the applicable statute.
1. Need for and Objectives of the Rule
Controlling emissions from nonroad engines and equipment, in
conjunction with controls on sulfur concentrations in diesel fuel, has
very significant public health and welfare benefits, as explained in
section I of this preamble. We are finalizing new engine standards and
related provisions under sections 213(a)(3) and (4) of the Clean Air
Act which, among other things, direct us to establish (and from time to
time revise) emission standards for new nonroad diesel engines.
Similarly, section 211(c)(1) authorizes EPA to regulate fuels if any
emission product of the fuel causes or contributes to air pollution
that may endanger public health or welfare, or that may impair the
performance of emission control technology on engines and vehicles. We
are finalizing new fuel standards today for both of these reasons.
2. Summary of Significant Public Comments on the IRFA
We received comments from engine and equipment manufacturers, fuel
refiners, fuel distributors and marketers, and consumers during the
public comment period following the proposal of this rulemaking. All of
the following comments were taken into account in developing today's
final rule. Responses to these comments are located in subsection 5
below, along with the description of the provisions that we are
finalizing to reduce the rule's impact on small businesses. More
detailed information in response to these comments can be found in
sections III.C. (Engine and Equipment Small Business Provisions) and
IV.B (Hardship Relief Provisions for Qualifying Refiners) of this
preamble. Additional detail may also be found in the Final Regulatory
Flexibility Analysis, located in the Regulatory Impact Analysis, as
well as in the Summary and Analysis of Comments for this final rule.
a. Public Comments Received on Engine and Equipment Standards
One small engine manufacturer commented that the proposed
provisions for small business engine manufacturers are appropriate and
strongly supported their inclusion in the final rule. The manufacturer
raised many concerns of why it believes that it is necessary to include
provisions, such as: Larger/higher-volume manufacturers will have
priority in supply of new technologies and will have more R&D time to
complete development of these systems before they are available to
smaller manufacturers; smaller manufacturers do not command the same
amount of attention from potential suppliers of critical technologies
for Tier 4 controls, and are thus concerned that they may not be able
to attract a manufacturer to work with them on the development of
compliant technologies. This small manufacturer believes that the
additional three-year time period proposed for small engine
manufacturers in the NPRM is necessary for the company, and is their
estimate of the time that it will take for these technologies to be
available to small engine manufacturers.
The Small Business Administration's Office of Advocacy
(``Advocacy'') raised the concern that the rule would impose
significant burdens on a substantial number of small entities producing
engines of 75 hp or less, with little corresponding environmental
benefit. Advocacy therefore recommended that PM standards for engines
in the 25-75 hp range not be based on performance of aftertreatment
technologies. Advocacy believed that the proposed flexibilities will
not suffice on their own to appropriately minimize the regulatory
burdens on small entities; and Advocacy noted that during the SBREFA
process some small equipment manufacturers stated that although EPA
would allow some equipment to be sold which would not require new
emissions controls, engine manufacturers would not produce or sell such
equipment. Advocacy also commented that we have not shown that
substantial numbers of small businesses have taken advantage of
previous small business flexibilities, or that small businesses would
be able to take advantage of the flexibilities under this rule. Lastly,
Advocacy commented that although full compliance with the more
stringent emissions controls requirements would be delayed for small
manufacturers, small business manufacturers eventually will be required
to produce equipment meeting the new requirements.
b. Public Comments Received on Fuel Standards
i. General Comments on Small Refiner Flexibility
One small refiner commented that it is not feasible at this time to
evaluate the impact of the three fuels regulations on the refining
industry (and small refiners), however it stated that we should
continue to evaluate the impacts and act quickly to avoid shortages and
price spikes and we should be prepared, if necessary, to act quickly in
considering changes in the regulations to avoid these problems. We also
received comment that some small refiners that produce locomotive and
marine fuels fear that future sulfur reductions to these markets could
be very damaging.
ii. Comments on the Small Refiner Definition
A small refiner commented that the proposed redefinition of a small
refiner (to not grandfather as small refiners those that were small for
highway diesel) would both negate the benefits afforded under the small
refiner provisions in the Highway Diesel Sulfur rule and disqualify its
status as a small refiner. The small refiner is, however, in support of
the addition of the capacity limit in the small refiner definition
which will correct the problem of the inadvertent loop-hole in the two
previous fuel rules. Though the refiner is concerned that the wording
of the proposed language may result in small
[[Continued on page 39157]]
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