United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
Air
An Analysis of Costs
And Cost
Effectiveness Of
SO2 Control For
Mixed-Fuel-Fired
Steam Generating
Units
EPA-450/3-86-001
June 1986

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                                       EPA-450/3-86-001
An  Analysis of Costs and  Cost  Effectiveness
     of SO2 Control for Mixed-Fuel-Fired
             Steam Generating Units
                          Prepared by
                        Radian Corporation
                    Under Contract No. 68-02-381 6
                         Prepared for:
                U.S. ENVIRONMENTAL PROTECTION AGENCY
                      Office of Air and Radiation
                 Office of Air Quality Planning and Standards
                 Emission Standards and Engineering Division
                    Research Triangle Park, NC 27711

                          June 1986

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                                         DISCLAIMER

This report has been reviewed by the Office of Air Quality Planning and Standards, U.S. Environmental
Protection Agency, and approved for publication as received from the Radian Corporation. Approval does
not signify that the contents necessarily reflect the views and policies of the U.S. Environmental Protection
Agency, nor does mention of trade names or commercial products constitute endorsement or recommenda-
tion for use. Copies of this report are available from the National Technical Information Services, 5285 Port
Royal Road, Springfield, Virginia 221 61.

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                              TABLE OF CONTENTS




                                                         ,i             Page
                                                         i
1.0  INTRODUCTION	,...'.	  1


2.0  PROJECTIONS OF NEW MIXED FUEL-FIRED STEAM GENERATING UNITS	  3


3.0  MIXED FUEL-FIRED STEAM GENERATING UNIT S02 CONTROL COST	  9

     Coal/Nonfossil Mixed Fuel-Fired Steam Generating Units,,	 11

     Oil/Nonfossil Mixed Fuel-Fired Steam Generating Units.,,	 26

                                                         I
4.0  NATIONAL IMPACTS	i..	 30

     Selection of Regulatory Alternatives	«..	 30

     After-Tax NPV of Alternative Fuel Mixtures and Emission
     Control Systems	:	 31

     Analysis of Regulatory Alternatives	,1	 34


5.0  CONSIDERATION OF EMISSION CREDITS	*...	 39


6.0  REFERENCES	',!	 56
APPENDIX A:  COST DEVELOPMENT FOR MIXED FUEL-FIRED
             STEAM GENERATING UNITS	,.	A-l

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                               1.0  INTRODUCTION         !
                                                         I
      The  analysis  described herein was  undertaken in conjunction with
 efforts  to  develop new source performance standards (NSP'S)  for industrial-
 commercial-institutional  steam generating units with hea^ input capacities
 greater  than  100 million  Btu/hour.  Industrial-commercial-institutional
 steam generating units classified as  mixed fuel-fired steam generating units
 include  any unit firing a mixture of  nonsulfur-bearing fuels (e.g^  wood,
 solid waste,  municipal refuse, natural  gas,  etc.) with sulfur-bearing fossil
 fuels (e.g.,  coal, oil).
      Mixed  fuel-fired steam generating  units are economically attractive in
 many cases  because the nonsulfur-bearing fuel  is generally  a nonfossil fuel
 which is  replacing a more costly fossil  fuel.   Such units maintain the
                                                         i
 flexibility to fire 100 percent capacity of either fuel  ishould the need
 arise.
      Although mixed fuel-fired steam  generating units may be found at a  wide
.variety  o.f  industrial-commercial-institutional  sites, the principal  users  of
 mixed fuel-fired steam generating units  are industries that have a low
 sulfur gaseous fuel or a  nonfossil fuel  available on site as a byproduct of
 the plant's processes. By using tne  waste products from their processes as
 fuel, these industries are reducing their waste disposal  costs.
      Many mixed fuel combinations exist.  The most common fuel combinations
 fired in  mixed fuel-fired steam generating units are woo;d/coal and municipal
 waste/coal  mixtures.  Hence, the major  users of mixed fuel-fired steam
 generating  units are the  forest products and the paper a'nd  allied products
                                                         I
 industries.
                          -
      The objective of this report is  to  estimate the potential national
 impacts  associated with possible NSPS limiting sulfur dfoxide (S0?)
 emissions from new, modified, or reconstructed mixed fuel-fired steam
 generating  units.   These  impacts are  based on an examination of the annual
 SO- control costs, SO^.emissions, and the cost effectiveness of SO- control
 on model  mixed fuel-fired steam generating units.  In addition, the cost

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effectiveness of including versus not including an "emission credit" in
possible NSPS for mixed fuel-fired steam generating units is also examined.
     Projections of the number of new mixed fuel-fired steam generating
units and the development of model steam generating units are discussed in
Section 2.0.  Section 3.0 presents the results of the model mixed fuel-fired
steam generating unit cost analysis.  The results of the national impacts
analysis are presented in Section 4.0.  Section 5.0 discusses the
consideration of emission credits for mixed fuel-fired steam generating
units.

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      2.0   PROJECTIONS OF NEW MIXED FUEL-FIRED STEAM GENERATING UNITS
                                                        i

     A wide variety of nonsulfur-bearing fuels may be co-fired with
sulfur-bearing fossil fuels in mixed fuel-fired industrial-commercial-
institutional steam generating units.  Little data or information are
readily available, however, concerning the existing population of mixed
                                                        i
fuel-fired steam generating units, current fuel firing practices (i.e.,
relative amounts of nonsulfur-bearing fuels and sulfur-bearing fossil fuels
typically co-fired), or the projected growth in the number of new mixed
fuel-fired steam generating units.  From the data and information that are
available, it'appears that the major users of mixed fuelrfired steam
generating units are the forest products and paper industries.  Wood is the
predominant nonsulfur-bearing fuel fired in these steam generating units.
The growth of mixed fuel-fired steam generating units firing
nonsulfur-bearing fuels other than wood is also expected'to be small in
comparison to wood/fossil fuel-fired steam generating unp'ts.  Therefore,
although the results discussed in this report are based on projections for
new steam generating units firing mixtures of sulfur-bearing fossil fuels
and wood, these results are considered representative of|the impacts on all
new mixed fuel-fired steam generating units.
     Model mixed fuel-fired steam generating units were developed based on
information obtained from a survey of the pulp and paper|and forest products
industries by the National Council of the Paper Industry;for Air and Stream
Improvement (NCASI).   This report provided information on the fuel mix,
population projections, and size distribution of mixed fuel-fired steam
                 2
generating units.
                                                        i
     During the five-year period from 1980 through 1984,:35 mixed fuel-fired
                                                        I
steam generating units having a total heat input capacity of 20.1 billion
                                                       2~
Btu/hour were installed in the pulp and paper industry.   It is anticipated
that about the same number of new mixed fuel-fired steam1generating units
having the same total capacity will be built over the five-year period
ending in 1990.  Consequently, the information provided by NCASI was used to

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project the population of new mixed fuel-fired steam generating units
anticipated in the time frame of 1985 through 1990.
     Table 1 presents the size distribution of these projected mixed
fuel-fired steam generating units.  Three model steam generating units were
selected to represent the size range presented in Table 1.  The small mixed
fuel-fired steam generating units (100-250 million Btu/hour} are represented
by a 150 million Btu/hour model unit, the medium sized units (250-500
million Btu/hour) are represented by a 400 million Btu/hour model unit, and
large units (>500 million Btu/hour) are represented by an 800 million
Btu/hour model unit.
     Table 2 presents the projected fuel mix distribution of mixed fuel-
fired steam generating units.   Three model fuel mixtures were selected to
represent those presented in Table 2.  Fuel mixtures of 20 percent
nonsulfur-bearing fuel/80 percent sulfur-bearing fossil fuel, 50 percent
nonsulfur-bearing fuel/50 percent sulfur-bearing fossil fuel, and 80  percent
nonsulfur-bearing fuel/20 percent sulfur-bearing fossil fuel were chosen to
represent mixed fuel  steam generating units firing 0 to 49 percent
nonsulfur-bearing fuel, 50 to  75  percent nonsulfur-bearing fuel, and  greater
than 75 percent nonsulfur-bearing fuel, respectively.
     Table 2 shows  that all five  150 million Btu/hour mixed fuel-fired steam
generating units fire a fuel mixture near 80 percent nonsulfur-bearing
fuel/20 percent sulfur-bearing fossil fuel.  Table 2 also shows  that,11 of
the projected medium  sized mixed  fuel-fired steam generating units will burn
a 20 percent sulfur-bearing fossil fuel mixture, 2 units will fire a  50
percent sulfur-bearing fossil  fuel mixture, and  2  units will fire an  80
percent sulfur-bearing fossil  fuel mixture.  Of  the large mixed  fuel-fired
steam generating units, four units will fire 20  percent sulfur-bearing
fossil fuel,  two units will fire  50  percent sulfur-bearing fossil fuel, and
nine units will  fire  80 percent  sulfur-bearing fossil  fuel.
     Regions  I,  IV, and X were selected  for analysis of the potential
impacts of S02  control on new  mixed  fuel-fired steam generating  units.
These  three  regions were  selected because  they have a  high concentration of
pulp and  paper  and  forest product industries.    Thus,  most new mixed

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TABLE 1.  PROJECTED SIZE DISTRIBUTION OF NEW MIXED FUEL-FIRED
     STEAM GENERATING UNITS FOR THE PERIOD 1985 TO 1990

Heat Input
(million
100 -
250 -
>500
Capacity
Btu/hr)
250
500

Model Unit Size
(million Btu/hr)
150
400
800
Number of Units
5
15
15

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fuel-fired steam generating units are expected to be installed in these
regions.  Based on historical data, 23 percent of mixed fuel-fired steam
generating units in the paper and allied products industry are in Region I,
45 percent of the units are in Region IV, and 32 percent bf the units are in
         3
Region X.   It is assumed that new mixed fuel-fired units will follow this
same regional  distribution.  Within each region, mixed fuel-fired steam
generating units are distributed according to size and fuel mixture as
discussed above.  On this basis, Table 3 presents the regional distribution
of the projected model mixed fuel-fired steam generating units.

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         3.0  MIXED  FUEL-FIRED  STEAM  GENERATING  UNIT S02  CONTROL  COST
                                                          i
     This  section presents  the results  of an  analysis  of S0?  control  costs
 for mixed  fuel-fired  steam  generating units.  This  analysis considers  two
 alternative  control levels:                               :
                                                          i
     (1)   The  use of  low sulfur  fuels containing  less  than 1.2 Ib
           S02/million Btu for  coal and  less than  0.8 Ib  StL/miTMon  Btu  for
           oil.
     (2)   The  use of  flue gas  desulfurization (FGD)  systems to achieve a 90
           percent reduction in S02 emissions.             j

     All costs presented in this analysis  are in  January  1983 dollars.
Appendix A summarizes the general procedure and major  assumptions used to
develop the  cost estimates.  The analysis  is consistent with  that contained
in the Industrial Boiler SO,, Cost Report.4 'The regulatory baseline  is the
same- (i.e.,  existing State  implementation  plans [SIP's]) and, as in  the
Industrial Boiler S02 Cost Report, the costs of sodium FGD systems have been
used to represent the costs of FGD systems in general.4  For  the 800 million
Btu/hour units, the FGD cost is represented by two shop fabricated 400
million Btu/hour units.  Sodium FGD systems larger than about 400 million
Btu/hour are not available on a "packaged" basis.   Because it costs less to
install two  packaged FGD systems and increase overall rel inability, two 400
million Btu/hour packaged FGD units were selected over a field erected 800
million Btu/hour FGD unit.                                 '
     This analysis also assumes an overall annual  capacity factor of 0.6.
As discussed in the Industrial  Boiler SO^ Cost Report.'this annual  capacity
factor is considered representative of industrial-commercial-institutional
steam generating units in general.
     Fossil fuel  prices (Table  4) have also been assumed to be the same as
                                                          i
those used in the Industrial Boiler S02  Cost Report.  Data! are generally
unavailable, however,  on the cost of nonfossil.fuel.  In some  cases  the
nonfossil fuel  may be  a byproduct of the plant's processes' that  could not be

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sold and which has a negligible cost associated with its use as a fuel.  In
other cases, however, the nonfossil fuel is purchased much as are fossil
fuels.  In general, there is some cost associated with the use of nonfossil
fuel, although it is unlikely that the cost of nonfossil fuel would be
higher than that of available coal on a heating value basis.  Thus, this
analysis considers two cost scenarios for nonfossil fuel:i(l) nonfossil fuel
has zero cost, and (2) nonfossil fuel has the same cost as the least
expensive coal available (on a $/million Btu basis).     i
                                                         i
Coal/Nonfossil Mixed Fuel-Fired Steam Generating Units   j
                                                         i
     Tables 5, 6, and 7 present the results of the cost analysis for
coal/nonfossil mixed fuel-fired steam generating units in Regions I, IV, and
X, respectively.  As mentioned previously, these three regions are expected
                                                         i
to have the majority of new installations of mixed fuel-ffired steam
generating units due to the high concentration of pulp and paper and forest
products industries.  The average cost effectiveness of.S02 control of an
alternative control level based on the use of low sulfur coal is less than
$380/ton in Region I, $325/ton in Region IV, and $l,000/ton in Region X.
     The average cost effectiveness of SCL control associated with an
alternative control level based on the use of low sulfur poal is
significantly higher in Region X than in Regions I and IV;.  This is due to
the much lower emission reductions achieved between a medium and low sulfur
coal in Region X compared to the SCL emission reductions achieved between a
high and low sulfur coal in Regions I and IV.
     As expected, the average cost effectiveness of SCL cpntrol associated
with an alternative control level based on the use of Tow sulfur coal does
not vary with the size of the mixed fuel-fired steam generating unit.  As
shown, however,  it does vary with the proportion of coal present in the fuel
mixture fired.
     This results from the assumption of "emission credits" under the
regulatory baseline for mixed fuel-fired steam generating; units.  Currently,
under the existing new source performance standard for industrial-
                                      11

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commercial-institutional steam generating units of more than 250 million
Btu/hour heat input capacity (i.e., 40 CFR Part 60 Subpa|rt D) and regulatory
requirements contained in SIP's, dilution of the SO^ emissions resulting
from combustion of fossil fuel with the gases resulting from combustion of
nonfossil fuel is permitted.                            i
     Existing regulations permit one to add the heat input supplied to a
mixed fuel-fired steam generating unit supplied by a nonfossil fuel to that
supplied by a fossil fuel in determining compliance.  Since existing
regulations are generally written in terms of grams (or pounds) of S02 per
unit of heat input to the steam generating unit, including the heat input
supplied by the nonfossil fuel inherently provides an emission credit for a
mixed fuel-fired steam generating unit.
     Typically, for example, many existing regulations limit SO^ emissions
from coal-fired steam generating units to 1.2 Ib S0?/mil|lion Btu.  To
                                                   ^
achieve this emission limit, a coal-fired steam generating unit is
essentially required to fire a low sulfur coal or install an FGD system.
Because of the emission credit inherently provided by this type of
regulation, however, mixed fuel-fired steam generating units are not
required to fire a low sulfur coal or install an FGD system, but are
permitted to fire medium or even high sulfur coals.
                                                        I
     A mixed fuel-fired steam 'generating unit firing a fuel mixture of 20
percent coal and 80 percent nonfossil fuel, for example, would only be
required to fire a coal containing 6.0 Ib SO^/million Btu or less.  As
illustrated below, however, as the proportion of coal in, the fuel mixture
increases, the sulfur content of the coal that can be fibred decreases:
Fossil/Nonfossil Fuel Mixture
  20% Fossil/80% Nonfossil
  40% Fossil/60% Nonfossil
  50% Fossil750% Nonfossil
  60% Fossil740% Nonfossil
  80% Fossil/20% Nonfossil
Maximum Coal Sulfur Content
   (Ib SOp/million Btu)
         6.0
         3.0
         2.4
         2.0
         1.5
                                       15

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     The reasonableness of emission credits for mixed fuel-fired steam
generating units are examined in Section 5.0.  Except under the regulatory
baselines however, the analysis discussed in this section assumes no
emission credits.
     As a result, regardless of the proportion of coal fired in the fuel
mixture, mixed fuel-fired steam generating units must fire low sulfur coal
or install an FGD system to meet the requirements of an alternative control
level based on the use of low sulfur.coal.  As mentioned, however, this is
not the case under the regulatory baseline.  As illustrated above, as the
proportion of coal in the fuel mixture increases, a mixed fuel-fired steam
generating unit must fire a lower sulfur coal to meet the regulatory
baseline of 2.5 Ib S02/million Btu.
     Consequently, as the proportion of coal fired in the fuel mixture
varies, the incremental costs and SCL emission reductions between the
regulatory baseline and an alternative control level based on the use of low
sulfur fuel can also vary.  As a result, the average cost effectiveness of
S02 control for a low sulfur fuel alternative can vary as the proportion of
coal fired in the fuel mixture changes.
     Tables 5, 6, and 7 also present the average and incremental cost
effectiveness of SCL control associated with an alternative control level
requiring a 90 percent reduction in S02 emissions.  The average cost
effectiveness of S02 control ranges from as low as $462/ton for the largest
mixed fuel-fired steam generating unit firing a fuel mixture of 80 percent
coal and 20 percent nonfossil fuel in Region I, to as high as $2,333/ton for
the smallest mixed fuel-fired steam generating unit firing a fuel mixture of
20 percent coal and 80 percent nonfossil fuel in Region X.  As expected, the
average cost effectiveness of a percent reduction in S02 emissions generally
becomes more favorable as the size of a mixed fuel-fired steam generating
unit increases.  This is due to the economies of scale of the FGD system.
Because the analysis for the 800 million Btu/hour steam generating unit is
based on the use of two shop fabricated 400 million Btu/hour FGD units, the
average cost effectiveness is essentially the same for steam generating
units of 400 and 800 million Btu/hour heat  input capacity.
                                      16

-------
     The average cost effectiveness of SCL control associated with an
alternative control level requiring a percent reduction in SO^ emissions
also varies as the amount of coal fired in the fuel mixture varies.
Generally, the average cost effectiveness improves as the amount of coal
fired in the fuel mixture increases.                    i
                                                        i
     This is not always the case, however, as shown in Region IV in
progressing from a fuel mixture of 50 percent coal and 50 percent nonfossil
fuel to a fuel mixture of 80 percent coal and 20 percent nonfossil fuel.  In
this case, the average cost effectiveness of S02 control: associated with an
alternative control level' requiring a percent reduction in 50^ emissions
deteriorates rather than improves.
     In this particular case, a lower sulfur coal is required under the
                                                        i.1
regulatory baseline in a fuel mixture consisting of 80 percent coal and 20
percent nonfossil fuel than in a fuel mixture consisting1 of 50 percent coal
and 50 percent nonfossil fuel.  Consequently, the SOp emission reduction
achieved by an alternative control level requiring a 90 percent reduction in
S0? emissions is less for the 80 percent coal/20 percent; nonfossil fuel
mixture than for the 50 percent coal/50 percent nonfossil  fuel mixture.  As
a result, the average cost effectiveness of S02 control deteriorates in
progressing from the 50 percent coal/50 percent nonfossil  fuel mixture to
the 80 percent coal/20 percent nonfossil fuel mixture.
     As shown in the tables, the incremental cost effectiveness of achieving
a 90 percent reduction in S02 emissions over meeting an emission limit of
1.2 Ib SOp/million Btu is almost identical for units with heat input
capacities of 400  and 800 million Btu/hour.  This is primarily due to the
fact, discussed  above, that for an 800 million Btu/hour unit, the FGD cost
is  represented by  two 400 million Btu/hour FGD units.  The incremental cost
effectiveness of S0? control for a  150 million Btu/hour ^team generating
unit, however, is  higher in all cases than those associated with larger
steam generating units.               '
     The  incremental cost effectiveness also improves asi the percentage of
coal fired  increases.  This  is as one would expect, because without an
emission  credit  an alternative'control  level based on the use of low sulfur
                                      17

-------
fuel always requires the combustion of a low sulfur fuel or the use of an
F6D system.  Thus, in examining the incremental differences between an
alternative control level based on the use of low sulfur coal and an
alternative control level requiring a percent reduction in SCL emissions,
one is always comparing the costs and emissions associated with firing a low
sulfur fuel with the costs and emissions associated with an 'FGD system.  In
addition, FGD systems installed on mixed fuel-fired steam generating units
would be designed to accommodate firing of fossil fuel at full load to
provide maximum fuel use flexibility.  Thus, the costs of FGD systems
installed on units firing small amounts of fossil fuel would be similar to
those installed on mixed fuel-fired units that fire large amounts of fossil
fuel relative to nonfossil fuel.  However, the potential SCL emission
reductions obtainable from units burning relatively larger amounts of fossil
fuel relative to nonfossil fuel are much greater than for units burning
mostly nonfossil fuel.  As a result, for mixed fuel-fired steam generating
units that fire only small amounts of fossil fuel, the costs of achieving a
percent reduction in SCL emissions are relatively high in proportion to the
resulting emission reductions.  Conversely, as the amount of coal fired in
the fuel mixture increases, the FGD system costs demonstrate economies of
scale and the S0? emission reductions achieved increase.  The incremental
cost effectiveness of SCL control, therefore, improves.
     The amount of fossil fuel fired in a steam generating unit can be
expressed in terms of a fossil fuel utilization factor.  This represents the
percentage of the rated steam generating unit heat input capacity that is
supplied by fossil fuel.  The fossil fuel utilization factor is, therefore,
calculated on the basis of the amount of fossil fuel that is actually fired
compared to the maximum amount of fuel that could be fired in the steam
generating unit.  For example, a 400 million Btu/hour mixed fuel-fired steam
generating unit operating at an annual capacity factor of 0.6 is firing 240
million Btu/hour heat input -on an annual basis.  If this unit fires 20
percent fossil fuel and 80 percent nonfossil fuel, the heat input supplied
from fossil fuel is 48 million Btu/hour on an annual basis.  This represents
12 percent of the potential total annual heat input to the steam generating
                                       18

-------
unit, or a fossil fuel utilization factor of 0.12.  Similarly, a mixed
fuel-fired steam generating unit operating at an annual capacity factor of
0.6 and firing 50 percent fossil fuel/50 percent nonfossil fuel mixture
would have a fossil fuel utilization factor of 0.3, and a unit firing 80
percent fossil fuel and 20 percent nonfossil fuel would have a fossil fuel
utilization factor of 0.48.                             I
     Figures 1, 2, and 3 illustrate the incremental cost effectiveness of an
alternative control level requiring a 90 percent reduction in S0£ emissions
over an alternative control level based on the use of  low sulfur fuel as a
function of the fossil fuel utilization factor for mixedifuel-fired  steam
generating units operating at an annual capacity utilization factor  of 0.6.
Fossil fuel utilization factors of 0.12, 0.3, and 0.48 were examined and are
shown in the figures.                                   i
     The incremental  cost effectiveness of achieving a percent reduction in
S0? emissions varies  considerably with varying amounts of coal fired in the
steam generating unit.  As shown in the figures, as the fossil fuel
utilization factor increases, the incremental cost effectiveness decreases.
A more rapid decrease in incremental cost-effectiveness occurs in
progressing from a fossil fuel  utilization factor of 0.12 to a fossil fuel.
utilization factor of 0.3 than  in progressing from a fossil fuel utilization
factor of 0.3 to a fossil fuel  utilization factor of 0.6l.  Thus, the fossil
fuel utilization factor exerts  an important  influence  on, the costs  of
achieving a percent  reduction in SO,, emissions.         j
      Figure 4 illustrates the regional differences in.the incremental cost
effectiveness associated with an alternative control level requiring a 90
percent  reduction  in  S02 emissions  for a 400 million Btu/hour  steam
generating  unit.   This  figure shows that- the incremental; cost  effectiveness
of  an  alternative  control  level  requiring  a  90 percent reduction in SO^
emissions  over  an  alternative based on the use of  low  sulfur fuel  in Region
IV  is-about 30  percent  higher than  in  Region I and about 60 percent higher
than in  Region  X.  These differences are due to  regional: variations in coal
sulfur contents and  prices.  The  high  incremental  costs iassociated  with
achieving  a percent  reduction  in  SO- emissions  in  Region!  IV can  be
                                      19

-------
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                               •  a 800 Million Btu/hr
                                           O.3                O.48

                               Fossil Fu«l Utilization Factor
                         —T~
                         20
                     50

              Percent Coal USA
                                        8O
                                                   0.6
100
             Over alternative control level based on the use of low sulfur coal.
      Figure 1.   Incremental Cost Effectiveness of a Percent Reduction  Requirement
                 for  Mixed  Fuel-Fired Steam Generating Units Firing  Coal  in
                 Region  I.
                                            20

-------
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                       0.12               0.3                0-48

                               Fos«il Fu«l Utilization Factor
                         20
                                           50

                                     Percent Coal Use
                                                               80
                                                                         0-6
                                                                           100
             aOver alternative  control level based on the use of low sulfur coal
      Figure 2.   Incremental  Cost  Effectiveness of a Percent Reduction Requirement
                 for Mixed  Fuel-Fired  Steam Generating Units Firing Coal in
                 Region IV.
                                             21

-------
      9,000-t
      8,000-
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                              Fossil Fu«l Utilization Factor
                        20
                                     50

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 i
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100
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     Figure 3.
         Incremental Cost Effectiveness  of a  Percent Reduction Requirement
         for Mixed Fuel-Fired Steam Generating Units Firing Coal  in
         Region X.
                                             22

-------
     9,000-i
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                                                                  Region
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                           .  Fo**il Fuel Utilization Factor
                        20
                              	1
                                      5O

                               Percent Coal U«e
                                                              80
10O
              Over  alternative control level based on the use of low sulfur coal
    Figure 4.   Incremental  Cost  Effectiveness of a Percent Reduction Requirement
               for  a  400 million Btu/hour Mixed Fuel-Fired, Steam Generating Unit
               Firing Coal.  "
                                          -23  '

-------
attributed to the fact that a higher sulfur coal is typically fired in this
region.  Under a standard requiring a 90 percent reduction in SCL emissions,
steam generating units in Region IV will likely fire a Type H bituminous
coal having typical uncontrolled S02 emissions of about 5.5 Ib/million Btu.
A 90 percent reduction would reduce these emissions to 0.55 Ib SOp/million
Btu.  In contrast, steam generating units in Region I will 'likely fire a
coal having typical uncontrolled S02 emissions of about 4.2 Ib/million Btu,
and the uncontrolled emissions from a unit in Region X would typically be
about 2.1 Ib/million Btu.  A 90 percent reduction in Regions I and X,
therefore, will result in SO,, emissions of 0.42 and 0.21 Ib/million Btu,
respectively.  Compared to a low sulfur coal emission limit of 1.2 Ib
SOp/million Btu, steam generating units in Regions I and X realize greater
emission reductions under a 90 percent reduction requirement than those in
Region IV.  Therefore, a 90 percent reduction requirement would be more cost
effective in Regions I and X than in Region IV.
     The annualized costs presented in Tables 5, 6, and 7 assume that the
          •
price of nonfossil fuel is zero cost.  For a case where nonfossil fuel has a
price, annualized costs will increase.  However, since these increased
annualized costs cancel- out in comparing incremental impacts between
alternatives, the average and incremental cost effectiveness values cited
above and presented in Tables 5, 6, and 7 would remain unchanged.  To
illustrate this, Table 8 summarizes the costs and cost effectiveness of S02
control  for a 150 million Btu/hour mixed fuel-fired steam generating unit
firing a fuel mixture of 20 percent coal and 80 percent nonfossil fuel in
Regions I, IV, and X.  The annualized costs presented in this table assume
that the cost of the nonfossil fuel is equal to the cost of the lowest price'
coal in each region on a $/million Btu heating value basis.  This table
shows that although the total annualized costs are higher than those
presented in Tables 5, 6, and 7, the cost effectiveness values remain
unchanged.
                                      24

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Oil/Nonfossil Mixed Fuel-Fired Steam Generating Units

     Table 9 presents the results of the cost analysis for oil/nonfossil
mixed fuel-fired steam generating units in Region I.  Mixed fuel-fired units
were only examined in Region I because the price premium for a low sulfur
                                                                          5
oil compared to a high sulfur oil is essentially constant for all regions.
     The average cost effectiveness of SCL control associated with an
alternative control level based on the use of low sulfur oil is less than
$640/ton.  As expected, the average cost effectiveness of SOp control under
this alternative control level remains constant with mixed fuel-fired steam
generating unit size.  In addition, unlike the situation discussed above for
mixed fuel-fired steam generating units firing coal, the highest sulfur oil
available is always fired in the oil/nonfossil fuel mixture under the
regulatory baseline regardless of the proportion of oil in this fuel
mixture.  Consequently, the average cost effectiveness of SCL control also
remains constant as the proportion of oil fired in the fuel mixture varies.
     Table 9 also presents the average and incremental cost effectiveness of
SCL control associated with an alternative control level requiring a percent
reduction in S02 emissions.  The average cost effectiveness of an SCL
emissions percent reduction requirement ranges from as little as $467/ton
for the largest mixed fuel-fired steam generating unit firing a fuel mixture
containing 80 percent oil/20 percent nonfossil fuel, to as much as
$l,505/ton for the smallest mixed fuel-fired, unit firing a fuel mixture of
20 percent oil/80 percent nonfossil fuel.  Similarly, the incremental cost
effectiveness of S02 control ranges from as low as $0/ton to as high as
$5,000/ton.  As expected, the average and incremental cost effectiveness of
S0? control associated with an alternative control level requiring a percent
reduction in S0? emissions improves as the size of the mixed fuel-fired
steam generating unit'increases or as the proportion of oil fired in the
oil/nonfossil fuel mixture increases.  This is due to the economies of scale
experienced by the FGD system.
     Figure 5 illustrates the incremental cost effectiveness of an
alternative control level requiring a 90 percent reduction in SO- emissions
                                     26

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                              Percent  Oil  Use
                                                             80
                                                                    100
      Over alternative control level  based on the  use  of  low sulfur oil
      Figure 5.  Incremental Cost Effectiveness  of a  Percent Reduction

                Requirement for Mixed Fuel-Fired  Steam Generating Units

                Firing Oil.
                                       28

-------
over an alternative control level based on the use of low sulfur oil as a
function of the fossil fuel utilization factor for mixedjfuel-fired steam
generating units firing oil and operating at an annual capacity utilization
factor of 0.6.  As with mixed fuel-fired steam generating units firing coal,
fossil fuel utilization factors of 0.12, 0.3, and 0.48 were examined.
     As shown in the figure, as the fossil fuel utilization factor
increases, the incremental cost effectiveness decreases.  As discussed above
for mixed fuel-fired steam generating units firing coal,ithis decrease is
                                                         I
most rapid at low fossil fuel utilization factors.  Thus, the fossil fuel
utilization factor exerts an important influence on the costs of achieving a
percent reduction in S02 emissions.
     The annualized costs presented in Table 9 assume that the price of
nonfossil fuel is zero.  As discussed earlier for mixed fuel-fired steam
generating units firing coal, if the nonfossil fuel has a non-zero price,
the overall annualized costs will rise, but the incremental impacts
associated with S02 control will not change.             !
                                      29

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                            4.0  NATIONAL IMPACTS

     This section examines the national impacts of NSPS limiting SOg
emissions from new industrial-commercial-institutional  mixed fuel-fired
steam generating units.  The national impact analysis utilizes the projected
population of new mixed fuel-fired steam generating units; described in
Section 2.0.  To estimate these impacts, the total costsJassoclated with
each projected new mixed fuel-fired steam generating unit firing
coal/nonfossil, oil/nonfossil, or natural gas/nonfossil mixtures, including
the costs associated with environmental regulations, were compared on an
after-tax net present value (NPV) basis over a 15-year investment period.
The lowest cost means of complying with each regulatory alternative examined
was then determined for each mixed fuel-fired steam generating unit.  These
                                                         I
results were then aggregated to yield national projections in 1990 of
annualized costs, S0? emissions, and solid and liquid wastes associated with
mixed fuel-fired steam generating units.
                                                         i
Selection of Regulatory Alternatives                     ;
                                                         i
     The regulatory baseline represents the level of control required by
existing SIP's.  Currently, the average S02 emission limit required under
SIP's is approximately 2.5 Ib/million Btu-heat input.  Thus, a regulatory
baseline of 2.5 Ib/million Btu heat  input was selected for the analysis of
national impacts for new mixed fuel-fired steam generating units.  Also, as
discussed in the previous section, the regulatory baseline permits dilution
of the S02 emissions resulting from  combustion of fossil|fuels with the
gases resulting from combustion of nonfossil fuels to comply with this
emission limit.  Dilution is not permitted, however, to comply with the
                                                         I
various  regulatory alternatives examined.  The reasonableness of dilution or
"emission credits" for mixed fuel-fired steam generating;units is examined
                                                         i
in Section 5.0.
     This national impact analysis examined two alternative control levels:
an alternative  requiring a low sulfur fuel and an alternative requiring 90
                                      30

-------
percent reduction in S02 emissions.  Also, this analysis considered two size
categories of mixed fuel-fired steam generating units: units greater than
250 million Btu/hour heat input capacity; and units between 100 and 250
million Btu/hour heat input capacity.  Table 10 presents the four regulatory
alternatives examined.

After-Tax NPV of Alternative Fuel Mixtures and Emission Control Systems

     Table 11 presents the after-tax NPV of alternative fuel mixtures and
emission control systems for the regulatory baseline, for an alternative
control level based on the use of low sulfur fossil fuel, and for an
alternative control level requiring a 90 percent reduction in SO^ emissions.
These results are presented for a 150 million Btu/hour steam generating unit
firing 100 percent fossil fuel as well as a 20 percent fossil/80 percent
nonfossil fuel mixture.  The analysis for this particular fuel mixture and
size of steam generating unit are presented because this combination results
in conservative estimates of impacts associated with SO^ control.  As the
steam generating unit size and amount of fossil fuel fired in the mixture
increases, the cost of SOp control as a percent of total steam generating
unit costs decreases.
     The results presented in this table show that at the regulatory
baseline and for alternative control levels based on the use of low sulfur
fuels or requiring a percent reduction in SOp emissions, new projected mixed
fuel-fired steam generating units will continue to fire fossil/nonfossil
fuel mixtures.  In addition, all units are expected to select coal as the
fossil fuel to fire in the. fossil/nonfossil fuel mixture.  This is to be
expected because a steam generating unit-capable of firing a nonfossil fuel
on a grate is also capable of firing coal.  Thus, there are little capital
costs associated with the steam generating unit to be saved by firing
natural gas or oil with.the nonfossil fuel.
     As mentioned, Table 11 also shows that mixed fuel-fired steam
generating units do not "switch" fuels even under a regulatory alternative
requiring a 90 percent reduction in S02 emissions.  One exception was found
                                       31

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                     TABLE  10.   REGULATORY  ALTERNATIVES

                   Mixed  Fuel-Fired  Steam Generating  Uni^s


Baseline
Alternative I
Alternative II
Alternative III
Alternative IV
Steam Generating Unit Size
100 - 250
1
Baseline3 '
Baseline j
LSF i
.LSF
90% Red. |
(million Btu/hr)
>250
Baseline
LSFb '
LSF
90% Red.c . .
90% Red.
             .5  Ib  S02/million  Btu  (SIP
JLSF  =
= Low sulfur fuel  standard (1.2 Ib S0?/million
  0.8 Ib S00/million Btu for oil).
Btu for coal and
'%  Red.  =  Percent  reduction  requirement  (90%  SOp  removal).
                                      32

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in Region I when the price of the nonfossil fuel was assumed equal to that
of coal.  In this case the steam generating unit would switch to firing 100
percent oil.  It is generally not expected, however, that the price of
nonfossil fuel would ever be as high as the price of coal.  Consequently,
this one exception is considered to be highly unlikely and "fuel switching"
can be generally ruled out.                             ••
                                                        I
Analysis of Regulatory Alternatives                     i

     Table 12 summarizes the projected national impacts pf the four
regulatory alternatives selected for analysis.  The total annualized costs
shown assume a zero cost for nonfossil fuel.  As explained earlier in
Section 3.0, although the total annualized costs for each alternative would
be higher if the analysis was based on a non-zero cost fpr nonfossil fuel,
the incremental costs, or cost impacts, between regulatory alternatives
would remain the same.                                  |
     Table 12 shows that at the regulatory baseline the annualized costs for
mixed fuel-fired steam generating units are about $424.8! mill ion per year
and the annual SO- emissions are about 69,100 tons per year.  Under
Regulatory Alternative 1, annualized costs would be $445.9 million per year
with annual SOp emissions of 24,300 tons per year and an, average cost
effectiveness of $471/ton.  For Regulatory Alternative 2, annualized costs
would be $446.3 million per year and annual S0? emissions would be reduced
to 23,200 tons per year, for an average cost effectiveness of $468/ton.  The
incremental cost effectiveness of Regulatory Alternative 2 over Regulatory
Alternative 1  is $364/ton.                              '
     Under Regulatory Alternative 3, annualized costs would be about $470.0
million per year and annual emissions would be reduced t,o about 8,200 tons
per year.  Under Regulatory Alternative 4, annualized costs would be .$471.6
million per year with annual SO,, emissions of only 7,900 tons per year.
     The average cost effectiveness of Regulatory Alternatives 3 and 4 are
$742/ton and $765/ton, respectively.  The  incremental cost effectiveness of
Regulatory Alternative 3 over Regulatory Alternative 2 is $l,58.0/ton.  The
                                      34

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incremental cost effectiveness of Regulatory Alternative !4 over Regulatory
Alternative 3 is $5,333/ton.                             ,
     The high incremental cost effectiveness of Regulatory Alternative 4
over Regulatory Alternative 3 can be explained by examining the alternatives
themselves.  Under Regulatory Alternative 3, only steam generating units
with heat input capacities greater than 250 million Btu/hour" would be
required to achieve a percent reduction in SCL emissions.  Under Regulatory
Alternative 4, steam generating units with heat input capacities between 100
and 250 million Btu/hour would also be required to achieve a percent
reduction in SO- emissions.  As discussed in Section 2.0,; only five new
mixed fuel-fired steam generating units with heat input capacities in this
                                                         i
range are expected to be constructed in the five-year period ending in 1990.
On an annual basis, the potential emission reductions obtainable from these
mixed fuel-fired steam generating units with heat input capacities less than
250 million Btu/hour is quite small, even under a standard requiring a
percent reduction in S0? emissions.  In addition, aM .of i these units are
expected to fire very small amounts, of fossil fuel in relation to nonfossil
fuel (on the order of 20 percent).  As shown previously i"n Figures 1 to 3,
the incremental cost effectiveness -of achieving a percent reduction in S02
emissions over the use of low sulfur fuel is very high for steam generating
units firing 20 percent fossil fuel/80 percent nonfossil 'fuel mixtures.
     As discussed above, the amount of fossil fuel fired on an annual basis
compared to the rated annual heat input capacity for a particular steam
generating unit is referred to as the fossil fuel utilization factor.
Table 13 illustrates the relationship between incremental cost effectiveness
values and fossil fuel utilization factors.  A set of regulatory
alternatives was structured, ranging from establishing"an emission limit
based on the use of low sulfur fuel for all mixed fuel-fired steam
generating units to requiring all mixed fuel-fired steam generating units to
achieve a  percent reduction in S02 emissions.  Within this range were
alternatives requiring percent reduction for steam generating units with
fossil fuel utilization factors above 0.48 and the use of low sulfur fuels
for those  units with fossil fuel utilization factors of 6.48 or less;
                                      36

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percent reduction for steam generating units with fossil jfuel utilization
factors above 0.30 and the use of low sulfur fuel for units with fossil fuel
utilization factors of 0.30 or less; and percent reduction for steam
generating units with fossil fuel utilization factors above 0.12 and the use
of low sulfur fuel for units with fossil fuel utilization factors of 0.12 or
less.  '                                                     '
     As shown in Table 13, the incremental cost effectiveness of a percent
reduction requirement for steam generating units with fossil fuel
utilization factors above 0.48 over a low sulfur fuel requirement for these
steam generating units is $0/ton of SOp removed.  This is because no new
mixed fuel-fired steam generating units were projected to fire fossil fuel
                                                         I
in amounts exceeding 48 percent of their rated annual capacity; therefore,
no impacts were projected.  The incremental cost effectiveness of a percent
reduction requirement for steam generating units with fossil fuel
utilization factors above 0.30 and a low sulfur fuel requirement for units
with fossil fuel utilization factors of 0.30 or less, over a percent
reduction requirement-for only those units wit fossil fuel utilization
factors above 0.48, is $l,040/ton of SOp removed.  The incremental cost
effectiveness of a percent reduction requirement for steam generating units
with fossil fuel utilization factors above 0.12 and a low sulfur fuel
requirement for units with fossil fuel utilization factors of 0.12 or less,
over a percent reduction requirement for only those units with fossil fuel
'utilization factors above 0.30, is $l,460/ton of SO,, removed.  The
incremental cost effectiveness of requiring all mixed fuel-fired steam
generating units to achieve a percent reduction in SO,, emissions over a
percent requirement for only those units with fossil fuel; utilization
factors above 0.12 is $4,150/ton of S00 removed.
                                     38

-------

-------
                   5.0  CONSIDERATION OF EMISSION CREDITS;

     The S02 emissions resulting from the combustion of npnsulfur-bearing
fuels, such as wood, municipal solid waste, natural gas, land agricultural
waste products, are negligible.  In terms of S02 emissions, therefore, there
are environmental benefits associated with combustion of fuel mixtures
                                                         I
containing nonsulfur-bearing fuels.  Emissions of S02 from steam generating
units firing mixtures of coal or oil with nonsulfur-beari:ng fuels are lower
than emissions from coal- or oil-fired steam generating units operating at
the same heat input firing the same coal or oil.         j
                                                         I
     The existing NSPS for industrial-commercial-institutional steam
generating units with greater than 250 million Btu/hour heat input capacity
(i.e., 40 CFR Part 60 Subpart D) and existing SIP's provi.de "emission
credits" for mixed fuel-fired steam generating units.  An emission credit
for mixed fuel-fired steam generating units provides a "credit" toward the
emission limits or percent reduction requirements included in a standard for
the "dilution" of S02 emissions resulting from .combustion of sulfur-bearing
fossil fuels by the gases resulting from combustion of no!nsul fur-bearing
fuels.  Such an emission credit permits higher S02 emissions from mixed
fuel-fired steam generating units and results in the same level of emissions
from both a mixed fuel-fired steam generating unit and a 'fossil'fuel-fired
steam generating unit operating at the same heat input.  The difference in
S0? emissions mentioned above between these two types of Isteam generating
units is eliminated and, as a result, any environmental benefit is also
eliminated.                                              ;
     Table 14 illustrates how an emission credit for mixed fuel-fired steam
generating units would be incorporated into standards based on the use of
low sulfur fuel or standards requiring a percent reduction in SOp emissions.
The magnitude of the emission credit is determined by dividing the total
heat  input supplied to the steam generating unit by the heat input supplied
by the sulfur-bearing fossil fuel.                       '
     if standards based on the use of low sulfur fuels limited SO,, emissions
                                                                 <-
from  coal combustion to 1.2 Ib S0?/million Btu and from oil combustion to
                                      39

-------
                 TABLE 14.  CALCULATION OF MIXED FUEL-FIRED

                    STEAM GENERATING UNIT EMISSION CREDIT
A.   For a standard based on the use of low sulfur coal, (e.g., 1.2
     Ib/million Btu) an emission credit would allow the mixed fuel-fired
     steam generating unit to fire a higher sulfur coal.

     SCL Emission Limit Without Emission Credit =1.2 Ib/million Btu

     S02 Emission Limit With Emission Credit =

               1.2 ID/million Btu x (    Total Heat Input    }
                                      Fossil Fuel Heat Input

     Example:  For a 400 million Btu/hr heat input mixed fuel-fired steam
     generating unit operating at full capacity and firing a 50 percent
     coal/50 percent nonsulfur-bearing fuel mixture,

     SOy Emission Limit With Emission Credit =

               1.2 Ib/million Btu x 400 million Btu/hr = ^ Ib/m1ll1on Btu
                                    200 million Btu/hr


B.   For a standard requiring a percent reduction in S02 emissions, (e.g.,
     90 percent) an emission credit would allow the steam generating unit to
     operate the flue gas desulfurization system at a lower percent removal.

          S02 Percent Reduction Requirement Without Emission Credit =
               90 percent

          S09 Emissions Level Permitted = 100-90 = 10 percent
  *'          Lm

     SOp Percent Reduction Requirement With Emission Credit =

          100 - [10 Percent x    Total Heat Input    -,
                              Fossil Fuel Heat Input

     Example:  For a 400 million Btu/hr heat input mixed fuel-fired steam
     generating unit operating at full capacity and firing a 50 percent
     coal/50 percent nonsulfur-bearing fuel mixture,

     Percent Reduction Requirement With Emission Credit =

          100 Percent - [10 Percent x 400 million Btu/hr -, = 8Q
                                      200 million Btu/hr
                                      40

-------
0.8 1b SOp/million Btu, an emission credit would increase these emission
limits to the levels shown in Table 15.  Similarly, if standards required a
percent reduction in SCL emissions of 90 percent, an emission credit would
decrease this percent reduction requirement to the levels shown in Table 15.
     To assess the reasonableness of emission credits for mixed fuel-fired
steam generating units, the cost effectiveness of S0? control for these
systems was analyzed.  This analysis compared the cost effectiveness of S02
control for mixed fuel-fired steam generating units without emission credits
and the cost effectiveness of these same units with emission credits.  In
addition, the incremental cost effectiveness of S0? contrbl associated with
not providing emission credits for these systems was examined.
     Fuel pricing data are available only for low sulfur |fuels with specific
sulfur contents.  Thus, in order to use available fuel pricing data, this
analysis assumed an emission credit for coal/nonsulfur-bearing fuel mixtures
of:

     (1)  400 percent for 20 percent coal/80 percent nonsulfur-bearing fuel
          mixtures,                                      ">
     (2)  140 percent for 50 percent coal/50 percent nonsulfur-bearing fuel
          mixtures, and
     (3)  75 percent for 80 percent coal/20 percent nonsullfur-bearing fuel
          mixtures.
                                                         i
Similarly, for oil/nonsulfur-bearing fuel mixtures the following emission
credits were examined:

     (1)  400 percent for 20 percent oil/80 percent norisulfur-bearing fuel
          mixtures,
     (2)  100 percent for 50 percent oil/50 percent nonsulfur-bearing fuel
          mixtures, and
     (3)  100 percent for 80 percent oil/20 percent nonsulfur-bearing fuel
          mixtures.
                                      41

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        TABLE 15.   IMPACT OF.EMISSION  CREDITS  ON  SOg  EMISSION  LIMITS

                     AND PERCENT REDUCTION  REQUIREMENTS
Fuel Mixture
(Percent)
S02 Emission
Coal
Limit3
Oil
Percent Reduction
Requirement
20 Fossil/80 Nonsul fur-
bear ing fuel
50 Fossil/50 Nonsul fur-
bearing fuel
80 Fossil /20 Nonsul fur-
bear ing fuel
6.0

2.4

. 1,5

4.0

1.6

1.0

50

80

87-. 5

aSO« emission limit in Ib S0?/million Btu assuming an emission limit of
 1.2 Ib S0?/mi11ion Btu for a coal-fired steam generating unit and 0.8
 Ib S02/miTlion Btu for an oil-fired steam generating unit.

 Percent reduction requirement assuming a percent reduction  requirement
 of 90 percent for a coal-fired or oil-fired steam generating unit.
                                       42

-------
For standards requiring a percent reduction in SCL emissions, the emission
credits examined were:                                   !

     (1)  400 percent for 20 percent fossil fuel (coal or oil)/80 percent
          nonsulfur-bearing fuel mixtures (i.e., 50 percent SOp reduction),
     (2)  100 percent for 50 percent fossil fuel/50 percent '
          nonsulfur-bearing fuel mixtures (i.e., 80 percent SOp reduction),
          and
     (3)  25 percent for 80 percent fossil fuel/20 percent nonsulfur-bearing
          fuel mixtures (i.e., 87.5 percent SO,., reduction).

     Table 16 presents the cost and cost effectiveness of SOp control for a
400 million Btu/hour mixed fuel-fired steam generating unit firing coal as
the fossil fuel with an emission credit.  The costs and cost effectiveness
for this steam generating unit size were selected for analysis and
discussion because (1) the unit size is generally representative of mixed
fuel-fired units (with 15 of a total 35 projected new units in this size
range), and (2) new units in this size range are projected to fire the full
range of fossil/nonsulfur-bearing fuel mixtures.  Thus, tirends in costs and
cost effectiveness as a function of fuel mixture will be [illustrated.  In
addition to the analysis of 400 million Btu/hour mixed fuel-fired steam
generating units, a "worst case" analysis is presented at the end of this
section for a 150 million Btu/hour steam generating unit[firing a 20 percent
fossi1/80 percent nonsulfur-bearing fuel mixture in Region 1.
     As shown in Table 16, for a 400 million Btu/hour unit with an emission
                                                         j
credit, standards based on the use of low sulfur coal would result in no
reduction in S02 emissions in Region X.  .Similarly, standards based on the
use of  low sulfur coal would result in no reduction in SCL emissions for
mixed fuel-fired steam generating units firing a 20 percent coal/80 percent
nonsulfur-bearing fuel mixture in Regions I and IV.
     Table 17 shows the incremental cost effectiveness of not providing an
emission credit for coal/nonsulfur-bearing mixed fuel-fired steam generating
units.  The incremental cost effectiveness of the additional S0? emission
                                      43

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reductions achieved by not providing an emission credit ranges from $191/ton
to $397/ton in Regions I and IV.  There is little difference in this
incremental cost effectiveness of S02 control whether standards are based on
the use of low sulfur fuel or require a percent reduction in SO,, emissions.
     The incremental cost effectiveness is significantly higher in Region X
than in Regions I and IV.  Generally, it is in the range of $l,000/ton under
a standard based on the use of low sulfur coal, and ranges from $531/ton to
$l,068/ton under a standard requiring a percent reduction in SCL emissions.
As discussed in Section 3.0, this is primarily the result of the lower
emission reductions that exist between a medium and low sulfur coal in
Region X compared to emission reductions between a high and low sulfur coal
in Regions I and IV.
     Table 18 presents the cost and cost effectiveness of S02 control for a
400 million Btu/hour mixed fuel-fired steam generating unit firing oil as
the fossil fuel with an emission credit.  As noted above for mixed
fuel-fired steam generating units firing coal, with an emission credit, a
standard based on the use, of low sulfur fuel achieves no reduction in SOp
emissions for a mixed fuel-fired steam generating unit firing a 20 percent
oil/80 percent nonsulfur-bearing fuel mixture.
     Table 19 presents the incremental cost effectiveness of not providing
an emission credit for oil/nonsulfur-bearing mixed fuel-fired steam
generating units.  The incremental cost effectiveness of the additional SOg
emission reduction achieved by not providing an emission credit rarig.es from
$626/ton for a fuel mixture of 20 percent oil/80 percent nonsulfur-bearing
fuel to $926/ton for the fuel mixtures of 50 percent oil/50 percent
nonsulfur-bearing fuel and. 80 percent oil/20 percent nonsulfur-bearing fuel
under a standard based on the use of low-sulfur oil.
     With an emission credit, a mixed fuel-fired steam generating unit
firing a fuel mixture of 20 percent oil/80 percent nonsulfur-bearing fuel
fires a high sulfur oil.  A mixed fuel-fired steam generating unit firing a
fuel mixture of 50 percent oil/50 percent nonsulfur-bearing fuel or 80
percent oil/20 percent nonsulfur-bearing fuel, however, fires a medium
                                     46

-------


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-------
   TABLE 19.  INCREMENTAL COST EFFECTIVENESS O'F NOT PROVIDING AN EMISSION

             CREDIT FOR MIXED FUEL-FIRED STEAM GENERATING UNITS

                       FIRING OIL AS THE FOSSIL FUELa
                              Annualized
                                 Costs
                              ($l,000/yr)
                                           Annual
                                          Emissions
                                          (tons/yr)
             Incremental
          Cost Effectiveness
               ($/ton)
Low Sulfur Oil
20% Oil/80% Nonsulfur-Bearing Fuel
                                 8,353
                                 8,643
With Emission Credit
Without Emission Credit
50% Oil/50% Nonsulfur-Bearing Fuel

  With Emission Credit          12,037
  Without Emission Credit       12,426

80% Oil/20% Nonsulfur-Bearing Fuel

  With Emission Credit          15,540
  Without Emission Credit       16,162

Percent Reduction Requirement

20% Oil/80% Nonsulfur-Bearing Fuel
631
168
                                             840
                                             420
                                           1,346
                                             673
626
                926
                924
With Emission Credit 8,866
Without Emission Credit 8,960
50% Oil/50% Nonsulfur-Bearing Fuel
With Emission Credit 12,491
Without Emission Credit " 12,539
80% Oil/20% Nonsulfur-Bearing Fuel
With Emission Credit 16,063
Without Emission Credit 16,070
303
50
284
126
265
202
372
304
111
 400 million Btu/hr mixed fuel-fired steam generating unit.
                                      48

-------
sulfur oil.  Without an emission credit, a mixed fuel-fired steam generating
unit fires a low sulfur oil regardless of the fuel mixture.
     Consequently, the incremental cost effectiveness for mixed fuel-fired
steam generating units firing a 20 percent oil/80 percent1 nonsulfur-bearing
fuel mixture under a standard based on the use of low sulfur oil, with and
without an emission credit, is the difference between firing a high sulfur
oil versus a low sulfur oil.  For the other fuel mixturesjexamined, it is
the difference between firing a medium sulfur oil versus a low sulfur oil.
As a result, the incremental cost effectiveness of S02 control associated
with not providing an emission credit is higher for fuel fixtures of 50
percent oil/50 percent nonsulfur-bearing fuel and 80 percent oil/20 percent
nonsulfur-bearing fuel than it is for a fuel mixture of 20 percent oil/80
                                                         • i
percent nonsulfur-bearing fuel.
                                                         i
     As also shown in Table 19, the incremental cost effectiveness of S02
control resulting from the additional emission reduction associated with not
providing an emission credit under a standard requiring a1 percent reduction
in S02 emissions is quite low.  It is generally less than; $372/ton.
     This incremental cost effectiveness is lower than that cited above
under standards based on the use of low sulfur oil because of the "economies
of scale" associated "with FGD systems.  With or without an emission credit,
an FGD system must be installed to reduce S00 emissions. ! The only
                                            c.
difference is that with an emission credit, the system is'operated at a
lower level of performance than without an emission credit.  As a result,
the additional S02 emission reduction achieved by operating the system at a
high level of performance, as required without an emission credit, is very
cost effective.
     As discussed above, the costs and cost effectiveness; analysis for a 400
                                                         i
million Btu/hour mixed fuel-fired unit is considered representative of mixed
fuel-fired steam generating units in general and illustrates trends which
are a function of fuel mixture and regional location.  Costs and cost
effectiveness of S02 control for a 150 million Btu/hour mixed fuel-fired
steam generating unit with an emission credit firing a 20: percent coal/80-
percent nonsulfur-bearing fuel mixture in Region X and a 20 percent oil/80
                                     49

-------
percent nonsulfur-bearing fuel mixture in Region I are presented below.
This represents a "worst case" comparison in the sense that this combination
of relatively small mixed fuel-fired steam generating unit and high
percentage of nonsulfur-bearing fuel in the mixture results in the largest
emission credits and the highest cost effectiveness of SO,, control.  Other
cases involving either larger mixed fuel-fired steam generating units or a
higher fossil fuel content in the fuel mixture result in lower emission
credits and a lower cost effectiveness of SO,, control.  The results for
Region X are also presented for a mixed fuel-fired steam generating unit
firing coal because, of the three regions examined where mixed fuel-fired
steam generating units are expected to be constructed in significant
numbers, the coal prices in Region X result in the highest cost
effectiveness of S02 control.
     Table 20 presents the cost and cost effectiveness of SO,, control for a
150 million Btu/hour mixed fuel-fired steam generating unit firing 20
percent coal and 80 percent nonsulfur-bearing fuel with an emission credit.
This table shows that with an emission credit, standards based on the use of
low sulfur coal would result in no reduction in S02 emissions.  Thus, the
average cost effectiveness of S02 control for standards based on the use of
low sulfur'coal is $0/ton.  The average cost effectiveness of SO,, control
for standards requiring a percent reduction in emissions is $3,895/ton.  The
incremental cost effectiveness of S02 control for standards requiring a
percent reduction in emissions over standards based on low sulfur coal is
also $3,895/ton because the fuel fired under the regulatory baseline and
under standards based on the use of low sulfur coal are the same.
     Table 21 shows the incremental cost effectiveness of not providing an
emission credit for mixed fuel-fired steam generating units.  The
incremental cost effectiveness of not providing an emission credit for a
standard based on the use of low sulfur coal is $989/ton.  Similarly, the
incremental cost effectiveness of not providing emission credits for a
standard requiring a percent reduction in S02 emissions is $328/ton.
     Table 22 presents the cost and cost effectiveness of SO,, control for
mixed fuel-fired steam generating units firing oil as the fossil fuel with
                                      50

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-------
         TABLE 21.   INCREMENTAL COST EFFECTIVENESS  OF NOT  PROVIDING

       AN EMISSION  CREDIT FOR MIXED FUEL-FIRED STEAM GENERATING  UNITS

                          FIRING COAL IN REGION Xa


Low Sulfur Fuel
With Emission Credit
Without Emission Credit
Percent Reduction Requirement
With Emission Credit
Without Emission Credit
Annual ized
Costs
($l,000/yr)
3,587
3,677
3,922
3,944
Annual
Emissions
(tons/yr)
166
75
80
13
Incremental
Cost
Effectiveness
($/ton)
989
328
a!50 million Btu/hour mixed fuel-fired steam generating unit firing a
 20 percent coal/80 percent nonsulfur-bearing fuel  mixture.
                                      52

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                                                 53

-------
an emission credit.  As explained earlier, when an emission credit is
granted, a standard based on the use of low sulfur oil  results in no
reduction in S02 emissions.  Thus, the average cost effectiveness of a
standard based on the use of low sulfur oil is $0/ton.   The average cost
effectiveness of a standard requiring a percent reduction in S02 emissions
is $2,350/ton.  The incremental cost effectiveness of a standard requiring  a
percent reduction in SCL emissions over a standard based on the use of low
sulfur oil is $2,350/ton.
     Table 23 shows the incremental cost effectiveness  of not providing an
emission credit for mixed fuel-fired steam generating units firing oil as
the fossil fuel.  The incremental cost effectiveness of not providing
emission credits is $621/ton for standards based on the use of low sulfur
oil and $411/ton for standards requiring a percent reduction in SCL
emissions.
                                     54

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        TABLE 23.   INCREMENTAL COST EFFECTIVENESS  OF NOT PROVIDING

      AN EMISSION  CREDIT FOR MIXED FUEL-FIRED STEAM GENERATING UNITS

                      FIRING OIL AS THE FOSSIL FUEL3


Low Sulfur Oil
With Emission Credit
Without Emission Credit
Percent Reduction Requirement
With Emission Credit
Without Emission Credit
Annual ized
Costs
($l,000/yr)
3,713
3,821
4,002
4,041
Annual
Emissions
(tons/yr)
237 :
63
i
114
19
Incremental
Cost
Effectiveness
($/ton)
621
411
150 million Btu/hour mixed fuel-fired steam generating unit firing a
20 percent oil  and 80 percent nonsulfur-bearing fuel  mixture.
                                    55

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-------
                               6.0  REFERENCES
1.   National Council  of the Paper Industry for Air and Stream Improvement,
     Inc.  The Fuel  Mix and Operating Characteristics of .Power Boilers
     Capable of Firing Wood Residues.  Special Report No.' 81-14.   New York,
     NY.  November 1981.  p. 13.                         !

2.   Letter from Pinkerton, J. E., National Council of the Paper  Industry
     for Air and Stream Improvement, Inc., to Pahl, D., E.PA:SDB.   February
     15, 1985.  2 p.  Combination Boiler Installations at Pulp and Paper
     Mills for the 1980-1984 Period.

3.   U.S. Environmental Protection Agency.  Nonfossil Fuel Fired  Industrial
     Boilers - Background Information.  Research Triangle Park, NC.
     Publication No. 450/3-82-007.  March 1982.  pp. 9-28 - 9-32.

4.   U.S. Environmental Protection Agency.  Industrial Boiler S0? Cost
     Report.  Research Triangle Park, NC.  Publication No. 450/3-85-011.
     November 1984.   p. 3-4.

5.   Reference 4, p. 2-24.
                                                         i
6.   Memo from Murin,  P. J., and K. Barnett, Radian Corporation,  to
     Nonfossil Fuel-Fired Boilers File, June 22, 1982.  Emission  Control
     Specifications  and Model Boiler Cost Estimating,  pp. 30-33, 42-48.

7.   Memo from Short,  R., EPA:EAB to L. Jones, EPA:SDB, December  29, 1983.
     Annualized Fuel Prices by Region on a Before-Tax and After-Tax Basis
     and Factors for Converting Before-Tax Costs to an After-Tax  Basis.

8.   Letter from Hogan, T., Energy and Environmental Analysis, Inc., to R.
     Short, EPA:EAB.  November 7, 1984.  5 p.  After-Tax |Net Values of
     Industrial Fuel Prices.
                                       56

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-------
                         APPENDIX A
COST DEVELOPMENT FOR MIXED FUEL-FIRED STEAM  GENEiRATING  UNITS

-------

-------
         COST DEVELOPMENT FOR MIXED FUEL-FIRED STEAM GENERATING UNITS
                                                        l


                                                        I

A.  Fuel Characteristics                                !
                                                        I


- Wood Characteristics                                  ;



     H = 4,560 Btu/lb                                   i

     % S = 0.02                                         i

     % A = 1.0                                          '



-  Coal Characteristics                                 :

                                                        i
                                                        i
     Depends on which coal is fired.                    >



-  Mixture Characteristics



     Calculated on a heat input-basis



     Wood Feed Rate (Ib/hr) = Q (% Wood)
                                M
                                 wood

     where Q = Total Heat Input (106 Btu/hr)

           H = Heat Value (Btu/lb)



     Coal Feed Rate (Ib/hr) = Q (% Coal)

                                Hcoal                   '
                                                        |
                                                        I
     Total Fuel Feed Rate (Ib/hr) = Wood Feed Rate + Coal  Feed Rate.

                                                        I

-  Heating Value of Mixture                             i
                                     A-l

-------
     Hmix (Btu/lb) = (Wood Feed Rate)(HWQod) + (Coal Feed Rate)(HCQal)


                                Total Fuel Feed Rate (Ib/hr)



- Sulfur Content of Mixture




     S .„ (%) = (Wood Feed Rate)(S    .) +  (Coal Feed Rate)(Scoal)
      mix
                           Total Fuel Feed Rate  (Ib/hr)


     where S = Sulfur Content (%)




- Ash Content of Mixture




     Am1x (%) = (Wood Feed Rate)(AwQod) +  (Coal  Feed  Rate)(Acoa1)


                          Total  Fuel  Feed  Rate  (Ib/hr)


     where A = Ash Content (%)




B.  Flue Gas Flowrate




     FLWcoal (ACFM)  = Exp [8.14 x  1(T5  Hcoa1] x 1.84  x  106 Q/HCQal
      FLW    _,a  (ACFM)  =   73,500 acfm @. 150 million Btu/hr
        wood
                        196,000 acfm @ 400 million Btu/hr


                        392,000 acfm @ 800 million Btu/hr
      FLWmix (ACFM)  = (% Wood)(FLWwood}  + {



      where % Wood = percent of total  hea-t input supplied by wood.




           • % Coal = percent of total  heat input supplied by coal.
                                      A-2

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C.  Capital Costs

-  Steam Generating Unit

     Calculated based on information found in Reference 6.  All steam
                                                        i
     generating units are spreader stokers.             j

-  Particulate Matter Control

     Fabric filter for coal/nonfossil mixture.  Venturi scrubber for
                                                        i
     oil/nonfossil mixture.  Costs for PM control based on algorithms
     presented in Reference 4, Appendix A.  These costs are based on the fuel
                                                        i
     mixture characteristics.

- S02 Controls

     Sodium scrubbing used for coal and oil/nonfossil -mixtures.  Costs for S0
                                                        i              •
     control based on algorithms presented in Reference 4, Appendix A.  These'
     costs reflect the flexibility to achieve 90 percent; removal for a fully
     fired coal or oil steam generating unit.           |

D.  Operating and Maintenance Costs

-  Steam Generating Unit

     Based on information ..found in Reference 6.  Solid waste costs calculated
     from spreader stoker algorithm in Appendix A of Reference 4.

-  Particulate Matter Control
                                                        i
     Fabric filter and venturi scrubber costs calculated from algorithms in
     Appendix A of Reference 4.
                                     A-3

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     S02 Control

     Sodium scrubbing costs calculated from algorithms in Appendix A of
     Reference 4.

E.   Annualized Costs

     Calculated as shown in Table 2-8 of Reference 4.

F.   After Tax Costs

     Table A-l presents the after tax fuel prices used in this analysis,
     The after tax costs were calculated as explained in Reference 7.

G.   Uncontrolled Emissions

     For coal/nonfossil mixtures use mixture characteristics in AP-42
     equation for coal.

     For oil/nonfossil mixtures

     Emissions = (% Wood)(AP-42)WQod + (% Oil)(AP-42)Qll

aTaken from Reference  3, p. 8-8..
                                      A-4

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     TABLE A-l.  AFTER-TAX NET PRESENT VALUES OF INDUSTRIAL FUEL PRICES'
                               (S/MILLION BTU)

Fuel Type
Natural Gas
High Coal Penetration
Low Coal Penetration
Residual Oil
High Coal Penetration
3.0 Ib S02/106 Btu
1.6 Ib S02/106 Btu
0.8 Ib S02/106 Btu
0.3 Ib S02/106 Btu
Low Coal Penetration
3.0 Ib S02/106 Btu
1.6 Ib S02/106 Btu
0.8 Ib S02/106 Btu
0.3 Ib S02/106 Btu
Coal
Bituminous
B
D
E
F
' G
H
Subbituminous
B
D
E

I

25.45
22.59

23.93
25.59
27.52
29.36

18.27
19.49
20.92
22.34


14.00
13.86
13.60
12.85
11.90
12.18

-
-
-
Region
IV

25.68
23.10

23.82
25.49
27.42
29.35

18.15
19.38
?lo.80
22.21


11.99
11.24
11.16
10.83
' 10.43
9.78

•, -
-
; -

X

22.77
21.56

22.18
23.85
25.94
27.71

16.58
17.82
19.34
20.61


11.79
11.10
10.51
-
-
-

9.87
9.64
7.78
Taken from Reference 8.
                                    A-5

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                                   TECHNICAL REPORT DATA
                            (Please read Instructions on the reverse before completing)
  REPORT NO.
                              2.
                                                            3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
  An Analysis  of  the Costs and
  Control for  Mixed Fuel-Fired
                                 Cost Effectiveness of  S02
                                 Steam Generating Units
                                5. REPORT DATE
                                       June  1986
                                6. PERFORMING ORGANIZATION CODE
 . AUTHOR(S)
   Radian Corporation
   Research Triangle Park.
                                                            8. PERFORMING ORGANIZATION REPORT NO.
North Carolina
9. PERFORMING ORGANIZATION NAME AND ADDRESS
  Office of Air Quality Planning  and Standards
  U.S.  Environmental Protection Agency
  Research Triangle Park, North Carolina  27711
                                10. PROGRAM ELEMENT NO.
                                11. CONTRACT/GRANT NO.

                                   '  68-02-3816
12. SPONSORING AGENCY NAME AND ADDRESS
   DAA  for  Air Quality Planning  and  Standards
   Office of Air and Radiation
   U.S.  Environmental Protection Agency
   Research Triangle Park, North Carolina  27711
                                13. TYPjj pF REPORT AND PERIOD COVERED
                                     l-inal
                                14. SPONSORING AGENCY CODE
                                     EPA/200/04
15. SUPPLEMENTARY NOTES
16. ABSTRACT          ~~~ "	'	"	—	—	>	
       This  document presents an analysis  of the costs and cost  effectiveness of
  S02 control  for steam generating  units firing mixtures of'sulfur-bearing fossil
  fuels  (coal  or oil) with nonsulfur-bearing fuels (wood, solid  waste,  natural
  gas, etc.).   The incremental cost effectiveness of an alternative  control  level
  requiring  a  percent reduction in  S02  emissions over an alternative control  -level
  based  on the use of low sulfur fuel was  examined for various boiler sizes,
  regional locations, and fuel mixtures.   The incremental cost effectiveness
  increases  as decreasing amounts of coal  or oil are burned !in relation to
  nonsulfur-bearing fuels.
       The report also examines the costs  associated with allowing versus  not
  allowing emissionicredits based on the dilution of the sulfur-bearing fuel  heat
  input  with that from nonsulfur-bearing fuels.              \
                               KEY WORDS AND DOCUMENT ANALYSIS
                  DESCRIPTORS
  Air pollution
  Pollution control
  Standards of performance
  Fossil fuel-fired  industrial boilers
  Mixed fuel-fired industrial boilers
  Steam generating units
 8. DISTRIBUTION STATEMENT

  Release unlimited
                                              b.lDENTIFIERS/OPEN ENDED TERMS
                   Fossil fuel-fired
                      industrial  boilers
                   Air pollution  control
                   Mixed fuel-fired
                      industrial  boilers
                  19. SECURITY CLASS (This Report!
                        Unclassified
                                              20. SECURITY CLASS (This page)
                                                    Unclassified
                                                                         c. COSATI F'ield/Group
                                                                           13 B
                                                                        21. NO. OF PAGES
                                                                              64
                                             22. PRICE
EPA Form 2220-1 (Rev. 4-77)
                      PREVIOUS SOI TION iS OBSOLETE

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