p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

10) ll-K-(A)-23 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:48 AM Sheet 10 of 325 
P.2 

'- i 

A-83-27 

II-K-(A)-23 

DISTRIBUTION OF LARGE INDUSTRIAL BOILER SO2 EMISSIONS 

CONTROL COST-EFFECTIVENESS RATIOS 

Prepared for: 

U.S. ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

Research Triangle Park, North Carolina 27711 

Prepared by: 

ENERGY AND ENVIRONMENTAL ANALYSIS, INC, 

1655 North Fort Myer Drive 

Arlington, Virginia 22209 

April 5, 1985 
P.3 

This report was furnished to the U.S. Environmental Protection Agency 

by Energy and Environmental Analysis, Inc., Arlington, Virginia, 1n fulfillment of Contract Number 68-02-4202. The contents of this report are 

reproduced herein as received from the contractor. 

The opinions, findings, and conclusions expressed are those of the 

author and not necessarily those of the U.S. Environmental Protection 

Agency. 
IFCAM projections of total annualized costs and SO2 emissions from 

large new industrial fossil fuel-fired boilers can be used to derive 

average SO2 emissions control cost-effectiveness (C-E) ratios (increase 

in total annualized costs/reduction in total SO2 emissions). Table 1 

presents four alternative SO2 emissions control levels. Table 2 summarizes IFCAM projections for each of these control levels. The purpose 

of this report is to define the distribution of the average C-E ratios 

listed in Table 2. 

BACKGROUND 

The distribution of SO2 emissions control C-E ratios is a function 

of: 

- regional variability in SIP's and in projected industrial fuel 

prices 

- economies of scale in pollution control equipment costs related 

to boiler size and annual capacity utilization rates 

- "fuel switching" from residual fuel oil or coal combustion 

under an alternative control level to natural gas combustion 

under a different (more stringent) control level. 

Table 2 indicates that fuel switching is a significant factor. The 

number of new large industrial residual fuel oil and coal boilers is 

smaller under all three alternative SO2 NSPS than it is under the regulatory baseline. In general, a boiler which switches fuel types (from 

residual fuel oil or coal to natural gas) has a lower SO2 emissions control C-E ratio than a boiler which selects the same fuel type under both 

SO2 NSPS assumptions. The boiler which switches fuels has a relatively 

smaller cost increase (in some cases, a negative cost impact) and a larger SO2 emission reduction (switching from coal or residual fuel oil to 

natural gas results in a larger SO2 emission reduction than adding a 

scrubber; a scrubber reduces SO2 emissions by 50-90 percent, whereas 

switching to natural gas reduces SO2 emissions by 99.9 percent). 

In some cases, switching from coal, a capital-intensive alternative, under the regulatory baseline to natural gas under the alternative 

SO2 NSPS can result in a negative cost impact (the total before-tax 

levelized cost of a new industrial coal-fired boiler under the regulatory 

baseline is less than the total before-tax levelized cost of a new 
P.5 

TABLE 1. ALTERNATIVE SO2 NSPS FOR 

INDUSTRIAL FOSSIL FUEL-FIRED BOILERS 

Alternative 

control 

level 

Residual fuel oil Coal 

Boiler 

size 

category Ceiling Required Ceiling3 Required 

(MMBtu/hr) (lb/MMbtu) % reduction (lb/MMBtu) % reduction 

Regulatory 

baseline >250 

0.8/1.2 

0.3/0.6 

90% 

>100 

>100 

>100 

0.8 

0.8 

0.3 

0.3 90c 

1.2 

1.2 

0.6 

0.6 

- -

— 

>50b 

90d 

a30-day rolling average. 

bAll coal types in IFCAM must be scrubbed to comply with (but no lower than) 

the ceiling emission rate. 

cScrubbing (with a 90 percent reduction in SO2 emissions) is required only 

if the uncontrolled emission rate is larger than 0.3 lb S02/MMBtu. 

Scrubbing (with 90 precent reduction in SO2 emissions) is required for all 

coal types in IFCAM. 

-2-
TABLE 2. COMPARISON OF IFCAM PROJECTIONS FOR 1990a 

Regulatory 

baseline 

Alternative SO? NSPS 

0.8/1.2 0.3/0.6 90* 

CJ 

I 

SO2 emissions (IO3 short tons) 

Annualized costs0 (IO6 1982 $) 

279 

3,349 

Average incremental SO2 emissions control 

cost-effectiveness 

(1982 $/short ton) 

Number of new residual fuel oil 

boilers 

Number of new natural gas boilers 

Number of new coal boilers 

417 

170 

176 

106 

3,406 

329c 

39 

3,476 

l,045d 

16 

3,482 

844d 

320 

273 

11* 

245 

347 

129 

193 

399 

129 

aNew industrial fossil fuel-fired boilers installed between 1985 and 1990 and each larger than 

100 MMBtu/hr (total of 604). Reference price scenario. 

°Includes boiler and pollution control equipment capital, 0&M and fuel costs. 

cIncrement from the regulatory baseline; based on 251 boilers between 100 and 250 MMBtu/hr 

the regulatory baseline run. 

increment from the "0.8/1.2" run. 

eIn the 0.8/1.2 run, five of these switch to residual fuel oil and one to coal. 

^In both 0.-3/0.6 and 90% runs, seven of these switch to natural gas. 

9Eight of these units selected residual fuel oil under the 0.8/1.2 SO2 NSPS assumptions --

fuel switching from residual fuel oil to coal. The other four units selected coal in the 

0.8/1.2 run. 

in 
industrial natural gas boiler). Coal is selected under the regulatory 

baseline because it is the least-cost fuel type on an after-tax basis. 

Natural gas can be the least-cost fuel type on an after-tax basis under 

the alternative SO2 NSPS assumptions. The fuel choice decision is made 

based on a comparison of after-tax costs. The aggregate costs are reported on a before-tax basis. As a result, the alternative NSPS assumption can sometimes cause a cost increase on an after-tax basis (the total 

after-tax cost of natural gas is larger than the total after-tax cost of 

coal under the regulatory baseline) and a cost decrease on a before-tax 

basis. 

The annualized costs presented in Table 2 are shown on a before-tax 

basis. The average SO2 emissions control C-E ratios in Table 2, therefore, can be a weighted average of both positive and negative cost-effectiveness ratios. 

The projected SO2 emissions reductions are due to scrubbing, switching to natural gas, or switching to lower sulfur residual fuel oil and 

coal types. The average SO2 emissions control C-E ratios listed in 

Table 2 reflect several pollution control strategies and a wide range of 

boiler sizes (125-325 MMBtu/hr) and annual capacity utilization rates 

(25-75 percent) and SIP's and, as such, may not correspond with example 

model boiler C-E ratios. 

0.8/1.2 

Table 2 shows that there are projected to be 434 new large industrial residual fuel oil or coal boilers under the regulatory baseline 

SO2 NSPS assumptions. Recall from Table 1 that the SO2 NSPS assumptions 

are identical for the regulatory baseline and the "0.8/1.2" alternative 

control level when the boiler size is larger than 250 MMBtu/hr. Therefore, not all 434 new large industrial residual fuel oil or coal boilers 

under the regulatory baseline are subject to cost increases and SO2 

emissions reductions under the 0.8/1.2 alternative control level; only 

362 of these 434 new large units are between 100 and 250 MMBtu/hr-and 

only 251 of these 362 new units are subject to tighter SO2 emissions 

limits under the 0.8/1.2 alternative control level (because some new 

units are subject to low sulfur SIP's). 

-4-
P.8 

Figure 1 presents the distribution of incremental SO2 emissions 

control C-E ratios for these 251 units. Fuel switching (C0DE=1) occurs 

for 108 units; 143 units reduce SO2 emissions without changing fuel 

types (C0DE=0). The incremental C-E ratios range from $-466 to 

$l,369/short ton (1982 $) . 

In Figure 1, note the incremental C-E ratio category of $200-

400/short ton. There are 88 new industrial boilers in this category; 61 

units switched fuel types (C0DE=1) between the regulatory baseline and 

0.8/1.2 runs and 27 units did not change fuel types (C0DE=0). This is 

an example of how to interpret the bar charts. 

Some of the new industrial boilers (100-250 MMBtu/hr) which 

selected residual fuel oil in the regulatory baseline and 0.8/1.2 runs 

switched from a high sulfur residual fuel oil type (which requires 

staged combustion air to control N0X emissions under the proposed NSPS) 

to low sulfur residual fuel oil (which requires low excess air to 

control N0X emissions under the proposed N0X NSPS) in the 0.8/1.2 run.* 

Low excess air (LEA) is less expensive than staged combustion air (SCA). 

Therefore, alternative SO2 NSPS can result in higher fuel costs and 

lower N0X emissions control costs. This situation also occurs in 

switching from high sulfur residual fuel oil to natural gas and from 

coal to natural gas. As a result, the increased costs of the 

alternative SO2 NSPS are offset, to some extent, by reduced N0X 

emissions control costs. 

Figure 1 shows that six new industrial boilers, which did not 

change fuel types, have negative incremental C-E ratios. These six 

units selected residual fuel oil under the regulatory baseline and 

0.8/1.2 SO2 NSPS assumptions. All six units switched to lower sulfur 

content residual fuel oil types with five boilers switching from SCA to 

LEA to control N0X emissions. Four boilers selected scrubbers under the 

regulatory baseline and the 0.8/1.2 SO2 NSPS assumptions, but the 

scrubber capital and 0&M costs were smaller in the 0.8/1.2 run. --One 

unit selected a scrubber for the regulatory baseline and a compliance 

•This type of fuel switching, from one residual fuel oil type to another 

residual fuel oil type, is labelled C0DE=0 (not C0DE=1) in Figures 1, 2 

and 3. 

•5-
t 

1 

a. 

i 

FBEQUBMCI 

80 • 

70 • 

60 • 

SO * 

40 • 

30 • 

20 • 

1 

( » 

10 • 

FIGURE 1 

Distribution of Incremental 

0.8/1. 2 Run 

11111 

11111 

m n 

m n 

11111 

11111 

m n 

m n 

11111 

m n 

m i l 

m n 

m n 

m n 

m n 

m n 

jtii i 

m i l 

m n 

11111 

m n 

11111 

11111 11111 

11111 m n 

m n mi l 

m n 11111 

11111 11111 

11111 11111 

11111 11111 

11111 11111 

11111 ooooo 

11111 ooooo 

11111 ooooo 

m n ooooo 

11111 ooooo 

m n ooooo 

11111 11111 ooooo 

m i l 11111 ooooo 

11111 mi l ooooo 

11111 11111 ooooo 

11111 11111 ooooo 

ooooo ooooo ooooo 

ooooo ooooo ooooo 

ooooo ooooo ooooo 

< 0 0-200 200-400 

SO2 Emissions 

(1982 $/short 

ooooo 

ooooo 

ooooq 

ooooo 

ooooo 

ooooo 

ooooo 

ooooo 

ooooo 

ooooo 

Control 

ton) 

ooooo 

ooooo 

ooooo 

OQOOP 

ooooo 

ooooo 

ooooo 

qoooo 

ooooo 

ooooo 

ooooo 

ooooo 

ooooo 

ooooo 

OQOOO 

000-600 600-800 

C-E Ratios 

ooooo 

OOQQO 

ooooo 

OQOOO 

OOOOO 

ooooo 

OOOOO 

OQOQO 

OOQQO 

OOQOQ 

ooooo 

OOOOO 

ooooo 

OQOQO 

OQOOO 

OQOQO 

QOQQfl 

OQOQO 

ooooo 

•800-1Q0O 

QOOOO 

qoooo 

ooooo 

1000-1200 

' 

ooooo 

OOOOO 

ooooo 

OOQOQ 

OQOOO 

OOQOO 

OQOOQ 

iiboVvioo 
P.10 

residual fuel oil type for the 0.8/1.2 run. Another unit selected a SO2 

SIP compliance residual fuel oil type with an ESP (because of the PM 

emissions SIP) for the regulatory baseline and a low sulfur residual 

fuel oil type without an ESP for the 0.8/1.2 run. For one reason or 

another, total capital costs were smaller under the 0.8/1.2 SO2 NSPS 

assumptions. Switching from SCA to LEA (in five of the six cases) with 

lower N0X emissions control costs and lower total capital costs offset 

higher fuel costs and, as a result, these units are credited with 

negative before-tax incremental C-E ratios. 

0.3/0.6 

Figure 2 presents the distribution of incremental SO2 emissions 

control C-E ratios for 319 large (>100 MMBtu/hr) new industrial boilers 

which selected residual fuel oil or coal under the 0.8/1.2 SO2 NSPS assumptions (see Table 2). Figure 2 presents a comparison of the 0.3/0.6 

and 0.8/1.2 run results. Fuel switching (C0DE=1) occurs in 82 of the 

319 cases. The range of incremental C-E ratios in Figure 2 is $-751 to 

$3,423/short ton. 

There are 319 units in Figure 2 whereas there are only 251 units in 

Figure 1. All but 12 of the 331 new residual fuel oil and coal boilers 

in the 0.8/1.2 run are included in Figure 2. Not nearly all (only 251 

of the 434) of the new residual fuel oil and coal boilers in the regulatory baseline run are included in Figure 1 (as explained earlier). 

Footnote g in Table 2 explains that eight boilers switch fuel types 

from residual fuel oil under the 0.8/1.2 SO2 NSPS assumptions to coal 

under the 0.3/0.6 SO2 NSPS assumptions. These eight units have relatively large ($2,662-3,423/short ton) incremental C-E ratios in Figure 

2. The fuel switching situation discussed in the BACKGROUND section is 

switching from coal to natural gas. These eight units represent the 

opposite case -- switching to coal. In this case, the SO2 emission reduction is relatively small (25 percent, from 0.8 to 0.6 lb S02/MMBtu), 

but the before-tax annualized cost increase is large. 

There are two residual fuel oil boilers (C0DE=0) with negative incremental C-E ratios in Figure 2. They both selected to scrub 1.6 percent sulfur residual fuel oil (requiring SCA) in the 0.8/1.2 run and 

burn 0.3 percent sulfur residual fuel oil (requiring LEA) in the 0.3/0.6 

-7-
-8-

O 

b* 

o 

• • • 

o 

• + • 

in 

o 

• + • 

9. 

O 

• + • 

00 

o 

*-a 

o 

• +-

JO 

m 

o 

< 

o 

I OOOOOOOOOOOOOOOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOOOOOOOOOOOOOOO ! 

o 

I 

(J*. 

o 

ISI 

-J 

cr 

c 

o 

-h 

o _ 

OJ 

cn 

o 

-J 

a> 

n 

o 

OOOOOOO O 

OOOOOOO O 

OOOOOO O 

OOOOOO O 

o o o o o oo o 

! o o o o o o 

ro _ S i 

IS» 

o 

to 

- J 

o 

o 

I 

IM 

o 

V 

*\> 

OOOOOOO O OOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOO ! 

OOOOOOOOOOOOOOOO ! 

O O O O O I 

OOOOO ! ! O O O i 

O O O 

o 

I 

JO 

0> 

o 

OOOOOOOI — »-•— ooooooo*-*-* -

OOOOOOOr-r-l -

OOOOOOO*-*-*- * 

ll' d 
P.12 

run. These two units have tight residual fuel oil PM emissions SIP's. 

In the 0.8/1.2 run, they selected ESP's and scrubbers with about a 50 

percent SO2 emissions removal rate. In the 0.3/0.6 run, they selected 

0.3 percent sulfur residual fuel oil (without ESP's or scrubbers). The 

incremental before-tax C-E ratios are negative because they are going 

from a capital-intensive (ESP's and scrubbers) compliance alternative to 

a "clean" fuel option (with more expensive fuel costs and lower N0X 

emissions control costs). 

In Figure 2, there are three units which switched fuel types 

(C0DE=1) and incurred negative incremental C-E ratios. All three units 

switched from coal in the 0.8/1.2 run to natural gas in the 0.3/0.6 run. 

90S 

Figure 3 presents the distribution of incremental SO2 emissions 

control C-E ratios for all 331 large ( 100 MMBtu/hr) new industrial 

boilers which selected residual fuel oil or coal under the 0.8/1.2 SO2 

NSPS assumptions (see Table 2) . Figure 3 represents a comparison of the 

90% and the 0.8/1.2 run results. Fuel switching (C0DE=1) occurs in 134 

of the 331 cases. The range of incremental C-E ratios is $-1,367 to 

$3,118/short ton (1982 $) . 

Figure 3 also shows eight units which have relatively large incremental C-E ratios ( $2,000/short ton) and switched fuel types (from residual fuel oil in the 0.8/1.2 run to coal in the 90% run). This also 

occurs in Figure 2. 

Figure 3 is different from Figures 1 and 2 in two respects: 

• All of the boilers in Figure 3 with negative incremental C-E 

ratios switched fuel types; this is not true for Figures 1 and 

2. 

• There are some boilers in Figure 3 which switched fuel types 

with incremental C-E ratios between $600 and $l,200/short ton; 

this is not true for Figures 1 and 2. 

In Figure 3, 19 boilers switched to natural gas with negative incremental C-E ratios: three from coal and 16 from residual fuel oil. 

All 16 industrial residual fuel oil boilers needed ESP's in order to 

comply with tight PM emissions SIP's. A few of these also selected 

scrubbers with about a 50 percent SO2 emissions removal rate. These 

units selected natural gas, with no SO2 or PM emissions control equip-

• 9-
-oio 

*~ C IM 

O 

• + • 

b* 

O 

* + • 

O 

• * • 

o 

• + • 

-J 

o 

CD 

o 

• + • 

o 

• + • 

OOOOOOO O 

OOOOOOO O 

OOOOOOO O 

OOOOOOO O 

OOOOOOO O 

ooooooooo o 

ooooooooo o 

ooooooooo o 

ooooooooo o 

ooooooooo o 

OOOOOOO O 

OOOOOOO ! 

VO 

o 

15- * 

TO 

c 

CO 

ro 

(/> 

t/1 

<-t-

-J 

yml. 

ac 

rt* 

o 

3 

3 (-) 

•m 

a> 3 

a> 

3 

oo 

© 

ro 

o 

H. «•» 

ooooooooooeooooooo i 

OOOOOOOOOOOOOOOOOO l 

O O OOOOOOOOOOOOOOOO ! 

h OOOOOOOOOOOOOOOOOO l 

OOOOOOOOOOOOOOOOOO l 

oooooooooooooooo o 

oooooooooooooooo o 

oooooooooooooooo o 

oooooooooooooooo o 

oooooooooooooooo o 

ooooooooo o 

ooooooooo o 

ooooooooo o 

ooooooooo o 

ooooooooo o 

H 

cT ^ 

=. o ^ o 

3 

cf 

-J 

© 

o 

30 

OJ 

o 

O •— ••* y-. 

O r— *-* l-» 

O *•* .* »«. 

eid 
ment and slightly lower boiler capital costs, in the 90% run rather than 

full scrub with an ESP or full scrub a yery low sulfur residual fuel oil 

type. The incremental before-tax C-E ratios are negative because they 

moved from capital-intensive (ESP's and, in some cases, scrubbers) 

compliance alternatives to a "clean" fuel, natural gas. 

CONCLUSIONS 

t These distributions of incremental S0?_ emissions control C-E 

ratios for the Reference price scenario are wide, perhaps bimodal and include negative values. 

• The increased costs associated with alternative SO2 NSPS are 

offset, to some extent, by reduced N0X emissions control costs 

and differences associated with making fuel choice decisions 

in IFCAM on an after-tax basis and reporting costs on a 

before-tax basis. 

-11-