p.1 

OAR Box 1828 

Prepped by Ollie Stewart 

Document Number: 

322) IV-B-26 

Docket Number: 

A-83-27 

Printed 11/12/2008 11:12:59 AM Sheet 322 of 325 
P.2 

A-83-27 

IV-B-26 

^

£0Sr % UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

Office of Air Quality Planning and Standards 

K+M+J 532 Research Triangle Park, North Carolina 27711 

2 0 JUL 1987 

MEMORANDUM 

SUBJECT: Department of Energy (DOE) Comments on the Industrial Boiler 

NSPS (SO2) - Review of the Argonne National Lab (ANL) Report 

FROM: Fred Porter -^K~~~y.£ \-&<. 

Standards Development Branch (MD-13) 

TO: Docket #A-83-27 

THRU: Walt Stevenson 

Standards Development Branch (MD-13) 

SUMMARY 

Public comments submitted by DOE on the proposed new source performance 

standards (NSPS) limiting sulfur dioxide (SO2) emissions from new 

industrial-commercial-institutional steam generating units (i.e., boilers) 

included a report prepared by ANL assessing the cost effectiveness of 

emission control associated with various regulatory options for NSPS. 

The analysis in the ANL report is similar to that in the EPA model boiler 

analysis which examined the cost effectiveness of emission control associated with various regulatory alternatives for NSPS. Both analyses 

examine the cost effectiveness of emission control for specific coal-fired 

boilers under the assumption of no "fuel switching" (e.g., boilers firing 

coal switch to firing natural gas) in response to various regulatory 

options (i.e., the ANL report) or regulatory alternatives (i.e., the EPA 

analysis) for NSPS limiting SO2 emissions. 

The ANL report uses the same cost algorithms and generally uses 

the same coal types and coal prices as those used in the EPA model 

boiler analysis. There are, however, several differences in assumptions 

between the two analyses. This, in turn, results in somewhat different 

conclusions regarding the cost effectiveness of emission control, 

particularly with regard to the cost effectiveness of regulatory options/ 

alternatives for NSPS based on the use of low sulfur coal. 

The major difference between the ANL report and the EPA analysis 

concerns the availability of very low sulfur coals (i.e., those with 

emission levels of less than 1.2 lb SO2/MM Btu). The ANL report assumes 

very low sulfur coals with SO2 emission levels as low as 0.6 lb SO2/MM 

Btu are generally available or would become available in response to demand 

for such coals from new industrial-commervial-institutional boilers. The 

EPA analysis assumes very low sulfur coals are not generally available and 

would not become available as a result of the NSPS. 
P.3 

Thus, the two analyses are based on very different assumptions 

regarding the availability of >/ery low sulfur coals. The ANL report 

assumes such coals are available; and thus,assesses the cost effectiveness 

of regulatory options based on the use of such coals with emission 

limits as low as 0.6 lb S02/MM Btu. In contrast, the EPA analysis 

assumes such coals are not available and as a result is limited to 

assessing the cost effectiveness of regulatory alternatives based on 

the use of low sulfur coal with emission limits only as low as 1.2 

lb SO2/MM Btu. 

Another difference in basic assumptions between the ANL report and 

the EPA analysis concerns the annual costs of emission monitoring under 

the regulatory baseline. Both the ANL report and the EPA analysis 

assume that coal sampling and analysis would generally be used to 

monitor SO2 emissions under the regulatory baseline. The ANL report, 

however, assumes the costs associated with coal sampling and analysis 

are negligible. The EPA analysis, on the other hand, assumes they are 

significant and of the same order of magnitude as those associated with 

use of a continuous emission monitor. 

Both the ANL report and the EPA analysis, therefore, include costs 

for emission monitoring in regulatory options/alternatives based on the 

use of low sulfur coal. However, where the ANL report includes no costs 

for emission monitoring under the regulatory baseline, the EPA analysis 

includes such costs. 

As a result of this difference in assumptions regarding the costs 

of emission monitoring under the regulatory baseline, the incremental 

costs between regulatory options based on the use of low sulfur coal 

and the regulatory baseline are some $110,000 per year higher in the 

ANL report than the corresponding incremental costs in the EPA analysis. 

As one might expect, this has a major impact on the cost effectiveness 

of emission control. For a 100 MM Btu/hr boiler located in Region V, 

for example, this effectively increases the cost effectiveness of 

regulatory options based on the use of low sulfur coal in the ANL 

report by some $l,100/ton. 

Thus, where the EPA analysis concludes that the cost effectiveness 

of regulatory alternatives based on the use of low sulfur coal for a 100 

MM Btu/hr boiler located in Region V is in the range of $600/ton, the 

ANL report concludes the cost effectiveness is in the range of $l,900/ton. 

Adjusting the ANL costs to reflect the EPA assumption regarding the 

costs of emission monitoring under the regulatory baseline reduces the 

cost effectiveness in the ANL report to about $800/ton, which is comparable 

to that cited in the EPA analysis. 

Although the ANL report and the EPA analysis arrive at different 

conclusions regarding the cost effectiveness of regulatory options/ 

alternatives based on the use of low sulfur coal, this is not the case 

for regulatory options/alternatives requiring a percent reduction in 

emissions. In this area the two analyses reach similar conclusions. 

The ANL report, for example, estimates the cost effectiveness of options 

requiring a percent reduction in emissions over options based on the 
P.4 

use of low sulfur coal for a 100 MM Btu/hr boiler located in Region V 

as in the range of $l,900/ton. The EPA analysis estimates this cost 

effectiveness as in the range of $l,700/ton. 

In addition to examining the cost effectiveness of emission control 

associated with various regulatory options/alternatives for NSPS, both 

the ANL report and the EPA analysis examined the cost effectiveness of 

the additional emission reduction achieved by not providing emission 

credits for mixed fuel-fired boilers and boilers within cogeneration 

systems. In this area both analyses reached essentially the same 

conclusion, that is, the cost effectiveness is generally in the range 

of $300 - 400/ton. 

In summary, the ANL report and the EPA analysis reached quite 

different conclusions regarding the cost effectiveness of emission 

control associated with regulatory options/alternatives based on the 

use of low sulfur coal. Both analyses, however, reached essentially the 

same conclusions regarding the cost effectiveness of emission control 

associated with regulatory options/alternatives requiring a percent 

reduction in emissions, as well as the cost effectiveness associated 

with the additional emission reductions achieved by not providing 

emission credits for mixed fuel-fired boilers or boilers in cogeneration 

systems. 

While not specifically highlighted as a conclusion, the ANL report 

also leads to the conclusion that there is little difference in the 

cost effectiveness between regulatory options based on the use of low 

sulfur coal and regulatory options requiring a percent reduction in 

emissions. The cost effectiveness of either option is in the range of 

$l,900/ton. This is quite different from the conclusion reached in the 

EPA analysis that a significant difference exists in the cost effectiveness 

between these two regulatory alternatives. 

Considering only cost effectiveness, therefore, the ANL report 

leads to the conclusion that standards for industrial-commercialinstitutional boilers should require a percent reduction in emissions. 

The cost effectiveness of emission control is essentially the same 

whether these standards are based on the use of low sulfur coal or 

require a percent reduction. Emissions, however, are substantially 

lower if the standards require a percent reduction. 

The EPA analysis, on the other hand, does not necessarily lead to 

this conclusion. The cost effectiveness of emission control associated 

with standards requiring a percent reduction in emissions is significantly 

higher than the cost effectiveness of emission control associated with 

standards based on the use of low sulfur coal. Thus, the EPA analysis 

requires a judgment whether the higher cost effectiveness of emission 

control associated with standards requiring a percent reduction is 

reasonable. 
P.5 

COMPARISON OF THE ANL REPORT AND THE EPA ANALYSIS 

The approach employed in the ANL report is essentially the same 

as that employed in the EPA model boiler analysis. Both analyses 

examine the impacts associated with various regulatory options (i.e., 

the ANL report) or regulatory alternatives (i.e., the EPA analysis) in 

terms of model boilers located in various EPA Regions. Both analyses 

also use the same cost algorithms and generally use the same coal 

types and coal prices to estimate the costs associated with these 

regulatory options or alternatives. One might expect, therefore, that 

the two analyses would yield the same or very similar conclusions. A 

quick review of the two analyses, however, indicates that this is not 

the case, particularly with regard to the cost effectiveness associated 

with regulatory options or alternatives based on the use of low sulfur 

coal. 

Although the approach, including the cost algorithms and most of 

the coal types and coal prices are the same, there are a number of 

assumptions in the ANL report and the EPA analysis that differ, as shown 

in Table 1. Perhaps the most significant is that of the availability 

of low sulfur coals. The ANL report assumes tiery low sulfur coals, with 

SO2 emission rates as low as 0.6 lb SO2/MM Btu, are generally available; 

whereas, the EPA analysis assumes coals with such low emission rates are 

not generally available. 

The ANL report implicitly assumes that coal demand by new industrial 

boilers is sufficient to result in the application of coal washing to 

low sulfur bituminous and subbituminous coals to produce very low 

sulfur coals. Thus, although the ANL report initially adopts the same 

coal types and coal prices as the EPA analysis, it expands the number 

of coal types and coal prices by assuming that coal washing could be 

applied to these coals. This leads to a category of yery low sulfur 

coals in the ANL report which are capable of achieving emissions levels 

of 0.6 lb SO2/MM Btu. 

The EPA analysis, on the other hand, explicitly assumes that coal 

demand by new industrial boilers is not sufficient to result in significant 

changes in current coal production practices. Currently, coal washing 

is generally limited to eastern bituminous coals and is generally 

employed only to improve coal quality (i.e., lower ash level and increase 

heating value) or, in some cases, to produce low sulfur coals (i.e., 

coals capable of meeting emission limits of 1.2 lb SO2/MM Btu). Thus, 

coal washing is considered unlikely to be applied to low sulfur bituminous 

or subbituminous coals to produce ^/ery low sulfur coals (i.e., coals 

capable of meeting emission limits as low as 0.6 lb SO2/MM Btu) in 

response to coal demands by new industrial boilers. Consequently, the 

EPA analysis assumes that the lowest sulfur coal generally available to 

industrial boilers is capable of reducing emissions only to 1.2 lb SO2/ 

MM Btu. 

As a result of this difference in assumptions regarding the availability 

of very low sulfur coals, the ANL report is able to examine regulatory 

options based on the use of such coals with emission limits as low as 
TABLE 1 

Differences in Assumptions Between the ANL Report and the EPA Analysis 

ANL Report Assumptions 

1. Assumes coal demand from new 

industrial boilers sufficient 

to result in application of coal 

washing to low sulfur coal to 

produce very low sulfur coals. 

2. No costs for emission monitoring 

included under the regulatory 

baseline. 

3. Sulfur retention in the bottom 

ash is 5% and 15%, respectively, 

for bituminous and subbituminous 

coals. 

EPA Analysis Assumptions 

1. Assumes coal demand from new 

industrial boilers insufficient 

to change current coal washing 

practices; thus, application of 

coal washing limited to medium 

and intermediate sulfur coals 

to produce low sulfur coals. 

2. Costs for emission monitoring 

equivalent to the costs for a 

CEM included under the regulatory 

baseline. 

3. No sulfur retention in bottom 

ash assumed. 

Impact of Differences 

1. Permits ANL Report to examine 

options based on the use of 

very low sulfur coal (i.e., 

emission limits as low as 0.6 

lb SO2/MM Btu). 

2. Decreases costs under the regulatory baseline in the ANL Report, 

thus increasing the cost effectiveness of regulatory options. 

3. No impact on options based on 

the use of low or very low 

sulfur coal; but, results in 

lower emission reduction in 

ANL Report for options 

requiring a percent reduction, 

thus increasing the cost 

effectiveness of these options. 

cn 

4. To account for variabilty, RSD's 

of 10% and 20%, assumed for 

for washed and raw coals; no 

variability assumed in FGD 

performance. 

5. "Mixed" regulatory baseline of 

1.2 or 1.6 lb SO2/MM Btu. 

4. To account for variability, 

RSD of 20% assumed for coal 

and FGD performance. 

5. Single regulatory baseline 

of 2.5 lb SO2/MM Btu. 

4. Little or no impact on options 

based on low or very low sulfur 

coal; results in lower emission 

reduction in ANL Report for 

options requiring a percent 

reduction, thus increasing cost 

effectiveness of these options. 

5. Decreases emissions and increases 

costs in the ANL Report under the 

regulatory baseline; increases 

"average" cost effectiveness in 

ANL Report. 

Tl 
P.7 

0.6 lb SO2/MM Btu. In contrast, the EPA analysis is limited to examining 

regulatory alternatives based on the use of low sulfur coal with emission 

limits only as low as 1.2 lb SO2/MM Btu. It is not possible, therefore, 

to compare conclusions in the ANL report concerning regulatory options 

based on the use of very low sulfur coal with similar conclusions in 

the EPA analysis. The EPA analysis did not examine such alternatives. 

Beyond this difference in assumptions regarding the availability 

of very low sulfur coals, one reason for the apparent difference in 

conclusions between the ANL report and the EPA analysis is that the ANL 

report examined the average cost effectiveness of regulatory options 

compared to the regulatory baseline, but did not examine the incremental 

costs effectiveness among regulatory options. The EPA analysis examined 

the average cost effectiveness of various regulatory alternatives, but 

focused on examination of the incremental cost effectiveness among 

regulatory alternatives. 

Another reason is that the ANL report used a different regulatory 

baseline than the EPA analysis. The ANL report assumed the regulatory 

baseline requires the use of low sulfur coal (i.e., either 1.6 or 1.2 lb 

SO2/MM Btu) whereas the EPA analysis assumed the regulatory baseline 

permits the use of medium sulfur coal (i.e., 2.5 lb SO2/MM Btu). 

The impact of these later two factors can be overcome, however, by 

comparing the cost effectiveness between similar regulatory options and 

alternatives in the two analyses. Considering the case of a 100 MM 

Btu/hr boiler located in Region V, for example, the ANL report concludes 

that the cost effectiveness associated with a regulatory option requiring 

a 90 percent reduction in emissions over an option of 1.2 lb SO2/MM 

Btu, based on the use of low sulfur coal, is in the range of $l,900/ton 

of SO2. Similarly, the EPA analysis concludes that the cost effectiveness 

associated with a regulatory alternative requiring a 90 percent reduction 

in emissions over an alternative of 1.2 lb SO2/MM Btu, based on the use 

of low sulfur coal, is in the range of $l,700/ton of SO2. 

Thus, focusing on the cost effectiveness between similar regulatory 

options or alternatives essentially serves to reconcile the two analyses 

with respect to the cost effectiveness associated with options or 

alternatives requiring a percent reduction in emissions. 

This does not, on the other hand, serve to reconcile the apparent 

difference in conclusions between the two analyses regarding the cost 

effectiveness associated with regulatory options or alternatives based 

on the use of low sulfur coal. For the case cited above of the 100 MM 

Btu/hr boiler located in Region V, the ANL report concludes that the 

cost effectiveness associated with a regulatory option of 1.2 lb SO2/MM 

Btu over the regulatory baseline of 1.6 lb SO2/MM Btu is in the range of 

$l,900/ton. In contrast, the EPA analysis concludes that the cost 

effectiveness associated with a regulatory alternative of 1.2 lb SO2/MM 

Btu over an alternative of 1.7 lb SO2/MM Btu is about $600/ton. 

This discrepancy results in large part from the difference in 

assumptions between the ANL report and the EPA analysis regarding the 
P.8 

costs of emission monitoring under the regulatory baseline. The ANL 

report assumes that the costs associated with SO2 monitoring techniques 

currently used by many boilers under the regulatory baseline, such as 

coal sampling and analysis, are negligible. In addition, the ANL 

report also assumes that such techniques could not be used to monitor 

SO2 emissions under regulatory options based on the use of low sulfur 

coal. 

As a result, the ANL report assumes there are no costs associated 

with emission monitoring under the regulatory baseline. The cost of a 

continuous emission monitor is assigned to regulatory options based on 

the use of low sulfur coal and additional, although considerably lower, 

costs for a second continuous emission monitor are assigned to regulatory 

options requiring a percent reduction in emissions. (The second monitor 

is needed to determine the percent reduction in SO2 emissions achieved.) 

The EPA analysis, on the other hand, assumes that either coal 

sampling and analysis or continuous emission monitoring would be used 

to monitor emissions under all the regulatory alternatives examined. 

In the case of regulatory alternatives requiring a percent reduction in 

emissions, coal sampling and analysis could only be used to monitor SO2 

emissions prior to the flue gas desulfurization system, however. 

The EPA analysis also assumes that existing requirements to monitor 

SO2 emissions under the regulatory baseline, through the use of such 

techniques as coal sampling and analysis, are effective in generating 

useful and reliable data for accurately assessing emission levels from 

existing sources. (Note: If this were not the case, it would imply 

that enforcement personnel would be unable to effectively monitor the 

compliance status of existing sources and enforce existing regulations.) 

Studies have shown that the costs of coal sampling and analysis 

are generally of the same order of magnitude as the costs of a continuous 

emission monitoring system, if coal sampling and analysis is used to 

generate useful and reliable SO2 emission data. Thus, the EPA analysis 

assumes that the costs of SO2 monitoring techniques used by boilers 

under the regulatory baseline, such as coal sampling and analysis, are 

significant and that these costs are comparable to those of a continuous 

emission monitor. 

The EPA analysis, therefore, views the costs for a continuous 

emission monitor as representative of the costs of coal sampling and 

analysis. Consequently, these costs are assigned to the regulatory 

baseline as well as to regulatory alternatives based on the use of low 

sulfur coal. Costs for a second continuous emission monitor, with no 

"discount" as assumed in the ANL report, are assigned to regulatory 

alternatives requiring a percent reduction in emissions. 

It should also be noted in passing that the EPA analysis estimates 

the annual costs associated with a continuous emission monitor for SO2 

emissions as $50,000. Adding continuous emission monitors for opacity 

and nitrogen oxides (N0X) emissions increases this to about $110,000. 
P.9 

8 

The ANL report, on the other hand, estimates the annual costs of a 

continuous emission monitor for SO2 emissions as $110,000. Consequently, 

it appears the costs of emission monitoring in the ANL report associated 

with regulatory options based on the use of low sulfur coal actually 

represent the annual costs of monitoring particulate matter and N0X 

emissions, as well as the annual costs of monitoring SO2 emissions; 

inappropriate when attempting to assess the cost effectiveness associated 

with regulatory options for control of SO2 emissions. 

In any event, this difference in assumptions regarding the annual 

costs of emission monitoring under the regulatory baseline has a relatively 

small impact on the cost effectiveness associated with regulatory 

options or alternatives requiring a percent reduction in emissions. 

Due to the difference in the assumed costs of adding the second monitor, 

the total difference between the ANL report and the EPA analysis in 

annual monitoring costs is only about $17,000 between options or 

alternatives requiring a percent reduction in emissions and options or 

alternatives based on the use of low sulfur coal. 

This difference in assumptions has a major impact, however, on the 

cost effectiveness associated with regulatory options or alternatives 

based on the use of low sulfur coal. Due to the difference in assumptions 

regarding in the annual costs of emission monitoring under the regulatory 

baseline, the total difference between the ANL report and the EPA analysis, 

in the monitoring costs between regulatory options or alternatives based 

on the use of low sulfur coal and options or alternatives reflecting the 

regulatory baseline is $110,000. This significantly increases the annual 

costs associated with regulatory options based on the use of low sulfur 

coal in the ANL report and effectively increases the cost effectiveness 

in the ANL report by about $l,100/ton. Thus, it is responsible for most 

of the difference in conclusions between the ANL report and the EPA 

analysis regarding the cost effectiveness associated with regulatory 

options or alternatives based on the use of low sulfur coal. 

The ANL report and the EPA analysis, therefore, are generally in 

agreement with regard to the cost effectiveness associated with regulatory 

options or alternatives requiring a percent reduction in emissions. As 

illustrated by the above example for a 100 MM Btu/hr boiler located in 

Region V, both analyses conclude that the incremental cost effectiveness 

associated with such options or alternatives over options or alternatives 

based on the use of low sulfur coal is in the same general range (i.e., 

$1,700 - $l,900/ton for the example cited). 

Discounting the difference in assumptions regarding the annual 

costs of emission monitoring under the regulatory baseline, both analyses 

are also generally in agreement with regard to the cost effectiveness 

associated with regulatory options or alternatives based on the use of 

low sulfur coal (i.e., 1.2 lb SO2/MM Btu). In the example cited above 

for a 100 MM Btu/hr boiler located in Region V, for example, both the 

ANL report and the EPA analysis conclude that the incremental cost 

effectiveness associated with such options or alternatives over options 

or alternatives based on the use of low sulfur coal to meet an emission 

limit of 1.6 lb SO2/MM Btu is in the range of $600 - 800/ton. (Note: 
P.10 

The ANL value is calculated by subtracting the impact on cost effectiveness 

of the assumption regarding emission monitoring costs under the regulatory 

baseline [i.e., $l,100/ton] from the cost effectiveness value of $l,900/ton 

cited in the ANL report.) 

In addition to examining the cost effectiveness associated with 

various regulatory options or alternatives, both the ANL report and the 

EPA analysis examined the cost effectiveness associated with the additional 

emission reductions achieved by not providing emission credits for mixed 

fuel fired boilers or boilers operating within a cogeneration system. 

The ANL report, however, examined the cost effectiveness under regulatory 

options based on the use of very low sulfur coal and regulatory options 

requiring a percent reduction in emissions, but did not examine the 

cost effectiveness under options based on the use of low sulfur coal. 

The EPA analysis examined the cost effectiveness under regulatory 

alternatives based on the use of low sulfur coal and regulatory alternatives 

requiring a percent reduction in emissions. The two analyses can not 

be compared, therefore, with respect to conclusions regarding emission 

credits under regulatory options or alternatives based on the use of 

low sulfur or very low sulfur coals. Simliar options or alternatives 

were not examined in the two analyses. 

The two analyses can be compared directly, on the other hand, with 

respect to conclusions regarding emission credits under regulatory 

options or alternatives requiring a percent reduction in emissions. 

Conclusions regarding emission credits are not influenced by differences 

in assumptions regarding the regulatory baseline. As a result, both 

analyses reach similar conclusions with respect to emission credits 

and conclude that the cost effectiveness of the additional emission 

reductions achieved by not providing emission credits is generally in 

the range of $300 - 400/ton. 

REVIEW OF ANL "FINDINGS" 

° ANL Finding No. 1: 

The baseline emission rate used by EPA is considerably less 

stringent than typical emission rates contained in EPA-approved permits. 

The EPA analysis of the proposed standard produced lower cost-effectiveness values than would occur if typical emission rates were used. The 

following definition of the regulatory baseline was considered to be 

appropriate, based on EPA and State permit data: (1) 1.2 lb SO2/IO 

Btu for boilers >250 x IO6 Btu/hr nationwide and for boilers >100 x IO6 

Btu/hr in Regions VI and VIII-X, (2) 1.6 lb SOo/106 Btu for boilers greater 

than 100 and less than 250 x 106 Btu/hr in Regions I-V and VII. 

° Discussion 

This is not correct. In fact the two analyses differ very little 

with respect to the cost effectiveness associated with regulatory 

options or alternatives requiring a percent reduction in emissions, 
P.11 

!0 

as illustrated by the example discussed above comparing the results of 

the two analyses for boilers located in Region V. In this case, both 

analyses conclude that the cost effectiveness of emission control is 

in the range of $1,700 - $l,900/ton. 

On the other hand, there does appear to be a significant difference 

between the two analyses with regard to the cost effectiveness of 

emission control associated with regulatory options or alternatives 

based on the use of low sulfur coal. As illustrated by the example 

discussed above for Region V, the ANL report concludes this cost 

effectiveness is in the range of $l,900/ton; the EPA analysis concludes 

that it is in the range of $600/ton. As discussed above, this discrepancy 

between the two analyses is not the result of a difference in regulatory 

baselines, but the result primarily of a difference in assumptions 

regarding the annual costs of emission monitoring under the baseline. 

The ANL report assumes the annual costs of emission monitoring 

under the regulatory baseline are negligible, whereas the EPA analysis 

assumes these costs are significant. Thus, the ANL report effectively 

adds the costs of emission monitoring to the incremental costs of 

control in estimating the cost effectiveness associated with regulatory 

options based on the use of low sulfur coal over the regulatory baseline. 

The EPA analysis, on the other hand, effectively adds no additional 

costs for emission monitoring to the incremental costs of control in 

estimating the cost effectiveness of regulatory alternatives based on 

the use of low sulfur coal over the regulatory baseline. As a result, 

the cost effectiveness of emission control associated with regulatory 

options or alternatives based on the use of low sulfur coal are much 

higher in the ANL report than in the EPA analysis. 

In addition, as mentioned above, it also appears that the ANL 

report substantially overestimates the costs of emission monitoring by 

using the costs for monitoring opacity, N0X , and SO2 emissions rather 

than just those for monitoring SO2 emissions. 

In any event, it is not the difference in regulatory baselines 

that is primarily responsible for the lower cost effectiveness, but the 

difference in assumptions regarding the annual costs of emission monitoring 

under the regulatory baseline. Assuming such costs are significant 

appears more appropriate than assuming they are negligible as in the 

ANL report. Assuming these costs are negligible begs the question of 

how worthwhile current efforts may be to monitor the compliance status 

of boilers subject to existing State and Federal regulations 

limiting SO2 emissions. 

° ANL Finding No. 2: 

For 100 x IO6 Btu/hr boilers in Regions III, V, and VIII, costeffectiveness estimates are $l,700-$2,500/ton. For 250 and 400 x IO6 

Btu/hr boilers, cost-effectiveness estimates are about $1,500 and $l,000/ton, 

respectively. 
P.12 

11 

0 Discussion 

As illustrated above, the EPA analysis also concludes that the 

cost effectiveness of emission reduction associated with regulatory 

alternatives requiring a percent reduction in emissions is in this 

range cited in the ANL report. 

Unlike the ANL report, however, the EPA analysis concludes the 

cost effectiveness of emission control associated with regulatory 

alternatives based on the use of low sulfur coal is significantly lower 

than the cost effectiveness of emission control associated with regulatory 

alternatives requiring a percent reduction in emissions. As also 

discussed above, this is due primarily to the difference in assumptions 

between the two analyses regarding the annual costs associated with 

emission monitoring under the regulatory baseline. 

° ANL Finding No. 3: 

Under emission limitation options, the minimum cost-effectiveness 

for all boiler sizes and regions corresponds with emission ceilings in 

the 0.7-1.0 lb S02/10b/Btu range. To meet this limit, these boilers 

use cleaned coal. Lower emission ceilings necessitate use of FGD 

systems and result in substantial incremental cost increases. 

The most cost-effective emission ceiling for 100 x 10*> Btu/hr 

boilers in all three regions is 0.8 lb S0o/10 , which is achieved by 

burning cleaned coal. For 400 x 10& Btu/hr boilers in Regions V and 

VIII, cleaned coal combustion is the least-cost method for meeting 0.9 

and 0.7 lb SO2/IO Btu emission ceilings, respectively. For lower 

ceilings, FGD systems are selected. 

0 Discussion 

This is not correct. If the objective is to identify those options 

with the lowest cost effectiveness levels, the ANL report appears to 

indicate that an emission limitation of 0.2 lb SO2/MM Btu has the 

lowest cost effectiveness level. 

This is shown by figures in the ANL report plotting cost effectiveness 

verses emission reduction. The minimum cost effectiveness in these figures 

for 100 MM Btu/hr boilers in Regions III and V is an emission limitation 

of 0.2 lb SO2/MM Btu. In Region VIII, a 0.2 lb SO2/MM Btu emission 

limitation, has the same cost effectiveness as that associated with emission 

limitations of 0.7 - 1.0 lb SO2/MM Btu. Similar figures were not 

included in the ANL report for boilers of 400 MM Btu/hr. 

It should also be noted that these same figures show that the cost 

effectiveness levels associated with regulatory options requiring a 90 

percent reduction in emissions are lower than or the same as those 

associated with emission limitations in the range of 0.7 - 1.0 lb SO2/ 

MM Btu. 
12 

0 ANL Finding No. 4: 

A CEM requirement distorts the cost and cost-effectiveness of 

compliance-coal options versus technology-dependent approaches such as 

FGD. For some small boilers, the annual costs of monitoring would 

exceed the annual costs of emissions compliance. 

Cost-effectiveness estimates are sensitive to CEM requirements for 

all emission ceilings. Eliminating the CEM requirement for coal-fired 

boilers meeting emission ceilings without the use of FGD systems changes 

cost-effectiveness estimates from $800/ton to over $2,000/ton for 

100 x IO6 Btu/hr boilers. Differences for 250 x 106 Btu/hr boilers are 

about $500/ton and $l,000/ton in eastern and western regions, respectively. 

° Discussion 

As discussed above, the major difference between the ANL report 

and the EPA analysis concerns the cost effectiveness associated with 

regulatory options or alternatives based on the use of low sulfur coal 

As also discussed above, this difference is due primarily to the 

difference in assumptions regarding the annual costs of emission monitoring 

under the regulatory baseline. 

The ANL report assumes that the annual- costs of emission monitoring 

under the regulatory baseline are negligible. In addition, the ANL 

report appears to substantially over estimate the costs of monitoring 

SO2 emissions under regulatory options based on the use of low sulfur 

coal by including costs for monitoring opacity and N0X emissions as well 

as SO2 emissions. With these assumptions, as the ANL report concludes, 

monitoring costs substantially impact the cost effectiveness of regulatory 

options based on the use of low sulfur coal. 

The question, therefore, is which assumption regarding monitoring 

costs under the regulatory baseline is more appropriate; that used in 

the ANL report that any costs are negligible, or that used in the EPA 

analysis that such costs are significant. 

Boilers subject to existing State or Federal requirements under 

the regulatory baseline generally use a continuous emission monitor or 

coal sampling and analysis to monitor SO2 emissions. Once generated, 

these data are used to monitor the compliance status of these boilers. 

Studies have shown that the costs of coal sampling and analysis are 

comparable to those for a continuous emission monitor when coal sampling 

and analysis is used to generate reliable and accurate data concerning 

SO2 emissions. Thus, it seems more appropriate to assume that the 

annual costs of emission monitoring under the regulatory baseline are 

significant rather than negligible. If they are assumed to be negligible, 

it calls into question the value of current efforts to monitor the 

compliance status of existing boilers. 
P.14 

13 

° ANL Finding No. 5: 

The incremental costs for not allowing credit for a coal-fired boiler 

in a combined-cycle cogeneration system (receiving 25 percent of its heat 

input from oil-fired turbine exhaust) range from a few hundred to a few 

thousand dollars per ton of SO2. For boilers receiving 25 percent of 

their heat input from wood, the incremental costs of not allowing credit 

for the nonfossil fuel use are similar to the cogeneration values. 

Nonfossil fuel credits can be significant for coal-fired, combined-cycle 

cogeneration or multifuel boilers in situations where there is a marginal 

choice between compliance coal and FGD. For certain emission ceilings, 

the credit may allow use of lower cost compliance coal options. 

0 Discussion 

As discussed above, where the two analyses can be compared, the 

ANL report and the EPA analysis examining the cost effectiveness 

associated with the additional emission reductions achieved by not 

providing emission credits for mixed fuel fired boilers and boilers 

within cogeneration systems reach essentially the same conclusions. 

Under regulatory options or alternatives requiring a percent reduction 

in emissions, this cost effectiveness is generally in the range of 

$300 - 400/ton. 

The two analyses can not be compared with respect to conclusions 

regarding the cost effectiveness under regulatory options or alternatives 

based on the use of low sulfur coal. The ANL report only examined 

the cost effectiveness under regulatory options based on the use of 

very low sulfur coal. The EPA analysis only examined the cost effectiveness 

under regulatory alternatives based on the use of low sulfur coal. The 

two analyses, therefore, did not examine similar options or alternatives. 

As mentioned in the above finding, however, cost effectiveness 

levels higher than $300 - 400/ton occur in some cases under regulatory 

options based on the use of very low sulfur coal in the ANL report. As 

discussed in the report and inferred in this finding, these high cost 

effectiveness levels generally result when an emission limit is based 

on the use of very low sulfur coal and this emission limit is so low 

that it effectively requires the use of a flue gas desulfurization 

(FGD) system. In these cases, an emission credit can be significant 

enough that it "relaxes" the emission limit sufficiently to permit the 

use of low sulfur coal rather than an FGD system. Thus, the emission 

credit effectively changes the basic approach employed to reduce SO2 

emissions. 

Generally, emission credits are not this significant. In most 

cases, the effect of an emission credit is merely to reduce the degree 

of emission control necessary, but not change the basic approach used 

to reduce emissions. 

For example, under options or alternatives based on the use of low 

sulfur coal, an emission credit generally only permits a higher sulfur 

coal to be fired in the boiler; under options or alternatives requiring 
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14 

a percent reduction in emissions, an emission credit generally only 

permits a lower percent reduction to be achieved by an FGD system. In 

both these cases, the cost effectiveness of the additional emission 

reductions achieved by not providing emission credits is in the range 

of $300 - 400/ton. 

As mentioned, however, in some of the cases examined in the ANL 

report, the emission limit associated with an option based on the use 

of very low sulfur coal can be so low that it results in the use of an 

FGD, rather than the firing of a very low sulfur coal. In these cases, 

an emission credit may be significant enough, in terms of effectively 

raising the emission limit, that with an emission credit the boiler no 

longer uses an FGD system to reduce emissions, but fires a very low 

sulfur coal. 

In these cases, the cost effectiveness of the additional emission 

reductions achieved by not providing an emission credit can be in 

the range of several thousand dollars, as cited in the above finding. 

This high cost effectiveness, however, is not so much a reflection 

of the cost effectiveness generally associated with not providing 

emission credits, but a reflection of the higher cost effectiveness 

associated with the use of FGD systems to reduce SO2 emissions compared 

to the use of low sulfur coal to reduce emissions. 

o ANL Finding No. 6: 

The EPA coal cost data appeared too high with only minor variations 

in cost as a function of sulfur content and with no very low sulfur 

coals available. Cost effectiveness estimates based on the AUSM coal 

data tend to be slightly lower than those based on the EPA data for 

100 x IO6 Btu/hr boilers and slightly larger for 250 and 400 x IO6 

Btu/hr boilers in Regions III and V. In Region VIII, the AUSM data result 

in substantially higher cost effectivenss estimates (e.g., $5,740/ton 

compared to $2,160/ton for meeting a 0.6 lb SO2/IO Btu ceiling for 

a 250 x 106 Btu/hr boiler). 

0 Discussion 

- --• ' — -i 

As discussed above, a significant difference between the ANL report 

and the EPA analysis concerns the availability of very low sulfur coal. 

The ANL report implicitly assumes that coal demand from new industrial 

boilers will be sufficient to result in production of such coals, primarily 

through increased coal washing. 

Since utility boilers consume about 90 percent and industrial 

boilers only consume about 10 percent of the steam coal consumed in the 

United States, the EPA analysis assumes that coal markets and coal 

washing practices are determined primarily by the needs and demands of 

utility boilers, not industrial boilers. Consequently, the EPA analysis 

assumes that coal demand from new industrial boilers is not sufficient 

to significantly change existing coal markets or current coal washing 

practices and, as a result, very low sulfur coals are not considered 

generally available. 
P.16 

15 

Although the coal prices used in the EPA analysis are consistently 

above the adjusted AUSM coal prices cited, coal prices by themselves 

are relatively unimportant in terms of assessing the cost effectiveness 

associated with reducing SO2 emissions. What is important is the 

sulfur premium or the difference in price between low and high sulfur 

coals. 

As shown by figures in the ANL report, the sulfur premium in the 

EPA coal prices and the adjusted AUSM coal prices are quite similar in 

Regions III and V. In Region VIII, however, the AUSM coal prices do 

show a higher sulfur premium than the EPA coal prices. This higher 

sulfur premium explains the higher cost effectiveness value cited 

above for boilers located in Region VIII. Unfortunately, the ANL 

report provides no explanation of why the sulfur premium in Region 

VIII is so high and, as a result, provides no basis for attempting to 

reconcile this difference in sulfur premiums. 

0 ANL Finding No. 7: 

Projections of the amount of coal burned in new industrial boilers 

are contingent on assumptions about future fuel prices. Based on a 

simplified comparison of total levelized costs for coal- and oil-fired 

boilers, oil prices would have to rise to $35-$45/bbl in order for coal 

to compete effectively as an industrial boiler fuel. With natural 

gas and residual oil prices projected to be $26/bbl and $24/bbl (in 1983 

dollars) in the year 2000, respectively, there is little incentive to 

construct the new coal-fired industrial boilers. Thus, EPA may be overstating the environmental benefits (i.e., reduced emissions) of the 

proposed revision. 

0 Discussion 

Projections of the amount of coal likely to be fired in new industrial 

boilers are sensitive to projections of future fuel prices (i.e., natural 

gas, oil, and coal). The EPA national impacts analysis supporting the 

proposed NSPS considered two energy price projections (i.e., energy 

scenarios). The energy scenario considered most likely was that referred 

to as the "high oil penetration" scenario. Under this energy scenario, 

coal was projected to account for only 5 percent of the energy consumed 

in new industrial boilers. Natural gas was projected to account for 

about 30 percent and oil for about 65 percent. 

Another energy scenario was also considered. Under this energy 

scenario, termed the "high coal penetration" scenario, coal was projected 

to account for about 57 percent of the energy consumed in new industrial 

boilers. Natural gas was projected to account for about 42 percent and 

oil was projected to account for about 1 percent. 

Both energy scenarios, therefore, were quite different in their 

projected fuel mix in new industrial boilers. Sulfur dioxide emissions, 

however, were significant under either scenario. Under the high oil 
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penetration scenario, annual SO2 emissions of some 280 thousand tons 

were projected and under the high coal penetration scenario, annual 

SO2 emissions of some 325 thousand tons were projected. 

Thus, whether many coal fired industrial boilers are constructed 

or not, new source performance standards limiting SO2 emissions from 

new industrial boilers can have significant environmental benefits. 

If energy prices are such that few coal fired boilers are constructed, 

these benefits result primarily from reducing SO2 emissions from oil 

fired boilers. 

Even if only a few coal fired industrial boilers are constructed, 

however, the environmental benefits of standards limiting SO2 emissions 

from such boilers are significant. A typical 150 MM Btu/hr coal-fired 

boiler firing a medium sulfur coal, for example, results in SO2 emissions 

in the range of 800 tons/yr, if uncontrolled. Even firing a low sulfur 

coal, this boiler could emit some 400 tons/yr of SO2 emissions. Thus, 

even the benefits of reducing SO2 emissions from a single coal-fired 

boiler are considered significant.