www.AndoverTechnology.com 1

August 2, 2012

To: Doug Grano

Fm: Jim Staudt

Re: Response to Comments Regarding Colstrip NOx and SO2 Emission Reduction

I have developed responses to comments by PPL, the National Park Service, Earth Justice, and Montana 

DEQ (MDEQ). 

Responses to Comments by PPL

IB. PPL Comment: EPA Overestimates the Emissions Benefits of SNCR

IB.1. PPL’s Comment: SNCR Cannot achieve 25% reduction in NOx

The amount of NOx reduction possible at any particular boiler depends upon the process conditions at 

those boilers. PPL’s own documents (June 18, 2012 letter from PPL to EPA Region 8), including data 

from two SNCR vendors (Fuel Tech and Mobotec) that evaluated the Colstrip 1 and 2 boilers, support 

EPA’s assumption that SNCR can provide 25% reduction of NOx from a baseline of 0.20 lb/MMBtu at the 

Colstrip units 1 and 2. Fuel Tech, the most experienced vendor of this technology, has stated that 25% 

reduction is feasible (May 29, 2012 Fuel Tech to PPL letter and attachment 1 to PPL’s June 18, 2012 

letter). Therefore, there is no reason to believe that these reductions are not feasible. Furthermore, at 

lower loads higher NOx emission reductions would be achieved (up to 40% per Mobotec’s May 25, 2012 

letter to PPL letter and attachment 1 to PPL’s June 18, 2012 letter). As a result, on average over the full 

load range, over 25% NOx reduction would be possible.

IB.2. PPL’s Comment: EPA disregards ammonia slip, which would limit the effectiveness of SNCR

EPA did not disregard the effects of ammonia slip, which is widely known to be a by-product of this 

process, and this is discussed in the proposed FIP at 24023. Any adverse effects of ammonia slip with 

regard to plant operation or visibility are specific to the application, as described below.

As noted in the May 29, 2012 Fuel Tech letter, ammonia slip could be as high as 10 ppm, achieve 25% 

NOx reduction, and not pose an operating problem for the Colstrip units 1 and 2 in light of the fuel it 

burns. Air preheater fouling requires both ammonia slip and SO3 to be present under the correct 

conditions of temperature and moisture. In large part due to the alkalinity of the fly ash at Colstrip, 

which is present in high enough levels to be used as an SO2 reducing agent in the scrubbers, SO3 content 

of the flue gas at the Colstrip units 1 and 2 should be extremely low. Therefore, from the perspective of 

the impact on the air preheater and other downstream equipment, Colstrip units 1 and 2 can tolerate a 

higher ammonia slip than a unit burning another fuel that would produce higher SO3 concentrations. 

It should also be noted that detached plumes are not a concern in this case. Detached plumes form 

from ammonium chloride that forms after being emitted from chimneys when both ammonia and 
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chlorine are present in sufficient levels. Chlorine is not expected to be present in the exhaust from 

Colstrip 1 and 2 because the high alkalinity of the fly ash in combination with the wet scrubber will 

assure that virtually no chlorine is present in the flue gas that enters the chimney.

With regard to the impact of ammonia slip on other visibility or fine PM formation, PPL oversimplifies 

and therefore reaches incorrect conclusions. The role of any incremental ammonia slip on visibility will 

be determined by other sources of ammonia in the atmosphere, which include natural sources and 

other man-made sources, as well as the sources and concentrations of other pollutants that contribute 

to visibility impairment.

PPL also misstates information regarding the Centralia BART determination. Centralia was required to 

optimize its SNCR system and has assumed a 5 ppm ammonia slip in its estimates, not a 0.5 ppm slip 

level as PPL incorrectly asserts. More specifically, regarding Centralia’s SNCR optimization program,

“The goal of the optimization process is to identify three operating points of the SNCR system:

• The lowest NOx emission rate that will meet an ammonia slip of less than 545 ppmdv.

• The lowest NOx emission rate that will meet an ammonia slip of up to 20 ppmdv.

• The lowest NOx emission rate that coincides with the lowest ammonia slip.

• The ability to achieve a NOx emission rate no higher than 0.180 ppmdv, 30 operating day 

rolling average, each unit individually.”

Therefore, Centralia will be evaluating SNCR performance at levels up to 20 ppm in their optimization 

program.

IC. PPL Comment: EPA Does Not Properly Consider the Incremental Cost-Effectiveness of SNCR at Colstrip 

Units 1 and 2. 

IC.1. PPL Comment: SNCR is much more costly than SOFA, and accounts for a much smaller benefit.

The methodology for estimating incremental benefit and cost in a BART analysis is well established, and 

EPA followed this methodology. Each layer of control is evaluated on its own merits as well as the 

“cumulative” effect. By EPA’s estimates, SNCR provides incremental NOx reductions at a cost of roughly 

$3,300/ton,

1

and this has been confirmed by another estimate using data collected from SNCR vendors 

(see memo from Jim Staudt to Doug Grano, July 10, 2012).

Thus, EPA did properly consider the incremental cost-effectiveness of SNCR at Colstrip units 1 and 2. 

IC.2. PPL Comment: SNCR is not Cost Effective

As described in the previous answer, EPA estimated the incremental cost effectiveness of about 

$3,300/ton. This estimate has been confirmed based upon input from SNCR vendors (July 10, 2012 

memo from Jim Staudt to Doug Grano). It is also reasonable to evaluate the average cost effectiveness 

of combined controls, such as SOFA in combination with SNCR, and this is common practice in a BART 

analysis.

 

1

$3291/ton found in Federal Register /Vol. 77, No. 77 / Friday, April 20, 2012 pg 24027
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In their comments PPL indicates that they have assumed that SNCR cannot be relied on to achieve an 

emission rate of 0.15 lb/MMBtu, and PPL has suggested that higher controlled emission rates (and lower 

NOx reduction rates) should be used. A lower degree of assumed NOx reduction for SNCR will result in a 

higher estimated cost effectiveness in $/ton of NOx reduced. Therefore, this is an important assumption 

in making this calculation. PPL’s opinion that SNCR is not cost effective is based upon the presumption 

that less than 25% reduction from a baseline of 0.20 lb/MMBtu is possible on average (see PPL BART 

analysis at page 7). PPL states in their comments that only 10-15% reduction (controlled emission rate 

of 0.17-0.18 lb/MMBtu) is achievable based upon vendor input, which results in a much higher estimate 

of cost effectiveness in $/ton of NOx reduced. However, the vendor data provided by PPL (Attachment 

1: May 29, 2012 email from Dale Pfaff of Fuel Tech to Gordon Criswell of PPL) states that 25% reduction 

is achievable from an emission rate of 0.20 lb/MMBtu. Therefore, the vendor data provided by PPL in 

fact supports the emission reductions estimated by EPA. Absent other reliable information to 

demonstrate that 25% reduction from 0.20 lb/MMBtu is not achievable, the vendor data is the most 

reliable indicator of performance.

F. PPL Comment: EPA’s Consideration of Energy and Non-Air Quality Environmental Impacts

PPL states that EPA asserted that the energy needs of the SNCR system would be minimal without 

analysis. This is not the case. EPA did analyze the estimated energy and non-air quality environmental 

impacts of the SNCR system. EPA estimated electrical demand, water requirement, as well as increased 

fuel needs due to the SNCR system’s impact on the boiler efficiency. These costs were estimated to be

10-12% (see Colstrip Unit 1 BART Cost Analysis - SNCR+SOFA (2010 Dollars) and Colstrip Unit 2 BART 

Cost Analysis - SNCR+SOFA (2010 Dollars)) of the total estimated annual cost (excluding annualized 

capital), and were not sufficient to warrant ruling out SNCR as a control option.

No impact was anticipated to fly ash disposal cost. SNCR will not impact the amount of ash that is 

disposed of in the fly ash ponds.

With regard to secondary energy effects and air quality effects, such as those from trucks that deliver 

urea reagent, the cost of the fuel used in those trucks would be included in the delivered cost of the 

reagent and therefore this energy effect is implicitly addressed by the reagent cost. Air quality effects 

from increased truck traffic are not expected to be significant compared to the benefits associated with 

the emission reductions made possible by the reagent deliveries. NOx is a major criteria pollutant from 

diesel engines. However, the urea carried by the truck would control much more NOx from the Colstrip 

boilers than the urea delivery truck’s engine would produce.

IIB. PPL Comment: Installation of an Additional Scrubber Vessel Is Technically Impracticable. 

First, I am unconvinced that an additional scrubber vessel is necessary to avoid scaling. It is possible to 

inject lime and mitigate the risk of scaling through addition of a forced oxidation system or by use of 

chemical additives that mitigate scaling or perhaps use of magnesium enhanced lime. The current 

system uses natural oxidation. Forced oxidation will enable higher lime injection rates while avoiding 

scaling. Forced oxidation systems will require blowers and piping, and agitators that could be retrofit on 

the existing scrubber vessels (or, alternatively, an external oxidation tank) at what is likely to be a much 

lower cost than EPA’s estimated cost of a new absorber vessel.
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An alternative (or supplement) to forced oxidation is use of chemical additives that address scaling. 

These additives are available from companies such as Nalco Chemical Company. Use of magnesium 

enhanced lime would also offer advantages with respect to SO2 control and scaling as compared to lime 

that is not enhanced.

Second, I disagree that addition of a fourth scrubber vessel for each of Colstrip units 1 and 2 is 

impracticable. PPL’s argument that their site is “too congested” to install additional control equipment

is a very common argument used by facility owners that seems to be used regardless of the true site 

conditions. In the case of Colstrip, PPL’s argument that there is no space availability for an additional 

scrubber vessel is incorrect. The view of the site shows ample space for locating additional equipment 

(see the Google Earth close up of units 1 and 2). In fact, Burns & McDonnell (June 2012 report to PPL 

and attachment 6 to PPL’s June 18, 2012 letter) was able to find space for a new vessel with associated 

ductwork: “There is sufficient space behind the stacks for installation of the fourth scrubber module, ID 

fan, ductwork and accessories.” As URS pointed out, this might require an additional booster fan, which 

is included in the Burns & McDonnell estimate.

Colstrip Units 1 and 2 (Google Earth)

IIC. PPL Comment: EPA Overstates the Emissions Benefit of an Additional Scrubber Vessel

PPL argues that an additional vessel would not in fact reduce emissions because velocity through the 

existing scrubber vessel tray will be reduced. As noted elsewhere in this memo, I believe that an 

additional scrubber vessel may not be necessary to achieve 95% SO2 capture. Nevertheless, with regard 

to addition of another scrubber vessel and the impact on SO2 reduction, PPL relies on a June 15, 2012 

letter from Jonas Klingspor of URS Corporation that states the reduced gas velocity would reduce SO2

reduction. The URS letter and PPL, however, overlook the fact that the openings in the tray for the 

existing vessels could be reduced to restore gas velocity to the original level.
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URS provided estimates of emission rates possible under different conditions. The analyses performed 

by URS were limited either by increased scaling (the lowest rate of 0.13 lb/MMBtu with three vessels) or 

lower absorber gas velocity (0.16 lb/MMBtu with four vessels). Since URS did not evaluate addition of a 

forced oxidation system or any other means to address scaling, it is likely that a significantly lower 

emission rate than 0.13 lb/MMBtu is possible while using three vessels. And, addition of a fourth 

scrubber vessel, with tray openings in the three original vessels adjusted to maintain gas velocity, in 

combination with a forced oxidation system would certainly increase SO2 capture performance even 

more.

IID. PPL Comment: An Additional Scrubber Vessel Costs Far More than EPA Proposed and Is Not CostEffective.

In their comments PPL provided a cost estimate prepared by Burns & McDonnell that is much higher 

than what is in the proposed FIP, and they argue that this higher cost makes this modification not cost 

effective.

I attempted to get cost estimates from two scrubber suppliers for the cost of adding a vessel; however, 

it was not possible. Since these companies do business with PPL they did not want to go on the record 

in our response to PPL’s comments. However, I was able to examine the cost estimates in PPL’s 

comments relative to other scrubber project types and identify line items in their estimate that are 

questionable.

My opinion is that the cost estimated by Burns & McDonnell of adding a single module to treat 25% of 

the flue gas is unreasonable, equating to around $213/kW ($71 million divided by 333,000 kW),– or the 

equivalent of $853/kW when adjusting for the fact that only one fourth of the flue gas is being treated. 

To put this in perspective, this is more costly on a $/kW basis than the typical cost of a limestone forced 

oxidation wet FGD system (around $500/kW) that would provide over 95% removal for 100% of the flue 

gas. Also, according to the 2010 EIA Form 860 Enviroequip data, the original scrubber structure with 

three modules for unit 1 cost $34 million in 1975 (slightly over $100/kW), or about $11.3 million per 

scrubber. Using the Chemical Engineering Plant Cost Index (CEPCI) to escalate to 2011 dollars, the cost 

in today’s dollars would be about $109 million ($34 million times 585.7/182.4, or about $327/kW). This 

would suggest the cost of an additional vessel to be on the order of $27 million, or about 38% of what 

Burns & McDonnell estimated and consistent with what EPA has previously estimated. The difference in 

cost between EPA’s estimate and what Burns & McDonnell has estimated is far too large to be explained 

by the additional ductwork and fans associated with the retrofit. Table 4-1 of Burns & McDonnell has 

several costs that are questionable or high ($900,000 for Owner’s Project Management and $400,000 

for Owner’s Legal Counsel and $3.4 million in Escalation) and others that are very high and therefore 

require better explanation ($8.1 million for furnish and erect packages plus the estimates for 

Mechanical, Electrical and Civil and Structural Construction that total over $12 million). Engineering 

costs as well as many other costs are typically determined as a percentage of the other costs, therefore

the effect of overestimation of one cost is compounded because it contributes to overestimation of 

other costs. Because the estimate by Burns & McDonnell is so much higher than what is reasonably 

expected and includes several questionable cost elements, I believe that it is incorrect. And, in any 
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event, an additional scrubber vessel may not be necessary if a forced oxidation system or other means 

to control scaling is used on the existing three scrubber vessels.

Responses to Comments by National Park Service

NPS Comment: SNCR Effectiveness, page 6.

NPS argues that they are unconvinced that an emission limit of 0.15 lb/MMBtu can be achieved and 

cites CAM data to support their position. According to 2011 Title IV reporting data, several electric 

utility boilers employing SNCR routinely achieve under 0.15 lb/MMBtu, as indicated by their annual 

average emission rates shown below. Ten of these boilers burn coal and two of them burn residual oil. 

Most of these facilities have similar firing systems as Colstrip 1 and 2. As a result, other facilities achieve 

an emission rate under 0.15 lb/MMBtu and that rate can be achieved and maintained at Colstrip units 1 

and 2.

STATE FACILITY_NAME UNITID NOX_RATE UNIT_TYPE_INFO PRIMARY

FUEL_INFO NOX_CONTROL_INFO

CT

Norwalk Harbor 

Station 1 0.0996 Tangentially-fired Residual Oil

Selective Non-catalytic 

Reduction

CT

Norwalk Harbor 

Station 2 0.1023 Tangentially-fired Residual Oil

Selective Non-catalytic 

Reduction

MA Salem Harbor 3 0.1101

Dry bottom wall-fired 

boiler Coal

Selective Non-catalytic 

Reduction Low NOx Burner 

Technology w/ Overfire Air

MN

Boswell Energy 

Center 4 0.1324 Tangentially-fired Coal

Selective Non-catalytic 

Reduction Low NOx Burner 

Technology w/ Closedcoupled/Separated OFA

MN

Taconite Harbor 

Energy Center 1 0.1385 Tangentially-fired Coal

Overfire Air Selective Noncatalytic Reduction

MN

Taconite Harbor 

Energy Center 2 0.1445 Tangentially-fired Coal

Overfire Air Selective Noncatalytic Reduction

OH W H Sammis 5 0.1456

Dry bottom wall-fired 

boiler Coal

Low NOx Burner Technology 

(Dry Bottom only) Selective 

Non-catalytic Reduction

TX Big Brown 1 0.1401 Tangentially-fired Coal

Low NOx Burner Technology 

w/ Separated OFA Selective 

Non-catalytic Reduction

TX Big Brown 2 0.1369 Tangentially-fired Coal

Low NOx Burner Technology 

w/ Separated OFA Selective 

Non-catalytic Reduction

TX Monticello 1 0.1273 Tangentially-fired Coal

Low NOx Burner Technology 

w/ Separated OFA Selective 

Non-catalytic Reduction

TX Monticello 2 0.1236 Tangentially-fired Coal

Low NOx Burner Technology 

w/ Separated OFA Selective 

Non-catalytic Reduction

WI

Edgewater 

(4050) 4 0.1414 Cyclone boiler Coal

Overfire Air Other Selective 

Non-catalytic Reduction

Note: The Niles unit 2 in Ohio and the EdgeMoor unit 3 in Delaware also appeared in the Title IV data as coal-fired units with 

SNCR that had annual emissions below 0.15 lb/MMBtu, however, it is believed that they may have been firing natural gas for 

part of 2011 and were therefore removed from the list.
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NPS Comment: SNCR Costs, pages 6-8.

NPS made estimates of cost that indicate much higher costs for SNCR than assumed by EPA in the 

proposed FIP. I received information on cost and performance from the two vendors identified in PPL’s 

June 18, 2012 letter (see July 10, 2012 memo from Jim Staudt to Doug Grano). The higher of the two 

costs, received from Fuel Tech, results in an estimation of cost effectiveness of about $3,500/ton of NOx 

reduced. The lower of the two estimates, received from Mobotac, results in an estimated cost of about 

$2,800/ton, making the average of the two $3150/ton. This compares to EPA’s estimate of $3291/ton 

found in Federal Register /Vol. 77, No. 77 / Friday, April 20, 2012 pg 24027. As a result, EPA’s estimates 

are confirmed as being consistent with what is expected by the equipment suppliers that have 

experience designing and supplying these systems and the vendor estimates are based upon their 

review of the Colstrip 1 & 2 units and therefore reflect estimates that are specific to the boilers in terms 

of capital cost and reagent usage.

NPS Comment: Non-Air Quality Environmental Impacts of SNCR, pages 8-9.

With regard to the impact of ammonia slip on other visibility or fine PM formation, the role of any 

incremental ammonia slip on visibility will be determined by other sources of ammonia in the 

atmosphere, which include natural sources and other man-made sources, as well as the sources and 

concentrations of other pollutants that contribute to visibility impairment. As a result, depending upon 

the circumstances, an increase in ammonia slip may not have any impact on visibility.

With regard to the impact of SNCR on greenhouse gas emissions, especially N2O, N2O emissions are 

strongly impacted by the temperature profile within the combustion unit as N2O gets created and may 

also be destroyed at elevated temperatures as described in greater detail by Muzio and others.

2

 In 

lower temperature combustion systems N2O behaviour is different than in higher temperature 

combustion systems. For this reason N2O formation from SNCR applied to a waste incinerator would 

certainly be different and likely greater than from an electric utility boiler, and the data from the Grosso 

paper that is cited are not likely indicative of the N2O formation that would result from SNCR at the 

Colstrip units 1 and 2. Furthermore, as indicated in a 1997 report published by EPA (Nitrogen Oxides: 

Impacts on Public Health and the Environment (EPA 452/R-97-002, August 1997), the comparative 

impacts on N2O emissions between SCR and SNCR are not clear:

In selective non-catalytic reduction, use of NH3 results in less than 5 percent of the NO reduced 

being converted to N2O; use of urea converts more than 10 percent of the NO. The application 

of selective catalytic reduction suggests that N2O emissions are negligible from vanadium 

catalysts; noble metal catalysts, however, may convert significant quantities of NO into N2O 

(Kramlich and Linak, 1994). 

 

2 Muzio, L., Montgomery, T., Quartucy, G., Teixeira, D., “The Effect of Residence Time on SNCR Processes”, 1993 

Joint Symposium on Stationary Combustion NOx Control, Miami, FL, May 1993.
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Responses to Comments by Earth Justice

Earth Justice Comment: I.D.9 EPA Failed to Address Ammonia Slip Issues with SNCR

See response to comments to PPL and NPS.

Earth Justice Comment: II.B: EPA Settles for Minor Adjustments for SO2 Pollutants from Colstrip Units 

1 and 2 Instead of Proper BART Controls. Earth Justice argues that EPA should have considered 

other technologies, such as spray dryer absorber or NID scrubber technology. Earth Justice also 

argued that the existing scrubbers were capable of achieving emission limits of 0.06 lb/MMBtu.

Under BART, if a facility has an existing control device EPA may evaluate improvements to that 

device rather than replacement with another control device. Since Colstrip units 1 and 2 have 

existing scrubbers installed for the purpose of SO2 reduction, EPA did not evaluate replacement of 

the existing scrubbers with another type of SO2 reduction system, such as spray dryers or NID 

scrubbers.

In their argument,

"Finally, even with the existing venturi scrubbers, it is likely that Colstrip Units 1 and 2 could achieve an 

SO2 limit of 0.06 lb/MMBtu at a reasonable cost in order to further reduce visibility impacts to the 

affected Class I areas, TSD, pp. 68-73, further demonstrating that EPA has not imposed the best system of 

emission controls on SO2 emissions from Colstrip Units 1 and 2."

Earth Justice argues that the existing scrubbers at Colstrip units 1 and 2 could be upgraded to 

magnesium enhanced lime (MEL) scrubbers to increase the scrubber capture efficiency. As discussed 

earlier in this memo there is reason to believe that the existing scrubbers could be used to achieve 

higher capture efficiencies without the need for an additional vessel. Earth Justice believes that this is 

possible through modifications that would make the unit 1 and 2 vessels more like the scrubber vessels 

on units 3 and 4, which would include increasing the height on the scrubbers and adding additional 

spray levels. In addition, they recommend using MEL. Although PPL examined increased spray levels (it 

does not appear from the source they cite that PPL examined an increase in scrubber height) to increase 

scrubber efficiency to 91%. However, according to PPL’s study this will not result in the level of SO2 

capture efficiency needed to achieve 0.06 lb/MMBtu.

I would expect that use of MEL rather than common lime would be beneficial and certainly reduce the 

scaling that might result from lime addition, but addition of a forced oxidation system would likely be 

necessary anyhow. The facilities cited by Earth Justice as achieving high SO2 removals while using MEL 

(Mitchell station as well as Harrison) use forced oxidation systems, typically with an external oxidation 

tank.

3

 So, I agree with Earth Justice that a fourth vessel may not be necessary, as there are other 

options to improve the performance of the existing scrubbers that are less expensive. On the other 

hand, I am uncertain if the vessel heights could be increased easily or at the cost cited by Earth Justice 

 

3

Benson, L., Smith, K., Roden, B., “NEW MAGNESIUM – ENHANCED LIME FGD PROCESS”, available at 

www.carmeusena.com/files/files/TechPapersReports/a_20new_20magnesium_20enhanced_20lime_20

fgd_20process.pdf
www.AndoverTechnology.com 9

that is in PPL's June 2008 Addendum BART Report, p. 4-2 of $3 million. The $3 million cost cited by Earth 

Justice is an estimate by PPL that only includes additional pumping and sprays, and – contrary to what 

Earth Justice suggests - does not include an increase in the height of the scrubber vessels. A change in 

vessel height would require significant structural changes to the vessels and, due to the age of the 

existing vessels, might be problematic. Enlargement of each of the scrubber vessels by increasing height 

would therefore entail a far more costly retrofit – perhaps much more costly than what EPA has 

estimated for an additional vessel. Moreover, Earth Justice’s description of the scrubbers at units 1 and 

2 and units 3 and 4 on page 69 of their TSD compares them as if they should achieve similar 

performance with only a few changes to the unit 1 & 2 scrubbers: “They use the same general 

configuration and size of vessels as those used on Units 1 and 2.” And, later, in describing how the 

unit 3 and 4 scrubbers differ, “for units 3 and 4 “the vessel height was increased and an additional 

absorption spray level was added to Units 3 and 4.” However, this overlooks the fact that the two 

scrubbers have different technology suppliers (Combustion Engineering, now Alstom, in the case of 

units 1 & 2, and Bechtel in the case of units 3 & 4 – see 2010 EIA Form 860 Enviroequip data). The 

unit 3 & 4 scrubbers are one-of-a-kind scrubbers, and making unit 1 & 2 scrubbers more like unit 3 

& 4 scrubbers is not likely as simple as Earth Justice supposes. As a result, I am not persuaded that a 

reduction of the limit to 0.06 lb/MMBtu can be supported based upon the information Earth Justice has 

provided unless a much more costly retrofit is performed.

Earth Justice Comment VII.B.2: EPA must set more stringent SO2 emission limits for Colstrip Units 3 

and 4 to help achieve Reasonable Progress. Earth Justice states that Colstrip Units 3 and 4 have 

used MEL in the past for lower emission rates and therefore could use it to achieve lower emission 

rates than 0.08 lb/MMBtu.

Earth Justice cites a 1984 paper presented at the American Power Conference to support their argument

of a lower emission rate. I was not able to find this paper. Nevertheless, since Colstrip 3 had only 

started operation in 1984 and Colstrip 4 did not commence operation until 1986,4the data cited by 

Earth Justice cannot be more than short-term tests of Unit 3 that are not representative of longer term 

performance. According to 1985 and 1990 emissions data 5, Colstrip units 3 & 4 emitted the following 

emission rates:

SO2 Tons Heat Input, million Btu Lb/million Btu*

1985 Unit 3 1,383 33,541,658 0.082

1990 Unit 3 1,690 46,452,954 0.073

1990 Unit 4 2,029 55,387,330 0.073

* Calculated by multiplying SO2 tons by 2000 and dividing by heat input

Therefore, EPA’s data supports an emission rate of 0.08 lb/MMBtu.

 

4

See EIA Form 860 data

5

http://ampd.epa.gov/ampd/
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At the time these scrubbers were built, wet MEL scrubbers and wet caustic scrubbers were the only 

scrubbers that could deliver high capture rates (over 90%) with reasonable reliability. Scrubber 

technology has improved and other, less expensive, reagents are now preferred.

Although Colstrip Units 3 & 4 used MEL in the past, MEL is not readily available in the region near the 

Colstrip plant. MEL is produced from a blending of dolomitic lime with high calcium lime to achieve a 

lime with a magnesium content of 3-6% or so. The lime is produced by calcination of limestone. 

Dolomitic limestone is limestone with a significant amount of dolomite, or calcium magnesium 

carbonate. Because there are no dolomitic limestone deposits near the Colstrip plant, the dolomitic 

lime must be sourced from remote locations. This increases the cost of the lime (that is made from the 

dolomitic limestone). According to Carmeuse, a supplier of MEL, the closest source of dolomitic lime is 

1000 miles away from the Colstrip plant and transportation would cost $0.12 per mile per short ton plus 

a 24% fuel surcharge to transport,6or close to $150/short ton just for transportation of the reagent. 

Because the lime would be blended in closer to the plant with high calcium lime at perhaps an 8:1 ratio 

(reducing magnesium content from about 40% to about 4-5% this would result in an increased reagent 

cost of $15-$20 per ton. Assuming a high-calcium lime cost of about $95/ton 7, this raises the cost of 

reagent by close to 20% assuming constant reduction. Regent use might be improved somewhat for a 

given reduction level, but keeping in mind that this is a unique scrubber design, it is very hard to say 

what the impact would be. It is safe to say that the improvement in consumption would be well below 

20%, or the Colstrip plant might still be using MEL. In addition, reliance on a reagent source that is 1000 

miles away may cause operating risks during the winter months if delivery was interrupted. 

In summary,

 the data relied on by Earth Justice is not representative of what kind of performance is possible 

on a regular basis

 the use of MEL would definitely increase cost of operation and due to the unique design of the 

scrubber, it is unclear how much additional reduction is possible and at what cost

 the reliance on a reagent that is 1000 miles away could subject the plant to supply disruptions in 

the winter months

 

6

Email from Bob Roden, Carmeuse, July 31, 2012

7

Sargent & Lundy, “IPM Model – Revisions to Cost and Performance for APC Technologies, SDA FGD Cost 

Development Methodology FINAL”, Prepared for US EPA, August 2010 see table 2.
www.AndoverTechnology.com 11

Responses to Comments by Montana DEQ (MDEQ)

MDEQ Comment: MDEQ stated that EPA failed to provide analysis or consideration of the impact SNCR 

installation may have on mercury controls at Colstrip 1 & 2. MDEQ stated that this failure ignores factor 

3 of the five-factor analysis, “Any existing pollution control technology in use at the source.” MDEQ 

contended that the application of SNCR will require these units to displace the sorbent injection systems 

which limit mercury emissions, and that this displacement will compromise the Montana Mercury Rule.

SNCR has no impact on mercury capture in the scrubber or with mercury capture from sorbent injection 

and will neither improve nor harm any efforts at Colstrip units 1 and 2 to comply with Montana’s 

Mercury Rule. There is no reason why Colstrip units 1 and 2 cannot utilize both SNCR and sorbent 

injection (if sorbent injection is what PPL chooses to use at Colstrip 1 and 2). Injection points for SNCR 

and for sorbent injection are at different locations – the furnace for SNCR and the downstream 

ductwork for sorbent injection. The following facilities are equipped with both SNCR and activated 

carbon injection systems. The list of facilities includes units ranging from 65 MW to 405 MW and 

burning both bituminous and subbituminous fuels. Therefore, any argument that these two pollution 

control systems cannot be used together on the same facility has no basis.

Plant Name Unit ID State Name Modeled Fuels Capacity 

(MW)

Edge Moor 3 Delaware Bituminous 86.0

Edge Moor 4 Delaware Bituminous 174

Indian River Generating Station 4 Delaware Bituminous 405

Indian River Generating Station 3 Delaware Bituminous, 

Subbituminous 153

Vermilion 1 Illinois Subbituminous 84.0

Herbert A Wagner 2 Maryland Subbituminous 135

Salem Harbor 1 Massachusetts Bituminous 82.0

Salem Harbor 3 Massachusetts Bituminous 150

Salem Harbor 2 Massachusetts Bituminous 80.0

B L England 2 New Jersey Bituminous, 

Subbituminous 155

C R Huntley Generating Station 68 New York Bituminous, 

Subbituminous 190

C R Huntley Generating Station 67 New York Bituminous, 

Subbituminous 190

Dunkirk Generating Station 3 New York Bituminous, 

Subbituminous 185

Dunkirk Generating Station 1 New York Bituminous, 

Subbituminous 75.0

Taconite Harbor Energy Center 3 Minnesota Subbituminous 68.0

Taconite Harbor Energy Center 2 Minnesota Subbituminous 67.0

Taconite Harbor Energy Center 1 Minnesota Subbituminous 65.0

Source: NEEDS v4.10