www.AndoverTechnology.com 1 

### August 2 , 2012

To: Doug Grano

Fm: Jim Staudt

Re: Response to Comments Regarding Colstrip NO x and SO 2 Emission Reduction

I have developed responses to comments by PPL, the National Park Service, Earth Jus tice, and Montana DEQ (MDEQ).

Response s to Comments by PPL

I B. PPL Comment: EPA Overestimates the Emissions Benefits of SNCR

I B.1. PPL’s Comment: SNCR Cannot achieve 25% reduction in NO x
The amount of NO x 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 NO x 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 reduc tions are not feasible . Furthermore , at lower loads higher NO x 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% NO x reduction would be possible.

I B.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 o r visibility are specific to the application, as described below.

As noted in the May 2 9 , 2012 Fuel Tech letter , ammonia slip could be as high as 10 ppm, achieve 25%
NO x 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 SO 3 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 SO 2 reducing agent in the scrubbers, SO 3 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 an d 2 can tolerate a higher am monia slip than a unit burning another fuel that would produce higher SO 3 concentrations

.
It should also be noted that d etached plumes are not a concern in this case. Detached plumes form
from ammonium chloride that forms after being emitted from chimneys when both ammonia andwww.AndoverTechnology.com 2

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 we t 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 r ole 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 v isibility impairment.
PPL also misstates information regarding the Centralia BART determination. Centralia wa s 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 NO x emission rate that will meet an ammonia slip of less than 545 ppmdv.

• The lo west NO x emission rate that will meet an ammonia slip of up to 20 ppmdv.

• The lowest NO x emission rate that coincides with the lowest ammonia slip.

• The ability to achieve a NO x 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.

I C

. PPL Comment: EPA Does Not Properly Consider the Incremental Cost

- Effectiveness of SNCR at Colstrip
Units 1 and 2.

I C.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 ev aluated on its own merits as well as the “cumulative” effect. By EPA’s estimates, SNCR provides incremental NO x 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 f rom 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.

I C.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 a s 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 24027www.AndoverTechnology.com 3

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 h igher controlled emission rates (and lower
NO x reduction rates) should be used. A lower degree of assumed NO x reduction for SNCR will result in a higher estimated cost effectiveness in $/ton of NO
x reduced. Therefore, this is an important assumption
in m aking 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 NO
x reduced. However, the vendor data provided by PPL (Attachment
1: Ma y 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 Un it 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 th e delivered cost of the reagent and therefore this energy effect is implicitly addressed by the reagent cost. Air quality effects
from increased truck traf fic are not expected to be significant compared to the benefits associated with the emission reductions made possible by the reagent deliveries. NO x is a major criteria pollutant from diesel engines . However , the urea carried by the truck would control mu ch more NO x 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 curren t system uses natural oxidation. Forced oxidation will enable higher lime injection rates while avoiding

sc aling. Forced oxidation systems will re quire blowers and piping, and agitators that could be retrofit on the existing scrubber vessels (or, alterna tively, a n external oxidation tank ) at what is likely to be a much
lower cost than EPA’s estimated cost of a new absorber vessel.www.AndoverTechnology.com 4

A n alternative (or supplement) to forced oxidation is use of chemical additives that address scalin g. These additives are availab le 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 ves sel for each of Colstrip units 1 and 2 is impracticable. PPL ’s argument that their site is “too congested” to install add itional control equipment
is a very common argument used by facility owners that seems to be used regardless of the true site
conditio ns

. 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 fi nd space for a new ves sel with associated
ductwork : “There is sufficient space behind the stacks for installation of the fourth scrubber m odule, ID fan, ductwork and accessories

. ” As URS pointed out, this might require an additional booster fan, which
is included in the Burns & Mc D onnell 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 scru bber vessel may not be necessary to achieve 95% SO 2 capture . Nevertheless, with regard to addition of another scrubber vessel and the impact on SO 2 reduction, PPL relies on a June 15, 2012 letter from Jonas Klingspor of URS Corporation that states the reduced gas velocity would reduce SO 2 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

.www.AndoverTechnology.com 5

URS provided estimates of emission rates possible under different conditions. T he analyse s 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 f our 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 fourt h 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 SO 2 capture performance even

more.

IID. PPL Comment: An Additional Scrubber Vesse l Costs Far More than EPA Proposed and Is Not Cost

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

t han 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 d id not want to go on the record in our response to PPL’s comm ents

. 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 t he cost estimated by Burns & McDonnell of adding a sing le 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 perspec tive, 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 dolla rs 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 prev iously 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 E scalation) 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, the refore
the effect of overestimation of on e cost is compounded because it contributes to overestimation of
other costs. Because the estimate by Burn s & McDonnell is so much higher than what is reasonably expected and includes several questionable cost elem ents, I believe that it is incorrect. And, in anywww.AndoverTechnology.com 6

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

. Response s to Comments by N ational P ark S ervice

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 the ir position

. According to 2011 Title IV reporting data, several electric
uti lity 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 NO X _RATE UNIT_TYPE_INFO PRIMARY FUEL_INFO NO X _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 NO x Burner Technology w/ Overfire Air

MN Boswell Energy Center 4 0.1324 Tangentially

- fired Coal Selective Non

- catalytic Reduction Low NO x Burner Technology w/ Closed

coupled/Separated OFA

MN Taconite Harbor Energy Center 1 0.1385 Tangentially

- fired Coal Overfire Air Selective Non

catalytic Reduction

MN Taconite Harbor Energy Center 2 0.1445 Tangentially

- fired Coal Overfire Air Selective Non

catalytic Reduction

OH W H Sammis 5 0.1456 Dry bottom wall

- fired boiler Coal Low NO x Burner Technology (Dry Bottom only) Selective
Non

- catalytic Reduction

TX Big Brown 1 0.1401 Tangentially

- fired Coal Low NO x Burner Technology w/ Separated OFA Selective
Non

- catalytic Reduction

TX Big Brown 2 0.1369 Tangentially

- fired Coal Low NO x Burner Technology w/ Separated OFA Selective
Non

- catalytic Reduction

TX Monticello 1 0.1273 Tangentially

- fired Coal Low NO x Burner Technology w/ Separated OFA Selective
Non

- catalytic Reduction

TX Monticello 2 0.1236 Tangentially

- fired Coal Low NO x 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

.www.AndoverTechnology.com 7

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 Fu el Tech, results in an estimation of cost effectiveness of about $3,500/ton of NO
x 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 u nits 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 N 2 O, N 2 O emissions are

s trongly impacted by the temperature profile within the combustion unit as N 2 O 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 N 2 O behaviour is dif ferent than in higher temperature combustion systems. For this reason N 2 O 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 c ited are not likely indicative of the N 2 O 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, Au gust 1997) , the comparative impacts on N 2 O emissions between SCR and SNCR are not clear :

In selective non

- catalytic reduction, use of NH 3 results in less than 5 percent of the NO reduced being converted to N 2 O; use of urea converts more than 10 percent of the NO. The application of selective catalytic reduction suggests that N 2 O emissions are negligible from vanadium catalysts; noble metal catalysts, however, may convert significant quantities of NO into N 2 O (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 NO x Control, Miami, FL, May 1993.www.AndoverTechnology.com 8

Response s 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 SO 2 

### 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 scrubb ers 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 SO 2 

### reduction, EPA did not evaluate replacement of the existing scrubbers with another type of SO 2 

### reduction system, such as spray dryers or NID scrubbers.

In their argument,

"Finally, even with the existin g 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 n ot 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

ma gnesium 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 thr ough 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 PP L 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 certa inly 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 SO 2 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 incr eased easily or at the cost cited by Earth J ustice

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.pdfwww.AndoverTechnology.com 9

that is in P P L'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 incl ude 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 t heir 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 Engi neering, 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 theref ore could use it to achieve lower emission rates than 0.08 lb/MMBtu.

E arth 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, s ince C olstrip 3 had only started operation in 1984 and Colstrip 4 did not commence operation until 1986, 4 the 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 an d 1990 emissions data 5

, Colstrip units 3 & 4 emitted the following emission rates:

SO 2 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 SO 2 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/www.AndoverTechnology.com 10

At the time these scrubbers were built, wet MEL scrubbers and wet caustic scrubbers were the only scrubbers that cou ld deliver high capture rates (over 90%) with reasonable reliability. Scrubber technology has improved and other, less expensive, reagents are now preferred.
A lthough Colstrip Units 3 & 4 used MEL in the past, MEL is not readily available in the region ne ar 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.
D olomitic limestone is limestone with a significa nt amount of dolomite, or calcium magnesium carbonate. Because there are no dolomitic limestone deposits near the Colstrip plant , the dolomitic lime must b e sourced from remote locations . This increases the cost of the lime (that is made from the dolomit ic 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, 6 or 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 in creased 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 ME L 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 disrupt ions 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

Response s 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 emiss ions, 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 comp ly 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