UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

REGION 8

1595 Wynkoop Street

DENVER, CO 80202-1129

Phone 800-227-8917

http://www.epa.gov/region08

Ref: 8ENF-L

Via Email and UPS Overnight

Mr. Terry O'Clair

Director, Division of Air Quality

North Dakota Department ofHealth

918 E. Divide Avenue

Bismarck, ND 58501-1947

Re: EPA's Comments on the North Dakota

Department ofHealth's April 2010 Draft

BACT Determination for NOx for the

Milton R. Young Station

Dear Mr. O'Clair:

This letter transmits the United States Environmental Protection Agency's (EPA's)

comments on the North Dakota Department ofHeaIth's (NDDH's) April 2010, Draft Best

Available Control Technology (BACT) Determination for Nitrogen Oxides (NOx) for Milton R.

Young Station (MRYS), Units 1 and 2 (Draft BACT Determination).

The Draft BACT Determination concludes that low-dust and tail end Selective Catalytic

Reduction (SCR) are not cost effective NOx controls at MRYS. The Draft BACT Determination

found that low-dust SCR (LDSCR) would be more cost effective than tail-end SCR (TESCR),

and evaluated the cost effectiveness ofLDSCR based upon NDDH's conclusion that the average

cost effectiveness for LDSCR is $4,201 per ton for Unit 1 and $4,822 per ton for Unit 2. 1

NDDH's Draft BACT Determination also concludes that LDSCR was not cost effective because

ofthe incremental costs ofthese controls.

The Draft BACT Determination is not supported by the record and is not reasonable in

light of applicable statutory and regulatory provisions for two reasons. First, the Draft BACT

Determination relied upon unreasonable assumptions and factors not authorized by law to

determine the cost effectiveness of SCR at MRYS. This resulted in a significant overestimate of

1. Since NDDH found that LDSCR was more cost effective than TESCR, these comments are focused on LDCSR,

but most ofthe comments also apply to TESCR.
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

the cost ofthese controls. Second, even NDDH's unreasonably inflated cost estimates are on the

same order as costs previously borne by other sources and must be considered cost effective.

I. SCR is Cost Effective Based upon NDDH's Inflated Cost Estimates

The Consent Decree that EPA and NDDH entered into with Minnkota requires NDDH to

conduct its BACT analysis in accordance with the applicable federal and state statutes, and the

provisions ofChapter B ofEPA's "New Source Review Workshop Manual---Prevention of

Significant Deterioration and Nonattainment Area Permitting," (October 1990) (NSR Manual).2

The NSR Manual is used nationwide in PSD permitting decisions and provides that, "ifthe cost

ofreducing emissions with the top control alternative, expressed in dollars per ton, is on the

same order as the cost previously borne by other sources ofthe same type in applying that

control alternative, the alternative should initially be considered economically achievable, and

therefore acceptable as BACT.,,3 The NSR Manual further provides that "cost estimates used in

BACT are typically accurate to ± 20 to 30 percent. Therefore, control cost options which are

within ± 20 to 30 percent of each other should generally be considered to be indistinguishable

when comparing options.,,4

According to the NSR Manual, the economic impacts component of a BACT analysis

may include an examination of both the average cost effectiveness and the incremental cost

effectiveness of a control option.5 The Manual defines the "average cost effectiveness" as the

"total annualized costs of control divided by annual emission reductions, or the difference

between the baseline emission rate and the controlled emission rate...,,6

NDDH's Draft BACT Determination failed to conduct an adequate comparison ofthe

average cost effectiveness ofSCR at MRYS with other sources. NDDH only reviewed the cost

effectiveness of a small select group of facilities with SCRs in nearby states, ignoring the costs

borne by facilities that installed NOx controls throughout the country. The Clean Air Act, the

PSD regulations, and the NSR Manual do not allow a permitting authority to restrict its

comparative review to a subset ofthe whole ofthe sources that have undergone BACT review

for NOx • This review should have been nationwide, and the dollars per ton removed ofNOx can

be compared to sources undergoing PSD review across the country. Although a permitting

authority may consider unique circumstances relating to the location of a facility in determining

the total costs of a BACT control technology at that facility, it may not ignore the cost

effectiveness determinations from other parts ofthe country and choose to allow

2 See http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf.

3. See NSR Manual at B.44.

4. /d.

5. See NSR Manual at B.4l.

6. /d. at B.36.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

facilities to avoid the installation ofBACT level controls by setting unreasonable low cost

effectiveness thresholds.

The Draft BACT Detennination is also deficient because it compared the calculated cost

effectiveness ofLDSCR at MRYS with the average ofthe costs of controls from the facilities

within the small group selected by NDDH, instead of comparing the MRYS costs with individual

costs at the other facilities. NDDH's comparison ofthe cost effectiveness ofLDSCR at the

MRYS with the average costs of a small group of facilities is inconsistent with the NSR Manual

and frustrates the technology-forcing function ofthe BACT process because it ignores the higher

costs that other sources had to bear to install the same controls. Since the NSR program is

designed to maximize the use ofimproved technologies and requires controls that will achieve

the maximum reductions, the BACT analysis cannot just compare the cost effectiveness of

proposed controls with the average costs borne by other sources, but should favor consideration

ofthe highest control costs borne by other sources. The requirement in the Clean Air Act is for

the "Best" available controls, not the"Average" available controls.

Even the select group of control costs that NDDH used in the Draft BACT Detennination

demonstrates that the cost effectiveness ofLDSCR at MRYS was on the same order as the costs

borne by other facilities. NDDH's Draft BACT detennination concludes that the cost

effectiveness for NOx controls at Wygen 3 was $4,037 per ton. This is within 4% ofNDDH's

conclusions regarding the cost effectiveness ofLDSCR at Unit 1 ($4,201 per ton) and within

19 % ofNDDH's conclusions regarding the cost effectiveness ofLDSCR at Unit 2 ($4,822 per

ton). NDDH also compares the cost effectiveness ofLDSCR at MRYS with the BART cost

analysis conducted for a number of units. Although EPA is not clear why NDDH relied upon

these cost analyses, the cost ofinstalling LDSCR at MRYS would also be on the same order as

the cost ofinstalling SCR at these units, even based upon NDDH's inflated cost estimates.

NDDH also had infonnation in the record relating to the cost effectiveness of at least two

units that were on the same order as the cost effectiveness as LDSCR at MRYS, but did not

include any discussion ofthese units in the Draft BACT Detennination. On May 4,2010, in

response to a request from EPA, NDDH sent EPA "two files which contain excerpts from the

BACT analyses we reviewed."? These files contained a Pennit Application Analysis from the

Wyoming Department ofEnvironmental Quality (WDEQ) with infonnation regarding the cost

estimates for Wygen 2. This document shows that the cost effectiveness of installing SCR at

Wygen 2 to meet a rate of 0.06 lbs/MMBtu was $4,156 per ton. WDEQ stated "[t]he BACT

analysis indicates that 0.06 lb/NIMBtu is technically feasible and the Division considers the total

and incremental cost effectiveness to be reasonable."g The files also contained documents from

the NDDH record with infonnation from the RACT BACT LAER Clearinghouse relating to

7. See Enclosure 1.

8. See Enclosures 1 & 2.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Wisconsin Public Service Company's Weston 4 coal fired power plant. This information

indicates that $6,116 per ton for installing SCR was considered cost effective by Wisconsin.9

Since the NSR Manual provides that "control cost options which are within ± 20 to 30

percent of each other should generally be considered to be indistinguishable when comparing

options," even the data from NDDH's record indicates that the cost ofLDSCRs at MRYS is on

the same order as the cost effectiveness of other sources and should, therefore, be presumed to be

cost effective.

The Draft BACT Determination states that the cost effectiveness ofsome ofthe facilities

that it used for its comparison can be misleading because Minnkota used the highest removal

efficiency of any analysis reviewed. As NDDH points out, the NSR Manual does state that an

unrealistically low assessment ofthe emission reduction potential of a certain technology could

result in inflated cost effectiveness figures. The NSR Manual explains that the emissions

reductions must be considered reasonable, and supportable assumptions regarding control

efficiencies should be made. Since the emissions reductions that were used in the cost estimates

in this case were proposed by Minnkota and are consistent with current industry trends, it is

reasonable to expect the LDSCRs at MRYS to achieve this removal efficiency. Furthermore, the

discrepancy in assumed control efficiency can likely be attributed to MRYS's high baseline

emission rate and thus, a higher potential for emission reduction. For example, the baseline

emission rate noted in the NDDH determination for Sherco #2 is 0.20 Ib/MMBtu compared to

0.85 Ib/MMBtu for MRYS Unit 1. As such, the SCR technology can be expected to have a

higher percent removal at MRYS Unit 1 compared to Sherco #2 when the baseline emissions at

MRYS are over four times higher than the baseline emissions at Sherco #2.

After EPA received NDDH's Draft BACT Determination, it conducted a review ofthe

cost effectiveness ofNOx controls at other facilities and a review ofrelevant literature and policy

documents related to the cost effectiveness ofNOx controls. The determination ofBACT is

based on the pollutant that triggered PSD, in this case NOx, and therefore the cost effectiveness

(in dollars per ton removed) of any BACT control for NOx for any type ofsource can be

compared to the cost effectiveness of any other source ofNOx.' The results ofthis review, which

are described below, make it clear that LDSCR is cost effective at MRYS, even based upon the

inflated cost estimates used by NDDH:

• In 2001, EPA issued guidance related to presumptive BACT for NOx at refineries being

modified to meet EPA's low sulfur gasoline regulation. This guidance used a cost

effectiveness threshold of $10,000 per ton of NOx controlled in 2001 dollars. 1o

9. See Enclosure 1.

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EPAComments on NDDH Preliminary

NOx BACT Determination for MRYS

• The cost effectiveness threshold used for NOx reduction by several California air

pollution control districts are substantially more than the threshold in this EPA guidance

document, ranging from $9,700 to $24,500 per ton. I I

• Nebraska, Utah, Alabama, and Oklahoma have each stated that costs below $5,000 per

ton will be presumed to be cost effective. 12

• EPA Region 5 sent letters to Ohio and Indiana finding controls that were more expensive

than LDSCR at MRYS to be cost effective. 13

• EPA Region 4 sent letters to Alabama finding controls that were more expensive than

LDSCR at MRYS to be cost effective. 14

• A paper presented at the June 2002 Air and Waste Management meeting reported the

results of a survey ofthe threshold for economic feasibility in the BACT determinations

and in the LAER determinations separately by state. This survey reported that

Connecticut's BACT Determination average cost per ton was $9,000, Arkansas's was

$5,108, and Michigan's was $22,000. 15

10. See Memorandum from John S. Seitz, Director, OAQPS, to Air Division Directors regarding BACT and LAER

for Emissions ofNitrogen Oxides and Volatile Organic Compounds at Tier 2/Gasoline Sulfur Refinery Projects.,

available at http://www.epa.gov/ttn/caaaltl/memorandalbactguid.pdf. See also, Delaware Air Regulation

Development Committee Meeting #2 Minutes, April 19, 2006, available at

http://www.regulations.gov/searchlRegs/home.html#documentDetail?R=09000064807b7424.

11. See San Joaquin Valley Unified Air Pollution Control District, Final StaffReport: Update to BACT Cost

Effectiveness Thresholds, May 14,2008 available at,

http://www.valleyair.orgibusindiptolbactlMaY%202008%20BACT%20cosfl1020effectiveness%20threshold%20upda

te%20staff%2Oreport.pdf, See also San Joaquin Valley Unified Air Pollution Control District, Draft BACT Control

Technology Policy, March 1, 2010, (proposing to change BACT threshold for NOx form $9,700 to $24,500),

available at http://7l.6.68.10IWorkshops/postingsI2010/03-01-10IDraft%20BACT%20policYOIo20-

%20Mar%2020l0%20_2_.pdf.

12. See Nebraska Department ofEnvironmental Quality BACT Guidance Document, available at

http://www.deq.state.ne.us/Publica.ns£.c4afc76e4e077el1862568770059b73£,0949822f884b8ce1862573bd007daOe

9?OpenDocument, Utah Department ofEnvironmental Quality, Best Available Control Technology Summary,

available at http://www.airquality.utah.govlPermits/FORMSlFormOlb.pdf, and Energy and Environmental

Analysis, Inc's Regulatory Requirements Database for Small Electricity, available at http://www.eeainc.comlrrdbIDGRegProjectiStates/AL.htrnl, and http://www.eea-inc.comlrrdbIDGRegProjectiStates/OK.htrnl.

13. These letters are set forth in Enclosure 3. Note that the cost effectiveness outlined in these letters should be

adjusted to 2006 dollars for an accurate comparison to LDSCR at MRYS.

14. These letters are set forth in Enclosure 4. Note that the cost effectiveness outlined in these letters should be

adjusted to 2006 dollars for an accurate comparison to LDSCR at MRYS.

15. See Enclosure 5. "Comparison ofthe Most Recent BACT/LAER Determinations for Combustion Turbines by

State Air Pollution Control Agencies, Paper #: 42752, AWMA Meeting June 2002. Enclosure 4 also contains an

email from the state ofFlorida explaining that the reported results for Florida in this survey reflect the average actual

cost effectiveness during the relevant time period, and does not reflect Florida's view ofthe cost effectiveness

thresholds.

-5-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

• In 2001, EPA and the States ofArkansas, Nebraska, and Utah entered into a Consent

Decree with NuCor that stated that pollution control projects that are demonstrated to

cost $5,000 or less per ton reduced are presumptively economically feasible. 16

• Wyoming Department ofEnvironmental Quality's Permit Application Analysis for

Mountain Cement Company's Laramie Cement Plant considered an average cost

effectiveness of $4,540 per ton to be cost effective. I?

• A review ofinformation in the RACT BACT LAER Clearinghouse revealed at least

fourteen facilities in twelve states that identified NOx controls that were more expensive

than NDDH's estimates ofthe cost effectiveness ofLDSCR at MRYS. 18

• The Environmental Appeals Board noted in a 1989 decision that the range of costs

normally expended for NOx removal was $3,000 - 6,500/ton. After adjusting for

inflation, these costs are at least on the order ofNDDH's cost estimates for LDSCR at

MRYS. See In the Matter ofColumbia GulfTransmission Company, PSD Appeal No.

88-11 (EAB, lun 21, 1989) at 825.

If a permitting authority compares the cost effectiveness of a BACT determination today

with the cost effectiveness of a BACT determination from past years, it must consider the effects

ofinflation to properly compare the older project to the one under consideration.

As more fully set forth in EPA's previous comments to NDDH, a number of national

rulemakings, including the Clean Air Interstate Rule (CAIR), the Best Available Retrofit

Technology (BART) Guidelines, and revisions to the New Source Performance Standards

(NSPS) for Electric Utility Steam Generating Units all support the position that SCR is not only

technically feasible, but also cost effective for controlling NOx emissions from North Dakota

Lignite.

NDDH's Draft BACT Determination concluded that "[t]he expected cost effectiveness

[of LDSCR at MRYS] is higher than other plants where SCR has been applied as BACT.,,19 The

information set forth above clearly demonstrates that even NDDH's inflated cost estimates are

on the same order as costs previously borne by other sources and must be considered cost

effective.

NDDH's Draft BACT Determination also considered the incremental costs ofLDSCR.

The incremental cost effectiveness calculation compares the costs and emissions performance

level of a control option to those ofthe next most stringent option. The incremental cost

16. See Enclosure 6.

17. See Enclosure 7.

18. See Enclosure 8.

19. See NDDH's Draft BACT Determination at p. 12.

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BPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

effectiveness is then determined by the difference in total annual costs between two contiguous

options divided by the difference in emissions reduction. 20

In In re General Motors, 10 E.A.D. 360, (EAB 2002), the Environmental Appeals Board

explained the interplay between average and incremental cost. The Board explained that "the

Draft NSR Manual, while allowing for both average and incremental cost effectiveness analysis,

places primary stress on the average cost measure. See Draft NSR Manual at B.31 (BACT cost

effectiveness analysis turns on the average and, where appropriate, incremental cost

effectiveness ofthe control alternative). Moreover, the Draft Manual cautions that:

[U]ndue focus on incremental cost-effectiveness can give an impression that the cost of a

control alternative is unreasonably high, when, in fact, the cost-effectiveness, in terms of

dollars per total ton removed, is well within the normal range of acceptable BACT costs.

Id. at B.46. This caution against allowing incremental cost calculations to unjustifiably

inflate the cost component ofthe BACT analysis is in keeping with the objective ofthe

CAA that less effective control technologies be employed only when the source-specific

economic impacts or other costs prevent a source from using a more effective technology.

See generally Senate Debate on S. 252 (June 8, 1977) reprinted in 3 Senate Committee on

Environmental and Public Works, A Legislative History ofthe Clean Air Act

Amendments of 1977, p. 729 (statement of Sen. Edmund Muskie, sponsor ofS. 252,

stating that BACT, while allowing for flexibility based upon source specific factors, is

intended to "maximize the use ofimproved technology")." Id. at 370-378

Although it is not clear from the Draft BACT Determination how much emphasis NDDH

placed on the incremental cost effectiveness ofLDSCR at MRYS, it is clear that the incremental

cost effectiveness ofLDSCR compared to SNCR is not a valid basis for rejecting SCR as BACT.

Since the average cost effectiveness ofLDSCR at MRYS is well within the range of acceptable

BACT costs, it would be inconsistent with the NSR Manual to place undue focus upon the

incremental cost effectiveness ofthese controls to reject LDSCR as BACT.

In its analysis, NDDH lists several projects where a permitting agency rejected a more

stringent control option and the corresponding incremental cost effectiveness for the rejected

technology. It is not possible to tell from the Draft BACT Determination how much weight the

permitting agency gave, if any, to incremental cost effectiveness in the selection ofthe lessstringent option. As noted above, incremental cost effectiveness is not the primary criteria used

in a BACT determination. As such, it should not be assumed that the permitting agency gave

significant weight to incremental costs in the determinations cited by NDDH. Moreover,

considering the relatively small amount of emphasis that can be given to incremental cost

effectiveness, making any sort of direct comparison ofthe incremental cost effectiveness from

one project to the next is difficult at best.

20. See NSR Manual at B.43.

-7-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

The only three projects where NDDH states that the more stringent control technology

was rejected "based on" incremental cost are the Dry Fork Plant near Gillette, Wyoming (SCR at

0.043 Ib/MMBtu), the ADM facility in Columbus, Nebraska (SNCR achieving 0.05 Ib/MMBtu),

and Deseret Power in Uintah County, Utah (limestone injection and a wet scrubber). The other

projects listed by NDDH simply state the incremental cost effectiveness for the rejected control

option. NDDH does not state that incremental cost effectiveness was a significant factor in the

determination.

EPA examined the three BACT determinations that NDDH stated were based on

excessive incremental costs. The Draft BACT Determination stated "[t]he State of Wyoming

rejected an SCR operating at 0.043lb/l06 Btu at the Dry Fork Plant based on an incremental cost

of $1 0,300/ton.,,21 This statement is incorrect. As more fully set forth above, NDDH sent EPA

excerpts ofthe documents that it relied upon to compare the cost effectiveness ofLDSCR at

MRYS with other facilities. One ofthese documents included excerpts from the WDEQ Permit

Application Analysis for the Dry Fork coal fired power plant. EPA obtained a copy ofthe

complete document. Page 7 ofthis document, which was not included in the excerpts from

NDDH, directly contradicts NDDH's conclusion regarding incremental cost effectiveness, and

states "[t]he Division considers the incremental cost effectiveness of $1 0,303/ton reasonable for

an additional 117 tpy emission reduction but does not consider an incremental cost effectiveness

of$23,744/ton reasonable for an additional 50 tpy emission reduction.,,22

EPA also reviewed the details ofNebraska's BACT determination for the ADM

facility.23 While Nebraska states "$5600 per of additional NOx emissions reduction is

excessive," it is clear that incremental cost was not the only reason Nebraska eliminated SNCR

at a rate of 0.05 lb/MMBtu and made a BACT determination of SNCR at a rate of 0.07

Ib/MMBtu. In fact, Nebraska's analysis states that 0.05 Ib/MMBtu for SNCR is "not considered

technically feasible due to the increased opacity and fabric filter plugging from high levels

ammonia salt formation." Since the State of Nebraska concluded that it was not technically

feasible for the facility to meet a 0.05 Ib/MMBtu rate, NDDH cannot conclude that Nebraska

rejected this control option based upon the incremental cost effectiveness. Nebraska also stated

that the reasons why SNCR at 0.05 Ib/MMBtu was rejected as BACT include "opacity increases

by 10 percentage points or more, ammonia slip level increases above 10 ppm increases

condensable PM emissions, and the increases in fine particulate matter and ammonia emissions

make the proposed BACT limit for particulate matter unattainable." Even ifthe incremental cost

was given significant emphasis by Nebraska, as noted above, $5,600 per ton is even less than

what has been considered to be cost effective for average costs. Therefore, Nebraska's citation

21. NDDH's Draft BACT Detennination at p. 12.

22. See Enclosure 9. Although it is not clear where NDDH obtained these excerpts or how it reached a conclusion

that is directly contradicted by the plain language ofthe full document, we expect that NDDH may have obtained

these excerpts from EPA's administrative record in the Deseret Bonanza matter.

23. See Nebraska PSD Pennit for ADM's Columbus, Nebraska facility, p. 148, available at

http://www.epa.gov/region07/air/nsr/archives/2006/finalpermits/adm columbus final psd permit.pdf.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

of $5,600 per ton being excessive for incremental cost effectiveness should be considered an

outlier and reliance on this detennination as a basis for incremental cost effectiveness is

unwarranted.

NDDH's reliance upon Region 8's incremental cost analysis regarding the Deseret

Bonanza Waste Coal-Fired Unit (WCFU) is misplaced for several reasons. First, the incremental

cost analysis that NDDH refers to relates to S02, and not NOx• Second, EPA Region 8's

elimination of wet scrubbing with limestone injection in favor ofdry scrubbing plus limestone

injection for S02 BACT at WCFU was not entirely "based on an incremental cost of

$10,540/ton," as stated by NDDH. EPA Region 8 noted in its Final Statement ofBasis for the

pennit that, in addition to the relatively higher H2S04fonnation that results from a wet scrubber,

"[w]et FGD systems also require significantly more water than the dry FGD system. This is an

especially important consideration for Deseret's project, which will be located in an arid region

ofUtah.,,24 The issue ofwater use in wet versus dry scrubbing systems is generally recognized in

S02 BACT detenninations in Region 8 states. While there have been some projects that have

proposed wet scrubbers for larger pulverized-coal units, there have also been pulverized-coal

projects pennitted with dry scrubbing as BACT controls for S02. The issue ofwater use is often

cited as why dry scrubbing is selected over wet scrubbing. This is significant in that for

pulverized-coal facilities, there is no limestone injection upstream ofthe control device removing

substantial amounts of S02, as there are with circulating fluidized bed (CFB) boilers, such as that

being pennitted for the Bonanza WCFU project. Since there is no limestone injection upstream

of a scrubbing system (wet or dry) for a pulverized-coal unit, the selection of dry scrubbing, with

lower S02 removal efficiencies compared to wet scrubbing, becomes even more critical because

the difference in overall tons of S02 removed would be greater for pulverized coal units

compared to CFB units. Nonetheless, there have been BACT detenninations in the West for

pulverized coal fired units that have concluded dry scrubbing is BACT for S02.

Dry scrubbing with limestone was the most stringent BACT control option found by

Region 8 to have been selected by pennitting agencies for CFB boilers at the time the Bonanza

WCFU pennit was issued,zs In fact, Region 8 stated in its Final Statement of Basis for the

pennit that it was "not aware of any CFB boilers equipped with a wet scrubbing system."

However, Region 8 did find wet scrubbing to be a technically feasible control option for the

Bonanza WCFD. Limestone injection to the CFB boiler with 85% control was assumed in the

overall control efficiency of all add-on control options presented.

24. See Final Statement ofBasis for Deseret Power Electric Cooperative Bonanza Power Plant, p. 96, available at

http://www.epa.gov/region8/air/pd£'FinaIStatementOfBasis.pdf.

25. See Final Statement ofBasis for Permit No. PSD-OU-0002-04.00 pages 97 - 100. Pennits with BACT

determinations issued to AES Puerto Rico and Nevco Energy issued 8/10/04 and 10/12/04 respectively. Pennit

applications had also been submitted for CFB units proposing dry scrubbing (in addition to limestone injection) for

Red Trail Energy LLC - Richardton Ethanol Plant, MDU Co. - Gascoyne Generating Station and Great Northern

Power Development - South Heart.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Finally, the overall control efficiencies listed in the Final Statement ofBasis for wet

scrubbing and dry scrubbing (in combination with limestone injection) are 99.1% and 98.8%,

respectively. The difference in overall SOz reduction between wet scrubbing and dry scrubbing

(in combination with limestone injection) was 63 tons per year. In contrast, the incremental NOx

emission reductions between ASOFA plus SCR and ASOFA plus SNCR calculated in the

NDDH NOx BACT Determination are 3,439 tons per year for Unit 1 and 5,490 tons per year for

Unit 2. This equates to an incremental difference in NOx emission reductions at MRYS

compared to the SOz emission reductions at Bonanza WCFU of 55 times more for Unit 1, 87

times for more Unit 2, and 142 times more collectively.

In summary, while it is true that Region 8 did cite "unacceptably high incremental SOz

removal costs" in its reasoning for selecting dry scrubbing over wet scrubbing in the Bonanza

WCFU SOz BACT determination, it cannot be said that this decision was "based on" the

incremental cost. As described above, there were other important considerations (most notably

water conservation in an arid location) that went into this determination. These other

considerations were determined by Region 8 to outweigh the additional 63 tons per year

reduction that would be achieved by selecting a wet scrubber over a dry scrubber. It should be

noted that Region 8's final BACT determination selected the most stringent control technology

of any CFB unit permitted at that time with a permitted level of control consistent with the most

stringent BACT determinations. As such, the $10,540 ton per year incremental cost cited in this

determination should not be viewed as an independent "bright line" value. As noted above, there

are many significant differences between the Bonanza WCFU and MRYS projects. Furthermore,

as explained below, the non-standard cost methods used in the NDDH Draft BACT

Determination undermine the ability to make meaningful comparisons between the incremental

costs calculated for MRYS with other similar projects.

II. NDDH's Draft BACT Determination Failed to Follow EPA's NSR Workshop Manual

NDDH was and is required to conduct its BACT determination in accordance with the

NSR Manual and OAQPS Control Cost Manual (Control Cost Manual). The Draft BACT

Determination did not, however, follow the requirements in these manuals. Rather, it used

unauthorized cost methods, included costs for items that are not authorized, and relied upon

unreasonably high estimates for a number of costs. As more fully set forth below, conservative

revised cost estimates conducted in accordance with the NSR Manual and Control Cost Manual

and based upon more realistic estimates for a number ofitems cause the cost effectiveness of

LDSCR at MRYS to drop to approximately $2,000 per ton.

Since the significance of cost effectiveness values is determined by comparing the costs

for a given project to costs at other sources, it is critical that permitting authorities throughout the

United States follow a standardized approach for determining the cost effectiveness of controls.

The NSR Manual explains:

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Consistency in the approach to decision-making is a primary objective ofthe top-down

BACT approach. In order to maintain and improve the consistency ofBACT decisions

made on the basis of cost and economic considerations, procedures for estimating control

equipment costs are based on EPA's OAQPS Control Cost Manual and are set forth in

Appendix B ofthis document. Applicants should closely follow the procedures in the

appendix and any deviations should be clearly presented and justified in the

documentation ofthe BACT analysis.26

The Control Cost Manual also emphasizes the importance of using a consistent approach

to determining the cost effectiveness of controls. The Introduction to the Control Cost Manual

explains:

The objectives ofthis Manual are two-fold: (1) to provide guidance to industry and

regulatory authorities for the development of accurate and consistent costs (capital costs,

operating and maintenance expenses, and other costs) for air pollution control devices,

and (2) to establish a standardized and peer reviewed costing methodology by which all

air pollution control costing analyses can be performed.27

A. Inflated Capital Cost Estimates and Cost Methods

SCR systems are being successfully applied to virtually every kind ofstationary source

(utility boilers, incinerators, cement plants, glass plants, etc.) and fuel type (coal, biomass, coke,

etc.) worldwide. In meeting these varied and significant challenges for the widespread

deployment of SCR technology, system designers must always tailor the specifics of SCR

application to the varied conditions at each facility and the most suitable location for installing

the system. Although there are admittedly some unique aspects ofthe MRYS, almost all

facilities that have installed SCRs have had unique design challenges.

Capital costs for the installation of SCR on a coal fired electric generating unit are

commonly reported on a dollar per kilowatt of capacity basis. Minnkota's BACT analysis,

prepared by Bums & McDonnell (B&McD), which was used by NDDH to determine the cost

effectiveness of LDSCR, states that the estimated capital cost for LDSCR at MRYS based upon a

shared facilities approach was $543/kW for Unit 2 and $525/kW for Unit 1.28

26. See NSR Manual, at B-52

27. See Control Cost Manual, 2002, Chapter I, Section 1.1.

28. See November 2009 report by Burns & McDonnell, "NOx Best Available Control Technology Analysis Study

- Supplemental Report for the Milton R. Young Station Unit 1, revised February 2010, p. 4-11, and November 2009

report by Bums & McDonnell, "NOx Best Available Control Technology Analysis Study - Supplemental Report for

the Milton R. Young Station Unit 2, p. 4-11.

-11-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

In its BACT analysis, B&McD stated that a cost range for conventional high-dust SCR was

reported as between $55 and $150/kW?9 On February 16,2006, PowerGen magazine reported

the results ofsurvey ofSCR capital costs. The survey was conducted by the Electric Utility Cost

Group, and included responses from 72 individual units totaling 41 GW (representing 39% of

installed SCR systems in the U.S. by MW at the time ofthe study). The results ofthis survey

showed that costs were generally reported to be in the $100 to $200/kW (in 2006 dollars) range

for the majority ofthe systems, with only three reported installations exceeding $200/kW.30

Although some studies have reported slightly higher costs, most have reported results that are

generally within this range.3) Furthermore, two PSD permit applications submitted to NDDH in

2005 and 2006 for CFB utility boilers contemplated SCRs downstream of a dry scrubber and

baghouse (TESCR) and included estimated capital costS.32 The estimated capital costs for these

two projects ranged from $1 17/kW to $132/kW. Since these units were designed to bum North

Dakota lignite and are very close in size to MRYS Unit 1, it is unclear why the estimated capital

cost for MRYS Unit 1 are about four times higher than what was reported in those permit

applications.33

The fact that B&McD estimated capital costs for the LDSCRs at MRYS are so much

higher than the capital costs at other facilities calls the reliability of these cost estimates into

question. The reliability ofthese estimates becomes more questionable in light ofthe fact that a

number of extremely complicated and challenging SCR installations have had capital costs well

below the cost estimates for LDSCR at MRYS. There are at least two cold side SCRs that have

recently been installed in the United States that should be considered as a relatively reasonable

comparison. In 2007, Washington Group International prepared an "Emission Reduction Study"

that evaluated what would be the most cost effective SCR configuration at the WE Energies

South Oak Creek Units 5, 6, 7 and 8. The report concluded that retrofitting the units with coldside LDSCRs was determined to be the least expensive option and predicted capital costs for the

SCR systems of$190,500,000 total for all units. This comes out to approximately $168/kW for

the SCR equipment alone on the combined 1,135 MW at the facility.34

29. !d.

30. See M. Marano, Estimating SCR Installation Costs, Power, January/February 2006.

http://www.powermag.comlcoaVEstimating-SCR-installation-costs_506.html. The reported range of $100 -

$221/kW.

31. See Enclosure 10. 1. Edward Cichanowicz, Current Capital Cost and Cost Effectiveness of Power Plant

Emissions Control Technologies, June 2007.

32. See Enclosure 11. August 18, 2005 Application to Permit to Construct - South Heart Power Project, page 4-16

and June 2006 Gascoyne 500 Generating Station and Gascoyne Mine Application For A Permit To Construct And

Air Quality Technical Analysis.

33. Although NDDH rejected TESCR for these projects due to high cost effectiveness, these examples illustrate

how exceptionally high the B&McD estimates are for capital costs.

34. See Enclosure 12. WE Energies submitted information to the Public Service Commission (PUC) ofWisconsin

indicating that the cost ofits SCR system was higher than the costs identified in this study. Even ifthe costs from

the PUC submittal are used to calculate the cost per kW, however, these costs are significantly below Minnkota's

estimated capital costs.

-12-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

PSE&G also retrofitted its Mercer Units 1 and 2 with cold-side SCRs. The capital cost

for these retrofits was about $120 million.35 This comes out to approximately $1 851kW.

Although EPA and NDDH asked Minnkota to conduct a general comparison ofthe capital costs

ofinstalling SCR at MRYS with the costs ofLDSCR at these units, Minnkota declined to

conduct this comparison.

Minnkota has not explained the fact that the estimated capital costs for LDSCR and

TESCR at MRYS are so much higher than any other SCR system built, including the LDSCR

systems for Oak Creek and Mercer Stations. B&McD implies that the unique nature ofthe

application of SCR at MRYS creates a situation where seemingly no comparison to another SCR

installation is appropriate. As noted above, even if an SCR installation at MRYS would provide

unique challenges because ofthe different fuel or boiler type, this would not result in capital

costs that are over one and a halftimes as high as the upper end of SCR installations with the

highest degree ofretrofit difficulty. The differences for the basic capital cost equipment at

MRYS would not be expected to differ from other SCR installations on the scale estimated by

B&McD and no reasonable explanation has been provided by Minnkota for the large disparity.

As such, close examination ofthe stated costs must be conducted by NDDH to justify the costeffectiveness in its BACT determination.

EPA has examined these costs based on the information available during the public

notice period and believes that the B&McD analysis that NDDH relied upon included redundant

costs, insufficient justification for some ofthe cost estimates, and many components in the cost

methodology used to calculate Total Capital Investment that are unauthorized, inappropriate, and

inconsistent with the Control Cost Manual or other EPA-approved methods. When these items

are taken into account, it is clear that the cost values submitted by Minnkota and adopted into the

Draft BACT Determination result in a calculation of cost effectiveness that is grossly inflated

and ill-suited for comparisons with other BACT determinations.

First, as explained in detail in Mr. Hans Hartenstein's April 2010 expert report36, many of

the assumptions and design parameters that B&McD specified to SCR system and catalyst

vendors resulted in excessive equipment components and sizing ofthe SCR system and the

auxiliary/ balance ofplant components, which drove up materials and labor costs. Ifthe system

was designed to minimize capital costs, the general design would be different and the cost of

materials and labor would be much less. Furthermore, there appears to be redundancy for some

items that were included as "SCR System Equipment" and "Auxiliaries/Balance of Plant" costs.

35. See PSG&E press release at: http://www.pseg.com/media center/pressreleases/articles/200612006-11-30.jsp.

EPA verified the capital costs with communications with the New Jersey Department ofEnvironmental Protection

and Mr. Hans Hartenstein.

36. See Enclosure 13. Portions ofthis enclosure are subject to a confidential business information claim and will be

submitted separately and noted as CBI.

-13-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

For example, the "Auxiliaries/Balance of Plant" costs include "SCR bypass ducts and isolation

dampers." The SCR system vendor that provided a pricing proposal, which appears to have been

directly used by B&McD for the "SCR System Equipment" cost, included an SCR system with

"gas bypass for maintenance." Although vendor information can be used instead ofthe capital

cost equations detailed in the Control Cost Manual, Minnkota has not provided a basis for the

"Auxiliaries/Balance of Plant" costs, which are 80% ofthe "SCR System Equipment" costs.

Perry's Chemical Engineering Handbook, 6th Edition (Table B2) uses factors related to total

equipment costs which would be similar to the "SCR System Equipment" used in the B&McD

analysis. Perry's adds 55% to equipment costs for auxiliaries compared to B&McD's 80%. The

redundancies and comparatively high costs used for "Auxiliaries/Balance of Plant" that NDDH

relied upon in the Draft BACT Determination are unreasonable and not supported by the record

without further justification.

Another major concern is the degree to which the B&McD capital cost analysis deviates

from the Control Cost Manual methodology and includes numerous indirect cost and other

accounting mechanisms that are not included in the Control Cost Manual and not adequately

justified. Minnkota's February 11,2010 submittal claims that, "Bums & McDonnell used

standard estimating practices to estimate direct, installation, and indirect capital costs for MRYS

Unit l's and Unit 2's hypothetical application oflow-dust and tail end technologies." While

these estimating practices may be standard for use by B&McD or the utility industry for internal

justification or other accounting purposes, they are not appropriate for use in the context ofthe

BACT analysis. The standard approach is outlined in the Control Cost Manual, so that

comparisons of cost-effectiveness can be made with other projects nationally. B&McD's

approach undermines the ability to make these comparisons. 37

For example, B&McD calculated total indirect capital costs that equal about 50% ofthe

total direct capital cost compared to the Control Cost Manual which uses 20%. Ofthis 50%,

approximately 15% is listed as a "scope contingency" and another 15% is listed as a "pricing

contingency." The Control Cost Manual includes two contingencies for SCRs. The first is a

"process contingency" that is calculated as 5% ofthe direct capital costs. The second is a 15%

"project contingency" and is not considered to be part ofthe indirect capital costs. B&McD

indicates that its "pricing contingency" is equivalent to the "project contingency" in the Control

Cost Manual. B&McD's "pricing contingency" will actually be somewhat lower than the

Control Cost Manual's "project contingency" because, unlike the "project contingency" ofthe

Control Cost Manual, the 15% is not applied to the indirect capital costs. The "project

contingency" ofthe Control Cost Manual is calculated as 15% ofthe total direct plus indirect

37 Enclosure 14 is an example of a cost analysis submitted to NDDH as part of a BART submittal that does not

include many ofthe indirect capital costs and contingencies included in B&McD's analysis. Although EPA may not

be in agreement with every aspect ofthe cost analysis in the example, it does illustrate a case where the Control Cost

Manual format is generally followed and the estimated capital costs are far less (by a factor of almost 4 for LDSCR

on Unit 2, which is a smaller unit in comparison to the example and should cost less) than what was estimated for

MRYS.

-14-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

capital costs. However, B&McD's "scope contingency" of 15% is significantly higher than the

Control Cost Manual's 5% "process contingency." Assuming, as B&McD did, that the "project

contingency" is part of the indirect capital costs, it would equal 18% ofthe direct capital costs

and the total indirect capital costs for the Control Cost Manual would equal 38% ofthe direct

capital cost compared to 50% ofthe capital costs in the B&McD.38 There are other discrepancies

between B&McD's indirect costs and those in the Control Cost Manual. These differences are

tabulated below.

COl C 39 Tabie 1 C fC IC M I&B&M DI dO ° ompanson 0 ontro ost anna c n Irect apIta osts

Indirect Capital Costs Control Cost Manual B&McD Analysis Comparison (% ofDirect Cap Cost"A") (% ofDirect Cap Cost "A")

General Facilities 0.05X A 0.04XA B&McD 1% Lower (Construction Mgt)

Engineering & Home 0.10XA 0.15XA B&McD 5% Higher Office Fees

Startup Expenses 0 0.02XA B&McD 2% Higher

Process Contingency 0.05XA 0.15 X A B&McD 10% Higher (Scope Contingency)

Project Contingency 0.18XA 0.15XA B&McD 3% Lower (Pricing Contingency)

.0- • ).Ai0ci":\' .. +

[";L \T 'JI~l\'IcI)lJ~ O.3S:X:A O.51··X.A,." .·;\;~;I :i: .ili i:.;: . :. !• :T.:; .. Hjf!IJ..~i· ;

While this difference of 13% is significant, B&McD then adds two more contingencies

("cost escalation during project" and "owner's costs - other") and includes an allowance for

funds during construction (interest) before calculating the total capital investment. The Control

Cost Manual allows for "preproduction costs" of2% ofthe total direct, indirect capital costs, and

the "project contingency." Table 2 below compares these "other" costs used by B&McD and the

preproduction costs in the Control Cost Manual. To nonnalize these costs with those tabulated

above, percentages were converted back to the direct capital costs ("A,,).40

38. Per the Control Cost Manual, indirect capital costs = 0.2 times the direct capital costs. So, 15% ofthe total of

direct capital costs plus indirect capital costs = (1.2 * direct capital costs) (0.15) = 18% of direct capital costs.

39. Although, B&McD stated in their December 11,2010 submittal that their BACT cost estimates "follow the

outline ofTable 2.5 in the SCR Chapter of EPA's Control Cost Manual," many items do not match in description, so

some assumptions had to be made. Where there are differences, the B&McD cost is in parentheses. Also, as noted

above, this comparison assumes that "project contingency" of 15% is part ofthe indirect costs, so when applied

exclusively to the direct capital costs only, it becomes 18%.

40. Preproduction costs are listed as being 2% ofthe total direct (A), indirect (B), and "project contingency" (C)

costs. This becomes 3% ofthe total direct capital costs. (B = 0.20 * A; C = 0.18 * A; A + B + C = 1.38 A; 0.02 * 1.38 A = 0.03).

-15-
Table 2. Com

EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

arison of EPA Control Cost Manual & B&McD "Other" Ca ital Costs

Other Costs

Cost Escalation

Control Cost Manual B&McD Analysis

% of Direct Ca (% of Direct Ca Cost "A"

o 0.30 X A

Comparison

B&McD 30% Higher

Allowance for Funds

During Construction

(Interest During

Construction)

Preproduction Costs

Owners Cost - Other

(Owner

o

0.03A

o

0.20XA

o

0.17 X A

B&McD 20% Higher

B&McD 3% Lower

B&McD 17% Higher

Based on Tables 1 & 2 above, the B&McD cost analysis methodology results in capital

costs that are higher by a factor of about 1.8 (0.13 + 0.64 higher) than what would be calculated

using the Control Cost Manual, assuming the same base costs for total direct capital costs. As

noted above, the total direct capital costs used by B&McD appears to be overestimated. A large

portion ofthis discrepancy comes from the "other" costs added by B&McD (Table 2) that are not

included in the Control Cost Manual. These appear to be strictly contingencies and accounting

items which would not be at all unique to MYRS and, therefore, are not justified in the analysis.

These accounting items are unauthorized under the Control Cost Manual, create an unlevel

playing field for comparison with other BACT analyses and alone account for an increase in

.capital costs from the Control Cost Manual by a factor of 1.6.

Although NDDH asked B&McD to provide a detailed explanation regarding its high

indirect capital cost estimates, B&McD's February 11,2010, response to this request fails to

justify why the B&McD cost methodology should be allowed for the MRYS BACT analysis,

when it is not part ofthe Control Cost Manual and is not the standardized methodology used by

other sources. While the Control Cost Manual does contemplate some flexibility in some

contingencies (such as degree ofretrofit difficulty), B&McD has not substantiated the need to go

beyond standard contingencies applied through the Control Cost Manual. As stated in the

Control Cost Manual, "[c]ontingencies is a catch-all category that covers unforeseen costs that

may arise, such as possible redesign and modification of equipment, escalation increases in cost

of equipment, increase in field labor costs, and delays encountered in start-up."4l Thus, the

contingency in the Control Cost Manual should already account for possible changes in labor

costs, and inclusion of a contingency plus escalation of costs is redundant according to the Cost

Manual Methodology. Escalation of costs should not be included as a separate estimate in the

estimate ofTotal Capital Investment since it is included as part ofthe contingency estimate. In

Table 2.5 ofthe SCR chapter ofthe Control Cost Manual, the "Allowance for Funds During

41. See Control Cost Manual, 2002, Chapter 2, Section 2.3.1.

-16-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Construction" (inflation) is specifically listed as zero. It is unclear then why B&McD added

what amounts to 20% ofthe direct capital costs to cover inflation. Including "owner's costs" and

"owner's contingency" is also not consistent with the Cost Manual Methodology and appears to

be redundant.

B&McD mentions that it is anticipated that significant retrofit work will be required

which will affect the scope and price ofthe project. However, there have been many SCR

retrofits facing much more difficult challenges with space limitations and boiler modifications

than MRYS can be expected to face installing a LDSCR or TESCR downstream ofthe ESP (or

FGD) in a rural location. The contingencies outlined in the Control Cost Manual (5% process

contingency and 15% project contingency) are sufficient for purposes ofthe BACT analysis.

B. Inflated Annual Cost Estimations & Cost Methods

In addition to the inflated capital cost estimates and inappropriate cost methods used by

B&McD in the MRYS "BACT analysis that NDDH relied upon, B&McD also used inflated and

unjustified cost estimates for annual costs and used costing methods that are unauthorized by the

Control Cost Manual. Below are some ofthe issues identified by EPA. These are listed

following the numbering scheme in the detailed itemized B&McD BACT cost analysis submitted

December 11,2009 and updated February 11, 2010.

(1) Annual Maintenance Costs:

B&McD uses a factor of3% ofthe installed capital costs ofthe SCR equipment and

auxiliary equipment. The Control Cost Manual uses a factor of 1.5% oftotal capital

investment. No justification was given by B&McD for using a cost factor that is twice as

high.

(2) Annual Reagent Costs:

As stated in NDDH's January 11, 2010, letter to Minnkota and in Mr. Hartenstein's

expert report, the choice to use urea instead of anhydrous ammonia drives up annual

costs. As also stated in Mr. Hartenstein's expert report, the reasons given by B&McD in

the February 11,2010, response to NDDH are not unique to MRYS and do not constitute

justification for choosing the more expensive reagent. Since excessive cost is the main

reason cited by NDDH for not selecting the top level of control as BACT and there is a

less expensive option that is available, the analysis should be redone using anhydrous

ammoma.

-17-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

(3) Annual Electricity Costs:

In its February 11, 2010, response to NDDH, B&McD provided an explanation ofthe

electricity costs associated with extended outage periods for catalyst replacements and

ASOFA maintenance.42 In its analysis, B&McD estimates the following times for

various stages of catalyst replacement:

1) Reactor Cool Down:

2) Installation into spare catalyst layer:

3) Removal ofspent catalyst

and installation offresh catalyst:

4) Reactor heating for startup:

Total (Items 1,2 & 4):

48-60 hours

128 hours (16 shifts - one time event)

192 hours (24 shifts)

36-48 hours

276-300 hours

Conservatively assuming that one spent catalyst is always removed when a fresh catalyst

is added and disregarding the unreasonable assumption that only two shifts per day would

be used to perform the work while the unit remains idle, the range oftotal outage time

estimated by B&McD to cool down the reactor, exchange catalyst, and reheat the reactor

is 276 - 300 hours, or 11.5 - 12.5 days. This does not include the 96 hours (or four days)

ofregular scheduled boiler cleaning downtime that should be subtracted from these

totals. When this is accounted for, there would be a maximum of 204 hours for each

catalyst exchange in excess of normal downtime for each unit.

Even under B&McD's unwarranted "Scenario B" assumption that catalyst is replaced

three times per year for Unit 1 and four times per year for Unit 2, this equates to a

maximum of 900 hours per year of catalyst replacement time for Unit 1 and 1,200 hours

per year for Unit 2. This does not include the 96 hours (or four days) ofregular

downtime that should be subtracted from these totals for each outage period. When this

is accounted for, there would be a maximum of 612 (900 - 288) hours per year for

Unit 1 and 816 (1,200- 384) hours per year for Unit 2 under B&McD's worst case

scenario.

B&McD states that the excess downtime for SCR catalyst replacements under "Scenario

A" would be 213 and 256 hours for Unit 1 TESCR and LDSCR respectively, and 206 and

247 hours for Unit 2 TESCR and LDSCR respectively. It is unclear how B&McD carne

up with these values considering they are higher than the high end total of what was

outlined for each stage ofthe catalyst replacement once subtraction was made for normal

boiler cleaning (maximum of204 hours).

42. The NSR Workshop Manual states: "Lost production costs are not included in the cost estimate for a new or

modified source." Appendix B, p.ll. For the purpose ofthis analysis, EPA is assuming lost production is included

in the cost estimate.

-18-
EPA Comments on NDDH Preliminary

NOx BACT Detennination for MRYS

Furthennore, B&McD states that the excess downtime for SCR catalyst replacements

under "Scenario B" would be 980 and 938 hours for Unit 1 LDSCR and TESCR

respectively, and 1,234 hours for Unit 2 (LDSCR and TESCR). Again, it is unclear how

B&McD came up with these values considering they are higher than the high end total of

what was outlined for each stage ofthe catalyst replacement, even if no time ofthe

outage was subtracted for nonnal boiler cleaning (900 hours for Unit 1 and 1,200 hours

for Unit 2). When the subtraction for nonnal boiler cleaning is made, there is an even

larger discrepancy between B&McD's estimations and what was outlined for each stage

ofthe catalyst replacement (612 hours for Unit 1 and 816 hours for Unit 2).

While B&McD's additional outage times do not appear to correspond to the sum ofthe

catalyst replacement steps outlined in their February 11,2010, submittal, they also do not

appear to reflect the infonnation they received from SCR system and catalyst vendors

and their consultants. The infonnation received from these sources is addressed below.

Reactor Cool Down: Based on a September 29,2010, email from Babcock & Wilcox

Construction Co. Inc., Minnkota was advised that "we typically see 36 to 48 hrs before

entering the SCR." It is unclear why B&McD used 48-60 hours (although, as noted

above, even using the high end oftheir range, the additional outage times stated by

B&McD seem to exceed what would be calculated.) EPA believes 48 hours for reactor

cool down would be a conservative estimate.

Catalyst Exchange: According to a September 15,2009, email, B&McD's consultant

Fuel Tech's, '''rule ofthumb' estimate for catalyst installation is thirty (30) minutes per

module." This is based on conventional access, use ofhoists for module handling and

transport, and a typical crew of 4 to 6 people. With different system design and more

personnel, the time period can certainly be reduced."

As stated in Mr. Hartenstein's expert report, "[b]ased on the catalyst designs from HTI

and CERAM submitted to Minnkota, the number ofmodules per layer ranges from 96 -

104 for Unit 1 and 162 - 182 for Unit 2. Using the stated conservative 'rule ofthumb'

estimate ofthirty minutes per module, this equates to maximum time of2.2 days for Unit

1 and 3.8 days for Unit 2 to replace a layer of catalyst. As stated by Fuel Tech, this 'rule

ofthumb' estimate could be further reduced through design and personnel." This equals

a maximum of 52 hours for Unit 1 and 91 hours for Unit 2.

Based on B&McD's February 11, 2010, submittal the difference in time between

removing spent catalyst (16 shifts) and the removal ofspent catalyst and installing fresh

catalyst (24 shifts) is 64 hours.

-19-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

So, the maximum total time for removing a layer ofspent catalyst and installing

fresh catalyst is as follows:

Unit 1: 64 hours + 52 hours = 116 hours

Unit 2: 64 hours + 91 hours = 155 hours

These are both lower than the time described in the February 11, 2010, response for

removing spent catalyst and installing fresh catalyst (192 hours) Again, even using the

apparently inflated value of 192 hours, the additional outage times stated by B&McD

seem to exceed what would be calculated using these values.

Reactor Preheating for Startup: B&McD has stated this will take 36-48 hours. Based on

the very conservative nature oftheir other estimates and the comments in

Mr. Hartenstein's expert report on this subject, EPA believes 36 hours for reactor

preheating would be a conservative estimate.

Using the information supplied to B&McD and Minnkota from SCR system and catalyst

vendors, and B&McD's consultants, EPA calculates that a conservative total estimate of

excess downtime (subtracting the four days for normal cleaning downtime) from bringing

the unit down, to replacing spent catalyst with fresh catalyst, to bringing the SCR back

online for one layer of catalyst exchange is as follows:

Table 3.EPA Eft sIma es or Caatits E h xc ange r Imes

Replacement Step Time Unit 1 Time Unit 2

(hours) (hours)

Reactor Cool Down 48 48

Spent Catalyst Removal and 116 155 Installing Fresh Layer

Reactor Preheating for Startup 36 36

Subtract Scheduled Downtime -96 -96

EPA Total Estimate 104 143

B&McD Estimate (S, A) 213-247 206-247 • '~,:;~J!: ';'~;;;;,;;; ":,;;;" .,,;;ii;'; t,""()9~143 ' ;:Cc."" r, .."~;ii~L;'i;J0;' ; .1:'1=:inA ii

',; ',:.;;;;,

As can be seen from Table 3 above, B&McD's estimates for catalyst exchange times are

over twice as high for Unit 1 and over 50% higher for Unit 2 when compared to EPA's

estimates (which were based directly on the information provided to Minnkota and

B&McD by vendors and consultants).

Furthermore, B&McD added an additional 181-188 hours per year to the annual

electricity costs for extra downtime due to advanced separated overfire air (ASOFA)

-20-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

maintenance. Even assuming these values are realistic and necessary, which should be

justified by Minnkota, since the more realistic EPA estimates for catalyst exchanges for

both Unit 1 and Unit 2 are less than the stated ASOFA maintenance times, it should be

assumed that the SCR maintenance would be performed at least partially within the same

time allotted for ASOFA-related maintenance. B&McD gives no explanation as to why

the outage times for ASOFA and SCR are cumulative and the work could not be

scheduled and conducted concurrently. One possible reason would be ifthere were short

interruptions required for ASOFA maintenance that did not correspond with the normal

unit cleanings. This seems unlikely (especially for 181 - 188 hours per year) and

B&McD has not indicated that this would be the case normally. Appendix C3 ofthe

original 2006 NOx BACT Analysis provides the only basis that EPA can find for

including any ASOFA downtime. Page C3-3 describes lost availability due to "forced or

extended scheduled boiler outages that may result from problematic cyclone slag tapping

operational conditions encountered during substoichiometric cyclone operation with

SOFA." These times should be justified, as well as the need to conduct this maintenance

at a different time from the normal boiler cleanings and/or the SCR catalyst replacements.

Ifit is found that ASOFA maintenance times can fall within the same normal boiler

cleaning outages, B&McD's cost estimate must subtract all electricity costs attributed to

extended outage times for catalyst replacements accordingly.

Finally, it appears that for "Scenario A", B&McD did not take into account that the

catalyst exchanges will not be occurring each year. Since they will be occurring

approximately every other year, these costs need to be adjusted to an annual basis.

(4) Annual Water Costs:

No comments.

(5) Catalyst Replacement Costs:

Based on Note 5 in the detailed itemized B&McD BACT cost analysis submitted

December 11, 2010, and updated February 11, 2010, B&McD assumed a catalyst price of

$7,500 per cubic meter (in 2006 dollars) in calculating annual catalyst replacement costs.

This assumption appears to be significantly higher than either ofthe bids the two catalyst

vendors provided to Minnkota. Furthermore, this value is also substantially higher than

two ofthe three vendor bids received by Mr. Hartenstein's in response to his vendor

inquiry. It is unclear why B&McD used a unit catalyst price higher than any vendor bid

they received for their BACT analysis. While a higher unit price may be justifiable for

TESCR compared to LDSCR, it appears from Note 5 that B&McD used the same price

for LDSCR and TESCR. Sufficient detail is not provided on how adjustments were made

for the different volumes required for each catalyst replacement in a LDSCR and TESCR

application.

-21-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Furthennore, B&McD did not seem to consider the use ofregenerated catalyst in pricing

catalyst replacements. Catalyst regeneration has been in practice in the utility industry

for years to help save SCR maintenance costs and typically costs less than half ofwhat

new catalyst would cost. Ifthere is some reason Minnkota cannot use regenerated

catalyst at MRYS, this should be justified.

(6) Natural Gas for Flue Gas Reheating & Urea Conversion System:

As noted above and in Mr. Hartenstein's expert report, EPA questions whether natural

gas needs to be used instead ofsteam to reheat flue gas and whether urea needs to be used

instead of anhydrous ammonia at MRYS. See Mr. Hartenstein's expert report for more

infonnation.

(7) Operating Labor for SCR:

EPA agrees that no operating labor (or supervisory labor) should be included, consistent

with the Control Cost Manual.

(8) Annual Costs for Capital Recovery:

Based on greatly inflated capital costs (addressed extensively above), the annual capital

recovery cost is likewise greatly inflated.

(9) Administrative Overhead, Insurance, Taxes, etc.:

No comments.

In addition to the above comments, the levelized total annualized cost approach used by

B&McD is inappropriate, as it is inconsistent with the Control Cost Manual. Based on Note 15

in the detailed itemized B&McD BACT cost analysis submitted December 11,2010, and

updated February 11, 2010, B&McD increased the total direct annual costs (all annual costs with

the exception of capital recovery) by a factor of 1.25. While these estimating practicesmay be

standard for use by B&McD or the utility industry for internal justification or other accounting

purposes, they are not appropriate for use in the context ofthe BACT analysis. The standard

approach is outlined in the Control Cost Manual, so that comparisons of cost-effectiveness can

be made with other projects nationally. B&McD's approach undennines the ability to make

these comparisons.

The Control Cost Manual methodology provides estimates ofoperation and maintenance

that do not change with interest rate and equipment life. The equivalent unifonnannual cost

estimates from the Control Cost Manual are equal across the life ofthe equipment. Changing the

interest rate and equipment life will change the annualized capital cost estimate, but should not

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.,.

EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

change the annual operation and maintenance costs. The Control Cost Manual procedure

provides real estimates of costs (that is, inflation-adjusted), and not nominal costs.

C. EPA Corrected Cost Analysis

Due to the inflated nature ofB&McD's cost estimates, EPA conducted an independent

cost analysis for LDSCR and TESCR at MRYS. This analysis consisted oftwo parts. The first

was to request budgetary proposals from several catalyst vendors on catalyst performance

guarantees (NOx removal, initial catalyst life, and ammonia slip), catalyst volume and

dimensions, catalyst exchange diagrams up to approximately 100,000 hours, and catalyst price.

The Request for Proposal (RFP) was based on what EPA believes to be representative flue gas

characteristics and design specifications for a LDSCR on Unit 1 and a TESCR on Unit 2.

Mr. Hartenstein was hired by the Department ofJustice to perform this work on behalf ofEPA.

The RFP was sent to three catalyst vendors (CERAM, Johnson Matthey Catalysts (JMC),

and Haldor Topsoe) on March 3, 2010. While the facility in the RFP was not identified as

MRYS, the flue gas characteristics in the RFP were based on relevant actual flue gas parameters

found at MRYS, including recent stack test information for Unit 1 and Unit 2 and the 1983

Markowski data on particulate matter concentrations and compositions data for Unit 2.

Furthermore, it was clearly stated in the RFP that the majority ofthe sulfates within the

particulate matter are expected to be sodium and potassium sulfates. Upon request from two

catalyst vendors (CERAM and JMC), a typical coal composition ofCenter lignite was provided.

Responses from all three vendors were received between March 12 and March 31,2010. As

noted in Mr. Hartenstein's expert report, all three catalyst vendors were able to provide an initial

catalyst life guarantee of 24,000 operating hours in response to the RFP, as well as providing

catalyst size and price specifications at the guaranteed NOx and ammonia slip rates. More detail

is provided in Mr. Hartenstein's expert report. The RFP and the vendor responses are also

attached.43

The second part ofthe EPA's independent cost analysis was to calculate SCR cost

effectiveness (dollars per ton) based on the Control Cost Manual or other appropriate methods

using the relevant cost information obtained from the vendor survey conducted by

Mr. Hartenstein in combination with appropriate information in the B&McD cost analysis. For

this effort, EPA hired ERG as consultants.

43. See Enclosure 15. Request for Proposal and Vendor Responses. Portions ofthis enclosure are subject to a

confidential business infonnation claim and will be submitted separately and noted as CBI.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

ERG first evaluated the cost factors and methodology used by Minnkota and made a

comparison with the cost factors and methodology used in the Control Cost Manual. To cross

check the Control Cost Manual results, ERG also compared cost factors and methodology used

by Minnkota to those used in Perry's Chemical Engineering Handbook 6th Edition (Perry's). To

make these comparisons, ERG used the capital and annual cost tables for shared facilities in

Minnkota's December 11, 2009, submittal. For the capital costs, ERG back-calculated the cost

factors B&McD used to escalate SCR equipment costs to a final capital cost number. This

calculation showed that for the B&McD analysis:

• The cost for auxiliarieslbalance ofplant is approximately 80% ofthe SCR costs.

• Capital constructions costs are approximately 50% of capital equipment costs

(SCR plus auxiliaries).

• Indirect capital costs are approximately 50% oftotal capital costs.

• B&McD added another 47% to the capital plus indirect total to account for cost

escalation, interest, and owner's costs.

ERG then compared these cost factors with percentages used in the Control Cost Manual,

as well as Perry's. The comparison oftotal capital costs calculated by B&McD and the Control

Cost Manual is described in detail above under the capital cost analysis. Perry's uses costs

factors that are applied to total equipment costs. These total equipment costs would be

considered equivalent to the SCR system cost used by B&McD's methodology. Comparing the

B&McD and Perry's cost factors shows:

• Perry's adds 55% to equipment costs for auxiliaries compared to B&McD's value

of approximately 80%.

• Total direct costs in Perry's are 2.3 times the SCR system costs while the

B&McD total direct costs are about 2.7 times the SCR costs.

• For the indirect line items included in B&McD's cost table, Perry's adds 56% to

the direct costs which is similar to Minnkota's value of approximately 50%.

• Perry's does not include the factors B&McD added to the capital plus indirect to

account for cost escalation, interest, and owner's costs.

Because B&McD's cost factors are higher than both the Control Cost Manual and Perry's

factors, EPA calculated two additional capital cost cases for comparison. Both cases used the

same format as in B&McD's estimate, but used the Control Cost Manual and Perry's cost

factors, where available. ERG used the 2009 B&McD's SCR costs which were back-calculated

from the 2018 costs provided by Minnkota.44 As can be seen from Table 4 and Figure 1, the

capital costs estimated by B&McD for Minnkota are much higher than both the Control Cost

Manual and Perry's. The Control Cost Manual and Perry's methods compare favorably.

44. EPA strongly disagrees with B&McD assumption that the SCR in this matter will not be installed until 2018.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Table 4. Capital Cost Comparison

Capital Costs (2009, 1,000$) Low Dust Ul Low Dust U2 Tail End U1 Tail End U2

Minnkota $146,753 $254,175 $192,830 $329,150

OAQPS $91,114 $162,999 $120,629 $212,529

Perry's $87,613 $147,699 $108,416 $196,954

Capital Costs (2009; 1,000$)

$350,000 -,-------------------------------,

$300,000 ~-----------------------

$250,000 ~--------

$200,000 +-----------

$150,000 +---==;-------

$100,000

$50,000

$0

• Minnkola

.OAQPS

o Perry's

Low Dust U1 Low Dust U2 Tail End U1 Tail End U2

Figure 1: Comparison of Capital Costs Using Different Cost Methods

ERG then perfonned a new cost analysis that calculated capital and annual costs using

the Control Cost Manual methodology and factors where applicable along with B&McD's

original SCR equipment costs and other cost data that could not be independently verified by

EPA within the time allowed (auxiliaries/balance of plant, construction costs, natural gas

pipeline, reagent costs, natural gas costs), supplemented with other cost data and assumptions

provided by EPA. While EPA could not independently verify many ofthese costs, they were

included to produce an estimate that may overestimate actual costs, but is conservative in a

manner favorable to Minnkota. EPA provided ERG with different infonnation regarding catalyst

volume, catalyst cost, catalyst replacement frequency, and estimated additional outage time for

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

replacing spent catalyst. A conservative value for catalyst cost of$6,000 per cubic meter was

used. As noted above, this cost could be significantly reduced ifregenerated catalyst was used.

Contingencies were calculated using the Control Cost Manual assumptions. The maintenance

costs were adjusted using the cost factor in the Control Cost Manual and annual costs were not

"levelized" as done in the B&McD analysis.

ERG used the above information and calculated annual costs. ERG calculated four

different catalyst replacement scenarios. Scenarios 1 through 3 assume catalyst replacement of

one layer per year, one layer every two years, and one layer every three years. EPA believes

Scenario 3 is the most appropriate, as it reflects the performance guarantees provided by three

catalyst vendors in response to Mr. Hartenstein's RFP and the proposals provided to Minnkota

by one vendor. No calculations were made for the "Scenario B" assumptions used by B&McD

because, as EPA has stated previously and is well-documented in Mr. Hartenstein's expert

report, these assumptions are unsubstantiated and arbitrary. ERG's Scenarios 1-3 do not include

downtime for ASOFA because this has not been justified by Minnkota. Scenario 4 was run as

the "worst-case" scenario and assumes all of the additional outage time is based on the additional

outage times estimated for ASOFA provided by B&McD. There would be no additional unit

outage time (and associated electricity costs) for catalyst replacement, because all ofthis work

could be completed within the time allocated for ASOFA maintenance. As noted above, EPA

does not necessarily concur that these additional outage times for ASOFA are legitimate and

believes they should be justified by Minnkota. ERG modified the amount of time required for

each catalyst layer replacement from B&McD's assumptions, recalculated the unit availability

using the revised downtime, and recalculated electricity costs and corresponding NOx emissions

using the new availability. Table 5 shows the costs for each scenario. The annual costs in this

table include the annual costs associated with capital recovery.

Table 5. Annual Cost Comparison

Annual Costs (2009, 1,000$) Low Dust VI Low Dust V2 Tail End VI Tail End V2

Minnkota - Scenario A $36,923 $63,162 $43,290 $73,245

Minnkota - Scenario B $49,829 $95,310 $56,098 $106,022

OAQPS - Scenario 1 $19,753 $34,114 $23,016 $39,345

OAQPS - Scenario 2 $18,714 $30,837 $21,768 $36,464

OAQPS - Scenario 3 $18,081 $30,524 $21,660 $36,287

OAQPS - Scenario 4 $20,449 $33,370 $23,708 $38,598

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Annualized Costs (2009; 1.000$)

$120,000,----------------------------_

$100,0001-----------------------

$80,0001---------

$60,000 -/--------

$40,000

$20,000

$0

• Minnkola - SCenario A

• Minnkola - scenario B

OOAQPS - Scenario 1

OOAQPS - Scenario 2

.OAQPS - Scenario 3

Ie OAQPS - Scenario 4

Low Dust U1 Low Dust U2 Tail End U1 Tail End U2

Figure 2: Comparison of Annual Costs Using Different Cost Methods

Table 6 shows the costs in dollars per ton of NOx removed in both 2009 and 2006

dollars. North Dakota averaged B&McD's Scenario A and B in their summary, which is also

shown on the table. As can be seen from the table, when the Control Cost Manual cost factors

are used in conjunction with baseline cost information provided by B&McD, supplemented with

more reasonable cost data and assumptions on certain cost data, the cost-effectiveness is less

than half of the "average" value ofthe two B&McD scenarios used by NDDH, even under the

assumption that a layer of catalyst is replaced is every year (Control Cost Manual Scenario 1).

This assumption is three times higher than the catalyst exchange rate that was provided in

proposals from one catalyst vendor to Minnkota and performance guarantees provided to

Mr. Hartenstein from three catalyst vendors. ERG's analysis is attached. 45

45. See Enclosure 16.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

Table 6. Cost Comparison Dollar per Ton Removed

2009 Dollars (1,000$)

Annual Costs Low Dust UI Low Dust U2 Tail End U1 Tail End U2

Mirmkota - Scenario A $3,950 $4,250 $4,632 $4,930

Mirmkota - Scenario B $5,300 $6,362 $5,969 $7,078

North Dakota $4,625 $5,306 $5,301 $6,004

OAQPS - Scenario I $2,120 $2,301 $2,464 $2,654

OAQPS - Scenario 2 $2,010 $2,081 $2,332 $2,461

OAQPS - Scenario 3 $1,942 $2,061 $2,321 $2,451

OAQPS - Scenario 4 $2,194 $2,188 $2,537 $2,531

2006 DoHars (1,000$)

Mirmkota - Scenario A $3,586 $3,859 $4,206 $4,476

Mirmkota - Scenario B $4,813 $5,777 $5,420 $6,426

North Dakota $4,200 $4,818 $4,813 $5,451

OAQPS - Scenario 1 $1,925 $2,089 $2,238 $2,410

OAQPS - Scenario 2 $1,825 $1,890 $2,117 $2,235

OAQPS - Scenario 3 $1,764 $1,872 $2,108 $2,225

OAQPS - Scenario 4 $1,992 $1,987 $2,304 $2,298

Costs ($Iton removed)

$8,000 -,--------------------.-------~

$7,000 +-----------------------

$6,000 +---------

$5,000

$4,000

$3,000

$2,000

$1,000

$0

• Minnkola • Scenario A

• Minnkota - Scenario B

o OAQPS - Scenario 1

OOAQPS - Scenario 2

.OAQPS - Scenario 3

OAQPS - Scenario 4

Low Dusl U1 LowDuslU2 Tail End U1 Tail End U2

Figure 2: Comparison of Cost-Effectiveness Using Different Cost Methods

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

III. Conclusions

EPA requests that NDDH reconsider its preliminary BACT determination and find that

SCR represents BACT controls at MRYS. Since SCR has been successfully applied worldwide

to such a wide variety ofsources, there is a presumption that it is both technically and

economically feasible at MRYS. Minnkota failed to produce sufficient evidence to overcome

this presumption. Although NDDH identified some adverse energy and environmental impacts

associated with the use of SCR, it correctly concluded that these impacts would not preclude the

selection of SCR as BACT.

As more fully set forth above, Minnkota's cost estimates were not conducted in

accordance with the NSR Manual and the Control Cost Manual, and resulted in grossly

overestimated SCR costs. NDDH relied upon Minnkota's faulty cost estimates to conclude that

the cost effectiveness ofLDSCR at MRYS was $4,201 per ton for Unit 1 and $4,822 per ton for

Unit 2. Even these inflated and unreasonable cost estimates must result in a conclusion that

LDSCR is cost effective at MRYS. It is clear that many other sources have borne costs that are

more than this.

NDDH is required to base its BACT determination on cost estimates that are consistent

with the NSR Manual and the Control Cost Manual. IfMinnkota had followed the applicable

methodology, it would have resulted in a determination that the cost effectiveness of SCR at

MRYS was about $2,000 per ton. For the reasons set forth above, NDDH should reject

Minnkota's cost analysis and base its BACT determination on the application of the NSR

Manual and the Control Cost Manual. An objective review ofthese results would show that

SCR is cost effective.

If you would like to discuss any of these matters, please call Cynthia Reynolds at

(303) 312-62006 or Brenda Morris at (303) 312-6891.

rew M. Gaydosh

sistant Regional Administrator

Office ofEnforcement, Compliance and

Environmental Justice

Enclosures

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cc: David Glatt, NDDH (w/o Enclosures),

Dean Haas, NDDH (w/o Enclosures),

Jerry MacLaughlin, USDOJ (w/o Enclosures),

JeffKodish, OECA, (w/o Enclosures),

Brenda Morris, EPA (w/o Enclosures),

Hans Buenning, EPA

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS