Via Federal Express

JUL 3 1 2008

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

Mr: Terry O'Clair

Director, Division ofAir Quality

North Dakota Department ofHealth

918 E. Divide Avenue

Bismarck, ND 58501-1947

Re: Transmittal of EPA's Comments on the

North Dakota Department ofHealth's

Preliminary NOxBACT Determination for

Milton R. Young Station

Dear Mr. O'Clair:

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

comments on the North Dakota Department ofHealth's (NDDH's) Preliminary Best Available

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

Station (MRYS), Units 1 and 2 that was dated June 2008 and published for public comments

beginning on June 11,2008 and ending on July 11,20081 (hereinafter, "the NDDH BACT

determination").

EPA asserts that the operator ofMRYS, Minnkota PowerCooperative, Incorporated

("Minnkota"), failed to meet its burden of demonstrating to NDDH that selective catalytic

reduction (SCR) is technically infeasible under Step 2 ofthe Top-Down BACT analysis and

NDDH failed to provide a reasoned justification for its elimination of SCR as a control option at

MRYS. EPA is providing additional information supporting the technical feasibility of SCR at

MRYS for NDDH to consider and include in the administrative record for NDDH's Final BACT

determination. The comments and additional documents supplement previous correspondence

between EPA and NDDH concerning the October 2006 BACT analysis (hereinafter, "the

Minnkota BACT analysis") that was submitted by Bums & McDonnell ("B&McD") on behalf of

Minnkota. EPA submitted previous comments to NDDH on the Minnkota BACT analysis in

letters dated January 11,2007, January 26,2007, and October 4,2007. NDDH has not

adequately responded to many ofthe substantive issues raised in these letters.

1 Per July 8, 2008 letter from NDDH to EPA, the public comment period was extended until close of business on

August 1, 2008.
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

As described in more detail in the Enclosure, the basic premise ofthe NDDH BACT

determination is unreasonable and unsupported because it relies on the lack of a demonstrated

application of SCR technology to North Dakota lignite-fired cyclone boilers to eliminate from

consideration the application ofSCR to the units at MRYS.2 This premise is both an incorrect

application ofEPA's "Top-Down" BACT procedure, as outlined under Chapter B ofthe "New

Source Review Workshop Manual---Prevention of Significant Deterioration and Nonattainment

Area Permitting," (Draft October 1990) (EPA's NSR Manual)3 and also fails to consider the

widespread and successful application of SCR to utility boilers worldwide and to other industrial

stationary source types that have extremely varied and challenging flue gas characteristics.

NDDH's BACT determination uses the lack of demonstrated application of SCR specifically to

cyclone boilers fired with lignite from the Center Mine to conclude that the SCR technology in

any form would be technically infeasible and thus eliminated from consideration ofthe TopDown BACT analysis.

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

fuel type worldwide. In meeting these varied and significant challenges for the widespread

deployment ofSCR technology, system designers must always tailor the specifics ofSCR

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

the system. In the most challenging situations with highly variable flue gas characteristics

containing potential catalyst poisons in significant concentrations, designers have successfully

used the tail-end or low-dust SCR design.

The responses from the vendor query that was submitted by Minnkota and further pursued

by EPA clearly confirm that SCR is an available control option thatcan be applied to MRYS

without the need for any pilot testing. As detailed in the Enclosure, vendors have stated that a

tail-end SCR system would without question address the uncertainties and technical challenges.

associated with firing North Dakota lignite in a cyclone boiler described in the NDDH BACT

2 The focus ofEPA's comments herein is on SCR because this is the "top" add-on control option (Le. has the

highest potential degree of control) listed in the NDDH BACT determination. As such, EPA's primary concern is

that the "top" control option has been improperly eliminated from consideration. However, EPA has previously

commented on other control options (Hydrocarbon Enhanced Selective Non-Catalytic Reduction, Reburn with

Selective Non-Catalytic Reduction (SNCR), and Rich Reagent Injection with Advanced Separated Overfrre Air and

with SNCR) also being improperly eliminated as being technically infeasible in the Minnkota BACT analysis and

those comments stand. While the NDDH BACT determination for these other control options cites information

provided by Minnkota, there is no mention or response to the EPA's previous comments. EPA requests that NDDH

consider and respond to previous EPA comments prior to making the final BACT determination for these control

options.

3 The Consent Decree (Civil Action 1:06-CV-034) requires that the NDDH make its NOx BACT Determination, "in

accordance with the applicable federal and state statutes, regulations, and guidance cited in the defmition of "NOx

Top-Down BACT analysis," which requires the BACT analysis to, "be carried out in accordance with the provisions

ofChapter B ofEPA's 'New Source Review Workshop Manual- Prevention of Significant Deterioration and

Nonattainment Area Permitting,' (Draft 1990)." See page 7 ofthe Consent Decree.

-2-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

determination. Both SCR system suppliers and catalystsuppliers clearly believe tail-end SCR

is an available NOx control option at MRYS and would not require any pilot testing/or

application at MRYS. Vendor responses also indicate that a high-dust application is

commercially available at MRYS, albeit with the same concerns they-routinely have about the

uncertainties involved in applying SCR to any different fuel type and acknowledging the

challenge to maintain the proper temperature range for catalyst performance and life at MRYS.

EPA submits the following Enclosures for inclusion in the administrative record: (I)

supplemental information and expert technical opinion report (including references) of

consultant, Hans Hartenstein, President ofEvonik Energy Services LLC, (2) specific comments

by EPA on the NDDH BACT determination, and (3) additional documentation to be considered

in NDDH's final BACT determination.4 Mr. Hartenstein has included copies ofmost ofthese

references with his report. EPA believes the remainder ofthe references are public documents

and generally available. EPA can provide copies ofthese documents upon request by NDDH.

If you would like to discuss any ofthese matters, please call Cynthia Reynolds at

(303) 312-62006 or Brenda Morris at (303) 312-6891.

Andre M. Gaydosh

AssistantRegional Administrator

Office ofEnforcement, Compliance and

Environmental Justice

Enclosures

cc: David Glatt, NDDH (w/o Enclosures),

Dean Haas, NDDH (w/o Enclosures),

Jerry MacLaughlin, USDOJ (w/o Enclosures),

JeffKodish, OECA, (w/o Enclosures),

Ron Rutherford, EPA (w/o Enclosures),

Brenda Morris, EPA (w/o Enclosures),

Hans Buenning, EPA

Amy Platt, EPA (w/o Enclosures),

Douglas Latimer, EPA (w/o Enclosures),

4 Enclosure 3 contains documents that EPA received from Bums & McDonnell in response to an information

request submitted by EPA. Some ofthese documents may contain confidential business information and should be

handled accordingly.

-3-

ENCLOSURE 1

HANS HARTENSTEIN'S EXPERT OPINION REPORT

& REFERENCES (ON CD - 2 COPIES)

Feasibility of SCR Technology for NOx Control Technology

for the Milton R. Young Station, Center, North Dakota

Expert Report of

Hans Hartenstein

ON BEHALF OF THE

UNITED STATES DEPARTMENT OF JUSTICE

July 2008

A- 1
TABLE OF CONTENTS

Page

1. INTRODUCTION AND OVERVIEW 3

1.1 Information Required for the Expert Report 3

1.2 Purpose ofthe Report 3

2. SUMMARY OF CONCLUSIONS 4

3. QUALIFICATIONS 6

4. .THE MILTON R. YOUNG STATION: BACKGROUND 8

5. SCR TECHNOLOGy 8

6. SCR EVALUATION 19

6.1 Variability of Fuel Composition : 23

6.2 Results ofthe Coyote Pilot Testing 24

6.3 Soluble Sodium 27

6.4 Differences in Flue Gas Composition 29

6.5 Experience of Bums and McDonnell and Sargent and Lundy 30

6.6 Development Stage of High-Dust SCR 32

6.7 Temperature Variations 33

6.8 Catalyst Erosion 33

6.9 Catalyst Poisoning, Blinding and Plugging 34

6.10 Lack of Pilot Scale Testing Data 36

6.11 Lack of Vendor Guarantees 38

6.12 Review Authority 39

6.13 Conclusions 39

7. VENDOR QUERY TAIL-END SCR 46

8. SUMMARy 49

Appendix A: Data and Information Considered 51

Appendix B: SCR Vendor Query Correspondence 57

Appendix C: Selected Papers Authored in Last Ten Years 67

Appendix D: Resume 73

A-2
1. INTRODUCTION AND OVERVIEW

1.1 Information Required for the Expert Report

The following is a listing ofthe items provided with this report:

(1) This report contains my personal opinions, conclusions and the reasons

therefore.

(2) The body ofthe report and Appendix A list the data and other information

considered in forming these opinions.

(3) Appendix B provides a copy ofthe e-mail correspondence with several

selective catalytic reduction (SCR) catalyst manufacturers and SCR

equipment vendors concerning the technical feasibility oftail-end SCR

(TESCR).

(4) Appendix C includes a listing of publications authored during the past ten

years.

(5) Section III presents a statement of my qualifications; my resume is attached as

Appendix D.

(6) I am being compensated for the preparation ofthis report and my testimony

by the U.S. Department ofJustice.

(7) I have provided previous testimony within the preceding four years as an

expert at trial or by deposition.

1.2 Purpose ofthe Report

This report is written under a consulting contract and pursuant to a request from the

Department ofJustice (DOJ) for an analysis of whether or not the SCR technology would be

a technically feasible and available technology for the reduction of nitrous oxides (NOx) for

installation at the Milton R. Young Station located near Center, North Dakota.

A preliminary Best Available Control Technology (BACT) determination for control ofNOx

for the M.R. Young Station conducted by the Division of Air Quality ofthe North Dakota

Department of Health1 (the Department) concludes that the SCR technology is not

l Preliminary Best Available Control Technology Determination for Nitrogen Oxides for M.R. Young Station

Units 1 and 2, Division ofAir Quality NO Department ofHealth, 918 E. Divide Avenue, Bismarck, NO,

June 2008.

A-3
technically feasible at this time. I was asked to review the information in and provided by

this preliminary BACT determination and render an expert opinion concerning the technical

feasibility ofthe SCR technology for retrofit at the M.R. Young Station.

2. SUMMARY OF CONCLUSIONS

In summary, and for the reasons described herein, I have concluded that the SCR technology

is technically feasible and principally available for installation at both units at the Milton R.

Young Station for NOx reduction. I have further concluded that even though the high-dust

SCR (HDSCR) principle was investigated in some detail prior to the BACT determination:

The depth ofthe investigation concerning the technical feasibility ofHDSCR in this

case by means of pilot testing conducted at the Coyote Station (Coyote Pilot Testing)

was insufficient and the conclusions drawn from this pilot testing were speculative

and premature.

Virtually no investigation ofthe technical feasibility oflow-dust SCR (LDSCR) and

TESCR was conducted at all and both distinctly different SCR principles were

incorrectly treated as ifthey would be essentially the same.

The HDSCR Coyote Pilot Testing was ill-designed and inadequately conducted.

The data generated by the Coyote Pilot Testing for these reasons is inconclusive and

meaningless ofthe purpose ofthis determination.

The conclusions suggested by the Department based on the data presented are not

reasonably founded but premature, purely speculative and mostly incorrect.

Consequently, it is my opinion that the conclusions presented by the North Dakota

Department of Health in the BACT determination2., namely, that the SCR technology is not

technically feasible at this time for both units at the M.R. Young Station, is wrong. Such a

conclusion cannot be drawn correctly based on the available data. The SCR technology must

be considered principally, technically feasible for Minnkota's Milton R. Young Station. This

is even true for HDSCR even though not without significant but technically resolvable

challenges, which may result in HDSCR not being the economically most advantageous SCR

principle. However, whether HDSCR, LDSCR or TESCR is the economically most viable

SCR solution for M.R. Young is beyond the scope ofthis report.

Finally, I have concluded that no sufficiently detailed investigation was conducted for

LDSCR and/or TESCR in this case and the record ofinvestigation provided by the

£. Preliminary Best Available Control Technology Determination for Nitrogen Oxides for M.R. Young Station

Units I and 2, Division of Air Quality ND Department ofHealth, 918 E. Divide Avenue, Bismarck, ND,

June 2008.

A-4
Department is insufficient, inadequate and incomplete. Both ofthese SCR principles were

incorrectly treated by the Department as being essentially the same, which is incorrect and

unacceptable as the flue gas composition and characteristics entering a LDSCR are

completely different from the one entering a TESCR.

The statement made by the Department that none ofthe various principles ofthe SCR

technology (HDSCR, LDSCR, TESCR) can be considered applicable and technically

feasible at this time is not only purely speculative but factually incorrect. As a matter offact

a quick vendor survey conducted by me confirmed that all contacted vendors consider

TESCR as being unquestionably technically feasible, available and applicable for M.R.

Young Station. This was not only unanimously confirmed by all leading catalyst

manufacturers (Argillon, CERAM, Cormetech, Haldor Topsoe and Hitachi) but also by

leading SCR equipment vendors (Alstom, Babcock Power and Babcock & Wilcox).

Furthermore, these SCR equipment vendors and catalyst manufacturers confirmed my

opinion by stating that they also consider LDSCR as technically feasible and probably even

HDSCR, however not without significant but resolvable technical challenges such as limiting

the boiler outlet temperature variations to a range tolerable for SCR catalyst and eliminating

the popcorn ash problem. The temperature variations at the boiler outlets appear to be the

biggest hurdle for the application of HDSCR at this time; however, this issue is considered to

be technically resolvable as indicated by Babcock & Wilcoxd, who supplied both boilers at

M.R. Young Station. Answering the question of whether or not the extent ofmodifications of

existing equipment required to resolve the temperature variation issue makes HDSCR

economically less attractive in comparison to LDSCR or even TESCR is beyond the scope of

this report.

However, it is my opinion that the available data presented in the Department's BACT

determination± is insufficient, inconclusive and interpreted largely incorrectly when

concluding the HDSCR is technically infeasible. This conclusion cannot be supported by the

available data at all. Furthermore, concluding that LDSCR and/or TESCR are not technically

feasible based on the available data is incorrect, since no relevant data was presented that

supports such a conclusion in any way. Based on my more than 20 years of SCR experience

and my evaluation ofthe vendor responses, it is my opinion that the SCR technology is

technically feasible and principally available for installation at both units at the Milton R.

Young Station for NOx reduction. The only design engineering challenge is the proper

selection ofthe best suitable type of SCR principle.2. to be applied and the correct SCR

process and catalyst design. This, however, is neither a question oftechnical feasibility nor

of applicability or availability ofthe SCR technology but simply a question of economics.

;). E-mail from Steve Moormann (Babcock &Wilcox) to Robert Blakley (Bums & McDonnell) dated July 18,

2007.

.1. Preliminary Best Available Control Technology Determination for Nitrogen Oxides for M.R. Young Station

Units 1 and 2, Division of Air Quality NO Department ofHealth, 918 E. Divide Avenue, Bismarck, NO,

June 2008.

2. Defined by its location on the flue gas pass as HDSCR, LDSCR or TESCR.

A-5
3. QUALIFICATIONS

I have been involved in the business development, proposal engineering and estimating,

project management, process and design engineering, component and equipment

procurement, construction, erection, commissioning and start-up and operation of air

pollution control equipment for utility and industrial power plants as well as waste

incinerators (municipal waste, hazardous waste, sewage sludge, medical waste etc.) in a

variety of capacities for over twenty years. I began my career in the field of air pollution

control in 1983 as a staff engineer working for Mercedes-Benz in automobile engine

development adapting standard type European automobile engines with catalytic converters,

secondary air injection systems, exhaust gas recirculation systems etc. in order to comply

with more stringent emission regulations in entities such as California, the U.S. (48 states),

Japan etc.

In late 1987, I accepted a position with L&C SteinmUller GmbH in Germany, which was one

ofthe leading engineering and equipment vendors supplying power utility boilers, including

the associated air pollution control equipment. Initially, my field of responsibility included

business development for all environmental control technologies (air, water, waste) in

Southern Germany. In 1990, I became Department Manager ofthe Department of Gas

Cleaning for waste incineration facilities. In 1993, I became General Manager for Flue Gas

Cleaning at L&C SteinmUller. Between 1988 and 1999, I was personally fully involved in the

following retrofit phases in Europe:

Retrofitting all fossil fuel fired boilers (utility and industrial) with a thermal heat

input ofmore than 300 MW with flue gas desulfurization (FGD) systems ensuring a

continuous S02 removal efficiency of at least 85% at all times, mostly wet limestone

forced oxidation (LSFO) FGDs producing wallboard quality gypsum as a byproduct.

This retrofit phase started in Western Europe in the late 1970s and ended in Eastern

Europe in the late 1990s. FGD retrofits focused on Austria, Belgium, Bulgaria, Czech

Republic, Denmark, Finland, Germany, Greece, Holland, Hungary, Poland, Slovenia,

Slovakia, Spain, Sweden, Turkey and the U.K.

Retrofitting all fossil fuel fired boilers with a thermal heat input ofmore than 300

MW with nitrous oxide removal (DeNOx) systems ensuring a NOx emission rate of

less than 100 ppmQat all times, almost exclusively selective catalytic reduction (SCR)

DeNOx systems. This retrofit phase started in Europe in the mid 1980s and is still

ongoing. SCR retrofits focused on Austria, Belgium, Denmark, Finland, Germany,

Holland, Italy, and Sweden.

Retrofitting all waste incineration facilities regardless ofthe type ofwaste (municipal,

industrial, hazardous, sewage sludge, medical etc.) with extensive flue gas cleaning

2 At the following flue gas characteristics: NOx concentration by volume on a dry basis @ 5% O2, 1 atm.,

273 K.

A-6
systems for the removal of acid gases (SOx, HCI, HF), NOx, particulate matter (PM),

heavy metals including mercury (Hg), cadmium (Cd), lead (Pb) and numerous others

as well as dioxins (PCDD) and furans (PCDF). This retrofit phase started in Europe

in the early 1990s and is still ongoing. Waste incinerator retrofits focused on Austria,

Denmark, Finland, France, Germany, Holland, Norway, Sweden, and the U.K.

In 1999, I became a co-founder and Managing Director ofE&EC - Energy & Environmental

Consultants GmbH, an international engineering consulting firm with offices in Germany

and a representation in the U.S. Through E&EC I assisted a German SCR catalyst

manufacturer in a concentrated effort to supply SCR catalyst and system expertise to the

North American market. Also, through E&EC I assisted Babcock Borsig Power in Germany

to align their German subsidiary Babcock Borsig Power Environment (former L&C

SteinmUller) with their U.S. subsidiary DB Riley (today Babcock Power) in Worcester,

Massachusetts in order to take full advantage ofthe business opportunities provided through

the NOx SIP call under the Clean Air Act Amendments (CAAA) Title I Groundlevel Ozone

Requirements1.

Three months into the project, I was offered to take over the environmental business unit of

DB Riley, Inc. (later renamed Babcock Borsig Power, Inc., now renamed Babcock Power,·

Inc.) in Worcester, Ma. After accepting this position, I was responsible for the SCR retrofits

for the coal-fired units of American Electric Power (AEP), Detroit Edison (DTE), Duke

Power, Louisville Gas & Electric (LG&E) and its subsidiaries Kentucky Utilities (KU) and

Western Kentucky Energy (WKE), all now consolidated under E.ON-US, Northern Utilities

(NU), Pennsylvania Power & Light (PP&L), Santee Cooper (SC), and Wisconsin Electric

Energies (WE Energies) as well as the development ofthe emerging markets for FGDs and

mercury-removal technologies. I left DB Riley and refocused on E&EC shortly before DB

Riley's German parent company declared bankruptcy.

Through E&EC I founded SCR-Tech LLC together with a German partner and was acting

president ofSCR-Tech between 2001 and 2005. SCR-Tech was dedicated to providing the

North American utility industry with SCR management and catalyst regeneration services.

After the sale of SCR-Tech in 2004, I left SCR-Tech in 2005 and joined Steag LLC, a wholly

owned subsidiary ofSteag AG in Germany. Steag AG (now renamed Evonik Steag GmbH)

is part of Evonik Industries AG and dedicated to power generation and engineering. Evonik

Steag GmbH owns and operates more than 10,000 MW of mostly coal-fired power plants

around the world. In 2005, I accepted the position as president of Evonik Energy Services

LLC (formerly Steag LLC), which has been dedicated to serve the North American utility

industry with SCR design and management services since 1992 and also with catalyst

regeneration services since 2007.

Through E&EC, I am also assisting the North American utility industry in their SCR and

1 Call by USEPA for State Implementation Plans in 19 Eastern States in order to reduce the NOx emissions of

large sources (e.g. coal fired power plants) as required by the 1990 Clean Air Act Amendments (CAAA)

under Title I - Groundlevel Ozone.

A-7
FGD needs by fully utilizing my experience and expertise, which I developedover the past

21 years working as an engineer solely in the area of air pollution control systems for fossil

fuel fired power plants and waste incineration facilities with a focus on FGDs and SCRs.

4. THE MILTON R. YOUNG STATION: BACKGROUND

The M. R Milton Station consists oftwo North Dakota lignite-fired steam electric generation

units, with gross electric generating capacities of approximately 257 megawatts electric

(MWe) (Unit I) owned by Minnkota Power Cooperative and 477 MWe (Unit 2) owned by

Square Butte Electric Cooperative. The units went into operation in 1970 (Unit 1) and 1977

(Unit 2). Both units feature cyclone-fired Babcock & Wilcox (B&W) boilers followed by

tubular air pre-heaters. Air pollution control equipment consi,sts of overfire air (OFA)

systems for both units (Unit 2 OFA is scheduled in 2007 and Unit I OFA in 2009), a coldside electrostatic precipitator (ESP) for particulate matter (PM) control for both units and a

lime/fly ash wet scrubber for sulfur dioxide (SOz) control for Unit 2~. Unit I will be

retrofitted also with a wet lime scrubber supplied by Marsulex, which is scheduled to

commence operation in April 2011.2. Additionally, Minnkota Power Cooperative and Square

Butte Electric Cooperative are committed to retrofit BACT for NOx control for both units

under a Consent Decree with the United States and the State ofNorth Dakota, dated July 27,

2006. The NOx control technology to be retrofitted must be determined by a top-down

BACT Analysis, which must evaluate various technologies including SCR.

5. SCR TECHNOLOGY

The selective catalytic reduction (SCR) technology was originally developed in Japan under

a government grant in the 1970s and subsequently retrofitted to most Japanese fossil fuel

fired power plantslQ. SCR involves injecting gaseous ammonia generated from UREA,

aqueous or anhydrous ammonia into the flue gas at a specific temperature before it reaches a

catalyst. The catalyst significantly lowers the temperature required to complete the reaction

ofthe injected ammonia with NOx (mostly nitrogen oxide NO and nitrogen dioxide NOz) to

form nitrogen and water. Therefore the SCR reactor can be operated at a lower temperature

zone at a suitable location in the flue gas path. Compared to the same reactions taking place

without the presence of a catalyst, which is commonly referred to as selective non-catalytic

reduction (SNCR) and requires flue gas temperatures between 1,500 F (~800 DC) and 2000 F

Milton R. Young Station - Our Jewel on the Prairie, brochure published by Minnkota Power Cooperative

and Square Butte Electric Cooperative on Minnkota's website: www.minkota.com.

2 McIlvaine Utilitiy E-Alert #868, April 4, 2008.

12 Ando, Jumpei, "S02 and NOx Removal for Coal Fired Boilers in Japan," presented at the Seventh

Symposium on Flue Gas Desulfurization, May, 1992.

A-8
(~ 1,100 °C), the SCR process allows for a much higher NOx removal efficiency compared to

the SNCR process while ensuring a very low (typically less than 2 ppmvd @ 3% 02)

ammonia slip. Continuous NOx removal efficiencies of well above 90% with NOx outlet

concentrations well below 0.05 Ibs/MMBtull have been reportedll.

Various principles ofthe SCR technology are commonly described foremost by the SCR

reactor's location within the flue gas path. Three main categories of SCR systems with one

being split into two subcategories are known for fossil fuel fired utility boilers, namely:

High-dust SCR (HDSCR) located between the boiler's economizer outlet and the air

perheater inlet upstream ofthe ESP (pictured below). At this location typically no

reheating ofthe flue gas is required.

Steam

Boiler

High-Dust SCR

Reactor

Flue Gas

Oesulfurization

Low-dust SCR (LOSCR), which is split into two subcategories, namely:

o Hot-side LDSCR located downstream ofa hot-side ESP and upstream ofthe

air preheater (not pictured below). At this location no reheating ofthe flue gas

is typically required as the hot-side ESP is also upstream ofthe air pre-heater.

o Cold-side LDSCR located downstream ofthe air preheater as well as

downstream of a cold-side ESP (pictured below). At this location reheating of

the flue gas is typically required as the cold-side ESP is downstream ofthe air

preheater.

.!l.. MMBtu = million British thermal units.

II Erickson, c., S. Straight, L. Hutcheson, "Coal-Fired SCR Operating Experience with High Removal

Efficiency and Low-NOx Firing Systems", Babcock Power's website: www.babcockpower.com.

A-9
Steam

Boiler

Steam Coil For

Flue Gas

Reheating

Low-Dust

SCR

Reactor

Gas/Gas

Heat

Exchanger

Tail-end SCR (TESCR) located downstream of a dry or wet flue gas desulfurization

(FGD) system (pictured below). At this location the same type and net quantity of

reheating ofthe flue gas is always required as in case ofLDSCR located downstream

of a cold-side ESP pictured above.

Steam

Boiler

Steam Coil

For Flue Gas

Reheating

Tail-End

SCR

Reactor

Gas/Gas

Heat

Exchanger

~~~

After the technology was initially installed in Japan, SCR began to be used in Europe, mainly

in Germany during the 1980s, where legislation introduced in 198311 required all power

plants to drastically reduce the NOx emissions by the end ofthe decade. As a result, the first

HDSCR on a coal-fired power plant in Europe went into operation in 1985 (Altbach Power

il EPA-450/3-92-004, Office ofAir and Radiation, Office ofAir Quality Planning and Standards, "Summ\lry of

NOx Control Technologies and their Availability and Extent of Application", February 1992.

A-I0
Station Unit Sl.±), the first TESCR in Europe went into operation in 1986 (Hamburg Hafen

Generating Station Unit 1.li) and the first LDSCR went into operation in 1988 (Walsum

Cogeneration Plant Unit 7

lQ). By the end ofthe 1980s, SCRs were used in a wide variety of

coal-fired power plants worldwide after Austria, Denmark, Germany, Holland and Japan had

retrofitted most oftheir coal fired power plants with SCR systems for NOx removal. Even

the first HDSCR on a lignite or brown coal fired utility boiler went into operation in Austria

in 1990 (Voitsberg Power Station Unit J11). By the end ofthe 1980s, well over 100 SCR

systems had been installed in Europe on more than 30,000 MW of coal fired ~enerating

capacity with most SCRs representing retrofits of coal fired generating unitsL ~.

As reported by the Electric Power Research Institute (EPRIio, an institution solely funded by

and dedicated to the electric utility industry, by 1989 the SCR technology was fully

developed in two basic forms, namely as HDSCRs and as TESCRs. It is worth mentioning

that the TESCR principle was mainly developed for the use on cyclone-fired and other wet

bottom boilers because oftheir very high catalyst deactivation rates resulting from high

arsenic levels in the flue gas in case offly ash re-injection into the furnace for internal

vitrification and no arsenic mitigation by means of limestone addition. Furthermore, TESCRs

were also applied in some cases due to space constraints and/or difficult retrofit sites where

the installation of a HDSCR would have caused elongated periods of downtime ofthe unit.

In total about 40% ofthe SCR retrofits in Europe were TESCRs.

EPRI211reports that all European SCR systems visited during a field trip in 1988 consistently

met their design removal efficiencies of up to 88% in HDSCRs and TESCRs operating in

coal fired units firing coals with sulfur contents up to I.S %wt. This overall finding was

solidified by 1989 after additional years of operating experience.

EPRI reported heat rate penalties on the unit between 1 and 3% resulting from the necessity

offlue gas reheating in case of cold-side LDSCR and/or TESCR. Such flue gas reheating

requires the use of a gas/gas heat exchanger, in which the flue gas coming from the SCR

1.1 Fisia Babcock GmbH (formerly L&C Steinmiiller GmbH) and Babcock Power, Inc. reference lists SCR

systems.

.li Ibid

l.§ Ibid

11 Reference list on CERAM's website: www.frauenthal.net.

.lli Technical Feasibility and Cost ofSCR NOx Control in Utility Applications, RP 1256-8 prepared by United

Engineers and Constructors, Inc. for Electric Power Research Institute (EPRI), August 1989.

12 EPA-450/3-92-004, Office of Air and Radiation, Office of Air Quality Planning and Standards, "Summary of

NOx Control Technologies and their Availability and Extent of Application", February 1992.

.fQ Technical Feasibility and Cost ofSCR NOx Control in Utility Applications, RP 1256-8 prepared by United

Engineers and Constructors, Inc. for Electric Power Research Institute (EPRI), August 1989.

l..!. Ibid

A- 11
reactor outlet is used to reheat the flue gas going to the SCR reactor inlet similarly to an air

preheater. These gas/gas heat exchangers can be designed as rotary type, tubular or plate type

heat exchangers. All three types have been utilized successfully. Since a 100% efficient heat

transfer from the outgoing to the incoming flue gas is physically impossible, a comparatively

small amount of additional energy must be provided for reheating the flue gas downstream of

the gas/gas heat exchanger to the SCR reactor inlet temperature. This additional energy,

which is needed to overcome the temperature gradient ofthe gas/gas heat exchanger,

amounts to an additional heating ofthe flue gas oftypically between 45 degrees F (25 K) and

no more than 90 degrees F (50 K) with amounts known as low as 18 degrees F (IO K). Flue

gas reheating is most commonly accomplished in one oftwo ways, namely:

In case of coal-fired power plants or when steam ofsufficiently high pressure and

temperature is available, a steam coil is used for flue gas reheating. The use ofsteam

for flue gas reheating is generally the most economical and advantageous method as it

neither increases the flue gas flow rate nor adds any additionally constituents (i.e.

NOx) to the flue gas. Steam reheating is particularly economically advantageous in

coal-fired power plants, which are "turbine limited" meaning the boiler can generate

more high pressure steam at full load than the turbine needs for generating its

maximum electrical output. In such a case, the surplus generated high pressure steam,

which cannot be used for generating electricity, is ideally suitable for the use ofsteam

reheating ofthe flue gas without or only minimal impact on the generating capacity

ofthe unit. In this case, the heat rate penalty ofthe unit may be eliminated entirely.

In case no steam or only steam ofinsufficient temperature and pressure is available as

it is the case in many non-power plant applications, natural gas duct burners are

typically used for flue gas reheating. Such flue gas reheating results in some

additional operating cost for natural gas, which, however, can at least partially be

offset by significantly prolonged catalyst life oftypically well over 100,000 SCR

operating hours, a smaller overall SCR reactor, less installed catalyst volume and a

smaller catalyst pitch22• In some cases the additional operating costs can be

completely offset by the elimination of extended unit downtime, which would be

necessary for an HDSCR retrofit, and the availability of excess high pressure steam,

thus making TESCR the most economical solution.

EPRI23 reported TESCR systems in Europe to achieve NOx removal efficiencies

between 83 and 92% with cost between US$ 180 - 225 per kW and HDSCR systems

to achieve NOx removal efficiencies between 65 and 88% with cost between US$ 65

- 200 per kW. Considering the fact that this was reported in 1989, in other words

more than a decade before the SCR retrofit phase in the U.S. resulting from the

1£ Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Tenn SCR Catalyst Experience and Cost", The

2005 EPR! Workshop on Selective Catalytic Reduction, Louisville, KY, November 2005.

II Technical Feasibility and Cost ofSCR NOx Control in Utility Applications, RP 1256-8 prepared by United

Engineers and Constructors, Inc. for Electric Power Research Institute (EPR!), August 1989.

A- 12
CAAA NOx SIP ca1l24 and considering the fact that the cost of almost all SCRs

retrofitted in North America were within this range, it can be reasonably expected

that the retrofit cost for TESCR will also fall approximately within the range

determined by EPRI back in 1989.

All European and North American HDSCRs have achieved their targeted NOx emission rates

without any major operational problems. Early design flaws mostly resulting from

inadequate flow conditions and flue gas distribution problems were mostly corrected by

about 1990. By early 2000 more than 23,000 MW of SCRs were in operation in Japan and

more than 55,000 MW in Europe25, of which about 40% are TESCRs. Currently, more than

an estimated 250,000 MW of HDSCRs are successfully operating worldwide on utility

boilers with an estimated more than 100,000 MW in North America. The balance can be

found in Europe (Austria, Belgium, Denmark, Finland, France, Germany, Holland, Italy,

Portugal, Spain, Sweden, Turkey, etc,) and Asia (China, Japan, Korea, Taiwan, etc.).

By 1989/1990 approximately 18,000 MW of TESCRs were in operation or near completion

on coal-fired utility boilers in Europe. At the same time almost four years of extremely

positive operating experience had been collected on the first TESCR, which went into

operation in Hamburg in 1986. Today after more than 20 years ofTESCR operating

experience, catalyst lifetime in excess of 100,000 is considered normae6

.

As a result ofthis extremely positive long term operating experience with TESCR, this

principle was generally adopted as a universally applicable SCR solution for all types and

compositions offlue gases incompatible for HDSCR due to the catalyst deactivation

characteristics. Incompatible conditions for HDSCR can be either due to:

physical parameters ofthe flue gas, which are unacceptable, such as temperature, ash

content, etc., or

chemical composition ofthe flue gas, which may cause uneconomically rapid catalyst

deactivation such as higher concentrations of gaseous arsenic, phosphorus, sodium,

potassium, calcium, magnesium, chromium, barium, selenium, etc..

Consequently, TESCRs were installed for NOx control on a wide variety of high temperature

combustion and other thermal processes including:

Call by USEPA for State Implementation Plans in 19 Eastern States in order to reduce the NOx emissions of

large sources (e.g. coal fired power plants) as required by the 1990 Clean Air Act Amendments (CAAA)

under Title I - Groundlevel Ozone.

Sanyal, A., W. Allison, "Lessons Learned from SCR Experience ofCoal-Fired Units in Japan, Europe and

USA; Are These Enough?" Presented at the 2002 DOE Conference Selective Catalytic Reduction and Non

Catalytic Reduction forNOx Control, Pittsburgh, PA, May 2002.

.fQ Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Term SCR Catalyst Experience and Cost", The

2005 EPRI Workshop on Selective Catalytic Reduction, Louisville, KY, November 2005.

A-13
municipal solid waste incinerators (1989)

hazardous waste incinerators (1990)

sewage sludge incinerators (1990)

hospital and medical waste incinerators (1990) .

crematories (1991)

pharmaceutical waste incinerators (1992)

refinery crackers (1994)

glass smelters (1994)

blast furnace and coke gas combustors (1994)

nitric acid plants (1994)

biomass furnaces (1994)

construction debris and waste wood combustors (1995)

electric arc furnaces (1996)

ammunition and chemical weapons incinerators (1997)

ethylene crackers (1997)

Orimulsion boilers (1999)

roller mills (2000)

photovoltaic cell production (2002)

hydrogen reformers (2003)

steel coil heat treatment facilities (2003)

sintering plants (2003)

steel pickling (2005)

In short, almost every high NOx producing process imaginable was successfully retrofitted

with TESCR systems making the SCR technology the most widely used secondary NOx

A- 14
reduction technology worldwide. As a matter offact, in many cases, HDSCRs or LDSCRs

were successfully installed and operated despite the fact that original pilot testing often

suggested severe, rapid catalyst deactivation and seriously questioned the technical

feasibility of either one ofthese two SCR principles for these applications. Examples

include:

lignite or brown coal fired boilers (HDSCR, 1990)

cyclone fired and other wet bottom boilers with fly ash re-injection (HDSCR, 1991)

heavy fuel oil (HDSCR, 1992)

municipal solid waste incinerators (LDSCR, 1992)

hazardous waste incinerators (LDSCR, 1995)

roller mills (LDSCR, 2000)

cement kilns (HDSCR, 2003)

biomass (HDSCR, 2006)

Two o'fthe most recent examples ofthis development in the U.S. are the ongoing HDSCR

retrofits on PRB-fired utility boilers as well as at several utility boilers firing Texas lignite.

Once again, initial pilot testing seemed to have suggested that catalyst deactivation through

fly ash pluggage and chemical poisoning may be too rapid to make HDSCR economically

viable. For example, in case ofPRB-fired utility boilers, HDSCR pilot testing conducted at

.Dynegy's Baldwin Energy Center (Baldwin Pilot Testing) yielded results that clearly

suggested that PRB caused "significant accumulations of ash on the catalyst, on both

macroscopic and microscopic levels. On a macroscopic level, there were significant

observable accumulations that plugged the entrance as well as the exit ofthe catalyst

sections. On a microscopic level, the ash materials filled pores in the catalyst and, in many

cases, completely masked the pores within 4 months27."

During HDSCR pilot testing at Luminant's Sandow Generating Station Unit 4 catalyst

deactivation was determined to be about 20% after approximately 2,900 hours before

increasing to approximately 50% after some 3,500 hours due to catalyst pluggin~. Based on

an extrapolation ofthis data a HDSCR would not likely have reached 10,000 operating hours

prior to catalyst needed to be added or exchanged. For comparison purposes, typical SCR

catalyst design requires an addition or exchange of catalyst during an outage when the total

21. Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

Smith, R, J. Bennett, D. Broske, "Impacts ofTexas Lignite on SCR Catalyst Life and Performance",

presented at the 2007 EPRI SCR Workshop in Pensacola, Florida, November 2007.

A- 15
reactor potential has reached between 60% and 75% ofthe original value when equipped

with all new catalyst.

Yet, in both cases, at Baldwin and Sandow, HDSCR has become the NOx control method of

choice. Currently, more than fifty (50) PRB-fired boilers including at least twenty two (22)

cyclone-fired units have successfully operated HDSCRs without any ofthe problems

suggested based on the Baldwin Pilot Testing results29. Likewise, HDSCRs are being

installed at several utility units burning Texas lignite including Oak Grove 1 & 230, Sandow

411 & 532, Martin Lake 1,2 & 333 and Limestone 334.

In case of a TESCR installation, the situation is dramatically less challenging resulting from

the fact that the flue gas downstream of a wet scrubber, which a TESCR is exposed to, is

extremely clean compared to what the catalyst is exposed to in a HDCSR upstream ofthe

ESP. Downstream of an ESP and a wetscrubber in excess of 99% ofthe fly ash is removed

in the ESP35 and between 90% and 95% of S02 is removed in the wet scrubbe~, thus

leaving very little if anything in the flue gas that is critical for catalyst deactivation.

Additionally, downstream of a wet scrubber, the flue gas has gone through its dew point after

being cooled to saturation while passing through the wet scrubber. Going through the dew

point ofthe flue gas, which is typically between 110 F (~43 °C) and 150 F (~65°C), means

that all condensable catalyst poisons such as alkali and earth alkali salts, arsenic and

phosphorus oxides will inevitably have condensed and, along with all other highly water

soluble gaseous catalyst poisons including sodium and potassium sulfates, phosphates and

carbonates, will have been mostly removed by the wet scrubber. In a wet scrubber all water

soluble compounds including water soluble alkali sulfates, phosphates and carbonates as well

. as all residual alkali vapors are virtually quantitatively removed as a result oftheir extremely

high water solubility.

The very small residual amounts (less than 1%) ofsmall particles « 5 /lm) passing through

the ESP consist of condensed vapors or aerosols including sulfuric acid, alkali sulfates, earth22 Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

JQ E-Mail from Randy Sadler on behalfofCindy Khalaf, President ofArgillon LLC, supplier ofthe SCR

catalyst for Oak Grove 1 & 2, dated June 24, 2008.

11 McIlvaine Utiltiy E-Alert #870 dated April 18, 2008.

Jones, B., Introductory presentation at the GulfCoast Power Association Spring Conference, April 2006.

Jl McIlvaine Utiltiy E-Alert #874 dated May 16,2008.

11 McIlvaine Utility E-Alert #871 dated April 25, 2008.

J2 Milton R. Young Station - Our Jewel on the Prairie, brochure published by Minnkota Power Cooperative

and Square Butte Electric Cooperative on Minnkota's website: www.minkota.com.

JQ Ibid

A- 16
alkaline oxides and silicates. These small particles often act as condensation nuclei during

the rapid flue gas quenching in the inlet ofthe wet scrubber and are largely removed by this

mechanism. Thus, their already small quantity downstream ofthe ESP is reduced further,

typically by at least 50% across a wet scrubber. This means that compared to a HDSCR,

catalyst installed in a TESCR is confronted with less than 0.5% ofthe particulate matter and

less than 5 - 10% ofthe acid gases, vapors and other water soluble compounds, which cause

catalyst deactivation. Consequently, the experienced catalyst deactivation rate is

correspondingly slower.

It must be noted that particle bound compounds add very little to the chemical catalyst

poisoning causing deactivation. Only gaseous compounds or in liquid dissociated ions of

salts ofthese compounds are chemical catalyst poisons. However, as explained earlier, these

gaseous compounds are largely removed in a wet scrubber and the remaining concentrations

downstream of a wet scrubber are typically so negligible that the result is and in

extraordinarily slow catalyst deactivation. Furthermore, the flue gas is being reheated in a

TESCR prior to entering the catalyst, which means that these very small residual

concentrations of chemical catalyst poisons including alkali and earth alkali sulfates and

phosphates as well as the flue gas itself are at least 400 degrees (200 K) above their

respective dew points, which virtually eliminates the possibility ofthese residual catalyst

poisons condensing in the pores ofthe catalyst. In general, the condensation temperature or

dew point of any compound including these gaseous catalyst poisons is a function ofthe flue

gas temperature and the compound's concentration in the flue gas. As noted above, the

residual concentrations of catalyst poisons are very small in a TESCR downstream of a wet

scrubber and the difference between their dew point temperature, which is the flue gas

temperature at the outlet ofthe wet scrubber and the TESCR operating temperature is very

large due to the reheating ofthe flue gas. Consequently, any type penetration ofthese

chemical catalyst poisons and subsequent condensation in the catalyst pores is at least

extremely unlikely if not physically impossible at the TESCR operating conditions.

The virtually negligible residual amount of gaseous catalyst poisons entering a TESCR

compared to an HDSCR results directly in an almost proportionally extended catalyst life.

Based on 20 years of extraordinarily successful full scale TESCR operating experience in

Europe, a catalyst life oftypically well more than 100,000 hours must be considered the

norm rather than the exception. Several TESCRs after wet bottom utility boilers are still in

operation after 20 years with the initial fill of catalyst and no replacement, exchange or

addition37•

Additionally, the minimal concentration of catalyst poisons entering a TESCR and the

resulting very slow long-term catalyst deactivation (as experienced over 20 years of

operation ofTESCRs) led to the reduction in operating temperatures for TESCRs as shown

in the graph below, which can be found on Argillon's website38• Argillon, who is one ofthe

TI Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Term SCR Catalyst Experience and Cost", The

2005 EPRI Workshop on Selective Catalytic Reduction, Louisville, KY, November 2005.

1J! Argillon's website: www.argillon.com.

A- 17
leading catalyst manufacturers of honeycomb as well as plate catalyst marketed under the

trade name SINOx, has a wealth of experience in all types of SCR applications (HDSCR,

LDSCR, TESCR) with more than 500 SCR installations worldwidel2.. Based on Argillon's

extensive experience, Argillon promotes the use ofTESCR in a temperature range between

approximately 300 F (~150 °C) and no more than about 570 F (300°C) as can be seen in the

graph below.

SlNOxe Hi9tl Temperatu~'

catalYst

.~~am.cenQt"ator

oVieI'PIMtS

standard SINO~

CatalySt

L._--,-:"-'-..-~,7-:'.-,-:-,--'--~ __.--_."._--_._._--_.__.__."'._...0__..0 ...._. •__.__. . _ i ..... .

I S'N~~~ I~rn~~ !.' '" Catalyst I. . ...

I

I

r

1

I

i

I

I

i

i

r

i

i

I

I

!

I

I

I

i

i'. ··.. i ••};;.:

iTailel')~; I ' ........•.....

!'Plants .... ;;.!.;..

200"C 350*C

Operating Temperature

As a matter offact, for purely economic reasons and regardless ofthe fuel burned, no

TESCR system in Europe operates today at a temperature greater than about 550 F (~290

°C). Today, the majority ofTESCRs behind plants such as municipal and hazardous waste

incinerators, which have an incomparably greater fuel variability and much higher

concentrations ofthe entire spectrum of catalyst poisons (arsenic, barium, calcium,

chromium, magnesium, phosphorus, potassium, selenium, sodium, thallium, etc.) than any

coal-fired boiler will ever have, operate downstream ofwet scrubbers and/or baghouses or

activated carbon reactors (ACR) at temperatures as low as 300 F (~150 °C). These low

temperature TESCR operations have been extremely successful for over a decade now with

minimal to no catalyst deactivation experienced.

CERAM is another leading manufacturer of honeycomb SCR catalyst and with well over 500

SCR installations worldwide, more than 100 of which are LDSCR and TESCR installations.

CERAM, arguably one ofthe most experienced suppliers ofTESCR catalyst, fully confirms

this concept oflowering the TESCR temperature. CERAM sees no need for a TESCR

operating temperature ofmore than about 554 F (290°C) even in case of a wet bottom boiler

J2 Argillon's website: www.argillon.com

A- 18
such as a cyclone fired unit burning the most complex and difficult fuels including North

Dakota lignite4o. As a matter offact, the only thing that dictates the minimum SCR operating

temperature are the residualS02 and S03 concentrations in the flue gas, which determine the

ABS reaction equilibrium±l and thus the probability for ABS deposition on the catalyst and

in the gas/gas heat exchanger. This, however, is not an irreversible catalyst poisoning issue

but rather a reversible fouling problem not related to the SCR catalyst per se but simply to

the reaction chemistry between H20, S03 and NH3 in the flue gas at various temperatures.

In summary it can be stated that the SCR technology is the most widely used secondary NOx

control technology in the world. It is technically feasible and applicable to a large number of

thermal processes including all types of utility boilers burning any kind offuel. In my

professional experience gained over the last 20 years with the SCR technology, neither the

design ofthe boiler or the combustion system nor the composition ofthe fuel burned has ever

posed an irresolvable technical obstacle, which made the application ofthe SCR technology

in one of its principles (HDCSR, LDSCR, TESCR) technically infeasible. The only challenge

is the proper selection ofthe appropriate type of SCR principles (HDSCR, LDSCR or

TESCR) and the correct SCR process and catalyst design. This selection, however, is neither

a question oftechnical feasibility or applicability nor of availability ofthe SCR technology

but simply a question of economics.

6. SCREVALUATION

In June 2008, the North Dakota Department of Health's Division of Air Quality issued a

"Preliminary Best Available Control Technology Determination for Control ofNitrogen

Oxides for M.R. Young Station Units 1 and 242", in which it determined "that SCR is not

technically feasible for North Dakota lignite-fired cyclone boilers." This determination

seems to rest largely on five documents provided by Minnkota Power, namely:

1. Minnkota's Best Available Control Technology Analysis Study for Milton R. Young

Station Unit 1, October 2006.43

2. Square Butte's Best Available Control Technology Analysis Study for Milton R.

iQ Personal conversation with John Cochran, President ofCERAM Environmental, Inc., on June 25, 2008.

11 The reaction equilibrium between ammonium sulfate «NH4)ZS04) and ammonium hydrogen sulfate

(Nf!tHS04), which is often incorrectly referred to as ammonium bisulfate or ABS, in the flue gas. Both,

ammonium sulfate and ammonium hydrogen sulfate are products ofthe inevitable reaction of gaseous sulfur

trioxide (S03) and ammonia (NH3) contained in the flue gas upstream ofthe SCR catalyst.

Preliminary Best Available Control Technology Determination for Control ofNitrogen Oxides for M.R.

Young Station Units 1 and 2, Division of Air Quality, North Dakota Department ofHealth, 918 East Divide

Avenue, Bismarck, North Dakota.

1J. NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 1 Minnkota

Power Cooperative, Inc., Revised Final Report, October 2006,311777.

A- 19
Young Station Unit 2, October 2006.44

3. SCR Catalyst Performance in Flue Gases Derived From Subbituminous and Lignite

Coals, A. Benson, et al.45

4. Application of SCR Technology to North Dakota Lignite Fuels, Power Point

Presentation slides by Sargent and Lundy, LLC, May 2007.46

5. Additional Information and Discussion of Vendor Responses on SCR Technical

Feasibility, North Dakota's NOx BACT Determination for Milton R. Young Station

Units 1 and 2, May 2008.47

These five documents are seemingly reasonably recent with the first and second document

dated October 2006 and the forth and fifth documents dated May 2007 and May 2008,

respectively. However, the third document even though published in 2005 was already

accepted for publication in mid 2004 and the actual HDSCR catalyst pilot testing at the

Coyote Station (Coyote Pilot Testing) and at the Baldwin Energy Center (Baldwin Pilot

Testing) that lasted at least 6 months at each plant was conducted as early as 2000/200148.

This is relevant, since the Coyote Pilot Testing, which was conducted following the Baldwin

Pilot Testing, used the same pilot test reactor equipped with the same Haldor Topsoe catalyst

that was used at the Baldwin Pilot Testin~. Based on the Baldwin Pilot Test results the

technical feasibility ofHDSCR at Baldwin's cyclone-fired Units 1 & 2 burning 100% PRB

would have been at least highly questionable and a BACT determination similarly conducted

as the one by the Department for the M.R. Young Station would most likely have reached the

same conclusion as was reached for the M.R. Young Station, namely that the SCR is

technically infeasible for retrofit at the Baldwin Energy Center. However, the full scale

HDSCRs at Baldwin Units 1 & 2 were commissioned in 2002 and 2003 and have since been

in service for more than 45,000 hours without any ofthe problems indicated during the

Baldwin Pilot Testing.

11 NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2 Minnkota

Power Cooperative, Inc. Operating Agent for Square Butte Electric Cooperative, Owner. Revised Final

Report, October 2006, 311777.

Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

Sargent and Lundy, LLC, "Application of SCR Technology to North Dakota Lignite Fuels", a Power Point

presentation, May 2007.

11 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

E-mail from Flemming Hansen (Haldor Topsoe) dated June 30, 2008.

Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

A-20
At Associated Electric's New Madrid Station Units 1 & 2, both cyclone-fired units burning

100% PRB, HDSCRs were commissioned in 1999/2000 already and have been in operation

successfully since then. Numerous other cyclone-fired units burning 100% PRB were

retrofitted with HDSCRs and have also been operating successfully2Q,.21. This clearly proves

that the results obtained during the Baldwin Pilot Testing with this particular SCR catalyst

and this particular pilot test reactor design cannot be considered representative for a full scale

HDSCR installation at the same u.nit. Baldwin Units 1 & 2 don't use tIie type of Haldor

Topsoe catalyst used in the Baldwin and Coyote Pilot Testing but instead use Argillon plate

catalyst. New Madrid Units 1 & 2 also don't use the type of Haldor Topsoe catalyst used in

the Baldwin and Coyote Pilot Testing but instead use Cormetech honeycomb catalyst. Also,

the HDSCR reactors at Baldwin and New Madrid were properly designed and are adequate

to meet the challenges ofthis application and not as ill-designed and fundamentally flawed as

the Baldwin and Coyote Pilot Testing reactor and catalyst design. This fact along with the

conclusion that the Coyote Pilot Testin~ 9idn't provide much useful data was pointed out

clearly by the Department.

Furthermore, CERAM in one oftheir responses explicitly stated their beliefthat "t~e

information and test work presented indicate that it is certainly premature to assume that

there is a fatal flaw for the use of high duct SCR behind cyclones burning North Dakota

lignite. The concerns presented are similar in argument to those that where used 10 years ago

against the application of PRB for high dust (SCR) applications53

". CERAM continues

stating that "concerns reported by Dr. Benson54 regarding high sodium contents and fine

fume are duly noted, but inadequate evidence is presented that this could be a fatal flaw to

application of(HD)SCR considering the flawed pitch and resultant pluggage ofthe (Haldor

Topsoe) catalyst (used) during (the) Coyote Station testin~". This view ofCERAM was

further discussed in a personal conversation with Mr. Kurt Orehovsky, Product Manager of

2Q NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 1 Minnkota

Power Cooperative, Inc., Revised Final Report, October 2006, 311777.

.2l NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2 Minnkota

Power Cooperative, Inc. Operating Agent for Square Butte Electric Cooperative, Owner. Revised Final

Report, October 2006, 311777.

g Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

21 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8,2008.

2± Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

i2. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8,2008.

A- 21
CERAM's SCR Catalyst Division56• Mr. Orehovsky clearly stated that CERAM reviewed all

available data carefully and thoroughly and sees currently no reason why HDSCR would be

technically infeasible at M.R. Young Station, however, only after resolving the temperature

variation problem. He pointed out that CERAM would not expect any extraordinarily high

catalyst deactivation or pluggage at a cyclone-fired unit burning North Dakota lignite if in

fact an HDSCR system would be properly designed and operated. CERAM's extensive

experience with lignite and biomass fired units equipped with HDSCR support this position.

Despite that clear statement and despite the ongoing proof in form ofthe success ofthe

HDSCRs at New Madrid, Baldwin and many other cyclone-fired units burning 100% PRB,

the only field data the Department relied upon concerning the expected catalyst deactivation

and pluggage of an HDCSR installed at M.R. Young Units I and 2 is the data obtained from

the ill-designed and fundamentally flawed Coyote Pilot Testing.

Admittedly, the Coyote Pilot Testing results seem to indicate worse pluggage than the

Baldwin Pilot Testing results. However, it must be noted that the same pilot test reactor and

the same catalyst, which had been already used (and plugged) at Baldwin was subsequently

used at Coyote. The well known fact that catalyst that had been plugged and only

mechanically cleaned is more likely to quickly plug again than new, unused catalyst was

simply ignored. Furthermore, it is more than reasonable to expect that lignite fired units will

cause a higher rate of catalyst deactivation in an HDSCR than a PRB fired unit. This fact was

also proven during the Sandow 4 pilot testing2Z but is no reason for considering the SCR

technology in general as technically infeasible. In case of Sandow 4 and other units burning

Texas lignite HDSCR was even considered to be more economically viable than LDSCR or

TESCR with the technical feasibility not even being a question.

Given the fact that the same pilot test reactor and catalyst were used for the Baldwin and

subsequently for the Coyote Pilot Testing, it can be clearly stated that the reason for the pilot

testing results at Coyote being worse than at Baldwin was because ofthe pilot test reactor

and catalyst designs and the execution ofthe pilot testing, all ofwhich were already

inadequate for the Baldwin application but disastrous for the Coyote application. Yet, the

unanswered question remains, why is it unreasonable to assume that a properly designed and

operated HDSCR at M.R. Young Units I and 2 could be as successful as it has been and

continues to be at New Madrid, Baldwin and the many other cyclone-fired units burning

100% PRB despite the fact that the results ofthe Baldwin Pilot Testing seemed to indicate

the exact opposite? Based on this clear and indisputable evidence would not every reasonable

engineer first suspect that the reason for the failure ofthe Coyote Pilot Testing was the illdesigned test pilot reactor and catalyst and the flawed execution ofthe pilot testing just as it

was the case at Baldwin? However, instead oftrying to answer these most important

questions objectively and correctly, the Department jumped to the highly premature and

speculative conclusion that the SCR technology regardless ofthe selected principle (HDSCR,

Personal conversation with Mr. Kurt Orehovsky in Vienna, Austria, on July 7, 2008.

:il. Smith, R, J. Bennett, D. Broske, "Impacts ofTexas Lignite on SCR Catalyst Life and Performance",

presented at the 2007 EPRI SCR Workshop in Pensacola, Florida, November 2007.

A-22
LDSCR or TESCR) cannot be applied successful at the M.R. Young Station.

The Department lists the following twelve (12) conclusions that result in the Department's

largely speculative and unsubstantiated determination "that high dust SCR is not technically

feasible at this time for both units at the M.R. Young Station", the validity of which are

discussed in detail in the following sections.

6.1 Variability of Fuel Composition

_Lignite from the Center Mine is highly variable in heat and ash contents and in the

constituents that make up ash, which will affect SCR design and operation. This is an

undisputed fact, however, not only true for lignite from the Center Mine but for all coals

regardless whether it is anthracite, bituminous, sub-bituminous, lignite, brown coal etc. As a

matter offact, these listed classifications are nothing butthe result ofthe extremely high

variability ofthe various types of coal. Each class in itself has a high variability again, which

unquestionably affects SCR design and operation. This high variability includes also the

compounds sodium and potassium (as further discussed in several subsequent sections) as

well as all other catalyst poisons. Bituminous and sub-bituminous coals, which are

considered relatively unproblematic for HDSCR design and operation, may serve as an

example for this typical variability. Bituminous and sub-bituminous coal-fired boilers

constitute the vast majority of HDSCRs in the world even though the:

The heating value ranges from less than 8,000 Btu/lb to more than 13,000 Btu/lb.

The ash content can vary by one order ofmagnitude from as low as 4 %wt. to as high

as 40 %wt.

Sulfur contents also vary easily by one order ofmagnitude from less than 0.5%wt. in

sub-bituminous to more than 5%wt in bituminous coal.

Likewise arsenic content range over an order ofmagnitude from less than 3 ppm to

more than 40 ppm.

The list ofsimilarly wide ranges of concentrations and/or variability for individual

constituents of bituminous and sub-bituminous coals could be extended for almost every

element ofthe Periodic Table. However, I am not aware of one single case where this high

variability ofthe heat and ash contents ofthe coals and/or ofthe constituents that make up

the ash precluded one ofthe principles ofthe SCR technology (HDSCR, LDSCR, TESCR)

from being technically feasible and applicable.

Thus, it remains unexplained why the Department's conclusion that "lignite from the Center

Mine is extremely variable in heat content, ash content and in the constituents that make up

the ash", leads to the determination that the SCR technology is not technically feasible. Even

though the statement that "this variability will affect the design and operation of an SCR

A- 23
system", is only correct with respect to a HDSCR and maybe partially to a LDSCR, it is most

definitely not plausible for a TESCR. In case ofTESCR the preceding air pollution control

equipment (ESP and wet FGD) as well as the flue gas reheating system of a TESCR, which

typically includes a gas-gas heat exchanger and steam coil upstream ofthe SCR reactor,

virtually eliminate even the most extreme variability in the fuel and its resulting flue gas

composition upstream ofthe SCR catalyst. It is intuitively obvious that the coal's variability

in heat and ash content and in the constituents that make up the ash is no longer of any

relevance in case of a TESCR system after more than 99% ofthe ash has been removed in

the upstream air pollution control equipment58 •

6.2 Results ofthe Coyote Pilot Testing

The Department correctly states that "the only pilot testing that has ever been conducted on a

unit firing North Dakota lignite was at the Coyote Station59• The pilot scale SCR was

plugged after 2 months and little useful data was obtained". The Department further alludes

to the fact that "the pilot testing at the Coyote Station did not provide much useful data, and

in hind-sight, was ill-designed for a unit combusting North Dakota lignite". Yet despite the

Department's indisputably correct and valid recognition ofthis as well as the facts that:

no deactivation data exists and no conclusions should be drawn from this ill-designed

and highly flawed Coyote Pilot Testing;

several SCR equipment suppliers (Alstom, Babcock Power) clearly stated that, an

"(HD)SCR system could be successfully utilized on a boiler fired with Northern

lignite,,6o;

several catalyst manufacturers (CERAM, Haldor Topsoe) clearly stated and that

concerns reported by Dr. Benson2.l regarding high sodium contents and fine fume are

duly noted, but inadequate evidence is presented that this could be a fatal flaw to

application ofSCR considering the flawed pitch and resultant pluggage ofthe

(Haldor Topsoe) catalyst during Coyote Station testing,,62;

Milton R. Young Station - Our Jewel on the Prairie, brochure published by Minnkota Power Cooperative

and Square Butte Electric Cooperative on Minnkota's website: www.minkota.com.

l2 Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", FuelProcessing Technology 86 (2005) pages 577 - 613,2005.

.§Q Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

§l Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

g Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

A-24
several catalyst manufacturers (CERAM, Haldor Topsoe), who have experience with

high sodium and potassium containing fuels, offered industry standard type catalyst

performance guarantees (NOx removal efficiency, S02/S03 conversion rate, pressure

drop, NH3 slip, catalyst lifetime)63;

the Department still concludes that "the Coyote testing demonstrates to the Department that

North Dakota lignite firing will have more severe effects (plugging and catalyst deactivation)

than units firing sub-bituminous coal when the same design is employed".

This statement promotes three basic questions, namely:

a. How can the Coyote Pilot Testing demonstrate to the Department that North Dakota

lignite firing will have more severe effects (plugging and catalyst deactivation) when

no catalyst deactivation data exists and the pilot scale SCR reactor at the Coyote

Station plugged very quickly because the reactor was ill-designed and the selected

catalyst design not suitable, particularly for a unit combusting North Dakota lignite?

b. Does the Department have any additional information that may substantiate the

Department's otherwise completely unfounded conclusion and that wasn't provided

to the contacted vendors including Alstom, Babcock Power, CERAM and Haldor

Topsoe so that they reached the essentially opposite conclusion?

c. Why does the Department imply that the same catalyst and SCR design employed for

units firing sub-bituminous coal must also be used for M.R. Young Station?

As pointed out earlier, this is relevant since in the early 2000s, when the Coyote Pilot

TestingM was conducted, the results ofwhich provide the only catalyst relevant field data for

the Department's conclusion concerning the rapid pluggage and deactivation of catalyst in a

HDSCR, no long term full scale HDCSR operating experience was available from

Associated Electric's New Madrid Station, which was the first one to install HDSCR on a

cyclone-fired unit burning PRB. Yet, as pointed out by Bums & McDonnell, today a

significant number of cyclone-fired units in the U.S. burning PRB successfully operate

HDSCRs65, QQ, 67.

for Milton R. Young Station Units 1 & 2", May 8, 2008.

2l Ibid

§± Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit I Minnkota

Power Cooperative, Inc., Revised Final Report, October 2006, 311777.

§§ NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2 Minnkota

Power Cooperative, Inc. Operating Agent for Square Butte Electric Cooperative, Owner. Revised Final

Report, October 2006, 311777.

A- 25
The Department further states that "besides catalyst deactivation, it is likely that a high-dust

SCR would experience plugging problems (deposition on the catalyst surface) due primarily

to the carryover of popcorn ash from the boiler". This statement is also quite puzzling, since

the formation of popcorn ash is a commonly known phenomenon that has first caused

catalyst pluggage in Germany in the mid 1990s68 and is also a well known problem in the

U.S. since the early 2000s. However, it has been solved successfulll9 by the use of properly

designed popcorn ash removal systems70.

The Department's statement that "the advances made in the last few years for controlling

popcorn ash are not shown to be applicable to a cyclone boiler burning North Dakota lignite"

is not only purely speculative but defies all common engineering sense. Various designs and

types of popcorn ash screens have been installed in a wide variety of units in the U.S. and are

operating successfully. I believe that no engineering company with SCR experience

including Sargent and Lundy and Burns & McDonnell would seriously argue the fact that

properly designed popcorn ash screens could be successfully installed at M.R. Young

Station's Units 1 and 2 without additional pilot scale testing. Needless to addthat in case ofa

LDSCR or TESCR any concern over popcorn ash would be considered absurd simply by

virtue ofthe location ofthe LDSCR or TESCR in the flue gas path downstream ofthe ESP

(LSDCR) and wet scrubber (TESCR).

Furthermore, the Department's statement that "operation of an SCR system for only 2

months between catalyst replacements is not considered successful operation of SCR

technology," implies that the catalyst in a properly designed full scale HDSCR at the M.R.

Young Station would have to be replaced every two (2) months. Again, no deactivation data

was ever determined during or after the Coyote Pilot Testing to substantiate this claim. This

forces the conclusion that the mostly useless data obtained from the ill-designed and flawed

Coyote Pilot Testing was improperly and incorrectly used by the Department to speculatively

extrapolate to what mayor may not happen in a properly designed HDSCR system.

This bold speculative extrapolation to a catalyst life of only two (2) months between

replacements in a full scale HDSCR is particularly interesting since the Department

immediately contradicts its own conclusion by postulating that "without pilot testing, the life

ofthe catalyst cannot be predicted with any reasonable certainty." Assuming this latter

statement is true and further reiterating the fact that no deactivation testing from pilot testing

fil Sargent and Lundy, LLC, "Application of SCR Technology to North Dakota Lignite Fuels", a PowerPoint

presentation, May 2007.

2!! Hartenstein, H., H. Gutberlet, L. Licata, "Utility Experience with SCR in Gennany", a paper presented at the

Sixteenth Annual International Pittsburgh Coal Conference, October 1999.

22 Sargent and Lundy, LLC, "Application ofSCR Technology to North Dakota Lignite Fuels", a PowerPoint

Presentation, May 2007.

1Q Martin, M., M. Harrell, J, Jancauskas, H. Hartenstein, H. Sobolewski, "Large Particel Ash (LPA) Screen

Retrofits at Coal-Fired Units in Indiana and Ohio", DOE-NETL Conference on SCR/SNCR, 2006.

A-26
is available, how can the Department assert that a properly designed full scale HDSCR

system would operate for only two (2) months between catalyst replacements while stating at

the same time that the life ofthe catalyst cannot be predicted without further pilot testing?

Furthermore, the Department's bold postulation of an expected catalyst life of only two (2)

months between replacements is made despite the fact that two (2) experienced catalyst

suppliers (Haldor Topsoe and CERAM) offered firm performance and lifetime guaranteesll

for their catalyst installed in an HDSCR of considerably more than the 10,000 hour threshold

arbitrarily defined by the Department. Why the Department ignores all these facts and

concludes that it can predict the expected catalyst life better than even the most experienced

catalyst manufactures remains unknown.

6.3 Soluble Sodium

The Department concludes that "the combustion of(North Dakota) lignite produces soluble

sodium compounds, which cause more severe catalyst deactivation than insoluble sodium

compounds". Even though this statement may be generally correct, it remains unclear and

unexplained, why soluble sodium compounds, which can only penetrate into the catalyst and

deactivate the catalytically active vanadium pentoxide (V20S) when in they are either in the

gas phase or as sodium ions (Na+) dissociated in a liquid, would be present in the gas phase

or in a liquid and therefore in a mobile form.

The argument raised by Minnkota and reiterated by the Department that the formation oflow

temperature sodium-calcium-magnesium sulfates and phosphates poses the most significant

problem for the successful operation of SCR catalysts in a HDSCR may be true with respect

to catalyst deactivation. However, the simple comparison of emission rates ofthese

compounds with the fly ash is not a correct and appropriate way to derive any meaningful

prediction concerning the expected catalyst deactivation. Even though the Department

correctly states that "the catalyst deactivation rate may not be directly proportional to the

emission rates ofthe various constituents", incorrectly continues that "it does provide a

means of comparison ofthe flue gas characteristics". Unfortunately, the Department fails to

realize what was pointed out by one ofthe most experienced catalyst suppliers, namely that

"sodium is not a poison to catalyst at SCR operating temperatures72." Thus, the elaborate

comparison of emission factors ofsodium, potassium, calcium and magnesium emission

factors with the fly ash may have some academic value but is effectively meaningless for the

correct prediction of catalyst deactivation, since particle bound sodium, potassium, calcium

and magnesium in the fly ash are not mobile and therefore are not catalyst poisons.

Typically, sodium and potassium sulfates, so called pyrosulfate compounds, have very high

II Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

J1 Ibid

A-27
boiling points well above any possible SCR operating temperature. Thus, it is highly unlikely

that any appreciable quantities ofthese pyrosulfates will be present in the SCR in the gas

phase. This, however, would be necessary in order to cause severe and rapid catalyst

deactivation. Therefore, under these conditions these compounds are not a major concern.

Alternatively, these pyrosulfate compounds would have to be present in a liquid so that their

dissociated ions (i.e. Na+, K+) would be mobile in order to enter the catalyst pores and react

with the catalyst's active sites. However, these compounds will only be present in the

catalyst in a liquid form if either the SCR operating temperature is too low or during shut

down when cooling the SCR reactor to temperatures below the moisture dew point. Since the

melting point ofmost pyrosulfates is well above the typical HDSCR operating temperature of

650 - 750 F (343 - 400°C) the intrusion ofliquid pyrosulfates is no major concern with

respect to a severe, rapid catalyst deactivation. Therefore, even catalyst suppliers state clearly

that "sodium is not a poison to catalyst at SCR operating temperatures. Significant

deactivation can occur if condensed moisture transports sodium residing at the surface into

the catalyst pore structure during outage or layup73". Since the HDSCR operating

temperature must be expected to be maintained at well above 650 F (343°C) at all times, no

liquid ever occurs during SCR operation not even in the inner pores as the temperature is too

high even for capillary condensation. This well known fact is one ofthe main reasons why

HDSCR operating temperatures are selected to be typically in the range between 600 F (315

°C) and 800 F (427°C). Maintaining the required minimum SCR operating temperature at all

times is an absolute requirement for all HDSCRs regardless offuel type and/or boiler/burner

configuration and has nothing to do with North Dakota lignite and/or cyclone-fired boilers.

As pointed out earlier, the condensation ofmoisture in the pores ofthe SCR catalyst typically

occurs only during shut-down and subsequent cooling of an SCR reactor. Thus, reducing the

number ofshut-downs, which result in cooling the SCR catalyst to below the moisture dewpoint, is always advantageous for all HDSCRs regardless offuel- and/or firing type.

Given the fact that sixty (60) start-ups were reported for M.R. Young Unit 1

74 within a five

(5) year period and sixty two (62) start-ups for the same period for M.R. Young Unit 275, it

can be easily calculated that this equates to an average of approximately twelve (12) start-ups

per year or roughly one (1) per month. However, in case of Unit 1 only six (6) and in case of

Unit 2 only seventeen (17) were considered "cold" start-ups, which are defined as the boiler

having been without fuel-firing for more than seventy two (72) hours76• During shut-downs

1J. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion ofVendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

11 NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 1 Minnkota

Power Cooperative, Inc., Revised Final Report, October 2006, 311777.

1.2. NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2 Minnkota

Power Cooperative, Inc. Operating Agent for Square Butte Electric Cooperative, Owner. Revised Final

Report, October 2006, 311777.

1§. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

A-28
of less than seventy two (72) hours, SCR reactors are typically "buttoned up hot", which

means the SCR reactor is isolated from the flue gas path during shut down by means of

putting it in a bypass mode while the SCR is still at its design operating temperature. The

cooling rate ofsuch a "buttoned up hot" SCR reactor is known to be extremely slow. Unless

forced cooled with ambient air no "buttoned up hot" SCR reactor loses more than

approximately 50 - 100 degrees and therefore gets nowhere near the sulfuric acid or even the

moisture condensation temperature in a seventy two (72) hour period.

Therefore, catalyst deactivation by means ofsoluble sodium compounds in the ash being

dissociated into a liquid and penetrating into the catalyst pores and reacting there with the

catalytically active V20S must be expected to be rather slow. Since the actually experienced

catalyst deactivation rate due to this effect has never been measured, the respective

conclusion postulated by the Department cannot be considered more than an unsubstantiated

speculation.

6.4 Differences in Flue Gas Composition

The Department concludes that "the flue gas generated at the M.R. Young Station is different

from the flue gas at any plant where SCR technology has been applied". The absoluteness of

this statement, which is not even limited to power plants, is quite amazing as it indubitably

implies that the Department has complete detailed knowledge not only ofthe flue gas

composition of every other power plant in the world equipped with an SCR system but also

of every other plant in the world where the SCR technology is applied. Even though

theoretically possible, the lack of any data from all these other plants strongly suggests that

this may be highly questionable and largely overreaching. As a matter offact, 1am sure that I

could easily present to the Department several plants where the SCR technology has been

applied successfully that the Department doesn't even know that these plants existed.

Furthermore, the Department states that this absolute uniqueness is "primarily due to the high

ash concentration ofsoluble sodium compounds and the total loading of catalyst deactivation

chemicals". Again, as discussed in section 6.3 and clearly pointed out by catalyst suppliers,

sodium is not a catalyst poison at SCR operating temperatures77. The claimed uniqueness of

the flue gas generated at the M.R. Young Station appears to be highly speculative and

completely unproven as comparisons were only drawn to:

bituminous coal (specifically mentioning Pennsylvania coal);

sub-bituminous coal (specifically mentioning Wyoming PRB);

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

J1 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

A-29
other lignites (specifically mentioning Texas lignite).

Needless to say that Pennsylvania coal is not the only bituminous coal in the world,

Wyoming PRB iS,not the world's only sub-bituminous coal and Texas lignite is referred to as

Texas lignite for the simple reason that it is somewhat unique to Texas compared to the many

other types of lignites and brown coals around the world. Thus, the Department's statement

in its far reaching and absolute form must either be considered extraordinarily uninformed or

only correct ifrigorously limited to the three specific coal types mentioned. In that sense this

conclusion has little if any relevance to the question ofthe technical feasibility ofthe SCR

technology to the M.R. Young Station and should be simply ignored as completely

irrelevant.

6.5 Experience of Burns and McDonnell and Sargent and Lundy

The Department concludes that "both Bums and McDonnell and Sargent and Lundy have

extensive experience with the design and operation of SCR systems". The fact ofthe matter

is, however, that the SCR experience ofBums & McDonnell must be considered rather

limited for a number ofreasons, namely Bums & McDonnell has provided SCR related

services for only seventeen (17) power' plants78. At least ten (10) ofthese are not even in

operation yet and only two (2) SCR projects are retrofits. Thus, Bums & McDonnell has very

little experience with SCR retrofits and the only two (2) SCR retrofits, in which Bums and

McDonnell was involved as Owner's Engineer, namely Hoosier Energy's Merom Station and

HMPL's Henderson Station, have accumulated any appreciable long-term operating

experience. However, in both ofthese cases, Bums & McDonnell's scope was limited to

portions completely irrelevant to SCR process and catalyst design such as balance-of-plant

design including foundations, electrical, controls integration, civil and contract oversighe9

•

In the case ofthe Henderson Station, the SCR was supplied by Alstom and the catalyst by

Cormetech. All process design, catalyst selection and design and all relevant process

performance guarantees were provided by either Alstom or Cormetech. None were provided

by Bums & McDonnell. In the case ofthe Merom Station, the SCR was supplied by Lurgi

and the catalyst by KWH. Again, all process design, catalyst selection and design and all

relevant process performance guarantees were provided by either Lurgi or KWH. None were

provided by Bums & McDonnell.

Detailed design is currently being provided by Bums & McDonnell for only one (1) power

plant, namely Associated Electric's Thomas Hill Units 1,2 and 3. The SCRs are currently

under construction and Bums & McDonnell lists conceptual design and studies" structural

1l! Summary ofResponses to EPAIDOH Questions on Minnkota Power's NOx BACT Analysis for Milton R.

Young Units 1 & 2, Presentation by EERC, Minnkota Power, Bums & McDonnell to NDDH and U.S. EPA,

May 23, 2007.

12. Ibid

A-30
design, balance of plant design and construction management as services provided8o • It is

worth noting that again none ofthese services have anything to do with the SCR process or

catalyst design. The only service provided by Bums & McDonnell for this one (1) SCR

retrofit project at least remotely related to SCR process design was the selection ofthe

reagent and the catalyst manufacturer. However, reagent selection is irrelevant for catalyst

deactivation and/or pluggage and the SCR catalyst itself is supplied by CERAM including

the design, sizing as well as all process performance guaranteesll. Thus, the catalyst selection

performed by Bums and McDonnell was nothing more than recommending CERAM as the

catalyst supplier presumably on the basis of a lowest price competitive bidding process.

In summary it is worth noting that Bums & McDonnell has neither provided SCR process

design and/or SCR process performance guarantees in one single case nor ever operated any

SCR system. Thus, the Department's conclusion concerning Bums & McDonnell's

"extensive experience with the design and operation of SCR systems" seems to be based on a

surprising lack offamiliarity ofthe true capabilities and limitations ofthese architect

engineering (A/E) firms. Concerning the "extensive operating experience" the Department's

conclusion is plain wrong and for the remainder coarsely exaggerating as no A/E ever

provides any process and/or catalyst design and/or performance guarantees.

Even though Sargent and Lundy claims significantly more SCR experience than Bums &

McDonnell, Sargent and Lundy has also only acted as an A/E for SCR retrofits. Sargent and

Lundy lists to have been involved in approximately 27,000 MWs ofSCRs as an A/E. This

represents a little more than one fifth e/s) ofthe SCRs retrofitted to coal-fired units in North

America82

or less than half ofthe 46% claimed by Sargent and Lundy. Despite Sargent and

Lundy's greater involvement in SCR retrofits as an A/E compared to Bums & McDonnell, it

must be noted that Sargent and Lundy has also never provided any SCR process and/or

catalyst design and/or performance guarantees and never operated any SCR systems. Thus,

the Department's conclusion concerning Sargent and Lundy's "extensive experience with the

design and operation ofSCR systems" seems to be also based on a lack offamiliarity ofthe

true capabilities and limitations ofthese architect engineering (A/E) firms. Concerning the

"extensive operating experience" the Department's conclusion is plain wrong and for the

remainder at least highly questionable as no AlE ever provides and process and/or catalyst

design and/or performance guarantees.

In general it must be noted that all services, which are critical for SCR system process design

and process performance guarantees, including:

process design;

Jill Summary ofResponses to EPAIDQH Questions on Minnkota Power's NQx BACT Analysis for Milton R.

Young Units 1 & 2, Presentation by EERC, Minnkota Power, Burns & McDonnell to NDDH and U.S. EPA,

May 23, 2007.

1U. Reference list on CERAM's website: www.frauenthal.net.

Sargent and Lundy LLC, "Application of SCR Technology to North Dakota Lignite Fuels", a PowerPoint

Presentation, May 2007.

A- 31
catalyst sizing and design;

flow modeling and SCR rector design;

process performance guarantees;

catalyst performance guarantees;

have never been and most likely will never be provided by neither Bums and McDonnell nor

Sargent and Lundy. All these critical services are always either supplied by an SCR

equipment supplier (Alstom, Babcock Power, Babcock & Wilcox, etc.) or by the catalyst

manufacturer (Argillon, CERAM, Cormetech, Haldor Topsoe, Hitachi, etc.). As a matter of

fact, all catalyst related performance guarantees (NOx removal efficiency or activity,

S02/S03 conversion rate, catalyst life or deactivation rate, etc.) are never provided by anyone

other than the catalyst manufacturers. Even the SCR equipment suppliers only pass through

the catalyst performance guarantees obtained from the catalyst manufacturer to the end

customer. And at least two (2) ofthese catalyst manufacturers, namely Haldor Topsoe and

CERAM were clearly willing to provide industry standard type performance guarantees for

their catalys~. Notably, both ofthese catalyst manufacturers have extensive HDSCR

experience with high sodium and potassium containing fuels such as biomass and/or lignite.

It remains unclear why the Department didn't exploit the statements ofthese highly

experienced catalyst manufacturers further but rather relied on the AlE's who have no SCR

process and/or catalyst design experience, have never provided any SCR process and/or

catalyst related performance guarantees and have absolutely no SCR operating experience.

6.6 Development Stage ofHigh-Dust SCR

The Department states that "to design and install an SCR system for a cyclone-fired unit

firing North Dakota lignite without obtaining additional data from bench scale would be

experimentation". This conclusion is again in clear disagreement with the statement of

catalyst manufacturers such as Haldor Topsoe and CERAM, who were willing to provide

industry standard type cataly~t performance guarantees even for HDSCR. This clearly

indicates that both ofthese highly experienced catalyst manufacturers see no need for

obtaining additional data from bench scale experimentation but feel to be in the position to

design and install a HDSCR system at M.R. Young's Units 1 and 2.

Needless to say that no catalyst manufacturer and/or SCR system supplier will tum down the

opportunity for additional bench scale and/or pilot testing if offered as it always effectively

presents itself as a welcome possibility for risk free research paid by others. Also needless to

say, every A/E, who typically charges billable manhours, will favor bench scale and/or pilot

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion ofVendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

A- 32
testing, thus extending the life ofthe project and therefore the amount ofmanhours billable.

Furthermore, even if HDSCR would not be economically viable, LDSCR or TESCR

certainly would be and are indubitably technically feasible and applicable as clearly

indicated by the multitude of applications ofthis principle ofthe SCR technology to a wide

range of processes (see also section 5 ofthis report). Why the Department essentially ignores

all the statements by these catalyst manufacturers and insists stubbornly that their provided

SCR catalyst design84 is experimentation, remains a mystery.

6.7 Temperature Variations

The Department correctly states that "the temperature variation ofthe flue gas entering the

(HD)SCR will adversely affect the performance and must be resolved for successful

application ofthis technology". However, the large temperature variations present at these

units is very unusual for coal-fired units including cyclone-fired units. It is a unit specific

problem related to the very unique design ofthe backpass ofthe boiler and the air preheater

rather than to cyclone-fired boilers and/or North Dakota lignite. According to the boiler

supplier Babcock & Wilcox only four (4) ofthese type boilers including the two (2) at M.R.

Young Station were ever buil~, which clearly makes this the exception rather than the rule.

In fact, such large temperature variations would not be tolerable for any HDSCR installed

after any type offiring system (single or opposed wall-fired, tangentially-fired, turbo-fired,

cyclone-fired, etc.) burning any type offuel (bituminous, sub-bituminous, lignite, brown, etc.

coal, oil, gas, biomass, etc.). Thus, the temperature variation problem, which Babcock &

Wilcox indicated can be technically resolved by incorporating the appropriate and necessary

measures for the modification ofthe boiler's backpass and possibly the lignite pre-drying

system~, is no reason to determine that the SCR technology is technically infeasible for

cyclone-fired units burning North Dakota lignite. In a worst case scenario it may make

HDSCR the economically less attractive alternative compared to LDSCR or TESCR due to

the very unique boiler design employed at the M.R. Young Station.

6.8 Catalyst Erosion

The Department concludes that "there are unresolved issues regarding catalyst erosion from

the ash generated at the M.R. Young Station". This conclusion is not substantiated by any

data and at least highly disputable based on long-term SCR operating experience in Europe.

Units equipped with HDSCR systems firing up to 40% ash waste coals have been in

M Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion of Vendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units I & 2", May 8, 2008.

E-mail from Steve Moormann (Babcock &Wilcox) to Robert Blakley (Bums & McDonnell) dated 07/18/07.

Ibid

A-33
successful operation for almost two (2) decades now without any major operating problems

or excessive catalyst erosion87• The average ash content ofCenter Mine North Dakota lignite,

which has an average heating value of approximately 50% of bituminous coal, is less than

about 8%wt88• Hence, approximately twice as much lignite must be burned for the same heat

input compared to average bituminous coal. This, however, results still only in an equivalent

average ash content of about 16%wt. of comparable bituminous coal, which is a factor of

approximately 2.5 lower than the maximum ash content that HDSCRs have been exposed to

successfully in Europe. As a matter offact, bituminous coals with ash contents in the range

of 12 - 15 %wt. are considered normal in Europe and pose no erosion threat to SCR catalyst

whatsoever. Consequently, preventing excessive ash erosion ofthe catalyst is simply a matter

of correct SCR design as has been proven extensively in Europe. Neither Bums &

McDonnell nor Sargent and Lundy have any experience with HDSCR designs for higher ash

coals or any experience with the operation ofHDSCRs on high ash units.

This leads to the conclusion that the Department's concerns over seemingly unresolved

issues regarding catalyst erosion appear to be the result of a simple lack of knowledge ofthe

many HDSCRs that have been subjected to much harsher conditions for almost two (2)

decades now.

6.9 Catalyst Poisoning, Blinding and Plugging

The Department correctly states that "poisoning, blinding and plugging of a catalyst are

affected by the geometries and properties ofthe catalyst". However, subsequently, the

Department concludes that "cyclone firing ofFort Union lignite and Center Mine coal results

in a flue gas stream that highly accelerates poisoning, blinding and plugging (of pores) due to

the rich sodium and potassium vapors, particles and ammonia sulfates (due to ammonia

injection) in lignite-fired cyclone flue gas". The categorical absoluteness ofthis statement is

impressive as it rest solely on the highly questionable results ofthe ill-designed Coyote Pilot

Testin~. As already elaborated on in detail in sections 6.2 and 6.3 ofthis report and

confirmed by the Department90, the data ofthe referenced Coyote Pilot Testing is more or

less useless. Despite the facts that:

No deactivation data ofthe catalyst was ever determined during or after the Coyote

.!IT Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Term SCR Catalyst Experience and Cost", The

2005 EPRI Workshop on Selective Catalytic Reduction, Louisville, KY, November 2005.

.§J! Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas derived from

subbituminous and lignite coals", Fuel Processing Technology 86 (2005) pages 577 - 613,2005.

90 Page 7 ofthe Preliminary Best Available Control Technology Determination for Nitrogen Oxides for M.R.

Young Station Units 1 and 2, Division of Air Quality ND Department ofHealth, 918 E. Divide Avenue,

Bismarck, ND, June 2008.

A-34
Pilot Testing.

The combination ofthe fatally flawed Coyote Pilot Testing reactor design, the

inadequacy ofthe selected catalyst type and the extremely poor execution ofthe test

runs caused the severe catalyst pluggage after only two (2) months rather than the

flue gas composition and/or ash characteristics as pointed by highly experienced

catalyst manufacturers including CERAM and Haldor Topsoe2.l, who provided the

catalyst for the Baldwin and Coyote Pilot Testing.

The catalyst manufacturers most experienced with similar fuels (i.e. biomass, PRB,

brown coal, etc.) clearly stated92 that:

o "the deactivation rate ofthe catalyst will be high but manageable" (Haldor

Topsoe);

o "the information and test work presented indicate that it is certainly premature

to assume that there is a fatal flaw for the use of high dust SCRbehind

cyclones firing North Dakota lignite" (CERAM);

o they "are willing to warrant the catalyst performance" based on industry

standard terms (Haldor Topsoe);

o "a commercial offering regarding this project" can be provided (CERAM);

the Department boldly decided that "the engineering solutions of a larger SCR reactor, more

catalyst and larger pitch do not resolve the rapid plugging of catalyst pores". This conclusion

is in sharp contrast to the statements provided not only by the catalyst manufacturers most

experienced with similar types offuels but also with the statements made by some ofthe

most experienced SCR system suppliers (Alstom, Babcock Power), who "expect that an SCR

system could be successfully utilized on a boiler fired with Northern lignite fueI 93

".

The Department continues stating that "there is no catalyst vendor solution to reduce or

eliminate pore plugging. The chemical and physical process of pore plugging cannot be

reversed, which dictates catalyst change out." This statement is simply incorrect as several

well proven methods exist for successfully reducing and/or eliminating pore plugging and

completely reversing sodium and potassium poisoning ofthe catalyst. For instance, Alstom

in their correspondence with Bums & McDonnell points out several times94 that as a result of

.2.l Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

2l Ibid

21 Ibid

2± Ibid

A- 35
the highly efficient flue gas cleaning equipment upstream of a LDSCR or TESCR, the

installation of a LDSCR or TESCR would eliminate these issues. Furthermore, Haldor

Topsoe points out that "the expected poisons are mostly water soluble, therefore periodic

water washing ofthe catalyst can be used to regain activity and to increase overall service

life95". This is a clear reference towards the various in-situ96, on-site97 and off-site98 catalyst

washing, rejuvenation and regeneration processes that are commercially available and have

been successfully used in the U.S. as well as in Europe for more than a decade now. These

methods have proven beyond any doubt the possibility ofregaining the catalyst's full initial

activity for a fraction ofthe cost of new catalyst. They can also be applied multiple times to

the same catalyst, particularly in case ofsodium and potassium poisoning as well as fly ash

pluggage, where simple washing either in-situ99

or on sitelOO has yielded excellent results.

These various washing, rejuvenation and regeneration technologies have been utilized

successfully by the U.S. utility industry since early 2003l.Ql.

Why the Department ignores these facts and makes a statement in clear contradiction to all

this evidence remains unknown.

6.10 Lack of Pilot Scale Testing Data

The Department states that "without pilot testing, the long term NOx reduction efficiency,

the volume ofthe reactor, the catalyst pitch, life ofthe catalyst, or even type ofthe catalyst to

be used cannot be predicted with a high degree of confidence." This statement is most

interesting as is seems to be in clear contradiction to the Department's previous statements

that:

"Cyclone firing ofFort Union lignite and Center Mine coal results in aflue gas

stream that highly accelerates poisoning, blinding and plugging (ofpores) due to the

rich sodium and potassium vapors, particles and ammonia sulfates (due to ammonia

22. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

2§ Maier, H, W. Gotz, "In Situ Catalyst Regeneration - a Cost Saving Tec~nology for SCR Operators", a paper

presented at Power Gen, 2001.

21 Nagai, Y, Y. Inatsune, I. Morita, Y. Kato, K. Yokoyama, K. Ito, P. Otte, "Rejuvenation ofthe SCR Catalyst

at Mehrum", a paper presented at the Electric Power Conference, 2004.

.2J! Hartenstein, H., H. Gutberlet, "Catalyst Regeneration - An Integral Part of Proper Catalyst Management",

The 2001 EPRI Workshop on Selective Catalytic Reduction, 2001.

22 Maier, H, J. Matschke, "Recent Experience With SCR Catalyst Regeneration", a paper presented at the

DOE-NETL Conference on SCR/SNCR, 2001.

100 www.envirgy.com/en/references/catalyst regeneration.

lQl www.ebinger-kat.com/en/referenzen.php.

A-36
injection) in lignite-fired cyclone flue gas".

"The engineering solutions of a larger SCR reactor, more catalyst and larger pitch do

not resolve the rapid plugging of catalyst pores."

"The pilot scale (HD)SCR that was deployed at the Coyote Station was plugged and

the catalyst pores deactivated after 2 months (approx. 1,430 hours)" The Department

believes successful operation is considerably more than a few thousand hours of

operation."

How can the Department postulate on one hand that without further pilot testing long term

NOx reduction efficiency or in other words catalyst deactivation and therefore catalyst life

cannot be predicted with a high degree of confidence, while claiming on the other hand with

the seemingly highest degree of confidence that:

The flue gas composition leads to highly accelerated catalyst poisoning, blinding and

plugging?

Successful operation is considerably more than a few thousand hours based on the

fact that the ill-design HDSCR pilot test reactor plugged after only two (2) months?

Likewise how can the Department postulate on one hand that such fundamental HDSCR

design parameters as volume ofthe SCR reactor, catalyst pitch and type of catalyst cannot be

predicted with a high degree of confidence, while claiming on the other hand with the

seemingly highest degree of confidence that no engineering solutions of a larger SCR

reactor, more catalyst volume and larger pitch exist to resolve the rapid plugging of catalyst

pores? Unfortunately, the Department fails to resolve these obviously diametrically

contradicting statements.

Yet, it must be noted that the Department's claims concerning the rapid catalyst poisoning,

blinding and plugging as well as the claim that no engineering solutions exist to mitigate

these, are solely based on the highly questionable results ofthe ill-designed Coyote Pilot

Testing. At the same time, however, the Department states that without additional pilot

testing none ofthese necessary predictions could be made since the Coyote Pilot Testing was

ill-designed and didn't provide much useful datalO2• This contradiction further nurtures the

impression that the Department either solely relies upon or completely negates the Coyote

Pilot Testing results depending on what ever seems to favor the particular argument against

SCR at the moment.

.!R Preliminary Best Available Control Technology Determination for Nitrogen Oxides for M.R. Young Station

Units 1 and 2, page 7, Division ofAir Quality NO Department ofHealth, 918 E. Divide Avenue, Bismarck,

NO, June 2008.

A-37
6.11 Lack of Vendor Guarantees

The Department states that "vendors cannot without further pilot testing, guarantee SCR

system performance for M.R. Young Station boilers firing North Dakota lignite". This

statement is simply incorrect as both CERAM and Haldor Topsoe clearly stated that they

would be willing to offer industry standard type performance guarantees103 for their catalyst

for a HDSCR system installed at M.R. Young Station - see also the discussion in section 6.9

ofthis report.

The Department's claim that "even the most optimistic vendors don't offer true guarantees of

catalyst performance", is as incorrect as the first statement. Both, Haldor Topsoe and

CERAM clearly stated that they would be willing to offer industry standard type guarantees

for the performance oftheir catalyst for a HDSCR at M.R. Young Station. The fact that the

Department argues that "the guarantee is limited to the contract value" merely unveils the

Department's surprising lack offamiliarity with the type and extent of performance

guarantees provided within the utility industry. The fact ofthe matter is that no equipment

vendor in the utility industry ever accepts any liability for performance guarantees above and

beyond the full amount ofthe contract value, which is exactly what was offered Le. by

Haldor Topsoe 104• This is not only common practice in the utility industry but also a well

known fact to all A/E's including Bums & McDonnell and Sargent and Lundy. If asked,

none ofthe eight (8) participants in the SCR Vendor Query would offer an unlimited liability

or even a limit ofliability ofmore than the contract value for performance guarantees. Bums

& McDonnell as well as Sargent and Lundy, who themselves never provide any type of

process or system performance guarantees what so ever, are fully aware ofthis fact and will

surely admit to it if asked.

It is worth mentioning that in case a project such as an SCR retrofit at M.R. Young Station

would be carried out by an AlE such as Bums & McDonnell or Sargent and Lundy as an

owner's engineer for Minnkota and/or Square Butte, the only performance guarantees the

owner (in this case Minnkota and/or Square Butte) would ever receive would be the various

system performance independent guarantees for the performance ofthe individual equipment

and components supplied by the individual vendors including the one from the catalyst

supplier. Each ofthese individual equipment and component performance guarantees would

be limited to the value of and the equipment and/or component supplied by the respective

vendor and simply passed through by the AlE to the owner. Thus, none ofthese individual

performance guarantees would come even remotely close to covering the entire value ofthe

SCR retrofit as each one would represent only a small portion ofthe entire project. The

owner (in this case Minnkota and/or Square Butte) would have no performance guarantee for

103 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

104 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion ofVendor Responses on SCR Technical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8, 2008.

A- 38
the entire SCR system and not even any kind ofsystem performance guarantee from the AlE

that all the individually purchased pieces of equipment andlor components fit together as

intended so that the entire system performs as intended.

As a matter offact, the type and extent of performance guarantees offered by the catalyst

suppliers CERAM and Haldor Topsoe including the stated limitation of liability are most

certainly exactly the same as were provided for each and every SCR project, in which Bums

& McDonnell and Sargent and Lundy were ever involved.

If an owner seeks a true system performance guarantee that covers the entire scope ofthe

project, no AlE is needed. As a matter offact, an AlE is a hindrance in such a case as such

true complete system performance guarantees are only offered by complete system suppliers

such as Alstom, Babcock Power or Babcock & Wilcox. Contrary to an AlE, these true

system suppliers are willing and able to provide the entire scope of a tum-key SCR retrofit

including complete system performance guarantees for up to the value ofthe entire retrofit

project, which is then again the value ofthe contract. Such a tum-key supply, however,

eliminates the need for an owner to additionally pay an AlE, which is the simple reason why

these types of contracts are not favored by the AlEs. Yet, the most successful SCR retrofits in

the U.s. were done as tum-key installations without the use of an AlE.

6.12 Review Authority

The Department claims the review authority for this case. I do not comment on this.

6.13 Conclusions

In conclusion, it must be stated that the Department made numerous factually incorrect

claims, conclusions and statements as outlined in detail above. The most significant ones

include:

The conclusion that HDSCR is not technically feasible based on the data obtained

from the ill-designed HDSCR Coyote Pilot Testing that provided little useful data -

see sections 6.2, 6.3 and 6.9.

The conclusion that HDSCR is not technically feasible based on the lack of any

meaningful pilot testing data because the HDSCR Coyote Pilot Testing was illdesigned and provided little useful date - see sections 6.4, 6.6, 6.8 6.10 and 6.11.

The statement that Bums & McDonnell and Sargent and Lundy have extensive

experience with the design and operation of SCR systems - see section 6.5.

The claim that vendors cannot guarantee SCR system performance for M.R. Young

Station - see section 6.11.

A-39
The claim that LDSCR and TESCR are not technically feasible based on the data

obtained from the ill-designed HDSCR Coyote Pilot Testing that provided little

useful data and must be considered completely irrelevant altogether for an LDSCR

and/or TESCR design and application.

It is worth pointing out that the Department contradicted its own statements numerous times,

particularly concerning the quality ofthe data ofthe HDSCR Coyote Pilot Testing and the

unavailability of any really useful data from said pilot testing. No explanation was offered

why the HDSCR Coyote Pilot Testing data is condemned as inadequate in some cases, yet

hailed as offering the absolute truth in some other cases. Depending on what seems to best fit

the argument at the moment that HDSCR is not technically feasible for the M.R. Young

Station, the Department seems to either solely rely on this essentially useless Coyote Pilot

Testing data, which appears to be the case for the Department's conclusions concerning

catalyst:

poisoning, blinding and plugging;

deactivation and lifetime;

or seems to complain that no reliable pilot testing data is available, which appears to be the

. case for the Department's conclusions concerning catalyst:

erosion;

sizing (type, pitch, volume);

performance guarantees from the vendors.

The incorrectness ofthe Department's conclusions concerning the expected catalyst

deactivation as well as the performance guarantees was pointed out by some ofthose, who

know best, namely the catalyst manufacturers and SCR system supplierslOS.

The Department's arguments concerning fuel variability and ash composition are true for all

coals and by no means unique to this application and thus of no relevance to this case.

Likewise, the argument concerning unacceptable temperature variations and possible

popcorn ash problems are also of no further relevance to this case as all these issues would

have to and can be successfully resolved regardless ofthe type of combustion system (i.e.

cyclone fired) and/or the type offuel burned (i.e. North Dakota lignite).

Finally, the Department's conclusions against the technical feasibility ofLDSCR and

TESCR are completely unsubstantiated and erroneous. Not only does the Department fail to

105 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional Information and

Discussion ofVendor Responses on SCRTechnical Feasibility, North Dakota's NOx BACT Determination

for Milton R. Young Station Units 1 & 2", May 8,2008.

A-40
correctly distinguish and separate these two (2) distinctly different types of SCR systems, it

also concludes that "the (catalyst) deactivation issue for low-dust and tail-gas SCR remains

as with the high-dust SCR". Deciphered in detail, this is the Department's only single

argument against the application of a LDSCR or TESCR, since all other argued issues are

admitted to be "not unresolvable". Unfortunately, the Department again bases its erroneous

conclusion concerning LDSCR and TESCR solely on the data obtained during the illdesigned HDSCR Coyote Pilot Testing. As little if any relevance this essentially useless data

may have for an HDSCR application it most certainly has absolutely no relevance for a

possible LDSCR and/or TESCR application. The Department fails to recognize this.

A noticeably poor and incomplete attempt was made to provide at least some, however, not

meaningful data for the flue gas and fly ash composition downstream ofthe ESP. This

clearly suggests the lack of any meaningful data for the correct evaluation of an LDSCR. The

only data provided was some sampling performed downstream ofthe ESP at a temperature of

300 F (149 cC), which is well below the temperature range of 650 - 750 F (343 - 400 cC)

required for LDSCR operation. Therefore, the deposition data cited by the Department from

Minnkota's November 9,2007 response to comments106 is not relevant for the flue gas

conditions present in a LDSCR and even less for the flue gas conditions in a TESCR.

Unquestionably, the condensation of vapors including pyrosulfates and gaseous compounds

responsible for the stickiness ofthe ash is a function oftemperature as condensation of

vapors and gaseous compounds occurs progressively at lower temperatures. The Department

fails to explain how data concerning the stickiness ofthe ash particles collected on a silicon

dioxide surface at 300 F (149 cC) would have any significant relevance for the prediction of

catalyst pore pluggage by ash particles at 650 - 750 F (343 - 400 cC).

Absolutely no useful data characterizing the conditions downstream ofthe wet FGD was

provided, thus making any conclusion concerning a TESCR nothing but presumptive

speculation. The only at least somewhat factual attempts to argue why catalyst deactivation

downstream of a wet scrubber could be an issue is the Department's comment concerning the

Minn-Dak Farmer's Coop's coal fired boilers and some convoluted data107, which

presumably obtained by means ofstack testing downstream ofthe wet scrubber at M.R.

Young Station's Unit 2.

Using the Minn-Dak boilers 7A and 7B as an example, the Department argues that "MinnDak had trouble complying with its particulate matter emission limit due to sodium

compounds passing through the air pollution control device. In order to maintain compliance,

the ash Na20 content ofthe coal combusted had to be limited". The Department argues that

this is sufficient support for the Department's conclusion that "alkali mineral compounds are

not removed by the ESP or S02 scrubbing system". As a result the Department argues that "it

106 Response letter to EPA's October 4, 2007 letter sent from Minnkota Power Cooperative, Inc. to Mr. Terry

O'Clair, Director, Division of Air Quality at the North Dakota Department ofHealth, dated November 9,

2007.

107 Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

A- 41
appears a significant amount ofsodium compounds, a catalyst poison, will enter a low-dust

or tail-gas SCR system. The deactivation issue for low-dust and tail-gas SCR will remain the

same as for the high-dust SCR. The research, design and pilot testing needed to develop an

SCR system that will have reasonable success makes this technology also not applicable at

this time."

As will be shown in detail in section 7 ofthis report, no research, design and/or pilot testing

is needed to install a TESCR that will have complete success at M.R. Young Station. The

Minn-Dak experience cited by the Department, however, is by no means of any relevance to

the technical feasibility of a TESCR at M.R. Young Station, yet it seems to form the sole and

only basis for the Department's reasoning that TESCR is not applicable at this time.

Reviewing Minn-Dak's Air Pollution Control Title V Permit to Operate108 and the North

Dakota Department ofHealth's Inspection Repo~, it becomes evident that neither the

particulate matter removal device nor the wet scrubber are comparable to the air pollution

control equipment installed or under construction at M.R. Young Station. Minn-Dak's boilers

7A and 7B, which are two Babcock & Wilcox stoker-fired boilers burning coal, biogas and

natural gas, are equipped with multi-cyclones and co-current venturi scrubbers rather than

ESPs and counter-current spray towers. The coal burned was reported to be sub-bituminous

coal from the Spring Creek Coal Company in Montana rather than North Dakota lignitellQ.

Not only is the partitioning ofthe ash constituents ofthe coal that occurs in a cyclone-fired

boiler different from that in a stoker-fired boilerill but also is said partitioning different for

different coals. Thus, using data from a stoker-fired unit burning PRB to predict the

partitioning at a cyclone-fired unit burning North Dakota lignite is simply inappropriate.

As correctly stated by the Department, Minn-Dak has a restriction on the sodium content in

the coal at 2.8% NazO on a dry mass basis in the coal ash in order to meet the particulate

emission limit of 45.5 lb/hr, which, however, equates to 0.40 Ib/l06 Btu rather than 0.10

Ib/l06 Btu as erroneously claimed by the Department. It is critically important to note that the

sub-bituminous coal fired at Minn-Dakill. has an ash content of approximately 4 - 5%, which

is typical for sub-bituminous coal and not about 8 - 10% on average as North Dakota lignite.

In other words, North Dakota lignite has about twice the amount of ash compared to subbituminous coal. Furthermore, it is important to realize that the sub-bituminous coal burned

at Minn-Dak has only between 0.3% and 0.5% sulfur, which means that the uncontrolled SOz

108 State ofNorth Dakota, Department ofHealth, Division ofAir Quality, Air Pollution Control Title V Permit

to Operate, Permit Number T5-X78001 issued on 7/31/2006.

109 North Dakota Department ofHealth, Inspection Report, issued on 10/27/2003.

llQ Ibid

ill Response letter to EPA's October 4, 2007 letter sent from MinnkotaPower Cooperative, Inc. to Mr. Terry

O'Clair, Director, Division ofAir Quality at the North Dakota Department ofHealth, dated November 9,

2007.

ill State ofNorth Dakota, Department ofHealth, Division ofAir Quality, Air Pollution Control Title V Permit

to Operate, Permit Number T5-X78001 issued on 7/31/2006.

A-42
emissions range between 0.7Ib/l06 Btu and 1.1 Ib/l06 Btuill, which compares very

favorably to a permitted emission limit of 3.0 Ib/106 Btu. The measured S02 emission rate

was reported to be around 0.1 lb/l 06 Btu at a time when the uncontrolled emission rate was

theoretically and not accounting for any S02 being captured in the fly ash only about 0.7

lb/l 06 Btu (based on the coal data included in the report), which suggests a S02 removal rate

of no more than at the most 70%ill:. Combining this with the fact that these stoker fired units

have no ESP but are equipped with only multi-cyclones as primary particulate control

devices, suggests very strongly that the co-current venturi scrubbers were never intended to

remove any significant amounts of S02 but where designed as additional particulate removal

devices.

Multi-cyclones are comparatively simple devices designed for the removal of only the

coarsest fly ash particles. Therefore, multi-cyclones have not been used in utility boilers for

more than 40 years anymore. Due to the fact that multi-cyclones are based on the principal of

centrifugal forces removing the particles, only the largest and heaviest particles can be

removed. Contrary to that, ESPs electrically charge all sizes of particles, which are then

removed in an electric field as a result oftheir electric charge. Therefore, ESPs are much

more effective removal devices for particulate matter, particularly for very small particles.

Since PRB is known to generate a comparatively larg<;: fraction of very fine ash particles and

since these stoker-fired units were most likely not designed for burning PRB, it is quite

conceivable why the units didn't meet their particulate emission limit while burning PRB.

Not being equipped with particulate control devices suitable for the removal offine particles,

limiting the sodium content in the ash serves as means to limit the amount of very small

particles formed.

Co-current venturi scrubbers are particulate removal devices, which operate on the principle

of inertial impaction ofsmaller particles on water droplets as a result oflargely different

velocities. Again, only the larger particles have enough mass and therefore inertia to be

removed successfully. Small particles with a small mass and therefore very little inertia

follow the gas stream and successfully evade impaction. Contrary to that, counter-current

spray towers designed for S02 removal are based on the principle of offering a large amount

offinely dispersed liquid for the rapid cooling ofthe flue gas to its saturation temperature

followed by the absorption of gaseous air pollutants such as S02. During the rapid cooling of

the flue gas with a large excess of water, the very small particles, which provide a

comparatively large surface area, act as condensation nuclei and are absorbed into the .

scrubbing solution. Also, the flue gas residence time in a counter-current spray tower is much

longer than in a co-current venturi scrubber, which further assists removing small particles.

Suggesting that the flue gas inlet composition to a TESCR downstream of an ESP and a

counter-current wet flue gas desulfurization scrubber is even similar to the flue gas

composition downstream of a multi-cyclone and a co-current venturi scrubber designed for

ill. North Dakota Department ofHealth, Inspection Report, issued on 10/27/2003.

ill Ibid

A-43
coarse particulate removal is truly creative. Yet, the fact ofthe matter remains that the MimlOak experience is not comparable to the situation at the M.R. Young Station due to the

different:

coal burned (PRB versus North Dakota lignite);

combustion system design (stoker fired versus cyclone fired);

primary particulate matter removal device (multi-cyclone versus ESP);

wet scrubber design and purpose (co-current venturi for particulate removal versus

counter-current spray tower for S02 removal).

Thus, the Minn-Dak experience must be considered completely meaningless and irrelevant

for the possible application of a TESCR at the M.R. Young Station.

In Minnkota's April 18,2007 response to question from the Departmentill, Minnkota states

that "stack sampling was conducted downstream ofthe ESP and wet FGD on Unit 2."

However, it remains unclear whether the data provided represents samples taken downstream

ofthe ESP or samples taken downstream ofthe wet scrubber. Furthermore, even ifthe data

represents samples downstream ofthe wet scrubber, it is unknown whether the samples were

taken downstream ofthe wet scrubber but upstream ofthe bypassing flue gas re-entering the

flue gas stream to the stack or downstream ofthe bypass re-entry point. These questions are

very relevant, since the flue gas stream downstream ofthe ESP and upstream ofthe wet

scrubber is significantly different from the flue gas downstream ofthe wet scrubber.

Likewise, the flue gas stream downstream ofthe wet scrubber but upstream ofthe bypass reentry point is significantly different than the flue gas downstream ofthe bypassing flue gas

re-entering the flue gas stream coming from the wet scrubber to the stack. An e-mail string

between Minnkota and Bums & MacDonnelllliseems to indicate that at least the sampling

may have been done downstream ofthe wet scrubber and downstream ofthe bypass re-entry

point ofthe flue gas for reheating. Ifthis is confirmed than this data is completely useless for

the correct characterization ofthe flue gas stream entering a TESCR as approximately 18%

ofthe flue gas bypassed the wet scrubber at the time ofsamplingill. This means that the flue

gas sampled clearly does not represent what would enter a TESCR as everything that is

removed in a wet scrubber was still present in almost one fifth ofthe flue gas during

sampling. Since the sampling was clearly not intended to characterize the flue gas

composition entering a TESCR but intended to prove the particulate removal downstream of

the ESP, this data cannot be considered relevant for any reasonable judgment concerning the

technical feasibility of a TESCR.

ill Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit I

and Unit 2 NOx BACT Analysis Study, April 18, 2007.

ill E-mail string from John Graves (Minnkota) to Robert Blakely (Bums & McDonnell) dated April 12, 2007.

ill Ibid

A-44
Also, no flue gas characteristics (temperatures, velocity, composition, etc.) at the sampling

point are provided. Without exact knowledge of all these important details, the provided data

is useless even for any reasonable judgment concerning a LDSCR. However, even ifsome of

this missing information would be made available, the data would still be meaningless unless

the total mass flow or at least the total concentration ofthe various compounds in the flue gas

would be provided. The provided data only offers a morphological composition analysis of

the samples expressed in relative percentages ofthe various elements as a portion ofthe

entire sample. No information about the absolute amount ofthe various compounds as well

as their aggregate state was made available, which renders the data in its provided form as

absolutely useless for any meaningful interpretation concerning expected catalyst

deactivation rates. Why only this by itself completely useless portion ofthe data was

provided while all information needed to make the data possibly meaningful was withheld

(assuming that this information exists), remains unknown.

While the Department devotes forty (40) pages ofthe seventy two (72) page document to

arguments why HDSCR should be considered technically not feasible, little more than two

(2) pages are dedicated to LDSCR and TESCR combined. Ofthese two (2) pages little more

than one (I) page deals with possible site constraints and flue gas reheating, both of which

are correctly dismissed as being economic considerations instead oftechnical feasibility

issues, thus leaving about only one (1) page for the combined evaluation of LDSCR and

TESCR. This one (1) page states the Department's conclusion that a LDSCR and/or a

TESCR are technically infeasible without presenting any relevant supporting data. The

Department's conclusion rests solely on the incorrect, unsupported and unfounded claim that

"the deactivation issue for low-dust and tail-gas SCR remains the same as for high-dust

SCR". However, only a few paragraphs later, the Department contradicts this earlier

statement by postulating that "catalyst deactivation of a low-dust or tail-gas SCR due to

alkali compounds is an issue that will require extensive research, design and pilot testing to

determine whether the technology can be successfully applied to units fired on North Dakota

lignite". Either the Department can provide relevant supporting data for the claim that the

deactivation issue in a TESCR remains the same as in a HDSCR, or such supporting data

doesn't exist, in which case the claim is purely speculative and unsupported.

It is also a fact that the SCR Vendor Query conducted by Bums & McDonnell very

specifically stated that it was solely directed towards HDSCR, thus ignoring LDSCR and

TESCR. Why attempts by various vendors (Alstom, Babcock Power, CERAM) to also

consider LDSCR and/or TESCR were seemingly ignored remains unexplained.

Thus, the final conclusion reached by the Department that HDSCR is not technically feasible

is unacceptable. All the presented data, investigations, vendor information etc. most certainly

don't allow the conclusion that HDSCR is not technically feasible. Concluding that HDSCR

is technically infeasible is premature and unfounded.

Furthermore, the Department's conclusion that LDSCR and TESCR are both not technically

feasible is clearly presumptive and speculative as this conclusion cannot be supported by any

relevant data, investigation or vendor information. Additionally, it must be stated that this

A-45
conclusion is wrong as the only one (1) claim of excessive catalyst deactivation made against

TESCR is clearly technically not defendable.

In summary, this leads to the conclusion that the Department's statement that that SCR

technology is not technically feasible for application at the M.R. Young Station's cyclonefired units burning North Dakota lignite is incorrect. HDSCR may very well be technically

feasible, LDSCR is most likely technically feasible and TESCR is most certainly technically

feasible for application at the M.R. Young Station's cyclone-fired units burning North

Dakota lignite. With at least one SCR principle, namely TESCR being most certainly

technically feasible for the application at the M.R. Young Station, the Department's BACT

analysis incorrectly eliminated the SCR technology from further consideration.

7. VENDOR QUERY TAIL-END SCR

In order to further substantiate the technical feasibility ofTESCR for the M.R. Young

Station, the same eight (8) vendors were contacted that also participated in the Vendor Query

conducted by Bums & McDonnellill. Due to vacation schedules and other personal

restrictions only six (6) ofthe eight (8) vendors contacted were able to provide written

responses, while two (2) could provide only verbal responses. Also, time constraints

demanded that the scope and extent ofthe discussion with these eight (8) vendors had to be

limited to some very fundamental questions concerning TESCR.

Since catalyst deactivation seems to be the primary concern ofthe Department, more time

was devoted to communication with the catalyst manufacturers (Argillon, CERAM,

Cormetech, Haldor Tospoe, Hitachi) as they are ultimately the ones, who provide the process

performance guarantees for the catalyst. Somewhat less time was devoted to the SCR

equipment vendors, who ultimately also rely on the catalyst manufacturers for catalyst

performance and deactivation information and guarantees. Therefore, the response ofthe

catalyst manufacturers was considered to be most meaningful, particularly the responses of

the ones with extensive TESCR experience. Again, more time was devoted to the companies

with TESCR experience (Alstom, Argillon, CERAM, Babcock Power, Haldor Topsoe)

compared to the ones with no TESCR experience (Babcock & Wilcox, Cormetech, Hitachi).

The following eight (8) vendors were contacted:

SCR equipment vendors:

o Alstom - Mr. Michael Philips was not available due to time constraints and

therefore directed me to Mr. John Buschmann, SCR Product Manager at

Alstom, who provided only a verbal response due to insufficienttime for a

ill. Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to NDDH and EPA

Comments Regarding SCR Technical Feasibility and Non-SCR Concerns Milton R. Young Station Unit 1

and Unit 2 NOx BACT Analysis Study, April 18,2007.

A-46
written response. Alstom has extensive TESCR experience.

o Babcock Power - Dr. Clayton Erickson provided a written statement.

Babcock Power has access to extensive TESCR experience and is the

equipment supplier ofthe LOCSR downstream of a cold-side ESP under

construction as WE Energies' South Oak Creek Station.

o Babcock & Wilcox - Mr. Steve Moormann could not be reached. Instead, Mr.

Donald Tonn, SCR Process Expert at Babcock & Wilcox in Barberton, OH

was contacted and provided a written response. Babcock & Wilcox has no

TESCR experience.

SCR catalyst manufacturers:

o Argillon - Mrs. Cindy Khalaf provided a written statement. Argillon has

extensive TESCR experience.

o CERAM - Mr. John Cochran provided a written statement. CERAM has

extensive TESCR experience.

o Cormetech - Mr. Scot Pritchard provided a written statement. Cormetech has

no TESCR experience but some LOSCR experience.

o Haldor Topsoe - Mr. Flemming Hansen provided awritten statement. Haldor

Topsoe has extensive TESCR experience.

o Hitachi - Mr. Anthony Favale provided only a verbal response due to

insufficient time for a written response. Hitachi has no TESCR experience but

some LOSCR experience.

Due to the time constraints, the person named above at each ofthe eight (8) vendors was

contacted by phone and informed about the purpose ofthe discussion as well as asked

whether he or she would be willing to provide a briefstatement in writing per e-mail. All

contacted people agreed to provide a written statement. However, Messrs. John Buschmann

of Alstom and Anthony Favale of Hitachi who could provide only provide a verbal response

due to time constraints as the written response would have arrived after the submission of

this report.

All eight (8) vendors, namely three (3) SCR system suppliers (Alstom, Babcock Power and

Babcock & Wilcox) and five (5) SCR catalyst suppliers (Argillon, CERAM, Cormetech,

Haldor Topsoe and Hitachi) were asked to provide answers to the following three (3)

questions:

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and

the fuel (NO lignite), would <company>:

a. Consider a tail-end SCR technically feasible?

A-47
b. Recommend or require additional pilot testing?

c. Be willing to provide commercial guarantees for catalyst performance (activity,

pressure drop and S02/S03 conversion rate) and lifetime? Ifso what would these be?

All eight (8) vendors answered the question a. with a clear "yes". None ofthe vendors

expressed even the slightest doubts that TESCR would not be technically feasible for both

units at the M.R. Young Station. All three (3) contacted SCR system suppliers and all

responding five (5) SCR catalyst suppliers consider TESCR to be unquestionably technically

feasible for cyclone fired units burning North Dakota lignite.

All five (5) responding catalyst manufacturers answered question b. with a clear "no", thus

dismissing any need for any further pilot testing for a TESCR application at M.R. Young

Station.

Likewise, the SCR system suppliers Babcock Power and Alstom also dismissed any need for

any additional pilot testing for a TESCR. The only SCR system supplier, who stated that they

"would require further discussion with the catalyst suppliers", was Babcock & Wilcox. This

caution is simply the result ofthe lack of experience ofBabcock & Wilcox with TESCRs.

Given the fact that even though Babcock & Wilcox has a license from Hitachi for SCR

catalyst but Hitachi has no experience with TESCR either, such caution is no surprise.

All five (5) responding catalyst suppliers and all three (3) SCR system suppliers answered

question c. with a clear statement that they would provide common commercial performance

guarantees. Argillon indicated 90% NOx removal efficiency at less than 2 ppmvd @ 3% O2

NH3 slip and greater 24,000 SCR operating hours catalyst life. Obviously, more details

would have to be determined as the project would need to be defined better. Only Babcock &

Wilcox stated that the commercial guarantees would have to be discussed first with the

catalyst suppliers before passing them on to the buyer. Hitachi stated that they would have to

see the exact flue gas composition in order to determine what commercial guarantees would

be provided. Again, this can be explained by the fact that neither Babcock & Wilcox nor

Hitachi has any TESCR experience and did not have time to evaluate a TESCR application

for M.R. Young Station in sufficient detail.

Additionally, during the verbal discussions with all four (4) catalyst suppliers as well as all

three (3) responding SCR systems suppliers, the contact persons made it very clear that their

companies would not consider HDSCR as technically infeasible at this time. Particularly, all

five (5) responding catalyst suppliers very adamantly stated that the existing knowledge does

not support prematurely discarding HDSCR as a technically feasible possibility. All five (5)

responding catalyst suppliers suggested that properly designed and executed HDSCR pilot

testing would certainly be helpful to decide whether HDSCR would be more economically

attractive than LDSCR or TESCR for the M.R. Young Station. The e-mail correspondence of

all six (6) vendors, who responded in writing, is presented in detail in Appendix A.

A-48
8. SUMMARY

In summary, it must be concluded that TESCR is not only technically feasible but may be

even the most economical SCR alternative for M.R. Young Station. As reiterated by the

responding vendors, the very high removal efficiency ofthe ESP and wet FGD upstream of a

TESCR combined with the flue gas reheating from the flue gas dew point provides flue gas

conditions, which are unquestionably much more favorable for SCR catalyst than the

conditions present in almost all HDSCRs. Two decades ofTESCR experience in Europe

have proven that TESCR can be successfully applied to the most complex processes and the

most difficult flue gases. Catalyst replacement in most TESCRs has been minimal to none.

Most coal-fired units equipped with TESCRs still utilize the initial catalyst fill after more

than 130,000 SCR operating hours. Due to the greatly reduced mass flow of catalyst poisons

to the SCR catalyst the catalyst deactivation rates in TESCRs have proven to be extremely

low, in some cases barely measurable.

Additionally, minimal unit downtime for TESCR tie-in resulting in very little if any lost

generation is a huge advantage for TESCRs as they can be constructed typically completely

independent of and parallel to unit operation. Flue gas reheat cost is relatively low as the flue

gas needs to be reheated with high pressure steam only by about 18 - 65 degrees (10K - 35

K) and the condensate from the steam coil is typically further used for dilution air heating

and subsequent feed water before returned to the condensate from the turbine.

2BO"C PO 7. 34mb.,

S02

02 B.~~; 260mgim'

I

'j CO 8. 59mg1m '

j NO. 103mgim 3 A

, stBubO.01E i

NOxi1230ntgINm'!5%02 I

2B9'c

240'C f

HO_VW.9,3% .0.8%

210'C

• 43.B'lio

1.99m

Spw-Boh BI3 Anti'IE•

ntsp Ke"i'l~entsp

26l'C

j: HO-VW SIr -2.6"C

- 10~2 % l66'C

76.2bar

~X3 FG OPFVERS OENOX

02B ... EIN 009

FG VERDlFTGEBL SA ENTWAsSERUNG FO Menge 213 kg/'

... EIN 002 EIN RG-Menge 371m's

VWVERotFTGEBL BAN'E-ENTSP NOXSW 105m91NIII'

VOOWAHLl ErN NH3 SW 301kg/. E f

~~.~E~Ng6 NH3 Konzontr.l4.1 r.... ~-.;--=_·~-:1~4!!3-b;.rJiiiiliii~,.~ VWNH3EINO 45.3% I 478"C

REliELVENT 1 • I SW 290'C

AUF 54.2·c I

Spw

-

---~-~-- -------- r- -·-----r~---- -- ---- r- ,- r ~- -- 1---- , . I

:- -----.----11-- ---·1 - :: ; I i

A-49
The graph above presents a typical process flow diagram from a TESCR on a 300 MW coalfired unit. This TESCR has operated for more than 130,000 hours for more 20 years now on

the initial fill of catalyst with a continuous NOx removal efficiency in excess of 91 %. As can

be seen on the graph, the high pressure steam used for reheating is cooled from about 892 F

(478°C) to ultimately 410 F (210°C) after dilution air and feedwater heating and prior to

being discharged to the feedwater storage tank. Also worth noting is the small amount of

only 18 degrees F (10K) that need to be added to the flue gas by means of high pressure

steam. As can be seen, the flue gas downstream ofthe gas-gas heat exchanger enters the

steam coil with a temperature of approximately 534 F (279°C) and enters the SCR reactor

downstream ofthe steam coil with a temperature of only about 552 F (289°C). This proves

the high efficiency ofthe gas-gas heat exchanger and the small amount of high pressure

steam needed for flue gas reheating, which makes this concept economically more attractive.

In the u.s. currently both 325 MW units at PSE&G's Mercer Generating Station are

equipped with TESCRs with flue gas reheat downstream ofthe ESPs. Spray dryer absorbers

followed by baghouses downstream are being added downstream ofthe SCRs, thus

effectively converting them from TESCRs to LDSCRs. Th~ same type SCR with flue gas

reheat is currently being installed at WE Energies South Otter Creek Generating Station.

Thus, LDSCR and/or TESCR systems can neither be dismissed as being technically

infeasible nor based on economic reasons. Particularly the TESCR principle was developed

specifically in order to successfully adapt the SCR technology to units with the most difficult

flue gas compositions and the most complex retrofit challenges. During its 22 years of

extraordinarily successful operating history, the TESCR principle has not only

unconditionally proven itself as one ofthe most viable SCR principles but certainly the most

universally applicable of all SCR principles.

A- 50
Appendix A: Data and Information Considered

"Alternative Control Technologies Document NOx Emissions from Utility Boilers" March

1994. U.S. EPA, Office of Air and Radiation, Office of Air Quality Planning and

Standards. This information can be found at website address:

http://www.epa.gov/ttn/catc/dir1/utboiler.pdf.

Amended SIP Permit to Operate, letter from the North Dakota Department of Health to

John Graves, Minnkota Power Cooperative, dated February 5, 2002.

Ando, Jumpei, "S02 and NOx Removal for Coal Fired Boilers in Japan," presented at the

Seventh Symposium on Flue Gas Desulfurization, May, 1992.

Argillon's website: www.argillon.com.

Assessment ofS02and NOx Emission Control Technology in Europe, Air and Energy

Engineering Research Laboratory, EPA-600/2-88-013, February 1988.

Attachment 10, "Initial Design" Boiler Heat Input Rating vs "As Built" Boiler Heat Input

Rating, George W. Button, January. 2001.

Attachment 11, Expert Opinion Report, Maximum Boiler Heat Input Capacity Units 1 and 2

Milton R. Young Station, Minnkota Power Cooperative, Inc. Center, N.D., 58530, Robert

L. Pearson, Ph.D., PE, CH2M Hill, 100 Inverness Terrace East, Englewood, CP 80224, ca.

2001.

Benson, A. J. D. Laub, C. R. Crocker, J. H. Pavlish, "SCR catalyst performance in flue gas

derived from subbituminous and lignite coals", Fuel Processing Technology 86 (2005)

pages 577 - 613,2005.

"Compilation of Air Pollutant Emission Factors AP-42, Fifth Edition, Volume 1: Stationary

Point and Area Sources, Chapter 1.1, Bituminous and Subbituminous Coal Combustion"

dated July 1993.

Current Status of SCR in Japan. by: Yasuyuki Nakabayashi and Rikiya Abe, Research and

Engineering office, Thermal Power Department, Electric Power Development Co., Ltd.

Tokyo, Japan 100. ca 1987.

Cyclone NOx Control: Technology and Issues Assessment, Electric Power Research

Institute, 1998.

A- 51
East Texas Electric Generating Facilities (EGFs) Stakeholder Meeting Summary, TCEQ

East Texas rulemaking concept, Austin, Texas, November 18,2005.

E-Mail from Randy Sadler on behalf ofCindy Khalaf, President ofArgillon LLC, supplier

ofthe SCR catalyst for Oak Grove 1 & 2, dated June 24, 2008.

E-mail from Flemming Hansen (Haldor Topsoe) dated June 30, 2008.

E-mail string from John Graves (Minnkota) to Robert Blakely (Bums & McDonnell) dated

April 12,2007.

E-mail from Steve Moormann (Babcock &Wilcox) to Robert Blakley (Bums &

McDonnell) dated July 18,2007.

EPA-450/3-92-004, Office of Air and Radiation, Office ofAir Quality Planning and

Standards, "Summary ofNOx Control Technologies and their Availability and Extent of

Application", February 1992.

Erickson, C., S. Straight, L. Hutcheson, "Coal-Fired SCR Operating Experience with High

Removal Efficiency and Low-NOx Firing Systems", Babcock Power's website:

www.babcockpower.com.

Exclusive analysis ofTXU court decision;an article published in Power Engineering,

September 2006.

Feasibility and Cost ofSCR NOx Control in Utility Applications, RP 1256-8 prepared by

United Engineers and Constructors, Inc. for Electric Power Research Institute (EPRI),

August 1989.

Fisia Babcock GmbH (formerly L&C Steinmiiller GmbH) and Babcock Power, Inc.

reference lists SCR systems.

Hartenstein, H., H. Gutberlet, "Catalyst Regeneration - An Integral Part of Proper Catalyst

Management", The 2001 EPRI Workshop on Selective Catalytic Reduction, 2001.

Hartenstein, H., H. Gutberlet, L. Licata, "Utility Experience with SCR in Germany", a

paper presented at the Sixteenth Annual International Pittsburgh Coal Conference, October

1999.

Institute ofClean Air Companies (ICAC) letter to Michael Leavitt, USEPA Administrator

dated July 15,2004.

A-52
Impact ofTexas Lignite Coal on SCR Catalyst Life and Performance, Field Data from

TXU's Martin Lake Plant, EPRl Report 1004732, Electric Power Research Institute,

December 2003.

Jones, R, Introductory presentation at the Gulf Coast Power Spring Conference, April

2006.

Maier, H, J. Matschke, "Recent Experience With SCR Catalyst Regeneration", a paper

presented at the DOE-NETL Conference on SCR/SNCR, 2001.

Maier, H, W. Gotz, "In Situ Catalyst Regeneration - a Cost Saving Technology for SCR

Operators", a paper presented at Power Gen, 2001.

Martin, M., M. Harrell, J, Jancauskas, H. Hartenstein, H. Sobolewski, "Large Particle Ash

(LPA) Screen Retrofits at Coal-Fired Units in Indiana and Ohio", DOE-NETL Conference

on SCR/SNCR, 2006.

McIlvaine Utility E-Alert #868, April 4, 2008.

McIlvaine Utility E-Alert #871 dated April 25, 2008.

McIlvaine Utility E-Alert #870 dated April 18, 2008.

McIlvaine Utility E-Alert #874 dated May 16,2008.

Milton R. Young Station - Our Jewel on the Prairie, brochure published by Minnkota

Power Cooperative and Square Butte Electric Cooperative on Minnkota's website:

www.minkota.com.

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, "Additional

Information and Discussion of Vendor Responses on SCR Technical Feasibility, North

Dakota's NOx BACT Determination for Milton R. Young Station Units 1 & 2", May 8,

2008.

Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative, Responses to

NDDH and EPA Comments Regarding SCR Technical Feasibility and Non-SCR Concerns

Milton R. Young Station Unit 1 and Unit 2 NOx BACT Analysis Study, April 18,2007.

Nagai, Y., Y. Inatsune, 1. Morita, Y. Kato, K. Yokoyama, K. Ito, P. Otte, "Rejuvenation of

the SCR Catalyst at Mehrum", a paper presented at the Electric Power Conference, 2004.

North Dakota Department of Health, Inspection Report, issued on 10/27/2003.

A- 53
NOx Abatement for Stationary Sources in Japan, Jumpei Ando, EPA/600/7-81-030, May

1983.

NOx Abatement for Stationary Sources in Japan, Jumpei Ando, Heiichiro Tohata, Katsuya

Nagata, and B.A. Laseke. EPA/600/7-77-l03b, September 1977.

NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit

1 Minnkota Power Cooperative, Inc., Revised Final Report, October 2006, 311777.

NOx Best Available Control Technology Analysis Study for Milton R. Young Station Unit

2 Minnkota Power Cooperative, Inc. Operating Agent for Square Butte Electric

Cooperative, Owner. Revised Final Report, October 2006,311777.

NOx Control Field Test Results on Coal-Fired Cyclone Boilers-CNCIG Programs, Electric

Power Research Institute, 1999.

Preliminary Best Available Control Technology Determination for Control ofNitrogen

Oxides for M.R. Young Station Units 1 and 2, Division of Air Quality, North Dakota

Department of Health, 918 East Divide Avenue, Bismarck, North Dakota.

Preliminary Best Available Control Technology Determination for Nitrogen Oxides for

M.R. Young Station Units 1 and 2, Division ofAir Quality ND Department of Health, 918

E. Divide Avenue, Bismarck, ND, June 2008.

PSD Applicability Determination M.R. Young Station Unit 1 Turbine Upgrade, letter from

the North Dakota Department ofHealth to John Graves, Minnkota Power Cooperative,

dated March 11,2005.

Reference list on CERAM's website: www.frauenthal.net.

Reference list on Ebinger Katalysatorservice's website: www.ebingerkat.com/en/referenzen.php

Reference list on Envirgy's website:

www.envirgy.com/en/references/catalyst regeneration.

Response letter to EPA's October 4, 2007 letter sent from Minnkota Power Cooperative,

Inc. to Mr. Terry O'Clair, Director, Division ofAir Quality at the North Dakota Department

of Health, dated November 9,2007.

Sanyal, A., W. Allison, "Lessons Learned from SCR Experience ofCoal-Fired Units in

Japan, Europe and USA; Are These Enough?" Presented at the 2002 DOE Conference

Selective Catalytic Reduction and Non Catalytic Reduction for NOx Control, Pittsburgh,

PA, May 2002.

A- 54
Sargent & Lundy Engineers Engineering Data, Unit 1 Baldwin Power Station. IPPRO0085676-744.

Sargent and Lundy, LLC, "Application of SCR Technology to North Dakota Lignite Fuels",

a Power Point presentation, May 2007.

Selective Catalytic Reduction for Coal-Fired Power Plants: Feasibility and Economics,

EPRI CS-3603, October 1984.

Smith, R, J. Bennett, D. Broske, "Impacts ofTexas Lignite on SCR Catalyst Life and

Performance", presented at the 2007 EPRI SCR Workshop in Pensacola, Florida, November

2007.

S02 and NOxAbatement for Stationary Sources in Japan. 1. Ando. U.S. EPAlIERL, EPA600/7-83-028, May 1983.

Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Term SCR Catalyst Experience

and Cost", The 2005 EPRI Workshop on Selective Catalytic Reduction, Louisville, KY,

November 2005.

State ofNorth Dakota, Department of Health, Division of Air Quality, Air Pollution Control

Title V Permit to Operate, Permit Number T5-X78001 issued on 7/31/2006.

Summary ofResponses to EPA/DOH Questions on Minnkota Power's NOx BACT

Analysis for Milton R. Young Units 1 & 2, Presentation by EERC, Minnkota Power, Burns

& McDonnell to NDDH and U.S. EPA, May 23, 2007.

Tangential Low NOx System at Reliant Energy's Limestone Unit 2 Cuts Texas Lignite,

PRB and Pet Coke NOx, Ron Pearce, Reliant Energy and John Grusha, Foster Wheeler

Energy Corporation, May 30, 2001.

Technical Assessment ofNOx Removal Processes for Utility Application. EPA-600/7-77-

127, November 1977.

Technical Feasibility and Cost of SCR NOx Control in Utility Applications, RP 1256-8

prepared by United Engineers and Constructors, Inc. for Electric Power Research Institute

(EPRI), August 1989.

"Top-Down" Best Available Control Technology Guidance Document (Mar. 15, 1990).

Office of Air Quality Planning and Standards, U.S. EPA.

Twenty-five Years of SCR Evolution: Implications for US Application and Operation,

Cichanowicz and Muzio, 2001.

A- 55
Yurkanin, T., H,-V. Hartenstein, "O&M Cost Savings Through SCR Management and

Catalyst Regeneration for the Logan Generating Plant", a paper presented at the 6th Annual

Electric Power Conference & Exhibition, Baltimore, MD, 2004.

A-56
Appendix B: SCR Vendor Query Correspondence

1. Vendor Correspondence with SCR system suppliers

1.1 E-Mail correspondence with Clay Erickson, Babcock Power (SCR System

Vendor - extensive tail-end SCR experience)

From: cerickson@babcockpower.com [mailto:cerickson@babcockpower.com]

Sent: Thursday, June 19, 2008 15:59

To: Hans Hartenstein

Cc: jlangone@babcockpower.com; tlicata@babcockpower.com

Subject: Re: Tail-end SCR

Hans,

Babcock Power has reviewed the Milton Young plant in the past, based on these reviews Babcock

Power finds

o A tail-end SCR is technically and commercial feasible

o Babcock Power does not recommend or require additional pilot testing only proper flue gas

characterization as with any SCR system per performed

o Will provide commercial guarantees for the SCR and catalyst performance (activity,

pressure drop and S02/S03 conversion rate) and lifetime

Babcock Power has the largest SCR experience list in the world; from this experience we are

completely confident in the application of a tail end system at Milton Young. If you have further

questions please let me know.

With best regards,

Clay

Clayton Erickson, PhD

Director, Process Engineering

Babcock Power Inc.

5 Neponset Street

Worcester, MA 01606

T: 508-854-4039 F: 508-854-1177

M: 508-245-2383

From: "HansHartenstein"<Hans.Hartenstein@Evonik-EnergyServices.us>

Sent: 06/18/2008 12:16

To: <cerickson@babcockpower.com>

SUbject: Tail-end SCR

Clay,

As discussed during our phone conversation today, during which you stated that Babcock Power

considers a high-dust SCR principally, technically feasible even though not without technically

resolvable challenges for Minnkota's Milton R. Young Station, I would also be interested in Babcock

Power's position' on the technical feasibility of a tail-end SCR (downstream of a wet scrubber including

A- 57
flue gas reheat) Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber)

and the fuel (ND lignite), would Babcock Power:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure

drop and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones built by your licensor Fisia Babcock

(most of which are on wet bottom boilers) went into operation in the late 1980s and most of them still

operate on the initial fill of catalyst after almost 20 years and up to 130,000 operating hours, I would

assume that Babcock Power 1Fisia Babcock has sufficient confidence in your tail-end SCR

experience to competently respond to these questions. Please let me know if you have any additional

questions. Thanks.

Best regards,

Hans Hartenstein

1.2 E-Mail Correspondence with Don Tonn, Babcock & Wilcox (SCR System

Vendor - no tail-end SCR experience)

From: Tonn, Donald P [mailto:dptonn@babcock.com]

sent: Monday, June 23, 2008 16:06

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans:

Please note my responses to your questions in the referenced email below.

Regards,

Donald P. Tonn

Babcock & Wilcox Power Generation Group

AQCS Technology

Phone 330-860-1986

Cell 330-289-7795

From: Hans Hartenstein [mailto:Hans,Hartenstein@Evonik-EnergyServices.us]

sent: Wednesday, June 18, 2008 13:25

To: Tonn, Donald P

Subject: Tail-end SCR

Don,

As discussed during our phone conversation today, during which you stated that Babcock &Wilcox

considers a tail-end SCR (downstream of a wet scrubber including flue gas reheat) principally

technically feasible for Minnkota's Milton R. Young Station, I would be interested in Babcock &

Wilcox's position on the following questions. Given your knowledge about the plant (cyclone-fired

B&W boilers, ESP, wet scrubber) and the fuel (ND lignite), would Babcock & Wilcox:

Consider a tail-end SCR technically feasible? Yes

Recommend or require additional pilot testing? Requires further discussion with catalyst

suppliers.

A-58
Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be? While B&W has

considered tail-end SCR systems on other projects we have not had these commercial

guarantee discussions with the catalyst suppliers for the North Dakota lignite application.

Before consideration of providing these guarantees a comfort level would be required after

obtaining guarantees from catalyst suppliers.

Given the fact that tail-end SCRs in Germany went into operation in the late 1980s and most of them

still operate on the initial fill of catalyst after almost 20 years and up to 130,000 operating hours, I

would assume that Babcock & Wilcox has sufficient confidence in tail-end SCR systems to

competently respond to these questions. Please let me know if you have any additional questions.

Thanks.

Best regards,

Hans Hartenstein

2. Vendor Correspondence with SCR Catalyst Manufacturers

2.1 E-Mail Correspondence with Cindy Khalaf, Argillon (Catalyst Manufacturerextensive tail-end SCR experience)

From: Khalaf Cindy R [mailto:cindy.khalaf@argillon.com]

Sent: Tuesday, June 24 2008 14:15

To: Hans Hartenstein

Subject: Re: Argillon Tail-end SCR

No problem.

Regards,

Cindy

From: Hans Hartenstein <Hans.Hartenstein@Evonik-EnergyServices.us>

Sent: Tuesday, June 24,2008, 16:45

To: Khalaf Cindy R

Subject: RE: Argillon Tail-end SCR

Cindy,

Thanks a bunch for taking the time to respond. I greatly appreciate your answer. I'll keep you posted

where this thing is going.

Best regards,

Hans Hartenstein

http://www.evonik-energyservices.us

From: Sadler Randy rmailto:randy.sadler@argillon.coml

Sent: Tuesday, June 24,200808:15 AM

A- 59
To: Hans Hartenstein

Cc: Khalaf Cindy R

Subject: Argillon Tail-end SCR

Importance: High

On behalf of Cindy Khalaf -

Hans,

Further to our phone call, as far as I know, Argillon has more tail end experience than any other SCR

catalyst manufacturer and, as you noted, we also have experience with high dust, German lignite

SCRs. Argillon also won the first US lignite SCR catalyst project (Luminant Oak Grove 1 & 2) and

provided commercial guarantees. These units are not in service yet. So, yes, we consider ourselves

able to answer these questions competently.

Consider a tail-end SCR technically feasible?

Yes, we consider this configuration to be technically feasible. As you know, tail end SCRs are often

used when there are significant catalyst poisons in a flue gas stream. A wet scrubber can remove

most of these poisons, resulting in very low catalyst deactivation.

Recommend or require additional pilot testing?

For a high dust configuration, we would say definitely. For a tail-end configuration, we would say no.

We would only like to see a flue gas analysis for conditions at the inlet to the SCR in order to predict

deactivation rate.

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop and

S02/S03 conversion rate) and lifetime? If so what would these be?

Generally speaking, yes, we would provide guarantees for DeNOx & slip as specified (not to exceed

90% or 2 ppm), 24k hours life, S02 conversion rate - low but value TBD, pressure drop - value TBD.

Of course we would have to see the technical specifications before being more specific. In addition,

tail-end SCRs perform much longer, so depending on the application specifics, customer, etc., we

may decide to extend the operating life guarantees. This is a commercial decision and will be

reviewed on a case-by case basis.

If you have any more questions, please let me know.

Regards,

Cindy

Cindy R. Khalaf

Argillon LLC

President

Tel: 678.341.7520

Mobile: 770.331.9571

FAX: 678.341.7509

Email: cindy.khalaf@argillon.com

5895 Shiloh Road, Ste. 101

Alpharetta, GA 30005

From: Hans Hartenstein [mamo:Hans.Hartenstein@Evonik-EnergyServices.us]

Sent: Thursday, June 19, 2008 16:29

A-60
To: Khalaf Cindy R

Subject: Tail-end SCR

Cindy,

As discussed during our phone conversation today, during which you stated that Argillon considers a

high-dust SCR principally technically, feasible based on your high-dust SCR experience with lignite

fired units in Europe even though not without technically resolvable challenges for Minnkota's Milton

R. Young Station, I would also be interested in Argillon's position on the technical feasibility of a tailend SCR (downstream of a wet scrubber including flue gas reheat). Given your knowledge about the

plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel (NO lignite), would Argillon:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with Argillon catalyst went

into operation in the late 1980s and most of them still operate on the initial fill of catalyst after almost

20 years and up to 130,000 operating hours, I would assume that Argillon has sufficient confidence in

your tail-end SCR experience to competently respond to these questions. Please let me know if you

have any additional questions. Thanks.

Best regards, .

Hans Hartenstein

2.2 E-Mail Correspondence with John Cochran, CERAM Environmental (Catalyst

Manufacturer - extensive tail-end SCR experience)

From: John Cochran [mailto:John.Cochran@ceram-usa.com]

sent: Wednesday, June 25, 2008 15:14

To: Hans Hartenstein

Cc: Greg Holscher; Noel Rosha; Orehovsky Kurt

Subject: RE: Request for Information

Hans,

CERAM certainly considers the use of a tail-end SCR on applications such as the Milton R. Young

Station as technically feasible provided a proper design approach is used. CERAM has the

experience from more than 100 tail-end and low dust applications dating from 1988 that would

substantiate our opinion. For a tail-end approach we see no need for additional pilot testing. As

such, we can provide full commercial guarantees for catalyst performance (activity or lifetime,

conversion rate, pressure drop, etc.).

The choice between high dust and tail-end processes certainly should consider capital costs,

operating costs and process risk. Based on our experience certainly process risk would favor a tailend approach, but albeit for most circumstances at a higher "all-in" cost. Should very high retrofit

factors be present for a high dust arrangement then the relative economic factors may even favor a

tail-end approach.

I hope this information is useful to your evaluation. Please advise should you have any further

A- 61
questions or information needs. Thanks.

Best Regards,

John Cochran

CERAM Environmental, Inc.

www.frauenthal.net

913.239.9896 (phone)

913.205.5615 (cell)

This e-mail and any attachments are confidential. Ifyou have received this electranic transmission in error, please reply to the sender

regarding the error and permanently delete the original message and any attachments.

From: Hans Hartenstein [mailto:Hans.Hartenstein@Evonik-EnergyServices.us]

sent: Tuesday, June 17, 2008 7:20

To: John Cochran

Subject: Request for Information

John,

As discussed during our phone conversation today, during which you stated that CERAM considers a

high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R. Young Station, I would also be interested in CERAM's position on

the technical feasibility of a tail-end SCR (downstream of a wet scrubber including flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(ND lignite), would CERAM:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with CERAM catalyst

(Herne 1, 2 and 3, Voerde (West) 1 and 2, LOnen 10 and 11 - all ofwhich are wet bottom boilers)

went into operation in the late 1980s and most of them still operate on the initial fill of catalyst after

almost 20 years and up to 130,000 operating hours, I would assume that CERAM has sufficient

confidence in your tail-end SCR experience to competently respond to these questions. Please let me

know if you have any additional questions. Thanks.

Best regards,

Hans Hartenstein

2.3 E-Mail Correspondence with Scot Pritchard, Cormetech (Catalyst

Manufacturer - no tail-end SCR experience)

From: Pritchard, Scot G. [mailto:PritchardSG@Cormetech.com]

Sent: Thursday, June 19, 2008 17:41

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

A- 62
I was thinking of if you put a coupon in the tailend location and it showed something weird then you

would have to do something more elaborate Le. A slipstream with longer hours, etc. We do not

anticipate this - in fact you could probably do without the coupon test as well since I don't see any

reason why this system would be any different the primary tail end experience i.e. Unlikely any

nasties make it through the lower temperature environment and scrubber process. The coupon is OK

but I really don't expect to see much. Finally, we have not done any specific coupon tests (because

slipstream has been the primary way to evaluate) so we would need to think through the best way to

do it - Le. holder, mounting arrangement, test method, hours of exposure, etc. If you already have

something in mind please let uS know.

Hope that helps with the clarification.

Scot

From: "Hans Hartenstein" <Hans.Hartenstein@Evonik-EnergyServices.us>

Sent: Thursday, 6/19/084:26 pm

To: "Pritchard, Scot G." <PritchardSG@Cormetech.com>

Subject: RE: Tail-end SCR

Scot,

Thanks for the input from Cormetech, which is greatly valued. One question for clarification purposes

only, though. Coupon tests and/or flue gas analysis would only be performed in order to characterize

the flue gas going into the tail-end SCR as is needed for the design of any APC equipment. Obviously,

nobody could offer any performance guarantees concerning what's coming out of a tail-end SCR

without knowing what's going into it. You state that in case coupon tests would show a significant

accumulation of catalyst poisons, a subsequent slip stream test, which is unquestionably more

accurate and representative of a full scale - in this case tail-end - SCR, would be recommended.

Stating this, do I understand you right that you would recommend this slip stream testing mainly for the

purpose of properly characterizing the flue gas composition at the inlet to the tail-end SCR in order to

provide a reliable basis for correct catalyst design? Do I assume correctly, that you would not require

extensive and long-term (12 - 24 months) pilot testing with a slip stream reactor because you have

serious doubts about the principal technical feasibility of a tail-end SCR for this application? Please

clarify. Thanks.

Best regards,

Hans Hartenstein

From: Pritchard, Scot G. [mailto:PritchardSG@Cormetech.com]

Sent: Thursday, June 19, 2008 12:15

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

Please see my input below.

As discussed during our phone conversation today, during which you stated that Cormetech considers

a high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R. Young Station, I would also be interested in Cormetech's position

on the technical feasibility of a tail-end SCR (downstream of a wet scrubber including flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(ND lignite), would Cormetech:

Consider a tail-end SCR technically feasible? - yes

A- 63
Recommend or require additional pilot testing? - We generally do not consider coupon testing

an accurate representation of an SCR, however in order to minimize cost and provide basic

screening information we would suggest the potential use of a coupon sample test. If the

coupon shows significant accumulation of catalyst poisons, a subsequent slipstream type test

which is more representative of a full scale SCR i.e match velocity, AVs, etc. would be

recommended.

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be? Presuming the

coupon test does not shoW anything unusual (which we do not expect to see anything

unusual) we would be willing to provide commercial guarantees for a low dust application.

Basic guarantees would be associated with life (this would not include specific Ko and KlKo

as guarantees - the guarantee would be an efficiency and slip guarantee at a certain number

of operating hours ), S02 conversion, pressure loss.

As discussed, the high dust application needs additional due diligence testing (slipstream, ash testing,

etc.) as well as the practicality of the applicable operating temperature to establish the commercial

stance for a high dust application on North Dakota Lignite. We have done such work for Texas lignite

as well as other coal sources and other fuels/applications in the past and would expect to be able to

achieve the same for this application. The economics for any given application would be considered

on a case by case basis.

Let me know if you have any questions. Also I would appreciate anything of the final document that

you can share.

Thank you and regards,

Scot Pritchard

VP, Sales & Marketing

Cormetech

919-595-8708 0

919-815-2380 c

Frain: Hans Hartenstein [mailto:Hans.Hartenstein@Evonik-EnergyServices.us]

sent: Thursday, June 19, 2008 11:35 AM

To: Pritchard, Scot G.

Subject: Tail-end SCR

Scot,

As discussed during our phone conversation today, during which you stated that Cormetech considers

a high-dust SCR principally technically, feasible even though not without technically resolvable

challenges for Minnkota's Milton R. Young Station, I would also be interested in Cormetech's position

on the technical feasibility of a tail-end SCR (downstream of a wet scrubber including flue gas reheat)

Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet scrubber) and the fuel

(NO lignite), would Cormetech:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rate) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany (most of which are on wet bottom boilers) went into

operation in the late 1980s and most of them still operate on the initial fill of catalyst after almost 20

years and up to 130,000 operating hours, I would assume that Cormetech has sufficient confidence in

tail-end SCR systems to competently respond to these questions. Please let me know if you have any

additional questions. Thanks.

A- 64
Best regards,

Hans Hartenstein

2.4 E-Mail Correspondence with Flemming Hansen, Haldor Topsoe (Catalyst

Manufacturer - extensive tail-end SCR experience)

From: Flemming Hansen [mailto:FGH@topsoe.com]

sent: Friday, June 27, 2008 12:56

To: Hans Hartenstein

Subject: RE: Tail-end SCR

Hans,

Your understanding is what I meant to say.

Thanks

Flemming G. Hansen

Manager SCR DeNOx Catalyst

Haldor Topsoe, Inc.

281-228-5120 (office)

281-228-5129 (fax)

281-684-8820 (cell)

FGH@Topsoe.com

www.topsoe.com

"Hans Hartenstein"

<Hans.Hartenstein@EvonikEnergyServices.us>

06/24/2008 04:16 PM

Flemming,

To "Flemming Hansen" <FGH@topsoe.com>

cc

Subject RE: Tail-end SCR

Thanks for your note. Just to make sure that I understand you correctly. Is it correct to state that

Haldor Topsoe feels fully confident that a tail-end SCR is technically feasible and would not

experience any accelerated catalyst deactivation? Therefore, you would be willing to guarantee

catalyst performance (NOx removal efficiency, pressure drop, S02/S03 conversion rate and catalyst

lifetime) without any need for further pilot testing. Please confirm. Thanks.

Best regards,

Hans Hartenstein

From: Flemming Hansen [mailto:FGH@topsoe.com]

Sent: Dienstag, 24. Juni 200816:44

To: Hans Hartenstein

A-65
Subject: Re: Tail-end SCR

Hans,

Like you describe we have had very good operating experience with SCR in the clean environment

after a scrubber or bag filter. There appears to be practically no catalyst deactivation and with the low

amount of particulate the catalyst pitch can be small, which both leads to a compact SCR as

compared to a high dust SCR.

Based on the clean flue gas after the FGO we would not require any further testing in order to

guarantee a catalyst performance.

The actual guarantees would be as normally applied in a high dust installation and depend on the

catalyst volume and operating conditions. At the low operating temperature expected at the tail-end

position the S02 oxidation will be negligible.

I hope this confirmation will have your approval.

Flemming G. Hansen

Manager SCR OeNOx Catalyst

Haldor Topsoe, Inc.

281-228-5120 (office)

281-228-5129 (fax)

281-684-8820 (cell)

FGH@Topsoe.com

www.topsoe.com

"Hans Hartenstein" <Hans.Hartenstein@EvonikEnergyServices.us>

06/24/2008 10:24 AM

Flemming,

To <fgh@topsoe.com>

cc

Subject Tail-end SCR

As discussed during our phone conversation today, during which you stated that Haldor Topsoe

considers a high-dust SCR principally technically, feasible even though not without technically

resolvable challenges for Minnkota's Milton R. Young Station, I would also be interested in Haldor

Topsoe's position on the technical feasibility of a tail-end SCR (downstream of a wet scrubber

including flue gas reheat) Given your knowledge about the plant (cyclone-fired B&W boilers, ESP, wet

scrubber) and the fuel (NO lignite), would Haldor Topsoe:

Consider a tail-end SCR technically feasible?

Recommend or require additional pilot testing?

Be willing to provide commercial guarantees for catalyst performance (activity, pressure drop

and S02/S03 conversion rat~) and lifetime? If so what would these be?

Given the fact that tail-end SCRs in Germany including the ones equipped with your catalyst have

been in operation since the late 1980s and most of them still operate on the initial fill·of catalyst after

almost 20 years and up to 130,000 operating hours, I would assume that Haldor Topsoe has sufficient

confidence in your tail-end SCR experience to competently respond to these questions. Please let me

know if you have any additional questions. Thanks.

Best regards,

Hans Hartenstein

A-66
Appendix C: Selected Papers Authored in Last Ten Years

Selected SCR related papers in English I have authored in the last ten years:

Licata, A., W. Schiittenhelm, H. Hartenstein, "Mercury and Dioxin Control for Municipal

Waste Combustors", Asia-North American Waste Management Conference, Los Angeles,

CA, USA 1998.

Hartenstein, H., P. Dyke, "Working Group 1 Expert Report - Sources and Technology", 1st

Scientific and Evaluation Workshop on Persistent Manufactured Chemicals and ByProducts from Industrial and Combustion Processes, UNEP Chemicals, Geneva,

Switzerland 1999.

Bouwman, H., H. Hartenstein, "Working Group 2 Expert Report - Technology and

Remediation", 4th Workshop on Policy, Social and Economic Issues Assessing Persistent

Toxic Substances, UNEP Chemicals, Geneva, Switzerland 1999.

Chandler, J, 1. Gallant, H. Hartenstein, "Retrofit of a WTE-Facility With SCR for NOx and

PCDD/F Control NazS4-lnjection for Mercury Control", i h North American Waste-ToEnergy Conference, Tampa, FL, USA 1999.

Hartenstein, H., "Dioxin and Furan Inventories - National and Regional Emissions of

PCDD/PCDF", UNEP Chemicals, Geneva, Switzerland 1999.

Hartenstein, H., H. Gutberlet, "Utility Experience with SCR in Germany", DOE Conference

on SCRlSNCR, Pittsburgh, PA, USA 1999.

Chandler, 1., J. Gallant, H. Hartenstein, A. Licata, "Retrofit of a WTE Facility with SCR for

NOx and PCDDIF Control and NaZS4 Injection for Mercury Control", DOE Conference on

SCRlSNCR, Pittsburgh, PA, USA 1999.

Schiittenhelm, W., R. Wemhoner, H. Hartenstein, K. Werner, "Reduction ofPCDD/F

Emissions From Iron Ore Sintering Plants - The First Full-Scale SCR Installation", 19th

International Symposium on Halogenated Environmental Organic Pollutants and POPs -

Dioxin 99, Venice, Italy 1999.

Gutberlet, H., H. Hartenstein, A. Licata, "SOz Conversion Rate of DeNOx Catalysts -

Effects on Downstream Plant Components and Remedial Measures", The Mega Symposium

- EPA-DOE-EPRI Combined Power Plant Air Pollution Control Symposium, Atlanta, GA,

USA 1999.

Hartenstein, H.-U.; Schiittenhelm, W.; "Dioxin and Furan Reduction Technologies for

Combustion and Industrial Thermal Process Facilities", Workshop on Polychlorinated

Dibenzo-P-Dioxins and Polychlorinated Dibenzofurans, Pollution Control Department,

Bangkok, Thailand 1999

A- 67
Hartenstein, H. "UNEP's Standardized Dioxin Release Inventory Kit - A Tool to Assist

Countries in Establishing National PCDD/PCDF Release Inventories", Sub-Regional

Expert Meeting on the Reduction of Persistent Organic Pollutants (POPs) in Particular

Dioxins and Furans, St. Petersburg, Russia 1999.

Hartenstein, H. "Techniques to Reduce Emissions of Dioxins And Furans From Large

Sources", Sub-Regional Expert Meeting on the Reduction of Persistent Organic Pollutants

(POPs) in Particular Dioxins and Furans, St. Petersburg, Russia 1999.

Hartenstein, H., "Modem Technologies to Reduce Emissions of Dioxins and Furans from

Waste Incineration", International Symposium on Environmental Endocrine Disrupters '99,

Kobe, Japan 1999.

Fiedler, H., P. Dyke, H. Hartenstein, "Standardized Dioxin Inventory Toolkit" UNEP

Chemicals, Geneva, Switzerland 2000.

Chandler, J, H. Hartenstein, "Controlling Heavy Metals and Persistent Organic Pollutants

from Waste Incineration", Internationales Symposium zur Abfallwirtschaft in Mitteleuropa,

Prague, Czech Republic 2000.

Hartenstein, H., "Availability ofTechniques to Reduce Non-Pesticide PTS", STAP

Brainstorming Meeting on Persistent Organic Pollutants (POPs), Bridgetown, Barbados

2000.

Hartenstein, H., "Guidance Document for the Collection, Assembly and Evaluation of Data

on Sources, Environmental Levels and Impact Assessment" GEF: Regionally Based

Assessment ofPersistent Toxic Substances, UNEP Chemicals, Geneva, Switzerland 2000.

Hartenstein, H., "Techniques to Reduce PCDD/PCDF Emissions from Waste Incineration",

Invitational Expert PCDDIPCDF Workshop sponsored by UNEP Chemicals Switzerland,

Gesellschaft fUr Technische Zusammenarbeit Germany and the Thai Pollution Control

Department, Bangkok, Thailand 2000.

Licata, A., H. Hartenstein, "Modem Technologiesto Reduce Emissions of Dioxins and

Furans from Waste Incineration", 8th Annual North American Waste To Energy

Conference, Nashville, TN, USA 2000.

Hartenstein, H., "Introduction and Use ofTechniques to Reduce Emissions ofDioxins and

Furans - A Training Module to Complement UNEP's Standardized Toolkit for

Identification and Quantification of Dioxin and Furan Releases", UNEP Chemicals,

Geneva, Switzerland 2000.

Hartenstein, H. "Techniques to Reduce Emission of Dioxins and Furans", UNEP Workshop

on PCBs, Dioxins and Furans, Montevideo, Uruguay 2000.

A- 68
Fiedler, H., P. Dyke, H. Hartenstein, "Standardized Toolkit to Establish Dioxin

Inventories", UNEP Workshop on PCBs, Dioxins and Furans, Montevideo, Uruguay 2000.

Fiedler, H., P. Dyke, H. Hartenstein, "Needs and Ways to Establish Complete and

Comparable Dioxin Inventories", 20th International Symposium on Halogenated

Environmental Organic Pollutants and POPs - Dioxin 2000, Seoul, Korea 2000.

Schluttig, A., P. Servatius, H. Hartenstein, "Lifetime Extension ofSCR-DeNOx Catalysts

Using SCR-Tech's High Efficiency Ultrasonic Regeneration Process", DOE Conference on

SCR/SNCR, Pittsburgh, Pa, USA 2001.

Hartenstein, H., "Final Result Evaluation Report - Thailand Dioxin Sampling Program

November 20,2000 - January 26, 2001", Gesellschaft fUr Technische Zusammenarbeit,

Bonn, Germany 2001.

Hartenstein, H., A. Schluttig, P. Servatius, "Lifetime Extension ofSCR-DeNOx Catalysts

Using SCR-Tech's High Efficiency Ultrasonic Regeneration Process", Coal-Gen, Chicago,

II, USA 2001.

Hartenstein, H., A. Schluttig, P. Servatius, H. Gutberlet, "Experience with Full Scale

Commercial Regeneration ofSCR-DeNOx Catalyst" The Mega Symposium - EPA-DOEEPRI Combined Power Plant Air Pollution Control Symposium, Chicago, IL, USA 2001.

Hartenstein, H., H. Gutberlet, "Catalyst Regeneration - An Integral Part of Proper Catalyst

Management", The 2001 EPRI Workshop on Selective Catalytic Reduction, Baltimore,

MD, USA 2001.

Hartenstein, H., "SCR Experience in Europe - Lessons Learned After 17 Years of SCR

Operation", Invitational SCR Workshop by Babcock & Wilcox, Akron, OH, USA 2002.

Bullock, D., H. Hartenstein, "O&M Cost Reduction of a Coal-Fired US Merchant Plant

Through an Optimized SCR Management Strategy Involving Catalyst Regeneration", DOE

Conference on SCR/SNCR, Pittsburgh, PA, USA 2002.

Fiedler, H., P. Chareonsong, 1. Mayer, H. Hartenstein, "PCDD/PCDF Emissions From

Stationary Sources - First Results From Thailand", 22nd International Symposium on

Halogenated Organic & Persistent Organic Pollutants - Dioxin 2002, Barcelona, Spain

2002.

Harrison, K., E. Healy, H. Hartenstein, "Southern Company's Investigation ofCatalyst

Cleaning and Regeneration Options", The 2002 EPRI Workshop on Selective Catalytic

Reduction, Atlanta, GA, USA 2002. .

A- 69
Craig, M., H. Harrison, E. Healy, H. Hartenstein, "Catalyst Pluggage Due to Popcorn AshCleaning and Regeneration Options", The Mega Symposium - EPA-DOE-EPRI Combined

Power Plant Air Pollution Control Symposium, Washington, D.C., USA 2003.

Bullock, D., H. Hartenstein, "O&M Cost Reduction of a Coal-Fired US Merchant Plant

Through an Optimized SCR Management Strategy Involving Catalyst RegenerationStrategy Update Summer 2003", The Stack Emissions Symposium, Clearwater Beach, FL,

USA 2003.

Bullock, D, H. Hartenstein, "Full-Scale Catalyst Regeneration Experience At The CoalFired Indiantown Generating Plant", DOE Conference on SCR/SNCR, Pittsburgh, PA, USA

2003.

Hartenstein, H., "Dioxin and Furan Reduction Technologies for Combustion and Industrial

Thermal Process Facilities", Handbook ofEnvironmental Chemistry- Volume 3

Anthropogenic Compounds Part 0 - Persistent Organic Pollutants, Springer Verlag Berlin

Heidelberg New York, ISBN 3-540-43728-2, Germany 2003.

Hartenstein, H. "Performance ofCommonly Used Combustion Technologies on POPs

Destruction", STAP/GEF Technical Workshop on Emerging Innovative Technologies for

the Destruction and Decontamination of Obsolete POPs, Washington D.C., USA 2003.

Hartenstein, H., "Control Technologies for the W. H. Sammis Plant, Stratton, Ohio" Expert

Report for the US Department ofJustice, Civil Action No. C-2-99-1181, Washington D.C.,

USA 2003.

Hartenstein, H., "Catalyst Regeneration Experience", NOx Round Table 2004 Conference

and Exhibit, Akron, OH, USA 2004.

Yurkanin, T, H. Hartenstein, "O&M Cost Savings Through SCR Management and Catalyst

Regeneration for the Logan Generating Plant", Electric Power 2004 Conference and

Exhibit, Baltimore, MA, USA 2004.

Hartenstein, H., "Air Pollution Control Technologies for the W. H. Sammis Plant, Stratton,

Ohio developed in connection with United States v. Ohio Edison Company, et at." Expert

Rebuttal Report for the US Department ofJustice, Civil Action No. C-2-99-1181,

Washington D.C., USA 2004.

Hartenstein, H., "Incineration Technologies", World Bank Workshop Series: Issues on

Waste Disposal: Workshop 1 - Hazardous Wastes, Washington D.C., USA, 2004.

Wiese, S., D. Monnin, K. Sauvageau, H. Hartenstein, "O&M Cost Optimized SCR

Operation and Management at AES' Somerset Station", The Mega Symposium - Combined

Air Pollution Control Symposium, Washington D.C., USA 2004.

A-70
Harrison, K, E. Healy, M. Craig, T. Harbin, L. Mays, H. Hartenstein, "Simultaneous

Reduction ofthe S02 Oxidation Rate During Catalyst Washing And Regeneration", 2004

EPRl SCR Workshop, Pittsburgh, PA, USA 2004.

Hartenstein, H., "Pet Coke - Effects of Wet and Dry Scrubbing", 2005 WPCA / Dominion

Particulate - Scrubber Seminar, Richmond, VA, USA 2005.

Hartenstein, H., "LPA Screens - Utilities Need a Proven Solution", WPCA News, Issue 8

fall 2005, Chicago, IL, USA 2005

Sobolewski, H, H. Hartenstein, H. Rhein, "STEAG's Long Term SCR Catalyst Experience

and Cost", The 2005 EPRl Workshop on Selective Catalytic Reduction, Louisville, KY,

USA 2005.

Hartenstein, H., "LPA Screens - A Proven Solution", 2006 NOx Round Table Conference

and Expo, Charlotte, NC, USA 2006

Hartenstein, H., "SCR Management Ensures SCR Performance at Minimum Operating

Cost", WPCA News, Issue 9 spring 2006, Chicago, IL, USA 2006

Sobolewski, H., H. Hartenstein, M. Martin, "STEAG's Long Term SCR Catalyst

Experience and Cost", DOE-NETL Conference on SCRlSNCR, Pittsburgh, PA, USA 2006

Martin, M., M. Harrell, J, Jancauskas, H. Hartenstein, H. Sobolewski, "Large Particel Ash

(LPA) Screen Retrofits at Coal-Fired Units in Indiana and Ohio", DOE-NETL Conference

on SCRlSNCR, Pittsburgh, PA, USA 2006

Hartenstein, H., "SCR Operating and Management Experience Including Catalyst

Regeneration", AES Operator's Meeting, Denver, CO, USA 2006

Hartenstein, H., "AIG Tuning - An Essential Part of SCR Management", WPCA News,

Issue 10 fall 2006, Chicago, IL, USA 2006

Rhein, H., S. Sobolewski, H. Hartenstein, M. Martin, "STEAG's Long-Term Catalyst

Operating Experience and Cost", Power Plant Air Pollutant Control Mega Symposium,

Baltimore, MD, USA 2006

Harrell, M., J. Jancauskas, H. Hartenstein, S. Sobolewski, M. Martin "LPA Screen Retrofits

at Coal-Fired Units in Indiana and Ohio", Power Plant Air Pollutant Control Mega

Symposium, Baltimore, MD, USA 2006

Rhein, H., H. Hartenstein, H. Brilggendick, "Cost Development of Single Absorber Open

Spray Tower LSFO FGDs During the Last 20 Years - STEAG's Experience", Power Plant

Air Pollutant Control Mega Symposium, Baltimore, MD, USA 2006.

A-71
Hartenstein, H., S. Wiese, M. Martin, "Regeneration - STEAG Process and Experience",

The 2006 EPRI Workshop on Selective Catalytic Reduction, Dearborn, MI, USA 2006

Martin, M. H. Hartenstein, "Bench Scale Testing of Catalyst - History and Protocol", The

2006 EPRI Workshop on Selective Catalytic Reduction, Dearborn, MI, USA 2006

Hartenstein, H., "German Experience With Catalyst Regeneration", 2007 NOx Round Table

Conference and Expo, Cincinnati, OH, USA 2007

Hartenstein, H., "STEAG's Catalyst Regeneration Process - Ten Years of Experience",

2007 NOx Round Table Conference and Expo, Cincinnati, OH, USA 2007

Martin, M., H. Hartenstein, "Catalyst Bench Scale Testing: Guidelines and Round Robin

Testing", WPCA News, Issue 11 spring 2007, Chicago, IL, USA 2007

Elliot, P., Hartenstein, H., "Selective Separation of Mercury and Other Heavy Metals

During FGD Wastewater Treatment"", 2007 APC Round Table Conference and Expo,

Chattanooga, TN, USA 2007

Elliot, P., H. Hartenstein, "A Cost Effective FGD Wastewater Treatment System" WPCA

News, Issue 12 fall 2007, Chicago, IL, USA 2007

Kramer, M., C. Gerlach, H. Hartenstein, "As203 and S03 Testing at Hoosier Energy's

Merom Generating Station", The 2007 EPRI Workshop on Selective Catalytic Reduction,

Pensacola, FL, USA 2007

A-72
Appendix D: Resume

Hans-Ulrich H art ens t e i n

Title:

Managing Director E&EC

Nationality:

German

Education:

• University of Stuttgart

• University of Stuttgart

• University of Florida

• University ofToronto

General Experiences:

B. Sc. in Mechanical Engineering

M.E. in Mechanical Engineering

M.E. in Environmental Engineering

Global Executive MBA

Mr. Hartenstein has been in the envirom~ental field for over twenty years. His experience

includes project development, project management and supervision, coordination and

implementation of design and building projects for municipal waste-to-energy, hazardous

waste incineration, and air pollution control facilities (SCR, FGD, Hg control, PCDD/PCDF

control) in the power utility industry and waste-to-energy industry.

His responsibilities included project development, process engineering and management,

procurement and construction supervision, start-up and commissioning, environmental and

financial analysis, permitting application procedures and regulatory interfacing.

Mr. Hartenstein has been project management director of numerous air pollution control

systems, one municipal waste-to-energy project, and four hazardous waste incineration

projects. He has been involved in the development of eighteen environmental projects out of

which seven also included permitting procedures and process design, two also included

construction and one included complete start-up and commissioning.

Mr. Hartenstein has also directed development ofwaste management and air pollution

control segments and managed a $ 61 million turnkey contract for 80 TPD hazardous waste

incineration contract including a tail-end SCR. After completion ofthe facility Mr.

Hartenstein was responsible for the initial 2 years of operation ofthe plant. He was also

responsible for the successful negotiations of eight tum key mass bum, waste-to-energy

contracts valued in excess of $ 600 million and he has successfully negotiated several

international air pollution control technology licenses (SCR and FGD) among Polish,

A-73
Korean, American and Japanese companies.

He has managed and supervised feasibility analysis, conceptual engineering and design,

permitting final design, technology development, and project implementation and has

assisted in project financial planning including assuring financing for several projects.

Since 1999 Mr. Hartenstein has been active mainly in the U.S. in the areas of SCR and FGD

retrofits to fossil fuel fired electric utility generating stations. He expanded his initial focus

on the design and construction ofthese SCR and FGD retrofits quickly into the areas of long

term operation and maintenance of air pollution control equipment. His current focus is on

most cost effective long term FGD and SCR management ensuring maximum performance at

the lowest possible cost.

Positions Held:

• Environmental Engineer L&C SteinmUller GmbH!)

• Senior Environmental Engineer L&C SteinmUller GmbH!)

• Engineering Department Manager L&C SteinmUller GmbH!)

• Senior Engineering Director L&C SteinmUller GmbH!)

• Project Management Director L&C SteinmUller GmbH!)

• Plant Manager RVA Bohlen RVA Bohlen GmbH

• Senior Vice President Babcock Borsig Power, Inc.2

)

• President SCR-Tech LLC

• President Evonik Energy Services LLC3

)

• Managing Director E&EC GmbH

1987 - 1989

1989 -1990

1990 -1992

1992 -1995

1995 - 1997

1997 -1999

2000 - 2001

2001- 2005

2006 - present

1999 - present

I) L&C Steinmiiller GmbH has been acquired and renamed to Fisia Babcock GmbH

2) Babcock Borsig Power, Inc. has been acquired and renamed Babcok Power, Inc.

3) Steag LLC was renamed Evonik Energy Services LLC, no change in ownership

Professional Memberships

• Member ofthe World Pollution Control Association (WPCA)

• Invitational member ofthe Scientific Technical Advisory Panel (STAP) ofthe United

Nations Environment Programme related to POPs and PTS.

A-74
ENCLOSURE 2

EPA COMMENTS ON NDDH PRELIMINARY BACT

DETERMINATION

EPA COMMENTS ON NDDH PRELIMINARY BACT DETERMINATION

I. NDDH'S ANALYSIS OF TECHNICAL FEASIBILITY OF TAIL-END AND

LOW-DUST SCR AT MRYS IS INCORRECT AND BASED ON INCOMPLETE

INFORMATION.

In previous comment letters, EPA explained that the applicability of SCR downstream

of pollution control equipment (tail-end SCR (TESCR) or low-dust SCR (LDSCR» would

effectively eliminate the catalyst plugging and deactivation problems described in the

Minnkota BACT analysis and that the costs associated with plant modifications and flue gas

reheat in order achieve proper catalyst operating temperatures are a matter of cost and not

technical feasibility. \ B&McD's response to EPA's comments was that the information

provided by the Energy & Environmental Research Center (EERC) shows that, "effective

solutions to prevent or remove micropore pluggage and blinding of SCR catalyst from

sodium-sulfur compounds evident in the flue gas stream exhausted from a North Dakota

lignite-fired boiler, whether installed in a conventional hot-side or cold-side application

downstream of a wet scrubber, have not been developed by SCR catalyst vendors" and that,

"these are credible arguments that adequately describe the reasons that preclude the

successful deployment ofthis technology on the cyclone boilers at MRYS.,,2 B&McD does

not agree that an economic analysis would be required because, "[t]he extensive plant

modifications anticipated to deploy SCR at Unit 1 and Unit 2 at MRYS still do not resolve

the catalyst micropore plugging and blinding problems evident in the Coyote Station pilotscale testing.,,3 EERC adds that, "[t]here is evidence ofsodium, potassium, calcium, and

sulfur deposition downstream ofthe ESP as illustrated in Figure 1 presented in response to

ERC Core Issue number 2.,,4

Based on these responses, it appears that the basis for Minnkota's assertion that TESCR

and LDSCR are teChnically infeasible is solely based the perceived catalyst micropore

plugging and deactivation problems extrapolated from the results ofthe Coyote Station pilot

testing and the flue gas sampling performed on MRYS Unit 1 downstream ofthe electrostatic

precipitator at 3000 F.

.The NDDH BACT determination states that the site constraint and flue gas reheat

issues are a matter of economicsinstead oftechnical feasibility, but "catalyst deactivation of

a low-dust or tail-gas SCR due to alkali compounds is an issue that will require extensive

research, design and pilot testing to determine whether the technology can be successfully

applied to units fired on North Dakota lignite. Therefore, these technologies are not

1 See EPA's January 9, 2007 letter to NDDH (sent via fax), pages 13-16 and October 4,2007 letter to NDDH and

Minnkota, pages 31-35.

2 See Minnkota's November 9, 2007 letter to NDDH, page A-28.

3 See Minnkota's November 9, 2007 letter to NDDH, page A-29.

4 See Minnkota's November 9,2007 letter to NDDH, page A-29. Figure I shows a "Cross-section of a surface

exposed to flue gas at about 3000 F in MRY Unit 1" and the relative weight percentages ofsodium, silicon, sulfur,

potassium, calcium, and iron.
EPA Comments on NDDH Preliminary

NOx. BACT Determination . for MRYS

considered applicable and not technically feasible at this time."s,6 The NDDH BACT

determination cites the sampling provided in Minnkota's November 9,2007 letter which

showed weight percentages ofvarious compounds collected downstream ofthe electrostatic

precipitator and previous·experierlce at the Minn-Dak Farmer's Coop. coal-fired facility,

which had problems maintaining compliance with a particulate limit and subsequently had to

limit their fuel sodium content.7 As more fully set forth below, Minnkota has failed to

produce sufficient evidence to show that TESCR or LDSCR would experience extreme

.catalyst deactivation that would preclude the successful operation at MRYS.

Coyote Station Pilot Testing

Minnkota cites the Coyote Station pilot testing results as they relate to catalyst

deactivation and plugging caused by sodium compounds and other alkali compounds as

evidence that MRYS would not be suitable for a TESCR or LDSCR installation. This

assertion is completely unfounded for a number ofreasons. First, as described in previous

EPA comment letters and as supplemented by the expert opinion report ofMr. Hartenstein

provided herein, the Coyote Station pilot testing was clearly flawed and does not even

provide meaningful conclusions to apply to afull-scale installation of high-dust SCR

(HDSCR). Furthermore, since the Coyote Station pilot testing used flue gas upstream ofthe

pollution control equipment, there is even less reason to believe that test results (even the

qualitative results expounded on by Minnkota) have any relevance to a TESCR or LDSCR

application, which would have substantially less ash constituents downstream of an

5 See NDDH BACT detennination, pages 56-57.

6 The NDDH has made the detennination that SCR would be technically feasible in its analysis ofthe

Westmoreland Power, Inc. Gascoyne 500 Generating Station. In its May 2007 analysis ofthe Gascoyne 500 project,

the NDDH states, "[b]y reheating the flue gas and locating the SCR downstream ofthe other air pollution control

devices, SCR appears to be technically feasible. However, the Department is not certain that this technology will

work with a Dakota lignite-fIred unit because it has not been used before.. For these reasons, the Department

retained, with reservations, it as a technologically feasible control option." (See pages 58-59.) This proposed

. project would consist oftwo 285 MW-gross circulating fluidized bed boilers controlled by a dry scrubber and

baghouse. The SCR would be located downstream of both control devices. In this case, the applicant

(Westmoreland) cited many ofthe same concerns stated by Minnkota and the NDDH regarding uncertainty with

North Dakota lignite and the signifIcant engineering involved in applying SCRto this facility (Westmoreland even

cited the EERC report on the pilot testing at Coyote Station), but concluded low-dust SCR was still technically

feasible. In their pennit application, Westmoreland states, "it is likely that Westmoreland would incur signifIcant

engineering and testing to ensure the viability of a low-dust SCR control system on a lignite-fIred CFB boiler.

However, there does not appear to be any technical basis to exclude low-dust SCR from the BACT detennination."

Apparently, the NDDH agrees with Westmoreland that the signifIcant engineering and testing does not preclude

technical feasibility AND agrees with Minnkota who believes that such activities do preclude technical feasibility.

Low-dust SCR was eventually eliminated from consideration for mainly economic reasons, primarily due to the low

uncontrolled NOx emissions from the Gascoyne boilers. While the confIguration in the Westmoreland

detennination is referred to as low-dust SCR, it should be considered tail-end SCR, as it is downstream of a both a

particulate control device and S02 scrubber.

7 See NDDH BACTdetennination, pages 55-56.

-2-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

electrostatic precipitator (for LDSCR) and wet scrubber (TESCR). Thus, the Coyote Station

pilot testing did not provide any meaningful data in terms of evaluating HDSCR and is even

less useful for evaluating technical feasibility ofTESCR and LDSCR.

MRYS Unit 1 Sampling

Minnkota's November 9, 2007 letter, which is cited in the NDDH BACT

determination, explains that flue gas sampling ofMRYS Unit 1 was conducted downstream

ofthe electrostatic precipitator and a cross-sectional analysis ofthe constituents was

performed. Minnkota and the EERC asserts that the sampling shows a high degree of

sulfated potassium and sodium compounds similar to the compounds observed at the Coyote

Station pilot test. Therefore, Minnkota believes that the electrostatic precipitator would not

remove much ofthe vaporized sodium and potassium and implies that similar results would

have been produced during the Coyote Station pilot test if conducted doWnstream ofthe

electrostatic precipitator. Aside from the fact that the Coyote Station pilot testing had

significant design and operational problems, the results ofthe flue gas sampling presented in

Minnkota's November 9, 2007 letter in no way quantifies the total amount of particulate

material that was collected and would be expected to exist in a LDSCR environment. The

data that was presented is only in terms weight percentages and only provides evidence that

there will be sodium and potassium downstream ofthe electrostatic precipitator. While these

compounds may exist in a LDSCR environment, no attempt was made by Minnkota to

quantify how these weight percentage would translate to loading to a LDSCR and how that

would affect catalyst life. Therefore, using this data to show that the presence ofsodium and

potassium compounds downstream ofthe electrostatic precipitator would preclude the

successful operation of a LDSCR is completely speculative and highly questionable.

The NDDH BACT determination uses this d~ta in conjunction with an emission factor

comparison presented in the NDDH analysis to reach a similar conclusion. Without knowing

what the total amount ofloading is downstream ofthe electrostatic precipitator and how

these weight percentages relate to LDSCR loading and catalyst life, however, the conclusions

in the NDDH BACT determination are pure speculation and highly questionable. The

NDDH BACT determination also uses this data to support that conclusion that these catalyst

poisons will enter a TESCR, even though the sampling was done without wet scrubbing.

Using this data in anyway to support the conclusion that a TESCR could not be successfully

operated is completely without merit. As explained in the expert opinion report by Mr.

Hartenstein provided herein, soluble compounds would almost completely be removed by a

wet scrubber and the flue gas temperatures after gas reheat for either a TESCR or LDSCR

system would be higher than those expected for condensation of any trace sodium or

potassium compounds remaining. Therefore, the MRYS Unit 1 sampling presented does not

-3-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

demonstrate, to any degree, that a TESCRor LDSCR could not be successfully operated at

MRYS.8

Minn-Dak Farmer's Coop. Experience

As explained in detail in Mr. Hartenstein's expert opinion report, using the experience

at the Minn-Dak Farmer's Coop. facility to make the claim that TESCR and LDSCR is

technically infeasible at MRYS is unfounded. First, the pollution control at the Minn-Dak

facility is completely unlike that at MRYS. The Minn-Dak boilers are equipped with

multiclones and a venturi scrubber. The lack ofsimilarity ofMRYS to other facilities that

have successfully operated SCR has been used extensively elsewhere in the NDDH BACT

determination to support the claim of SCR technical infeasibility, yet this fact seems to be

unimportant to the NDDH in this instance. The NDDH BACT determination also makes no

attempt to relate the particulate matter emissions experienced at Minn-Dak to a theoretical

TESCR sodium loading rate and catalyst life at MRYS that would support the claim that the·

Minn-Dak situation is evidence that TESCR would not be technically feasible at MRYS.

This is likely because no such case could be made. Furthermore, as explained elsewhere

herein and in Hans Hartenstein's expert opinion report, stack temperature conditions (and

how those temperatures relate to the physical state of catalyst poison compounds) during a

particulate matter stack test (as would have been the case in the Minn-Dak situation) and the

operation of a TESCR after flue gas reheat are very different. Therefore, to use the NDDH's

experience with the Minn-Dak facility to support the conclusion that TESCR could not be

successfully operated at MRYS is completely speculative anq highly questionable.

SCR System and Catalyst Vendor Responses on TESCR

The NDDH BACT determination fails to adequately address the vendor responses

provided by Minnkota in the evaluation ofTESCR or LDSCR. This is likely because the

B&McD SCR system and catalyst vendor query appears to have been specifically directed at

only getting responses related to a HDSCR application and with no attempt made to get

information about vendor opinions or guarantees related to TESCR or LDSCR. .

As detailed in Mr. Hartenstein's expert opinion report, an additional query was made to

the same vendors that were contacted by B&McD to get information on technical feasibility,

the need for additional research, and guarantees related to TESCR.

8 Although not referenced in the NDDH BACT determination, Minnkota also submitted some sampling information

for Unit 2 that may have been taken downstream ofthe electrostatic precipitator and S02 scrubber (although the

bypass was operating during the sampling). As explained in Mr. Hartenstein's expert opinion report, this data

cannot be considered relevant for any reasonable judgment concerning the technical feasibility of a TESCR.

-4-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

The responses received from SCR system suppliers (Alstom and Babcock Power) and

catalyst vendors (Argillion, CERAM, and Haldor Topsoe) that have extensive experience

with TESCR demonstrate that TESCR is available and applicable to MRYS without the need

to do additional pilot testing. This information is very important, because these experts have

actual experience with these installations. While much ofthis experience is outside ofthe

United States, that should not influence the analysis oftechnical feasibility. Clearly, these

companies will make TESCR available to Minnkota and believe the physical and chemical

characteristics ofthe flue gas at MRYS in a TESCR environment poses no significant

differences that would preclude the successful operation at MRYS.

Conclusion on TESCR Technical Feasibility

Based on the evidence outlined above, in addition to the substantial explanation

provided in the expert opinion report of Mr. Hartenstein, a leading expert in SCR

installations at power plants, TESCR is a technically feasible control option at MRYS and

. needs to be evaluated to at least step 4 ofthe Top-Down BACT analysis.

Conclusion on LDSCR Technical Feasibility

Since no apparent attempt was made to query vendors related to LDSCR, this analysis

remains incomplete. While both Minnkota and the NDDH have made technical arguments as

to why LDSCR would be technically infeasible at MRYS due to catalyst plugging and

deactivation, these arguments are based on pure speculation and improper comparisons with

other situations that do not quantitatively provide any evidence that LDSCR could not be

successfully operated at MRYS. EPA believes LDSCR is very likely technically feasible.

II. .NDDH'S TECHNICAL FEASIBILITY ANALYSIS OF HIGH-DUST SCR IS

INCORRECT AND BASED UPON FLAWED DATA.

As more fully set forth below, the NDDH BACT determination's conclusion that

HDSCR is technically infeasible is not supported by the record and is based upon an

incorrect interpretation ofEPA's NSR Manual. NDDH's BACT determination provides

twelve reasons to support its decisionthat HDSCR is technically infeasible. These individual

points are examined in detail in Mr. Hartenstein's expert opinion report and will not be

expounded upon here in detail.

HDSCR Catalyst Plugging & Deactivation

• The catalyst plugging and deactivation problems cited in the NDDH's BACT

determination are largely based upon the Coyote Station pilot test conducted by

EERC, which was fundamentally flawed and would not be indicative of a full-scale

operation.

-5-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

• The NDDH BACT determination acknowledges the fundamental problems with

Coyote Station pilot test and states that it provided little useful data. However, the

pilot test is cited throughout the HDSCR technical feasibility analysis as a basis for

supporting the position that HDSCR is technically infeasible.9

• The comparison of different coal-type emission factors in the NDDH BACT

determination is used to support the conclusion that the differences in flue gas

characteristics ofsodium and total primary alkali constituents (CaO, Na20, MgO, and

K20) would "preclude the successful application of existing (presumably high-dust)

SCR technology to the M.R. Young Station."lO This conclusion is complete

speculation. While the NDDH BACT determination correctly points out that a linear

relationship does not exist between the loading rates of alkali constituents derived

from emission factors and catalyst deactivation, the NDDH BACT determination uses

this comparison to draw the conclusion that the flue gas characteristics at MRYS

would be sufficiently "different" than other fuel types where SCR has been

successfully applied. Again, there is no clear basis for this conclusion. The

comparison shows cyclone units firing North Dakota lignite to emit about six times as

much NaO and about twice as much primary alkali constituents as wall-fired or

tangentially-fired plants burning Wyoming Powder River Basin (PRB) subbituminous

coal. The NDDH BACT determination does not attempt to relate these ratios to

expected catalyst life;

• For the current coal analyses, the ratios of primary alkali loading for Center Mine

cyclone units compared to Texas Lignite cyclones, Texas Lignite pulverized units,

and PRB subbituminous pulverized units are 1.7,2.0, and 23 respectively. There is a

larger disparity between the same primary alkali constituents on units within other

fuel and boiler types that have successfully demonstrated SCR use. For example, the·

ratio of primary alkali constituent loading between pulverized coal units burning PRB

subbituminous coal versus eastern bituminous coal on a Ib/MMBtu basis would be

3.0. This difference is higher than the 2.3 ratio between a Center Mine cyclone unit

and the same pulverized unit burning PRB. Therefore, pased on the methodology and

'.J

9 For example, on pages 49-50, the NDDH BACT determination states, "[t]he pilot scale SCR plugged after only 2

months and little useful data was obtained.....Operation of an SCR system for only 2 months between catalyst

replacement is not considered successful operation of SCR technology." Based on this discussion, the NDDH is

strongly implying that a HDSCR at MRYS would need a catalyst replacement due to deactivation after only two

months, although it is widely known that information related to catalyst plugging on a pilot scale is not applicable to

full-sca:Ie installations and no activation data was obtained on the Coyote Station pilot test. The NDDH BACT

determination also states the Coyote Station pilot test was "ill-designed for a unit combusting North Dakota lignite"

(see page 7), which makes the use ofthis 2-month prediction of catalyst replacement based on pilot-scale plugging

results even more baffling.

10 See NDDH BACT determination, page 51.

-6-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

rationale presented in the NDDH BACT determination, HDSCR could not have been

successfully applied to pulverized coal units burning PRB subbituminous coal

because there was three times as much primary alkali constituent loading in the flue

gas compared to the eastern bituminous coal plants, where SCR had already been

successfully operated.

• Despite the considerable and varied experience that exists worldwide with applying

SCR on different source and fuel types, the NDDH BACT determination dismisses

the notion that HDSCR is technically feasible at MRYS as "speculation." However,

the NDDH believes a mathematical comparison showing elevated amounts ofsodium

and other alkali constituents in the flue gas with some unknown effect on catalyst life

in a HDSCR location is "evidence" that HDSCR is technically infeasible at MRYS.

• The responses from two ofthe three catalyst manufacturers (CERAM and Haldor

Topsoe) to the B&McD query related to HDSCR indicates that catalyst suppliers

would be willing to guarantee HDSCR performance ifthe temperature issue unique to

the units at MRYS was resolved by SCR system suppliers. The catalyst vendors

expressed concern about the flue gas constituents ofNorth Dakota lignite, but did not

indicate there was a fatal flaw to operating HDSCR based on the fuel type. The issue

ofsodium poisoning was specifically discussed by CERAM and was not a cause of

concern based on their past experience with high sodium applications. Haldor

Topsoe was also made aware ofthe sodium issue and was able to provide an industry-

.standard guarantee. The catalystsuppliers were able to estimate the catalyst life of a

HDSCR application at MRYS based on their previous experience.

• It is apparent that the catalyst suppliers that responded affirmatively to being able to

provide performance guarantees on a HDSCR ifthe temperature variation issue was

resolved (CERAM and Haldor Topsoe) were prompted by B&McD to issue

statements that pilot testing on North Dakota lignite would be required prior to such

guarantees. ll As noted in Mr. Hartenstein's expert opinion report, catalyst vendors

would always be in favor of doing HDSCR pilot testing for a new fuel type, as it

minimizes their risks at little or no cost to themselves.

• CERAM responded to B&McD's follow-up by stating that "we agree that there is

good cause for further testing on a lignite fired unit to further mitigate the risks and

optimize design." This statement is clearly a recommendation that acknowledges

testing would enhance the applicability oftheir catalyst in a HDSCR application to

North Dakota lignite, not a requirement in order to develop its availability. In its May

11,2007 response to the B&McD query, CERAM outlined detailed design ofthe

11 See April 28, 2008 emails from Robert Blakley (B&McD) to Noel Rasha (CERAM) and Flemming Hansen

(Haldor Topsoe).

-7-
EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

catalyst and guaranteed a catalyst life of 16,000 hours. Contrary to statements in the

NDDH BACT determination thata HDSCR could not be designed at MRYS due to

uncertainties in deactivation rates ofthe catalyst, a very experienced and reputable

catalyst vendor has expressed confidence that it could do so (ifthe temperature

variation issue is resolved) and provided such information.

• Haldor Topsoe responded to B&McD's follow-up by stating, "[w]e suggest that the

next step is a larger pilot scale experiment with in the order of 2x2m of catalyst

installed. We would like to participate in such an experiment. This would allow

better catalyst cleaning and give a better determination ofthe catalyst degradation

over time. Based on our current information, we expect 60% deactivation over the

first 10,000 operating hours. We can not provide a 'make good' guarantee',. but are

willing to warrant the catalyst performance up to the contract value." These

statements are clearly a recommendation that acknowledge testing would enhance the

applicability oftheir catalyst in a HDSCR application to North Dakota lignite, not a

requirement in order to develop its availability. In fact, contrary to statements in the

NDDH BACT determination that a HDSCR could not be designed at MRYS due to

uncertainties in deactivation rates ofthe catalyst, a very experienced and reputable

catalyst vendor has expressed confidence that it could do so, provided the temperature

variation issue is resolved. As explained in Mr. Hartenstein's expert opinion report,

the guarantee up to the contract value is a standard industry guarantee. Thus, the

statements by Haldor Topsoe do not support the notion that HDSCR would require

pilot testing in order for commercial availability, as outlined·in the NDDH BACT

determination.

• The export opinion report ofMr. Hartenstein clearly indicates that based on his

extensive knowledge and experience with SCR applications under widely different

flue gas conditions and discussions he had with catalyst vendors and SCR system

suppliers, catalyst and plugging and deactivation would not be a fatal flaw to

installing HDSCR at MRYS.

• As will be explained in more detail in a later section, the docket information for the

TXU Oak Grove New Source Review permit (a proposed project that will include

HDSCR and burn 100% Texas lignite) provides further evidence that, despite the

challenges that exist in applying HDSCR to a new fuel type, the utility industry

believes that SCR is technically feasible and any questions about the its application

are a matter of cost. This is evident not only in the permit docket, but also in a letter

from the Electric Power Research Institute that was originally sent to the NDDH in

EPA's January 8, 2007 letter. In addition, the Texas Commission on Environmental

Quality determined that the uncertainties involved with firing a new fuel type and the

accelerated HDSCR catalyst plugging and deactivation that was expected from

-8-
/

EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

exclusively firing Texas lignite was not a reason to find that SCR would be

technically infeasible. While the properties ofNorth Dakota and Texas lignite might

not be the same, the same basic principle applies that the accelerated catalyst

replacement requirements are a matter of economics and not technical feasibility.

Based on the information and observations above, EPA concludes that the successful

operation and technical feasibility ofHDSCR at MRYS would not be precluded by the

catalyst plugging and deactivation issues related to the cyclone-firing North Dakota lignite

described by Minnkota and in the NDDH BACT determination. Catalyst vendors believe the

challenges involved would be manageable and they would be able to design a suitable

catalyst with a performance guarantee. While the vendors would prefer to conduct some

testing to mitigate risks, optimize the design, and better predict catalyst life, these same

vendors also appear willing to make the catalyst commercially available. Therefore, HDSCR

should not be eliminated as being technically infeasible on the basis of catalyst plugging and

deactivation.

MRYS Temperature Variation Issue Related to HDSCR

• The SCR system supplier responses indicate that the temperature variation issue

would likely be very challenging for a HDSCR installation at MRYS (and more

unique than the potential catalyst plugging and deactivation issues for cyclone-firing

ofNorth Dakota lignite). Although the B&McD query was clearly directed toward a

response only on HDSCR, SCR system suppliers (Alstom and Backbock Power)

suggested looking at the possibility ofTESCR as a way of avoiding both the concerns

with temperature variations and fuel characteristics.

• The other SCR system supplier (Babcock & Wilcox, which does not have extensive

TESCR experience) certainly did not dismiss the possibility of being able to

overcome the challenges presented at MRYS for SCR installation and welcomed

working with Minnkota to explore "creative solutions."

• EPA received information in response to a Clean Air Act Section 114 request

pertaining to the vendor query conducted by B&McD. 12 This information is included

herein. Babcock & Wilcox (B&W), who was the original manufacturer ofthe boilers

at MRYS, indicates that modifications to the boiler likely could be made that would

address the temperature problems, or that out of boiler modifications/changes (e.g.

auxiliary fuel drying) would be necessary. In either case, the temperature issue

appears to a resolvable technical problem, albeit at a likely high cost.

12 See July 18,2007 e-mail from Steve Moormann (Babcock & Wilcox) to Robert Blakely (Bums & McDonnell).

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

EPA believes that the technical issue with the temperature variation inthe backpass

end ofthe boilers at MRYS where a HDSCR would be located presents a,significant

challenge. However, it appears that the technical challenges with the temperature variation

can be resolved. Furthermore, the issue of backpass boiler temperature variation completely

goes away in the case ofTESCR and LDSCR. Therefore, no matter what the implications

are ofresolving the temperature variation issue, there are other options for installing SCR

technology that would avoid this problem altogether.

EPA's Conclusion on HDSCR

In summary, EPA believes the NDDH BACT analysis incorrectly eliminates HDSCR

as technically infeasible at MRYS because pilot testing would be required on Center Mine

lignite fuel before application at MRYS. The uniqueness ofthe fuel at MRYS (Center Mine

lignite) does not appear to pose technical problems that catalyst vendors do not believe can

be managed in order to provide a reasonable guarantee. The soluble sodium deactivation

issue cited in the NDDH BACT determination as a fatal flaw to installing HDSCR is not

supported by any useful or relevant data and is speculative. Furthermore, the opinions of

catalyst suppliers and leading SCR expert Mr. Hartenstein indicate that catalyst poisoning by

sodium is only an issue during periods when, the catalyst is allowed to cool well below its

normal operating temperature. This would be an infrequent occurrence and can be managed

by isolating the catalyst during shut-downs. Additionally, catalyst regeneration is a viable

option (that is currently used in practice) for restoring catalyst life by either in-situ, on-site,

or off-site water washing. 13 The temperature variation problem appears to be a more

significant challenge for the successful operation ofHDSCR (but not TESCR or LDSCR),

but the necessary modifications to resolve this problem would be a matter of cost.

III.' THE NDDH BACT DETERMINATION INCORRECTLY APPLIES THE

CONCEPT OF PILOT TESTING IN EPA'S NsR MANUAL TO CONCLUDE

THAT SCR IS NOT TECHNICALLY FEASIBLE.

NDDH has misinterpreted EPA'sNSR Manual to support a finding oftechnical

infeasibility ofSCR at MRYS because it has been suggested pilot testing and/or engineering

research would be required. EPA has previously clarified for Minnkota and the NDDH that

this reference in E~A's NSR Manual is only relevant to whether a control option was.

13 On page 46, the NDDH BACT detennination states that there are "no known engineering solutions to ....restore

the catalytic reactions by removing particles from catalyst pores." This is simply not true and it appears that the

NDDH did not investigate this possibility in any depth. As one example of actual regeneration experience, EPA is

enclosing a 2007 NOx Round Table & Expo Presentation by Reinhold Environmental Ltd (February 5-6, 2007 in

Cincinnati, OH) that details in-situ and on-site catalyst washing experience at the Avedore Station in Denmark.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

"available." There is little question that SCR is "available" for installation at MRYS and, in

fact, the Minnkota BACT analysis already conceded that SCR is "available.,,14

The NDDH BACT determination relies upon the lack of demonstrated application of

SCR technology and mitigating tools used to manage ash deposition and catalyst deactivation

(such as screens, baffles, soot-blowing, rejuvenation, etc.) on a cyclone boiler firing North

Dakota lignite to conclude that it is necessary for the source to do additional pilot testing and

engineering studies. According to NDDH's interpretation ofEPA's NSR Manual, this

additional step precludes the technology from being considered technically feasible.

The NDDH BACT determination states that, "[t]he fundamental question for this

BACT determination is whether SCR is an available technology for North Dakota lignitefired cyclone boilers such as Minnkota Units 1 and 2.,,15 The concept of availability of a

control technology is introduced in the NDDH BACT determination by quoting EPA's NSR

Manual, which states, "[a] control technique is considered available, within the context

presented above, ifit has reached the licensing and commercial state of development. A

source would not be required to experience extended time delays or resource penalties to

allow research to be conducted on a newtechnique. Neither is it expected that an applicant

would be required experience extended trials to learn how to apply a technology on a totally

new and dissimilar source type. Consequently, technologies in the pilot scale testing stages

of development would not be considered available for BACT review.,,!6

The NDDH BACT determination concludes, "SCR has not reached this stage for North

Dakota lignite-fired cyclone boilers, and because ofthe difference in the gas stream!?, the

Department concludes that Minnkota need not experience extended trials to learn how to

apply the technology on such a dissimilar source type.,,18

With this statement, NDDH has erroneously combined two steps which are described in

EPA's NSR Manual as separate steps for determining technical feasibility of a control option,

14 See EPA's October 4, 2007 letter to NDDH and Minnkota, page 31 and Minnkota BACT analysis, page AI-32,

where B&McD states, "SCRtechnology is an available technology which has been installed on numerous

powerplant facilities around the world and there are a large number ofmanufacturers that market the technology.

The question is whether SCR technology is "applicable" fOf a unit firing North Dakota lignite." In its November 13,

2007, letter, Minnkota appears to have reversed course on the issue of SCR availability, and attempts to focus on the

dissimilar aspects of MRYS to other facilities that have installed SCR. Notwithstanding the statements in this letter,

however, there is no disputing that the Minnkota BACT analysis clearly stated that SCR is available and that the

only question is whether it is applicable.

15 See NDDH BACT Determination, page 5.

16 See EPA's NSR Manual, page 8018.

17 The concept of evaluating differences in the gas stream between the source under review and other sources where

a control option has been applied is introduced in EPA's NSR Manual during the discussion of whether an available

control option is also applicable.

18 See NDDH BACT Determination, page 6.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

namely, availability and applicability, A plain reading ofEPA's NSR Manual shows that

EPA saw the technical feasibility determination as two separate steps. First, the reviewing

authority should determine whether a control option is available. As stated in the EPA NSR

Manual, if a new control option is only in the early developmental stage, it is riot considered

(commercially) available. Therefore, under the Top-Down BACT analysis, the control

option is eliminated from consideration as being technically infeasible, without any analysis

on whether the control option is applicable to the source under review and does not require

the same degree oftechnical analysis and judgment on the part ofthe reviewing authority.

EPA's NSR Manual specifically mentions pilot testing as a component of determining

availability, which is defined as the "process commonly used for bringing a control

technology concept to reality as a commercial product.

• conceptstage;

• research and patenting;

• bench scale or laboratory testing;

• pilot scale testing; (emphasis added)

• licensing and commercial demonstration; and

• commercial sales." 19

For determining whether a control option is available, EPA's NSR Manual does not

describe the comparison of gas stream characteristics between the source under review and

other sources. Commercial availability of SCR is a plain fact, evidenced by the SCR system

supplier and catalyst vendor responses garnered by B&McD and supplemented by EPA

herein, the extensive applications of SCR to coal-fired power plants and other industrial

sources worldwide for decades, and eve.n as stated in the Minnkota BACT analysis. 20

The second step ofthe technical.feasibility analysis is to determine whether an

available control option is also applicable to the source under review. As noted correctly in

the NDDH BACT determination, the EPA's NSR Manual "provides that technical judgment

ofthe review authority must be exercised in detetmining whether a control alternative is

applicable to the source type under consideration,,21 (emphasis added) and cites a portion

EPA's NSR Manual regarding applicability, which states, "a commercially available control

option will be presumed to be applicable ifit has been or is soon to be deployed (e.g. is

19 See EPA's NSR Manual, page B.17.

20 EPA also strongly disagrees with the assertion in the NDDH BACT determination that a control option can be

eliminated under the Top-Down BACT process if any "engineering study" is required. This very vague and broad

term could be applied to any phase of designinga piece of pollution equipment or technique. Presumably, every

major piece of pollution control equipment (Le. scrubber, SCR, baghouse, Electrostatic Precipitator, etc.) applied to

a utility boiler has entailed engineering study. EPA categorically dismisses use ofthis term in NDDH's BACT

determination and believes that this extremely narrow view of what is required in the Top-Down BACT process is

particularly problematic.

21 See NDDH BACT Determination, page 5 and EPA's NSR Manual page 8.18.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

specified in a permit) on the same or similar source type. Absenta showing ofthis type,

technical feasibility would be based on examination ofthe physical and chemical

characteristics ofthe pollutant-bearing gas stream and comparison ofthe gas stream

characteristics ofthe source types to which the technology has been applied previously.,,22

(Emphasis added.) Hence, a comparison of gas stream characteristics would only be required

once it has already been established that the control option is available. Furthermore, the

question of whether pilot testing and conducting additional research is necessary no longer

applies to the analysis, since it is only relevant for a determination of availability, which

would have already been confirmed. Contrary to EPA's NSR Manual, the NDDH BACT

determination makes a determination of availability based, in part, on the comparison of gas

stream characteristics.

The NDDH BACT determination states, "all responses (to the B&McD vendor query)

indicated the following: l}The need for additional testing to either determine ifthere were

any fatal flaws or to obtain data for the design of a potentially successful SCR system.',23

Clearly, this is not the type of pilot testing that is referenced in the·EPA NSR Manual for

developing a new control technology from concept stage to the commercial state of

development. This type oftesting would instead provide more certainty to designers and

likely result in a more optimum SCR system design at MRYS, as it would to any application

of SCR to a new,plant. In other words, this type oftesting would be used to enhance the

applicability of SCR at MRYS. The responses from SCR system suppliers and catalyst

vendors are speaking to the advantages of doing additional testing on North Dakota lignite to

enhance the applicability of(HD)SCR at MRYS, not on whetherSCR is a commercially

available control technology. For example, when prompted by B&McD on the prospect of

doing pilot testing, CERAM stated, "we would agree that there is good cause for further

testing on a lignite fired unit tofurther mitigate the risks and optimize design.,,24 (Emphasis

added.) .

Since SCR has been so widely applied to coal-fired boilers and other industrial sources,

commercial availability of SCR should be determined primarily based on whether the SCR

system suppliers and catalyst suppliers ·are willing to commercially provide and install the

technology on the source in question, not based on whether the reviewing authority believes

additional testing would provide more certainty and lead to a better designed SCR. It is clear

from the record that vendors are willing to do so. Many ofthe vendors responses from the

B&McD query clearly indicate that they believe SCR can work at MRYS2 and do not

22 See EPA's NSRManual, page 8.18.

23 See NDDH BACT Determination, pages 39-40.

24 See May 6, 2008 email from Ceram Environmental, Inc. to B&McD.

25 See May 30, 2007 and May 5, 2008 letters from Alstom Power to B&McD; see May 11,2007 and May 6, 2008

emails from Babcock Power Environmental, Inc. to B&McD; see May 11,2007 and May 6, 2008 emails from

Ceram Environmental, Inc. to B&McD; see May 10,2007 and May 5, 2008 emaiisfromHaldorTopsoe.Inc.to

B&McD. Note that these responses have been greatly supplemented by the vendor responses related to TESCR

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

require that pilot testing be conducted upfront to make the technology commercially

available. .

Lastly, the NDDH BACT Determination for LDSCR and TESCR at MRYS also

concludes, "catalyst deactivation of a low-dust or tail gas SCR due to alkali compounds is an

issue that will require extensive research, design and pilot testing to determine whether the

technology can be successfully applied to units fired on North Dakota lignite. Therefore,

these technologies are not considered applicable and not technically feasible at this time.,,26

Again; this rationale is a misinterpretation ofthe EPA NSR Manual. The question of

whether LDSCR and TESCR are in the pilot testing stage of development is only relevant in

terms of whether it is an available control option. Both LDSCR and TESCR are not only

available control options, but would also be applicable to MYRS. In fact, the responses from

the supplemental SCR system catalyst vendor query conducted by Mr. Hartenstein, and

provided in the Enclosure herein, clearly indicates that vendors would provide a TESCR at

MRYS with a guarantee and do not support doing any additional pilot testing.

IV. THE NDDH BACT DETERMINATION FRUSTRATES THE TECHNOLOGYFORCING FUNCTION OF THE BACT PROCESS THAT WAS INTENDED BY

CONGRESS.

The NDDH BACT determination is not only atodds with EPA's NSR Manual, but it

also frustrates the technology-forcing function ofthe BACT process. As described above,

the NDDH BACT determination repeatedly notes a lack of actual experience with SCR on

North Dakota lignite and cyclone boilers as a primary basis for concluding that

"experimentation" and/or "extensive, and correspondingly expensive, engineering studies"

would be necessary to determine ifUncertainties could be overcome. Congress developed the

case-by-case BACT process so that the best technology becomes as widespread as possible.

The NDDH BACT determination takes the position that a control option is technically

infeasible because no other power plant with the exact same design and fuel source has

applied the control option. Under this presumption, the best technology would not become

widely used, unless some independent "proof' ofit working on the exact type ofsource and

flue gas characteristics under review was provided. This application ofthe BACT process is

contrary to the technology-forcing function ofthe BACT process that congress intended

when enacting Clean Air Act.

gathered by Mr. Hartenstein. .

26 See NDDH BACT Determination, page 57.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

v. OTHER COMMENTS ON THE NDDH BACT DETERMINATION

1. Page 4 ofNDDH BACT Determination: "Information from Sargent and Lundy

indicates that not enough information is available to determine whether SCR

technology can be successfully adapted to units burning North Dakota lignite."

EPA Response: This is not what Sargent & Lundy actually said in the May 2007

presentation to NDDH and EPA. In Sargent and Lundy's Conclusion Summary, they

state, "[slome important unanswered questions pose significant risks for an SCR

design engineer:

An unknown catalyst deactivation rate will prevent:

• optimum selection of a catalyst design

• selection of an appropriate reactor size

This could burden the operator with a long term costly maintenance requirements

(sic) and unscheduled outages"

Sargent & Lundy states that premature catalyst failure will require more frequent

catalyst replacement, ammonia slip and subsequent airheater pluggage, and higher

auxiliary power requirements. These conclusions suggest that Sargent & Lundy's

opinion is that the lack of data specific to North Dakota lignite on SCR operation

would result in a less than optimal design and as a result increased capital and

operating costs. While this opinion indicates that applying SCR to North Dakota

lignite without obtaining further data might not be the best engineering approach,

Sargent & Lundy did not opine that SCR could not be "successful" on units firing

North Dakota lignite.

2. Page 70ftheNDDH BACT determination: "The advances made in the last few years

for controlling popcorn ash are not shown to· be applicable to a cyclone boiler burning

North Dakota lignite. Extensive engineering analyses, and likely pilot scale testing,

will be necessary to determine ifthese advances can be applied at M.R. Young

Station."

EPA Response: This statement and conclusion is inconsistent with the discussions

between NDDH, EPA, and Minnkota at the May 23,2007 meeting held in Bismarck.

During this meeting popcorn ash was discussed and EPA's consultant, Roger

Christman, stated that he believed the popcorn ash problem had been dealt with

successfully at many other facilities and that it would not pose a significant problem

at MRYS. Mr. Christman asked Minnkota and B&McD whether they agreed that the

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EPA Comments on NDDfI Preliminary

NOx BACT Determination for MRYS

effects of popcorn ash is solvable at MRYS and whether it could be "taken offthe

table" as a real issue in the discussion ofHSSCR technical feasibility. Minnkota

agreed that it was a solvable issue and certainly did not indicate that pilot testing

would be required to address the effects of popcorn ash at MRYS. In light ofthese

discussions, it is unclear why NDDH still believes that this is a technical barrier for

the successful operation ofHDSCR at MRYS.

3. Pages 13-15 ofthe NDDH BACT determination: In identifying all control

technologies under Step 1 ofthe Top-Down BACT analysis, the NDDH BACT

determination lists, "Fuel Switching/Blending/Cleaning." In the Step 2 analysis for

this control option, the NDDH BACT determination cites experience at the Big Stone

Power Plant in South Dakota with switching to PRB fuel as not lowering NOx

emissions and then references a Seventh Circuit Appeals Court decision regarding the

Prairie State Generating Station PSD permit that stated fuel switching is not required

for mine mouth power plants in the BACT analysis. Therefore, the NDDH BACT

determination concludes that switching or blending fuels other than Center Mine

lignite in order to mitigate the effects ofthe fuel on other control options would not

be required.

EPA Response: While the NDDH BACT determination appears· to have looked at

fuel switching and blending, it ignores the possibility offuel cleaning in Step 2,

although fuel cleaning was correctly listed under Step 1. Many ofthe technical

problems described in the NDDH BACT determination for installation of other

control options, such as SCR, are due to downstream conditions caused by the poor

quality ofthe Center Mine lignite fuel (i.e. high ash, high sodhun, high moisture, low

heating content, the need to do fuel predrying in the cyclone boiler, etc.). Therefore,

it appears that NDDH should explore potential fuel cleaning possibilities to address

these effects. While EPA does not agree that fuel cleaning would be required in order

for SCR to be considered technically feasible, the conclusions ofthe NDDH BACT

determination are further flawed and incomplete without such an analysis.

4. Page 29 ofthe NDDH BACT determination: "Consumers Energy indicated they

purchase coal from several western mines as well as eastern mines. They also·

indicated that none ofthe coal obtained from the Spring Creek Mine is fed to a unit

equipped with an SCR system. Based on this information the Department is not

aware of any power plant that is equipped with an SCR system and bums Spring

Creek Mine coal."

EPA Response: There is a reference to a May 13, 2008 email froin Bradely Plummer

ofConsumers Energy to Tom Bachman ofNDDH. This email was not made part of

the administrative record, but appears to be information that the NDDH relied upon in

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

making its BACT determination. This email should be made publically available and

part ofthe administrative record for this BACT determination. .

5. EPA would like to add the documents identified in Sections VI through VIII, below,

to the administrative record for the NDDH to consider in its Final BACT

determination.

VI. DOCKET INFORMATION FOR THE TXU OAK GROVE NSR PERMITIS

EVIDENCE THAT THE UTILITY INDUSTRY & OTHER STATE AGENCIES

BELIEVE THAT SCR IS TECHNICALLY FEASIBLE & CAN BE APPLIED

TO NEW FUEL TYPES & BOILER TYPES.

On July 27,2005, Oak Grove Management Company, LLC (Oak Grove) applied to the

Texas Commission on Environmental Quality (TCEQ) for a Prevention of Significant

Deterioration (PSD) permit to construct a new 1,600 MW (net) pulverized coal power plant

consisting oftwo 860 MW (gross) units. The proposed facility would be fired on 100%

Texas lignite. On February 21, 2006, the TCEQ Executive Director issued a preliminary

decision and draft permit that required HDSCR and a limit of 0.08 lb/MMBtu as BACT for

NOx . At Oak Grove's request, the application and determination was referred to the State

Office of Administrative Hearings (SOAH) for hearing on whether it complied with all

applicable statutory and regulatory requirements.

On August 23, 2006, the SOAR Administrative Law Judges (ALJs) issued a Proposal

for Decision (PFD) with a finding that Oak Grove failed "prove by a preponderance ofthe

evidence that its BACT proposal to use SCR with lignite-fired boilers can reasonably be

expected to achieve a 0.08lb1MMBtu NOx emission rate.',27 Essentially, the ALJs found

that since HDSCR has not been previously proven in practice on a plant burning 100% Texas

lignite, there were uncertainties with the application of, "a relatively new technology that has

never been used in the United States on a commercial scale with a lignite-fired electric power

plant.',28

While Oak Grove took the position that there were uncertainties and challenges with

the design of an SCR reactor for lignite coal firing, the company argued that SCR is

technically feasible and that, "the PFD failed to make the distinction between 'technical

practicability' and 'economic reasonableness' .',29 Oak Grove takes the position that, "[t]o the

extent that there is any issue or question regarding the use SCR (sic) at the proposed facility,

it is a question of cost.',30 Oak Grove's reason for pointing out the uncertainties with

27 See AU's Proposal for Decision and Order, August 23,2006, page 24.

28 See AU's Proposal for Decision and Order, August 23,2006, page 24.

29 See Applicant's Exception to the Proposal for Decision, September 12,2006 page 10.

30 See Applicant's Exception to the Proposal for Decision, September 12,2006, page 10.

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· EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

applying SCR to a fuel type that has never been demonstrated in practice was an attempt to

have the NOx limit raised in the final permit, not to show that SCR should be considered

technically infeasible.

Additionally, Babcock Power Environmental, as the Air Quality Control System

supplier for Oak Grove, sent a letter to the TCEQ's Executive Director (August 30,2006)

outlining why it believes the ALl's PFD is incorrect and SCR is technically feasible for the

Oak Grove plant. Interestingly, Babcock Power cites the EERC Coyote Station pilot testing

results and dismisses those problems based on moisture problems introduced by the

sootblowers that caused much ofthe plugging during that test.

The TCED permit engineer for the Oak Grove permit, Randy Hamilton; also believed

that HDSCR should not only be considered technically feasible, but Mr. Hamilton also

recommended a lower NOx limit of 0.07 IblMMBtu to the TCEQ Environmental Director.

Although the ALJs appear to have misconstrued a statement made by Mr. Hamilton in his

written deposition to SOAH, where Mr. Hamilton describes the hypothetical best and worst

case possibilities ofSCR ash deposition on the Oak Grove units,31 Mr. Hamilton confirmed

with EPA that it was never his professional opinion that the worst case scenario he described

was a real possibility, but only a rhetorical examination oftwo logically possible outcomes.32

Ultimately, the TCEQ's Final Order (June 21,2007) rejected the arguments over

technical infeasibility of SCR at Oak Grove, overturned the ALJ'sPFD, and granted the PSD

permit to Oak Grove with a NOx BACT determination of SCR and a limit of 0.08 IbIMMBtu.

In short, the Commission found that the ALJs "placed too much emphasis on the absence of

previous applications ofthe proposed technologies with regard to Texas lignite.,,33

The positions taken by the TCEQ (technical staff, Executive Director, and Final Order),

Oak Grove, and Babcock Power largely coincide-with and support EPA's position with

regard to general technical feasibility of SCR on different fuel types and whether questions of

feasibility are a matter oftechnical feasibility or economic feasibility. EPA also generally

agrees with these parties that the position taken by the ALls (and likewise by Minnkota and

the NDDH in the case ofMRYS), "will remove an essential element ofthe air emissions

permitting process as contemplated by both state and federal Clean Air Acts - the

advancement of air pollution control process.....Simply stated, the ALl's interpretation ofthe

31 See ALJ's Proposal for Decision and Order, August 23,2006, page 15, "[t]he uncertainty with regard to ash

deposition is not mathematically convertible to a NOx emission limit adjustment. The ideal outcome would be that

plugging proyes to be no problem at all. Under this scenario, NOx emissions could be as low as any coal-fIred

boiler and the BACT emission limit could have been lower. The worst outcome would be that the SCR plugs with

flyash rapidly and completely and no engineering solution can be found. Under this scenario, SCR would be

technically infeasible, and BACT would have to be higher, based on the next most effective technology... "

32 See April 16,2008 email from Randy Hamilton (TCEQ) to Hans Buenning (EPA Region 8).

33 See TCEQ Final Order, June 21,2007, page 45.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

technical practicability element ofthe BACT analysis would categorically prevent the first-

. time application of new control technologies in Texas.,,34 The same could be said ofthe state

ofNorth Dakota under the positions taken in the NDDH BACT determination.

EPA is submitting the TCEQ/SOAH Docket information for the Oak Grove permit

proceeding to be entered in the administrative record and considered in NDDH's Final

BACT determination (see Enclosure 3). While EPA understands that there are differences

between Texas and North Dakota lignites, as well as the boiler configurations at Oak Grove

and MRYS that make the technical application of SCR different, the principles illustrated in

the Oak Grove permit proceeding related to the BACT process largely parallel those in the

Minnkota NOx BACT determination. EPA is also submitting additional information relative

to the Oak Grove permit proceeding that is not contained in the docket (also part of

Enclosure 3). The docket can be accessed electronically at: .

http://www7.tceq.state.tx.us/uploads/eagendas/Agendas/2007/6-13-2007/Oak%20Grove.pdf

VII. B&McD 114 RESPONSE DOCUMENTS

On June 20, 2008, EPA issued a Clean Air Act, Section 114 request for information to

B&McD asking for information related to the SCR system and catalyst vendor query that was

conducted by B&McD on behalf ofMinnkota. EPA received B&McD's response on July 3,

2008. EPA is submitting portions ofthe response herein as part ofEnclosure 3 for the state

to include in the administrative record and consider in NDDH's Final BACT determination.

To summarize some significant findings, the B&McD response indicates:

• Early draft versions ofthe vendor query document prepared by B&McD asked

for vendor opinions ofthe temperature variation issue for HDSCRat MRYS

and possible boiler modifications that could address thisproblem. At

Minnkota's direction, this request was removed from the final query document.

• Based on B&McD's call notes following up with the vendors that gave more

optimistic responses in early 2007 (those that were less optimistic were deemed

by Minnkota as not needing follow-up), it is clear that catalyst vendors were not

swayed by ~he arguments set forth by B&McD and EERC related to the

potential severity ofsodium catalyst poisoning. Also, SCRsystem suppliers

told B&McD that they believe tail-gas SCR would resolve the problems being

advanced by B&McDand EERC related to lignite fuel firing. Why B&McD

did not pursue the tail-gas option with vendors after it had been suggested is

unclear.

34 See Applicant's Exception to the Proposal for Decision, September 12, 2006, page 8.

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EPA Comments on NDDH Preliminary

NOx BACT Determination for MRYS

• In two separate documents (comments on a draft response to EPA comments

dated February 6, 2007 and an email correspondence dated May 10,2007),.

Robert Johnson (who was working as a consultant, but it is believed previously

worked for Argillion and then B&McD) opined on many ofthe technical issues

for an SCR at MRYS. The positions taken by Mr. Johnson largely support

positions taken by EPA, namely that there is no useful underlying data that

supports the claims ofEERC regarding the severity ofsodium catalyst

poisoning (in HDSCR, LDSCR, or TESCR), the Coyote Station pilot testing

"was a flawed test and the results should not be used to draw any conclusions

other than that a full scale system design needs to be done very carefully",

sodium is not much of a concern as a catalyst poison at SCR operating

temperatures, and that TESCR is a likely candidate for MRYS.

• It appears Minnkota has conducted a cost analysis of SCR at MRYS using

different expected catalyst life spans of 12,000 and 24,000 hours. This

information has not been made publically available to EPA's knowledge.

VIII. DOCKET INFORMATION FOR THE CLEAN AIR INTERSTATE RULE

(CAIR), BEST AVAILABLE RETROFIT TECHNOLOGY (BART)

GUIDELINES, AND NEW SOURCE PERFORMANCE STANDARDS jNsPS)

STATES THAT EPA DETERMINED THAT SCR IS TECHNICALLY

FEASIBLE FOR LIGNITE FIRED UTILITY BOILERS.

In a January 8, 2007 letter (sent via fax), EPA provided the NDDH with docket

information and references related to various rulemakings (CAIR, BART Guidelines, NSPS),

where EPA determined SCR to be feasible at lignite-fired utility boilers. This information

does not appear to be completely in the administrative record for the NDDH BACT

determination, so EPA is providing information related to these rulemakings herein as part of

Enclosure 3 for the NDDH to include in the administrative record and consider in NDDH's

Final BACT determination. As mentioned in the January 8, 2007 letter, through these three

rulemakings, EPA determined SCR to be technically feasible and rejected commenter's

concerns that SCR would not be technically feasible for lignite units, including those fired on

North Dakota lignite. EPA reiterates that the position now being taken in the NDDH BACT

determination is contrary to that established by EPA in these three national rulemakings.

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ENCLOSURE 3

ADDITIONAL DOCUMENTATION FOR

ADMINISTRATIVE RECORD