## Comments and Responses to NDDH Regarding U.S. EPA Region 8’s July 31, 2008 Comments and Plains Justice July 30, 2008 Comments on NDDH Preliminary NOx BACT Determination for Milton R. Young Station (MRYS) September 22, 2008

Burns & McDonnell (B&McD), and their SCR consultant, Tackticks LLC, along with the Energy & Environmental Research Center (EERC) of the University of North Dakota, have

reviewed the EPA’s comments (U.S. EPA, 2008), those of the Department of Justice’s commenter, Hans Hartenstein (Hartenstein, 2008), and Plains Ju stice (Plains Ju stice, 2008). These are responses regarding selective catal ytic reduction (SCR) t echnology feasibility and non-SCR concerns pertaining to the NDDH’s Preliminary NO X BACT Determination for Nitrogen Oxides for Milton R. Young Station Units 1 and 2, dated June 2008 (NDDH, 2008).

We continue to believe that the administrati ve record fully supports a finding by the North Dakota Department of Health (“NDDH”) that separa ted over-fire air (SOFA) in conjunction with selective non-catalytic reducti on (SNCR) technology is Best Av ailable Control Technology for electric generating units that utilize cyclone bur ners firing North Dakota lignite. The following sections address specific topics mentioned in the EPA’s comments and other issues in greater

detail.

• General Regulatory Considerations

• Corrections, Clarification and Omissions of Hartenstein and EPA’s comments

• SCR Technology Review and Update

• Variability of Lignite

• Results of Coyote Pilot Testing

• Soluble Sodium

• Differences in Flue Gas Composition

• Catalyst Poisoning, Blinding, and Plugging

• Applicability of SCR Development for Texas Lignite

• SCR Catalyst Erosion

• Pilot Testing for SCR CatalystResponses to Comments 2 September 22, 2008 • Vendor Guarantees for TESCR

• Temperature Variations for HDSCR

• Burns & McDonnell’s SCR Experience

• Comments by Sargent and Lundy on SCR Experience

• Comments on Hans Hartenstein’s Qua lifications for SCR Expert Opinions

• Fuel Switching

• Non-SCR Controls

• Conclusions



## General Regulatory Considerations In determining BACT, the limits placed on MRYS will be required for the plant’s lifetime. In order for the units to run, emission rates will n eed to be met. Any emissions limit exceedance

can result in a violation subject to significant financial pena lties, injunctive relief and possible unforeseen equipment changes or plant outages. Many of the boilers referenced in EPA’s report are not subject to New Source Review but some ot her form of regulation such as the NOx State Implementation Plan (SIP) Call program. There is a significant difference in NOx SIP and NSR. The NOx SIP Call is a seasonal (May to October) cap and trade program. Under this program, a utility’s NOx emissions are capped to a level belo w historic emissions. The utility has the option to apply pollution controls and/or buy offsets fr om other utilities. Under the NOx SIP program, a problem with the pollution cont rol equipment can be overcome by buying allowances while continuing to operate their units. NSR require s the controls be operating continuously and properly during plant operation.

1. EPA is deviating from a case-by-case BACT analysis by casting a wide net over SCR and insisting that it will work on all fuels and boile r types. Based on their comments, and those of DOJ’s expert, in essence, “any problem can be overcome, SCR has been used successfully everywhere and no long term problems exist”. Ho wever, as detailed later, our experts have found many instances where SCR was not used as a reduction strategy, or was unsuccessful.Responses to Comments 3 September 22, 2008 In Minnkota’s case, the combustion process fr om cyclone boilers and the North Dakota lignite makes application of SCR infeasible . Our specific combustion issue revolves around the size and type of combustion products produ ced in a cyclone-fired boiler when firing a high-sodium-containing lignite . The cyclone combustion process occurs at higher temperatures and different air distributions than other boiler t ypes. Cyclone firing combustion products are partitioned between the slag that flows out of the bottom of the furnace and the flue gas containing impurities. Th e flue gas impurities are enriched in alkali (sodium and potassium) species relative to ot her boiler types. Thes e species are known to blind and poison the SCR catalyst. The impur ities of concern are vaporized during the cyclone combustion process to form a gas a nd upon gas cooling these gas phase impurities will condense to form aerosols or small partic les that will deposit on the surface and in the pores of SCR catalysts. Once deposited, these al kali-rich materials will react with other gas phase species and deposited par ticles causing blinding or can r eact with active sites in the catalyst causing poisoning. This is well doc umented by Tackticks (see Appendix A) as well as by the DOJ’s expert (Harte nstein). In a TESCR system, the flue gas passes through a precipitator and scrubber prior to reaching the SCR system. Large particles can be removed from the precipitator and scr ubber. However, the removal of aerosols and small particulate (less than 2 microns in diameter) is depende nt on the aerosol and sm all particle size and composition. Sodium, potassium and alkali aerosols are not easily removed from the precipitator and scrubber and no vendors w ill guarantee removal rates. In a TESCR application for a high-sodium lignite fired cyclone, the TESCR catalyst is likely to be exposed to appreciable concentrations of sodi um, potassium and alkali concentrations. The second part of this case-by-case BACT evaluate s the fuel used. North Dakota lignite is known to have a much higher levels of catal yst poisoning constituents than other lignite types. The lethal combination of the high te mperature cyclone firing combustion process and high levels of catalyst poisoning constituents present in the lignite make this specific application technically infeasible.

2. Some catalyst vendors have “guaranteed cata lyst operation” for the Minnkota units, according to DOJ’s expert. EPA has taken a “guarantee” as a demonstration that the SCR application for North Dakota lignite is commercial. From the discussion above, EPA would lead us toResponses to Comments 4 September 22, 2008 believe that the high sodium levels and the cyclone combustion processes resulting in an abundance of SCR blinding and poisoning alkali sp ecies in the flue gas are inconsequential since a vendor will provide equipment to Minnkota. However, Minnkota has to evaluate a guarantee on the long term vi ability of meeting an emissions limit, including catalyst maintenance and replacement requirements, a nd therefore we must question the vendor on

numerous issues.

• Does the vendor look at the long term co mpliance obligations that Minnkota will be subject to? The vendor guarantees and contractua l language will vary from project to project. For example, a vendor could guara ntee a one time performa nce of their product and meet their obligation. However, the e nd user is stuck with a product that does not provide long term compliance. Some ve ndor language may guarantee a product for a longer period but assumes that certain ope rational conditions are met during that time period. If the operating conditions deviate, the vendor is no longe r responsible. It is not unusual for vendors to guarantee performance then have to settle claims or change offer. Yet, Minnkota will still need to meet emission limits for the plant’s lifetime.

• The only test data (Coyote) for a cyclone boiler burning North Dakota lignite resulted in significant catalyst blinding a nd plugging in a short time period. How

does a vendor resolve this issue? Burns & McDonnell and EERC contacted Haldor Topsoe (HT) about this issue (B&McD and EER C, 2007). HT participated in the Coyote test that showed catalyst b linding and plugging was so severe that they could not make catalyst reactivity measurements. HT suggested that they would increase the pitch of the catalyst but had no solution for severe blinding and plugging of the catalyst pore

structure. HT indicated that there were no ca talyst designs available that would alleviate the severe blinding and plugging of the pore st ructure due to the hi gh levels of sodiumrich aerosols present in flue derived from the cyclone-fired combus tion of ND lignite.

3. EPA has claimed the Coyote pilot-scale SCR test to be completely invalid and no conclusions can be made. The Coyote test was develope d by a consortium of Cormetech (catalyst vendor), Haldor Topsoe (catalyst vendor), H itachi (SCR system provider), EPRI (researchResponses to Comments 5 September 22, 2008 agency), US. DOE, Alliant Energy, Otter Ta il Power, Ameren, Dynegy, and Lignite Energy Council. This pilot test was in tended to evaluate the fouling pot ential of SCR on lignite coal. DOJ’s expert claims the test was fatally flawe d, yet the participants in the test included vendors that design and install SCR systems as well as end-user utilities that have applied SCR on their boilers. This team was competent and, like many pilot tests, it is meant as a learning opportunity. Certainly, further testing may change some of the testing parameters, but the intent was to evaluate the system. Mi nnkota believes this te sting was valid for its intended purpose and from this sole test, it was determined that there are significant impediments to using SCR on MRYS. The te st results showed catalyst blinding and plugging due to sodium and potassium rich specie s. Peer reviewed literature written by many authors have verified that sodium and pot assium species are fatal to the catalyst life.



## Corrections, Clarifications and Omissions of Hartenstein and EPA Comments The EPA’s SCR technology comments (U.S. EPA. 2008) rely heavily on their interpretation of information mostly repeated from earlier comm ents to Minnkota and opinions expressed by the Department of Justice’s (DOJ) commenter (Hartenstein, 2008), Many of these comments need

to be clarified for the record.

1. Hartenstein implies that lignite-fired boile rs are significantly represented among the 30,000 MW of SCR systems installed in Europe. This is misleading and subs tantially incorrect. Very few of the many SCRs retrofit in Europe we re installed on lignite-fired utility boilers.

Tackticks has advised that to the best of their knowledge, they are aware of SCR being originally installed at only tw o plants, and neither of thes e plants is operational today.

2. The EPA argues that NDDH’s preliminary BACT Determination does not properly compare

the emissions from other coal-fired boilers with high fuel sodium content to other boilers that successfully operate SCRs firing Powder River Basin (PRB) coal with high dust SCRs in the United States and are comparable to the Young Station boilers for their flyash alkali contents. The EPA ignored the Department’s supporting de tailed information by EERC that explainsResponses to Comments 6 September 22, 2008 why SCRs are not able to tolera te the higher levels of alkali species contained in flue gas

such as exhausted from the MRYS boilers as compared to the PRB coal fired boilers..

3. In addition, the EPA and Hartenstein did not pr ovide any substantial technical information

that demonstrates that effective solutions to prevent or remove pore pluggage and blinding of SCR catalyst from sodium- and potassium-rich species present in the flue gas stream exhausted from a North Dakota lignite-fired cyclone boiler, whether installed in a

conventional hot-side or cold-s ide application downstream of a wet scrubber, have been developed by catalyst vendors.

4. Hartenstein did not demonstrate he had an unders tanding of Center lignite characteristics and variability issues. Specifically, he did not unde rstand how soluble sodium is used to define the abundance of organically associated sodium in lignite and how sodium will vary because of the abundance of other ash forming compone nts in the coal. The abundance of sodium and other ash forming components vary dramat ically and uniquely in North Dakota (Fort Union region) lignite coal and result in ope rational challenges. Hartenstein does not

understand the differences between Fort Union lignite and Texas lignite. He indicates that

the installations of SCR on Powder River Ba sin (PRB) subbituminous coal and testing on Texas lignite indicate feasibility for SCR on ND lignite even though the levels of sodium in typical PRB coal and Texas lign ites are very low (0.7 to 1.5% Na 2 O) as compared to 4.4 %

Na 2 O for Center lignite. The amount and form of alkali species in the coal along with combustion processes influence their ability to be enriched in the aerosol and fine particle fraction of the fly ash. The size and compositi on of the particle along with gas velocity determines their ability to penetrate and de posit on SCR catalyst passages and in pores and cause plugging, blinding, and poisoning.

5. Hartenstein did not address the issue of the pa rtitioning of ash-forming species between the slag and fly ash components in cyclone-fired sy stems that result in an enrichment of sodium and other flame-volatilized species in the flue gas. These flame-volatilized species will condense homogeneously to produce abundant so dium and potassium-rich aerosols becauseResponses to Comments 7 September 22, 2008 of the lower level of entraine d solid ash particles in cyclone combustion-derived flue gases relative to pulverized coal combustion derived flue gas.

6. Hartenstein did not address the formation of aerosols and how that can impact SCR performance. The key issue for high sodium Fo rt Union (North Dakota lignite) coals fired in cyclone-fired boilers is the abunda nce of alkali-rich aerosols in th e flue gas that can penetrate into the pores of SCR catalyst, causing blinding and poisoning. This is an issue for high dust and low dust / tail-end SCR applications. He appears to not be familiar with the diffusion mechanism of transport of aeros ols deep into the SCR catalysts that can cause poisoning and plugging. Hartenstein appears to confuse the im portance of catalyst pi tch relative to pore plugging and blinding. He incorrectly suggests that catalyst pitch will solve the pore plugging and blinding problem. Using wider pitch catalyst does not eliminate the penetration of alkali-rich aerosols deep into SCR catalys t causing pore plugging and blinding problems. The impact of such aerosols that pass thr ough the electrostatic prec ipitator (ESP) on the performance of low dust SCR applications was no t discussed by Hartenstein. This fine ash that escapes from the ESP is finer than th e bulk flyash and has a higher catalyst plugging potential due to a higher tendenc y to agglomerate. In additio n, Hartenstein did not consider information provided on Powerspan barrier discha rge reactor pilot slipstream testing that

showed alkali rich accumulations downstream of the Unit 1 ESP at the MRY station.

7. Hartenstein’s knowledge of gas- solid reaction mechanisms to form sulfate and pyrosulfate phase in situ in SCR catalysts appears to be very limited and was not adequately addressed.

8. Hartenstein did not discuss th e recent literature on catalys t poisoning studies in Europe associated with cofiring high al kali (Na and K) containing bioma ss. This testing has showed significant poisoning of catalysts due to alkali aerosol penetration into catalysts and the subsequent reaction with catalyst active components causing poisoning.

9. Hartenstein did not offer information that mo re than 20,000 MW of li gnite fired units in Germany were not required to in stall SCR in order to comply with the national regulation, or that even new lignite-fired units being insta lled today in Germany are not equipped with SCRResponses to Comments 8 September 22, 2008 of any type. He did not stat e that Germany had only one cy clone-fired boile r operating with a LDSCR (Walsum Unit 7), or that the unit bu rns bituminous coal; nor did he advise that Voitsberg Unit 3, a boiler in Austria firing ligni te coal, only ran for a short time with a highdust SCR and was subsequently shutdown and demolished. He states that TESCR technology was “generally adopte d as a universally applicable SCR solution for all types...”

but failed to mention that there has never b een another TESCR built after Siersdorf, (which was finished in early 1991 and has subsequent ly been decommissioned), in the United States or Europe. To the best of our knowledge, there is no TESCR anywhere in the world on a lignite-fired utility boiler. He cites “Ceram’s extensive experience with lignite..”, but fails to report that this consists of only one plant with Ceram catalyst havi ng operated for a short period of time on lignite and a few pilot programs, so that it is dubious to say that this vendor has extensive experience on lignite fired boi ler SCR plants (see Appendix A). There are numerous other instances of missing or factua lly incorrect information attributed to Mr. Hartenstein discussed in Appendix A.

10. Again, the EPA fails to recognize conclusively th at ash chemical and physical properties of the Texas lignite (Wilcox formation) that T XU proposes to burn at the new Oak Grove powerplant where SCR is being installed (but has not yet be gun operation) do not represent what is fired in North Dakota, and therefore technical feasibility and expected performance in a Texas lignite-fired pulverized coal boiler SCR application is not transferable to North Dakota lignite-fired cyclone burner units due to the significant differences in flue gas and ash chemical and physical properties. The compositi on of the Texas lignite fired at Martin Lake, where SCR mini-SCR pilot testing has been co nducted, is typical of the composition of lignite fired at Sandow, with sodium oxide levels in the Texas lignite ash equal to 0.7%. The levels of sodium oxide in Center lignite aver age 4.4% and can be as high as 13% in as-fired samples. Hartenstein (2008) does not provide information on chemical composition of any fuels that are comparable to high sodium ND lignite where SCR installation have been

installed and tested or successfully operated.Responses to Comments 9 September 22, 2008 11. No examples were provided of on-line clean ing methods nor catalyst that would prove resistant to damage from such methods that would be effective in removing surface blinding and pore plugging deposits such as those seen in the Coyote pilot test catalyst even with the suggested edge erosion prevention measures in place. Hans Hartenstein does not address this issue in his comments. Hartenstein implies in his report (2008), that catalyst that has been poisoned by sodium compounds can be regenerated in-situ, and th at this technique is well developed. There is extremely limited experience with in-situ catalyst cleaning on coal-fired

units. It has never been used for blinded or chemically poisoned catalyst, but only for mechanically plugged catalyst (see Appendix A).

The following discussion will provide information on the following topics relevant to the EPA’s comments: an SCR technology review and update; th e variability of lign ite; results of Coyote pilot testing; soluble sodium; differences in flue gas compos ition; catalyst poisoning, blinding and plugging; applicability of SCR developmen t for Texas lignite; SCR catalyst erosion and cleaning; pilot testing for SCR catalyst; vendor guarantees for TESCR; temperature variations for HDSCR; Burns & McDonnell’s SCR experien ce; comments by Sargent and Lundy on SCR experience; comments on Hans Hartenstein’s qu alifications for SCR expert opinions; fuel switching/blending/cleaning; non-SCR controls; and conclusions.



## SCR Technology Review and Update The literature provided by Hartenstein in his expe rt report (Hartenstei n, 2008) did not provide any new information that would indicate the SCR technology is feasible for NO x reduction at the MRY plant. Much of the information Hartenst ein provided was reviewed earlier by the Energy & Environmental Research Center (EERC) and Burns and McDonnell. In addition, the reports provided by Hartenstein were not peer reviewed and were derived primarily from companies

who have vested interests in the SCR tec hnology and typically do not discuss problems and challenges. The reports from EP RI provided more useful information on the characteristics of the Texas lignite.

Hartenstein (2008) provided little information i ndicating that he is familiar with blinding and poisoning processes involving alka li (sodium and potassium). A demonstrated understanding ofResponses to Comments 10 September 22, 2008 the blinding, plugging, and poison due to firing al kali-rich fuels is vital in determining the feasibility of SCR technologies. Much of th is background information has been provided in EERC’s previous comments (2007 and earlier). In addition, a significant amount of work has recently been conducted in Europe on blinding a nd poisoning of SCR catalysts associated with firing biomass alone and with coal. Much of the discussions are focused on the impact of alkalirich aerosols on catalyst deactivation.

Since Hartenstein does not ade quately address key mechanisms of catalyst deactivation and poisons, it is appropriate to provide a summary of the techni cal information. Guo (2006) who conducted testing of catalyst de activation studies described the mechanisms of catalyst deactivation as shown in Figure 1. There are four primary types of catalyst deactivation.

• The first is channel plugging and is impacted by so called “popcorn ash” or in many cases typical of ash deposit fragments. Channel pl ugging is largely driv en by the size of the

ash materials carried back into the flue gas treatment system and can typically be controlled by the use of large particle ash screens to remove the ash, or by providing larger pitch catalyst.

• The second type is pore plugging by small fly as h particles. Small particles sometimes become lodged in the openings to the catalyst pore system and can cause plugging. These particles are typically not bonded and can be removed by various cleaning technologies.

• The third type is masking of the macrosurface by a dense phase. These phases that form are typically sulfates. The sulfates have formed as a result of in-situ sulfation of deposited alkali and alkaline earth materials.

• The fourth type is poisoning of the active site s in the catalyst. The active sites in SCR catalyst can be poisoned by the diffusion of various types of aerosols. The aerosols will diffuse into the pores and react with the active components of the catalyst.Responses to Comments 11 September 22, 2008 Figure 1. General mechanisms of SCR catalyst deactivation (Guo, 2006).

High sodium lignites are prone to form abundant levels of aerosols when fired in a cyclone

burner. Aerosols are formed as a result of the homogenous condensati on of flame-volatilized species in combustion systems. During combus tion of lignite, sodium, potassium, sulfur, and other components will vaporize and upon gas cooling these components will condense to form aerosols and other particles. As a re sult of these interactions, the resulting ash composition and mass distribution as a function of size is also shown in Figure 2. Typical

ash derived from coal combustion has a bimodal to multimodal size distribution that consists of a submicron and supermicron size fracti on as shown in Figure 3. The submicron component is largely a result of the condensatio n of flame-volatilized in organic components.

The intermediate size mode at about 2 microm eters is derived from the more refractory organically associated elements such as calci um and magnesium. The larger particles at approximately 12 to 15 μm are derived from th e mineral grains present in the coal. The larger-size particles have been called the re sidual ash by some investigators (Sarofim and others, 1977) because these ash particles resemble, to a limited degree, the original mineralsResponses to Comments 12 September 22, 2008 in the coal. Sodium and other flame-volatilized components are concentrat ed in the finer size fractions of ash as shown in Figure 4. This figure illustrates the increase in the sodium

content in the finer size fractions of ash as a result of firing high sodium lignite. The sodium content of the 3rd stage (1–3 micrometer size cut) of the sampling train approached 20%

Na 2 O.

Figure 2. Transformation of inorganic com ponents present in coal during combustion.Responses to Comments 13 September 22, 2008 Figure 3. Final size distribution of ash partic les produced upon combustion of lignitic coals (Benson and Laumb, 2007).

Figure 4. Composition distribut ion of ash particles during combustion of North Dakota Lignite (Benson and others, 1983).

The transport of intermediate ash species (i.e., in organic vapors, liquids, and solids) is a function

of the state and size of the ash species and system conditions such as gas flow patterns, gas velocity, and temperature. Severa l processes are involved in the tran sport of ash particles. These processes have been described by Raask (1985) and Rosner (1986). The primary transport mechanisms are illustrated in Figure 5. For la rger particles inertial impaction and eddy impaction in turbulent regions are the domina nt mechanisms. The aerosols (small particles

<1 μ m) and vapor-phase species are transported by the vapor phase and small particle diffusion. The inorganic materials are transported to he at-transfer and catalyst surfaces by diffusion, electrophoresis, and inertial impaction.Responses to Comments 14 September 22, 2008 Figure 5. Scanning electron microscope seconda ry electron image of SCR surface structure before exposure to flue gases.

Recent work conducted by Zheng and others (2008) in a paper entitled “Deactivation of V 2 O 5 - WO 3 -TiO 2 SCR catalyst at biomass fired power plan t entitled “Elucidation of mechanisms by lab- and pilot-scale experiments” described the diffusion of aerosols and their ability to cause catalyst poisoning. Figure 6 shows a plot of th e aerosol concentration as a function of size, catalyst pore size, and the diffusion coefficient with size. These result show that diffusion of the submicron aerosol is highly likely since potentia l for diffusion increases with the smaller size fraction of particles and that the mechanism w ill be active for particulate from upstream and downstream of the partic ulate control device such as an E SP. These efforts followed earlier studies where Zheng and others (2005) biomass-derived alkali ri ch aerosols caused a drop in

NO x reduction activity by 52% afte r about 1140 hours of operation.Responses to Comments 15 September 22, 2008 a. Comparison to ESP inlet size distribution of fly ash.

b. Comparison to ESP outlet size distribution of fly ash

Figure 6. Comparison of the size distribution of the aerosol produced during combustion with the diffusion coefficient and catal yst pore size (Modified after Zhe ng and others (2008) with data from Linak and Wendt (1994)).

The association of alkali and alkaline earth elements in Cent er lignite is similar to the

associations found in biomass. In both Center lignite and biomass ma terials the alkali and alkaline earth elements are largely organically associated. An analysis of a wood residue biomass material that is similar to lignite is shown in Table 1. The total alkali (Na 2 O+K 2 O)Responses to Comments 16 September 22, 2008 calculated on a lb/mmBTU basis for the wood resi due is 0.10. The total alkali for the average Center lignite was determined to be 0.84 lb/ mmBTU. Compositions of various biomass types were compiled by Miles and others (1995) and they found the total al kali ranged from 0.06 to 1.15 lb/mmBTU. The overall chemical compositi ons for the biomass are listed in Tables 2 through 5 along with the water soluble alkali. Miles and others (1995) conducted chemical fractionation, a procedure that determines the a bundance of alkali and other elements that is soluble (associated as soluble species and with the fuel organic fraction), on the biomass and

found that the alkali we re mainly organical ly associated. Because of the organic association alkali sp ecies vaporize upon combustion and condense to form aerosols upon gas cooling. This vaporizatio n of alkali during biomass combustion resulting in the formation of aerosols has been investigat ed by numerous researchers. One of the most recent paper is by Hindiyarti and others (2008).

Table 1. Example of a wood res idue biomass composition. Wood Residue Biomass Proximate Analysis, as received, wt% Moisture 7.30 Volatile Matter 76.82 Fixed Carbon 15.25 Ash 0.6 Ultimate Analysis, as received, wt% Hydrogen 6.1 Carbon 46.85 Nitrogen 0.1 Sulfur 0.1 Oxygen 46.05 Ash 0.63 Heating Value, Btu/lb 8274 Ash Composition, wt% equivalent oxide SiO 2 27.7 Al 2 O 3 11.0 Fe 2 O 3 10.0 TiO 2 0.5 P 2 O 5 1.4 CaO 28.4 MgO 5.9 Na 2 O 4.9 K 2 O 7.6 SO 3 2.5 Lb alkali (Na 2 O+K 2 O)/mBtu 0.10Responses to Comments 17 September 22, 2008 Table 2. Wood Fuel Blends: Alkali Deposit Investigation Samples (Miles and others 1995).Responses to Comments 18 September 22, 2008 Table 3. Wood Fuel Blends: Various (Miles and others 1995).Responses to Comments 19 September 22, 2008 Table 4. Urban Waste Fuels and Residues (Miles and others 1995).Responses to Comments 20 September 22, 2008 Table 5. Wood Fuel: Energy Crops (Miles and others 1995).Responses to Comments 21 September 22, 2008 Hartenstein (2008) indicated that “sodium is not a poison at SCR operating temperatures.” This statement is inconsistent with Hartenstein’s past claims, where he makes the following statement (Hartenstein and Licata, 1996) “...elements such as sodium and potassium, are known to cause permanent irreversible disactivation of SCR catalys ts.” There is literature information indicating that sodium is a poison at SCR operating temperat ures. The poisoning mechanisms of alkali and alkaline earth oxides on vanadia catalysts were in vestigated by Chen and others (1990). Their

work found that the deactivation is directly related to th e basicity of the poisons. The ranking of the strengths of the poisons are listed as follows: Cs 2 O > Rb 2 O > K 2 O > PbO > Na 2 O > LiO >

CaO > P 2 O 5 . Figure 7 shows the activities of the cat alyst with various elements added. The testing was conducted at 300°C. In addition, Gu o (2006) conducted a study on the intrinsic SCR activity for NO with NH 3 reaction and found that the additions of K, Na, and Ca greatly decrease the NO reduction activity of 1% V 2 O 5 – 9% WO 3 /TiO 2 as illustrated in Figure 8.

Figure 7. Rate constants for a V 2 O 5 /TiO 2 combined with different amount of oxide poisons (Chen and others, 1990).Responses to Comments 22 September 22, 2008 Figure 8. Impact of NO x reduction rate constant as a resu lt of poisoning by sodium, potassium, and calcium (Guo, 2006).

The mechanisms of catalyst deactivation due to alkali components are currently being investigated in depth. Severa l studies are being conducted in Europe because of poisoning of catalysts due to biomass firing and co-firing. Th e diffusion of alkali (Na and K) vapor has been ruled out as was correctly stated by Hartenstein (2008) because it will be in the condensed form at SCR temperatures. However, the presence of alkali aerosols does contribute to the deactivation of catalysts (Zhe ng and others 2008, Zheng and others 2005). The rates of

deactivation in full-scale and labor atory studies were about 1% per day. They indicated that the in-situ formation of liquid potassium-vanadiu m-pyrosulfates could be one of the possible mechanisms. However, testing showed that th e deactivation reactions also take place in the

absence of SO 2 due to aerosol penetrati on into the catalyst.

The exact form of the alkali aero sol (hydroxide, sulfate, or other) that contributes to poisoning is not known. Zheng and others (2008) indicate the possible mechan ism of deactivation occurs by the diffusion of aerosol particle s rich in alkali into the cataly st pores followed by reaction with the V–OH groups producing –V–O–K (Na). These observations are consistent with the work conducted by Kling and others (2007) who investig ated deactivation of SCR catalysts in threeResponses to Comments 23 September 22, 2008 biomass and peat fired 100 MW-scale combustion sy stems. They found that the increased levels of sodium and potassium accumulated in the S CR catalyst was derived from the ultra fine particles (aerosols). These accumulations of aer osols resulted in decreased the NOx reduction catalytic activity as shown in Figure 9.

Figure 9. Reduction in catalytic ac tivity as a function of accumul ation of alkali in the catalyst (Kling and others (2007).

Recent testing conducted by Strege and others (2008) at a stoker-fir ed utility boiler firing a blend of biomass and Powder River Basin coal (PRB) found that the catalyst deactivation rate was about 18% per 1000 hours. The components resp onsible for the deactivation were sodium, potassium, and calcium sulfate- based materials. Alkali com ponents (sodium and potassium) were found deep inside the catalyst.

Broske (2003) in an EPRI report indicated that for analysis of spent catalysts from medium sulfur bituminous (Appalachian) coal found that the concentration of sodium and potassium species accumulated to over 100 times the levels found in new catalysts. The levels reached in the catalyst were between 4000 and 6000 ppm. This is for an Appalachian co al that typically hasResponses to Comments 24 September 22, 2008 low levels of sodium in the ash. In this partic ular catalyst, arsenic was found to be the primary contributor to poisoning but the alkali (sodium and potassium) also contributed.

The impact of aerosols on the performance of low dust SCR applications was not discussed by Hartenstein (2008). The impacts have been id entified by Copolo and others (2003). They indicated in their paper that “The ash however, th at escapes from the precipitators is finer than the ash in general ..... Although less likely to cause erosion, it does ha ve a higher plugging potential as finer ash has been found to have a higher tendency to agglomerate.” In addition, Hartenstein (2008) did not consider informati on provided on ash accumulations downstream of the ESP at the MRY station. Testing of Powers pan’s barrier discharge reactor (Tolbert and Benson, 2008) was conducted to determine the potential application of the Powerspan technology for new power generation firing high sodium ND lignite. The barrier discharge reactor is placed downstream of particulate cont rol systems to enable the oxidation of NO to NO x species that will allow for capture in an ammonia-based scrubbing system. A slipstream barrier discharge reactor system was designed by Powers pan and the EERC and installed downstream of the ESP on Unit 1 at the MRY Station. The ga s temperature was approximately 300°F.

The primary concern regarding the success of the Powerspan technology was that sodium-rich aerosols exiting the ESP would accumulate on the qua rtz rod resulting in decreased performance of the barrier discharge reactor. At two week intervals duri ng the testing campaign, the reactor was inspected and rods were removed for analysis. The ash accumulation resulted in decreased nitrogen oxide (NO) oxidation due to accumulations of alkali and alkaline earth sulfate rich ash layer on the rods. An example of the ash accumu lation on the rod after exposure to flue gases downstream of the ESP is illustrated in Figure 10 . The exposed quartz rods were mounted in epoxy resin and cross-sectioned fo r scanning electron microscopy a nd x-ray microanalysis. The image in Figure 10 shows a highly bonded ash coating on the surface of the quartz rod. The red line represents the line analyzed across deposit an d the quartz rod. The length of the line is 22μm. The abundance elements were determin ed along the red line shown in Figure 10. The levels of sodium and potassium in the bonde d ash layer were great er than 10 percent.Responses to Comments 25 September 22, 2008 Figure 10. SEM image of quartz rod exposed to flue gas downstream of the ESP at MRY Unit 1 with element composition line scan across the deposit and quartz rod (Tolbert and Benson, 2008).

The bulk composition of ash scraped from sel ected quartz rods was determined by x-ray fluorescence (XRF). The rods sampled were from three electrodes that were exposed to flue gas downstream of the ESP for 20, 48, and 107 days. The bulk composition summarized in Table 6 shows significant levels of sodium, calci um, and potassium along with sulfur.Responses to Comments 26 September 22, 2008 Table 6. Bulk composition of ash removed fr om electrode samples obtained from rod removed at 20, 48, and 107 days.

In the 1999 technical paper, Mr. Hartenstein ( 1999) and his co-authors reported SCR catalyst deactivation due to sodium at the RWE Staudinger plant in Germany. Specifically, it is reported on page 5 of the referenced paper that “...the fly ash from the German coal formed highly adhesive deposits, while the porti on of South African coal contri buted to the formation of a liquefied fly ash. The reason for this was determin ed by a chemical analysis of the fly ash. It

can be seen that the content of the alkali sulfate, which adhere s to the surface of the fly ash particles, favors the tendency to agglomerate. A phase analysis of the deposits revealed crystalline sodium aluminum sulfate a nd potassium aluminum sulfate (NaAl(SO 4 ) 2 ;KAl(SO 4 ) 2 ).”

This information supports the Department’s opini on related to the formation of sodium–related deposits on the SCR catalyst that accelerate the d eactivation of the catalysts. This information conflicts with Mr. Hartenstein’s statement, on pa ge A-28 of his expert report, that the “...the intrusion of liquid pyrosulfates is no major concern with respect to a severe, rapid catalyst

deactivation.”Responses to Comments 27 September 22, 2008 

## Variability of Lignite North Dakota lignite or lignite from the Fort Union Region of North America has very unique properties. The Fort Union lignite coals are uniqu e because of the extraordinarily high levels of

alkali and alkaline earth elements that are associated with the or ganic or combustible fraction of the coal. The constituents that are organically associated are considered ion exchangeable or

soluble sodium. The association of the sodium in Fort Union lignites is si milar to the association of sodium and potassium found in biomass. In addition, the coal contains mineral grains consisting of mixed clays, quartz, and sulfides th at vary significantly in abundance. The form of the element influences their form in the flue ga s. For example, organi cally associated sodium will vaporize during combustion and form an aer osol upon gas cooling, while mineral associated sodium (sodium in a clay) is less likely to vapo rize and will be retained with the clay-derived particle. The sodium associated with the aerosol is much more reactive than sodium associated with a melted clay-derived particle.

The organically-associated elements are prone to vaporize during combustion. These organically associated elements will condense homogenously to form submicron sized aerosols or ultrafine particles. In addition, the organically associat ed elements will react with aluminosilicates producing low-viscosity (low me lting point silicate-based liquids) phases and with sulfurproducing sulfates and pyrosulfate. These elemen ts contribute to the formation of deposits on ceramic/refractory surfaces, cyclones, heat-tra nsfer surfaces, SCR catalysts, and gas filters. Formation of these deposits will l ead to operability problems, with the potential to shut down the system. Lignite composition is highly variable and, therefore, will co ntribute to a range of challenges. As a result of these challenges a nd efforts to identify problematic species, a significant database of selected North Dakota lig nites, specifically Center lignite, has been developed to provide the basis fo r understanding the be havior of lignite a nd to project potential challenges. The variability of the Center mine lignite characte ristics are summarized in Table 7.Responses to Comments 28 September 22, 2008Table 7. Center lignite composition (moisture, ash, sulfur, and heating value expressedon an as-received basis; and ash compositionexpressed as weight percent equivalent oxide of the ash produced at 750 °C).Moisture,% Ash, % Sulfur% Btu/lb Al2O3BaO CaO Fe2O3MgO P2O5K2O SiO2Na2O SO3Average 37.13 9.64 0.98 6578 11.68 0.52 13.15 8.90 3.99 0.12 1.33 36.04 4.40 18.39Max 39.37 25.46* 2.55 7101 15.62 1.22 23.96 24.72 7.09 1.00 2.30 55.98 13.03 34.50Min 33.56 4.97 0.47 5852 6.31 0.20 6.80 5.38 2.30 0.01 0.16 12.30 0.55 8.1290th Perc. 38.10 12.51 1.29 6820 14.23 0.84 19.92 12.20 5.68 0.41 1.92 45.98 8.71 26.2510th Perc. 35.95 7.06 0.72 6359 9.58 0.37 9.73 7.08 3.00 0.04 0.61 22.70 1.99 14.3545th Perc. 37.17 9.33 0.90 6552 11.62 0.47 12.15 8.34 3.81 0.09 1.36 36.99 4.09 17.3055th Perc. 37.37 9.75 0.94 6592 11.97 0.50 12.74 8.68 3.97 0.10 1.44 38.36 4.61 18.02* High value may be an analysis or reporting error. Sample could not be reanalyzed to verify.Responses to Comments 29 September 22, 2008 Hartenstein (2008) indicated that “I am not aware of a single case where high variability of heat

and ash contents of the coals and/or of the c onstituents that make up the ash preclude the principles of the SCR technology from being techni cally feasible and app licable.” Hartenstein did not indicate how he would identify a design coal for the catalyst design for high dust SCR based on the lignite characteristic . In addition, Hartenstein inco rrectly assumes that over the range of fuel properties the performance of the particulate control systems will not be impacted, thus avoiding impact on a low-dust or tail-end S CR. In cases where there is high sodium and low ash contents, the abundance of aerosol particles increases dram atically. These particles can make their way through particulate control devi ces and can impact the performance of low dust and tail-end SCR as discussed previously.

Hartenstein (2008) does not provide information on chemical composition of the fuels that are comparable to high sodium lignite where SCR in stallation have been installed and tested or successfully operated. The composition of the Texas li gnite fired at Martin La ke is typical of the composition of lignite fired at Sandow and is show n in Table 8. The sodium oxide levels in the Texas lignite ash is 0.7%. The levels of sodium oxide in Center lignite average 4.4% and can be as high as 13% in as-fired samples.

It is surprising that Hartenstein did not discuss his experience w ith German Ruhr Brown coal as described in a paper by Hartenst ein and others (1999) where they found that ”... the pressure drop across the catalyst layers rapi dly increased....” when they fired German Ruhr coal alone. The problem was associated with the highly “a dhesive” fly ash bonded with an alkali sulfate phase. They were unable to fire 100% lignite and had to rely on blending with a South African coal to reduce the problem. He also stated that “We have also learned that we had to analyze not only for sodium (Na) and potassium (K) content of the coal but also we need to know if the Na and K compounds are water-soluble. In a water soluble form, these alkaline metals are highly mobile and will migrate throughout the catal yst material reducing active sites.”Responses to Comments 30 September 22, 2008 Table 8. Average Texas Lignite Coal a nd Ash Composition (Ulvog and Wiemuth, 2003)



## Results of the Coyote Pilot Testing

Hartenstein stated “The HDSCR Coyote pilot testing was il l-designed and fundamentally

flawed.” Hartenstein based this statement on hi s flawed interpretation of the Coyote testing. Hartenstein (2008) incorrectly interpreted the te sting at Coyote Station as follows: “Admittedly, the Coyote Pilot Testing results se em 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 an d only mechanically cleaned is more likely to quickly plug again than new, unused catalyst was simply ignored.”

Hartenstein (2008) described the reactor as being “ill -designed.” The reactor system initial design was based on a design provided by Corm etech. The final design was reviewed and approved by the project team that included Co rmetech, Haldor Topsoe, Hitachi, EPRI, US. DOE, Alliant Energy, Otter Tail Power, Ameren, Dynegy, and Lignite Energy Council. InResponses to Comments 31 September 22, 2008 addition, the selection of catalyst for the testi ng at Coyote was based on the recommendations of Haldor Topsoe. The testing protocols including the soot blowing media and frequency as well as all operating conditions were reviewed and approved by the aforementioned project team.

The following describes how the testing was con ducted and is clearly de scribed in Benson and others (2005).

1. The same reactor system used at Baldwin station was moved to the Coyote Station and

installed.

2. The system was completely cleaned prio r to operations at the Coyote Station.

3. Fresh catalyst was installed in reactor pr ior to testing at the Coyote Station.

4. At approximately two month intervals, the reactor was inspected and sections of the catalyst were removed for analysis, and fresh catalyst replaced the ca talyst section that

was removed.

5. The catalyst sections were analyzed for por e plugging and Haldor Topsoe was going to conduct activity measurements.

6. Haldor Topsoe indicated th at the catalyst was too pl ugged to measure reactivity.

The slipstream reactors worked we ll at the Baldwin Station (cyc lone PRB fired) and Columbia (pulverized coal tangential PRB fire d) with minor to moderate fou ling. The same reactor used at Baldwin was used at the Coyote Station. The pi tch of the catalyst used at Coyote Station was 6mm as recommended by Hansen at Haldor Tops oe. A comparison of the first 500 hours with both systems using fresh catalys ts is shown in Figures 11 and 12 for Baldwin and Coyote Station, respectively.Responses to Comments 32 September 22, 2008 Baldwin SCR Reactor First 500 hours

0 0.2 0.4 0.6 0.8

1 1.2

0 100 200 300 400 500 Runtime (hours)CAT DP (" of H20)

Figure 11. Pressure drop across SCR reactor during first 500 hours of testing at Baldwin

Coyote SCR Reactor First 500 Hours

0 0.2 0.4 0.6 0.8

1 1.2

0 100 200 300 400 500 Runtime (hours)CAT DP (" of H20)

Figure 12. Pressure drop across SCR reactor during first 500 hours of testing at Coyote

Initially, at Baldwin there were some problems w ith start up and operation of the reactor because of plant outages. The pressure drop at the end of 500 hours averaged about 0.6 inches of water. The pressure drop for Coyote Station is shown in Figure 12, and at the end of 500 hours the pressure drop averaged about 0.85 inches of wa ter. The plugging and blinding of the catalyst

was severe.Responses to Comments 33 September 22, 2008 

## Soluble Sodium

Soluble sodium is used to describe the form of so dium in the coal as well as forms of sodium in

ash. The soluble form of sodium in coal is used to describe the abundance of sodium associated with the water soluble and organic fraction of th e coal. During combustion the soluble sodium (organically associated) in the co al is much more likely to vapori ze than an insoluble form. This is especially true for a cyclone -fired boiler. Upon gas cooling the alkali vapors will condense to form aerosols or sometimes called ultrafine particle s. These ultrafine particles can diffuse into the pores of the catalyst a nd react with V-OH groups formi ng V-O-K(Na) rendering the site inactive (Zheng and others 2008). Hartenstein’s fo llowing interpretation is inconsistent with the work by Zheng and others (2008) which is co-autho red by one of the lead scientists from Haldor Topsoe.

”Unfortunately, the Department fails to rea lize what was pointed out by one of the most experienced catalyst suppliers, namely that “s odium is not a poison to catalyst at SCR operating temperatures.” Thus, the elaborat e comparison of emission factors of sodium, potassium, calcium, and magnesium emission f actors with the fly ash may have some academic value but is effectively meaningl ess for the correct pr ediction of catalyst deactivation, since particle bound sodium, pot assium, calcium and magnesium in the fly

ash are not mobile and theref ore are not catalyst poisons.”

The abundance of alkali aerosols in the flue gas as depicted by emission factor will have an impact on the rate of catalyst deactivation by the fo rmation of aerosols that directly poison sites or produce pyrosulfates. The impact of the abundance of alkali (sodium and potassium) is clearly illustrated by the recent work conducted by (Kling and others (2007).

The formation of pyrosulfates as describe d earlier (EERC and Burns and McDonnell) is consistent with recent investigations of al kali poisoning of catalyst (Zheng and others 2008, Zheng and others 2005). They indicated that th e in situ formation of liquid potassium-vanadiumpyrosulfates could be one of the possible mechan isms. Hartenstein (2008) states “Alternatively, these pyrosulfate compounds would have to be pres ent in a liquid so that their dissociated ions (i.e. Na+, K+) would be mobile in order to ente r the catalyst pores and react with the catalyst’sResponses to Comments 34 September 22, 2008 active sites.” He does not cons ider their in-situ formation as a result of the reaction of

accumulated Na or K-rich aerosols with SO 3 and vanadium in the pores of the catalyst. Vanadium and iron compounds are know to catalyze the formation of pyrosulfates. Hartenstein (2008) also incorrectly states the range of melting points of the pyrosulfate phases (650 to 750oF). The melting points of sele cted pyrosulfates are listed in Table 9 and have a range of (535 to 1281oF).

Table 9. Melting Points of Selected Pyrosulfate Compounds 

### Compound Temperature, °C Temperature, °F

K 3 Fe(SO 4 ) 3 K 3 Al(SO 4 ) 3 KFe(SO 4 ) 2 Na 3 Fe(SO 4 ) 3 Na 3 Al(SO 4 ) 3 NaFe(SO 4 ) 2 Na 2 S 2 O 7 K 2 S 2 O 7 (K 1.5 Na 0.5 )S 2 O 7 618 654 694 624 646 690 401 300 279 1144 1209 1281 1155 1195 1274 754 572 535



## Differences in Flue Gas Composition The flue gas derived from the cyclone combusti on of high sodium lignite contains an abundance

of alkali-rich aerosols. This is well known and has been pub lished by Benson and others (1983) as well as other investigators. The abundance of alkali rich aeroso ls is similar to that found in biomass combustion systems. Recently, work conducted by Zheng and other (2008) point out the importance of the aerosol pa rticles and catal yst poisoning.

Hartenstein again makes the incorrect claim th at “sodium is not a catalyst poison at SCR operating temperature” and dismi sses the uniqueness of the flue gas derived from high sodium lignites. However, he provides no example of a coal fired in a boile r that produces a flue gas that is characteristic of flue gases produced from No rth Dakota lignite where SCR has been installed and successfully operated.Responses to Comments 35 September 22, 2008 

## Catalyst Poisoning, Blinding and Plugging

The pores of the catalyst exposed to the alkali- rich flue gas derived from the cyclone-fired combustion of ND lignite at the Coyote pilot test were plugged. Penetration into the pores was

extensive. Sulfation of the al kali components resu lted in filling and pluggi ng of the pores of the catalyst. Cyclone firing increase s the abundance of alkali and othe r flame-volatilized species in the flue gas stream. The more refractory compone nts end up in the slag. The alkali-rich flue gas stream is deficient in larger entrained ash part icles derived from quartz and clay mineral in the flue gas stream. Upon gas cool ing the alkali components will largely condense homogeneously

to form alkali-rich aerosols because of the low abundance of larger ash particles for heterogeneous condensation. This results in a fl ue gas with higher alkali aerosol content than produced by pulverized coal fired systems.

The aerosols diffuse into the cataly st pores and are subsequently sulf ated or interact with catalyst active sites resulting in plugging/ blinding and deactiva tion, respectively. There does not appear to be a catalyst material that has shown significantly improvement over the past catalyst relative to the performance in high sodium containing system. The specific question was asked to Flemming Hansen of Haldor Topsoe (Hansen, 2007) as to whether improvements have been made in catalysts over the ones tested at Coyot e Station that warrant further testing. He indicated that no formulation or design changes ha ve been made to improve their performance in high sodium containing flue gases.



## Applicability of SCR Development for Texas Lignite EPA provided several comments regarding future application of high-dust SCR at TXU’s Oak Grove facility as an example that it should not be eliminated as technically infeasible (at MRYS) on the basis of catalyst plugging a nd deactivation. The EPA mentioned catalyst vendors’ beliefs, and an opinion by Electric Power Research In stitute (EPRI) issued on September 7, 2006 and determinations by the Texas Commission on Envir onmental Quality. The EPA also states that “while the properties of North Da kota and Texas lignite might not be the same...” that the “sameResponses to Comments 36 September 22, 2008 basic principle applies that th e accelerated catalyst replacement requirements are a matter of

economics and not technical feasibil ity” (U.S. EPA, 2008, Enclosure 2).

As responses to previous EPA opinions on th is subject have been presented elsewhere (Minnkota, 2007A, 2007B, 2007C, 2008), the EPA fails to recognize conclusively that ash chemical and physical properties of Texas lignite (Wilcox formati on) that TXU proposes to burn at the new Oak Grove powerplant do not represen t what is fired in North Dakota, and its technical feasibility and expected performance in an SCR application is not transferable to North Dakota lignite-fired cyclone burner units due to the significant differences in flue gas and ash chemical and physical properties.

The EPA also fails to recognize and acknowledge that significant pilot testing has been conducted at several power plants in Texas that fire lignite supplied from various locations in Texas, and that there are no cyclone-fired boilers in Texas. The EPA has gone down the same path that tried to compare German SCR app lications which lack significant cyclone boiler experience and is not currently required for lignite -fired boilers to be ap propriate and comparable to North Dakota lignite-fired cyclone burner units. These are misleading statements and contrary to the presentation of the body of information submitted in support of the NDDH’s preliminary

BACT determination for MRYS.



## SCR Catalyst Erosion and Cleaning Various means of resolving catalyst erosion have been previously discussed in earlier comments and responses (Minnkota, 2007A and 2007B). While hardened leading catalyst surfaces may be

resistant to erosion from entraine d flyash, the more important issues to consider are effectiveness and damage from on-line catalyst cleaning methods . Hans Hartenstein (2008) does not address

this issue in his comments.

Effective on-line cleaning of catalys t deposits seen in the Coyote pi lot testing, especially with the micropores plugged with sodium-sulfur compounds , does not appear to be achievable.Responses to Comments 37 September 22, 2008 No examples of on-line cleaning methods nor cataly st that would prove resistant to damage from such methods that would be effective in removing surface blinding and pore plugging deposits such as those seen in the Coyote pilot test ca talyst even with the suggested edge erosion prevention measures in place have been identified. It is difficult to compare current experience with lower fouling coals with a hypothetical installation on a cy clone boiler firing North Dakota lignite, without having pilot or full-scale testi ng experience on the subject fuel to expected surface blinding and pore plugging deposits and cleaning operation conditions.

Hartenstein implies, on page A-36 of his report, th at catalyst that has been poisoned by sodium compounds can be regenerated in-situ, and that th is technique is well developed. ENBW in Germany developed this technique, but it has never had a commercial success. Regarding the contention of Hartenstein, there is extremely lim ited experience with in-s itu catalyst cleaning on

coal-fired units. It also has never been used fo r blinded or chemically poisoned catalyst, but only for mechanically plugged catalyst (see Appendix A).



## Pilot Testing for SCR Catalyst In many cases where SCR technology has been a pplied to fossil fuel-f ired boilers located throughout the world burning a variety of coals and solid petroleum bypr oducts, extensive pilot testing programs have been performed prior to the implementation on full-scale utility boilers: Germany in the 1980’s, the United States in the 1980’s for low sulfur and high coals, and in Texas since year 2000 on Texas lignite. The app lication of SCR technolo gy to coal-fired boiler in Germany has been almost exclusively on non-ligni te fired units. Both in Germany and in the United States, it has been demonstrated that it is very difficult to sole ly rely on SCR catalyst suppliers’ experience with simila r coals and pulverized coal-fir ed boilers when developing SCR system designs and understanding process issues th at are important to the successful deployment, operation, and maintenance of such emissions reduction technology in st rict compliance with regulatory and subsequent permit requirements.

Many pilot test programs have been conducte d to implement SCR technology when new and unknown process issues have been raised. There ha ve been multiple pilot tests and research and development programs involving app lication of SCR technology to fossi l fuel-fired utility boilersResponses to Comments 38 September 22, 2008 in Germany. Several are described in Appendix A by Burns & McDonnell’s SCR technology consultant assisting in these respon ses, who participated in them.

These described pilot SCR test programs incl ude a high dust SCR on a wet bottom boiler before the first high dust SCRs were built in Germa ny, and a TESCR application. The first tests determined that the catalyst deactivated rapidly, which contradicted what the catalyst suppliers believed, which was that such testing was unnecessa ry. The HDSCR pilot test revealed the fact

that arsenic was unknown as a str ong catalyst poison. Most of th e German utilities decided not

to retrofit wet bottom boilers th at had fly ash recirculation wi th a HDSCR so that arsenic poisoning could be avoided (see Appendix A).

Utilities built tail-end SCRs in Germany that included a wet sc rubber ahead of the reactor to avoid the arsenic poisoning problems with the cataly st. Again, pilot testing led to the discovery of a new catalyst poison (SiF 4 ) which caused the first catalyst la yer to lose more than 50 % activity in less than 2,000 hours. This demons trates that SCR catalysts can be severely

deactivated even when boilers bur n coals with a SCR configurati on that were not expected to cause such problems (see Appendix A).

A recent pilot SCR test program in the South east United States involving eastern bituminous coal, Venezuelan coal and pet coke at a utility boiler was performed to account for the influences of the fuel on the NOx activity and SO2 oxidation ra tes of the catalyst. With limited worldwide experience on such a range of fuels, the Utility decided to conduct an ex tensive pilot program to assess impacts on the catalyst (s ee Appendix A). Following comple tion of the pilot testing, the catalyst vendors found it necessary to significan tly modify and/or completely withdraw the guarantees they had offered prior to the testing.

Mr. Hartenstein and his co-author s support pilot programs for those SCR applications in which new and uncertain process considerations are en countered. In the refe renced technical paper (Hartenstein, 1999), Mr. Hartenstein states: “In principle, the reducti on of NOx emissions with SCR catalysts is a mature technology, which was developed many years ago. Nevertheless, experience has shown that in many applications, special features were required that necessitateResponses to Comments 39 September 22, 2008 further optimization of the DeNOx system. In particular, standard solutions were often not possible or optimal when retr ofitting existing power plants.”

In the case of Milton R Young, the uncertainty a ssociated with the high sodium concentration and the presence of sodium aerosol s in the flue gas raise serious concerns pertaining to catalyst performance. The potential application of a ny SCR technology at Milton R. Young suggested by

the EPA and Mr. Hartenstein is not standar d, and is very unique , due to the special considerations pertaining to th e lignite, boiler operating temper atures, flue gas reheating, among

others. Pilot testing is certainly warra nted before any claims that this technology is feasible at M.R. Yong Station can be confirmed. The pilot testing must utilize new concepts and designs that alleviate the problems associated with alka li aerosols. These new concepts and designs do not appear to be currently available from the vendors.

We disagree with catalyst vendors and Mr. Harten stein that pilot testi ng is not required for HDSCR, LDSCR, or TESCR prior to application to the boilers at MRYS. They have not cited any substantiated data that show successful SCR experience from coal-fired boilers with similar boiler- and fuel-specific conditions as present on North Dakota lignite-fired cyclone boilers that make this technology infeasible at Young station. The lack of evidence shown to prove that such factors have been solved such that any form of SCR technology would not require extensive pilot testing and design development for these applicat ions is significant a nd important in supporting the NDDH’s arguments against adopting SCR technology as BACT for MRYS boilers.

As we have stated previousl y, the application of emission re duction technology that requires such extensive pilot testing and design developm ent should not be considered as available and technically feasible for th e purposes of a BACT determ ination (U.S. EPA, 1990).



## Vendor Guarantees for TESCR Burns & McDonnell’s consultant (Tackticks LLC) has significant experience in dealing with SCR system suppliers and catalyst vendors involvi ng their initial willingness to offer guarantees and what they will actually agree to sign in th e form of a contract. Mr. Hartenstein (2008)Responses to Comments 40 September 22, 2008 frequently states that various catalyst and SCR system vendors would be willing to offer performance guarantees for the Milton R. Young Station TESCR.

Examples of cases where SCR vendors have ini tially said they would guarantee performance without hesitation then subsequently changed th eir offer or settled a claim by the utility for failure to meet guarantees are described in Appendix A.

It is typical for vendors to do this in the absence of a detailed technical sp ecification and contract with commercial conditions and liquidated damage s. Actual performance guarantees that the SCR vendor intends to agree with for the purpose of a entering a binding contract will only be

offered once all technical issues and challenges have been identif ied and addressed in the system specification. The vendors will not present pe rformance guarantees for negotiation without having assessed their risk mitigation strategy. As the cost of potentially having to provide one or several levels of replacement catalyst in or der to make it through the guarantee and warranty periods is significantly less than 10 percent of the total installed cost for a typical coal-fired SCR project, and the total liquidated damages should such replacement be required prematurely are only a fraction of the utility’s pot ential actual and consequential damages, the supplier’s financial exposure is decidedly much less than the buyer’s (u tility) should such failure to meet guarantees

and warranties occur.



## Temperature Variations for HDSCR Hans Hartenstein’s comments agree with the NDDH’s position that such large boiler flue gas exit temperature variations, as shown in Minnkota’s April 20 07 response letter (Minnkota, 2007B), would not be tolerable for a high dust S CR at MRYS. Mr. Hartenstein (2008) went

further to state this would not be tolerable fo r any HDSCR installed af ter any type of firing system burning any type of fuel. The ability to successfully control SCR reactor inlet temperatures in a high-dust SCR application at MRYS without impairi ng lignite pre-drying has

not been confirmed.

The EPA’s, Plains Justice’s, and Hans Hartenst ein’s comments (2008) al l assume that the SCR catalyst system suppliers (boiler original e quipment manufacturers) will solve the statedResponses to Comments 41 September 22, 2008 temperature problems. None of the catalyst ven dors queried offered to guarantee their catalyst’s performance with the current situation of too low and excessively high operating temperatures on these boilers under various operating conditions. The SCR system suppliers queried did not offer any examples of successful application of proven solutions to th e conditions existing at MRYS (B&McD and EERC, 2008). It is specula tive and would be inappropriate to assume these challenges have been or will be solved or to expect meaningful responses from vendors knowing the nature of the conditions i nvolved have not been resolved.

Mr. Hartenstein states, on page A-9 of the refere nced opinion report (2008) , that no flue gas reheating is typically required fo r HDSCR (and LDSCR). This is inco rrect. The majority of coalfired boilers with HDSCR technology cannot ma intain minimum operating temperature over the entire load range, therefor e reheating with economizer bypass, split economizer or supplementary heat input from duct burners is necessary (see Appendix A). Because of the unique arrangement of economizers in the flue gas ductwork from Minnkot a’s boilers, and lack of a natural gas pipeline serving th e plant, this has already been dismissed in previous responses to the EPA’s comments (Minnkota, 2007A, 2007B, 2007C, 2008).



## Burns & McDonnell’s SCR Experience The NDDH’s Preliminary NOx BACT Determination included a statement attesting to the “extensive experience with the design and operation of SCR systems” of Burns & McDonnell, which was refuted by the DOJ’s commenter (Harte nstein 2008). A brief summary of Burns & McDonnell’s size, years in business as an engineer ing firm and both general and specific areas of experience and technical expertis e, particularly in regards to utility powerplant boiler NOx emissions control was presented to the NDDH and EPA in May, 2007 ( B&McD and EERC, 2007)

.

The issue of experience with SCR sy stems in this response is a questi on of relevance. It will be helpful to first discuss what typical phases a project may go through from start to completion.

These are:

• Preliminary study and investigation

• Conceptual DesignResponses to Comments 42 September 22, 2008 • Detailed design

• Procurement

• Fabrication and delivery

• Construction

• Commissioning

• Startup and tuning

Project execution involves al l phases listed above and, depe nding on the project and the contracting strategy; the architec tural and engineering (A&E) firm’s role may involve all of the above or selected portions of the listed phases while remaining portions are delegated to other

entities such as techno logy suppliers, system ve ndors, or the owner.

Is Burns & McDonnell’s SCR Experience even a rele vant factor at this stage of the project?

Burns & McDonnell’s role in this project has been to perform the BACT analysis, not to design two SCR systems for Units 1 and 2 at Milton R. Young Station. Our experience on performing BACT for utility powerplant units located in the United States is relevant and extensive. Some engineering firms only work on the environm ental permitting and study aspects of pollution control and emissions reduction projects while others focus more on the implementation and

construction. Burns & McDonne ll has successfully worked in both areas and continues to provide these services to our cl ients. Mr. Hartenstein seems c onfused as to the role of an engineering firm and from that lack of understanding has made some irrelevant commentary.

What constitutes “SCR Experience”? Relevant experience in various as pects of a project and specifically a retrofit air pollution control project has to be considered. Burns & McDonne ll’s role in an air po llution control retrofit project does not typically include the “process design” porti on but there are many aspects of retrofit projects that are not specific to just an SCR retrofit project. For example, our structural engineers that are experienced at ductwork arra ngement, detailed design of hot flue gas ducts, foundation design, structural steel design, consid eration for wind, snow, seismic as well as component thermal expansion and movements all contribute to the project. None of those aspects are specific to SCR pro cess design but all are relevant for SCR system design and BurnsResponses to Comments 43 September 22, 2008 & McDonnell has successfully provi ded these engineering and design efforts on many projects including SCR retrofit projects.

The specific issue discussed in the EPA’s comment document on NDDH’s Preliminary BACT Determination (NDDH, 2008) is in regard to SCR process design and catalyst design. In this type of retrofit emissions control project, Burn s & McDonnell’s role is to serve the Owner’s needs and gather the data, resources, and exper tise needed to execute the project. Burns & McDonnell would develop and specify the operati ng conditions, fuel, and flue gas parameters and values that form a basis of design whic h the catalyst supplier re lies on, along with their expertise and proprietary knowledge of their products, to offer a proposed catalyst type, pitch and volume required to meet certain performanc e guarantees and warranty requirements. The catalyst supplier is in the best position to determine how they propose to meet the specified performance responsibility, understa nd how that offer fits their business’ commercial/financial impact, and whether this may impair or enha nce the long term supply of their product.

It is within Burns & McDonnell’s ability to assess the relevance of the various catalyst suppliers’ offers, their experience, and their level of understa nding of the site, the project, the fuel and other system concerns in order to advise the owne r as to which vendors are deemed qualified for bidding and executing the pertinent portions of an SCR retrofit project. Many utility owners are not comfortable with performing such technolo gy and vendor assessments alone, nor do they maintain the in-house resources that have expertis e to do such tasks to a level that significantly reduces their risk of selecting a vendor to provide a product that ultimately does not meet their requirements nor satisfy their expectations.

As has been pointed out in NDDH’s Preliminar y BACT Determination ( NDDH, 2008) and other supporting documents (Minnkota, 2007A, 2007B , 2007C, 2008; B&McD and EERC, 2007 and 2008; Appendix A), significant concer ns exist about the un ique characteristics of the fuel burned, type of firing, and flue gas and ash constituen ts and their influence on the viability of SCR application on these units. We recognize this site-specific situation fa lls outside the current knowledge and experience base of the potential catalyst supplier s. Additionally, some of the significant concerns on this project have nothi ng to do with what th e catalyst supplier canResponses to Comments 44 September 22, 2008 address, such as the boiler exit temperature. This concern and ways to address it are rightly placed in the boiler design firm’s realm of expertis e. Burns & McDonnell’s role in this phase of the project is to gather, manage, and assess the technical information and advise the owner based

on what these entities claim and what has been do ne elsewhere as well as to investigate publiclyavailable technical data that is relevant.

Burns & McDonnell’s SCR Experience can be categorized in four distinct areas:

• Preliminary studies

• Conceptual designs and cost estimates

• Engineering management of project implementation

• Detailed design engineering duties

Each of these roles serves an important function during the over all project timeline. We can elaborate and provide more details on each catego ry of specific experience on various projects. This is considered business proprietary information and will only be made available if needed. We do not feel this project-speci fic information is relevant to the current issue raised by the Hartenstein (2008), and have not included these details at this time but can if required. A summary of the roles and experience is provided be low as we feel it will suffice to demonstrate our capability and viability for the role we have served thus far on this effort.

• Preliminary studies Burns & McDonnell has performed studies for util ity clients for many years. The level of detail in what is deemed a preliminary study can be described as typi cally evaluating various alternatives. In a pollution c ontrol retrofit study, various comp liance scenarios are evaluated in a screening analysis where technologies are reviewed with regard to several criteria: whether or not the technology is commercially available or under development, the level of experience of the technology, what suppliers are qualified, an evaluation of regulatory impact, very rough screening level cost estima tes of the project, discussion of contracting alternatives, and schedule. In some cases when there is uncertainty or a range of alternatives and compliance scenarios, where more than on e pollutant is involved, and more than one unit, possible variable levels of control for each pollutant, a matrix of alternatives andResponses to Comments 45 September 22, 2008 potential outcomes is developed to help narrow the focus of the overall strategy. Burns & McDonnell has performed many studies as descri bed that have involved a wide range of complexity. This experience includes studies fo r utility clients with multiple unit sites and multiple sites covering SO 2 , NOx, Hg, and particulate emissions along with some current

work that includes CO 2 control as potential regulatory impacts are being assessed. Other studies have been specific single unit evaluations of SCR application onl y that were done to provide the owner a relative cost and impact on the utility operation. In summary, Burns & McDonnell has performed numerous studies of these types over the past thirty plus years, of which SCR technology retrofit was included in near ly every one of them over the past five

years.

• Conceptual designs and cost estimates Typically after the screening level or preliminary study has been performed, many owners need a more definitive and site specific evaluation of the retrofit project for their unit at the site. Burns & McDonnell has performed these evaluations for SCR retrofits; particulate control retrofits including new pul se jet or reverse air fabric filters; electrostatic precipitator projects including rebuilds, upgrad es, conversion to fabric filter, and hot side to cold side conversions; and various SO 2 control alternatives includi ng wet flue gas desulfurization (FGD) or semi-dry FGD, including spray dr yer scrubbers, and circ ulating fluidized bed (CFB) dry scrubbers. FGD technology studies have included processes based on various reagents such as wet lime, wet limestone, ammo nia, lime spray drying, and a few of the more developmental proprietary processes that are fairly new to the market. Also, we have performed evaluations of upgrades to existing particulate and SO 2 removal systems where upgrade and refurbishment is being evaluated along with new equipment system retrofits to look for the best solution comparing capital cost, arrangement, operating costs, outage requirements, and construction constraints. Th e level of detail required or desired by an Owner on this type of project can vary. Some of these projects can extend over 12 months in duration and can involve 20-30% of the design ef fort being complete whereas others are less

detailed and can involve 4-8 mont hs of engineering and evaluation.Responses to Comments 46 September 22, 2008 The main point here is that Bu rns & McDonnell’s experience and expertise is relevant to our role in providing BACT Analysis study repor ts, additional information and responses as inputs to the NDDH’s BACT Determination process. It includes retrofit and new utility and industrial powerplant air polluti on control projects involving SCRs and other technologies,

and involves individuals who a pply process design and operating knowledge, whether they

exist within Burns & McDonnell or are available through tech nology suppliers or consultants, to the specific conditions involved. To suggest that A/E firms provide no value to clients for these projects (Hartenstein, 2008) is personal opinion not based on an informed understanding of project role s and responsibilities nor ut ility owner perspectives.



## Comments by Sargent and Lundy on SCR Experience On page A-31 of Mr. Hartenstein’ s report, Hartenstein calls into question the SCR experience of Sargent and Lundy (S&L). The following respon se to Mr. Hartenstein’s comments has been prepared by Mr. William Deprie st of S&L (Depriest, 2008):

“S&L's involvement in the U.S. Power Industry's SCR program in the late 1990's and 2000's as presented to the NDDH in May 2007 represents NOx reduction

activities associated with the NO x SIP CALL and various projects related to NOx

non-attainment areas in the U.S. These NO X reduction programs represent the vast majority of SCR work in the U.S. during that time frame but it does not include any new unit work or any gas fire d combined cycle work which we would classify in a different category of experi ence. Specifically, we were involved in

53 of 113 units in-service or near to in-s ervice at the time of May 2007 to the best of our knowledge. Again, it is importa nt to note that these NOx programs represent by-far the vast majo rity of SCRs in progress in the U.S. at that time and that S&L was clearly a le ader in this area.

In regard to Mr. Hartenstein's claims to S&L's role on these projects, I have the following comments:Responses to Comments 47 September 22, 2008 • S&L provided all of the process desi gn on the vast majority of our SCR projects. In some cases (6) we "team ed" with another entity with SCR expertise and shared in the process design role.

• S&L specified the process design criteria for the catalyst on all of our projects short of the actual formulation chemistry which is typically proprietary to the catalyst supplier.

• S&L has never made claims to either an S&L guarantee position regarding catalyst performance or direct opera ting experience with SCR systems.”



## Comments on Hans Hartenstein’s Qualifications for Expert SCR Opinions

Enclosure 1 of the EPA’s referenc ed letter (EPA, 2008) included de scriptions of relevant work experience, and the resume Mr. Hans-Ulrich Hart enstein in Appendix D. Mr. Hartenstein also

made numerous statements in his comment s regarding the NDDH’s Preliminary NOx BACT Determination attesting to his considerable technical knowledge and personal experience with the design and operation of SCR systems (Hartenstein, 2008).

According to Burns & McDonnell’s consultant assi sting in these responses to Mr. Hartenstein’s and the EPA’s comments on SCRs, Hartenstein’ s claimed personal expe rience and technical expertise on the design of German SCRs, especially of the tail-end variety, is not what it appears to be (see Appendix A). It is difficult to determine the true extent of Mr. Hartenstein’s SCR technical experience, but his qualifications state that his di rect involvement with SCR technology on coal-fired boilers has largely occurred since 1999 in the United States, not in Germany during the majority of the mentioned SCR retrofits . Mr. Hartenstein’s involvement with SCR technology seems to be mostly bus iness development related.

As Mr. Hartenstein states himsel f on page A-6 of the referenc ed opinion report (2008), he was not involved in SCR retrofits for utility boile rs until 1993. Experience claimed with waste-toenergy LDSCR systems, which are completely di fferent and not comparable to LDSCR systemsResponses to Comments 48 September 22, 2008 on fossil fuel fired boilers, does not transfer eff ectively to the North Dakota lignite cyclone-fired units in question. 

## Fuel Switching While clean fuels may be considered to meet BACT requirements, clean fuels may only be considered when the permit applicant proposes to meet BACT using clean fuels. See Pub. Law No. 101-549, § 403(d), 104 Stat. at 2631 (1990) (U.S. Senate Report of the Committee on Environment and Public Works to Accompa ny S. 1630 (Dec. 20, 1989) discussing the addition

of “clean fuels” to the definition of BA CT in the 1990 Clean Air Act Amendments).

Fuel switching/blending/cleaning was mentione d in the EPA’s comments (EPA, 2008, Enclosure 2) but only fuel cleaning was questioned as a poten tial technique that was not fully considered in the NDDH’s analysis. Fuel cleaning has typically been practiced wher e removal of sulfur, typically as inorganic pyrite form (FeS), is pe rformed by simple density separation methods (“air jigging” in a classifier separate fr om or within coal pulverizers wh ich reject the heavier pieces).

This reduces the amount of sulfur introduced into the furnace and potentially emitted to the downstream gas cleaning equipment.

In Minnkota’s NOx BACT determination case, fuel cleaning would presumably not be attempting to remove nitrogen from the fuel, for reduction of the formation into NO X , as this would be impractical from a solid fuel. Nitroge n oxides are also created from nitrogen in the combustion air being exposed to high temperatures in the cyclone burners. So the issue of fuel cleaning is really one of trying to remove elements in the li gnite besides nitrogen, for the purpose of mitigating other problems associated with th ose specific elements. Thus, it appears that the

EPA and Plains Justice are rais ing this issue in trying to us e fuel cleaning as an “enabling technique” so that SCR technology could be depl oyed without resolving the problems associated those problem elements.

Ash is included in the Center lignite supplied fr om the adjacent mine. Some ash comes from the mineral layers that are above and below the lignite seams as a result of the practical inability to completely separate the lignite from the burde n material during mining. The remainder and majority of ash in the lignite is bound within the co al particles. Reducing the amount of boundResponses to Comments 49 September 22, 2008 ash in the lignite prior to introdu ction to the boiler would not be practical with known methods of fuel cleaning.

In cyclone boilers, ash is not normally problematic if it melts within the cyclone burner barrel

and drains out to become bottom ash. In the ca se of North Dakota lignite-fired cyclone boilers, there is a high amount of ash that is not cap tured and drained from the cyclones and lower furnace as bottom ash. Thus, a higher than typi cal 70:30 bottom ash: flyash ratio for cyclone boilers occurs at MRYS, closer to a 50:50 split. This means that a significant amount of ash is released from the burners as flyash, where these particulates escape and become entrained in the flue gases rising up through the furnace.

As previously discussed in earli er responses, it is sodium and pot assium-related elements that would cause SCR catalyst deactivation. These tr oublesome elements are mostly in forms where they are organically-bound within the coal particles, so simp le “air jigging” classification

methods are believed to be ineffective.

The arguments for coal cleaning also do not cite specific examples where minerals such as sodium and potassium have been removed economically and would not require pilot testing in order to demonstrate that the technology is deve loped sufficiently to be successful for this application



## Non-SCR NOx Controls Plains Justice implies that because various non-SCR NO X reduction technologies have been demonstrated or pilot-tested on any utility bo iler, the control technol ogy would be technically feasible at MRYS. This ignores the differences in specific conditions at the MRYS boilers compared with where the technology has been de monstrated that are pertinent to whether the technology is appropriate and coul d be successful at MRYS.

Successful implementation of NO X controls is highly dependen t on the specific configuration and process conditions that lend themselves to be compatible within the limits of constructability, survivability, and effectiven ess. Just because a control technology isResponses to Comments 50 September 22, 2008 “technically feasible” based on Plains Justice’ s interpretation of the NSR Manual (U.S. EPA, 1990) does not mean it will work e ffectively at MRYS to reduce NO x emissions. Many comments by Plains Justice give the impressi on that they did not review Minnkota’s BACT Analysis study reports (B&McD, 2006), or unders tand the technical reasons why such non-SCR

NO x control technologies were not evaluated for MRYS.

An example of this is Plains Justice’s suggesti on that injection of a fl uxing agent to increase melting of solid combustion products will reduce catalyst poisoning due to a reduced amount of flyash. Superficially, this sounds plausible, but where fluxing agents have been added to coal for reduction of impact on SCR catalyst, it is due to the practice of flyash reinjection or firing of

bituminous coal with low calcium -to-arsenic ratio. For the cycl one boilers firing North Dakota lignite, the fuel and its response to melting is mo re complex than other coals where the use of fluxing agents has been demonstrated as desc ribed. These cyclone boilers are designed specifically to melt the fuel ash in the cyclone burn ers as part of the combustion process. Flyash reinjection is not practiced, and arsenic is not significant in No rth Dakota lignite-fired cyclone boilers; however, sodium is a known catalyst poison a nd is present in abundance in ND lignite.

The problem with Plains Justice’ s argument is that the use of the fluxing agent mentioned would not prevent melting of sodium compounds which crea tes a fine fume that does not get captured in the molten slag. Sodium, in fact, is preferen tially released from the slag that forms in the cyclone burners and lower furnace and is then exhaus ted where it is available to react with sulfur and calcium to foul and deactivate SCR catalysts. This is the main source of sodium that ends up in the boiler’s exhausted flue gas instead of rema ining in the slag. This has been explained in numerous ways by EERC in previous respons es to EPA comments (Minnkota, 2007A, 2007B, 2007C, 2008; B&McD and EERC, 2007 and 2008).

Most of the “commercially available solutions” to facilitate the use of SCR that Plains Justice lists involve coal cleaning and dr ying or beneficiation. MRYS al ready has cyclone lignite drying systems, which are required for preparing the fu el for proper combustion in the cyclone burners. The arguments for coal cleaning also do not cite specific examples where minerals such as sodium and potassium have been removed economically and would not require pilot testing inResponses to Comments 51 September 22, 2008 order to demonstrate that the technology is deve loped sufficiently to be successful for this application.

Minnkota’s BACT Analysis reports and previo us responses to EPA comments (Minnkota, 2007A, 2007B, 2007C, 2008; B&McD, 2006; B&Mc D and EERC, 2007 and 2008) have explained that other non-SCR technologies, such as various forms of enhanced selective noncatalytic reduction (SNCR) with natural gas or coal reburn, low NOx burners, and flue gas recirculation are not appropriate for the operating conditions expe rienced inside the boilers at MRYS. Plains Justice appears to ignore the arguments previ ously presented regarding the expected limitations of effective NO X reduction at MRYS with modest cyclone air-staged combustion compared with lower NO X emissions demonstrated at Ameren’s Sioux plant with deeply staged cyclones using lower furnace urea reagent injection. Oxygen-enhanced combustion, NOx adsorption from flue gases us ing activated coke, and various chemical treatment processes have not been demonstrated on cyclone boilers or lig nite fuels, and thus would require extensive pilot or full-scale testin g in order to assess thei r potential performance and economics. The interpretation of the NSR Manual (U.S. EPA, 1990) noting that requiring extensive pilot or full-scale demonstration of the technology is outsi de the BACT process beyond step 2 has already been presented in pr evious responses (Arfmann and others, 2007).



## Conclusions In the end, EPA’s objections to NDDH’s Prelimin ary BACT Determination may be reduced to disputing NDDH’s characterization of the gas stream characterist ics and the impacts of those

characteristics on boiler and emi ssions control operations. EPA and Hartenstein suggest that these impacts can be resolved by the use of TESCR, and that TESCR technology will work at MRYS (2008). We believe their arguments are flawed because they fail to recognize the significance of these facts:

• There is no prior experience with full-scal e SCR on any unit firing North Dakota lignite.

• Results from the only known example of simu lating SCR catalyst exposure to high-alkali containing flue gases produced from firi ng North Dakota lignite in a cyclone boiler showed severe catalyst blinding and plugging due to sodium and potassium rich speciesResponses to Comments 52 September 22, 2008 (Benson, 2005). Coyote pilot-scale SCR test was intended to evaluate the fouling potential of SCR on lignite coal results. The Coyote test was deve loped by a consortium of three catalyst vendors, EPRI , U.S. DOE, and other particip ants that design and install SCR systems as well as end-user utilities th at have applied SCR on their boilers. This team was competent and Minnkota believes th is testing was valid for its intended purpose. From this sole test, it was determined that there are significant impediments to using SCR on MRYS. Peer-reviewed literature written by many authors has verified that sodium and potassium species ar e fatal to the catalyst life.

• European SCR experience at lignite-fired ut ility boilers has been very limited. One HDSCR installation was at Voitsberg Unit 3 (Austria) and there were HDSCRs on three units at the Bayernwerk Schwandorf plant in Germany. These units were not cyclonefired, the fuel burned was much lower in sodi um than North Dakota lignite, and the units are no longer in operation (see Appendix A).

• There have never been, to the best of our knowledge, any tail-end S CRs applied to coalfired utility boilers burning li gnite, whether in Europe or North America (see Appendix A).

• There have not been, to the best of our knowledge, any TESCRS installed on any coalfired utility boiler anywhere in the worl d since 1991, when the TESCR on the Siersdorf power station in Germany was pl aced into service. Siersdor f did not burn lignite, did not have a Wet FGD system, and has since been decommissioned (see Appendix A). This 17-year span since the last TESCR installation on a coal-fired utility boiler belies EPA’s contention that TESCR has been universally applied and represents BACT for NOx control on a North Dakota lign ite-fired cyclone boiler.

• Contrary to statements made by Mr. Harten stein (2008), there are no currently active or planned TESCR installations in the U.S. on coal-fired utility boilers. PSEG Mercer Station does not have TESCR configuration (i t is LDSCR), and the SCR systems at South Oak Creek Station for WE Energies will also be LDSCR, not TESCR as stated by Hartenstein. The change in SCR type at S outh Oak Creek was made due to the technical incompatibility of full scrubbing Wet FGD and the type of gas-to-gas heat exchangerResponses to Comments 53 September 22, 2008 (GGH) required for TESCR. Neither of thes e plants burn (or will burn) high-sodium lignite (see Appendix A).Responses to Comments 54 September 22, 2008 REFERENCES (sorted in alphabetical order)

Arfmann, D.; Benson, S.A.; Weilert, C.V. prepared for Minnkota Power Cooperative, Inc., Appropriateness of Conducting Pilo t Testing of Selective Cataly tic Reduction (SCR) Technology at Milton R. Young Station Units 1 and 2, Fo r Use In A NOx BACT Analysis, August 14, 2007. Benson, S.A.; Laumb, J.D.; Crocker, C.R.; Pavlish, J.H., SCR Catalyst Performance in Flue Gases Derived from Subbituminous and Lignite Coals. Fuel Process

. Technol

. 2005 , 86 , 577– 613. Benson, S.A.; Laumb, M.L., Ash Behavior in Combustion Systems, Energy Generation Conference, Bismarck, ND, 2007. Benson, S.A.; Rindt, D.K.; Montgomery, G.G.; Sear s, D.R., Microanalytical Characterization of North Dakota Fly Ash; Prepr. Pap.—Am. Chem. Soc., Div. Fuel Chem. 1983 , 28 (2), 213–222. Broske, D., Operation and Maintenance Guidelines for Selective Catalytic Reduction Systems, 1004145, EPRI Final Report, Dec 2003. Burns & McDonnell, NO X Best Available Control Technology Analysis Study for Milton R. Young Station Unit 1 Minnkota Power Coope rative, Inc. and a separate NO X Best Available Control Technology Analysis Study for Milton R. Young Station Unit 2 Square Butte Electric Cooperative, October 2006. Burns & McDonnell and Energy & Envir onmental Research Center (EERC), Information Request (SCR Vendor Query and Attachments), April 2007. Burns & McDonnell and Energy & Environmenta l Research Center (EERC) presentation, Summary of Responses to EPA/DOH Questions on Minnkota Power’s NOx BACT Analysis for Milton R. Young Units 1 & 2

, to North Dakota Department of Health, Environmental Health Section, Division of Air Quality, and United St ates Environmental Protection Agency, May 23, 2007. Chen, J.P.; Buzanowski, M.A.; Yang, R.T.; Cich anowicz, J.E., Deactivation of the Vanadia Catalyst in the Selective Catalytic Reduction Process. J. Air Waste Manage. Assoc. 1990 , 40 , 1403–1409. Copolo, T.K.; Killen, D.C, Gretta, W.J.; Franklin, H.N.; Mukai, M., Low-Dust SCR System Experience for Coal Fired Boilers. Presented at the Electric Power Conference, Mar 4–6, 2003. Depreist, W., Personal Communication, September 2008. Guo, X., Poisoning and Sulfation on Vandia SCR Catalyst. Doctor of Philosophy Dissertation, Department of Chemical Engineerin g, Brigham Young University, August 2006. Hansen, F. Personal Communication, Feb 2007. Hartenstein, H.-U., Enclosure 1 to U.S. EPA Region 8 July 31, 2008 letter to NDDH: Hans Hartenstein’s Expert Opinion Report Feas ibility of SCR Technology for NOx Control Technology for the Milton R. Young Station, Cent er, North Dakota on Behalf of the United States Department of Justice, July 2008.Responses to Comments 55 September 22, 2008 Hartenstein, H-U.; Gutberlet, H.; Licata, A. Utility Experience with SCR in Germany. In Proceedings of the 16th Annual Inte rnational Pittsburgh Coal Conference ; Pittsburgh, PA, Oct 11 – 15, 1999. Hartenstein, H-U; Licata, A., The Applicati on of a Low Temperature Selective Catalytic Reduction System for Municipal & Hazardous Waste Combustors. In Proceedings of the 17th Biennial Waste pr ocessing Conference , ASME, 1996. Hindiyarti, L.; Frandsen, F.; Li vbjerg, H.; Glarborg, P.; Marshall, P., An Exploratory Study of Alkali Sulfate Aerosol Formation During Biomass Combustion. Fuel 2008, 87, 1591–1600. Kling, A.; Andersson, C.; Myringer, A.; Eskilsso n, D.; Jaras, S.G., Alkali Deactivation of HighDust SCR Catalysts Used for NO x Reduction Exposed to Flue Gas from 100-MW-Scale Biofuel and Peat Fired Boilers: Influence of Flue Gas Composition. Applied Catalysis B: Environmental 2007 , 69 , 240–251. Linak, W.P.; Wendt, J.O.L., Trace Metal Transf ormation Mechanisms During Coal Combustion, Fuel , 1994 , 39 , 173–198. Miles, T.R.; Miles, T.R.; Baxter, L.L.; Bryers , R.W.; Jenkins, B.M.; Oden, L.L., Alkali Deposits Found in Biomass Power Plants. A Preliminary Investigation of Their Extent and Nature; Summary Report for National Renewable Ener gy Laboratory Subcontract No. TZ-2-1-1226-1, April 1995. Minnkota Power Cooperative, Inc. and Square Bu tte Electric Cooperative, Responses To EPA Comments NOx BACT Analysis Study Milton R. Young Station Unit 1 and Unit 2 Regarding SCR Technical Feasibility March 15, 2007 (re: U.S. EPA Region 8 letter January 8, 2007), March 19, 2007. ( 2007 A ) Minnkota Power Cooperative, Inc. and Square Bu tte Electric Cooperative, Responses To NDDH and EPA Comments Regarding SCR Technical F easibility and Non-SCR Concerns Milton R. Young Station Unit 1 and Unit 2 NOx BACT Analysis Study April 18, 2007 (re: NDDH letter February 1, 2007 including U.S. EPA Region 8 letter January 26, 2007), April 23, 2007. ( 2007 B ) Minnkota Power Cooperative, Inc. and Square Butte Electric Cooperative Comment and Response To EPA Region 8’s October 4, 2007 Co mment on NDDH BACT Determination at Milton R. Young Station, (re: U.S. EPA Re gion 8 letter October 4, 2007), November, 2007. ( 2007 C ) Minnkota Power Cooperative, Inc. and Squa re Butte Electric C ooperative Additional Information and Discussion of Vendor Responses on SCR Technical Feas ibility North Dakota’s NOx BACT Determination for Milton R. Young Station Units 1 & 2, May 8, 2008. ND Department of Health, Division of Air Quality Preliminary Best Available Control Technology Determination for Cont rol of Nitrogen Oxides for M.R. Young Station Units 1 and 2, June 2008, released for public comment June 3, 2008. Plains Justice letter by Nicole Shalla to Terry L. O’Clair, Director, Division of Air Quality, North Dakota Department of Health, Re: Commen ts on the Preliminary BACT Determination for Control of Nitrogen Oxides for M.R. Young Station Units 1 and 2, July 30, 2008.Responses to Comments 56 September 22, 2008 Raask, E. Mineral Impurities in Coal Combustion ; Hemisphere Publishing Company: Washington, 1985. Rosner, D.E. Transport Processes in Chemically Reacting Flow Systems, Butterworths, Boston, MA 1986. Sarofim, A.F.; Howard, J.B.; Padia, A.S. The Ph ysical Transformation of the Mineral Matter in Pulverized Coal under Simu lated Combustion Conditions. Combust. Sci. Technol. 1977 , 16 , 187–204. Strege, J.R.; Zygarlicke, C.J.; Folkedahl, B.C.; SCR Deactivation in a Full-Scale Cofired Utility Boiler. Fuel 2008 , 87 (7), 1341–1347. Tolbert, S.G.; Benson, S.A. JV Task 117 – Impact of Lignite Properties on Powerspan’s NO x Oxidation System ; Final Report (May 1 – Dec 31, 2007) for U.S. Department of Energy National Energy Technology Laboratory Cooperative Agreement No. DE-FC26-98FT40321, Powerspan, Montana–Dakota Utilities Co., Minnesota Power, Basin Electric Power Cooperative, North Dakota Industrial Commission, a nd Minnkota Power Cooperative, Inc.; EERC Publication 2008- EERC-03-09; Energy & Environmental Resear ch Center: Grand Forks, ND, April 2008. United States Environmental Protection Agency (U.S. EPA or EPA) Region 8 letter by Andrew M. Gaydosh, Assistant Regional Administrator, Office of Enforcement, Compliance and Environmental Justice to Terry L. O’Clair, Director, Division of Ai r Quality, North Dakota Department of Health, Re: Transmittal of EP A’s Comments on North Dakota Department of Health’s Preliminary NO x BACT Determination for Milton R. Young Station, date stamped July 31, 2008 (with Enclosures). Enclosure 2 to U.S. EPA Region 8 July 31, 2008 letter to NDDH: EPA’s Comments on NDDH Preliminary BACT Determination. U.S. EPA New Source Review Workshop Manual, Prevention of Significant Deterioration and Nonattainment Area Permitting, Office of Air Qu ality Planning and Standards, Research Triangle Park, N.C. 27711 (the Dr aft October 1990 “NSR Manual”) Ulvog, P.; Wiemuth, B. Impacts of Texas Lignite Coal on SCR Catalyst Life and Performance Field Data from TXU’s Martin Lake Pl ant, 1004732, EPRI Final Report, Dec 2003. Zheng, Y.; Jensen, A.D.; Johnsson, J.E. Deactivation of V 2 O 5 -WO 3 -TiO 2 SCR Catalyst at a Biomass-Fired Combined Heat and Power Plant; Applied Catalysis B: Environmental 2005 60 , 253–264. Zheng, Y.; Jensen, A.D.; Johnsson, J.E.; Thøgersen, J.R. Deactivation of V 2 O 5 -WO 3 -TiO 2 SCR Catalyst at Biomass Fired Power Plants: Elucid ation of Mechanisms by Lab- and Pilot-Scale Experiments; Applied Catalysis B: Environmental

. 2008 , 83 , 186–194.Responses to Comments September 22, 2008 APPENDIX A

Tackticks, LLC Report “Comments to Enclosure 1 Hans Hart enstein’ Expert Opinion Report”

Tackticks, LLC General Company Information

Resume for Volker Rummenhohl

Resume for Robert E. Johnson

Tackticks LLC SCR Consulting and Process Engineering Reference List, June 2007

## Minnkota Milton R. Young Station NOx BACT

Comments to Enclosure 1 Hans Hartenstein’s Expert Opinion Report

Prepared for Burns & McDonnell Engineers

by:

Tackticks, LLC Volker Rummenhohl, Principal Author Robert Johnson September, 2008- 2 -



## Introduction Mr. Volker Rummenhohl, Tack ticks, LLC, has prepared the following comments to Mr. Hans Hartenstein’s Expert Opinion Repor t pertaining to the “Feasibility of SCR Technology for NOx Control Technology for th e Milton R. Young Station, Center, North Dakota (July 2008).”

The following comments address five general to pics rather than a point by point rebuttal of Mr. Hartenstein’s statements. These five general topics are: Mr. Hartenstein’s qualifications, information not reported by Mr. Hartenstein, incorrect information presented by Mr. Hartenstein, vendor guarant ees and catalyst poisons / pilot tests.

In general, Mr. Hartenstein mainly reports th e opinion of third parties and not his own. In some cases where his own opinion is offered, si gnificant materially-related information is either missing or the information he presents is incorrect. For instance, he mistakenly refers to the SCR systems at PSEG Mercer St ation as tail end systems. Mr. Hartenstein does not have hands on experience with the design, commissioning, operation or maintenance of tail end SCR systems (TESCR) for coal fired boilers. He also does not have experience with design or commissioning of Low Dust SCR systems (LDSCR) for coal fired boilers.

In his report, Mr. Hartenstein focuses entirely on the cataly st and ignores problems that have occurred with the subsystems of a SCR plant. 

## Qualifications As Mr. Hartenstein states himself on page A- 6 of the referenced opinion report, he was not involved with SCR retrofits for utility boi lers until 1993. His direct involvement with SCR technology on coal-fired boile rs has largely occurred si nce 1999 in the United States, not in Germany during the majority of the me ntioned SCR retrofits. Mr. Hartenstein’s involvement with SCR technology seems to be mostly business development related. Experience claimed with waste-to-energy LDSCR systems, which are completely different and not comparable to SCR systems on fossil fuel fired boilers, does not transfer effectively to the units in question. The size is much smaller and this allows the use of different pre heat equipment. All waste-to-ene rgy plants in Europe have either activated carbon injection or fixed bed activated carbon plan ts. Those take out all poisons such as all acidic components, arseni c etc. from the flue gas.

The dead line for the retrofit of SCR systems for fossil fired units was January 1, 1990 in Germany. All but one TESCR system was built and commissioned by that date. The last TESCR system was installed in 1991 at th e 170 MW Siersdorf pow er station, firing bituminous coal, equipped with a dry circulat ing fluidized bed scrubber and electrostatic precipitator with natural gas-fired duct bur ners ahead of the TESCR reactor. Mr. Hartenstein was not involved with that project . The author was responsible for process

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design and commissioning for th e Siersdorf power station’s SCR system constructor. This power station has since been decommissioned and dismantled. 

## Missing information On page A-11, Mr. Hartenstein references the high dust SCR system (HDSCR) that was installed in 1990 at the Voitsberg Power Statio n in Austria. This paragraph concludes with the implication that lignite-fired boilers are among the 30,000 MW of SCR systems installed in Europe. However, Mr. Hartenst ein does not offer the information that more than 20,000 MW of lignite fired units in Germ any were not required to install SCR in order to comply with the national regulation. These units were exempted from the regulation despite the fact that they would not achieve the required emission limit of 200 mg/Nm 3 . It should be noted that high dust SCR systems were installed and operated at the lignite-fired Bayernwerk Schwandorf pl ant in Germany. The units fired a Czech lignite and were decommissioned in the late 1990s. Voitsberg Unit 3 and the units at the Bayernwerk Schwandorf plant in Germany, whic h were not cyclone-fired, have been the only SCRs ever to operate on European lignite, and the fuel they burned was much lower in sodium than contained in North Dakota lignite. To the best of my knowledge, there have been no TESCRs built nor are any curr ently operating anywhere in the world on lignite-fired utility boilers.

Mr. Hartenstein also did not state in his re port that Germany had only one cyclone-fired (slag tap) unit with a SCR system. This unit is Walsum 7, the NOx emissions control system is a LDSCR, and the unit does not burn lignite.

Mr. Hartenstein also did not explain that the Voitsberg lignite -fired dry-bottom pulverized coal unit operated only for a very short period of time with high dust SCR, before the boiler was taken out of business and decommissioned. The power station does not exist any longer.

Mr. Hartenstein also fails to explain that on util ity boilers you cannot send saturated gas from the scrubber to the gas-gas heat exch ange (GGH) for the TESCR. The gypsum in the flue gas will deposit on the SCR GGH su rface and lead to a fast pressure drop increase. It is extremely difficult or impossi ble to clean this duri ng an outage. The FGD GGHs are frequently washed with liquid wate r during operation, which keeps them clean.

Mr. Hartenstein, on page A-10 of his report, displays a diagram purporting to be the configuration of a TESCR downstr eam of a wet FGD system. Wh at he fails to explain is that there is no TESCR on any utility boiler anywhere in the world that uses this configuration successfully downs tream of a wet FGD. For the reasons noted above, the GGH of the TESCR cannot accept the flue gas imme diately from the F GD without reheat. This diagram offered by Mr. Hartenstein re presents an infeasible configuration.

Mr. Hartenstein reports on page A-50 re garding the “We Ener gies South Otter ( sic ) Creek Generating Station” and implies that this S CR project proves the viability of TESCR. He fails to explain that for this project, which is located at the South Oak Creek plant,

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Alstom and Howden, which are the main GGH suppliers for the SCR market, both required that the flue gas be free of moisture droplets and preheated to allow the use of TESCR. Otherwise they would not offer performance guarantees. This particular project has now changed the SCR system to a LDSCR due, in part, to issues related to the GGH.

In the German TESCR installations, a rotary GGH could be used because the required FGD removal efficiency was about 80% , and the flue gas leaving the FGD could be reheated with bypass or by other means prior to entering the GGH for the TESCR. This is confirmed by the data shown in the boile r process flow diagram from an operating utility boiler plant shown by Mr. Hartenstein on page A-49 of his report. It is clearly seen that the flue gas te mperature entering the GGH for the TESCR is 87 °C, or more than 30 degrees C above the saturated flue gas temperature at the FGD absorber outlet (typically 55 °C). Obviously, although not sh own on his diagram, th e flue gas at this plant has been reheated prior to the inlet to the TESCR GGH. The FGD systems in Germany typically use an “FGD GGH” to accomplish this reheat. However, leakage across the FGD GGH makes a rotary GGH infe asible for TESCR systems following high SO 2 removal efficiency FGD systems, as required in the U.S.

Mr. Hartenstein references several times the “ill-designed” pilot test plant that was conducted at the Coyote Stati on. However, he does not o ffer a single reason why the pilot plant was “ill-designed”. 

## Incorrect Information Mr. Hartenstein states, on page A-9, that no flue gas re-heating is typically required for HDSCR and LDSCR. This is incorrect. Th e majority of the units cannot maintain minimum operating temperature over the enti re load range, therefore reheating with economizer bypass, split economizer or duct burne rs is necessary. Ve ctren installed duct burners on four units.

Denmark and the Netherlands did not have S CR by the end of the 80s, as stated by Mr. Hartenstein on page A-11.

While rotary, tubular and plate type heat exch angers have been used for re-heating flue gas, as noted by Mr. Hartenstein on page A-12, not a single coal fi red unit with a LDSCR or TESCR system has a heat exchanger other th an rotary. As discussed above, this poses a problem with fouling and leakage when locat ed directly downstream of a wet scrubber without reheat.

Mr. Hartenstein states on page A-12 for turbine limited units: “In this case, the heat rate penalty of the unit may be eliminated completely”. This is complete nonsense. There will still be a penalty since more heat input is necessary for the same electrical output.

Mr. Hartenstein states on page A-13 that it can reasonably be assumed that the retrofit cost today would be the same as stated in an EPRI report from 1989. The cost for rotary heat exchangers for LDSCR and TESCR are much higher today.

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Further, Mr. Hartenstein states on the same page that TESCR technology was “generally adopted as a universally applicable SCR so lution for all types...” There has never been another TESCR built after Siersdorf, which wa s finished in early 1991, in the US or Europe.

The following is an excerpt from page A- 19 of Mr. Hartenstein’s report concerning minimum operating temperature:

“As a matter of fact, the only thing that di ctates the minimum SC R operating temperature are the residual SO 2 and SO 3 concentrations in the flue gas, which determine the ABS reaction equilibrium 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 H 2 O, SO 3 and NH 3 in the flue gas at various temperatures.”

It is factually incorrect that th e temperature depends only on the SO 2 and SO 3 concentration of the flue gas. It is independent of the SO 2 concentration. Minimum operating temperature depends primarily on the SO 3 , ammonia and moisture concentrations in the flue gas. Catalyst fouling is only reversib le if no calcium has reacted with the ammonium bisulfate. On ce that has happened it becomes irreversible.

On page A-19, Mr. Hartenstein states:

“The reaction equilibrium betw een ammonium sulfate ((NH 4 )2SO 4 ) and ammonium hydrogen sulfate (NH 4 HSO 4 ), which is often incorrectly referred to as ammonium bisulfate or ABS, in the flu e gas. Both ammonium su lfate and ammonium hydrogen sulfate are products of the inevitable re action of gaseous sulfur trioxide (SO 3 ) and ammonia (NH 3 ) contained in the flue gas ups tream of the SCR catalyst.”

Ammonium hydrogen sulfate is a differe nt name for ammonium bisulfate.

Mr. Hartenstein discusses, on page A-22, “Ceram’s extensive experience with lignite..” With only one plant with CERAM catalyst having operated for a short period of time on lignite and a few pilot programs, it is im possible to say that CERAM has extensive experience on lignite fired plants.

Mr. Hartenstein devotes an enti re section to soluble sodium (Section 6.3, page A-27). He notes in the second paragraph a statement from one of the catalyst suppliers that sodium is not a catalyst poison at S CR operating temperatures.

Yet, on page 5 of the technical paper, “U tility Experience with SCR in Germany,” presented at the Sixteenth Annual Internati onal Pittsburgh Coal C onference in October, 1999, Mr. Hartenstein and his co-authors reported SCR catalyst deactivation due to

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sodium at the RWE Staudinger plant in German y. Specifically, it is reported on page 5 that “...the fly ash from the German coal formed highly adhesive deposits, while the portion of South African coal contributed to the formation of a liquefied fly ash. The reason for this was determined by a chemical analysis of the fly ash. It can be seen that the content of the alkali su lfate, which adheres to the su rface of the fly ash particles, favors the tendency to agglomerate. A phase an alysis of the deposits revealed crystalline sodium aluminum sulfate and potas sium aluminum sulfate (NaAl(SO 4 ) 2 ;KAl(SO 4 ) 2 ).”

This information would tend to support the Department’s opi nion related to the formation of sodium–related deposits on the SCR catal yst and accelerate the deactivation of the catalysts. This information would also tend to conflict with Mr. Hartenstein’s statement, on page A-28 of his expert report, that the “...the intrusion of liquid pyrosulfates is no major concern with respect to a se vere, rapid catalyst deactivation.”

Mr. Hartenstein states on page A-29:

“...of less than seventy two (72) hours, SC R reactors are typically “buttoned up hot,” which means the SCR reactor is isolated fr om the flue gas path dur ing shut down by means of putting it in a bypass mode while the SCR is still at its design operating temperature. The cooling rate of such 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 conde nsation temperature in a seventy two (72) hour period.”

This is a statement, which is incorrect and must be based on the lack of practical experience. I have been involved in severa l measurements of cool down rates for SCR units. The rate differs in a range between five and ten degree Fahrenheit per hour depending on the quality of the dampers and th e insulation, the unit size, catalyst volume installed and the ambient conditio ns. It must also be cons idered that the boiler is operated at low loads before during the s hut down phase. This means the starting temperature is already very low. Almost al l units are below the aci d dew point after 72 hours and most of them at the water dew point.

Mr. Hartenstein takes exception to the De partment’s statement on page A-29, as excerpted below:

“The Department concludes that “the flue gas generated at M.R. Young Station is different from the flue at any plant wher e SCR technology has been applied.” The absoluteness of this statement, which is not even limited to power plans, is quite amazing as it indubitably implies that the Department has complete detailed knowledge not only of the 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

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strongly suggests that this may be highl y questionable and largely overreaching. As a matter of fact, I am sure that I could easi ly 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.”

The statement of the Department can be eas ily supported since ther e is not a single SCR system in operation on a lignite fired boiler in the United Stat es, nor in Europe, at this time.

The statements on pages A-31 and A-32 th at Burns & McDonnell never has given a guarantee and never provided process design are incorrect.

On page A-32, Mr. Hartenstein states:

“As a matter of fact, all catalyst re lated performance guarantees (NOx removal efficiency or activity, SO 2 /SO 3 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 ca talyst performance guarantees obtained from the catalyst manufacturers to the end customer. And at le ast two (2) of these catalyst manufacturers, namel y Haldor Topsoe and CERAM were clearly willing to provide industry standard type performance guarantees for their catalyst.”

This statement can only be explained by a la ck of involvement in the design of SCR plants. Catalyst performance guarantees are not always a pass through from the system supplier. Depending on the contract, there are a lot of other issues that are not done by the catalyst supplier. Distri butions, pop-corn ash screens, control system, and analyzer system all impact the performance of the S CR catalyst but may not be guaranteed by the catalyst supplier. These are typically warranted by the system supplier.

On page A-39, Mr. Hartenstein states:

“Yet, the most successful SCR retrofits in the U.S. were done as turn-key installations without the use of an A/E.”

There are certainly many examples of successf ul SCR projects which were executed on different contractual conditions.

Mr. Hartenstein states on page A-50 that the SCR systems at PSE&G Mercer Generating Station are TESCR. This is incorrect. Both SCR systems at this plant are LDSCR with flue gas re-heating. Mr. Hartenstein also states that the SCR systems at WE Energy South Oak Creek Station will be TESCR. This is also incorrect. South Oak Creek started out as TESCR, but technical difficulties have forced the change to a LDSCR.

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## Vendor Guarantees Mr. Hartenstein frequently states that vari ous catalyst and SCR system vendors would be willing to offer performance guarantees for the Milton R. Young Station SCR. It is typical for vendors to do this in the absence of a detailed specificat ion and contract with commercial conditions and liquidated damage s. Performance guara ntees will only be offered once all technical issues and challenge s have been identified and addressed in the system specification. The vendors will not present performance guarantees for negotiation without having assessed their risk mitigation strategy.

A recent example of this occurred on the retrof it of SCR systems on two units in Florida. Three catalyst vendors provided totally differe nt sets of preliminary guarantees at the beginning of the project. All three supplie rs changed their guarantees after a 2,000 hour pilot test significantly identified the effects of various fuels on the expected performance of the catalyst.

Another example occurred several years ago on three SCR units in Pennsylvania. Two catalyst suppliers (Haldor Topsoe and CE RAM) provided guarantees based on their experience with similar coals, but were very surprised about the rapid deactivation of the catalyst. These companies are those most c ited in Mr. Hartenstein’s paper. The money the utility received in a settlement with the turn key supplier was a very small fraction of the long term operating costs ab sorbed by the Utility to ma intain SCR system operation. 

## Catalyst Poisons and Pilot Projects In many cases where SCR technology has been a pplied to fossil fuel-f ired boilers located throughout the world burning a variety of coals and solid petroleum byproducts,extensive pilot testing programs have been performed prior to implementation on fullscale power plants: Germany in the 1980’s, Un ited States in 1980’s, and in Texas since year 2002.

There are two pilot tests and one R&D program in which the author was involved with in Germany. The results of these programs emphasize the importance of understanding design and process issues for certa in applications. These also demonstrated that it is very difficult to solely rely on experi ence with similar coals and boilers.

The first was a pilot program for a high dus t SCR on a wet bottom boiler at the Franken power station in Germany. This was before the first HDSCRs were built in Germany. All catalyst suppliers said that it would be unnecessary to conduct a test program, since these companies had sufficient experience basis fr om the units in Japan. It turned out that the catalyst deactivated rapidly. Some catalys t types lost almost al l of their activity in just 200 hours. At this tim e, arsenic was not known to be an issue for the catalyst because it had not been observed in the Japane se SCR systems. The pilot test revealed the fact that arsenic is a heavy catalyst poison. Most of the utilities decided not to retrofit wet bottom boilers that had fly ash recircula tion with a HDSCR so th at arsenic poisoning could be avoided.

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The second pilot program was in the Reuter power station in Ber lin. The author was involved in a pilot plant that included a wet scrubber and a TESCR. The result was that it is impossible to have saturated flue ga s going to the GGH of the TESCR without drying and pre heating it. The gypsum in the flue gas plugged the TESCR GGH with no means to clean it. The temperatures are too high to clean it with liquid wate r as it is frequently done on the FGD GGHs.

Utilities built TESCRs in Germany to avoid the arsenic problems. Everybody thought that an indefinite catalyst lifetime could be e xpected. It was even more surprising to see that the first layer on which activity was meas ured lost more than 50 % activity in less than 2,000 hours. Again, a new catalyst poison was detect ed. It was SiF 4 , a gaseous component which forms on the plates of the FG D rotary heat exchanger in a reaction of SiO 2 , H 2 SO 4 and HF. It was an R&D project of several million dollars to detect the poison, the formation mechanism and the solu tion. Lime was injected upstream of the FGD, which bound the sulfuric acid on the GGH plates. The capital cost of the lime system is certainly not include d in the EPRI cost reports referenced by Mr. Hartenstein.

See:

German Experience Sheds Light on SCR O&M Issues , September 1992 issue of Power magazine, Coauthor. (attached).

The author also participated in a more rece nt pilot test program for a Southeast U.S. Utility. At this particular plant, a proposed SCR system had to be designed for three very different fuels: East ern bituminous, Venezuelan coal and pet coke. Due to very stringent permit conditions related to NOx, NH 3 and SO 3 emissions, the SCR system and catalyst had to account for the influences of the fuel on the NOx activity and SO 2 oxidation rates of the catalyst. With limited worldwide experi ence on such a range of fuels, the Utility decided to conduct an extensive pilot program to assess impact s on the cataly st. All three suppliers changed their guara ntees after a 2,000 hour pilot test identified significant effects of the various fuels on the expected pe rformance of the catalyst. This SCR is not yet operational.

The EPA also fails to recogni ze and acknowledge that significant pilot testing has been conducted at two power plants in Texas that fi re lignite supplied from various locations in Texas, and that there are no cyclone-fired bo ilers in Texas. The EPA has gone down the same path that tried to compare German SCR applications, which lack significant cyclone boiler experience and is not currently required for lignite-f ired boilers, to be appropriate and comparable to North Dakota lignite-fired cyclone burner units. These are misleading statements and contrary to the presenta tion of the body of information submitted in support of the NDDH’s preliminary BACT determination for MRYS.

These examples emphasize the importance of understanding the intricate process design issues that will influence SCR performance. The industry has benefitted from the many

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pilot test programs that have been conducted to implement SCR technology when new and unknown process issues have been raised. In the case of Milton R Young, the uncertainty associated with the high sodium concentration and the presence of sodium aerosols in the flue gas raise qu estions pertaining to catalyst performance. Pilot testing is certainly warranted.

Mr. Hartenstein and his co-aut hors support pilo t programs for those SCR applications in which new and uncertain process consideratio ns are encountered. On page 2 of the technical paper, “Utility Experience with S CR in Germany,” presen ted at the Sixteenth Annual International Pittsburgh Coal Conf erence in October, 1999, Mr. Hartenstein states: “In principle, the reduction of NOx emi ssions with SCR catalysts is a mature technology, which was developed many years ago. Nevertheless, experience has shown that in many applications, special features were required that necessitate further optimization of the DeNOx system. In parti cular, standard solutions were often not possible or optimal when retr ofitting existing power plants.”

Mr. Hartenstein implies, on page A-36 of his re port, that catalyst that has been poisoned by sodium compounds can be regenerated in-s itu, and that this technique is well developed. Regarding the contention of Hartenstein, there is extremely limited experience with in-situ catalyst cleaning on coal-fired units. ENBW in Germany developed this technique, but it has never had a commercial success. It also has never been used for blinded or chemically poisoned catalyst, but only for mechanically plugged catalyst.

The possible application of any SCR technolog y at Milton R. Young is not standard, due to the special considerations pertaining to the lignite, boiler operati ng temperatures, flue gas reheating, among others.

Comments to Enclosure 1 Hans Ha rtenstein’s Expert Opinion Report Prepared by Tackticks, LLC (September 2008)12 General Company Information:

Principal Company Address:

Tackticks, LLC 247 Booth Meadow Lane Durham, NC 27713

Phone #: 919 – 484 – 1500 Fax#: 919 – 484 – 1544

President: Volker Rummenhohl vrummenhohl@tackticks.com

Regional: Robert E. Johnson rjohnson@tackticks.com 913 – 897 – 07273 Tackticks, LLC

1.1 General Company Description

Tackticks, LLC has a broad range of engineering ex perience with SCR systems and related power plant operations. Tackticks, LLC was formed in 2001 by Volker Rummenhohl after working withi n the SCR industry for almo st twenty years, first in Europe then in the US. Tackticks has been involved wit h SCR’s using gas, coal, oil and all types of waste fuel used in boilers, simple cycle and combined cycle systems and incinerators.

The company’s primary focus is optimizing process design, catalyst selection and performance of SCR systems on coal-fir ed boilers. The company’s clients are Electric Utilities, Inde pendent Power Producers, Arch itect & Engineers, OEM's and component suppliers. Tackticks has also been involved in the design of SCR systems, start ups, ammonia injection grid tuning, performance testing, trouble shooting and O & M support.

Tackticks, LLC has special experien ce with the design, operation and maintenance support of operating units with generation exceed ing 15,000 MW. The company’s services are targeted to minimize the operati ng costs of the SCR system, to diagnose operat ing problems, to enhance ov erall performance and to assist Clients in managing the most comprehensive catalyst strategies.

The involvement in the SCR strategy c ontracts enables Tackticks, LLC to be at the front of technology advancement and development.

Tackticks, LLC also currently owns seve nty five percent of the flow modeling company FlowTack, LLC. FlowTack, LL C performs CFD and physical flow models for all kind of technologies. Among those technologies is of course also the SCR technology. FlowTack also designs ammonia injection grids for SCR systems.4 General Description of Services

The following is a general description of Tackticks’ services:

Process Design

Tackticks can assist Clients define the appropriate SCR desi gn parameters. Historical boiler operating data will be re viewed and assessed to determine unit process data at full, mid and low loads. Tackticks can assist Clients in selecting SCR catalyst performance requirements so that the Client ’s NOx emission control strategy is effectively met wit h minimum negative impact due to ammonia slip and SO2 oxidation.

Tackticks will help define process distribu tion requirements so that long term performance and operational demands are met.

SCR Arrangement

Tackticks can assist Clients in determini ng preliminary SCR arrangements and reviewing initial design crit eria. With the use of Co mputational Fluid Dynamics modeling, Tackticks can recommend optimal arrangements of duct configuration and flow correction devices in order to maintain appropriate flue gas velocities, velocity distribution, fly ash distributi on and ammonia to NOx distribution within the SCR system.

Specification Review & Preparation

Tackticks can assist Clients by reviewin g turnkey specifications with special attention paid to, but not limited to, design data, guarantees, process design, equipment, catalyst design, potential im pacts on boiler and unit operation.

Tackticks can also prepare technical spec ifications for Clients. Our company focus is generally applied to catalyst se lection, ammonia injection grid design, flow modeling and flow co rrection requirements, r eagent system requirements and performance guarantees.

Proposal Evaluation

Tackticks has also evaluated proposals for Clients. The company’s assistance in this area can range from a complete te chnical assessment of a proposed design and its compliance with the specification to an analysis of a specific technical issue. Tackticks will assist in the devel opment of evaluation cr iteria, preparation of questions to the suppliers, and recommendat ion of the most qu alified supplier.5 SCR Troubleshooting and Optimization

Tackticks can assist Operat ors in solving current operational issues and suggesting improvements to the SCR system in order to enhance overall performance. Services include systems audits, ammonia injection grid tuning, catalyst testing and system inspections.

Requirements for Annual SCR Operation

Tackticks can review SCR operational procedures to ensure appropriateness for annual operation. This includes all oper ating sub-systems of the SCR system. Tackticks can evaluate seasonal catalyst performance and update for year-round operation. Catalyst management plans can be updated accordingly to coincide with unit outage schedules.6 Volker Rummenhohl 247 Booth Meadow Lane Durham, NC 27713-5810

Work Experience:

FlowTack, LLC Manager January 2004 – Present Mr. Rummenhohl manages FlowTack, LLC a flow model and computational fluid dynamics company.

Tackticks, LLC President February 2001 - Present Mr. Rummenhohl is currently the president of Ta ckticks, LLC, a consulting firm located in Durham, North Carolina. Tackticks provides pr ocess consulting for air quality control systems and specializes in SCR systems. Consulting work includes review of arrangement drawings, writing and reviewing air quality specifications, general process consulting, training, and support during project startup. Mr. Rummenhohl continues to consult with Black & Veatch on the evaluation and design of SCR projects.

STEAG AG Manager, North America September 1993 – February 2001 Mr. Rummenhohl was the Manager of STEAG AG’s liaison office in Durham, North Carolina. His responsibilit ies include market ing and implementing the company’s experience and expertise in designing, engineering, startup, commissioning, and performance testing of Selective Cataly tic Reduction (SCR) systems in North America. During his time in this position, Mr. Rummenhohl has consulted for a number of U.S. utilities, architectural and engineering firms, and manufacturers, conducted seminars, and presented oral and written testimony for regulatory agencies. He was located in the United States to consult with Black & Veatch on the evaluation and design of domestic SCR projects.

STEAG AG Division Manager, Environmental Engineering Group January 1990 - August 1993 Duties included the maintenance and continued im provement / optimization of SCR systems for over 5,300 MW of coal fueled electric and cogeneration capacity owned and operated by STEAG. These systems have now been in operation for in excess of 600,000 cumulative hours. Additionally, Mr. Rummenhohl was resp onsible for the design and engineering of SCR plants. This includes the three SCR plants for the residual oil fired power station Leuna.7 Lentjes AG Project Engineer and Manager 1983 – 1990 Lentjes AG is one of Germany’s largest designers, engineers, and constructors of SCR systems. In the position of project engineer and manager, Mr. Rummenhohl was involved in the design, engineering, procurement, construction, and commissioning of over $600 million of SCR systems thro ughout Germany. Responsibilities included supervision of the startup and commissioning of SCR retrofit systems for 2,200 MW.

University of Dortmund 1981 - 1983 Mr. Rummenhohl is a 1981 graduate engineer with an advanced degree in chemical engineering (“Diplom Ingenieur,” comparable to a U.S. Master of Science degree) from the University of Dortmund. Afte r graduation, Mr. Rummenhohl taught as an Assistant Professor for a period of two years at the University.

U.S. Technical Papers

Pre Heater Pluggage Issues , presented at the 2006 NOx Round Table, Charlotte, NC, January, 2006, Author.

Start-Up and Shutdown of SCR Systems Im pact on the Lifetime of the Systems

, presented at the 24 th Annual Electric Utility Chemistr y Workshop at the University of Illinois, May 11-13, 2004, Author.

Effective Catalyst and SCR System Management, presented at the 24 th Annual Electric Utility Chemistry Workshop at the University of Illinois, May 11-13, 2004, Coauthor.

SCR Experience on High Sulfur Fuel, presented at the 2003 NOx Round Table, Birmingham, AL January 28-30, 2003, Author.

Design & Initial Start Up Results from the New Madrid SCR Retrofit Project, presented at the ICAC Forum 2000, Wash ington, DC March 20-24, 2000, Coauthor.

Economic Alternatives for Effective NO x Emissions Reduction , presented at the DOE SCR and SNCR NO x Emission Controls Conference, Pittsburgh, Pennsylvania, May 15-16, 1997, Coauthor.

Helping the Utility Compete and Comply: Lessons Learned Lead to Informed Decision-making for NO x Emissions Reductions , presented at the PowerGen Americas Conference Anaheim, Califor nia, December 5-7, 1995, Coauthor.

Effects on Catalytic Activity and SO 2 / SO 3 Conversion of DeNO x Catalytic Converters Downstream of Oil-Fired Power Plants: Causes and Remedial Measures , presented at EPRI/EPA 1993 Joint Symposium on Stationary NO x Control, Miami, Florida, May 24-27, 1993, Coauthor.

SNCR, SCR and Hybrid Systems Capabilities, Limitations, and Cost , presented at EPRI/EPA 1995 Joint Symposium on Stationary Combustion NO x Control, May 16- 19, 1995, Coauthor.

The Impact of SCR and SNCR Systems on Plant Equipment and Operations

, presented at the ICAC NO x Emissions Control Conference, Arlington, Virginia, November 2, 1994, Coauthor.8 Relating the German DeNO x Experience to U.S. Power Plants : Lessons Learned from More Than 30,000 MW of DeNO x Retrofits, presented at the ASME Joint International Power Generation Conference, Phoenix, Arizona, October 3, 1994 Coauthor.

The Effects of Various Parameters on SCR System Cost , presented at the PowerGen Americas ’93 Conference, Dallas, Te xas, November 17, 1993, Coauthor.

Alternative NO x Emission Reduction System Comparison , presented at the 1993 USDOE Coal-Fired Power Plant Upgrade Conference, Warsaw, Poland, June 17, 1993, Coauthor.

German Experience Sheds Light on SCR O&M Issues , September 1992 issue of Power magazine, Coauthor.9 ROBERT E. JOHNSON

PROFESSIONAL EXPERIENCE

Mar 2007 – Present Tackticks, LLC – Durham, NC Air Pollution Control Consultant -- Sp ecific focus on Selective Catalytic Reduction (SCR) technology and applications. Principal responsibilities include SCR process design analysis and recommendations, Flow Modeling Analysis, SCR performance evaluation, ammonia injection grid design and tuning, SCR system inspections. 2003 – Feb 2007 Burns & McDonnell Engineers – Kansas City, MO

SCR Program Manager – Responsible for promoting BMcD’s SCRrelated activities within the Power Industry. Provided technical consultation on in-house projects to Clients and Project Teams as well as assisting Clients with oper ating performance evaluations.

Major Accomplishments

• Member of the Team that secured a major SCR design engineering project from a major Midwestern Cooperative.

• Lead technical advisor for ten (10) SCR projects.

1996 – 2003 C & I Ceramics USA – Alpharetta, GA (formerly Siemens Power Generation)

Vice-President, Sales – Responsible for Sales of Siemens’ SCR Catalysts to the Power Industry

Major Accomplishments

• Negotiated systemwide agreements wi th three U.S. Utilities for the supply of SCR catalyst for SIP-related compliance projects.

• Successfully negotiated contracts with other Utilities for similar projects.

• Total Sales in excess of $300 million.

1989 – 1996 Wahlco Environmental Systems – Leawood, Kansas

Vice President of New Technologies – Responsible for the commercialization and market development of Wahlco’s NOx emission control technology. Coordinated te chnology assessment and research activities.

Major Accomplishments

• Sold Wahlco’s first commercial Staged NOx Reduction System on a gas-fired boiler.

• Negotiated partnerships with key participants in demonstration programs for Staged NOx Reduction System. Instrumental in selecting customers for demonstrat ion sites; successfully negotiated first demonstration on a coal-fired boiler.10 • Negotiated first commercial flue gas conditioning installations on a coal-fired cogeneration plant, a hot-side electrostatic precipitator, and the industry’s first baghouse application.

1983 – 1989 Belco Technologies Corporation – Parsippany, New Jersey

Regional Manager – Directed air pollution control equipment sales for special projects involving new accounts and existing customers with emphasis on flue gas conditioning and microprocessor based control systems.

Major Accomplishments

• Sold Company’s first flue gas conditioning system, first precipitator rebuild on a cement kiln, and first new precipitator installation on a cement kiln.

• Sold $2 million of equipment upgrades, control systems and parts.

1983 Israel Electric Company – Independent Consultant

1977 – 1982 Apollo Technologies, Inc. – Regional Manager, Technical Services

EDUCATION Bachelor of Science, Fairleigh Dickinson University, 1976 Bachelor of Arts, University of Notre Dame, 1975

Technical Papers & Presentations

"Selective Catalytic Reduction Performance Project at Public Service Electric and Gas Company's Mercer Generating Station Unit No. 2;" Wallace, Gibbons et al., presented at EPRI/EPA 1995 Joint Symposium on Stationary Combustion NOx Control, May 16-19, 1995, Kansas City Missouri

"Selective Catalytic Reduction: Successful Commercial Performance on Two U.S. Coal-Fired Boilers;" Wagner, Bullock et al; presented at EPRI-DOE-EPA Combined Utility Air Pollutant Control Symposium, The Mega Symposium, August 25-29, 1997, Washington, D.C.

"SCR For a 460 MW Coal Fueled Unit: Stanton Unit 2 Design, Startup, and Operation;" Cochran, Scarlett et al; presented at EPRI-DOE-EPA Combined Utility Air Po llutant Control Symposium, The Mega Symposium, August 25-29, 1997, Washington, D.C.

"Current Practices for Monitoring Ammonia S lip from SCR Processes;" Sigling, Johnson; presented at FETC 1998 Conference on SCR and SNCR for NOx Control, May, 1998, Pittsburgh, Pennsylvania

"Powder River Basin (PRB) Coal and High Arsenic C oncentrations: Catalyst Specific Issues and Operating Experience;" Rigby, Hums et al.; pres ented at EPRI Workshop on Selective Catalytic Reduction, April 18-21, 2000, Memphis, Tennessee

"SCR Catalyst Design Issues and Operating Experience: Coals with High Arsenic Concentrations and Coals from the Powder River Ba sin;" Rigby, Sigling, et al; presented at The International Joint Power Generation Conferen ce, July 23-28, 2000, Miami Beach, Florida11 "U.S. Utility Coal-Fired Selective Catalytic Reduction Applications: SCR Catalyst-Specific Issues and Operating Experience;" Sigling, Johnson; pr esented at EPRI 2001 Workshop on Selective Catalytic Reduction, November 13-15, 2001, Baltimore, Maryland

"U.S. Utility Coal-Fired SCR Ap plications: SCR Catalyst-Spec ific Issues and Operating Experiences;" Sigling, Johnson; presented at ICAC Forum 2002, February, 2002, Houston, Texas

"SCR Catalyst Performance: New Information fo r U.S. Operators;" Sigling, Johnson; presented at EPRI 2002 Workshop on Selective Catalytic Reduction; October 16, 2002, Atlanta, Georgia

"Peak SCR Performance Requires Consolidated Program Management;" presented at Electric Power 2004, April 1, 2004, Baltimore, Maryland

"SCR Update for Simple Cycle Gas Turbine Applications;" presented at Power Gen International 2004, December, 2004, Orlando, Florida

"Selective Catalytic Reduction System Desi gn Considerations;" presented at Power Gen International 2004, December, 2004, Orlando, Florida

“Selective Catalytic Reduction System Desi gn Considerations;” presented at the 110 th Plant Design and Operating Committee, January, 2005, Fort Worth, Texas

“SCR Program Management;” presented at the 110 th Plant Design and Operating Committee, January, 2005, Fort Worth, Texas

“How Can You Maximize Results from Your SCR Catalyst Replacement?” presented at Burns & McDonnell 2006 Coal Symposium, Ap ril, 2006, Kansas City, Missouri

“SCR Program Management: A Powerful Program to Enhance Plant Operations;” presented at the 57 th Annual Generation Conference, Association of Rural Electric Generating Cooperatives, June, 2006, Cincinnati, Ohio

“Thomas Hill Unit 3 SCR Retrofit Design Approach Avoi ds Increases in Dra ft Loss;” presented at Coal Gen 2006, August, 2006, Cincinnati, Ohio

“SCR Technology for Coal Fired Boilers: De sign Considerations for Proper Performance;” presented at Power Gen Asia, September, 2006, Hong Kong

“Environmental Controls Retrofit Project at AECI Thomas Hill Ener gy Center;” presented at EPRI 2006 Workshop on SCR, November, 2006, Dearborn, Michigan

“Thomas Hill Unit 3 SCR Retrofit Design Approach Avoi ds Increases in Dra ft Loss;” presented at Power Gen International 2006, November, 2006, Orlando, Florida12Tackticks LLC SCR Consulting and Process Engineering Reference ListJune, 2007Plant Size MW Fuel Utility/IPP Time ServiceProvidedRemarksNew Madrid 1 600 PRB Coal AECI 2001 High DustStuart 1-4 4*600 Bit. Coal Dayton Power & Light 2001 - High DustKillen 2 600 Bit. Coal Dayton Power & Light 2001 - Low Dust/ Hot ESPCully 3 265 Bit. Coal VECTREN 2001 - 2003 High DustWarrick 4 325 Bit. Coal VECTREN 2001 - High DustBrown 1 265 Bit. Coal VECTREN 2002 - High DustBrown 2 265 Bit. Coal VECTREN 2001 - High DustDesert Basin (Trouble Shooting)180 Gas Reliant Energy 2001 HRSGMichigan City 12 540 PRB/Bit. Blend NIPSCO 2001 - 2003 High DustShafer 14 540 Bit. Coal NIPSCO 2001 - High DustBailly 8 420 High Sulfur Coal NIPSCO 2002 - High DustDallman 31 & 32 2 * 85 High Sulfur CoalCWLP Springfield 2001 - 2003 High DustDallman 33 150 High Sulfur Coal CWLPSpringfield 2001 - 2003 High DustLambton 3 & 4 2 * 500 High Sulfur Coal Ontario Power Generation 2001 - 2003 High DustNanticoke 7 & 8 2 * 500 PRB/ Bit. Blend Ontario Power Generation 2001 - High DustE.D. Edwards 3 365 Bit. Coal Ameren Current High DustDuck Creek 440 Bit. Coal Ameren Current High DustMercer 1 & 2 2 * 325 Bit. Coal PSE&G 2002 - Low Dust/ Cold ESPPowerton (project delayed) 2 * 700 Bit. Coal MidWestGen 2001 – 2002 Low Dust/ Cold ESPHomer City 1 & 2 (upgrades) 2 * 600 Bit. Coal MidWest Gen 2002-2005 High DustBrandon Shores 1 & 2 (upgrades) 2 * 650 Bit. Coal Constellation Energy 2002 Low Dust/ Hot ESPCanal 1 & 2 (upgrades) 2 * 600 Oil MIRANT 2001 - High Dust13Plant Size MW Fuel Utility/IPP Time ServiceProvidedRemarksLovett 3,4,5 435 Bit. Coal MIRANT 2002 - High DustHarding Street 470 Bit. Coal AES 2003-2004 High DustWeston 600 Bit. Coal Wisconsin Public ServiceCorp.2004 - High DustPrairie State 2*750 High Sulfur Coal Peabody Energy 2004 - High DustThoroughbred 2*750 High Sulfur CoalPeabody Energy 2004 - High DustHomer City 3 (upgrades) 650 Bit. Coal MidWest Gen 2002-2005 High DustThomas Hill 1,2,3 1135 PRB AECI 2005-2010 High DustElmer Smith PS Unit 1 (TroubleShooting)150 Bit. Coal OMU 2005 High DustSt. Johns River Power Plant 2* 660 Petcoke, Bit.CoalSJRPP 2005-2009 High DustNorthport Unit 3 150 Oil Key Spann Energy 2005- High DustLa Cygne Unit 1 800 PRB Kansas Power & Light 2005 High DustSibley Unit 3 420 PRB Aquila Current High DustSouthwest Unit 1 194 PRB City Utilities SpringfieldMOCurrent High DustOak Creek Units 5 - 8 1,200 PRB WE Energy Current Tail EndTrimble County Unit 2 900 Bit. Coal LGE Energy Current High DustSouthern Company (VariousPlants)PRB, Bit. Coal Southern Company Current High DustTotal > 28,300 MW