### Domtar Responses to ADEQ Regarding Region 6 Comments on Domtar BART analysis

1. Comment: ADEQ should provide th e proposed SO2 and NOx BART em ission limits shown in Table
1-1 in terms of lbs/MMBtu.

Response: Before establishing lb/MMBtu limits we re quest that ADEQ (and EPA) consider the concernsexpressed in our June 25, 2007 letter written in response to ADEQ’s draft SIP BART provisions (retransmitted in a September 16, 2013 e-mail from Ms. Ke lley Crouch to Ms. Mary Pettyjohn). In summary, we feel that converting the modeled lb/hr rat es to lb/MMBtu artificially restricts operations beyond what is represented in the visibility modeling

.



### 2. Comment: Section 2 of the BART report explains that a new baseline emission rate for SO2, NOx, and PM is proposed for Power Boiler 1 to reflect the change in emissions resulting from the installation of a wet ESP in 2007. ADEQ should al so provide updated emissions information for Power Boiler 1 in support of the new baseline emission rates.

Response: The explanation of the base line values found in the June 28, 2013 BART report is provided below. However, please note that we are updating the BART report such that these values – for NO X and PM – are no longer presented. The new baseline values are described in response to comment 6, below, and in the revised BART report submitted along with this document.

The adjusted baseline NO X and PM emission rates of 121.2 lb/hr and 6.4 lb/hr, respectively, were based on the maximum daily heat input for the boiler from 2009 – 2011 (11,069.67 MMBtu/day) and stack testing completed on April 22, 2010 (three-hour average results: 0.2628 lb-NO X /MMBtu and 0.0139 lb-PM/MMBtu). The summary table from the stack test report is prov ided in the spreadsheet submitted along with this
document.

The SO 2 (17.5 lb/hr) value was calculated based on maximu m fuel usage rates in a single day in 2009 – 2011 and sulfur contents (from analysis and/ or published values from NCASI) as follows:

Contribution from fuel oil combustion: 50 gal-oil/min * 60 min/hr * 7.88 lb/gal * 0.014 lb-S/lb-oil * 2 lb-SO 2 /lb-S * (1-97.5/100) = 16.55 lb-SO 2 /hr

Contribution from TDF & bark combustion: 594 ton-fuel/day * 1 day/24 hr * 0.74 lb-S/ton-fuel * 2 lb-SO 2 /lb-S * (1-97.5/100) = 0.92 lb-SO 2 /hr

Total = 16.55 lb/hr + 0.92 lb/hr = 17.47 lb-SO 2 /hr



### 3. Comment: ADEQ should provide calc ulations and fuel use data utilized in estimating the 24-hr
maximum emission rates for the revise d baseline period for Power Boiler 1.

Response: See response to comment 2 above.



### 4. Comment: The SO2 BART analysis (section 5.1) states “Because No. 1 Power Boiler does not contribute to visibility im pairment greater than 0.5 Δ dv at any of the Class I areas, and moreover does not contribute to visibility impairment on even a single day, Domtar proposes no additional

### add-on controls...” This is not an appropriate justification for not conducting a BART analysis for SO2. The 0.5 dv threshold applies only to the determ ination of whether the facility, considering all BART eligible units, is subject to BART. If the to tal impact from all BART eligible units at the facility is greater than 0.5 dv, then each unit must be evaluated for BART. In addition, we also note that the preamble of the RH rule explains th at “Failing to consider less-than-perceptible contributions to visibility impairment would igno re the CAA’s intent to have BART requirements apply to sources that contribu te to, as well as cause, such impairment” (70 FR 39104, at 39129). Given that sources are subject to BART based on a contribution threshold of 0.5 dv, it would be inconsistent to automatically rule out additional c ontrols where the improvement in visibility may be less than 1.0 dv or even less than 0.5 dv. A perceptib le visibility improvement is not a requirement of the BART determination because visibility im provements that are not perceptible may still be determined to be significant.

We note that in some cases, states may adopt a more streamlined approach to making BART determinations where appropriate. For example, a State need not undertake an exhaustive analysis
where it is clear that controls would be costly and any improveme nts in visibility resulting from reductions in emissions would be negligible (70 FR 39104, at 39116). An examination of the baseline visibility results for Boiler 1 indicates that visibility impacts on the high impact days are primarily due to nitrate. Therefore, it is likely that further reductions in SO 2 emissions would not be
cost-effective in terms of visibility benefit unless those controls were extremely inexpensive. After taking the above into considerati on, if ADEQ has found it is still appr opriate to take the streamlined approach to making a BART determination for SO 2, it should provide an appropriate justification
that satisfies the RH rule and is c onsistent with the BART guidelines.

Response: It was not our intent to argue that a BART analysis is not required, and we apologize for the confusion. Rather, as is pointed out above, in light of the very low baseline visibility results, it is clear that any/all SO 2 emissions reduction options w ould be ruled out as cost infeasible and any improvements in visibility reductions would be negligible. In short, there are no “extremely inexpensive” SO 2 control options. Therefore, no additional analysis is needed.



### 5. Comment: The BART analysis dismisses the cont rol options evaluated for NOx BART for Power
Boiler 1 because “The No. 1 Power Boiler does not cont ribute to visibility impairment greater than 0.5 dv nor any single day of impairment [greater than 0.5 dv] at any of the Class I areas ... therefore, the considered control options provide no improveme nt in visibility impairment” (section 6.3). As
discussed in our comment above fo r SO2 BART, given that sources are subject to BART based on a
contribution threshold of 0.5 dv combined for all BA RT eligible units at the facility, it would be
inconsistent to rule out additional controls on the ba sis that the improvement in visibility is less than 0.5 dv. Therefore, we recommend that the above quoted language be revised. Additionally, we note that we have remaining concerns with the evaluati on of the NOx control scenarios, as detailed in
comments below.

Response: As with SO 2 (see previous comment), in light of the ve ry low baseline visibility results for No. 1 Power Boiler, it is clear that any/all NO X emissions reduction options would be ruled out as cost infeasible. Domtar has developed cost effectiveness estimates for two NO X control options for No. 1 Power. In theoriginal (2006/2007) BART analysis, a cost effectiveness of greater than $7,000/ton was presented for 50 percent control via MdN. 1 In the June 28, 2013 BART report we pr esented cost effectiveness values for three SNCR scenarios, the most cost effective of which (the 45 percent control scenario) was greater than $6,800/ton. These costs are clearly not justified based on the very small amount of visibility improvement that could potentially be achieved (eve n if one were to assume that post-c ontrol visibility results would go to zero). Therefore, no addi tional analysis is needed

.

6. 

### Comment: The maximum 24-hr emission rate for Powe r Boiler 1 is estimated as 17.5 lb/hr for SO2 and 121.2 lb/hr NOx. However, an emission limit of 21 lb/hr for SO2 and 145 lb/hr for NOx demonstrated based on a monthly and 12-month rolling basis are proposed as BART. Given that compliance with the SO2 and NOx BART emission limits is proposed on a monthly basis, we do not believe a 20% compliance margin above the 24- hr maximum emission rates is necessary. A justification, including any supporting emissions data or other information, explaining the need for a 20% compliance margin should be provided.

Response: For NO X and PM 10 , the 20 percent compliance margin was requested because the proposed emission levels – to apply as limitations during all future operation – were based on a snapshot data (i.e., one test result). In the updated BART report submitted along with this document, we have removed the 20 percent compliance margin proposal. Rather, we have re-calculated the baseline emission rates for the No. 1 Power Boiler based on a more robust analysis of past st ack testing. The additional data considered in the analysis – based on methods approved by EPA in other BART determinations – provides us with a higher level of comfort that the new proposed BART emission levels can be achieved at all times without the need for an artificial compliance margin.

For PM, four three-hour tests (so 12 data points) have been completed since the installation of the WESP in early 2007. They are summarized in Table 1, below.

Table 1 – No. 1 Power Boiler PM Test Results

No. 1 Power Boiler Run 1 Run 2 Run 3 Average

Test Date (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

8/7/2007 0.0124 0.0177 0.0113 0.0138

2/26/2008 0.0368 0.0434 0.0468 0.0423

2/28/2008 0.0389 0.0619 0.0475 0.0494

4/22/2010 0.0190 0.0128 0.0098 0.0139

From the above data, the mean average plus two standa rd deviations is 0.066 lb/MMBtu. At the maximum daily heat input for the boiler from 2009 – 2011 (11,069.67 MMBtu/day), this emission level is equivalent to 30.4 lb/hr on a maximum day basis.

1 Domtar prepared cost effectiveness estimates despite questioning the technical feasibility of MdN.For NO X , we have three three-hour tests (so nine data points) in the last 10 years. 2 They are summarized in Table 2, below.

Table 2 – No. 1 Power Boiler NO X Test Results

No. 1 Power Boiler Run 1 Run 2 Run 3 Average

Test Date (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

3/10/2004 0.3518 0.4048 0.3893 0.3820

10/25/2005 0.3446 0.3706 0.3582 0.3578

4/22/2010 0.2400 0.2641 0.2843 0.2628

From the above data, the mean average plus two standa rd deviations is 0.4496 lb/MMBtu. At the maximum daily heat input for the boiler from 2009 – 2011 (11,069.67 MMBtu/day), this emission level is equivalent to 207.4 lb/hr on a maximum day basis.

For SO 2 , unlike NO X and PM 10 , we do not have stack test data upon which to determine variability. However, we have monthly SO 2 emissions calculations based on known fuel usage and sulfur contents, and it is reasonable to review this data to determine variability. These monthly values are shown in Table 3, below.

Table 3 – No. 1 Power Boiler Monthly SO 2 Emissions

No. 1 Power Boiler SO 2 Emissions (tons/month)

Month 2009 2010 2011 January 0.263 * 0.374 * 0.27 February 0.294 * 0.26 0.24

March 0.04 0.30 0.27
April 0.08 0.20 0.18
May 0.02 0.28 0.23

June 0.00 0.08 0.21
July 0.19 0.22 0.21
August 0.23 0.79 0.18
September 0.13 0.20 0.21

October 0.19 0.14 0.21

November 0.18 0.11 0.20

December 0.13 0.13 0.21

* These values are adjusted from Domtar’s official emissions records to include consideration of the 97.5 % control efficiency on SO 2 emissions from fuel oil combustion provided by the WESP. The consideration was not applied in the official records until 2011. Only three months are adjusted because those are the only months in 2009 and 2010 during which fuel oil was combusted.

The standard deviation (0.129) of this data is equal to 62 percent of the mean average (0.207) of the data.
This means that SO 2 emissions, while small, vary a great deal from month-to-month. Considering this information we feel it is prudent to apply a 20 percent variability factor to the daily baseline SO 2 emission

rate.

2 The 2007 installation of the WESP did not affect NO X emissions.At these revised baseline emission levels, visibilit y impacts remain at levels less than 0.5 ∆ dv. Modeling results for the adjusted baselin e scenario are presented below.

Table 4 – Adjusted Visibility Modeling Result s for No. 1 Power Boiler Baseline Scenario

CACR UPBU HERC MING

Emission Unit Scenario 98th % ∆ dv Days > 0.5 ∆ dv 98th % ∆ dv Days > 0.5 ∆ dv 98th % ∆ dv Days > 0.5 ∆ dv 98th % ∆ dv Days > 0.5 ∆ dv
No. 1
Power Boiler Adjusted Baseline 0.335 0 0.038 0 0.020 0 0.014 0

All of this information is incor porated in the updated BART report.



### 7. Comment: The Lundberg report on emissions controls fo r Power Boiler 2 states that “With regard to the BART regulation, as discussed, there has been no guidance from the regulatory authorities. Given this, we have selected 90% SO2 reduction as a common-sense approach to the situation... if higher removal rates are required the equipment offe red can probably be re-designed without a major impact on the project.” We disagree that there has been no guidan ce from EPA regarding what level
of control should be evaluated for BART. The RH rule requires that in anal yzing controls for BART, the most stringent emission control level that the technology is capable of achieving must be taken into account (70 FR 39166). Based on the above stat ement made in the Lundberg report, it does not appear this requirement has been met in the SO2 BART analysis. Addi tionally, the SO2 BART analysis states that consideration of any furthe r control using an add-on wet scrubber/WESP beyond
what was evaluated and selected as BART is unreasonable. This appe ars to contradict the statement made in the Lundberg report concerning the feasibili ty of re-designing the equipment to achieve a higher removal rate if needed. Th e potential for greater removal e fficiency may result in greater visibility improvement than what is currently ex pected. ADEQ should ensure that the requirement to evaluate the most stringent level of SO2 cont rol the add-on wet scrubb er/WESP is capable of achieving has been met.

Response: Firstly, we want to make sure that it is cl ear that we evaluated a total control efficiency of 99 percent (90 percent for the existing scrubber and 90 pe rcent more for the new scrubber/WESP) in the revised BART analysis. We believe this satisfies the BART guidelines regarding evaluation of the most stringent
controls available.

Moreover, the Lundberg proposal is not an Appropriati ons Request (AR) level quote, and it has never been viewed as such. Rather, it is a sales proposal with sal es pitch statements such as “...if higher removal rates are required the equipment offered can probably be re-designed without a major impact on the project” (emphasis added). This statement simply is not true . Moreover, as Domtar’s engineers have continued to review the Lundberg proposal, comparing it to their ow n operational experience, they continue to find areas that Lundberg did not adequately or appropriately consid er. For specific examples, refer to some of the items discussed in comments 9 and 10, below. Despite th e questionable statements and assumptions made by Lundberg in the report, it remains the best informa tion we have to estimate baseline costs (subject to amendments based on the experience of Domtar’s engineers).This is one example of a larger issue – a lack of responsiveness from controls vendors. With the exception of the two questionable reports we have received, we have found that cont rols vendors are unwilling to provide any level of cost or emissions estimates for the controls considered in our BART analysis. We assume that this is the case because the controls vendors reasonably understand that it is unlikely that their efforts to evaluate the hypothetical cost and emissions estimates will result in an equipment sale, considering the very little, if any, quantifiable visibility improvements that may be achieved relative to the cost of upgrades such

as:

 Adding another scrubber downstream of an existing, well-operating scrubber.

 Spending hundreds of hours (and tens or hundreds of thousands of dollars) and months of delay to find upgrades to an existing scrubber to potentia lly squeeze another fraction of a percent of efficiency.

 Adding SNCR to a wood-fired, swing-load boiler.

Moreover, even for the two vendor reports we have obtained, requests for refinements have not been answered. It seems that until a contract is in place, vendors are unwilling to refine their general assumptions/estimates.

We did recently receive an updated report from Lundbe rg that reflects a new scrubber alone without an accompanying WESP (more on this later), but it incl udes the same inaccurate/inappropriate assumptions as the original report.

We implore ADEQ to consider the difficulty that we face in trying to gather additional information from vendors about these control options and to weigh that diffi culty with the very minimal possible gain (greater than 99%) that may or may not be achieved.

Updated Lundberg Report – Scrubber Only, No WESP Because of the change in Boiler MACT (=BART) PM emission standard (see response to comment 15), a WESP is no longer needed for No. 2 Power Boiler, a nd Domtar asked Lundberg to update its report accordingly. The update resulted in less equipment co sts and total capital investment. Domtar’s BART report has been updated to reflect this change.



### 8. Comment: In analyzing SO2 BART for Power Boile r 2, Domtar states that Lundberg evaluated upgrades to the existing scrubber but that it has been unable to quantify any potential additional control. After discarding this potential BART c ontrol option from further c onsideration with little explanation, however, Domtar subse quently determined that the SO2 BART control it did evaluate – an additional add-on scrubber/wet ESP - is not BART. In light of this, Domtar should re-evaluate the scrubber upgrade option it rejected and provide any reports prepared by Lundberg or others on the scrubber upgrade option.

Response: Based on limited information from Lundberg (see discussion in respon se to comment 7 about vendor cooperation) and our engineers, it is clear th at a true engineering assessment, which would likely amount to hundreds of hours of engineering time and, perhaps more importantly, several months of additional delay, to quantify upgrade possibilities would potentially only achieve a fraction of a percentage, if that, of additional control efficiency. For example, an ID fa n upgrade was considered but it was determined that the potentially achievable amount of additional pressure drop (leading to additional scrubbing) would be marginal – leading to an unquantifiable (or at l east un-certifiable) amount of additional SO 2 control. In our view, it issimply not worth the effort to find what, in the end, may be an almost unquantifiable increase in efficiency. Again, we ask ADEQ to weigh the pros and cons of such an exercise in light of the minor, if even quantifiable, possible control efficiency gain – and even smaller visibility improvement.



### 9. Comment: One of the reasons Domtar cites for re jecting the scrubber/wet ESP for SO2 BART for Power Boiler 2 is the cost for additional energy a nd water use. However, this appears to conflict with the Lundberg report which states, “there would be no additional process water requirement because spent water from the spray scrubber/wet ESP could ‘feed forward’ to the scrubber system as make-up.” If this statement from the Lundberg report is incorrect and water cost /availability is really being used as a reason for reject ing the scrubber/wet ESP as SO2 BA RT, the BART analysis should provide additional information on the amount of wa ter this scrubber/WESP will use over and above the plant’s process water and the cost of that water.

Response: This quote is an example of where Lundberg’s proposal falls short of an AR-level quote. There is no question that additional process water would be required (beyond what is currently being used for the existing scrubber). The Lundberg report is simply not a complete evaluation of operations and costs when compared to Domtar’s experience with similar controls , and therefore it had to be supplemented based on the experience of Domtar’s engineers.

Moreover, we have verified with Lundberg that an additional water usage rate of 20 gal/1000 acfm (equivalent to 1,874,592,264 gal/yr) will be needed to operate the new scrubber.



### 10. Comment: ADEQ should provide supporting information for some of the line items in the scrubber/wet ESP cost analysis for Power Boiler 2:

a. Comment: Detailed documentation should be provi ded for the “Costs to Retrofit” figure of $13,175,000, referenced as footnote 11 in Appendix B, which states, “Domtar's engineers estimate that PEC accounts for only approximately 40% of the total investment to place a new WESP into service.”

Response: The 40% (or 2.5 factor) value is a sta ndard, developed based on capital project experience, used among Domtar’s engineers when considering the type of sales proposal values provided by Lundberg. Following is an explanatory quote from the Ashdown Mill’s engineering manager.

We commonly use a "factored" estimate wh en an engineering estimate has not been performed. Depending on the nature of the proj ect, we typically use a factor between 2.0 and 3.5 of the process equipment cost to determine the Total Installed Cost (TIC). For our "Gate 1" process (conceptual level discussion), a factored estimate is normally employed. For "Gate 2" and Gate "3", we invest in engineering studies to reach a +/- 25% and +/-10% quality scope and estimate respectively.

In the case of the BART project on No.2 Po wer Boiler which involved scrubbers and wet electrostatic precipitator, we received a budgetary proposal from A.H. Lundberg to provide the process equipment and process engineering for $5.27MM. We elected to use a factor of 2.5 (lower end of the range) given the scope of supply for the process equipment. 2.5 × $5.27MM = $13.175MM.

### b. Comment: Documentation should be provided for the wastewater treatment figure of $6,092,425 and it should specifically be documented how much of that treatment would be due to the addition of the sc rubber/wet ESP in relation to the rest of the plant.

Response: See response to similar but expanded comment 10.e.



### c. Comment: Documentation should be provided for the annual sorbent caustic usage of $2,300,000. It should specifically be documented how much of that sorbent caustic is necessary due to the addition of the scrubber/ wet ESP over and above that supplied by the existing process stream.

Response: Lundberg estimated a sorbent usage rate of 5 lb/min (2,628,000 lb/yr) is needed to achieve the additional 90 percent (overall 99 percent). This rate is for the new scrubber only; it is over and above the usage for the existing scrubber system.



### d. Comment: The cost analysis bases its capital re covery factor (CRF) on a 20 year life based on a reference from the CCM. The section of the CCM referenced states that “For ESPs, the system lifetime varies from 5 to 40 years, with 20 years being typical” (Section 6, Chapter 3 of the CCM). Since Domtar has obtained a quote from the vendor, documentation of the vendor’s estimate/guarantee of the expected lif etime of the equipment should be provided and ADEQ should ensure that the CRF is based on the vendor’s estimate/guarantee.

Response: We have received no information from Lundbe rg in regards to expected equipment life. Again, the Lundberg report is not an AR-level quote, and Lundberg has not responded to additional requests for information. As such, we felt it was correct to use the “typical” value from the CCM. Nevertheless, we have revised the estimate in the revised BART report to use 30 years (assumed to be EPA’s preference based on comment 14.a.) rather than 20 years. The cost effectiveness value changed by about $100/ton.



### e. Comment: The need for an annual wastewater treatment cost of over $6M should be documented. In particular, it should be explaine d how much of this treatment cost is due solely to the addition of the scrubber/wet E SP over and above the treatment needed for its existing process wastewater streams. This s hould include documenta tion of the additional wastewater volume generated due to the scrubber/wet ESP.

Response: The $6M figure is associated with the new scrubber only; it does not consider existing costs of operating the existing scrubber.



### f. Comment: A fully working spreadsheet of th e cost calculations should be provided.

Response: The spreadsheet is included.



### 11. Comment: Regarding the evaluation of SNCR for Powe r Boilers 1 and 2, ADEQ should ensure that Domtar provides any information it received from FuelTech that was used to analyze the potential control efficiency, cost, reagent usage, and any other information that is relevant to a BART determination. For instance, Figure 6- 1 appears to have been copied fr om a report. This and all other

### reports relevant to the NOx BART determinatio n should be provided. Domtar should justify any assumptions regarding the cont rol scenarios it assumed and ev aluated for SNCR and why those
control scenarios are different for Power Boilers 1 and 2. The RH rule requir es that in analyzing controls for BART, the most stringent emission control level that the technology is capable of achieving must be taken into account (70 FR 39166) . Therefore, ADEQ should ensure that Domtar
demonstrates that it has evaluate d the most stringent level of NOx control SNCR is capable of providing for Power Boilers 1 and 2.

Response: The complete FuelTech report is now provi ded along with the Lundberg report with the revised BART report. However, it should be noted that, similar to the Lundberg report discussed previously, the FuelTech report is not an AR-level quote, and FuelT ech has not responded to requests for refinements. Therefore, the report must be amended or at least cons idered in light of operational experience and, more so in this case, information provided by NCASI. See the r esponse to comment 12, below. Further, not only is the FuelTech report not a complete evaluation of Domtar’s boilers, it is also simply mi staken in several areas. Some examples: (a) the steaming rate on No. 2 Power Boiler used to represent 50-75% of MCR is actually only 30% of MCR; (b) at another point in the proposal it says this same 30% of MCR is 100% MCR; (c) the heat input rating is listed as 615 MMBtu/hr but in actuality it is 820 MMBtu/hr; (d) it presents a SCR control option when clearly such technology is infeasible for Do mtar’s boilers (see section 4.4.2.4 of the 2006/2007 BART report). For these reasons, the only information in the report that was relied upon were the estimates
of NO X reductions and associated urea consumption rates.



### 12. Comment: For Power Boiler 2, Domtar proposes a 6% decrease in NOx from the original BART determination (30% reduction using LNB). Domtar also states that this level of control (36%) is potentially achievable with SNCR. However, SNCR was evaluated at 35% control. It is unclear
how this level of reduction was determined based on an evaluation of the five -factors and evaluation of the control efficiency of the av ailable control technologies. It is al so unclear if th e combination of
LNB and SNCR was examined.

Response: The control efficiency we analyzed was 35%, not 36%. The confusion is apparently due to our comparison to the original (2007) BART proposal value presented in Section 6.3 of the report. We were simply pointing out that the 35% control efficiency resu lted in an emission level that is 6% less than the original BART proposal, which was based on 30% control. It should be noted that the 30% and the 6% values are not additive since they are calculated using di fferent bases. Nevertheless, the comparison to the original BART proposal is not of primary im portance. We apologize for the confusion.

Notwithstanding the limited sales information we receive d from FuelTech about how SNCR might work with our boilers, we remain highly skeptical of the applicab ility/effectiveness of this c ontrol option. Anecdotally, operators with SNCR experience have told us that it is “dirty”, “difficult”, and “not a preferred option.” Furthermore, the National Council for Air and Stream Improvement (NCASI), remains steadfast in their
assessment of SNCR.

From NCASI’s 2008 Handbook fo r Pulp and Paper, "The use of SNCR sy stems on coal-fired boilers is still in the development stage." And from January 17, 2013 , “[NCASI’s] understanding about the applicability of SNCR systems to control NO X in industrial boilers has not changed. We agree that for a base loaded pulp mill bark or coal boiler or boiler with steady flue gas flow patterns and temperature distribution across the flue gas pathway, SNCR can be quite effec tive, resulting typically in about a 50% NO X reduction. We are notaware of a pulp mill bark boiler with fluctuating load s that has successfully operated an SNCR system and
obtained >50% NO X control consistently. Either the boiler opera tes at more or less a steady load or the SNCR system is used for polishing (<20 to 30% NO X reduction) purposes.” (emphasis added)

The EPA-referenced Temple-Inland (Orange , TX) facility has experienced the issues described by NCASI. It achieves only approximately 20% control with its SNCR system.

Despite these warnings, we have proposed as BART th e control level purported by FuelTech; moreover, we selected the higher of the two levels. Based on our or iginal BART analyses, this new proposed BART level represents further control than is achievable by comb ustion controls alone. It does not however represent a simple addition (of control efficiencies) to combustion controls. Considering the warnings from NCASI, the evidence of the Temple-Inland installation, and the anec dotes regarding SNCR, we feel that 35% is a prudent
BART determination.



### 13. Comment: Methane de-NOx (MdN) is modeled at 50% control efficiency for Power Boiler 2 and is modeled to reduce visibility impacts at Caney Creek by approximately 0.3 dv. However there is no discussion of MdN feasibility, anticipated control efficiency, or cost. It is unclear how MdN was considered as part of the 5-fact or analysis. Domtar’s previous analysis, prepared in 2006/2007 and submitted with the Arkansas Regional Haze SIP in 2008 evaluated MdN and determined that it was not cost-effective but did not perfor m a visibility analysis on this c ontrol option. Similarly, no cost or emissions data are provided for LNB in the revi sed draft BART analysis, even though the revised draft BART reports states the source may inst all LNB to meet the NOx BART emission limit proposed for Power Boiler 2. ADEQ must ensure that the revised Domtar BART analysis it submits as part of the Regional Haze SIP revision includes the complete evaluation of all NOx controls, including MdN and LNB. If in its Regional Haze SIP revision, ADEQ decides to rely on or use any parts of the 2006/2007 Domtar BART analysis, it must ensure that the info rmation (especially any information on costs, control efficien cy, and availability of controls) continues to be up to date and that those portions of the 2006/2007 BART analysis are re-submitted and included in the Regional Haze SIP revision package. If ADEQ is indeed rely ing on the cost information for MdN provided in the 2006/2007 Domtar BART analysis, we believe the cost of that control for Power Boiler 2 ($4,259/NOx ton reduced) is not unreasonable given th e significant visibility improvement expected at Caney Creek. The BART analys is should include a discussion of why MdN was not selected for
NOx BART for Power Boiler 2 after all five factors were taken into consideration.

Response: We request that ADEQ rely upon informat ion presented for in the 2006/2007 BART analysis where no new information has been presented in the 2013/2014 analysis. For example, the previously submitted cost information for MdN should be relied upon as we have no further information about costs for this control option. A cursory review of the MdN co st calculations reveals two potential updates, which we feel are not needed because of the technical infeasibility of MdN (discussed briefly below), but which would clearly rule out MdN as cost infeasible if their incorporation was required. First, the cost values presented for MdN in the 2006/2007 analysis would be scaled to a 2012 (or later) basis. Second, the uncontrolled (baseline) rates used in the 2006/2007 analysis woul d be updated. For example, the No. 2 Power Boiler baseline emission rate of 2,514 tpy, which is incorrect , would be updated to 2,240 tpy (the maximum day emission rate, annualized) or 1,536 tpy (the actual annua l emission rate as presented in emission inventories).The technical feasibility discussions for MdN presented in the 2006/2007 analysis remain legitimate and should be relied upon now. Further, we have completed additional research to determine if MdN has been placed into operation since the original anal ysis. A current query of the RBLC for all NO X control determinations for all process types reveals not even one instance of MdN with the possible exception of a

“De-NO X system” on a Nitric Acid Plant, which is not a combustion device and therefore not a comparable source type. And NCASI has also not published any information regarding MdN systems in operation.

Similar to MdN, we request that ADEQ rely upo n LNB-related information presented in the 2006/2007 BART report except for updated modeling results, which app ear in Table 6-3 of the latest report (the reasons for the updates are explained in section 3 of the report).



### 14. Comment: Domtar should provide the following regarding the cost analyses for SNCR:

a. Comment: Domtar should assume a 30 year operating life.

Response: We have revised our cost estimates to use 30 years for capital recovery. Making this change results in fairly minor cost effectiveness decreases.



### b. Comment: Domtar should provi de documentation for the annual maintenance fee of $310,000, and the fixed (indirect) costs of $771,895.

Response: First, it is important to note that these values are found in the No. 2 Power Boiler Wet Scrubber analysis, not an SNCR analysis. Neverthe less, Domtar has provide d additional information regarding these values below.

The $310,000 value was estimated based on the actual, historical costs of maintenance and cleaning of the existing WESP on the No. 1 Power Boiler. Now that the WESP is no longer being considered, this value has been reduced to $150,000 (l abor and materials) for the scrubber alone.

The $771,895 value was the sum of the four no n-capital recovery indirect cost categories – administrative charges, property tax, insurance, and overhead – as calculated in accordance with EPA’s Control Cost Manual ( see Section 5, Table 1.4). Moreove r, upon inspection it was discovered that the overhead cost calculation incorrectly accounted for only maintenance labor and materials. In the revised analysis, operator labor and supervisor labor are now also included as per the CCM’s instructions. Furthermore, these costs have decreas ed in proportion to the decrease in Total Capital Investment reflecting a wet scrubber alone (without an accompanying WESP). The result of all of the above is a total indirect cost value of $578,207.



### c. Comment: There are a number of factors that ar e listed in the SNCR cost evaluations that are not explained. For instance, Domtar should expl ain why the bark cost and the ash disposal cost, the 2011 and 1998 cost indices, and the bark HHV are relevant to the SNCR cost
estimations.

Response: EPA’s CCM, at Section 4, Chapter 1, pages 1-35 and 1-36, discusses costs for coal (i.e., fuel) required to make up for SNCR-related heat lo sses and the subsequent additional ash disposal costs (which occur regardless of which fuel is used). The coal-based equations presented thereinapply directly to the No. 2 Power Boiler because it is primarily coal-fired. The same equations were also applied to the No. 1 Power Boiler, but bark properties (e.g., heat value, ash content) were substituted for coal properties since the No. 1 Power Boiler combusts primarily bark.

The cost indices are Chemical Engineering Plant Cost Indices (CEPCI), a standard in engineering
economic calculations.



### d. Comment: Domtar should explain how the equation for the direct capital costs was derived, including all constants and parameters.

Response: See EPA’s CCM at Section 4, Chapter 1, Equation 1.19.



### e. Comment: Domtar should justify why a project contingency of 15% is needed for this project. Why is a process contingency al so specified and how is that calculated?

Response: Both contingency values were estimat ed based on formulas presented in EPA’s CCM at Section 4, Chapter 1, Table 1.4. Domtar does not have a complete, engineering-verified vendor quote, i.e., an AR-level quote, with which to compare the CCM’s default costing equations and
therefore has no reason to disbelieve the cost estimates derived from the CCM.



### f. Comment: Domtar should explain the following costs, what they cover, and how they are calculated: preproduction cost, inventory capital, general faci lities, engineering and home office fees. [Domtar cites the CCM as a referenc e for SNCR costs, but these fees should still be justified as real costs].

Response: Absent an AR-level quote (see discussions above) we have no reason to disbelieve the costing categories, methodologies, and resulting estimates derived from the CCM. Moreover, Domtar’s engineers agree with the cost categories presented for SNCR in the CCM. That is, Domtar expects that it would indeed incur costs for indi rect installation cost for items such as general facilities (construction contractors) and engin eering/home office (i.e., corporate) work; other installation costs such as preproduction (startup and testing) and inventory capital (the initial purchase of urea); and the contingencies that are necessary.



### g. Comment: Domtar should provide a more accurate documentation for the urea cost. The link provided in the notes to the SN CR cost table in Appendix B refe rs to a World Bank quote for a bulk spot FOB price for delive ry to the Black Sea area and Eastern Europe. In addition, there appears to be a huge spike in price in 2008 that does not app ear to be repr esentative of the general price trend.

Response: The cost used in the SNCR cost table was confirmed to be an accurate representation of locally available urea on January 27, 2014 via a phone call to CDI, Inc., a supplier with a distribution point in Crossett, AR. It was also confirmed during the call with CDI that urea prices fluctuate drastically.



### 15. Comment: We agree with the general approach of re lying on the MACT PM standard to satisfy the PM BART requirement for Power Boiler 2. However, to be able to take this streamlined approach,

### the current MACT PM limit must be used to sati sfy PM BART. The BART guidelines provide that for “For VOC and PM sources subject to MACT standards, sates may streamline the analysis by including a discussion of the MA CT controls and whether any ma jor new technologies have been developed subsequent to the MA CT standards... Unless there are new technologies subsequent to
the MACT standards which would lead to cost-eff ective increases in the level of control, you may rely on the MACT standards for pu rposes of BART” (Appendix Y to Part 51, section IV.C). Based on this language, it is clearly no t acceptable to take the streamlin ed approach by using an outdated MACT PM emission limit to satisfy PM BART . On January 31, 2013, EPA took final action on the proposed reconsideration of certain issues related to the MACT em ission standards, promulgating a final MACT PM limit of 0.04 lb/MMBtu for existing coal-burning boilers and process heaters (see 78 FR 7138). However, Domtar proposes to take the streamlined approach for PM BART by accepting the previous MACT PM emission limit of 0.07 lb/MMBtu, which was promulgated in 2004 and has since been vacated and remanded by the DC Circuit Court. In the Arkansas RH SIP submitted in 2008, it was appropriate for the st ate to rely on the 0.07 lb/MMBtu MACT PM
emission limit for Power Boiler 1 b ecause the effective date of the DC Circuit’s vacatur of the 2004
MACT rule was after the close of the public notice and comment pe riod for Arkansas’s proposed RH rule. However, ADEQ must now address PM BART for Power Boiler 2 in a RH SIP revision that addresses the portions of the 2008 RH SIP disapproved by EPA, and it must therefore ensure that if the streamlined approach is taken for PM for Powe r Boiler 2, the current MACT PM limit is used to satisfy PM BART. Additionally, ADEQ should ensure that the BART analysis includes a discussion of the MACT controls and whether any major new technologies have been developed subsequent to the final MACT PM standard issued in January 2013.

Response: Domtar proposes to use the streamlined approach and to propose the new Boiler MACT limit as BART for the No. 2 Power Boiler. The No. 2 Power Boiler is a “hybrid suspension grate boiler” as defined in 40 CFR 63 Subpart DDDDD, at 63.7575, and as such is subject to a PM limit of 0.44 lb/MMBtu ( see Table 2 of 40 CFR 63 Subpart DDDDD). 3

Since the Boiler MACT standard was established recently (earlier in 2013), the technology analysis used by EPA in the rulemaking is up-to-date. Moreover, the deadline for compliance with the Boiler MACT is prior to the anticipated BA RT compliance deadline.

3 ADEQ provided a letter concurring with this determination on October 28, 2013.