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

1. Comment: ADEQ should provide the proposed SO2 and NOx BART emission limits shown in Table 

1-1 in terms of lbs/MMBtu. 

Response: Before establishing lb/MMBtu limits we request that ADEQ (and EPA) consider the concerns 

expressed 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. Kelley Crouch to Ms. Mary Pettyjohn). In summary, 

we feel that converting the modeled lb/hr rates 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 also provide updated emissions information for 

Power Boiler 1 in support of the new baseline emission rates.

Response: The explanation of the baseline 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 NOX 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 NOX 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-NOX/MMBtu and 0.0139 lb-PM/MMBtu). 

The summary table from the stack test report is provided in the spreadsheet submitted along with this 

document. 

The SO2 (17.5 lb/hr) value was calculated based on maximum 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-SO2/lb-S * (1-97.5/100) = 16.55 lb-SO2/hr

Contribution from TDF & bark combustion: 

594 ton-fuel/day * 1 day/24 hr * 0.74 lb-S/ton-fuel * 2 lb-SO2/lb-S * (1-97.5/100) = 0.92 lb-SO2/hr 

Total = 16.55 lb/hr + 0.92 lb/hr = 17.47 lb-SO2/hr 

3. Comment: ADEQ should provide calculations and fuel use data utilized in estimating the 24-hr 

maximum emission rates for the revised 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 impairment greater than 0.5 Δdv at any of the Class I areas, and moreover 

does not contribute to visibility impairment on even a single day, Domtar proposes no additional 

ASHDOWN-Q9-000210
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 determination of whether the facility, considering all 

BART eligible units, is subject to BART. If the total 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 that “Failing to consider less-than-perceptible 

contributions to visibility impairment would ignore the CAA’s intent to have BART requirements 

apply to sources that contribute 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 controls where the improvement in visibility may be 

less than 1.0 dv or even less than 0.5 dv. A perceptible visibility improvement is not a requirement 

of the BART determination because visibility improvements 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 improvements 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 SO2 emissions would not be 

cost-effective in terms of visibility benefit unless those controls were extremely inexpensive. After 

taking the above into consideration, if ADEQ has found it is still appropriate to take the streamlined 

approach to making a BART determination for SO2, it should provide an appropriate justification 

that satisfies the RH rule and is consistent 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 SO2 emissions reduction options would be ruled out as cost infeasible and any improvements in 

visibility reductions would be negligible. In short, there are no “extremely inexpensive” SO2 control options. 

Therefore, no additional analysis is needed. 

5. Comment: The BART analysis dismisses the control options evaluated for NOx BART for Power 

Boiler 1 because “The No. 1 Power Boiler does not contribute 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 improvement in visibility impairment” (section 6.3). As 

discussed in our comment above for SO2 BART, given that sources are subject to BART based on a 

contribution threshold of 0.5 dv combined for all BART eligible units at the facility, it would be 

inconsistent to rule out additional controls on the basis 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 evaluation of the NOx control scenarios, as detailed in 

comments below. 

Response: As with SO2 (see previous comment), in light of the very low baseline visibility results for No. 1 

Power Boiler, it is clear that any/all NOX emissions reduction options would be ruled out as cost infeasible. 

Domtar has developed cost effectiveness estimates for two NOX control options for No. 1 Power. In the 

ASHDOWN-Q9-000211
original (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 presented 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 (even if one were to assume that post-control visibility results would go to 

zero). Therefore, no additional analysis is needed. 

6. Comment: The maximum 24-hr emission rate for Power 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 NOX and PM10, 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 stack 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 standard 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.

ASHDOWN-Q9-000212
For NOX, 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 NOX 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 standard 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 SO2, unlike NOX and PM10, we do not have stack test data upon which to determine variability. However, 

we have monthly SO2 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 SO2 Emissions 

No. 1 Power Boiler SO2 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 SO2 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 SO2 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 SO2 emission 

rate. 

                                                            

2

 The 2007 installation of the WESP did not affect NOX emissions.

ASHDOWN-Q9-000213
At these revised baseline emission levels, visibility impacts remain at levels less than 0.5 ∆dv. Modeling 

results for the adjusted baseline scenario are presented below. 

Table 4 – Adjusted Visibility Modeling Results 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 incorporated in the updated BART report. 

7. Comment: The Lundberg report on emissions controls for 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 offered can probably be re-designed without a major 

impact on the project.” We disagree that there has been no guidance from EPA regarding what level 

of control should be evaluated for BART. The RH rule requires 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). Based on the above statement made in the Lundberg report, it does not 

appear this requirement has been met in the SO2 BART analysis. Additionally, the SO2 BART 

analysis states that consideration of any further control using an add-on wet scrubber/WESP beyond 

what was evaluated and selected as BART is unreasonable. This appears to contradict the statement 

made in the Lundberg report concerning the feasibility of re-designing the equipment to achieve a 

higher removal rate if needed. The potential for greater removal efficiency may result in greater 

visibility improvement than what is currently expected. ADEQ should ensure that the requirement to 

evaluate the most stringent level of SO2 control the add-on wet scrubber/WESP is capable of 

achieving has been met. 

Response: Firstly, we want to make sure that it is clear that we evaluated a total control efficiency of 99 

percent (90 percent for the existing scrubber and 90 percent 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 Appropriations Request (AR) level quote, and it has never been 

viewed as such. Rather, it is a sales proposal with sales 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 own operational experience, they continue to find areas 

that Lundberg did not adequately or appropriately consider. For specific examples, refer to some of the items 

discussed in comments 9 and 10, below. Despite the questionable statements and assumptions made by 

Lundberg in the report, it remains the best information we have to estimate baseline costs (subject to 

amendments based on the experience of Domtar’s engineers). 

ASHDOWN-Q9-000214
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 controls 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 potentially 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 Lundberg that reflects a new scrubber alone without an 

accompanying WESP (more on this later), but it includes 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 difficulty 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, and Domtar asked Lundberg to update its report 

accordingly. The update resulted in less equipment costs and total capital investment. Domtar’s BART 

report has been updated to reflect this change. 

8. Comment: In analyzing SO2 BART for Power Boiler 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 control option from further consideration with little 

explanation, however, Domtar subsequently 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 response to comment 7 about 

vendor cooperation) and our engineers, it is clear that 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 fan 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 least un-certifiable) amount of additional SO2 control. In our view, it is 

ASHDOWN-Q9-000215
simply 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 rejecting the scrubber/wet ESP for SO2 BART for 

Power Boiler 2 is the cost for additional energy and 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 rejecting the scrubber/wet ESP as SO2 BART, the BART analysis should 

provide additional information on the amount of water 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 provided 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 standard, 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 when an engineering estimate has not been 

performed. Depending on the nature of the project, 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 Power 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. 

ASHDOWN-Q9-000216
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 scrubber/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 recovery 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 lifetime 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 Lundberg 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 explained how much of this treatment cost is due 

solely to the addition of the scrubber/wet ESP over and above the treatment needed for its 

existing process wastewater streams. This should include documentation 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 the cost calculations should be provided. 

Response: The spreadsheet is included. 

11. Comment: Regarding the evaluation of SNCR for Power 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 from a report. This and all other 

ASHDOWN-Q9-000217
reports relevant to the NOx BART determination should be provided. Domtar should justify any 

assumptions regarding the control scenarios it assumed and evaluated for SNCR and why those 

control scenarios are different for Power Boilers 1 and 2. The RH rule requires 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 evaluated 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 provided 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 FuelTech has not responded to requests for refinements. 

Therefore, the report must be amended or at least considered in light of operational experience and, more so 

in this case, information provided by NCASI. See the response to comment 12, below. Further, not only is 

the FuelTech report not a complete evaluation of Domtar’s boilers, it is also simply mistaken 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 Domtar’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 NOX 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 available control technologies. It is also unclear if the 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 resulted 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 different bases. Nevertheless, the comparison to the 

original BART proposal is not of primary importance. We apologize for the confusion. 

Notwithstanding the limited sales information we received from FuelTech about how SNCR might work with 

our boilers, we remain highly skeptical of the applicability/effectiveness of this control 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 for Pulp and Paper, "The use of SNCR systems 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 NOX 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 effective, resulting typically in about a 50% NOX reduction. We are not 

ASHDOWN-Q9-000218
aware of a pulp mill bark boiler with fluctuating loads that has successfully operated an SNCR system and 

obtained >50% NOX control consistently. Either the boiler operates at more or less a steady load or the SNCR 

system is used for polishing (<20 to 30% NOX 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 the control level purported by FuelTech; moreover, we 

selected the higher of the two levels. Based on our original BART analyses, this new proposed BART level 

represents further control than is achievable by combustion 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 anecdotes 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-factor 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 perform a visibility analysis on this control option. Similarly, no cost or 

emissions data are provided for LNB in the revised draft BART analysis, even though the revised 

draft BART reports states the source may install 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 information (especially any 

information on costs, control efficiency, 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 relying 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 the significant visibility improvement expected 

at Caney Creek. The BART analysis 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 information 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 cost 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 would 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 annual emission rate as presented in emission inventories). 

ASHDOWN-Q9-000219
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 analysis. A current query of the RBLC for all NOX control 

determinations for all process types reveals not even one instance of MdN with the possible exception of a 

“De-NOX 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 upon LNB-related information presented in the 2006/2007 

BART report except for updated modeling results, which appear 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 provide 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. Nevertheless, Domtar has provided 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 (labor and materials) for the scrubber alone. 

The $771,895 value was the sum of the four non-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). Moreover, 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 decreased 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 are listed in the SNCR cost evaluations that are 

not explained. For instance, Domtar should explain 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 losses and the subsequent additional ash disposal 

costs (which occur regardless of which fuel is used). The coal-based equations presented therein 

ASHDOWN-Q9-000220
apply 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 also specified and how is that calculated? 

Response: Both contingency values were estimated 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 facilities, engineering and home 

office fees. [Domtar cites the CCM as a reference 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 indirect installation cost for items such as general 

facilities (construction contractors) and engineering/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 SNCR cost table in Appendix B refers to a World Bank quote for 

a bulk spot FOB price for delivery to the Black Sea area and Eastern Europe. In addition, 

there appears to be a huge spike in price in 2008 that does not appear to be representative 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 relying on the MACT PM standard to satisfy the 

PM BART requirement for Power Boiler 2. However, to be able to take this streamlined approach, 

ASHDOWN-Q9-000221
the current MACT PM limit must be used to satisfy 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 MACT controls and whether any major new technologies have been 

developed subsequent to the MACT standards... Unless there are new technologies subsequent to 

the MACT standards which would lead to cost-effective increases in the level of control, you may 

rely on the MACT standards for purposes of BART” (Appendix Y to Part 51, section IV.C). Based 

on this language, it is clearly not acceptable to take the streamlined 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 emission 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 state to rely on the 0.07 lb/MMBtu MACT PM 

emission limit for Power Boiler 1 because the effective date of the DC Circuit’s vacatur of the 2004 

MACT rule was after the close of the public notice and comment period 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 Power 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 BART compliance deadline.

                                                            

3

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

ASHDOWN-Q9-000222