Appendix 9 - IDEM Responses to National Park Service Comments 
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Appendix 9 - 1 

IDEM Responses to National Park Service Comments 

Chapter 2, Regional Planning

Comment: 

IDEM has identified 19 Class I areas that are impacted by Indiana emissions. Table 1 in 

Appendix 1 lists the specific Class I areas that Indiana impacts and cites the technical analyses 

that support that determination. It would be helpful to include Table 1 in the SIP Chapter 2. 

IDEM Response: 

IDEM has added Table 1 in Appendix 1 to Chapter 2 in the SIP and subsequent tables have been 

renumbered as necessary. 

Chapter 4, Baseline Conditions, Pollutant Contribution, Uniform Rate of Progress

Comment: 

IDEM cites work of MRPO and other states but does not provide any information to illustrate the 

baseline visibility conditions, the pollutant contributions, and the needed visibility improvement. 

We recommend that IDEM pick a Class I area from each region and include in Chapter 4 a 

summary of pollutant contributions in the baseline period for the average of the 20% worst days 

and monthly or daily time series from the IMPROVE data to illustrate the temporal variation in 

pollutant contributions. 

As part of the contribution assessment IDEM should explicitly state which pollutants would be 

most effective to control to improve visibility at the impacted Class I areas. We also recommend 

illustrating the glide paths for the uniform rate of progress for the selected Class I areas or at 

least adding these data to the Appendices and citing in Chapter 4 where the data can be found. 

IDEM Response: 

IDEM has included a summary, in Chapter 4, of pollutant contributions in the baseline period for 

the average of the 20% best and worst days for the northern Class 1 areas. Although pollutant 

contributions from Class 1 areas in the central, eastern and northeastern regions have been 

included in the discussion, the summary focused primary on the northern Class 1 areas. Detailed 

information to illustrate the baseline visibility conditions, the pollutant contributions, the needed 

visibility improvement and glide paths for the uniform rate of progress have been added in 

Appendix 9a. 

Chapter 5, Emissions Inventory: 

Comment:

This chapter very briefly summarizes the methods used by the MRPO to develop the 2005 and 

future year inventories. Please include the MRPO Technical Support Document as an Appendix. 

Table 3 summarizes the Electric Generating Unit (EGU) projections from the Integrated 

Planning Model (IPM) Version 3.0 for three scenarios. Please provide more detailed explanation 

how the three scenarios differ and explicitly why sulfur dioxide (SO2) and nitrogen oxides (NOx) 

emissions for Indiana are lower in Scenario 5a than Scenarios 5b and 5c. 
Appendix 9 - 2 

IDEM needs to discuss the projected emissions changes between 2005 and 2018 as evidence that 

Indiana is making reasonable progress. Table 4 does not appear to be cited or discussed in the 

text, yet this is the most important data for demonstrating Indiana’s emission reductions. Please 

provide emissions summaries in Table 4 as tons/year rather than tons/day to avoid questions how 

to account for weekly and seasonal variability to scale to tons/year values. 

IDEM Response: 

IDEM has included the LADCO Technical Support Document "Regional Air Quality Analyses 

for Ozone, PM2.5, and Regional Haze: Final Technical Support Document" in Appendix 9b. In 

addition, a more detailed discussion of the three scenarios and the projected emissions changes 

between 2005 and 2018 has been incorporated. A discussion of the Table 4 data has been 

incorporated, as well, and emissions summaries in Table 4 have been changed from tons/day to 

tons/year. 

Chapter 6, Modeling Assessment

Comment: 

IDEM relies on the MRPO modeling. Please include the MRPO Technical Support Document in 

an Appendix. A discussion of model performance is necessary to demonstrate confidence in 

model projections. There is not an Attainment Test for regional haze; you could delete the 

Section 6.2 header and cover the material under Section 6.1. 

The wording in the last paragraph on page 22 is confusing as written. Please clarify your intent. 

If model results are less than the uniform rate of visibility improvement does that mean greater 

visibility improvement than the uniform rate? 

The scenario terms used in Tables 6 and 7 are not the same as described in Chapter 5 Emissions 

Inventory. Please explain how the terms for the emissions assumptions in Tables 6 and 7 relate 

to the scenarios in Table 4. How does “Will Do” compare to Scenario 5a, 5b, or 5c? Do the 

“Will Do” adjustments pertain only to the EGU sector? Please provide additional clarification 

on what assumptions are included in the modeled scenarios. 

IDEM Response: 

IDEM has included the LADCO Technical Support Document "Regional Air Quality Analyses 

for Ozone, PM2.5, and Regional Haze: Final Technical Support Document" in Appendix 9 b and 

removed the section heading "Attainment Test for Regional Haze/Visibility." In addition, a 

better explanation of how the terms for the emissions assumptions in Tables 6 and 7 relate to the 

scenarios in Table 4 has been provided along with a clearer discussion of the visibility modeling 

results. 

Chapter 7, Reasonable Progress Goals

Comment: 

Please add reference to Appendix 1 for contribution assessments from MRPO and other RPOs 

and Appendix 2 for letters from states requesting consultation. 
Appendix 9 - 3 

We agree that based on the contribution assessments presented in Appendix 1 and 3 and in 

sections 7.2-7.9, Indiana sources have comparatively small contributions to Class I areas in 

neighboring states. 

To comply with the Regional Haze Rule Sections 308(d)(3)(ii) and (iv), IDEM still needs to 

demonstrate that it has included in its long term strategy all measures needed to achieve its share 

of emission reductions and to identify all anthropogenic sources of visibility impairment 

considered in developing the long term strategy. IDEM has cited modeling results of MRPO and 

neighboring RPOs, but IDEM still needs to evaluate its emission sources and demonstrate using 

a four factor analysis that Indiana is making reasonable progress in reducing anthropogenic 

emissions. This demonstration should evaluate the monitoring, emissions inventory, and 

modeling data to determine which pollutants are most important to control, what reductions are 

already expected by 2018, what source categories are major contributors in 2018, and evaluate 

the four factors for those major source categories. The MRPO provided a four factor analysis for 

major source categories that IDEM could cite in evaluating what control measures are feasible 

and reasonable for specific stationary sources. 

Several states have used emissions (Q) divided by distance (d) as a screening method to 

prioritize which stationary sources to consider in a reasonable progress analysis. If IDEM 

considered a Q/d for SO2+NOx = 10 for sources with emissions of SO2+NOx greater than 200 

tons/year, IDEM would likely be able to focus the reasonable progress analysis on specific 

stationary sources within a few major source categories. The VISTAS and CENRAP Areas of 

Influence are another method to identify which sources in Indiana should be evaluated for 

reasonable progress. 

IDEM Response: 

IDEM has added reference to Appendix 1 for contribution assessments from MRPO and other 

RPOs and Appendix 2 for letters from states requesting consultation. In addition, IDEM has 

included additional information related to Indiana's emissions and visibility contributions and a 

detailed discussion of the measures needed to achieve Indiana's share of reductions in Appendix 

9c and LADCO's "Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor 

Analysis” Document (July 18, 2007)". 

Chapter 8 Best Available Retrofit Technology (BART)

Comment: 

Please add greater description of the data presented in Table 10, BART-eligible Electric 

Generating Units (EGU) covered by the Clean Air Interstate Rule (CAIR) and discuss the 

implications in the text. Does Table 10 cover all EGU in Indiana including those units that are 

BART-eligible, those units listed by MANE-VU, and all other units? Please clarify what 

assumptions were used for each column. Does column “2009 + Projected” include only legally 

enforceable controls? What criteria were used to include a future control date? Does each 

succeeding column to the right include only controls that were not included in previous columns? 

If the LADCO column is empty does that mean that the controls assumed by IPM are legally 

enforceable and included in the LADCO modeling or not legally enforceable and not included in 

the LADCO modeling? Please make clear in the text that controls modeled by IPM Version 3.0 

are estimates and may not be legally required. 
Appendix 9 - 4 

IDEM Response: 

IDEM has added a more detailed description of the data presented in Table 10 and an 

explanation of the assumptions made for each column in the table. A discussion of the 

implications of the various modeling scenarios and the best current information available 

regarding Indiana EGU controls and the legal enforceability of these controls has been added. 

Section 8.4 BART Exemptions for ArcelorMittal-Burns Harbor, ESSROC-Speed, and 

SABIC

Comment: 

Based on our conference call on December 13, 2010, we understand that the ammonia values 

used in the final BART exemption modeling differed from the values cited in the MRPO BART 

modeling protocol. We request that IDEM update this section to clarify the revised ammonia 

values that better reflect measured values in the region. Because the visibility impacts of the 

three sources did not exceed the contribution threshold using the revised ammonia values, if 

IDEM updates the cited analytical methods to reflect the revisions, we can support the BART 

exemptions. 

IDEM Response: 

IDEM has updated this section to clarify the revised ammonia values that better reflect measured 

values in the region and added the discussions and data for ArcelorMittal Burns Harbor, 

ESSROC - Speed and SABIC CALPUFF results using Bondville Ammonia Monitoring Results 

2003-2005 in Appendix 9d.

Section 8.7 BART Determination for Alcoa

We question whether it is valid to take credit as a BART Alternative for SO2 and NOx reductions 

that were required under New Source Performance Standards (NSPS) when Alcoa increased the 

capacities of Boilers 1, 2, and 3. Boilers 2 and 3 are subject to BART; Boiler 1 is not. Boiler 4 

is classified as an EGU and is also subject to BART. Wet flue gas desulfurization (FGD) 

scrubbers were installed on all boilers in 2008. For SO2, NSPS requires 90% control. IDEM 

proposes to use SO2 reductions for Boiler 1 to offset the difference between BART (92% 

control) and proposed controls (90% control) for Boilers 2 and 3. IDEM credits the scrubber 

installed on Unit 1 as achieving significantly higher reductions in SO2, equal to approximately 

21,600 tons, than would be achieved by BART. However we understand that because Boiler 1 

was required by NSPS to reduce SO2 emissions by 90%, Alcoa can take credit in the BART 

Alternative for only the difference between the required 90% reduction and the proposed 91% 

reduction at Boiler 1. We do not believe that it is valid to use reductions that are required by 

permit to meet NSPS at Boiler 1 to also satisfy BART for the Boilers 2 and 3. 

Alcoa and IDEM have underestimated the efficiency of scrubbers (95%) and Selective Catalytic 

Reduction, SCR (90%). As well, Alcoa and IDEM are also proposing to increase SO2 and PM 

emissions from BART sources (potlines) above current levels. We do believe that the existing 

analyses support the determination that the BART Alternative is better than BART. 
Appendix 9 - 5 

Section 8.7 BART Determination and Modeling for Alcoa

8.7.1 Summary of Alcoa BART Analysis 

Comment: 

According to IDEM, the alternative achieves a visibility improvement equal to 0.46 dv and an 

overall improvement in visibility equal to 75% over the baseline and achieves significantly 

higher reductions in SO2, equal to approximately 21,600 tons. However, it is likely that the 

majority of the emission reductions cited by IDEM were the result of efforts by Alcoa to increase 

the capacities of Boilers 1, 2, and 3 while avoiding review under the Prevention of Significant 

Deterioration (PSD) regulations. In order to do so, Alcoa installed wet scrubbers to reduce SO2

emissions from these units, as well as installing Selective Catalytic Reduction on Boiler #4 to 

offset NOX emission increases from Boilers 1, 2, and 3. Therefore, we question whether it is 

valid to take credit as a BART Alternative for reductions made for other purposes, as we shall 

discuss later. 

IDEM Response: 

IDEM’s approach to BART reductions has been to follow guidance from various parts of the 

regional haze program. In the 1999 Regional Haze Regulations, Subpart P – Protection of 

Visibility, it states that reductions must be surplus to required emission reductions up to the 

baseline date. The established baseline date is 2002. The year 2002 has been used by various 

states, RPOs, and the EPA regional haze modeling guidance. It is also specified by the Lydia 

Wegman November 18, 2002 memo, “2002 Base Year Emission Inventory SIP Planning: 8-hr 

Ozone, PM2.5 and Regional Haze Programs.” 

The BART Rule, 70 FR 128, 39143, states that “(2) The EPA does not believe that anything in 

the CAA or relevant case law prohibits a State from considering emissions reductions required to 

meet other CAA requirements when determining whether source by source BART controls are 

necessary to make reasonable progress.” and “(3)...in lieu of BART programs be based on 

emissions reductions ‘surplus to reductions resulting from measures adopted to meet 

requirements as of the baseline date of the SIP.’ The baseline date for regional haze SIPs is 

2002...” This is extracted from a discussion justifying the use of CAIR, a program used for 

other purposes, to substitute for BART. Therefore, it is our belief that it is valid to take credit for 

BART alternatives made for other purposes. 

8.7.2 BART-eligible units at Alcoa

Alcoa identified 18 ingot furnaces, three boilers (Boilers 2, 3, and 4), and five aluminum refining 

furnaces (Potlines 2-6) as meeting the BART-eligibility criteria. Boilers 2 and 3 are classified as 

industrial boilers. Boiler 4 is classified as an Electric Generating Unit (EGU). Alcoa, in its 

December analysis addressed PM, SO2, and NOx for all its BART-eligible units including Boiler 

4. According to the Indiana BART rule, 326 IAC 26-1-5, participation of this boiler in the Clean 

Air Interstate Rule (CAIR) satisfies the SO2 and NOX requirements. The BART analysis will 

therefore address PM only for this boiler. 
Appendix 9 - 6 

Boilers 2, 3, and 4 are dry bottom, pulverized coal-fired units. Boiler 2 came online in January 

1964, Boiler 3 came online in October 1965, and the construction of Boiler 4 started on March 

16, 1968. Boilers 2 and 3 each had a nominal heat input capacity of 1,357 MMBtu/hr prior to a 

recent upgrade to a nominal heat input capacity of 1,589 MMBtu/hr. Boiler 4 has a nominal heat 

input capacity of 2,958 MMBtu/hr. Each boiler is equipped with an electrostatic precipitator 

(ESP) for PM control. Boiler 2 was equipped with a low NOX burner (LNB) and overfire air 

(OFA) in 2004, Boiler 3 was equipped with LNB and OFA in 2002, and Boiler 4 was equipped 

with a LNB in 1998 and a selective catalytic reduction (SCR) system in 2004. Wet flue gas 

desulfurization (FGD) scrubbers were installed on all boilers in 2008. 

Emissions from potlines are captured and controlled with primary controls. Any uncaptured 

emissions escape through the roof monitors atop the potline buildings. The primary controls 

consist of a gas treatment system followed by a fabric filtration system. The total fluoride and 

particulate removal efficiencies of the control systems are estimated to exceed 99%. 

Ingot furnace emissions are uncontrolled. There are several material handling operations at the 

facility that meet the criteria for beginning operation between 1962 and 1977. However, the 

BART Guidelines require that only those operations at primary aluminum ore reduction plants 

that meet the NSPS applicability criteria for this source category should be considered for BART 

controls. These operations are the potroom groups and anode bake plants. IDEM also identified 

three (3) ingot furnaces in the Alcoa Title V permit that meet the 1962-1977 timeline criteria but 

were not included in the analysis. According to Alcoa, one of these furnaces has been physically 

removed and the other two furnaces did not operate in the baseline years. IDEM considers the 

impact of the other 18- furnaces to be negligible. 

8.7.3 BART Analysis 

The initial screening model projected the highest visibility impact at Mammoth Cave National 

Park (MCNP). Other Class I areas screened included Mingo Wilderness Area, Sipsey Wilderness 

Area, Great Smoky Mountains National Park, Joyce Kilmer – Slick Rock Wilderness Area, 

Cohutta Wilderness Area, and Shining Rock Wilderness Area. The impact at MCNP exceeded 

0.5 dv. Since the visibility impact was highest at MCNP, the BART analysis was solely based on 

the impact at MCNP. 

8.7.4 Control Strategy 

IDEM: Alcoa proposed an alternative to BART which requires less emissions reductions on 

some units for technical or economic reasons. However, it proposes to control emissions from 

Boiler 1 which is not a BART-eligible unit. For example, Alcoa determined SO2 BART for 

Boilers 2 and 3 as 92% reduction, but it proposes to control SO2 emissions from these boilers by 

90% as an alternative. Alcoa currently limits sulfur in the anode grade coke to ≤ 2%. Based on a 

market study, it has determined that the supply of <3% sulfur coke cannot be ascertained beyond 

2013. Therefore, it proposes BART as ≤ 3% sulfur coke and the alternative as ≤ 3.5% sulfur 

coke. In the alternative, the source proposes to control SO2 emissions from Boiler 1 by 91% and 

NOx emissions at 0.38 lb/MMBtu. 
Appendix 9 - 7 

Comment: 

We do not believe that it is valid to use reductions that are required by permit to avoid PSD1

and/or meet New Source Performance Standards (NSPS) at Boiler #1 to also satisfy BART for 

the BART sources. Construction began in 2005 and the FGDs went on-line in 2008 with the 

start-up of each re-rated unit. The upgraded boilers had to meet NSPS (since they were modified 

after Feb. 28, 2005) for large boilers (1, 2, and 3). 90% is the requirement for NSPS and Boiler 1 

is used to offset the difference with 2 and 3. Because Boiler #1 was required by NSPS to 

reduce SO2 emissions by 90%, we understand that Alcoa can take credit for only the 

difference between the required 90% reduction at Boiler #1 and the proposed 91% 

reduction at Boiler #1 in its BART Alternative.

 

IDEM Response: 

Please see the IDEM response to 8.7.1 above. 

Comment: 

The majority of the emission reductions and visibility improvement cited by IDEM were the 

result of efforts by Alcoa to increase the capacities of Boilers 1, 2, and 3 while avoiding PSD. 

The only emission reductions attributable to BART are due to the 91% SO2 control on Boiler 1 

versus the 90% control required by NSPS. Otherwise, Alcoa/IDEM are proposing to increase 

SO2 and PM emissions above current levels. 

IDEM Response: 

IDEM disagrees with the statement that "Alcoa/IDEM are proposing to increase SO2 and PM 

emissions above current levels" because, as stated in the response to 8.7.1 above, it is our belief 

that it is valid to take credit for BART alternatives made for other purposes. Therefore, 

emissions will be reduced and visibility improved from the base year as a result of Alcoa’s 

compliance with New Source Review and NSPS requirements. 

8.7.5 Discussion 

1. Highest Contributors to Visibility Impairment

IDEM: Boilers 2 and 3 are the highest contributors to visibility impairment. In the year of 

maximum impact, Boilers 2 and 3 contribute approximately 95%, followed by potlines 3%, 

followed by Boiler 4 equal to 2%, and the contribution from ingot furnaces is zero. Sulfates and 

nitrates from Boilers 2 and 3 account for 73% and 25% of the impacts, respectively. 

2. Boilers 2 and 3 - SO2

Comment: 

Alcoa has underestimated the effectiveness of wet scrubbing on its high sulfur coal. 

Although Alcoa cites “Typical removal efficiencies are 80–95%,” for SO2 scrubbers, 

Alcoa/IDEM determined BART as wet limestone flue gas desulfurization (FGD) for these 

boilers at control efficiency equal to 92%. Alcoa appears to have decided that Best Available 

Retrofit Technology is merely the average performance level (91.8%) of the scrubbers it found 

                                                           

1

 Limits on overall emissions of PM, NOX, and H2SO4 to avoid PSD were part of the permit. 
Appendix 9 - 8 

in the RBLC.2 Presumptive BART for coal-fired boilers3 is 95% SO2 control or 0.15 lb/mmBtu, 

neither of which was evaluated by Alcoa. BART for these boilers should be at least 95% SO2

control. 

While the BART Guidelines allow special consideration for existing scrubbers achieving greater 

than 50% SO2 control, we do not believe that the Alcoa scrubbers were in existence at the time 

of their July 6, 2005 publication. Although we could not find a clear definition of an “existing 

scrubber” in the BART Guidelines, we suggest that the same reasoning provided by the BART 

Guidelines for determining if a source is “in existence”4

 would logically apply to a scrubber. 

The only record we could find regarding permitting of the Alcoa scrubbers is an IDEM “Notice 

of Decision” dated December 29, 2005, five months after publication of the BART Guidelines: 

On November 17, 2005, the Office of Air Quality (OAQ) received an interim significant source 

modification petition from Alcoa Power Generating Inc. (APGI) - Warrick Power Plant located 

at 4700 Darlington Road, Newburgh, Indiana for construction of wet scrubbers for sulfur dioxide 

reduction and for the accompanying construction of material handling facilities and 

modifications to the coal pulverizers and the boilers identified as Units 1, 2, 3, and 4. 

We conclude that the Alcoa scrubbers were not “existing” at the time the BART Guidelines 

were published, and BART for Boilers 1 and 2 must be analyzed as if the scrubbers are not 

“existing.” If BART is determined to be greater than the 92% control proposed by 

Alcoa/IDEM, then it is likely that Alcoa would need to either demonstrate that they will 

achieve the higher BART level or upgrade them to do so. 

                                                           

2

 Twenty-four units were identified in the RBLC database that could be consider similar to the boiler units at Alcoa. 

Of these 24 units, approximately half utilized a form of dry flue gas desulfurization to control SO2 emissions, seven 

used wet scrubbing to control SO2 emissions, and the remaining units used other means such as low sulfur coal and 

good combustion practices. Of the 24 units in the database, 10 listed an SO2 removal efficiency in the range of 90% 

to 95% with an average of 91.8%. 

Based on the RBLC database analysis, which indicated an average control efficiency of 91.8% was BACT for SO2

from industrial boilers, and Standards of Performance for Industrial-Commercial-Institutional Steam Generating 

Units (40 CFR 60 Subpart Db) requires a 92% removal efficiency for this type of source, if reconstructed, it was 

determined that 92% efficiency would be reasonable for units 2 and 3. 

3

 Even though Boilers 2 and 3 are not subject to presumptive BART, it can be presumed that the technology 

assumed to achieve the presumptive limits for coal-fired EGUs greater than 200 MW can achieve similar results on 

the smaller coal-fired Alcoa boilers. We note that IDEM has referred to the presumptive BART limits for coal-fired 

EGUs greater than 200 MW in its review of NOX BART. 

4

 The visibility regulations define "in existence" in 40 CFR 51.301. Under these regulations, promulgated in 1980, 

“in existence” means that the owner or operator has obtained all necessary preconstruction approvals or permits . . . 

and either has (1) begun, or caused to begin, a continuous program of physical on-site construction of the facility or 

(2) entered into binding agreements or contractual obligations. 
Appendix 9 - 9 

IDEM Response: 

Alcoa used the 92% reduction level for the BART analysis for Boilers 2 and 3. The BART 

proposal was to control Boiler 1 at 91% and Boiler 2 and 3 at 90%, which still results in an 

overall improvement in visibility degradation. The actual modifications performed to the boilers 

were not extensive enough to trigger the 92% removal efficiency level requirements. 

3. Boilers 2 and 3 - NOx 

IDEM: Alcoa proposes low NOx Burners (LNB) and OFA with an emission limit equal to 0.38 

lb/MMBtu as BART and as alternative BART for these boilers. U.S.EPA’s presumptive BART 

limit for these boiler types is equal to 0.39 lb/MMBtu. Baseline modeling without these controls 

shows the highest visibility impact due to these boilers equal to 0.458 dv, which is projected to 

decrease to 0.064 dv with the above controls. Alcoa identified Selective Non-catalytic Reduction 

(SNCRs) and SCRs as feasible technologies to control NOx from these boilers; however, it did 

not perform visibility impact analysis with these technologies. The capital and annual costs of 

SNCR controls on these boilers are estimated at $3 million and $2.8 million respectively. The 

capital and annual costs of SCRs are estimated at $70 million and $13 million. Additional 

controls on these boilers are likely to yield visibility improvement at a very high cost/benefit 

($/dv improvement). 

Comment: 

Alcoa has underestimated the effectiveness of SCR. Although Alcoa notes that "SCR is 

capable of NOx reduction efficiencies in the range of 70–90%," it assumed 78% control in its 

cost analyses. It is generally assumed that a properly designed and operated SCR can achieve at 

least 90% control. 

Comment: 

Alcoa did not perform a five-step BART analysis for SNCR and SCR for Boilers 2 and 3 

because it did not perform visibility impact analysis with these technologies. The NOx 

controls proposed as BART are already required. 

IDEM Response: 

The NOx controls are significantly tighter than NSPS limits (0.38 lb/MMBTu vs. 0.70 

lb/MMBTu), which are the “required” controls referenced. In the Alcoa evaluation of possible 

NOx controls, LNBs were found to be cost effective options for the boilers at about $160/ton of 

NOx removed. SCNR at approximately $3,300/ton removed and SCR at approximately 

$5,100/ton removed were not further evaluated as feasible alternatives for NOx removal. 

4. Potlines 

IDEM: The maximum impact from these sources is 0.231 dv. This includes contributions due to 

vents and primary controls. Sulfates are the main contributors, at approximately 0.188 dv. 

Contributions due to other species are less than 0.01 dv. Therefore, any add-on controls for these 

pollutants will result in insignificant improvements in visibility. Due to insignificant impact from 

vents (0.013 dv), Alcoa did not perform the 5-step analysis for these sources. Further, these 

sources are subject to 40 CFR 63, Subpart LL, Maximum Achievable Control Technology 
Appendix 9 - 10 

(MACT). In order to comply with these standards, Alcoa follows work practices which minimize 

emissions escaping roof vents. 

Sulfur dioxide from potlines can be controlled by lowering sulfur content in the anode grade 

coke and/or by installing wet scrubbers. Alcoa presently limits sulfur at ≤ 2%. From a market 

study, Alcoa has concluded that a supply of coke below 3% sulfur cannot be ensured beyond 

2013, the year when the BART controls will be needed. Therefore it proposes ≤ 3% sulfur coke 

as BART and ≤ 3.5% sulfur coke as alternative BART. The 3.5% sulfur limit in the coke 

translates into 2.919% sulfur in the baked anode composite, the practice Alcoa follows to 

measure the sulfur content. 

The installed and annual costs of wet scrubbers on potlines are estimated at $300 million and $55 

million respectively. Modeling shows that SO2 scrubbers on potlines can improve visibility by 

0.138 dv. This improvement will be achieved at a cost/benefit ratio equal to $398 million/dv. 

Also, there are severe space and access limitations at the facility that would complicate the 

installation. 

Comment: 

Alcoa is proposing to increase SO2 emissions by 75% from this operation. 

IDEM Response: 

It is true that emissions will be increased due to the unavailability of 2% sulfur content petroleum 

coke and that is clearly explained in the discussion of the potline alternatives. This projected 

unavailability of 2% sulfur coke is the primary reason Alcoa proposed the alternative to BART. 

Taken in the context of a whole BART alternative, these increases, while approximately 75% for 

pot line emissions, are part of a scenario that results greater emissions reductions than straight 

BART. 

5. Boilers 2, 3 and 4 - PM 

IDEM: The maximum baseline impact due to filterable PM emissions from these sources is 

0.035 dv. Alcoa proposes ESPs with an emission limit equal to 0.03 lb/MMBtu as BART 

controls for Boilers 2 and 3. Alcoa determined BART for Boiler 4 as 0.015 lb/MMBtu, but it 

proposes alternative BART for this boiler as 0.1 lb/MMBtu. This boiler has a LNB and SCR for 

NOx control. Alcoa has noticed excessive conversion of SO2 to SO3 in the SCR due to the 

addition of an extra catalyst layer. To reduce SO3, which has the potential to adversely affect the 

downstream equipment and in order to comply with the sulfuric acid limit in its permit, Alcoa 

has applied for a permit to install a dry reagent injection system between the SCR and ESP. This 

system will remove SO3 from the gas stream, but it is expected to adversely affect the 

performance of the downstream ESP. The impact of this system on the ESP performance is not 

yet known. To account for this uncertainty, Alcoa proposes 0.1 lb/MMBtu as the alternative 

BART limit. A recent test, after the startup of the SO2 scrubber on this boiler, measured an 

emission rate equal to 0.05 lb/MMBtu which includes PM and sulfuric acid. 

The above limits are projected to lower the contribution from Boilers 2, 3, and 4 to 

approximately 0.005 dv. Alcoa identified fabric filters as feasible control technology for these 
Appendix 9 - 11 

boilers. However, estimating that these controls will not significantly improve visibility, it did 

not perform cost and visibility impact analyses with these controls. It roughly estimated the cost 

of fabric filters on these boilers at $97.18 million. This estimate is based on the cost of a fabric 

filter installed on a utility boiler. Alcoa estimates that installation of fabric filters on these boilers 

will improve visibility by 0.024 dv at a cost/benefit ratio equal to $445 million/dv. 

Comment: 

Alcoa did not perform a five-step BART analysis for PM for Boiler 4. (For example, Alcoa 

should have investigated low-oxidation catalysts, fabric filtration, and wet ESPs.) Instead, Alcoa 

is proposing to increase PM emissions from this unit. 

IDEM Response: 

At IDEM’s request, Alcoa provided information regarding the cost of adding a baghouse on each 

unit. 

Alcoa evaluated fabric filtration for Boiler 4 , the installation cost on a $ / dv basis was shown to 

be unreasonable. PM emissions from Boiler 4 would be higher than the BART level of control 

of 0.015 lb./mm Btu, which is the NSPS for a new utility boiler. However, the alternative to 

BART emission reductions provided by Boiler #1 offsets the PM emissions that would exceed 

the BART alone level from Boiler 4, and would therefore meet the regional haze rule 

requirements. 

Impact of Adding Baghouses for Units 2, 3, and 4

Based on information provided by another utility where baghouse control was installed, the 

capital cost for a baghouse on a 2830 mm Btu/hr. boiler was $49.7 mm. Assuming baghouse 

capital costs are proportional to heat input, the capital cost for the baseline heat inputs for the 

BART eligible boilers is estimated to be: 

Boiler 2: 1364.41 mm Btu/hr. Estimated baghouse capital cost would be 

(1364.41/2830) X $49.7 mm = $23.96 mm 

Boiler 3: 1323.51 mm Btu/hr. Estimated baghouse capital cost would be 

(1323.51/2830) X $49.7 mm = $23.24 mm 

Boiler 4: 2845.79 mm Btu/hr. Estimated baghouse capital cost would be 

(2845.79/2830) X $49.7 mm = $49.98 mm 

Airflow for boiler 2: 347,149 scfm 

Airflow for boiler 3: 335,372 scfm 

Airflow for boiler 4: 796,416 scfm 
Appendix 9 - 12 

Assuming the lowest emission rate a baghouse vendor will guarantee is 0.005 grains /scf, 

filterable PM emissions would be: 

Boiler 2: (0.005 grains/scf) X (347,149 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 14.88 

lbs./hr. 

Boiler 3: (0.005 grains/scf) X (335,149 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 14.36 

lbs./hr. 

Boiler 4: (0.005 grains/scf) X (796,416 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 34.13 

lbs./hr. 

On an annualized basis, the filterable PM emissions would be 128.07 tons from boilers 2 and 3 

combined, and 149.49 tons/yr. from boiler 4. 

Because the baghouses will be upstream of wet scrubbers, the assumed baghouse vendor 

guarantee emissions is conservative because it does not take into account the added filterable PM 

from the scrubbers. 

BART for filterable PM for all 3 boilers was electrostatic precipitators and SO2 scrubbers. 

BART was proposed at 0.03 lb./mm Btu for boilers 1 and 2, and 0.015 lb./mm Btu for boiler #4. 

BART annual filterable PM emissions would thus be: 

Boiler 2: (0.03 lb./mm Btu) X (1364.41 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

179.28 tons/yr. 

Boiler 3: (0.03 lb./mm Btu) X (1323.51 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

173.91 tons/yr. 

Boiler 4: (0.015 lb./mm Btu) X (2845.79 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

186.97 tons/yr. 

Detailed engineering would have to take into consideration the available real estate for 

installation of baghouses, removal of the precipitators or routing the exhaust gases in series 

through the precipitators, baghouses then downstream pollution removal equipment, present 

boiler and pollution control equipment configurations, ash handling from the ash removed by the 

baghouses, etc. Those factors would increase the capital cost assumptions used above. 

For the $/ton and $/dv improvement derived below, and the present prevailing economic 

conditions, Alcoa Power Generating Inc. – Warrick Power Plant does not understand the 

usefulness of performance of such a study. 

Assuming an annualized cost of 11% of the assumed capital costs, the annualized cost on a $/ton 

difference between the alternative to BART proposal and baghouses would be: 

Boilers 2 and 3: 11% of $47.2 mm = $5,192,000 / yr. 
Appendix 9 - 13 

BART emissions: 353.19 tons/yr. 

Baghouse: 128.07 tons/yr. 

Baghouse additional removal: (353.19 – 128.07) tons/yr. = 225.12 tons/yr. 

$ / ton impact: $5,192,000 / 225.12 tons/yr. = $23,063.26 / ton 

Boiler 4: 11% of $49.98 mm = $5,497,800 / yr. 

BART emissions: 186.97 tons/yr. 

Baghouse: 149.49 tons/yr. 

Baghouse additional removal: (186.97 – 149.49) tons/yr. = 37.48 tons/yr. 

$ / ton impact: $5,497,800 / 37.48 tons/yr. = $146,686.23 / ton 

Baseline visibility impact, filterable PM, boilers 2 and 3: 0.027 dv, based on 2003 (See revised 

table 5-2 in the BART determination report). 

The assumed baghouse outlet emissions would result in a filterable PM reduction of: 

Baseline: 635.02 lbs/hr. 

Baghouse: 63.37 lbs./hr. 

Reduction: [(635.02 – 63.37)/635.02] X 100 = 90.02% 

A reduction of 90.02% in the visibility impact would represent a dv impact reduction of: 

0.027 dv X (90.02/100) = 0.024 dv 

The annualized cost for baghouses on a $/dv basis would thus be: 

$(5,192,000 + 5,497,800) / 0.024 dv = $445 mm / dv 

The above 11% of capital assumption does not consider such operating costs as increased 

pressure drop represented by the baghouse, possible de-rating of the boiler, and the baghouse 

being upstream of a wet scrubber. The above cost estimates are thus low, but still show that the 

extra cost represented by baghouses is unreasonable both from a $/ton and $/dv basis. 

6. Ingot furnaces 

IDEM: The maximum baseline impact from these sources is 0.003 dv. Due to insignificant 

impact from these sources, Alcoa did not perform a 5-step BART analysis for these sources. 
Appendix 9 - 14 

Comment: 

Conclusions & Recommendations 

According to IDEM, the proposed BART Alternative achieves a visibility improvement equal to 

0.46 dv and an overall improvement in visibility equal to 75% over the baseline and achieves 

significantly higher reductions in SO2, equal to approximately 21,600 tons. While we recognize 

the emission reductions and visibility improvements that result from Alcoa’s compliance with 

New Source Review and NSPS requirements, we believe that the proposed BART Alternative 

improperly relies upon SO2 emission reductions that are already required by NSPS. 

Instead, it appears that Alcoa is proposing to increase PM emissions from Boiler #4 and SO2

emissions from the potlines, which is contrary to the fundamental premise of BART, unless it 

can at least be shown that the additional reductions of SO2 from Boiler #1—reductions beyond 

the 90% required by NSPS—result in more visibility improvement than the 1.5 dv that would be 

achieved if Alcoa met its proposed BART. (If BART is determined to be more stringent than 

proposed by Alcoa, then additional visibility improvements would be needed.) For example, it 

may be necessary to model the following scenarios: 

1.Baseline, BART-eligible units and Boiler #1@ 90% SO2 control 

2.BART, BART-eligible units and Boiler #1@ 90% SO2 control 

3.Alternative BART 

If Scenario #3 achieves greater visibility improvement than Scenario #2, then the Alternative 

BART would be acceptable. 

IDEM Response: 

IDEM believes that the emissions reductions associated with the NSPS for Boiler 1 should be 

included as part of the BART engineering analysis. Therefore, the modeling that has been 

conducted to date is valid. Review of the modeling results shows that the percent improvement 

from BART Eligible baseline to the BART control and BART Eligible baseline with Unit #1 to 

Alternative to BART fall within 4% of each other with a greater deciview improvement from the 

Alternative to BART scenario, which would average nearly 2 deciview improvement. 

Table 6-1 Visibility Impacts at Mammoth Cave National Park – BART Eligible Baseline Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 46.13 22.36 3.275 1.852 

2002 56.17 23.38 3.722 1.906 

2003 37.03 21.40 2.787 1.788 

2001-2003 56.17 22.38 3.722 1.849 

Table 6-5 Visibility Impacts at Mammoth Cave National Park – BART Control Level Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 9.18 4.60 0.850 0.444 

2002 10.46 3.07 0.958 0.299 

2003 10.75 4.16 0.992 0.402 

2001-2003 10.46 3.94 0.933 0.382 
Appendix 9 - 15 

Visibility Impacts at Mammoth Cave National Park – 

Difference between BART Eligible Baseline Emissions and BART Control Level Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 36.95 17.76 2.425 1.408 

2002 45.71 20.31 2.764 1.607 

2003 26.28 17.24 1.795 1.386 

2001-2003 45.71 18.44 2.789 1.467 

Percentage Difference between BART Eligible Baseline and BART Control Emissions 

2001 80.10% 79.43% 74.05% 76.03% 

2002 81.38% 86.87% 74.26% 84.31% 

2003 70.97% 80.56% 64.41% 77.52% 

2001-2003 81.38% 82.39% 74.93% 79.34% 

Table 6-2 Visibility Impacts at Mammoth Cave National Park – BART Eligible Baseline + Unit 1 Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 60.69 28.81 4.042 2.311 

2002 85.38 35.39 4.570 2.774 

2003 55.30 31.61 3.329 2.549 

2001-2003 85.38 31.94 4.570 2.545 

Table 6-3 Visibility Impacts at Mammoth Cave National Park – Alternative to BART Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 13.98 7.24 1.265 0.686 

2002 16.33 4.81 1.446 0.463 

2003 14.85 5.75 1.323 0.549 

2001-2003 16.33 5.93 1.345 0.566 

Visibility Impacts at Mammoth Cave National Park – 

Difference between BART Eligible Baseline + Unit 1 Emissions and Alternative to BART Emissions 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

 (%) (%) (DV) (DV) 

2001 46.71 21.57 2.777 1.625 

2002 69.05 30.58 3.124 2.311 

2003 40.45 25.86 2.006 2.000 

2001-2003 69.05 26.01 3.225 1.979 

Percentage Difference between BART Eligible Baseline + Unit 1 and Alternative to BART Emissions 

2001 76.96% 74.87% 68.70% 70.32% 

2002 80.87% 86.41% 68.36% 83.31% 

2003 73.15% 81.81% 60.26% 78.46% 

2001-2003 80.87% 81.43% 70.57% 77.76% 
Appendix 9 - 16 

Difference between BART eligible baseline and baseline + Unit 1 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

(%) (%) (DV) (DV) 

2001 14.56 6.45 0.767 0.459 

2002 29.21 12.01 0.848 0.868 

2003 18.27 10.21 0.542 0.761 

2001-2003 29.21 9.56 0.848 0.696 

Difference between Alternative to BART and BART Control 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

(%) (%) (DV) (DV) 

2001 4.8 2.64 0.415 0.242 

2002 5.87 1.74 0.488 0.164 

2003 4.1 1.59 0.331 0.147 

2001-2003 5.87 1.99 0.412 0.184 

Year Maximum Delta Bext 98th Percentile Delta Bext Maximum Delta 98th Percentile Delta 

(%) (%) (DV) (DV) 

2001 9.76 3.81 0.352 0.217 

2002 23.34 10.27 0.36 0.704 

2003 14.17 8.62 0.211 0.614 

2001-2003 23.34 7.57 0.436 0.512 

Chapter 9 Long Term Strategy 

Comment: 

Indiana needs to provide a more complete discussion of the long term strategy. The Strategy 

should list all the existing control programs that Indiana is implementing. Does the State have 

rules to limit emissions from construction sources? Indiana appears to rely on existing controls 

under CAIR or the proposed Transport Rule and existing federal requirements to reduce mobile 

sources. The State has not discussed any controls or consideration of controls beyond those 

required for other regulatory purposes. 

Table 6-7 Source and Specie Contributions to 8th Highest Extinction changes for BART Eligible Baseline at Mammoth Cave 

Source Group 

Bext 

Change 

Contribution 

to 

Total 

Bext 

Modeled 

Extinction 

SO4 

Contribution 

NO2 

Contribution 

Organics 

Contribution 

Elemental 

Carbon 

Contribution 

PM 

Coarse 

Contribution 

PM Fine 

Contribution 

 (%) (%) Mn-1 Mn-1 Mn-1 Mn-1 Mn-1 Mn-1 Mn-1

All Sources 22.380 100.000 4.818 4.087 0.574 0.066 0.000 0.001 0.089 

Lines 0.080 0.367 0.017 1.336 0.000 0.007 0.000 0.001 0.005 

GTC 0.493 2.213 0.106 0.098 0.001 0.004 0.000 0.000 0.003 

A-398s 0.680 3.073 0.146 0.135 0.001 0.004 0.000 0.000 0.004 

Melter/Holders 0.020 0.033 0.002 0.033 0.004 0.000 0.000 0.000 0.001 

WPP01 4.870 21.740 1.049 0.890 0.145 0.006 0.000 0.000 0.008 

WPP02 15.923 71.130 3.429 2.960 0.425 0.018 0.000 0.000 0.022 

WPP03 0.313 1.443 0.067 0.000 0.000 0.023 0.000 0.000 0.045 
Appendix 9 - 17 

The Federal Land Managers request that Indiana acknowledge the connection between new 

emission permitting under New Source Review and the Regional Haze Rule visibility 

improvement goals to return to natural background visibility conditions by 2064. We 

recommend that the State commit to considering the visibility impacts as part of the New Source 

Review. 

IDEM Response: 

Indiana has state rules with specific requirements that apply to emissions from construction 

sources and visibility. First, “rules to limit emissions from construction sources”, IDEM thinks 

that all Class 1 areas are far enough away from any construction sources in Indiana that there 

would be no impact on visibility. However, Indiana's Article 6 Particulate Rules, Rule 6-4, 

Fugitive Dust Emissions, limits fugitive emissions from construction activities. Second, 

“adverse impact on visibility” is defined and the responsibilities of sources impacting federal 

Class I areas outlined in Indiana’s Article 2 Permit Review Rules, Rule 2-2, Prevention of 

Significant Deterioration (PSD) Requirements. The following sections are taken from Indiana 

Administrative Code that covers the Air Pollution Control Board. 

326 IAC 2-2-1 Definitions

(c) "Adverse impact on visibility" means visibility impairment that interferes with the 

management, protection, preservation, or enjoyment of the visitor's visual experience of the 

federal Class I area as defined in section 13 of this rule. This determination must be made on a 

case-by-case basis taking into account the geographic extent, intensity, duration, frequency, and 

time of visibility impairment, and how these factors correlate with: 

(1) times of visitor use of the federal Class I area; and 

(2) the frequency and timing of natural conditions that reduce visibility. 

326 IAC 2-2-14 Sources impacting federal Class I areas: additional requirements

Sec. 14. (a) The department shall provide written notice of any permit application for a proposed 

major stationary source or major modification, the emissions from which may affect a Class I 

area, to the federal land manager and the federal official charged with direct responsibility for 

management of any lands within any such area. Such notification shall be given within thirty 

(30) days of receipt of a permit application and at least sixty (60) days prior to any public hearing 

on the application for a permit to construct and shall include the following: 

(1) A copy of all information relevant to the permit application. 

(2) An analysis of the proposed source's anticipated impacts on visibility in the federal Class I 

area. The department shall also provide the federal land manager and such federal officials with 

a copy of the preliminary determination required under this section, and shall make available to 

them any materials used in making that determination, promptly after the department makes the 

determination. The department shall also notify all affected federal land managers within thirty 

(30) days of receipt of any advance notification of any such permit application. 

(b) The federal land manager and the federal official charged with direct responsibility 

for management of the Class I area have an affirmative responsibility to protect the air quality 

related values, including visibility, of the Class I area and to consider, in consultation with U.S. 

EPA, whether a proposed source or modification will have an adverse impact on such values. 
Appendix 9 - 18 

(c) The department shall consider any analysis performed by the federal land manager, 

provided to the department within thirty (30) days of the notification required by subsection (a), 

that shows that a proposed new major stationary source or major modification may have an 

adverse impact on visibility in any federal Class I area. Where the department finds that the 

analysis does not demonstrate to the satisfaction of the department that an adverse impact on 

visibility will result in the federal Class I area, the department must, in the notice of public 

hearing on the permit application, either explain the decision or give notice as to where the 

explanation may be obtained. 

(d) The federal land manager of any Class I area may demonstrate to the department that 

the emissions from a proposed major stationary source or major modification would have an 

adverse impact on the air quality-related values, including visibility, of a Class I area, 

notwithstanding that the change in air quality resulting from emissions from the major stationary 

source or major modification would not cause or contribute to concentrations that would exceed 

the maximum allowable increases for a Class I area. If the department concurs with the 

demonstration, then the department shall not issue the permit. 

(e) The owner or operator of a proposed major stationary source or major modification 

may demonstrate to the federal land manager that the emissions from the source or modification 

would have no adverse impact on the air quality related values of any Class I areas, including 

visibility, notwithstanding that the change in air quality resulting from emissions from the major 

stationary source or major modification would cause or contribute to concentrations that would 

exceed the maximum allowable increases for a Class I area. If the federal land manager concurs 

with the demonstration and the federal land manager so certifies, the department may issue the 

permit provided that the applicable requirements of this section are otherwise met, to issue the 

permit with emission limitations as may be necessary to assure that emissions of sulfur dioxide, 

particulate matter, and nitrogen oxides shall not exceed the following maximum allowable 

increases over minor source baseline concentration for such pollutants: 

Maximum Allowable Increase 

Pollutant (Micrograms Per Cubic Meter)

Particulate matter: 

PM10, annual arithmetic mean 17 

PM10, 24 hour maximum 30 

Sulfur dioxide: 

Annual arithmetic mean 20 

24 hour maximum 91 

3 hour maximum 325 

Nitrogen dioxide: 

Annual arithmetic mean 25 

(f) The owner or operator of a proposed major stationary source or major modification 

that cannot be approved under subsection (e) may demonstrate to the department that the source 

cannot be constructed by reason of any maximum allowable increase for sulfur dioxide for a 

period of twenty-four (24) hours or less applicable to any Class I area and, in the case of federal 

mandatory Class I areas, that an exemption under this subsection would not adversely affect the 

air quality related values of the area, including visibility. The department, after consideration of 

the federal land manager's recommendation, if any, and subject to the federal land manager's 
Appendix 9 - 19 

concurrence, may, after notice and public hearing, grant an exemption from such maximum 

allowable increase. If such exemption is granted, the department shall issue a permit to such 

major stationary source or major modification pursuant to the requirements under subsection (h) 

provided that the applicable requirements of this section are otherwise met. 

(g) In any case where the department recommends an exemption in which the federal 

land manager does not concur, the recommendations of the department and the federal land 

manager shall be transmitted to the president. The president may approve the department's 

recommendation if the president finds that the exemption is in the national interest. If the 

exemption is approved, the department shall issue a permit pursuant to the requirements under 

subsection (h) provided that the applicable requirements of this section are otherwise met. 

(h) In the case of a permit issued pursuant to subsection (f) or (g), the major stationary 

source or major modification shall 

comply with such emission limitations as may be necessary to assure that emissions of sulfur 

dioxide from the major stationary source or major modification would not, during any day on 

which the otherwise applicable maximum allowable increases are exceeded, cause or contribute 

to concentrations that would exceed the following maximum allowable increases over the 

baseline concentration and to assure that such emissions would not cause or contribute to 

concentrations that exceed the otherwise applicable maximum allowable increases for periods of 

exposure of twenty-four (24) hours or less for more than eighteen (18) days, not necessarily 

consecutive, during any annual period: 

Maximum Allowable Increase 

(Micrograms Per Cubic Meter) of Sulfur Dioxide

Terrain Areas

Period of Exposure Low High 

24 hour maximum 36 62 

3 hour maximum 130 221 

(i) The department shall transmit to the U.S. EPA a copy of each permit application 

relating to a major stationary source or major modification and provide notice to the U.S. EPA of 

the following actions related to consideration of such permit under this 

section: 

(1) Receipt of an advanced notification of a permit application affected by this section. 

(2) Any written notice provided to the federal land manager under this section. 

(3) Public notice of a preliminary determination. 

(4) Notices of public hearings. 

(5) Decisions to grant or deny exemptions in accordance with this section. 

(6) Any decision in accordance with subsection (c) that an analysis submitted by the 

federal land manager does not demonstrate 

to the satisfaction of the department that an adverse impact on visibility will result in the Class I 

area. 

(7) Denial of a permit. 

(8) Issuance of a permit. 
IN REPLY REFER TO,

United States Department of the Interior

NATIONAL PARK SERVICE

Air Resources Division

PO. Box 25287

Denver, CO 80225

~="""-=::;/

~4

TAKE PRIDE'

INAMERICA

January 3, 20 II

N36l5 (2350)

Ken Ritter

Air Programs Branch

IDEM Office of Air Quality

100 North Senate Avenue

Indianapolis, Indiana 46204-2251

Dear Mr. Ritter:

On November 5, 2010, we received Indiana's draft State Implementation Plan to address

regional haze. We appreciate the opportunity to work closely with the State through the

initial evaluation, development, and review of this plan. Cooperative efforts such as

these ensure that, together, we will continue to make progress toward the Clean Air Act's

goal of natural visibility conditions at all of our most pristine National Parks and

wilderness areas for future generations.

This letter acknowledges that the U.S. Department of the Interior, National Park Service

(NPS), in consultation with the U.S. Fish and Wildlife Service (FWS), has received and

conducted a substantive review of your revised proposed Regional Haze Rule

implementation plan in fulfillment of your requirements under the federal regulations 40

CFR 51.308(i)(2). Please note, however, that only the U.S. Environmental Protection

Agency (EPA) can make a final determination regarding the document's completeness

and, therefore, ability to receive federal approval from EPA.

As outlined in a letter to each State dated August I, 2006, our review focused on eight

basic content areas. The content areas reflect priorities for the Federal Land Manager

agencies, and we have enclosed comments associated with these priorities.
2

We look forward to your response, as per section 40 CFR 51.308(i)(3). For further

information regarding our comments, please contact Pat Brewer at (303) 969-2153.

Again, we appreciate the opportunity to work closely with the State of Indiana to improve

visibility in our Class I areas.

Sincerely,

9;t;f:::;rL

Acting Chief, Air Resources Division

Enclosures

cc:

John Summerhays

U.S. EPA Region 5

77 W. Jackson Blvd.

Chicago, Illinois 60604
 

 
 
Appendix 9a - Baseline Visibility Conditions, Pollutant Contributions, Needed 

Visibility Improvement and Glide Paths for the Uniform Rate of Progress 
This page intentionally left blank. 
Appendix 9a - 1 

For the 20% worst visibility days in the northern Class 1 areas, the pollutants that contribute to visibility impairment are 

sulfates, which represent 35-55% impairment, nitrates are 25-30% of the pollutant contribution and organic carbon 

contributes 12-22% to visibility impairment . These results are shown below in Figure 1. 

Figure 1. 20% Best Days 20% Worst Days 

Monthly average light extinction values for the northern Class 1 areas are shown below in Figure 2. Sulfates represent 

the highest contributing pollutant to light extinction with nitrates and organic carbon providing seasonal contributions. 

Nitrates have higher contributions during the late fall, winter and early spring while organic carbon has higher 

contributions to light extinction during the summer. Elemental carbon, and coarse mass are fairly consistent throughout 

the year at all northern Class 1 areas. 
Appendix 9a - 2 

 Figure 2. Monthly Average Light Extinction Values for Northern Class 1 Areas 

  

   

LADCO conducted photochemical modeling for baseline and future year light extinction. This source apportionment 

modeling analyzed regional, source and pollutant impacts on visibility at Isle Royale in Michigan (as shown below in 

Figure 3); Mammoth Cave National Park in Kentucky (Figure 4); Shenandoah National Park in Virginia (Figure 5); and Lye 

Brook Wilderness in Vermont (Figure 6). Indiana’s contributions to visibility impairment in the northern Class 1 areas of 

Isle Royale, Seney and Boundary Waters, comprises mainly of sulfates from EGU emissions. 
Appendix 9a - 3 

Figure 3. Isle Royale, Michigan

2005 (LADCO Round 5) 2018 (LADCO Round 5)

2005 (LADCO Round 5)         2018 (LADCO Round 5)
Appendix 9a - 4 

Figure 4. Seney, Michigan

2005 (LADCO Round 5)     2018 (LADCO Round 5)

2005 (LADCO Round 5)       2018 (LADCO Round 5)
Appendix 9a - 5 

Figure 5. Boundary Waters, Minnesota

2005 (LADCO Round 5)           2018 (LADCO Round 5)

2005 (LADCO Round 5)           2018 (LADCO Round 5)
Appendix 9a - 6 

Figure 6. Voyageurs, Minnesota 

2005 (LADCO Round 5)           2018 (LADCO Round 5) 

2005 (LADCO Round 5)           2018 (LADCO Round 5)
Appendix 9a - 7 

Indiana contributions to visibility impairment at Mammoth Cave, Kentucky comprise mostly of sulfates emissions from 

EGUs, as shown in Figure 7. Indiana’s contributions to light extinction are expected to decrease through 2018 and overall 

light extinction at Mammoth Cave is expected to be approximately half of the light extinction modeled for 2005. 

Figure 7. Mammoth Cave, Kentucky

2005 (LADCO Round 5)           2018 (LADCO Round 5)

2005 (LADCO Round 5)           2018 (LADCO Round 5)
Appendix 9a - 8 

Indiana contributions to visibility impairment at Shenandoah National Park, Virginia comprise mostly of sulfate emissions 

from EGUs, as shown in Figure 8. Indiana’s contributions to light extinction are predicted to decrease through 2018 and 

overall light extinction at Shenandoah is expected to be approximately half of the light extinction modeled for 2005. 

Figure 8. Shenandoah, Virginia 

2005 (LADCO Round 5)           2018 (LADCO Round 5)

2005 (LADCO Round 5)           2018 (LADCO Round 5)
Appendix 9a - 9 

Indiana contributions to visibility impairment at Lye Brook Wilderness, Vermont comprise mostly of sulfate emissions from 

EGUs, as shown in Figure 9. Indiana’s contributions to light extinction will decrease through 2018 and overall light 

extinction at Lye Brook is expected to be approximately 1/3 of the light extinction modeled for 2005. 

Figure 9. Lye Brook Wilderness, Vermont

2005 (LADCO Round 5)           2018 (LADCO Round 5) 

  

2005 (LADCO Round 5)           2018 (LADCO Round 5)

Indiana contributions to visibility impairment at all the Class 1 areas analyzed were less than 5 Mm-1 with the exception of 

Indiana’s contribution to visibility at Mammoth Cave National Park in Kentucky. The future year modeling shows that 

Indiana is projected to have reduced its contribution on Mammoth Caves’ visibility impairment by approximately 50% by 

2018. 
Appendix 9a - 10 

LADCO conducted back trajectory analyses to determine which states were culpable during bad visibility days at each of 

the northern Class 1 area analyzed. Table 1 shows the percentage of light extinction culpability from states in the eastern 

United States at the northern Class 1 areas. Indiana is shown to contribute less than 3 % light extinction at Boundary 

Waters Canoe Area, MN and Seney Wilderness, MI and no appreciable contribution to light extinction at Voyageurs 

National Park, MN. 

 Table 1. LADCO's Back Trajectory Analysis -1997-2001 (percent of light extinction) 

   Region

Boundary Waters  

Light Extinction

Voyageurs  

Light Extinction

Seney  

Light Extinction

      Best All Days Worst Best All Days Worst Best All Days Worst

US Alabama     0.03                 0.2 0.39

   Arkansas    0.3 0.4     0.1 0.19     1.54 2.93

   Florida                       0.09 0.17

   Georgia                       0.21 0.39

   Illinois     1.68 2.74     0.5 1.22     4.99 7.43

   Indiana     0.57 1.18              1.67 2.17

   Iowa     5.14 7.44     6.12 10.24     5.27 5.66

   Kentucky                       1.14 2.18

   Louisiana    0.12 0.23     0.03 0.06     0.78 1.23

   Michigan 0.78 1.17 0.66 0.27 1.22 1.57 14.51 13.68 14.68

   Minnesota 22.04 34.75 37.63 20.96 34.6 36.88 1.46 5.41 3.79

   Mississippi     0.06                 0.62 1.04

   Missouri     2.17 3.26     1.02 0.3     2.42 3.17

   New Hampshire                       0.02    

   New York                       0.07 0.1

   North Carolina     0.09                 0.19 0.36

   North Dakota 1.21 5.13 5.91 1.59 6.51 7.11     1.26 0.64

   Ohio     0.19 0.23           0.07 1.61 2.8

   Pennsylvania                    0.49 0.15 0.26

   South Carolina                       0.21 0.39

   South Dakota 0.45 3.06 4.38     4.08 6.93     1.13 1.12

   Tennessee        0.01              0.47 0.85

   Vermont                       0.02    

   Virginia     0.03                 0.17 0.33

   West Virginia     0.05                 0.54 1.02

   Wisconsin 1.31 7.86 10.06     5.5 9.66 0.26 10.63 8.44

   Western States 1.1 4.31 5.74     7.05 9.53     5.8 5.9

Canada Manitoba 9.95 7.45 3.71 17.65 10.35 6.04 3.77 2.37 0.77

   Ontario 47.52 15.96 8.92 49.56 13.59 4.98 50.97 12.86 7.66

   Quebec 1.77 0.15     0.21 0.01     0.97 0.93 0.41

   Other Provinces 2.27 3.73 2.46 6.05 6.29 2.35 0.86 1.72 2.28

Other (over water, etc) 11.61 6.02 5.05 3.72 3.05 2.94 26.65 21.86 21.44

Total     100 100 100 100 100 100 100 100 100
Appendix 9a - 11 

LADCO summarized its back trajectory, Round 4 and Round 5 PSAT analyses along with the CENRAP and MPCA PSAT 

modeling results to show the state culpabilities on the northern Class 1 areas. As can be seen, Indiana’s impacts on the 

Boundary Waters, Voyageurs and Isle Royale Class 1 areas are less than 6% of the total visibility impairment. Indiana is 

modeled to have a slightly higher impact at Seney, with modeled results less than 12% of total visibility impairment. 

Emission reductions that are projected through future year 2018 PSAT modeling show Indiana’s impact will be reduced 

approximately 20% or more, decreasing Indiana’s impact on future year visibility at Seney. 

Table 2. State Culpabilities Based on PSAT Modeling and Trajectory Analysis 

Boundary Waters Seney

LADCO LADCO LADCO‐  LADCO LADCO LADCO

State/Region

Rnd 4

PSAT

Rnd 5

PSAT

MPCA‐

PSAT

CENRAP

PSAT

Traj

Analysis

Rnd 4

PSAT

Rnd 5

PSAT

Traj

Analysis

Michigan 3.40% 4.80% 3.00% 1.90% 0.70% 13.80% 18.10% 14.70%

Minnesota 30.50% 23.50% 28.00% 30.60% 37.60% 4.80% 1.60% 3.80%

Wisconsin 10.40% 10.90% 10.00% 6.40% 10.60% 12.60% 10.90% 8.40%

Illinois 5.20% 5.10% 6.00% 3.50% 2.70% 13.00% 14.30% 7.40%

Indiana 2.90% 3.90% 3.00% 1.80% 1.20% 9.60% 11.60% 2.20%

Iowa 7.60% 8.30% 8.00% 2.50% 7.40% 6.20% 3.80% 5.70%

Missouri 5.20% 3.40% 6.00% 2.10% 3.30% 6.50% 4.80% 3.20%

N. Dakota 5.70% 1.10% 6.00% 4.60% 5.90% 1.50% 0.10% 0.60%

Canada 1.90% 2.70% 3.00% 12.50% 15.10% 2.10% 1.20% 11.10%

CENRAP‐WRAP 10.90% 13.50%     4.20% 10.10% 13.10% 10.00% 7.00%

TOTAL 83.60% 77.20% 73.00% 70.20% 94.60% 83.30% 76.40% 64.10%

Voyageurs Isle Royale

LADCO LADCO MPCA‐  CENRAP LADCO‐  LADCO LADCO

State/Region

Rnd 4

PSAT

Rnd 5

PSAT PSAT PSAT

Traj

Analysis

Rnd 4

PSAT

Rnd 5

PSAT

Michigan 2.00% 4.90% 2.00% 1.00% 1.60% 12.70% 13.40%

Minnesota 35.00% 20.20% 31.00% 31.50% 36.90% 14.10% 9.50%

Wisconsin 6.30% 7.90% 6.00% 3.70% 9.70% 16.30% 14.70%

Illinois 3.00% 7.10% 3.00% 1.80% 1.20% 7.00% 8.70%

Indiana 1.60% 4.60% 2.00% 0.80%     5.60% 5.20%

Iowa 7.40% 7.10% 7.00% 2.40% 10.20% 6.90% 8.30%

Missouri 4.30% 4.00% 4.00% 1.60% 0.30% 3.90% 4.60%

N. Dakota 10.30% 1.70% 13.00% 6.10% 7.10% 3.60% 0.30%

Canada 2.70% 3.30% 5.00% 17.20% 13.30% 2.20% 1.70%

CENRAP‐WRAP 10.20% 13.70% 6.10% 16.50% 12.50% 12.60%    

TOTAL 82.70% 74.50% 73.00% 72.20% 96.80% 84.90% 79.00%

Table II‐2, “Regional Haze in the Upper Midwest: Summary of Technical Information” Feb 22, 2008
Appendix 9a - 12 

Baseline visibility conditions for the northern Class 1 areas, taken from 2000 through 2004, established the baseline 

values at the northern Class 1 areas between 18.5 and 23.5 deciviews for the 20% worst days using the old IMPROVE 

equation and baseline values at the northern Class 1 areas between 19.5 and 24.5 deciviews using the new IMPROVE 

equation. This information is used to establish the uniform rate of improvement (URI) for 2018. Table 3 shows the 

visibility values for the northern Class 1 area using the old and new IMPROVE equations. 

Table 3. Visibility Values for the Northern Class 1 Area using the Old and New IMPROVE Equations 

Old IMPROVE Equation (Cite: VIEWS, November 2005)

   20% Worst Days Baseline 2018 Natural

   2000 2001 2002 2003 2004 Value URI Value Conditions

Voyageurs 18.5 18 19 19.2 17.6 18.46 16.74 11.09

BWCA 19.85 19.99 19.68 19.73 17.65 19.38 17.47 11.21

Isle Royale 20 22 20.8 19.5 19.1 20.28 18.17 11.22

Seney 22.6 24.9 24 23.8 22.6 23.58 20.73 11.37

   20% Best Days Baseline Natural    

   2000 2001 2002 2003 2004 Value Conditions    

Voyageurs 6.3 6.2 6.7 7 5.4 6.32 3.41    

BWCA 5.9 6.52 6.93 6.67 5.61 6.33 3.53    

Isle Royale 5.7 6.4 6.4 6.3 5.3 6.02 3.54    

Seney 5.8 6.1 7.3 7.5 5.8 6.5 3.69    

New IMPROVE Equation (Cite: VIEWS, March 2006)

   20% Worst Days Baseline 2018 Natural

   2000 2001 2002 2003 2004 Value URI Value Conditions

Voyageurs 19.55 18.57 20.14 20.25 18.87 19.48 17.74 12.05

BWCA 20.2 20.04 20.76 20.13 18.18 19.86 17.94 11.61

Isle Royale 20.53 23.07 21.97 22.35 20.02 21.59 19.43 12.36

Seney 22.94 25.91 25.38 24.48 23.15 24.37 21.64 12.65

20% Best Days Baseline Natural

2000 2001 2002 2003 2004 Value Conditions

Voyageurs 7.01 7.12 7.53 7.68 6.37 7.14 4.26

BWCA 6 6.92 7 6.45 5.77 6.43 3.42

Isle Royale 6.49 7.16 7.07 6.99 6.12 6.77 3.72

Seney 6.5 6.78 7.82 8.01 6.58 7.14 3.73

The glide paths, as determined by LADCO’s Base M modeling, show the different emission scenarios meeting the glide 

paths for most Class 1 areas by 2018. The different emission scenarios include: 

- R5S1a scenario - EGU emissions as assumed by the EPA’s IPM3.0 model

- R5S1b scenario – EPA’s IPM3.0 model emissions for EGUs along with several “will do” adjustments identified by 

states (legally binding agreements such as consent degrees, operating permits, signed contracts, etc). 

Modeling results show the deciview values resulting from the different emission rates fall in line with the glide path for 

each Class 1 area for the 20% worst days. Further explanation of the glide path results can be found in the “Regional Air 

Quality Analyses for Ozone, PM2.5 and Regional Haze: Final Technical Support Document, April 25, 2008” page 96-100. 
References:

“Regional Haze in the Upper Midwest: Summary of Technical Information Version 2.2”, February 22, 2008

http://www.ladco.org/reports/rpo/consultation/products/regional_haze_in_the_upper_midwest_summary_of_te

chnical_information_v2.2_feb_22_2008.pdf

“Regional Air Quality Analyses for Ozone, PM2.5 and Regional Haze, Final Technical Support Document” April, 25,

2008

http://www.ladco.org/reports/technical_support_document/tsd/tsd_version_iv_april_25_2008_final.pdf

“Reasonable Progress for Class I Areas in the Northern Midwest – Factor Analysis” July 18, 2007

http://www.ladco.org/reports/rpo/consultation/products/reasonable_progress_for_class_i_areas_in_the_norther

n_midwest‐factor_analysis_draft_final_technical_memo_july_18_2007.pdf

  
Appendix 9b - LADCO Technical Support Document 

"Regional Air Quality Analyses for Ozone, PM2.5, and Regional Haze 

Final Technical Support Document" 

 
This page intentionally left blank. 
Regional Air Quality Analyses for

Ozone, PM2.5, and Regional Haze: 

Final Technical Support Document

April 25, 2008

States of Illinois, Indiana, Michigan, Ohio, and Wisconsin
ii

Table of Contents

 Section-Title Page

Executive Summary iii

1.0 Introduction 1

1.1 SIP Requirements 1

1.2 Organization 2

1.3 Technical Work: Overview 3

2.0 Ambient Data Analyses 4

2.1 Ozone 4

2.2 PM2.5 21

2.3 Regional Haze 35

3.0 Air Quality Modeling 46

3.1 Selection of Base Year 46

3.2 Future Years of Interest 46

3.3 Modeling System 47

3.4 Domain/Grid Resolution 47

3.5 Model Inputs: Meteorology 48

3.6 Model Inputs: Emissions 51

3.7 Base Year Modeling Results 60

4.0 Attainment Demonstration for Ozone and PM2.5 71

4.1 Future Year Modeling Results 71

4.2 Supplemental Analyses 82

4.3 Weight of Evidence Determination for Ozone 82

4.4 Weight of Evidence Determination for PM2.5 90

5.0 Reasonable Progress Assessment for Regional Haze 93

5.1 Class I Areas Impacted 93

5.2 Future Year Modeling Results 96

5.3 Weight of Evidence Determination for Regional Haze 104

6.0 Summary 111

7.0 References 114

Appendix I Ozone and PM2.5 Modeling Results

Appendix II Ozone Source Apportionment Modeling Results

Appendix III PM2.5Source Apportionment Modeling Results

Appendix IV Haze Source Apportionment Modeling Results
Appendix 9c - LADCO’s "Reasonable Progress for Class 1 Areas in the 

Northern Midwest – Factor Analysis Document (July 18, 2007)"
This page intentionally left blank.
Appendix 9c - 1 

LADCO’s “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 

2007) addresses factor analysis to establish a reasonable progress goal toward achieving natural visibility 

conditions in mandatory Class 1 areas. While Indiana does not have any Class 1 areas within the state, it 

may potentially impact visibility at nearby Class 1 areas. This factor analysis will address sulfur dioxides 

(SO2) and nitrogen oxides (NOx) emissions at several source categories, including electric generating 

units (EGUs), industrial, commercial and institutional (ICI) boilers, ammonia from agricultural operations, 

NOx emissions from onroad and nonroad mobile sources and reciprocating engines and turbines. 

Indiana has reviewed the information contained in the “Reasonable Progress for Class 1 Areas in the 

Northern Midwest – Factor Analysis” and has listed emissions and visibility impact tables to show 

Indiana’s contributions. Additional analyses related to each source category will be referenced but not 

shown in this appendix. 

EGU – Page 22-38 of LADCO’s “Reasonable Progress for Class 1 Areas in the Northern Midwest – 

Factor Analysis” 

Indiana’s emissions were based on LADCO’s Base K emissions for 2002 and projected to 2018 and are 

shown below in Table 1. Indiana’s emission contribution to the 9-state northern Midwest region (including 

the states of Michigan, Minnesota, Wisconsin, Illinois, Iowa, Missouri, North Dakota and South Dakota) 

was 33% of SO2 emissions and 24% of NOx emissions for 2002. Indiana’s contribution is projected to 

drop to 21% for SO2 emissions and 17% of NOx by 2018. 

Table 1.  Estimated Baseline Emissions from EGUs

   Emissions in 2002

Projected

emissions in 2018

   (1000 tons/year) (1000 tons/year)

   SO2 Nox SO2 Nox

Michigan 403 164 399 100

Minnesota 116 99 86 42

Wisconsin 220 107 155 46

3‐State Subtotal 739 370 641 188

Illinois 478 260 241 73

Indiana 912 303 377 95

Iowa 150 93 147 51

Missouri 305 167 281 78

North Dakota 137 72 109 72

South Dakota 13 16 12 15

9‐State Total 2,734 1,280 1,808 571

Table 5.1-2 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Two sets of possible caps have been evaluated, which are termed EGU1 and EGU2: 

EGU1 would establish a regional emissions cap for SO2 and NOX based on projected fuel 

Consumption: 

 SO2 limited to 0.15 pounds per million British thermal units (lb/million-BTU) of fossil fuel 

consumption in the region 

 NOX limited to 0.10 lb/million-BTU 
Appendix 9c - 2 

EGU2 would establish regional emission caps for SO2 and NOX based on projected fuel 

consumption: 

 SO2 limited to 0.10 lb/million-BTU 

 NOX limited to 0.07 lb/million-BTU 

Estimated costs for SO2 and NOx controls for each of the possible cap scenarios for the 9-State region is 

listed in Tables 5.1-3 and 5.1-4 of the “Reasonable Progress for Class 1 Areas in the Northern Midwest – 

Factor Analysis” document. The estimated energy and non-air environmental impacts of EGU control 

strategies can be found in Table 5.1-8 and estimated annual health benefits applied to the 5-state 

Midwest Regional Planning Organization can be found in Table 5.1-9. 

Based on these possible caps, visibility impacts were determined and improvements were shown for 

2018. Indiana emission reductions were combined with the other 8 state region emission reductions to 

determine the visibility improvements and are shown below in Table 2. Significant visibility improvements 

were modeled with both emission cap scenarios. 

Table 2.  Estimated Visibility Impacts of EGU Control Strategies

   Estimated Visibility Improvement in 2018 (DV)

   Boundary Isle   

Strategy and region Waters Voyageurs Royale Seney Average

EGU1 Emission Caps: 9‐State Region

SO2 0.77 0.35 0.84 1.01 0.74

NOX 0.18 0.24 0.15 0.12 0.17

Total 0.95 0.59 1 1.13 0.92

EGU2 Emission Caps: 9‐State Region

SO2 0.87 0.4 0.96 1.18 0.85

NOX 0.26 0.3 0.23 0.19 0.24

Total 1.13 0.69 1.18 1.37 1.09

Table 5.1-10 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Cost effectiveness of EGU control strategies for the 9-State region can be found in Table 5.1-11. 

ICI– Page 39-52 of LADCO’s “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor 

Analysis” 

Non-EGU point sources, such as Industrial, Commercial and Institutional (ICI) boilers was identified by 

source apportionment as the second largest contributor to visibility impairment to the northern Class 1 

areas. Two control strategies have been constructed to address non-EGU/ICI boiler emissions. The first 

strategy, referred to as the ICI1, requires 40% SO2 reduction and 60% NOx reduction from 2018 baseline 

emissions. The second strategy was created by an ICI Workgroup and identifies SO2 and NOx emission 

limitations based on boiler type, size and fuel type consumed. This strategy would result in approximately 

77% SO2 emission reductions and 70% reduction in NOx emissions. Table 5.2-3 of the “Reasonable 

Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” document outlines the ICI 

Workgroup proposed emission caps for NOx and SO2 for different boiler and fuel types. 
Appendix 9c - 3 

Indiana’s emissions were based on LADCO’s Base K emissions for 2002 and projected to 2018 and are 

shown below in Table 6. Indiana’s emission contribution to the 9-state northern Midwest region (including 

the states of Michigan, Minnesota, Wisconsin, Illinois, Iowa, Missouri, North Dakota and South Dakota) 

was 28.4% of SO2 emissions and 21% of NOx emissions for 2002. Indiana’s contribution is projected to 

drop to 28.3% for SO2 emissions and 20.7% of NOx by 2018. 

Table 3 Estimated Point and Area Emissions from ICI Boilers

   Emissions from ICI sources in 2002

Projected emissions from ICI sources in

2018

   (1000 tons/year) (1000 tons/year)

   SO2 Nox SO2 Nox

Michigan 44.2 27 42.8 26.5

Minnesota 20.2 52.9 19.7 52.7

Wisconsin 57 34.5 54.8 33.9

3‐State Subtotal 121.5 114.4 117.2 113.1

Illinois 58.9 49.5 59 48

Indiana 108.9 54.2 105.2 52.5

Iowa 32.2 16.3 30.6 16.2

Missouri 53 18.8 52.5 18.7

North Dakota 7.6 5.1 7.2 5.1

South Dakota 0.7 0.3 0.7 0.3

9‐State Total 382.8 258.7 372.3 253.9

Table 5.2-1 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Estimated cost of ICI1 SO2 and NOx controls for the 9-state region can be found in Tables 5.2-5 and 5.2-

6 of the “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” document 

with the estimated cost of ICI Workgroup SO2 and NOx controls for the 9-state region can be found in 

Tables 5.2-7 and 5.2-8. The estimated energy and non-air environmental impact of ICI control strategies 

for the 9-state region can be found in Table 5.2-10 with cost effectiveness of the ICI controls found in 

Table 5.2-12. 

Visibility improvements at nearby Class 1 areas are realized with emission reductions from ICI point and 

area sources, however these improvements are an order of magnitude less that those achieved from 

EGU emission reductions. Impacts are shown below in Table 4. 
Appendix 9c - 4 

Table 4.  Estimated Visibility Impacts of ICI Control Strategies

   Estimated Visibility Improvement in 2018 (DV)

   Boundary Isle    

   Waters Voyageurs Royale Seney Average

ICI1 3‐State SO2 0.07 0.03 0.07 0.05 0.06

   NOX 0.07 0.05 0.03 0.02 0.04

   9‐State SO2 0.09 0.05 0.09 0.11 0.08

   NOX 0.1 0.07 0.05 0.06 0.07

ICI

Workgroup 3‐State SO2 0.1 0.06 0.11 0.09 0.09

   NOX 0.1 0.06 0.03 0.03 0.05

   9‐State SO2 0.15 0.08 0.15 0.18 0.14

      NOX 0.11 0.08 0.06 0.07 0.08

Table 5.2-11 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Reciprocating Engines and Turbines – Page 53-60 of LADCO’s “Reasonable Progress for Class 1 

Areas in the Northern Midwest – Factor Analysis” 

Indiana’s reciprocating engines and turbine emissions were based on LADCO’s Base K emissions for 

2002 and projected to 2018 and are listed below in Table 5. Indiana’s emission contribution to the 9-state 

northern Midwest region (including the states of Michigan, Minnesota, Wisconsin, Illinois, Iowa, Missouri, 

North Dakota and South Dakota) was 9% of NOx emissions for 2002. Indiana’s contribution is projected 

to drop to 8% of NOx emissions by 2018. Stationary internal combustion engines are projected to 

represent 11 % of all non-EGU point sources in 2018. 

Table 5.  Estimated Emissions from Reciprocating Engines and Turbines in Non‐EGU Emissions in 2018

   Nox Emissions from stationary Projected Nox  from stationary

   internal Combustion sources in 2002 internal Combustion sources in 2018

   (tons/day) (tons/day)

   Reciprocating        Reciprocating       

   Engines Turbines Total Engines Turbines Total

Michigan 44.1 11.4 55.5 41.4 11.5 52.9

Minnesota 18.3 5.9 24.3 17.6 6.3 23.9

Wisconsin 8.1 1.9 10 7.2 1.9 9.2

3‐State Subtotal 70.5 19.2 89.8 66.2 19.7 85.9

Illinois 112.5 14.3 126.8 110.6 15.9 126.4

Indiana 25.1 1.7 26.8 23 1.8 24.7

Iowa 26.3 1.6 27.9 25.2 1.7 26.9

Missouri 21 3.2 24.3 20.2 3.4 23.6

North Dakota 8.7 1.3 10 8.3 1.4 9.7

South Dakota 0 1 1 0 1.1 1.1

9‐State Total 264.1 42.5 306.6 253.6 44.9 298.4

Table 5.3-1 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)
Appendix 9c - 5 

Emission reductions for candidate internal combustion control measures are found in Table 5.3-2 of the 

“Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” document. Indiana’s 

sources with emissions of 100 tons/year or more could realize emission reductions up to 88.5% with 

sources with emission of 10 tons/year or more up to 87.7%. Estimated cost effectiveness of controls for 

internal combustion sources are found in Table 5.3-3 with cost effectiveness in terms of visibility 

improvement found in Table 5.3-5. 

Indiana emission reductions were combined with the other 8 state region emission reductions to 

determine the visibility improvements and are shown below in Table 6. Visibility improvements were 

modeled with larger improvements seen from emission reductions from the reciprocating engines. 

Table 6.  Estimated Visibility Improvements from Internal Combustion Control Measures

9‐State region

Control of sources emitting over 100

tons/year

Boundary

Waters Voyageurs

Isle

Royale Seney Average

Reciprocating engines    0.074 0.053 0.036 0.044 0.052

Turbines    0.01 0.007 0.005 0.006 0.007

Total 0.084 0.06 0.041 0.05 0.059

9‐State region

Control of sources emitting over 10

tons/year

Boundary

Waters Voyageurs

Isle

Royale Seney Average

Reciprocating engines    0.105 0.075 0.051 0.062 0.073

Turbines    0.017 0.012 0.008 0.01 0.012

Total    0.121 0.087 0.059 0.072 0.085

Table 5.3-4 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Ammonia from Agricultural Sources – Page 61-67 of LADCO’s “Reasonable Progress for Class 1 

Areas in the Northern Midwest – Factor Analysis” 

Agricultural sources account for an estimated 97% of ammonia emissions in the nine-state region with 

most of those emissions coming from livestock. Cost effectiveness for control measures for agricultural 

ammonia emissions in the study region is found in Table 5.4-1 of the “Reasonable Progress for Class 1 

Areas in the Northern Midwest – Factor Analysis” document with the estimated energy and non-air 

environmental impact located in Table 5.4-2. Cost effectiveness in terms of visibility improvement from 

agricultural ammonia emission reductions from the 9-state region can be found in Table 5.4-4. 

Visibility improvements at nearby Class 1 areas are realized with 10% and 15% ammonia emission 

reductions and are shown below in Table 7. Indiana would not be expected to significantly impact nearby 

Class 1 areas due to the ground-level releases of ammonia being dispersed before reaching the 

surrounding Class 1 areas. 

Table 7.  Estimated Visibility Impacts of Agricultural Ammonia Emission Control Measures.

Estimated visibility Improvement in 2018 (DV)

   Boundary Isle    

   Waters Voyageurs Royale Seney Average

10% Ammonia Reduction in the 9‐state region 0.15 0.18 0.15 0.17 0.16

15% Ammonia Reduction in the 9‐state region 0.23 0.27 0.23 0.26 0.25

Table 5.4‐3 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)
Appendix 9c - 6 

Mobile Sources – Page 68-76 of LADCO’s “Reasonable Progress for Class 1 Areas in the Northern 

Midwest – Factor Analysis” 

Source apportionment modeling show that mobile sources contribute significantly to 

visibility impairment in 2018 in the northern Midwest Class I areas, despite projected NOX reductions from 

on-the-books Federal and state-wide programs targeting on- and non-road mobile source sectors as well 

as locomotives and marine engines. Potential additional control strategies were identified that could be 

applied on a regional level. 

For on-road engines: 

 Low-NOX Reflash 

 Anti-Idling 

 Midwest Clean Diesel Initiative (MCDI) 

 Cetane Additive Program 

For non-road and locomotive engines: 

 Anti-Idling 

 Cetane Additive Program 

 MCDI 

Estimated cost effectiveness and emission reduction potential from mobile sources in the 9-state region 

are found in Table 5.5-1. The estimated energy and non-air environmental impacts from mobile source 

control strategies are listed in Table 5.5-2. Cost effectiveness of mobile source controls in terms of 

visibility improvement can be found in Table 5.5-4. 

Emission reductions resulting from the above mobile emission control strategies for the 9-state region will 

average less than 2% for 2012 emission projections and just over 2 % for 2018 emission projections. 

Resulting visibility improvements as a result of each of the emission reductions will only improve visibility 

by less than 0.005 deciviews with visibility impacts from the cumulative mobile emission reductions 

resulting in 0.04 deciview improvement. 

SUMMARY 

Tables 8 and 9 show the 2002 and 2018 emission summaries for the nine state region for NOx and SO2. 

Table 10 shows a summary of the estimate visibility impacted from each of the source category emission 

reductions strategies. All Class 1 areas see a bigger benefit for visibility with emission controls on EGUs 

followed by ammonia reduction from agricultural sources. This analysis takes into account emission 

reductions from sources in all nine states within the study region so visibility improvement represents a 

cumulative impact from the states of Indiana, Michigan, Minnesota, Wisconsin, Illinois, Iowa, Missouri, 

North Dakota and South Dakota. 
Appendix 9c - 7 

Table A-1.1 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Table 8. Summary of Current (2002) Emissions in the Nine States in the Study Region 

 Onroad Nonroad Marine, 

 ICI Reciprocating Other Area Mobile Mobile Aircraft, 

 EGU Boilers Engines Turbines Point Sources Sources Sources Railroad Total 

SO2 in 2002 

Michigan 1,103 55 107 71 19 1 1,355 

Minnesota 318 23 36 33 19 8 437 

Wisconsin 602 149 14 9 13 13 800 

3-State Subtotal 2,023 227 156 113 51 21 2,592 

Illinois 1,310 161 213 11 31 0 1,725 

Indiana 2,499 148 144 158 17 0 2,966 

Iowa 412 88 50 2 12 8 571 

Missouri 835 28 227 117 12 12 1,231 

North Dakota 376 21 22 142 0 3 564 

South Dakota 35 1 3 50 0 1 90 

9-State Total 7,489 676 813 594 123 44 9,739 

NOx in 2002 

Michigan 448 45 44 11 116 49 926 205 114 1,959 

Minnesota 271 26 18 6 117 126 455 208 100 1,327 

Wisconsin 294 65 8 2 24 32 481 145 79 1,129 

3-State Subtotal 1,013 136 71 19 256 208 1,862 557 294 4,416 

Illinois 712 101 112 14 129 62 890 324 277 2,622 

Indiana 830 105 25 2 106 63 703 178 123 2,133 

Iowa 254 45 26 2 39 7 304 174 89 941 

Missouri 458 12 21 3 63 64 602 199 133 1,555 

North Dakota 196 14 9 1 7 45 75 2 46 395 

South Dakota 44 1 0 1 14 14 92 2 8 176 

9-State Total 3,507 413 264 42 616 462 4,529 1,437 969 12,239 
Appendix 9c - 8 

Table A-1.2 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

Table 9. Summary of Projected (2018) Emissions in the Nine States in the Study Region 

 Onroad Nonroad Marine, 

 ICI Reciprocating Other Area Mobile Mobile Aircraft, 

 EGU Boilers Engines Turbines Point Sources Sources Sources Railroad Total 

SO2 in 2018 

Michigan 1,093 51 134 68 0 1 1,347 

Minnesota 236 22 48 34 4 2 346 

Wisconsin 426 142 15 10 0 9 601 

3-State Subtotal 1,755 215 196 112 4 11 2,294 

Illinois 661 155 94 13 0 0 923 

Indiana 1,033 138 152 153 3 0 1,479 

Iowa 404 83 74 3 1 2 567 

Missouri 770 26 395 120 3 7 1,321 

North 298 20 32 137 4 0 491 

South 33 2 4 51 3 0 94 

9-State Total 4,952 641 948 588 19 20 7,168 

NOx in 2018 

Michigan 273 43 41 11 133 54 385 94 110 1,145 

Minnesota 115 25 18 6 134 136 205 175 54 867 

Wisconsin 126 64 7 2 21 35 118 69 57 500 

3-State Subtotal 514 132 66 20 287 225 708 338 222 2,512 

Illinois 199 96 111 16 121 73 176 154 186 1,131 

Indiana 262 100 23 2 101 69 105 141 84 887 

Iowa 140 44 25 2 50 9 67 141 47 525 

Missouri 213 12 20 3 75 74 119 161 99 777 

North Dakota 196 14 8 1 12 50 34 204 24 545 

South Dakota 40 1 0 1 22 15 42 148 5 273 

9-State Total 1,564 400 254 45 669 515 1,250 1,288 666 6,650 
Appendix 9c - 9 

Table 10. Estimated Visibility Impacts of Potential Control Strategies 

Estimated visibility improvement 

on the 20% worst-visibility 

days in 2018 (deciviews) 

Boundary Isle 

Strategy and 

Region Waters Voyageurs Royale Seney Average 

EGU EGU1 9-State SO2 0.77 0.35 0.84 1.01 0.74 

NOX 0.18 0.24 0.15 0.12 0.17 

EGU2 9-State SO2 0.87 0.4 0.96 1.18 0.85 

NOX 0.26 0.3 0.23 0.19 0.24 

ICI boilers ICI1 9-State SO2 0.09 0.047 0.092 0.109 0.084 

NOX 0.098 0.07 0.048 0.058 0.068 

ICI Workgroup 9-State SO2 0.145 0.075 0.148 0.176 0.136 

NOX 0.114 0.082 0.056 0.067 0.08 

Reciprocating 

Engines 

Reciprocating engines 

emitting 9-State NOX 0.074 0.053 0.036 0.044 0.052 

and Turbines 100 tons/year or more 

Turbines emitting 100 

tons/year 9-State NOX 0.01 0.007 0.005 0.006 0.007 

or more 

Reciprocating engines 

emitting 9-State NOX 0.105 0.075 0.051 0.062 0.073 

10 tons/year or more 

Turbines emitting 10 tons/year 9-State NOX 0.017 0.012 0.008 0.01 0.012 

or more 

Agricultural Sources 10% reduction 9-State NH3 0.15 0.18 0.15 0.17 0.16 

15% reduction 9-State NH3 0.23 0.27 0.23 0.26 0.25 

Mobile Sources Low-NOX Reflash 9-State NOX 0.008 0.009 0.012 0.012 0.01 

MCDI 9-State NOX 0.014 0.018 0.013 0.013 0.015 

Anti-Idling 9-State NOX 0.005 0.007 0.006 0.006 0.006 

Cetane Additive Program 9-State NOX 0.006 0.007 0.009 0.01 0.008 

Table 6.5-2 “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

References:

LADCO’s “Reasonable Progress for Class 1 Areas in the Northern Midwest – Factor Analysis” (July 18, 2007)

http://www.ladco.org/reports/rpo/consultation/products/reasonable_progress_for_class_i_areas_in_the_norther

n_midwest‐factor_analysis_draft_final_technical_memo_july_18_2007.pdf
Appendix 9d - Discussions and Data for 

ArcelorMittal Burns Harbor, ESSROC - Speed and SABIC CALPUFF Results 

using Bondville Ammonia Monitoring Results 2003-2005 
This page intentionally left blank.
Appendix 9d - 1 

Concerns with BART eligibility modeling presented to Indiana DEM by sources: 

Huffman, 2009.09.11 

ArcelorMittal – Burns Harbor 

- The source used the new IMPROVE eqn. for light extinction – while this is generally 

acceptable the impacts on the modeled light extinction appears to be much greater than 

would be expected by this change alone. Most of the reduction in days over the thresholds 

for change in light extinction was accredited to this change. 

IDEM Response: Burns Harbor used the most current regulatory versions of 

CALPUFF/CALMET/CALPOST versions 5.8, Level 070623. Burns Harbor requested the use of 

the new IMPROVE equation upon its release. Burns Harbor included a letter, dated October, 

2006 from Dr. Ivar Tombach regarding the use of CALPOST outputs with the new IMPROVE 

equation. Burns Harbor completed their CALPUFF modeling in mid August of 2008. U.S. EPA 

Region 5 forwarded an email, dated July 28, 2008 from the National Parks Service that states 

since Dr. Scire had posted a new version of CALPOST, NPS would no longer be recommending 

Dr. Tombach’s new IMPROVE spreadsheet. Burns Harbor submitted their CALPUFF modeling 

results soon after this email release, in part due to the uncertainty of U.S. EPA approved 

CALPUFF version to be used for BART modeling. Therefore, IDEM reviewed and accepted the 

Burns Harbor results. 

The “Revised IMPROVE Algorithm for Estimating Light Extinction from Particle Speciation 

Data”1

 includes studies that were conducted to determine the impact of the new IMPROVE 

equation on light extinction compared with the old IMPROVE equation and measured values. 

Class 1 areas with nephelometers were analyzed. There are seven Class 1 areas within the MRPO 

modeling domain that have nephelometers. Modeled results on the 20% best days showed new 

IMPROVE equation results for light scattering was slightly lower at most Class 1 areas than the 

old IMPROVE equation yet would be considered conservative as the modeled results were 

greater than measured light scattering. A summary of the results are below in Table 1: 

Table 1: Mean Light Scattering (BSP) Results for 20% Best Days 

Class 1 Area 

Measured 

BSP Value (Mm-1) 

Old IMPROVE 

BSP value (Mm-1) 

New IMPROVE 

BSP value (Mm-1) 

Boundary Waters 5.4 7.7 6.6 

Dolly Sods 15 20 19 

Great Gulf 5.4 8.0 6.8 

Great Smokey Mountains 15 20 20 

Lye Brook 5.3 8.2 7.0 

Mammoth Cave 18 22 19 

Shenandoah 11 14 13 

Variations in the speciation results were due to slight increases or decreases in ammonia sulfate, 

ammonia nitrate and organic carbon. The light scattering calculations using the new IMPROVE 

equation were similar to the old IMPROV 
Appendix 9d - 2 

E equation results and still higher than the measured light scattering values. IDEM finds no 

reason to dispute the results from the new IMPROVE equation and accepts the Burns Harbor 

CALPUFF modeling results. 

- The source used the average annual values instead of the 20% best days for comparison. 

This will result in the appearance of less impact on light extinction from the source 

emissions. This reduction in impact may not be accurate. (“Natural visibility conditions, 

the 20% best days,...” - LADCO BART modeling protocol). 

IDEM Response: Burns Harbor used 6 kilometer CALPUFF and CALMET grids, thus allowing 

for use of the less conservative average annual background. U.S. EPA approved the use of 20% 

best day annual background concentrations for MRPO states when using the MRPO 36 kilometer 

grid CALMET without meteorological station observational data. The more refined VISTAS 6 

kilometer CALMET data used by Burns Harbor included observational data and therefore, use of 

the average annual background concentrations was warranted per U.S. EPA. 

- The source used background ammonia values of 0.3 ppb in January through March with 

0.5 ppb the rest of the year. This does follow LADCO protocol for BART modeling but it 

appears very low given the source emission may travel over long stretches of agricultural 

land where ammonia values are likely much higher. 

IDEM Response: As mentioned, information from the LADCO MRPO protocol was used in the 

modeling. The protocol was approved by U.S. EPA which included the domain seasonal 

ammonia values, taken from annual 2002 CAMx simulations, which represented the best 

available information to conduct CALPUFF modeling for the MRPO states. 

In response to this comment, IDEM conducted additional CALPUFF runs, using Bondville 

ammonia data collected from November 2003 through October 2005. This data was not available 

at the time the LADCO MRPO BART modeling protocol was created and distributed to the 

LADCO states in early 2006. Below in Table 2 is the comparison of the 2002 seasonal averages 

with the 2003 to 2005 Bondville average monitored monthly ammonia data. 

Table 2 Comparison of Ammonia Concentrations (ppb) for CALPUFF modeling for 

ArcelorMittal 

Data Source Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 

CAMx 2002 0.3 0.3 0.3 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Bondville 03-05 0.43 0.57 2.16 2.31 1.69 1.45 1.5 1.7 1.58 1.81 2.17 0.57 

Comparison of the Burns Harbor CALPUFF modeling results using the MRPO background 

ammonia concentrations and the 2003 – 2005 Bondville data showed only slight increases in 

overall light extinction and the delta deciview changes. The largest light extinction change was 

1.06% and the delta deciviews change was 0.084 dv at Seney. There was an increase in the 

number of days compared to the BART threshold using the revised ammonia background at 

Mingo and Seney National Wildlife Refuges, however the results when calculated using the new 

IMPROVE model did not change. A summary of results can be found in Appendix A. The new 

IMPROVE equation spreadsheet results for Burns Harbor are included. 

- The source didn't model to Dolly Sods (Q/d~40), Otter Creek, or other “eastern” Class I 

areas as was done in the IDEM protocol. These Class I areas are not the closest Class I 
Appendix 9d - 3 

areas but they are directly "downwind" (east) of the facilities. For example, Otter Creek 

(691 km) is closer and downwind of the facility than Isle Royale (700 km) which was 

modeled as a receptor for the source emissions. This leaves in question the actual impacts 

of the emissions. 

IDEM Response: It was IDEM’s understanding that analyzing BART-eligible sources using the 

Q/d method was a crude screening method that was discouraged by U.S. EPA. IDEM does 

understand the concern for visibility impacts on eastern Class 1 areas. Burns Harbor modeled the 

four nearest Class 1 areas of Seney Wilderness, Isle Royale National Park, Mammoth Cave 

National Park and Mingo Wilderness. IDEM modeled sixteen Class 1 areas and determined the 

highest visibility impacts from Burns Harbor occurred at Seney, Isle Royale, Mammoth and 

Mingo Class 1 areas. While Burns Harbor did impact visibility at the eastern Class 1 areas 

mentioned, the visibility impacts from Burns Harbor on Dolly Sods, James River Face, Linville 

Gorge and Shenandoah National Park were found to be much less than the impacts at the four 

nearest Class 1 areas. The highest number of days at the four eastern Class 1 areas modeled above 

the BART threshold was 4 at Dolly Sods and 3 days at Shenandoah, both occurring in 2003. All 

other areas were modeled at one day or none. 

- “Burns Harbor’s use of a more refined 6-km grid warranted the use of the average natural 

background concentrations for Class I areas in the eastern United States” (rather than the 

20% best days as a natural background). A smaller grid does not necessarily imply more 

accurate, or precise, data so there is no real justification for opting to utilize a less stringent 

comparison. 

IDEM Response: Using the average annual natural background concentrations follows U.S. EPA 

guidance for refined CALPUFF/CALMET grid analysis and has been accepted in previous 

submittals throughout the country. The 20% best days was a result of MRPO using less refined 

grids (36 km compared to 12 km, 6 km or 4 km grid resolution and no meteorological 

observations blended into the CALMET files). IDEM has discouraged sources from conducting 

CALPUFF modeling for BART purposes using refined grids of less than a 4 kilometer grid 

resolution. 

- Total natural background extinction coefficients used by Burns Harbor were allocated to 

soils instead of distributing among sulfates, nitrates, organic and elemental carbon, coarse 

mass and soil (pages 4-2 through 4-4). – BH says it did not significantly affect results, 

however, the point of the new IMPROVE equations appears to be that it uses the speciated 

particulates and they impact visibility (light extinction) differently. It appears that not 

including the speciated particulates would limit, or hinder, the benefits gained through the 

use of the new IMPROVE equations. 

IDEM Response: This issue was raised by IDEM in March of 2009 and addressed by Burns 

Harbor in Attachment 4 in the hardcopy of the IDEM review document submitted for review in 

May of 2009. Burns Harbor explained that whether allocating the total background as soils or 

speciated components of ammonia sulfate, ammonia nitrate, organic carbon, elemental carbon 

and coarse mass, the resulting background extinction values are the same. Resulting modeling 

showed that the allocation of the total natural background extinction coefficients did not impact 

the light extinction results. 

- Burn Harbor uses a grid resolution of 6 km rather than the 36 km grid from IDEM but uses 

the same MM5 databases from the LADCO/MWRPO 36-km CALMET database. i.e. How 
Appendix 9d - 4 

does the use of met data with a 36-km resolution with a 6-km grid improve the modeling? 

There do not appear to be any actual improvements gained by using a smaller grid. The 

improvements appear to be limited to the addition of observations in the meteorological 

data. 

-

IDEM Response: Burns Harbor refined the CALMET data using the latest U.S. EPA approved 

versions of CALPUFF and CALMET (pg. 3-1 of “Source Specific BART Modeling Report: 

ArcelorMittal Burns Harbor LLC, August 2008). The modeling domain included the four nearest 

Class 1 areas and had a 6 km grid resolution. The CALPUFF and CALMET data was processed 

with the 6 km grid terrain and land use data as well as the hourly observations and Table 3-1 lists 

the CALMET user-defined field for Meteorology grid spacing (DGRIDKM) at 6 km. Initial wind 

fields were produced using MM5 data sets at 36 km from CENRAP and MRPO but were 

processed at 6 km to characterize wind flow for the area. 

ESSROC-Speed 

- ESSROC did not model particulate matter (PM10) emissions. 

IDEM Response: At the time of the initial review, IDEM was not requiring PM10 emissions to be 

modeled. However, IDEM’s review of ESSROC Speed’s modeling included PM10 emissions 

which ESSROC-Speed provided estimates. IDEM’s CALPUFF results showed NOx, SO2 and 

PM10 emissions did not cause visibility impacts that exceeded the subject to BART threshold in 

its submittal in October of 2008.

- ESSROC modeling used 4 KM CALMET data (2001-2003) and 4 km CALPUFF grid from 

VISTAS but MM5 data is only available in 12 km resolution. This would limit the stated 

benefit of using a smaller grid size. 

IDEM Response: ESSROC utilized the VISTAS’s 4 km sub-regional Domain 3 meteorological 

data, as detailed in ESSROC-Speed’s “BART Applicability Analysis, Air Quality Modeling 

Report” Section 3.2. IDEM’s review used the emissions and stack parameter data modeled by 

ESSROC and modeled those using IDEM’s original CALPUFF model set-up to make the subject 

to BART determination. This was done in order to compare visibility results from the U.S. EPA 

approved MRPO BART modeling protocol for the Midwest states, including Indiana. 

- No cumulative impacts to Class I areas as a whole were analyzed. The source only modeled 

change in light extinction to Mammoth Cave. There are 11 Class I areas within 600 km of 

ESSROC and IDEM originally modeled impacts to 16 Class I areas in the eastern United 

States. 

-

IDEM Response: ESSROC-Speed requested modeling only the nearest Class 1 area due to 

limited resources and amount of time to model using a more refined modeling grid domain. 

IDEM’s review included modeling the sixteen nearby Class 1 areas and determined that the 

highest deciviews impact from ESSROC-Speed occurred at the Mammoth Cave Class 1 area with 

no other Class 1 areas beside Mammoth Cave recording delta deciview above the BART 

threshold. Cumulative impacts to Class 1 areas as a whole were used to determine whether a 

source was BART-eligible, however to make subject to BART determinations, visibility impacts 

on each individual Class 1 areas were analyzed. 

- Background ammonia used by ESSROC (0.3 Jan-Mar and 0.5 ppb the rest of the year) is 

likely too low to represent the land use around the source and the potentially impacted 

Class I areas. 
Appendix 9d - 5 

-

IDEM Response: As mentioned, information from the LADCO MRPO protocol was used in the 

modeling. The protocol was approved by U.S. EPA which included the domain seasonal 

ammonia values, taken from annual 2002 CAMx simulations. 

IDEM has conducted further CALPUFF runs, using Bondville ammonia data collected from 

November 2003 through October 2005. This data was not available at the time the LADCO 

MRPO BART modeling protocol was created and distributed to the LADCO states in early 2006. 

Below in Table 3 is the comparison of the 2002 seasonal averages with the 2003 to 2005 

Bondville average monthly data. 

Table 3 Comparison of Ammonia Concentrations (ppb) for CALPUFF modeling for 

ESSROC-Speed 

Data Source Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 

CAMx 2002 0.3 0.3 0.3 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Bondville 03-05 0.43 0.57 2.16 2.31 1.69 1.45 1.5 1.7 1.58 1.81 2.17 0.57 

Comparison of the ESSROC-Speed CALPUFF modeling results using the MRPO background 

ammonia concentrations and the 2003 – 2005 Bondville data showed only slight increases in 

overall light extinction and the largest deciviews changes. The largest light extinction change 

was 0.15% and the largest deciviews change was 0.015 dv at Dolly Sods. There was an increase 

in the number of days above the BART threshold using the revised ammonia background at 

Mammoth Caves, however this increase was by one day and the total days for the year remained 

below the BART threshold. A summary of results can be found in Appendix B. 

SABIC 

- SABIC modeling used 4 KM CALMET data (2001-2003) and 4 km CALPUFF grid from 

VISTAS but MM5 data is only available in 12 km resolution. This would limit the stated 

benefit of using a smaller grid size. 

IDEM Response: SABIC utilized the VISTAS’s 4 km sub-regional Domain 3 meteorological 

data. IDEM’s review used the emissions and stack parameter data modeled by SABIC and 

modeled those using IDEM’s original CALPUFF model set-up to make a subject to BART 

determination. This was done in order to compare visibility results from the U.S. EPA approved 

MRPO BART modeling protocol for the Midwest states, including Indiana. 

- The source used the average annual values instead of the 20% best days for comparison. 

This will result in the appearance of less impact on light extinction from the source 

emissions. This reduction in impact may not be accurate. (“Natural visibility conditions, 

the 20% best days,...” - LADCO BART modeling protocol). 

IDEM Response: SABIC used 4 kilometer CALPUFF and CALMET grids, thus allowing for 

use of the less conservative average annual background. U.S. EPA approved the use of 20% best 

day annual background concentrations for MRPO states when using the MRPO 36 kilometer grid 

CALMET without meteorological station observational data. The VISTAS’s 4 kilometer 

CALMET data used by SABIC included observational data and therefore, use of the average 

annual background concentrations was warranted. 
Appendix 9d - 6 

- SABIC - Chose a modeling domain for refined 4 km modeling and then based the Class I 

areas to model to base on the domain rather than the other way around. In doing so SABIC 

left off Hercules Glades Class I Wilderness area and included many Class I receptors 

further away. 

IDEM Response: SABIC used the pre-determined sub domain grid taken from the VISTAS 

BART modeling protocol and modeled all Class 1 areas within the sub domain grid. IDEM’s 

review modeled the sixteen nearby Class 1 areas as were modeled in the initial subject to BART 

determination modeling. This review showed all nearby Class 1 areas would not be impacted by 

SABIC above the BART threshold. 

- Background ammonia used by ESSROC (0.3 Jan-Mar and 0.5 ppb the rest of the year) is 

likely too low to represent the land use around the source and the potentially impacted 

Class I areas. 

-

IDEM Response: As mentioned, information from the LADCO MRPO protocol was used in the 

modeling. The protocol was approved by U.S. EPA which included the domain seasonal 

ammonia values, taken from annual 2002 CAMx simulations. 

IDEM has conducted further CALPUFF runs, using Bondville ammonia data collected from 

November 2003 through October 2005. This data was not available at the time the LADCO 

MRPO BART modeling protocol was created and distributed to the LADCO states in early 2006. 

Below in Table 4 is the comparison of the 2002 seasonal averages with the 2003 to 2005 

Bondville average monthly data. 

Table 4 Comparison of Ammonia Concentrations (ppb) for CALPUFF modeling for SABIC 

Data Source Jan Feb Mar Apr May June July Aug Sept Oct Nov Dec 

CAMx 2002 0.3 0.3 0.3 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Bondville 03-05 0.43 0.57 2.16 2.31 1.69 1.45 1.5 1.7 1.58 1.81 2.17 0.57 

Comparison of the SABIC CALPUFF modeling results using the MRPO background ammonia 

concentrations and the 2003 – 2005 Bondville data showed only slight increases in overall light 

extinction and the largest deciviews changes. The largest light extinction change was 0.17% and 

the largest deciviews change was 0.016 dv at Sipsey Wilderness. There was an increase in the 

number of days above the BART threshold using the revised ammonia background at Hercules 

Glades Wilderness, however this increase was by one day and the total days for the year remained 

below the BART threshold. A summary of results can be found in Appendix C. 

- SABIC utilized the ammonia limiting technique (ALM) which does not appear to be a valid 

switch in CALPUFF 

-

IDEM Response: Discussion between IDEM, EPA and Federal Land Managers, held on a 

conference call on September 16, 2009, brought this issue to light. IDEM understands that if the 

MNITRATE switch is set to 1, this option does not affect light extinction and delta deciview 

calculations. Review of the input file shows the MNITRATE switch in the CALPOST input file 
Appendix 9d - 7 

was set to 1 and therefore the ALM option was used correctly. SABIC verified this result by 

email on November 11, 2009. 

References: 

1

http://vista.cira.colostate.edu/improve/Publications/GrayLit/019_RevisedIMPROVEeq/RevisedIMPROV

EAlgorithm3.doc
Appendix 9d - 8 

Appendix 9d - ArcelorMittal Burns HarborCALPUFF Results using Bondville 

Ammonia Monitoring Results 2003-2005 
Appendix 9d - 9 

CALPUFF Results for Mittal - Comparing Ammonia background 

 With MRPO NH3 With Bondville NH3 Difference 

Extinction Change Extinction Change Extinction Change 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 11.94% 7.55% 10.58% 12.07% 7.64% 11.33% 0.13% 0.09% 0.75% 

Brigantine Wild. - NJ 3.38% 5.82% 5.17% 3.45% 6.08% 5.58% 0.07% 0.26% 0.41% 

Dolly Sods - WV 7.89% 5.61% 5.31% 8.31% 5.81% 5.51% 0.42% 0.20% 0.20% 

Great Gulf Wild - NH 6.08% 4.47% 12.92% 6.24% 4.63% 13.59% 0.16% 0.16% 0.67% 

Great Smokey Mount - TN 5.50% 5.44% 4.58% 5.60% 5.56% 4.86% 0.10% 0.12% 0.28% 

Hercules - Glades Wild. - MO 10.54% 4.58% 13.77% 10.68% 4.73% 14.24% 0.14% 0.15% 0.47% 

Isle Royale - MI 7.22% 13.77% 9.17% 7.32% 14.25% 9.80% 0.10% 0.48% 0.63% 

James River Face - VA 2.70% 3.92% 2.73% 2.76% 4.07% 2.89% 0.06% 0.15% 0.16% 

Linville Gorge - NC 4.23% 2.37% 2.34% 4.36% 2.41% 2.48% 0.13% 0.04% 0.14% 

Lye Brook Wild. - VT 5.49% 5.30% 8.01% 5.67% 5.37% 8.47% 0.18% 0.07% 0.46% 

Mammoth Caves - KY 10.55% 5.62% 6.66% 10.77% 5.90% 7.32% 0.22% 0.28% 0.66% 

Mingo Wild. - MO 9.14% 7.23% 8.91% 9.35% 7.34% 9.27% 0.21% 0.11% 0.36% 

Seney Wild. - MI 14.72% 20.36% 26.29% 15.47% 21.31% 27.35% 0.75% 0.95% 1.06% 

Shenandoah N.P. - VA 4.95% 6.16% 4.68% 5.14% 6.25% 4.86% 0.19% 0.09% 0.18% 

Sipsey Wild. - AL 4.12% 2.01% 3.12% 4.23% 2.06% 3.31% 0.11% 0.05% 0.19% 

Voyageurs N.P. - MN 4.47% 12.21% 9.91% 4.54% 12.37% 10.29% 0.07% 0.16% 0.38% 

Largest Delta Deciview Largest Delta Deciview Largest Delta Deciview 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 1.128 0.728 1.006 1.14 0.736 1.073 0.012 0.008 0.067 

Brigantine Wild. - NJ 0.333 0.565 0.504 0.34 0.59 0.543 0.007 0.025 0.039 

Dolly Sods - WV 0.759 0.546 0.517 0.798 0.565 0.536 0.039 0.019 0.019 

Great Gulf Wild - NH 0.54 0.437 1.215 0.606 0.453 1.275 0.066 0.016 0.06 

Great Smokey Mount - TN 0.535 0.53 0.448 0.545 0.541 0.474 0.01 0.011 0.026 

Hercules - Glades Wild. - MO 1.002 0.448 1.29 1.015 0.462 1.332 0.013 0.014 0.042 

Isle Royale - MI 0.697 1.29 0.877 0.706 1.332 0.935 0.009 0.042 0.058 

James River Face - VA 0.267 0.384 0.269 0.273 0.399 0.285 0.006 0.015 0.016 

Linville Gorge - NC 0.414 0.234 0.231 0.427 0.238 0.245 0.013 0.004 0.014 

Lye Brook Wild. - VT 0.534 0.516 0.771 0.552 0.523 0.813 0.018 0.007 0.042 

Mammoth Caves - KY 1.003 0.547 0.645 1.023 0.573 0.707 0.02 0.026 0.062 

Mingo Wild. - MO 0.875 0.698 0.854 0.894 0.708 0.886 0.019 0.01 0.032 

Seney Wild. - MI 1.373 1.854 2.334 1.439 1.932 2.418 0.066 0.078 0.084 

Shenandoah N.P. - VA 0.483 0.597 0.457 0.501 0.606 0.475 0.018 0.009 0.018 

Sipsey Wild. - AL 0.404 0.199 0.307 0.414 0.203 0.325 0.01 0.004 0.018 

Voyageurs N.P. - MN 0.438 1.152 0.945 0.444 1.167 0.979 0.006 0.015 0.034 

Days above 0.5 DV Days above 0.5 DV Days above 0.5 DV 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 1 2 4 1 3 4 0 1 0 

Brigantine Wild. - NJ 0 1 1 0 1 1 0 0 0 

Dolly Sods - WV 1 3 1 1 4 1 0 1 0 

Great Gulf Wild - NH 1 0 2 1 0 2 0 0 0 

Great Smokey Mount - TN 2 0 0 2 1 0 0 1 0 

Hercules - Glades Wild. - MO 2 0 1 2 0 1 0 0 0 

Isle Royale - MI 2 4 4 2 4 4 0 0 0 

James River Face - VA 0 0 0 0 0 0 0 0 0 

Linville Gorge - NC 0 0 0 0 0 0 0 0 0 

Lye Brook Wild. - VT 1 1 4 1 1 4 0 0 0 

Mammoth Caves - KY 6 1 4 7 1 4 1 0 0 

Mingo Wild. - MO 5 3 2 5 3 4 0 0 2 

Seney Wild. - MI 9 17 16 10 17 19 1 0 3 

Shenandoah N.P. - VA 1 3 0 1 3 0 0 0 0 

Sipsey Wild. - AL 0 0 0 0 0 0 0 0 0 

Voyageurs N.P. - MN 0 1 1 0 1 1 0 0 0 
Appendix 9d - 10 

Appendix 9d - ESSROC - Speed CALPUFF Results using Bondville Ammonia 

Monitoring Results 2003-2005 
Appendix 9d - 11 

CALPUFF Results for ESSROC - Speed - Comparing Ammonia background 

 With MRPO NH3 With Bondville NH3 Difference 

Extinction Change Extinction Change Extinction Change 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0.14% 0.67% 0.47% 0.14% 0.69% 0.54% 0.00% 0.02% 0.07% 

Brigantine Wild. - NJ 1.52% 0.92% 0.59% 1.53% 0.92% 0.60% 0.01% 0.00% 0.01% 

Dolly Sods - WV 1.12% 1.11% 1.93% 1.18% 1.26% 2.02% 0.06% 0.15% 0.09% 

Great Gulf Wild - NH 0.95% 0.55% 0.73% 0.97% 0.55% 0.73% 0.02% 0.00% 0.00% 

Great Smokey Mount - TN 1.35% 2.56% 4.58% 1.45% 2.58% 4.58% 0.10% 0.02% 0.00% 

Hercules - Glades Wild. - MO 0.57% 0.49% 0.39% 0.58% 0.49% 0.39% 0.01% 0.00% 0.00% 

Isle Royale - MI 0.20% 1.30% 0.79% 0.20% 1.35% 0.90% 0.00% 0.05% 0.11% 

James River Face - VA 0.96% 1.51% 1.34% 1.00% 1.52% 1.35% 0.04% 0.01% 0.01% 

Linville Gorge - NC 2.50% 1.43% 1.61% 2.51% 1.44% 1.61% 0.01% 0.01% 0.00% 

Lye Brook Wild. - VT 1.20% 1.11% 1.61% 1.24% 1.12% 1.62% 0.04% 0.01% 0.01% 

Mammoth Caves - KY 6.08% 8.21% 10.36% 6.11% 8.23% 10.50% 0.03% 0.02% 0.14% 

Mingo Wild. - MO 4.05% 3.18% 1.87% 4.08% 3.22% 1.87% 0.03% 0.04% 0.00% 

Seney Wild. - MI 0.74% 1.45% 0.67% 0.74% 1.47% 0.68% 0.00% 0.02% 0.01% 

Shenandoah N.P. - VA 1.45% 1.90% 1.36% 1.46% 1.92% 1.37% 0.01% 0.02% 0.01% 

Sipsey Wild. - AL 1.85% 1.44% 3.95% 1.86% 1.45% 3.97% 0.01% 0.01% 0.02% 

Voyageurs N.P. - MN 0.11% 0.21% 0.10% 0.11% 0.21% 0.10% 0.00% 0.00% 0.00% 

Largest Delta Deciview Largest Delta Deciview Largest Delta Deciview 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0.014 0.068 0.047 0.014 0.069 0.054 0 0.001 0.007 

Brigantine Wild. - NJ 0.151 0.091 0.058 0.152 0.091 0.059 0.001 0 0.001 

Dolly Sods - WV 0.111 0.11 0.191 0.117 0.125 0.2 0.006 0.015 0.009 

Great Gulf Wild - NH 0.095 0.055 0.073 0.096 0.055 0.073 0.001 0 0 

Great Smokey Mount - TN 0.134 0.253 0.447 0.144 0.254 0.448 0.01 0.001 0.001 

Hercules - Glades Wild. - MO 0.057 0.049 0.039 0.058 0.049 0.039 0.001 0 0 

Isle Royale - MI 0.02 0.129 0.079 0.02 0.134 0.09 0 0.005 0.011 

James River Face - VA 0.095 0.15 0.133 0.1 0.151 0.134 0.005 0.001 0.001 

Linville Gorge - NC 0.247 0.142 0.16 0.248 0.143 0.16 0.001 0.001 0 

Lye Brook Wild. - VT 0.119 0.11 0.16 0.124 0.112 0.161 0.005 0.002 0.001 

Mammoth Caves - KY 0.59 0.789 0.985 0.593 0.791 0.999 0.003 0.002 0.014 

Mingo Wild. - MO 0.397 0.313 0.183 0.4 0.317 0.185 0.003 0.004 0.002 

Seney Wild. - MI 0.073 0.144 0.067 0.074 0.146 0.068 0.001 0.002 0.001 

Shenandoah N.P. - VA 0.144 0.189 0.135 0.145 0.19 0.136 0.001 0.001 0.001 

Sipsey Wild. - AL 0.183 0.143 0.388 0.184 0.144 0.39 0.001 0.001 0.002 

Voyageurs N.P. - MN 0.011 0.021 0.01 0.011 0.021 0.01 0 0 0 

Days above 0.5 DV Days above 0.5 DV Days above 0.5 DV 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0 0 0 0 0 0 0 0 0 

Brigantine Wild. - NJ 0 0 0 0 0 0 0 0 0 

Dolly Sods - WV 0 0 0 0 0 0 0 0 0 

Great Gulf Wild - NH 0 0 0 0 0 0 0 0 0 

Great Smokey Mount - TN 0 0 0 0 0 0 0 0 0 

Hercules - Glades Wild. - MO 0 0 0 0 0 0 0 0 0 

Isle Royale - MI 0 0 0 0 0 0 0 0 0 

James River Face - VA 0 0 0 0 0 0 0 0 0 

Linville Gorge - NC 0 0 0 0 0 0 0 0 0 

Lye Brook Wild. - VT 0 0 0 0 0 0 0 0 0 

Mammoth Caves - KY 2 5 3 2 5 4 0 0 1 

Mingo Wild. - MO 0 0 0 0 0 0 0 0 0 

Seney Wild. - MI 0 0 0 0 0 0 0 0 0 

Shenandoah N.P. - VA 0 0 0 0 0 0 0 0 0 

Sipsey Wild. - AL 0 0 0 0 0 0 0 0 0 

Voyageurs N.P. - MN 0 0 0 0 0 0 0 0 0 
Appendix 9d - 12 

Appendix 9d - SABIC CALPUFF Results using Bondville Ammonia 

Monitoring Results 2003-2005 
Appendix 9d - 13 

CALPUFF Results for Sabic - Comparing Ammonia background 

 With MRPO NH3 With Bondville NH3 Difference 

Extinction Change Extinction Change Extinction Change 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0.35% 1.65% 0.43% 0.35% 1.66% 0.44% 0.00% 0.01% 0.01% 

Brigantine Wild. - NJ 1.57% 0.83% 1.17% 1.57% 0.83% 1.18% 0.00% 0.00% 0.01% 

Dolly Sods - WV 0.82% 0.95% 1.14% 0.83% 0.95% 1.15% 0.01% 0.00% 0.01% 

Great Gulf Wild - NH 1.01% 1.20% 1.22% 1.01% 1.20% 1.22% 0.00% 0.00% 0.00% 

Great Smokey Mount - TN 1.07% 1.95% 2.93% 1.07% 1.95% 2.94% 0.00% 0.00% 0.01% 

Hercules - Glades Wild. - MO 1.76% 4.67% 6.23% 1.78% 4.67% 6.23% 0.02% 0.00% 0.00% 

Isle Royale - MI 1.02% 2.03% 0.89% 1.02% 2.03% 0.90% 0.00% 0.00% 0.01% 

James River Face - VA 0.61% 1.49% 2.36% 0.61% 1.49% 2.37% 0.00% 0.00% 0.01% 

Linville Gorge - NC 1.05% 1.80% 5.73% 1.06% 1.80% 5.75% 0.01% 0.00% 0.02% 

Lye Brook Wild. - VT 1.68% 1.57% 2.54% 1.69% 1.59% 2.54% 0.01% 0.02% 0.00% 

Mammoth Caves - KY 6.68% 9.52% 6.67% 6.68% 9.53% 6.69% 0.00% 0.01% 0.02% 

Mingo Wild. - MO 11.93% 11.03% 6.26% 11.95% 11.04% 6.31% 0.02% 0.01% 0.05% 

Seney Wild. - MI 1.45% 2.28% 1.69% 1.45% 2.28% 1.69% 0.00% 0.00% 0.00% 

Shenandoah N.P. - VA 1.24% 1.40% 1.67% 1.24% 1.41% 1.68% 0.00% 0.01% 0.01% 

Sipsey Wild. - AL 5.17% 1.73% 3.48% 5.34% 1.73% 3.49% 0.17% 0.00% 0.01% 

Voyageurs N.P. - MN 0.16% 0.98% 0.21% 0.16% 0.98% 0.21% 0.00% 0.00% 0.00% 

Largest Delta Deciview Largest Delta Deciview Largest Delta Deciview 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0.035 0.164 0.043 0.035 0.164 0.044 0 0 0.001 

Brigantine Wild. - NJ 0.155 0.082 0.117 0.155 0.083 0.117 0 0.001 0 

Dolly Sods - WV 0.082 0.095 0.113 0.082 0.095 0.115 0 0 0.002 

Great Gulf Wild - NH 0.101 0.119 0.122 0.101 0.119 0.122 0 0 0 

Great Smokey Mount - TN 0.107 0.193 0.289 0.107 0.193 0.29 0 0 0.001 

Hercules - Glades Wild. - MO 0.174 0.456 0.604 0.176 0.456 0.605 0.002 0 0.001 

Isle Royale - MI 0.102 0.201 0.088 0.102 0.201 0.09 0 0 0.002 

James River Face - VA 0.061 0.148 0.233 0.061 0.148 0.234 0 0 0.001 

Linville Gorge - NC 0.105 0.179 0.557 0.105 0.179 0.559 0 0 0.002 

Lye Brook Wild. - VT 0.166 0.156 0.25 0.167 0.158 0.251 0.001 0.002 0.001 

Mammoth Caves - KY 0.647 0.91 0.646 0.647 0.91 0.648 0 0 0.002 

Mingo Wild. - MO 1.127 1.046 0.607 1.129 1.047 0.612 0.002 0.001 0.005 

Seney Wild. - MI 0.144 0.225 0.168 0.144 0.225 0.168 0 0 0 

Shenandoah N.P. - VA 0.123 0.139 0.166 0.124 0.14 0.167 0.001 0.001 0.001 

Sipsey Wild. - AL 0.504 0.171 0.343 0.52 0.171 0.343 0.016 0 0 

Voyageurs N.P. - MN 0.016 0.097 0.021 0.016 0.097 0.021 0 0 0 

Days above 0.5 DV Days above 0.5 DV Days above 0.5 DV 

Class 1 Areas 2002 2003 2004 2002 2003 2004 2002 2003 2004 

Boundary Waters - MN 0 0 0 0 0 0 0 0 0 

Brigantine Wild. - NJ 0 0 0 0 0 0 0 0 0 

Dolly Sods - WV 0 0 0 0 0 0 0 0 0 

Great Gulf Wild - NH 0 0 0 0 0 0 0 0 0 

Great Smokey Mount - TN 0 0 0 0 0 0 0 0 0 

Hercules - Glades Wild. - MO 0 0 0 0 0 1 0 0 1 

Isle Royale - MI 0 0 0 0 0 0 0 0 0 

James River Face - VA 0 0 0 0 0 0 0 0 0 

Linville Gorge - NC 0 0 1 0 0 1 0 0 0 

Lye Brook Wild. - VT 0 0 0 0 0 0 0 0 0 

Mammoth Caves - KY 1 6 2 1 6 2 0 0 0 

Mingo Wild. - MO 1 2 1 1 2 1 0 0 0 

Seney Wild. - MI 0 0 0 0 0 0 0 0 0 

Shenandoah N.P. - VA 0 0 0 0 0 0 0 0 0 

Sipsey Wild. - AL 1 0 0 1 0 0 0 0 0 

Voyageurs N.P. - MN 0 0 0 0 0 0 0 0 0 
Appendix 9d - 14 

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Appendix 9e - Alcoa Responses to National Parks Service Comments 
1 

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ALCOA

Alcoa Power Generating Inc - Warrick Power Plant

4700 Darlington Road

PO Box 10

Newburgh, IN 47630 USA

Tel: 8128531519

Fax: 8128534851

Samuet.Bruntz@aJcoa.com

Feb. 3,2011

p, D[l2

u.s. Environmental Protection Agency

Mailcode 2822T

1200 Pennsylvania Ave. NW

Washington, DC 20460

Re: Docket ID# EPA-HQ- OAR-2009--0491

Notice ofData Availability (NODA)

5 F'ed. Reg. 1109 (January 7, 2011)

Dear Sir 01' Madam:

Alcoa Power Generating, Inc. (APGI) Wan-ick Power Plant appreciates the opportunity to

comment, as follows:

1.) This NODA specifically invites comment regardiJlg existing units listed ill. the initial

Clean Air TranSPOlt Rule (CATR) that should not have been included. The CATR, as proposed,

specified that the proposed rule wou.ld be applicable for electricity generating units producing

electricity for sale. APGI consists of units IA. Units 1"3 are industrial boilers that produce

electricity, steam, and hot process vvater for tbeAlcoa hlC. Wan-iok Operations plimary

aluminum smelter and alumiuum fabrication plant. Electricity produced by these units is used for

the exclusive use ofAlcoa Inc., and is not sold on the grid. Unit 4 isjointly Ulivned by APGl and

Vecll'en. 50% ofthe electricity produced by this unit is sold to the grid, so it will be subject to the

CATR. AFar requests that Units 1-3 be removed from the list of existing potential units, since

they do not sell to the grid.

2.) APGI recommends that NODA Option 1 be used for allocating state budgets to

subject units. Option 1 proportions baseline heat input for each subject unit to total statewide

baseline heat input to determine the ~hare ofstate budget to be allocated, APGl does have
FEE/D D11 p, DD3

concerns with the overall CATR concept, in general. EPA seems not to have considered air

quality improvements achieved by the vacated CAIR rule, The most recent air quality data

indicate substantially fewer nonattainment and maintenance areas than EPA's data.

3.) Modeling of existing CAIR requirements and other OTB controls indi,cate no need for the nature

and extent of controls as proposed in the CA1R. APGI thus conditions its recommendation for Option

1 on a re-evaluation by EPA of needed pollutant reductions based on improvements the vacated cArR

rule provided.

4.) EPA has proposed a PIP rather than a SIP, followed by a FIP, as required by the CAA.

Congress intended States to take the primary role in regulating stationary sources under

Title I ofthe CAA. Title I unequivocally guarantees States the opportmlity to establish a

statewide program for achieving the NAAQS, and only where States fail to establish such

programs does a FIP apply directly to the sources within the State.

EPA lacks statutory authority to reverse the order ofthe NAAQS process designed by

Congress and immediately impose its program for a State1s achievement ofthe NAAQS, .

unless and until a State hus failed to develop and obtain approval ofits o\vn State

program.

Not only does a FIP-first approach violate the CAA, italso deprives States and som-ces

tIle opportunity - intended by the statutory scheme - to selectively target reductions from

among the many emissions sources. It also does not allow states to considerhaTdwate .

installations that have provided air quality improvements, and to find innovative, sourcespecific solutions to achieving emission reductions.

Especially in light of air quality improvements achieved pursuant to the vacated CAJR

rule, the urgency in 11landated severe enu.ssions reductions proposed by the CATR ruJ.e

FIP first approach is nat warranted. APGI thus strongly encourages EPA to allow stutes

to address the needed realistic emissions reductions tbxough the nonna! SIP amendm..ent

process provided by the Clean Air Act.

Thank yOll for considering these comments.

/

~/anme1 H. Bruntz(t)~ Senior StaffEnvironmental Engineer

Alcoa Inc. - Wsnick Operations

Alcoa Power Genetating Inc. - WalTick Power Plant

(812) 853~1519
Appendix 10 - IDEM Responses to US Forest Service Comments 
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Appendix 10 - 1 

IDEM Responses to US Forest Service Comments 

Our interest in the Indiana Regional Haze SIP is due to the fact that sources in your State cause 

or contribute to visibility impairment in many of our Class I Wilderness areas including the 

Boundary Waters Canoe Area Wilderness in Minnesota, Hercules Glades Wilderness Area in 

Missouri, Sipsey Wilderness Area in Alabama, Caney Creek Wilderness Area and Upper Buffalo 

Wilderness Area in Arkansas, Great Gulf Wilderness Area in New Hampshire, Lye Brook 

Wilderness Area in Vermont, James River Face Wilderness Area in Virginia, and Dolly Sods and 

Otter Creek Wilderness Areas in West Virginia. 

BART analyses

Comment: 

RPO coordination 

On page 35 the quote “The Uniform Rate is achieved and exceeded at all MANE-VU Class I 

sites” from “Recent MANE-VU Projections of Visibility for 2018.” Do these projections include 

the latest predictions in emissions from Indiana sources? It appears that with some sources 

modeling out of being subject-to-BART the 2018 emissions from Indiana may be greater than 

what was predicted by MANE-VU in 2008. The possibility that the RPOs assumed greater 

emission reductions in their Class I area analysis (Section 7.0) are highlighted on page 69 

(Section 9.2) – “The analyses show no reductions from Indiana sources, beyond the BART rule, 

are necessary to meet the reasonable progress goals of the areas analyzed at this time.” (emphasis 

added). It is not clear what reductions from Indiana other States considered part of the BART 

rule and how these could differ from the reductions proposed in this Regional Haze SIP. 

IDEM Response: 

IDEM has added the megawatt capacities for the Indiana coal fired units listed in Table 10 to 

demonstrate the size of these units. This table highlights the BART-eligible units and notes 

which units were included in the MANEVU “ask” list, described in Section 7.9. IDEM has 

added a more detailed description of the data presented in Table 10 and an explanation of the 

assumptions made for each column in the table. A discussion of the implications of the various 

modeling scenarios and the best current information available regarding Indiana electric 

generating units controls and the legal enforceability of these controls has been added. In 

addition, two tables in Appendix 10a show a comparison between IDEM's projected controls and 

EPA and LADCO's modeling scenarios for SO2 and NOx controls.

Cumulative Haze impacts

On page 49 – Table 15 - it appears that when considered cumulatively (the sum of modeled days 

over the 0.5 dv threshold for all the Class I areas modeled – 15 (Seney) + 6 (Mammoth Cave) + 4 

(Mingo) + 4 (Isle Royale) = 29 days) Burns Harbor would still be subject to BART. As the 

facility impacts haze at so many Class I areas we feel Indiana should address the cumulative 

impact of the facility and consider ArcelorMittal Burns Harbor subject to BART. 

IDEM Response: 

IDEM appreciates the USFS's comment and position on this issue. However, a consistence 

approach is preferred. Representatives from EPA Region 5, the EPA Headquarters and the states 

of Ohio, Michigan, Wisconsin and Minnesota favor the approach of summing up days for each 
Appendix 10 - 2 

individual Class 1 area instead of counting all modeled receptors at all the Class 1 areas 

modeled. A summary of responses from these respondents on the question of using cumulative 

or individual Class 1 area days above the BART threshold for BART determinations is attached 

in Appendix 10b. 

Comment: 

Please adjust permitted emissions to the highest actual emissions when there is a significant 

difference for facilities not subject to BART. 

Page 53 – Table 18 is an example of our concern when revised modeling results in facilities no 

longer being considered subject to BART done by the three facilities (Burns Harbor, ESSROC 

and SABIC) in Indiana. When the “highest actual” emission rates are significantly lower than 

the “potential” emission rates and the lower rates are used as justification to avoid subject to 

BART designation, the lower rates need to be incorporated into a federally enforceable permit 

condition. The NOx emissions for the highest emitting day and potential emissions in Table 18 

are similar but the SO2 differences are significant. Reduction in permitted, potential emissions to 

the actual highest emissions would ensure that the facility’s (ESSROC) emissions remain 

consistent with the “not subject to BART” determination. Most importantly, it will ensure that 

the facility has a minimal impact on regional haze in Class I areas. 

IDEM Response: 

IDEM appreciates the USFS's comment and position on this issue. However, average 24-hour 

actual emission rates from the highest emitting day are permitted according to the BART Rule 

and have been accepted by U.S. EPA and IDEM for use in the CALPUFF model. 

Comment: 

SABIC 

We recommend that IDEM accepts the permit modification from SABIC to remove the oil 

burning provision from Part 70 Operating Permit. This will ensure long-term visibility 

improvements from this current status at the plant. 

IDEM Response: 

IDEM has accepted the permit modification request from SABIC to remove the oil burning 

provisions from its Part 70 Operating Permit. The all references to fuel oil were removed from 

the emission unit description of the boiler, identified as BW-Boiler with ID No. 09-0001, on 

08/2008 through Minor Source/Significant Permit Modification Nos. 129-26621-00002/129-

26650-00002. 

 

Alcoa 

Comment: 

Emission reductions from Boiler 1, a not-subject-to-BART unit, could be achieved through 

Reasonable Progress as part of the Regional Haze Rule, and as such are not necessarily better 

than what would be achieved under the rule. 

 
Appendix 10 - 3 

IDEM Response: 

IDEM’s approach to BART reductions has been to follow guidance from various parts of the 

regional haze program. In the 1999 Regional Haze Regulations, Subpart P – Protection of 

Visibility, it states that reductions must be surplus to required emission reductions up to the 

baseline date. The established baseline date is 2002. The year 2002 has been used by various 

states, RPOs, and the EPA regional haze modeling guidance. It is also specified by the Lydia 

Wegman November 18, 2002 memo, “2002 Base Year Emission Inventory SIP Planning: 8-hr 

Ozone, PM2.5 and Regional Haze Programs.” 

The BART Rule, 70 FR 128, 39143, states that “(2) The EPA does not believe that anything in 

the CAA or relevant case law prohibits a State from considering emissions reductions required to 

meet other CAA requirements when determining whether source by source BART controls are 

necessary to make reasonable progress.” and “(3)...in lieu of BART programs be based on 

emissions reductions ‘surplus to reductions resulting from measures adopted to meet 

requirements as of the baseline date of the SIP.’ The baseline date for regional haze SIPs is 

2002...” This is extracted from a discussion justifying the use of CAIR, a program used for 

other purposes, to substitute for BART. Therefore, it is our belief that emission reductions from 

Boiler 1 as part of the BART alternative proposed by Alcoa is acceptable under the rule. 

Comment: 

There is no apparent reason why the SO2 controls on Boilers 2 and 3 cannot achieve 92 percent 

or greater efficiency with wet FGD. Please explain and justify the need to operate this control 

equipment at 90 percent. Include this as part of the five-factor analysis. 

 

IDEM Response: 

Alcoa used the 92% reduction level for the BART control analysis for Boilers 2 and 3. The 

alternative to BART proposal was to control Boiler 1 at 91% and Boiler 2 and 3 at 90%, which 

still results in an overall improvement in visibility degradation. The actual modifications 

performed to the boilers were not extensive enough to trigger the 92% removal efficiency level 

requirements, as required in the re-construction criteria set forth in the NSPS for industrial 

boilers. 

Comment: 

The need to allow for increased sulfur content in coke above 3 percent has not been seen in 

previous BART determinations. Additional information about the need to use higher sulfur coke 

is needed. An analysis including cost comparisons and dollar per deciview comparisons between 

the proposed and alternative BART are needed as part of the five-factor analysis for the BART 

determination. 

IDEM Response: 

Sulfates are the main contributors, at approximately 0.188 dv. Contributions due to other species 

are less than 0.01 dv. Therefore, any add-on controls for these pollutants will result in 

insignificant improvements in visibility. Due to insignificant impact from vents (0.013 dv), 

Alcoa did not perform the 5-step analysis for these sources. Further, these sources are subject to 

40 CFR 63, Subpart LL, Maximum Achievable Control Technology (MACT). In order to 

comply with these standards, Alcoa follows work practices which minimize emissions escaping 

roof vents. 
Appendix 10 - 4 

Sulfur dioxide from potlines can be controlled by lowering sulfur content in the anode grade 

coke and/or by installing wet scrubbers. Alcoa presently limits sulfur at ≤ 2%. From a market 

study, Alcoa has concluded that a supply of coke below 3% sulfur cannot be ensured beyond 

2013, the year when the BART controls will be needed. Therefore it proposes ≤ 3% sulfur coke 

as BART and ≤ 3.5% sulfur coke as alternative BART. The 3.5% sulfur limit in the coke 

translates into 2.919% sulfur in the baked anode composite, the practice Alcoa follows to 

measure the sulfur content. 

The installed and annual costs of wet scrubbers on potlines are estimated at $300 million and $55 

million respectively. Modeling shows that SO2 scrubbers on potlines can improve visibility by 

0.138 dv. This improvement will be achieved at a cost/benefit ratio equal to $398 million/dv. 

Also, there are severe space and access limitations at the facility that would complicate the 

installation. 

Comment: 

A five factor analysis is needed for the Alcoa facility to accurately determine if SNCR or SCR 

technology for NOx control is feasible. Stating the costs and the assumption that these controls 

would not be cost effective without information, or data, to support the statement does not meet 

the needs, or intent, of a five factor analysis. Similar analysis is needed for PM controls on 

Boilers 2-4. 

IDEM Response: 

The NOx controls are significantly tighter than NSPS limits (0.38 lb/MMBtu vs. 0.70 

lb/MMBtu), which are the “required” controls referenced. In regard to PM, Alcoa provided 

information regarding the cost of adding a baghouse on each unit, at IDEM’s request. 

Alcoa evaluated fabric filtration for Boiler 4 , the installation cost on a $ / dv basis was shown to 

be unreasonable. PM emissions from Boiler 4 would be higher than the BART level of control 

of 0.015 lb./mm Btu, which is the NSPS for a new utility boiler. However, the alternative to 

BART emission reductions provided by Boiler #1 offsets the PM emissions that would exceed 

the BART alone level from Boiler 4, and would therefore meet the regional haze rule 

requirements. 

Impact of Adding Baghouses for Units 2, 3, and 4

Based on information provided by another utility where baghouse control was installed, the 

capital cost for a baghouse on a 2830 mm Btu/hr. boiler was $49.7 mm. Assuming baghouse 

capital costs are proportional to heat input, the capital cost for the baseline heat inputs for the 

BART eligible boilers is estimated to be: 

Boiler 2: 1364.41 mm Btu/hr. Estimated baghouse capital cost would be 

(1364.41/2830) X $49.7 mm = $23.96 mm 

Boiler 3: 1323.51 mm Btu/hr. Estimated baghouse capital cost would be 

(1323.51/2830) X $49.7 mm = $23.24 mm 

Boiler 4: 2845.79 mm Btu/hr. Estimated baghouse capital cost would be 
Appendix 10 - 5 

(2845.79/2830) X $49.7 mm = $49.98 mm 

Airflow for boiler 2: 347,149 scfm 

Airflow for boiler 3: 335,372 scfm 

Airflow for boiler 4: 796,416 scfm 

Assuming the lowest emission rate a baghouse vendor will guarantee is 0.005 grains /scf, 

filterable PM emissions would be: 

Boiler 2: (0.005 grains/scf) X (347,149 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 14.88 

lbs./hr. 

Boiler 3: (0.005 grains/scf) X (335,149 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 14.36 

lbs./hr. 

Boiler 4: (0.005 grains/scf) X (796,416 scf/min) X (60 min. /hr.) X (1 lb. /7000 grains) = 34.13 

lbs./hr. 

On an annualized basis, the filterable PM emissions would be 128.07 tons from boilers 2 and 3 

combined, and 149.49 tons/yr. from boiler 4. 

Because the baghouses will be upstream of wet scrubbers, the assumed baghouse vendor 

guarantee emissions is conservative because it does not take into account the added filterable PM 

from the scrubbers. 

BART for filterable PM for all 3 boilers was electrostatic precipitators and SO2 scrubbers. 

BART was proposed at 0.03 lb./mm Btu for boilers 1 and 2, and 0.015 lb./mm Btu for boiler #4. 

BART annual filterable PM emissions would thus be: 

Boiler 2: (0.03 lb./mm Btu) X (1364.41 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

179.28 tons/yr. 

Boiler 3: (0.03 lb./mm Btu) X (1323.51 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

173.91 tons/yr. 

Boiler 4: (0.015 lb./mm Btu) X (2845.79 mm Btu/hr.) X (8760 hrs/yr.) X (1 ton/2000 lbs.) = 

186.97 tons/yr. 

Detailed engineering would have to take into consideration the available real estate for 

installation of baghouses, removal of the precipitators or routing the exhaust gases in series 

through the precipitators, baghouses then downstream pollution removal equipment, present 

boiler and pollution control equipment configurations, ash handling from the ash removed by the 

baghouses, etc. Those factors would increase the capital cost assumptions used above. 
Appendix 10 - 6 

For the $/ton and $/dv improvement derived below, and the present prevailing economic 

conditions, Alcoa Power Generating Inc. – Warrick Power Plant does not understand the 

usefulness of performance of such a study. 

Assuming an annualized cost of 11% of the assumed capital costs, the annualized cost on a $/ton 

difference between the alternative to BART proposal and baghouses would be: 

Boilers 2 and 3: 11% of $47.2 mm = $5,192,000 / yr. 

BART emissions: 353.19 tons/yr. 

Baghouse: 128.07 tons/yr. 

Baghouse additional removal: (353.19 – 128.07) tons/yr. = 225.12 tons/yr. 

$ / ton impact: $5,192,000 / 225.12 tons/yr. = $23,063.26 / ton 

Boiler 4: 11% of $49.98 mm = $5,497,800 / yr. 

BART emissions: 186.97 tons/yr. 

Baghouse: 149.49 tons/yr. 

Baghouse additional removal: (186.97 – 149.49) tons/yr. = 37.48 tons/yr. 

$ / ton impact: $5,497,800 / 37.48 tons/yr. = $146,686.23 / ton 

Baseline visibility impact, filterable PM, boilers 2 and 3: 0.027 dv, based on 2003 (See revised 

table 5-2 in the BART determination report). 

The assumed baghouse outlet emissions would result in a filterable PM reduction of: 

Baseline: 635.02 lbs/hr. 

Baghouse: 63.37 lbs./hr. 

Reduction: [(635.02 – 63.37)/635.02] X 100 = 90.02% 

A reduction of 90.02% in the visibility impact would represent a dv impact reduction of: 

0.027 dv X (90.02/100) = 0.024 dv 

The annualized cost for baghouses on a $/dv basis would thus be: 

$(5,192,000 + 5,497,800) / 0.024 dv = $445 mm / dv 

The above 11% of capital assumption does not consider such operating costs as increased 

pressure drop represented by the baghouse, possible de-rating of the boiler, and the baghouse 

being upstream of a wet scrubber. The above cost estimates are thus low, but still show that the 

extra cost represented by baghouses is unreasonable both from a $/ton and $/dv basis. 
Appendix 10 - 7 

Long-term Strategy

Comment: 

Necessary smoke management regulations and techniques for prescribed burning on National 

Forest land appear to be covered in IC 13-17-9 and 326 IAC 4-1 and the associated information 

in Appendix 6. However, it may be beneficial to formalize these regulations in an Indiana 

Smoke Management Plan/Program per EPA’s Interim Air Quality Policy on Wildland and 

Prescribed Fires (April 23, 1998). The Forest Service will work with the State to help develop 

this SMP in the future. 

We request that Indiana provide language in your SIP linking the Regional Haze and New 

Source Review programs, including continued FLM coordination for these programs. Currently, 

there is no mechanism in the SIP to ensure that the emissions from new stationary sources or 

major modifications of existing sources will make reasonable progress toward the national 

visibility goal (40 CFR 51.307). This could be especially important for emissions from new 

sources that were not anticipated in 2018 emission inventories. Please describe how new and 

expanded sources of air emissions will be reviewed to ensure they don’t jeopardize reasonable 

progress goals set by Class I Areas owner states. 

IDEM Response: 

Please see the IDEM Response to National Parks Service Comments in Appendix A for IDEMs 

response regarding the Long Term Strategy comment related to linking the Regional Haze and 

New Source Review programs in the SIP and the mechanism in the SIP to ensure that the 

emissions from new stationary sources or major modifications of existing sources will make 

reasonable progress toward the national visibility goal (40 CFR 51.307). 

 
Appendix 10 - 8 

This page intentionally left blank.

 
Appendix 10 - 9 

Appendix 10 - IDEM Responses to US Forest Service Comments Cover Letter 
Appendix 10 - 10 

This page intentionally left blank.
Appendix 10 - 11 

File Code: 2580 

Date: December 22, 2010 

Ken Ritter 

Air Programs Branch 

IDEM Office of Air Quality 

100 North Senate Avenue 

Indianapolis, IN 46204-2251 

Dear Mr. Ritter, 

On November 6, 2010 the State of Indiana submitted a draft State Implementation Plan (SIP) describing 

your proposal to improve regional haze impacts at mandatory Class I areas across your region. We 

appreciate the opportunity to work closely with your State through the initial evaluation, development, 

and now, subsequent review of this plan. Cooperative efforts such as these ensure that, together, we will 

continue to make progress toward the Clean Air Act’s goal of natural visibility conditions at our Class I 

Wilderness areas. 

The Forest Service provided informal comments on IDEM’s BART analyses to Mark Derf on September 

22, 2009 to which IDEM provided responses on February 9, 2010. We will not reiterate those comments 

again in this letter. This letter acknowledges that the U.S. Forest Service has received and conducted a 

substantive review of your proposed Regional Haze SIP including the Best Available Retrofit Technology 

(BART) designations. Please note that only the U.S. Environmental Protection Agency (EPA) can make 

a final determination about the document’s completeness, and therefore, only the EPA has the ability to 

approve the document. The Forest Service’s participation in Indiana’s administrative process does not 

waive any legal defenses or sovereignty rights it may have under the laws of the United States, including 

the Clean Air Act and its implementing regulations. 

I have attached comments to this letter from the perspective of a Federal Land Manager. I look forward 

to your response required by 40 CFR 51.308(i)(3). For further information, please contact air resources 

management specialist Edward Huffman (elhuffman@fs.fed.us, (304) 636-1800 ext. 192). 

Again, we appreciate the opportunity to work closely with the State of Indiana. The Forest Service 

compliments you on your hard work and dedication to significant improvement in our nation’s air quality 

values and visibility. 

Sincerely, 

/s/ Debra J. Tenney (for): 

CLYDE N. THOMPSON 

Forest Supervisor 

cc: John Summerhays - R5 E 

 Caring for the Land and Serving People Printed on Recycled Paper 

United States 

Department of 

Agriculture

Forest 

Service 

Monongahela National Forest 200 Sycamore Street 

Elkins, WV 26241 

304-636-1800 


Appendix 10a - SO2 and NOx Credits for Projected 

Best Available Retrofit Technology 
This page intentionally left blank.
SO2 CREDITS FOR PROJECTED BEST AVAILABLE RETROFIT TECHNOLOGY 

FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

SO2_CONTROL SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 

A B Brown Generating

Station 1 250 Dual Alkali FGD SCR+FGD 250 250 250 250 250 250 250 250 250 

A B Brown Generating

Station 2 250 Dual Alkali FGD SCR+FGD 250 250 250 250 250 250 250 250 250 

Alcoa Allowance Management Inc 1 144

Wet Limestone FGD (2008) LNB w/SOFA 144 144 144 144 144 

Alcoa Allowance Management Inc 2 144

Wet Limestone FGD (2008) LNB w/SOFA 144 144 144 144 144 

Alcoa Allowance Management Inc 3 144

Wet Limestone FGD (2008) LNB w/SOFA 144 144 144 144 144 

Alcoa Allowance Management Inc 4 300

Wet Limestone FGD (2008) SCR 300 300 FGD 300 300 FGD 300 300 FGD 300 

Bailly Generating Station 7 160 Wet Limestone SCR+FGD 160 160 160 160 160 160 160 160 160 

Bailly Generating

Station 8 320 Wet Limestone SCR+FGD 320 320 320 320 320 320 320 320 320 

Cayuga* 1 500

Wet Limestone (2008 - 95%)

FGD+LNB w/SOFA 500 500 500 500 SCR 500 500 SCR 500 500 SCR 500 

Cayuga* 2 495

Wet Limestone (2008 - 95%)

FGD+LNB w/SOFA 495 495 495 495 SCR 495 495 SCR 495 495 SCR 495 

Clifty Creek* 1 217

(FGD Scheduled after 2014) FGD+SCR 217 217 217 217 217 217 

Clifty Creek* 2 217

(FGD Scheduled after 2014) FGD+SCR 217 217 217 217 217 217 

Clifty Creek* 3 217

(FGD Scheduled after 2014) FGD+SCR 217 217 217 217 217 217 

Clifty Creek* 4 217

(FGD Scheduled after 2014) FGD+SCR 217 217 217 217 217 217 

Clifty Creek* 5 217

(FGD Scheduled after 2014) FGD+SCR 217 217 217 217 217 217 

Clifty Creek* 6 217

(FGD Scheduled after 2014) FGD 217 SCR 217 SCR 217 217 SCR 217 217 SCR 

Dean H Mitchell Generating Station 11 125 Shut Down LNB 125 125 125 125 125 Dean H Mitchell Generating Station 4 125 Shut Down

Comb. Optimization 125 125 125 SCR 125 125 

Dean H Mitchell Generating Station 5 125 Shut Down

Comb. Optimization 125 125 125 SCR 125 125 

Dean H Mitchell Generating Station 6 110 Shut Down LNB 110 110 110 SCR 110 110 Edwardsport 7-1 40

Unit will retire in 2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

LADCO Round 5 Runs

2009 + Projected Compared to IPM 

Existing

SO2

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

2009 + Projected Compared to IPM 

2020 Retrofit

2009 + Projected Compared 

2012 Retrofit

LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

C

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

 IPM 2010 

Retrofit

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

SO2_CONTROL SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 

LADCO Round 5 Runs

2009 + Projected Compared to IPM 

Existing

SO2

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

2009 + Projected Compared to IPM 

2020 Retrofit

2009 + Projected Compared 

2012 Retrofit

LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

C

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

 IPM 2010 

Retrofit

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

Edwardsport 7-2 40

Unit will retire in 2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

Edwardsport 8-1 40

Unit will retire in 2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

F B Culley Generating Station 2 90 Wet Limestone FGD+LNB 90 90 90 90 90 90 SNCR 90 90 90 F B Culley Generating Station 3 270 Wet Limestone FGD+SCR 270 270 270 270 270 270 270 270 270 Frank E Ratts 1SG1 122

U.S. EPA settlement, plant-wide from 2009 levels 42% reduction - 2012, 58% - 2014 LNB 122 SCR 122 122 

Frank E Ratts 2SG1 121

U.S. EPA settlement, plant-wide from 2009 levels 42% reduction - 2012, 58% - 2014 LNB SCR 

Gibson* 1 630 Wet Limestone SCR+FGD 630 630 630 630 630 630 630 630 630 Gibson* 2 630 Wet Limestone SCR+FGD 630 630 630 630 630 630 630 630 630 Gibson* 3 630 Wet Limestone SCR+FGD 630 630 630 630 630 630 630 630 630 

Gibson* 4 622 Wet Limestone SCR+FGD 622 622 622 622 622 622 622 622 622 Gibson 5 620 Wet Limestone SCR+FGD 620 620 620 620 620 620 620 620 620 

Harding Street Station (EW Stout) 50 109 SNCR

Harding Street Station (EW Stout) 60 109 SNCR

Harding Street Station (EW Stout)* 70 435 Wet Limestone SCR 435 FGD 435 435 FGD 435 435 FGD 435 435 FGD 435 

IPL Eagle Valley Generating Station 3 43
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

SO2_CONTROL SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 

LADCO Round 5 Runs

2009 + Projected Compared to IPM 

Existing

SO2

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

2009 + Projected Compared to IPM 

2020 Retrofit

2009 + Projected Compared 

2012 Retrofit

LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

C

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

 IPM 2010 

Retrofit

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IPL Eagle Valley Generating Station 4 56 LNB w/SOFA

IPL Eagle Valley Generating Station 5 62 LNB w/SOFA

IPL Eagle Valley Generating Station 6 99 LNB w/SOFA

Merom 1SG1 507

upgrade FGD-90% 2012, upgrade to 95% 2014 SCR+FGD 507 507 507 507 507 507 507 507 507 

Merom 2SG1 493

upgrade FGD-90% 2012, upgrade to 95% 2014 SCR+FGD 493 493 493 493 493 493 493 493 493 

Michigan City

Generating Station 12 469 SCR Hg Control 

Petersburg 1 232 Wet Limestone FGD+LNB 232 232 232 232 232 232 SCR 232 232 232 

Petersburg 2 407 Wet Limestone FGD+SCR 407 407 407 407 407 407 407 407 407 

Petersburg 3 510 Wet Limestone FGD+SCR 510 510 510 510 510 510 510 510 510 

Petersburg 4 545 Wet Limestone FGD+LNB 545 545 545 545 SCR 545 545 SCR 545 545 545 

R Gallagher* 1 140

Shut down by 2/1/12 or Convert to NG 1/1/13 LNB 140 140 140 

R Gallagher* 2 140

Dry Sorbent Technology 1/1/11 LNB 140 140 140 

R Gallagher* 3 140

Shut down by 2/1/12 or Convert to NG 1/1/13 LNB 140 140 140 

R Gallagher* 4 140

Dry Sorbent Technology 1/1/11 LNB

R M Schahfer Generating Station 14 431 SCR 431 Hg Control 431 

R M Schahfer Generating Station 15 472 LNB Hg Control 472 
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

SO2_CONTROL SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 

LADCO Round 5 Runs

2009 + Projected Compared to IPM 

Existing

SO2

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

2009 + Projected Compared to IPM 

2020 Retrofit

2009 + Projected Compared 

2012 Retrofit

LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

C

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

 IPM 2010 

Retrofit

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

R M Schahfer Generating Station 17 361

Wet Limestone

SCR 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361 361 

R M Schahfer Generating Station 18 361

Wet Limestone

LNB 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361 361 

Rockport* MB1 1300

FGD 12/31/17 TR allowances < CAIR 2012 and 2014 LNB w/OFA FGD 1300 FGD 1300 FGD+SCR 1300 1300 FGD 

Rockport* MB2 1300

FGD 12/31/17 TR allowances < CAIR 2012 and 2014 LNB w/OFA FGD 1300 FGD 1300 FGD+SCR 1300 1300 FGD 

State Line Generating Station (IN) 3 187State Line Generating Station (IN) 4 303 SCR SCR

SCR+Hg Control SCR

Tanners Creek* U1 140

Burn only coal with no more than 1.2 lb/MMBtu annual average OFA

Tanners Creek* U2 140

Burn only coal with no more than 1.2 lb/MMBtu annual average OFA

Tanners Creek* U3 200

Burn only coal with no more than 1.2 lb/MMBtu annual average OFA FGD+SCR 140 

Tanners Creek* U4 500

Burn only coal with no more than 1.2% sulfur content annual average OFA

Wabash River Gen Station* 1 85 IGCC

Wabash River Gen Station* 2 85 Shut Down 9-30-09 LNB 85 85

Wabash River Gen Station* 3 85 Shut Down 9-30-09 LNB 85 85 SNCR 

Wabash River Gen Station* 4 85 LNB

Wabash River Gen Station* 5 95 Shut Down 9-30-09 LNB 95 95 SNCR 

Wabash River Gen Station* 6 318

TR allocation in 2014 < CAIR LNB FGD+SCR 318 
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

SO2_CONTROL SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 SO2 

LADCO Round 5 Runs

2009 + Projected Compared to IPM 

Existing

SO2

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

2009 + Projected Compared to IPM 

2020 Retrofit

2009 + Projected Compared 

2012 Retrofit

LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

C

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

 IPM 2010 

Retrofit

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

Whitewater Valley 1 34.77 LNB

Whitewater Valley 2 62.8 Other LNB

10,800 9,463 10,800 13,220 12,810 13,520 15,882 13,978 11,077 

IDEM Base 

Case 

EPA Basecase 

IDEM 2010

IDEM 2020

EPA 2020

IDEM 2012

EPA 2010 

IDEM 2015

EPA 2015
NOX CREDITS FOR PROJECTED BEST AVAILABLE RETROFIT TECHNOLOGY 

FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

NOx_CONTROL NOx NOx NOx NOx NOx NOx NOx NOx NOx N

A B Brown Generating

Station 1 250

Selective Catalytic Reduction SCR+FGD 250 250 250 250 250 250 250 250 250 

A B Brown Generating

Station 2 250

Selective Catalytic Reduction SCR+FGD 250 250 250 250 250 250 250 250 250 

Alcoa Allowance Management Inc 1 144

Low NOx Burner 

Technology w/ Overfire Air LNB w/SOFA 144 144 144 144 144 144 144 144 144 

Alcoa Allowance Management Inc 2 144

Low NOx Burner Technology w/ Overfire Air LNB w/SOFA 144 144 144 144 144 144 144 144 144 

Alcoa Allowance Management Inc 3 144

Low NOx Burner Technology w/ Overfire Air LNB w/SOFA 144 144 144 144 144 144 144 144 144 

Alcoa Allowance Management Inc 4 300

Low NOx Burner Selective Catalytic Reduction SCR 300 300 300 300 FGD 300 300 FGD 300 300 FGD 300 

Bailly Generating Station 7 160

Overfire Air / Selective Catalytic Reduction (2008) SCR+FGD 160 160 160 160 160 160 160 160 160 

Bailly Generating

Station 8 320

Overfire Air / Selective Catalytic Reduction SCR+FGD 320 320 320 320 320 320 320 320 320 

Cayuga* 1 500

Low NOx Burner 

Technology w/ Separated OFA

FGD+LNB w/SOFA SCR 500 SCR 500 SCR 

Cayuga* 2 495

Low NOx Burner 

Technology w/ Separated OFA

FGD+LNB w/SOFA SCR 495 SCR 495 SCR 

Clifty Creek* 1 217

Overfire Air Selective Catalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 

Clifty Creek* 2 217

Overfire Air Selective Catalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 

Clifty Creek* 3 217

Overfire Air Selective Catalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 

Clifty Creek* 4 217

Overfire Air Selective Catalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 

Clifty Creek* 5 217

Overfire Air Selective Catalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 

Clifty Creek* 6 217 Overfire Air FGD SCR 217 SCR 217 SCR 217 SCR 

Dean H Mitchell Generating Station 11 125 Shut Down LNB 125 125 125 125 125 

Dean H Mitchell Generating Station 4 125 Shut Down

Comb. Optimization 125 125 125 SCR 125 125 

Dean H Mitchell Generating Station 5 125 Shut Down

Comb. Optimization 125 125 125 SCR 125 125 

Dean H Mitchell Generating Station 6 110 Shut Down LNB 110 110 110 SCR 110 110 Edwardsport 7-1 40

2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask

NOx LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

 IPM 2010 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

2009 + Projected Compared to IPM 

Existing

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

2009 + Projected Compared to IPM 

2020 Retrofit

LAD

Cred

Contr

M

LADCO Round 5 Runs

2009 + Projected Compared 

LADCO 2012 Retrofit
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

NOx_CONTROL NOx NOx NOx NOx NOx NOx NOx NOx NOx N

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask

NOx LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

 IPM 2010 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

2009 + Projected Compared to IPM 

Existing

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

2009 + Projected Compared to IPM 

2020 Retrofit

LAD

Cred

Contr

M

LADCO Round 5 Runs

2009 + Projected Compared 

LADCO 2012 Retrofit

Edwardsport 7-2 40

2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

Edwardsport 8-1 40

2012, IGCC will replace all the units in 2012 Retire Retire Retire Retire 

F B Culley Generating Station 2 90

Low NOx Burner 

Technology (Dry Bottom only) FGD+LNB 90 90 90 90 90 90 SNCR 90 90 90 

F B Culley Generating Station 3 270

Low NOx Burner 

Technology (Dry Bottom only) Selective Catalytic Reduction FGD+SCR 270 270 270 270 270 270 270 270 270 

Frank E Ratts 1SG1 122

Low NOx Burner 

Technology (Dry Bottom only) OFA2008 LNB 122 SCR 122 122 122 

Frank E Ratts 2SG1 121

Low NOx Burner 

Technology (Dry Bottom only) OFA2008 LNB SCR 121 

Gibson* 1 630

LNB w/ Overfire Air Selective Catalytic Reduction SCR+FGD 630 630 630 630 630 630 630 630 630 

Gibson* 2 630

Low NOx Burner 

Technology w/ Overfire Air Selective Catalytic Reduction SCR+FGD 630 630 630 630 630 630 630 630 630 

Gibson* 3 630

Low NOx Burner 

Technology w/ Overfire Air Selective Catalytic Reduction SCR+FGD 630 630 630 630 630 630 630 630 630 

Gibson* 4 622

Low NOx Burner 

Technology w/ Overfire Air Selective Catalytic Reduction SCR+FGD 622 622 622 622 622 622 622 622 622 

Gibson 5 620

Low NOx Burner 

Technology w/ Overfire Air Selective Catalytic Reduction SCR+FGD 620 620 620 620 620 620 620 620 620 

Harding Street Station (EW Stout) 50 109

LNB w/ Separated OFA Selective Noncatalytic Reduction SNCR 109 109 109 109 109 109 109 109 109 

Harding Street Station (EW Stout) 60 109

LNB w/ Separated OFA Selective Noncatalytic Reduction SNCR 109 109 109 109 109 109 109 109 109 

Harding Street Station (EW Stout)* 70 435

LNB w/ Closedcoupled/Separated OFA Selective Catalytic Reduction SCR 435 435 FGD 435 435 FGD 435 435 FGD 435 435 FGD 435 

IPL Eagle Valley

Generating Station 3 43
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

NOx_CONTROL NOx NOx NOx NOx NOx NOx NOx NOx NOx N

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask

NOx LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

 IPM 2010 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

2009 + Projected Compared to IPM 

Existing

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

2009 + Projected Compared to IPM 

2020 Retrofit

LAD

Cred

Contr

M

LADCO Round 5 Runs

2009 + Projected Compared 

LADCO 2012 Retrofit

IPL Eagle Valley Generating Station 4 56

Low NOx Burner Technology w/ Separated OFA LNB w/SOFA 56 56 56 56 56 56 56 56 56 

IPL Eagle Valley Generating Station 5 62

Low NOx Burner Technology w/ Separated OFA LNB w/SOFA 62 62 62 62 62 62 62 62 62 

IPL Eagle Valley Generating Station 6 99

Low NOx Burner Technology w/ Separated OFA LNB w/SOFA 99 99 99 99 99 99 99 99 99 

Merom 1SG1 507

Selective Catalytic Reduction Low Nox Burner Technology w/ Overfire Air SCR+FGD 507 507 507 507 507 507 507 507 507 

Merom 2SG1 493

Selective Catalytic Reduction Low NOx 

Burner Technology w/ Overfire Air 493 493 493 493 493 

Michigan City

Generating Station 12 469

Selective Catalytic Reduction SCR 469 469 469 469 469 469 Hg Control 469 469 469 

Petersburg 1 232

Low NOx Burner 

Technology w/ Closedcoupled/Sep. OFA FGD+LNB SCR 232 

Petersburg 2 407

LNB w/ Closedcoupled/Separated OFA Selective Catalytic Reduction FGD+SCR 407 407 407 407 407 407 407 407 407 

Petersburg 3 510

LNB w/ Closedcoupled/Separated OFA Selective Catalytic Reduction FGD+SCR 510 510 510 510 510 510 510 510 510 

Petersburg 4 545

Low NOx Burner 

Technology w/ Closedcoupled/Sep. OFA FGD+LNB SCR 545 SCR 545 

R Gallagher* 1 140

Shut down by 2/1/12 or Convert to NG 1/1/13 LNB 140 140 140 140 140 140 140 

R Gallagher* 2 140

Low NOx Burner 

Technology w/ Overfire Air LNB 140 140 140 140 140 140 140 140 140 

R Gallagher* 3 140

Shut down by 2/1/12 or Convert to NG 1/1/13 LNB 140 140 140 140 140 140 140 

R Gallagher* 4 140

Low NOx Burner 

Technology w/ Overfire Air LNB 140 140 140 140 140 140 140 140 140 

R M Schahfer Generating Station 14 431

Overfire Air Selective Catalytic Reduction SCR 431 431 431 431 431 431 Hg Control 431 431 431 

R M Schahfer Generating Station 15 472

LNB (Dry Bottom only) A 35% efficient stratified overfire air system was added in 2008 LNB 472 472 472 472 472 Hg Control 472 472 
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

NOx_CONTROL NOx NOx NOx NOx NOx NOx NOx NOx NOx N

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask

NOx LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

 IPM 2010 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

2009 + Projected Compared to IPM 

Existing

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

2009 + Projected Compared to IPM 

2020 Retrofit

LAD

Cred

Contr

M

LADCO Round 5 Runs

2009 + Projected Compared 

LADCO 2012 Retrofit

R M Schahfer Generating Station 17 361

LNB w/ Closedcoupled/Separated 

OFA

SCR 361 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361 361 

R M Schahfer Generating Station 18 361

LNB w/ Closedcoupled/Separated 

OFA

LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361 361 

Rockport* MB1 1300

LNB (Dry Bottom only) (SCR 12/31/17) LNB w/OFA FGD FGD FGD+SCR 1300 1300 FGD 

Rockport* MB2 1300

Technology (Dry Bottom only) (SCR 12/31/19) LNB w/OFA FGD FGD FGD+SCR 1300 1300 FGD 

State Line Generating

Station (IN) 3 187State Line GeneratingStation (IN) 4 303 Overfire Air 303 SCR 303 SCR 303

SCR+Hg Control 303 SCR 303

Tanners Creek* U1 140

Low NOx Burner 

Technology (Dry Bottom only) A 30% efficient SNCR will be in place in 2010. SNCR will operate year round OFA 140 140 140 140 140 

Tanners Creek* U2 140

Low NOx Burner 

Technology (Dry Bottom only) A 30% efficient SNCR will be in place in 2010. SNCR will operate year round OFA

Tanners Creek* U3 200

Low NOx Burner 

Technology (Dry Bottom only) A 30% efficient SNCR will be in place in 2010. SNCR will operate year round OFA 140 140 140 FGD+SCR 140 140 140 

Tanners Creek* U4 500 Overfire Air OFA

Wabash River Gen Station* 1 85 IGCCWabash River Gen Station* 2 85 Shut Down 9-30-09 LNBWabash River Gen Station* 3 85 Shut Down 9-30-09 LNB SNCR 

Wabash River Gen Station* 4 85

Low NOx Burner 

Technology w/ Overfire Air LNB 85 85 85 85 85 85 85 85 85 

Wabash River Gen Station* 5 95 Shut Down 9-30-09 LNB SNCR 

Wabash River Gen Station* 6 318

Low NOx Burner 

Technology w/ Separated OFA LNB FGD+SCR 318 
FACILITY_NAME

UNITID

Capacity 

MWe

2009 + Projected 

NOx_CONTROL NOx NOx NOx NOx NOx NOx NOx NOx NOx N

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe

BART-eligible Units

*MANEVU Ask

NOx LADCO 2012 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

INDIANA COAL-FIRED UNITS

2009 + Projected Compared to IPM 

Retrofit 2015

EPA Credit 

for 

Control(s) in 

MWe

EPA IPM 3.0 2006 runs

 IPM 2010 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

EPA Credit 

for 

Control(s) in 

MWe IPM 2020 

Retrofit

EPA Credit 

for 

Control(s) in 

MWe IPM Existing

2009 + Projected Compared to IPM 

2010 Retrofit

2009 + Projected Compared to IPM 

Existing

 IPM 2015 

Retrofit

IDEM 

Credit for 

Control(s) in 

MWe

IDEM 

Credit for 

Control(s) in 

MWe

2009 + Projected Compared to IPM 

2020 Retrofit

LAD

Cred

Contr

M

LADCO Round 5 Runs

2009 + Projected Compared 

LADCO 2012 Retrofit

Whitewater Valley 1 34.77

Low NOx Burner 

Technology w/ Separated OFA Ammonia Injection Overfire Air LNB 34.77 34.77 34.77 34.77 34.77 34.77 34.77 34.77 34.77 

Whitewater Valley 2 62.8

Low NOx Burner 

Technology w/ Separated OFA Ammonia Injection Overfire Air LNB 62.8 62.8 62.8 62.8 62.8 62.8 62.8 62.8 62.8 

12,981 11,420 12,981 11,637 13,103 12,425 15,703 15,958 13,103 

EPA 2015

IDEM 2010

EPA 2010 

IDEM Base 

IDEM 2015

Case 

EPA Basecase 

EPA 2020

IDEM 2020

IDEM 2012

LADCO 2012
Appendix 10b - BART Analyses Cumulative Haze Impacts E-mails 
This page intentionally left blank.
Appendix 10b - 1 

BART Analyses - Cumulative Haze Impacts

Below is a summary of responses to the question of using cumulative or individual Class 1 area days above the BART 

threshold for BART determinations. Respondents included representatives from EPA Region 5, EPA Headquarters and 

from the states of Ohio, Michigan, Wisconsin and Minnesota. All states appear to favor the approach of summing up days 

for each individual Class 1 area instead of counting all modeled receptors at all the Class 1 areas modeled. States desire 

a constant approach to this 

EPA Region 5 and EPA Headquarter Responses

Hello Mark,                     Sept. 5, 2008

Just FYI.   I had some discussions with Wisconsin last week about the single vs multiple Class I area determination question you asked

back in June.  I forwarded to them the communications I had sent to you, attached below.    We further had some conversations

with Tim Allen with the FWS and he stated that he's not seen the guidance interpreted that way.   In the work he's seen, analysis

done for Subject to BART has been single Class I area only.  However, for BART determination work, they are advising a multiple

Class I area analysis.   I don't see the logic in that but that's what being done apparently.    Of course, the bottom line on this is that

States can be as conservative as they feel is needed.   Maybe with the 0.5 dv threshold, additional conservatism is warranted.

I don't know if this will have any impact on your work but wanted to share it with you.

Randy.

P.S.   Guess we'll see you on the 11th regarding Alcoa.   We should probably talk briefly before the meeting.

Randy Robinson

USEPA Region 5

312 353‐6713

06/17/2008 12:45 PM          

                                                                    

To:  "DERF, MARK" MDERF@idem.IN.gov                                                         

Randall Robinson/R5/USEPA/US@EPA   

Cc:    

                                                                         

Subject  RE: Re: Fw: BART question          

                                                                         

Very helpful.  Thanks for passing along to Todd and getting back to me so quick. Enjoy the rest of your week off.  Take care.

From: Robinson.Randall@epamail.epa.gov

[mailto:Robinson.Randall@epamail.epa.gov]

Sent: Tuesday, June 17, 2008 1:40 PM

To: DERF, MARK

Subject: Fw: Re: Fw: BART question
Appendix 10b - 2 

Hi Mark,

I'm out this week but am trying to keep up with emails.  I sent an email to Todd Hawes last week with your question.  Below is his

reply.  The BART guidelines may provide additional support.  I've retouched base with Todd regarding your latest email.

Randy

Randy Robinson

USEPA Region 5

312 353‐6713

‐‐‐‐‐Forwarded by Randall Robinson/R5/USEPA/US on 06/17/2008 12:39PM

To: Randall Robinson/R5/USEPA/US@EPA

From: Todd Hawes/RTP/USEPA/US

Date: 06/12/2008 12:20PM

Subject: Re: Fw: BART question

As I recall, the protocol recommended the methodology described below in Mark's email in order to be conservative.  That is

entirely up to  the state, so we would be fine with summing up the days.  In addition to the Q&A, the BART Guidelines do provide

some support for modeling multiple Class I areas (70 FR 39126, also see footnote 36).  The Q&A,  if I remember correctly, was

advising to look at ALL receptors modeled,  so if there are receptors on more than one Class I area, you would  throw out the highest

7 days from the entire universe of receptors.  Even if there is double counting, it is up to the state to determine if it wants to use that

level of conservatism.  We did not specify a position on double counting.  I hope this is helpful.

Randall Robinson/R5/USEPA/US

                                                                      

  ‐‐‐‐‐Forwarded by Randall Robinson/R5/USEPA/US on 06/11/2008 7:27PM

                                                             

To: Todd Hawes/RTP/USEPA/US

From: Randall Robinson/R5/USEPA/US@EPA

Date: 06/12/2008 12:20PM

Subject: Fw: BART question                         

Hello Todd,

I'm out of the office this week and next but wanted to get some information to Indiana.  I haven't looked at the guidance in a while  

but my recollection is the characterization they provide below is correct.   That is, you sum the days, for impacts at any Class I area.

Is that correct?  If so, I guess their approach would be conservative if they are doublecounting days.   Lastly, is there any other

guidance, beyond the Q and A to send to them.

Thanks for your help.

Randy

Randy Robinson

USEPA Region 5

312 353‐6713
Appendix 10b - 3 

 ‐‐‐‐‐Forwarded by Randall Robinson/R5/USEPA/US on 06/11/2008 05:22PM

To: Randall Robinson/R5/USEPA/US@EPA

From: "DERF, MARK" <MDERF@idem.IN.gov>

Date: 06/10/2008 12:05PM

Subject: BART question

Need a quick clarification for our BART modeling.  Using the MRPO BART  modeling protocol and determining the output from Kirk

Baker's  software, Indiana has determined whether sources are subject to BART by  adding the number of days for all the 16 Class 1

areas modeled for each  year and comparing the 98th percentile.  This approach has come under  scrutiny from one of our BART

sources.  They are viewing their results  in a slightly different way.  They are only looking at the nearest  Class 1 area and basing their

results on that area only.  For instance,  they have 6 days over 0.5 DV at Mammoth Cave and 3 days over 0.5 DV at  Mingo in 2003

but are only counting the 6 days at Mammoth Cave.  I  contacted them and said that I wanted additional information to show  the

days that the high days occurred at Mammoth and Mingo to determine  if there were 9 different days over 0.5 DV for both Class 1

areas which  would make them subject to BART or if there was double counting where  impacts were over 0.5 DV at both Class 1

areas for the same day.

We had emailed each other about a similar situation on Dec 15, 2005 and  Nov. 29, 2006.  Your December email provided a Q & A

Part 1 document  with reference to this question.  I wanted to provide this document to  the source (or updated guidance if

available).  As the guidance reads  in Question/Response #24, the highest modeled delta‐DV for each day  should be used for all

modeled receptors, regardless of location.  The  modeled receptors represent those in all the Class 1 areas.

Is this your understanding of the guidance?  I guess IN's approach is a  little conservative in that some days could be over 0.5 DV for

more  than one Class 1 area and we would count them more than once towards  the determination of subject to BART.  It looks like

if the source  considers the highest delta‐DV from all modeled receptors for each day,  that meets guidance for BART.

Let me know if you need me to explain better.    Thanks.

Mark Derf

Office of Air Quality

Indiana Department of Environmental Management Indianapolis, IN 46206

Phone: 317 233‐6870

Fax: 317 233‐2342

mderf@idem.in.gov
Appendix 10b - 4 

Minnesota’s Response                June 26, 2008

Mark

We have interpreted the federal regulation as each Class I Area.  Thus, the count starts over at each Class I area.  In your case, we

would have counted Class I area "A" as 6 and Class I area "B" as 3.  BWCA and VOYA (in Minnesota) are adjacent to one another and

we still interpreted it this way  (although the end‐result would not change were we to use your approach).  I've never before heard

of a State using a compilation of all receptors at all Class I areas to make a subject‐to‐BART determination, so this is a new concept

to me.   

Margaret

‐‐‐‐‐Original Message‐‐‐‐‐ 

From: DERF, MARK [mailto:MDERF@idem.IN.gov]

Sent: Thursday, June 19, 2008 1:28 PM

To: Abigail Fontaine; James G Haywood; Matthew Johnson; Michael A Majewski; Scott Leopold; McCourtney, Margaret;

dana.thompson@epa.state.oh.us; Sarah.Vanderwielen@epa.state.oh.us;

Carolina.Prado@epa.state.oh.us; david.brown@dnr.iowa.gov

Subject: BART question

Indiana has received three separate BART exemption modeling analysis. One source had conducted a more refined analysis at 4 km

using the VISTAS protocol.  The issue is the results showed that there were 6 days modeled over 0.5 DV at the nearest Class I area

and 3 additional days over 0.5 DV at the next closest Class I area.  Both areas are within 300 kms of the source.  The source is arguing

that since this is a refined analysis, the only results that matter are those at the most affected (closest) Class I area.  Indiana has

summed all modeled Class I receptors with impacts over 0.5 DV to make subject to BART determinations, based on Kirk's CALPOST

output files.  In that case, the source would have 9 days over 0.5 DV for one year.  The source says that it should only be 6 days over.

Randy Robinson and Todd Hawes have replied with references to 70 FR39126 and also footnote 36.  I haven't found any specific

citation in the BART modeling guidelines and Appendix Y that directly address this issue so I wanted to get other opinions or see if

anyone else had run up against this issue.  The source points out that in accepted modeling protocols in other states, there is

language that mentioned a given Class I area or the relevant Class I area.  I tend to think that for exemption modeling, if a source is

trying to demonstrate they are not subject to BART, the threshold should include all modeled receptors below the 98th percentile of

0.5 DV.

If anyone has any thoughts, I would appreciate it.  Thanks.

Mark Derf

Office of Air Quality

Indiana Department of Environmental Management

Indianapolis, IN 46206

Phone: 317 233‐6870

Fax: 317 233‐2342

mderf@idem.in.gov
Appendix 10b - 5 

Ohio’s Response                     June 23, 2008

Mark:                        

It has been Ohio's understanding, for at least the last couple of years, that what governs is the number of days above threshold at

any single Class I area. The aggregate of all the days at all the downwind Class I areas has nothing to do with anything. Two or three

years ago, Kirk provided an analysis that seemed to indicate the aggregate over multiple areas was, in fact, pertinent. To me, and I

think to Bill, that was a totally outlandish interpretation. After we got the question clarified and resolved, I'm sure we decided that

only the most‐impacted single area governs.

  ‐‐ Dana

>>> "DERF, MARK" <MDERF@idem.IN.gov> 6/19/2008 2:28 pm >>>

Indiana has received three separate BART exemption modeling analysis.

One source had conducted a more refined analysis at 4 km using the VISTAS protocol.  The issue is the results showed that there

were 6 days modeled over 0.5 DV at the nearest Class I area and 3 additional days over 0.5 DV at the next closest Class I area.  Both

areas are within 300 kms of the source.  The source is arguing that since this is a refined analysis, the only results that matter are

those at the most affected

(closest) Class I area.  Indiana has summed all modeled Class I receptors with impacts over 0.5 DV to make subject to BART

determinations, based on Kirk's CALPOST output files.  In that case, the source would have 9 days over 0.5 DV for one year.  The

source says that it should only be 6 days over.

Randy Robinson and Todd Hawes have replied with references to 70 FR

39126 and also footnote 36.  I haven't found any specific citation in the BART modeling guidelines and Appendix Y that directly

address this issue so I wanted to get other opinions or see if anyone else had run up against this issue.  The source points out that in

accepted modeling protocols in other states, there is language that mentioned a given Class I area or the relevant Class I area.  I tend

to think that for exemption modeling, if a source is trying to demonstrate they are not subject to BART, the threshold should include

all modeled receptors below the 98th percentile of 0.5 DV.

If anyone has any thoughts, I would appreciate it.  Thanks.

Mark Derf

Office of Air Quality

Indiana Department of Environmental Management Indianapolis, IN 46206

Phone: 317 233‐6870

Fax: 317 233‐2342

mderf@idem.in.gov
Appendix 10b - 6 

Michigan’s Response                   June 20, 2008

We get people trying to color outside the box, too, on BART issues.  We have little guidance to go on, so I'll be interested to hear

what you determine...

Jim Haywood

Senior Meteorologist

Michigan Department of Environmental Quality

Phone: (517) 241‐7478

Fax: (517) 335‐3122

E‐mail: HaywoodJ@michigan.gov

>>> "DERF, MARK" <MDERF@idem.IN.gov> 06/19/2008 2:28:17 PM >>>

Indiana has received three separate BART exemption modeling analysis.

One source had conducted a more refined analysis at 4 km using the VISTAS protocol.  The issue is the results showed that there

were 6 days modeled over 0.5 DV at the nearest Class I area and 3 additional days over 0.5 DV at the next closest Class I area.  Both

areas are within 300 kms of the source.  The source is arguing that since this is a refined analysis, the only results that matter are

those at the most affected

(closest) Class I area.  Indiana has summed all modeled Class I receptors with impacts over 0.5 DV to make subject to BART

determinations, based on Kirk's CALPOST output files.  In that case, the source would have 9 days over 0.5 DV for one year.  The

source says that it should only be 6 days over.

Randy Robinson and Todd Hawes have replied with references to 70 FR

39126 and also footnote 36.  I haven't found any specific citation in the BART modeling guidelines and Appendix Y that directly

address this issue so I wanted to get other opinions or see if anyone else had run up against this issue.  The source points out that in

accepted modeling protocols in other states, there is language that mentioned a given Class I area or the relevant Class I area.  I tend

to think that for exemption modeling, if a source is trying to demonstrate they are not subject to BART, the threshold should include

all modeled receptors below the 98th percentile of 0.5 DV.

If anyone has any thoughts, I would appreciate it.  Thanks.

Mark Derf

Office of Air Quality

Indiana Department of Environmental Management Indianapolis, IN 46206

Phone: 317 233‐6870

Fax: 317 233‐2342

mderf@idem.in.gov
Appendix 10b - 7 

Wisconsin’s Response                   June 19, 2008

Hi Mark...

Just a thought, are you basing your results on the CALPUFF 36 km runs? If the source is using the 4 km met data they get to compare

their results to the annual average and not the 20% "worst days" we have to use.

Mike

From: DERF, MARK [mailto:MDERF@idem.IN.gov]

Sent: Thu 6/19/2008 1:28 PM

To: Abigail Fontaine; James G Haywood; Matthew Johnson; Majewski, Michael A ‐ DNR; Scott Leopold; Margaret McCourtney;

dana.thompson@epa.state.oh.us; Sarah.Vanderwielen@epa.state.oh.us; Carolina.Prado@epa.state.oh.us;

david.brown@dnr.iowa.gov

Subject: BART question

Indiana has received three separate BART exemption modeling analysis. One source had conducted a more refined analysis at 4 km

using the VISTAS protocol.  The issue is the results showed that there were 6 days modeled over 0.5 DV at the nearest Class I area

and 3 additional days over 0.5 DV at the next closest Class I area.  Both areas are within 300 kms of the source.  The source is arguing

that since this is a refined analysis, the only results that matter are those at the most affected(closest) Class I area.  Indiana has

summed all modeled Class I receptors with impacts over 0.5 DV to make subject to BART determinations, based on Kirk's CALPOST

output files.  In that case, the source would have 9 days over 0.5 DV for one year.  The source says that it should only be 6 days over.

Randy Robinson and Todd Hawes have replied with references to 70 FR 39126 and also footnote 36.  I haven't found any specific

citation in the BART modeling guidelines and Appendix Y that directly address this issue so I wanted to get other opinions or see if

anyone else had run up against this issue.  The source points out that in accepted modeling protocols in other states, there is

language that mentioned a given Class I area or the relevant Class I area.  I tend to think that for exemption modeling, if a source is

trying to demonstrate they are not subject to BART, the threshold should include all modeled receptors below the 98th percentile of

0.5 DV.

If anyone has any thoughts, I would appreciate it.  Thanks.

Mark Derf

Office of Air Quality

Indiana Department of Environmental Management

Indianapolis, IN 46206

Phone: 317 233‐6870

Fax: 317 233‐2342

mderf@idem.in.gov