## Appendix 9 - IDEM Responses to Na tional Park Service Comments

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### Appendix 9 - 1 IDEM Responses to Nation al Park Service Comments

Chapter 2, Regional Planning

Comment:

IDEM has identified 19 Class I areas that ar e 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 Append ix 1 to Chapter 2 in the SIP a nd subsequent tables have been

renumbered as necessary.

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

Comment:

IDEM cites work of MRPO and othe r states but does not provide a ny information to illustrate the

baseline visibility conditions, the pollutant contri butions, 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 s hould 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 po llutant 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 northeaster n regions have been

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

information to illustrate the ba seline visibility conditions, the po llutant contributi ons, 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 met hods 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 Un it (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 (SO 2 

### ) and nitrogen oxides (NO

x 

### )

emissions for Indiana are lower in Scen ario 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 doe s not appear to be cited or discussed in the

text, yet this is the most important data for de monstrating Indiana’s emi ssion 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 variab ility 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 Docu ment" in Appendix 9b. In

addition, a more detailed discussion of the thr ee 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 incl ude the MRPO Technical Support Document in

an Appendix. A discussion of model performan ce is necessary to dem onstrate 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 em issions 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 se ctor? 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 contribu tion assessments from MRPO and other RPOs

and Appendix 2 for letters from st ates requesting consultation.

### Appendix 9 - 3 We agree that based on the contribution asse ssments 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 anth ropogenic sources of visibility impairment

considered in developing the long term strategy. IDEM has cited modeli ng 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 ma king reasonable progress in reducing anthropogenic

emissions. This demonstration should evalua te the monitoring, emissions inventory, and

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

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

the four factors for those major source categories. The MRPO provided a f our 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) divi ded 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 SO 2 

### +NO

x 

### = 10 for sources with emissions of SO 2 

### +NO

x 

### greater than 200

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

stationary sources within a few major source cat egories. 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 c ontribution assessments from MRPO and other

RPOs and Appendix 2 for letters from states re questing 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 pr esented 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 al l EGU in Indiana includi ng 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 scenario s and the best current information available

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

Section 8.4 BART Exemptions for Arcelor Mittal-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 diffe red 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 th e region. Because the visi bility impacts of the

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

IDEM updates the cited analytical methods to reflect the revisi ons, 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 discussi ons and data for Arcel orMittal 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 SO 2 

### and NO

x 

### reductions

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

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

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

scrubbers were installed on all boilers in 2008. For SO 2 

### , NSPS requires 90% control. IDEM

proposes to use SO 2 

### reductions for Boiler 1 to offset the difference between BART (92%

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

installed on Unit 1 as achieving sign ificantly higher reductions in SO 2 

### , 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 SO 2 

### emissions by 90%, Alcoa can take credit in the BART

Alternative for only the difference between th e 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 SO 2 

### and PM

emissions from BART sources (potlines) above cu rrent 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 vi sibility improvement equal to 0.46 dv and an

overall improvement in visibil ity equal to 75% over the baseli ne and achieves significantly

higher reductions in SO 2 

### , equal to approximately 21,600 tons. However, it is likely that the

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

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

Deterioration (PSD) regulations. In order to do so, Alcoa installed we t scrubbers to reduce SO 2 

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

offset NO X 

### 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 reducti ons 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 gui dance. It is also specified by the Lydia

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

Ozone, PM 2.5 

### 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 determinin g 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 ju stifying 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 (B oilers 2, 3, and 4), and five aluminum refining

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

industrial boilers. Boiler 4 is classifi ed as an Electric Generating Unit (EGU)

. Alcoa, in its

December analysis addressed PM, SO 2 

### , and NOx for all its BART-elig ible 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 SO 2 

### and NO X 

### requirements. The BART analysis will

therefore address PM only for this boiler.

### Appendix 9 - 6 Boilers 2, 3, and 4 are dry bottom, pulverized co al-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 NO X 

### burner (LNB) and overfire air

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

with a LNB in 1998 and a selec tive 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 contro lled with primary controls. Any uncaptured

emissions escape through the roof monitors at op 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 ar e several material handling operations at the

facility that meet the criteria for begi nning 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 pe rmit that meet the 1962-1977 timeline criteria but

were not included in the analysis . According to Alcoa, one of th ese 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 in cluded Mingo Wilderness Ar ea, Sipsey Wilderness

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

Cohutta Wilderness Area, and Shining Rock Wild erness 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. Ho wever, it proposes to control emissions from

Boiler 1 which is not a BART-eligible unit. For example, Alcoa determined SO 2 

### BART for

Boilers 2 and 3 as 92% reducti on, but it proposes to control SO 2 

### emissions from these boilers by

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

market study, it has determined th at 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, th e source proposes to control SO 2 

### 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 va lid to use reductions that are re quired by perm it to avoid PSD 1



### 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 SO 2 

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

difference between the required 90% reducti on 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 vi sibility improvement cited by IDEM were the

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

The only emission reductions attributab le to BART are due to the 91% SO 2 

### control on Boiler 1

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

SO 2 

### and PM emissions above current levels.

IDEM Response:

IDEM disagrees with the statement that "Alcoa/IDEM are proposing to increase SO 2 

### 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 altern atives 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 highe st 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 contribu tion 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 remova l efficiencies are 80–95%,” for SO 2 

### 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, NO X , and H 2 SO 4 to avoid PSD were part of the permit.

### Appendix 9 - 8 in the RBLC. 2 

### Presumptive BART for coal-fired boilers 3 

### is 95% SO 2 

### control or 0.15 lb/mmBtu,

neither of which was evaluated by Alcoa. BART for these boilers should be at least 95% SO 2



### control.

While the BART Guidelines allow special consid eration for existing scru bbers 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 ap ply 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 Generati ng Inc. (APGI) - Warrick Power Plant located

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

reduction and for the accompanying constructi on of material handling facilities and

modifications to the coal pulverizers and th e 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 mu st 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 wo uld 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 SO 2 emissions, seven

used wet scrubbing to control SO 2 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 SO 2 removal efficiency in the range of 90%

to 95% with an av erage of 91.8%.

Based on the RBLC database analysis, which indicated an average control efficiency of 91.8% was BACT for SO 2 from industrial boilers, and Standards of Performance for Industrial-Commercial-Institutional Steam Generating

Units (40 CFR 60 Subpart Db) requires a 92% removal efficien cy 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 presum ptive BART, it can be presum ed that the technology

assumed to achieve the presumptive limits for coal-fired E GUs 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 NO X 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 preco nstruction 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 BA RT analysis for Boilers 2 and 3. The BART

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

overall improvement in visibility degradation. The actual modifications pe rformed 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 emissi on 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/MMB tu. Baseline modeling without these controls

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

decrease to 0.064 dv with the above controls. Al coa 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 thes e 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 estimat ed at $70 million and $13 million. Additional

controls on these boilers are likel y 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 ra nge of 70–90%," it assumed 78% control in its

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

least 90% control.

Comment:

Alcoa did not perform a five-step BART anal ysis 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 signifi cantly tighter than NSPS limits (0.38 lb/MMBTu vs. 0.70

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

NOx controls, LNBs were found to be cost effec tive 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 furthe r evaluated as feasible alternatives for NOx removal.

4. Potlines

IDEM: The maximum impact from th ese sources is 0.231 d v. This includes c ontributions due to

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

Contributions due to other specie s 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 pe rform 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 cont ent 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 wi ll 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 facil ity that would complicate the

installation.

Comment:

Alcoa is proposing to increase SO 2 

### 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 propos ed 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 re sults 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 emissi on limit equal to 0.03 lb/MMBtu as BART

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

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

NOx control. Alcoa has noticed excessive conv ersion 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 w ith 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, Alco a 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 th e contribution from Bo ilers 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 impr ove visibility, it did

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

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

filter installed on a utility boiler. Alcoa estimates th at 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 BA RT analysis for PM for Boiler 4. (For example, Alcoa

should have investigated low- oxidation catalysts, fabric filt ration, 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 , th e installation cost on a $ / dv basis was shown to

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

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

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

the BART alone level from Boiler 4, and woul d 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 emi ssions 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 el ectrostatic precipitator s 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 hr s/yr.) X (1 ton/2000 lbs.) =

186.97 tons/yr.

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

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

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

boiler and pollution control equipment configura tions, 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 BA RT 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, f ilterable 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 co nsider such operating costs as increased

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

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

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

6. Ingot furnaces

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

impact from these sources, Alcoa did not perf orm a 5-step BART analysis for these sources.

### Appendix 9 - 14 Comment:

Conclusions & Recommendations

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

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

significantly higher reductions in SO 2 

### , equal to approximately 21,600 tons. While we recognize

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

New Source Review and NSPS requirements, we be lieve that the propos ed BART Alternative

improperly relies upon SO 2 

### emission reductions that are already required by NSPS.

Instead, it appears that Alco a is proposing to increase PM emissions from Boiler #4 and SO 2 

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

can at least be shown that th e additional reductions of SO 2 

### from Boiler #1—reductions beyond

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

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

proposed by Alcoa, then additi onal visibility improvements woul d be needed.) For example, it

may be necessary to model the following scenarios:

1. Baseline, BART-eligible units and Boiler #1@ 90% SO 2 

### control

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

### control

3. Alternative BART

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

BART would be acceptable.

IDEM Response:

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

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

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

from BART Eligible baseline to the BART contro l 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 woul d average nearly 2 deciview improvement.

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

Year Maximum Delta Bext 98 th Percentile Delta Bext Maximum Delta 98 th 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 Na tional Park – BART Control Level Emissions

Year Maximum Delta Bext 98 th Percentile Delta Bext Maximum Delta 98 th 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 Em issions and BART Control Level Emissions

Year Maximum Delta Bext 98 th Percentile Delta Bext Maximum Delta 98 th 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 Mamm oth Cave National Park – BART Eligible Baseline + Unit 1 Emissions

Year Maximum Delta Bext 98 th Percentile Delta Bext Maximum Delta 98 th 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 Na tional Park – Alternative to BART Emissions

Year Maximum Delta Bext 98 th Percentile Delta Bext Maximum Delta 98 th 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 98 th Percentile Delta Bext Maximum Delta 98 th 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 98 th Percentile Delta Bext Maximum Delta 98 th 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 98 th Percentile Delta Bext Maximum Delta 98 th 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 98 th Percentile Delta Bext Maximum Delta 98 th 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 discu ssion of the long term strategy. The Strategy

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

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

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

sources. The State has not discu ssed any controls or considerat ion of controls beyond those

required for other regulatory purposes. Table 6-7 Source and Speci e Contributions to 8 th 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 c onditions 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 requireme nts that apply to emissions from construction

sources and visibility. First, “rules to limit em issions 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, I ndiana's Article 6 Partic ulate Rules, Rule 6-4,

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

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

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

Significant Deterioration (PSD) Re quirements. The following sect ions 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 visibi lity impairment that interferes with the

management, protection, preservati on, or enjoyment of the visito r'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 natura l conditions that reduce visibility.

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

Sec. 14. (a) The department shall provide writte n 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 a pplication and at least sixty (60) days prior to any public hearing

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

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

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

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

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

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

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

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

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

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

related values, including visibility, of the Class I area and to consider, in consu ltation 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 anal ysis performed by the federal land manager,

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

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

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

analysis does not demonstrate to the satisfaction of the departme nt 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 ar ea 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 vi sibility, of a Class I area,

notwithstanding that the change in air quality re sulting 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 th e change in air quality resulti ng from emissions from the major

stationary source or major modification would cause or contribute to conc entrations that would

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

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

permit provided that the applicable requirements of this section ar e 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 shal l 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 subs ection (e) may demonstrate to th e department that the source

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

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

mandatory Class I areas, that an exemption under this subsection would no t adversely affect the

air quality related values of th e area, including visibility. The de partment, after consideration of

the federal land manager's recommendation, if a ny, 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 grante d, 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 reco mmends 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 is sue a permit pursuant to the requirements under

subsection (h) provided that the applicable requ irements 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 allowa ble increases are exceeded, cause or contribute

to concentrations that would exceed the fo llowing maximum allowable increases over the

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

concentrations that exceed the otherwise applicable maximum allo wable increases for periods of

exposure of twenty-four (24) hours or less for mo re 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 s ource or major modification and pr ovide notice to the U.S. EPA of

the following actions related to cons ideration of such permit under this

section:

(1) Receipt of an advanced no tification of a permit application affected by this section.

(2) Any written notice provide d to the federal land mana ger under this section.

(3) Public notice of a pr eliminary determination.

(4) Notices of public hearings.

(5) Decisions to grant or deny exempti ons 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 adve rse 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 Conditio ns, Pollutant Contributions, Needed

Visibility Improvement and Glide Path s 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 ar e 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 fo r 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, wi nter 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 vi sibility at Isle Royale in Michigan (as shown below in

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

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

Isle Royale, Seney and Boundary Waters, comprise s 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 Nati onal 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 app roximately 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 Wild erness, 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 approximat ely 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 a ll 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 Mammo th 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 ar eas. Indiana is shown to contribute le ss than 3 % light extinction at Boundary

Waters Canoe Area, MN and Seney Wilderness, MI and no ap preciable 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 Rou nd 5 PSAT analyses along with the CENRAP and MPCA PSAT

modeling results to show the state culpabilities on the north ern 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 model ed results less than 12% of total visibility impairment.

Emission reductions that are projected through future y ear 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 area s, 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 Clas s 1 Area using the Old a nd 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. T he 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 d egrees, 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, PM 2.5 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/report s/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/repo rts/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/re ports/rpo/consultation/produ cts/reasonable_progress_for_class_i_areas_in_the_norther

n_midwest

‐ factor_analysis_draft_final_technical_memo_july_18_2007.pdf

## Appendix 9b - LADCO Techni cal Support Document

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

Final Technical Support Document"

### This page intentionally left blank.

# Regional Air Quality Analyses for

Ozone, PM 2. 5 

# , and Regional Haze:

F inal Technical Support Document

April 25 , 2008

States of Illinois, Indiana, Michigan, Ohio, and Wisconsinii 

# Table of Contents

Section

- Title Pa ge

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 PM 2. 5 

### 2 1

2

. 3 Regional Haze 35

3

. 0 Air Quality Model ing 4 6

3

. 1 Selection of Base Year 46

3

. 2 Future Years of Interest 46

3

. 3 Modeling System 4 7

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 De monstration for Ozone and PM 2.5 

### 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 PM 2. 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 PM 2.5 

### Modeling Results

Appendix II Ozone Source Apportio nment Modeling Results

Appendix III PM 2.5 

### Source 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 Anal ysis Document (July 18, 2007)"

### This page intentionally left blank.

### Appendix 9c - 1 LADCO’s “Reasonable Progress for Class 1 Areas in t he Northern Midwest – Factor Analysis” (July 18,

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

conditions in mandatory Class 1 areas. While Indiana does not have any Class 1 area s 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 list ed 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 contribut ion 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 fo r 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 t he 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 t hermal 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 Pr ogress 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 estima ted 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 t he 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, Commerci al 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 construct ed 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 cons umed. 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 Midwes t – 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 contribut ion 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 t he 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 NO x controls for the 9-state region can be found in

Tables 5.2-7 and 5.2-8. The estima ted energy and non-air environmental im pact of ICI control strategies

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

Table 5.2-12.

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

area sources, however these improvements are an or der 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 t he Northern Midwest – Factor Analysis” (July 18, 2007)

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

Areas in the Northern Midwest – Factor Analysis”

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

2002 and projected to 2018 and are listed below in Tabl e 5. Indiana’s emission c ontribution to the 9-state

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

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

to drop to 8% of NOx emissions by 2018. Stati onary 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 t he 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 Area s in the Northern Midwest – Factor Analysis” document. Indiana’s

sources with emissions of 100 tons/year or more c ould 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 t he 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 t he 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 e ffectiveness 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 Pr ogress for Class 1 Areas in the Northern

Midwest – Factor Analysis”

Source apportionment modeling show that m obile sources contribute significantly to

visibility impairment in 2018 in the northern Midwest Cl ass I areas, despite projec ted NOX reductions from

on-the-books Federal and state-wide programs targeti ng 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 pot ential 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 t he above mobile emission control stra tegies for the 9-state region will

average less than 2% for 2012 emission projection s 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 im pacted from each of the s ource 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 sour ces. 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, Michig an, Minnesota, Wisconsin, Illinois, Iowa, Missouri,

North Dakota and South Dakota.

### Appendix 9c - 7 Table A-1.1 “Reasonable Progress for Class 1 Areas in t he 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 t he 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 t he 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/re ports/rpo/consultation/produ cts/reasonable_progress_for_class_i_areas_in_the_norther

n_midwest

‐ factor_analysis_draft_final_technical_memo_july_18_2007.pdf

## Appendix 9d - Discus sions and Data for

ArcelorMittal Burns Harbor , ESSROC - Speed and SABIC CALPUFF Results

using Bondville Ammonia Mo nitoring 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 lig ht extinction – while this is generally

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

would be expected by this change alone. Mo st 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. Burn s 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, 20 08 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. Bu rns 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 de termine the impact of the new IMPROVE

equation on light extinction compared with th e 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 nephelo meters. Modeled results on th e 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 su mmary 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 measu red 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 inst ead 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 ob servational data. The more refined VISTAS 6

kilometer CALMET data used by Burns Harbor incl uded observational data and therefore, use of

the average annual background concentr ations 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 m ay 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 CA LPUFF modeling for the MRPO states.

In response to this comment, IDEM conducted additional CALPUFF runs, using Bondville

ammonia data collected from November 2003 throug h 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 Concen trations (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 m odeling results using the MRPO background

ammonia concentrations and the 2003 – 2005 Bond ville data showed only slight increases in

overall light extinction and the delta deciview cha nges. 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 no t 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 m odeled sixteen Class 1 areas and determined the

highest visibility impacts from Burns Harbor o ccurred 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 Har bor 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 gr id warranted the use of the average natural

background concentrations for Cl ass I areas in the eastern Unit ed 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 an alysis 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 equation s 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 th e IDEM review document submitted for review in

May of 2009. Burns Harbor explained that wh ether allocating the total background as soils or

speciated components of ammonia sulfate, amm onia nitrate, organic carbon, elemental carbon

and coarse mass, the resulting background extinc tion 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/MW RPO 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 improve ments gained by using a smaller grid. The

improvements appear to be limited to the a ddition 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). Th e 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 PM 10 

### emissions to be

modeled. However, IDEM’s review of ESSROC Speed’s modeling included PM 10 

### emissions

which ESSROC-Speed provided estimates. IDEM’s CALPUFF results showed NOx, SO 2 

### and

PM 10 

### 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 orde r 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 o ccurred 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 a nnual 2002 CAMx simulations.

IDEM has conducted further CALPUFF runs, us ing 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 Concen trations (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 mo deling results using the MRPO background

ammonia concentrations and the 2003 – 2005 Bond ville 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 thres hold 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 a nd 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 comp are 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 inst ead 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 a nd 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 st ates when using the MRPO 36 kilometer grid

CALMET without meteorological station observational data. The VISTAS’s 4 kilometer

CALMET data used by SABIC included observationa l 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 a ll 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 a nnual 2002 CAMx simulations.

IDEM has conducted further CALPUFF runs, us ing 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 Concentrat ions (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 re sults 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. Th e largest light extinction change was 0.17% and

the largest deciviews change was 0.016 dv at Sips ey 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 Harb orCALPUFF 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 CALPU FF Results using Bondville Ammonia

Monitoring Results 2003-2005

### Appendix 9d - 11 CALPUFF Results for ESSROC - Speed - Comparing A mmonia 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 CA LPUFF 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 This page intentionally left blank.

## Appendix 9e - Alcoa Responses to National Parks Service Comments1 

### This page intentionally left blank.

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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 of Data 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 (CA TR) 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 of Alcoa 

### Inc., and is not sold on the grid. Unit 

### 4 is jointly 

### Ulivned by 

### APGl and

Vecll'en. 50% 

### of the 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** 

### of state budget to be allocated, 

### APGl does have

# FEE/D D11 p, 

# DD3

concerns with the overall CA TR 

### 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 CA 1R. 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 of the 

### 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 of the NAAQS process designed by

Congress and immediately impose its program for a State1s achievement of the NAAQS,

. unless and until a State hus failed to develop and obtain approval of its 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.

# ~/**(t)~** / anme1 

### H. Bruntz

Senior Staff Environmental Engineer

Alcoa 

## Inc.

- Wsnick Operations

Alcoa Power Genetating 

### Inc.

- WalTick Power Plant



### (812)**853~1519**

## Appendix 10 - IDEM Re sponses to US Fore st Service Comments

### This page intentionally left blank.

### Appendix 10 - 1 IDEM Responses to US Forest Service Comments

Our interest in the Indiana Regi onal Haze SIP is due to the fact that sources in your State cause

or contribute to visibility impairment in many of our Class I Wilderne ss areas including the

Boundary Waters Canoe Area Wilderness in Minne sota, Hercules Glades Wilderness Area in

Missouri, Sipsey Wilderness Area in Alabama, Caney Creek Wilderness Area and Upper Buffalo

Wilderness Area in Arkansas, Great Gulf W ilderness 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 ac hieved and exceeded at all MANE-VU Class I

sites” from “Recent MANE-VU Projections of Visi bility for 2018.” Do these projections include

the latest predictions in emissions from Indian a sources? It appears that with some sources

modeling out of being subject-t o-BART the 2018 emissions from Indiana may be greater than

what was predicted by MANE-VU in 2008. The po ssibility that the RPOs assumed greater

emission reductions in their Class I area anal ysis (Section 7.0) are hi ghlighted 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 I ndiana 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 I ndiana coal fired units listed in Table 10 to

demonstrate the size of these units. This tabl e highlights the BART-eligible units and notes

which units were included in the MANEVU “as k” list, described in Section 7.9. IDEM has

added a more detailed description of the data pr esented 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 enforceab ility of these controls has been added. In

addition, two tables in Appendix 10a show a comp arison between IDEM's pr ojected controls and

EPA and LADCO's modeling scenarios for SO 2 

### and NO

x 

### controls.

Cumulative Haze impacts

On page 49 – Table 15 - it appears that when cons idered cumulatively (the sum of modeled days

over the 0.5 dv threshold for all the Class I area s 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 Ar celorMittal Burns Harbor subject to BART.

IDEM Response:

IDEM appreciates the USFS's comment and posit ion on this issue. However, a consistence

approach is preferred. Repres entatives from EPA Region 5, the EPA Headquarters and the states

of Ohio, Michigan, Wisconsin and Minnesota fa vor the approach of summing up days for each

### Appendix 10 - 2 individual Class 1 area instead of counting a ll modeled receptors at all the Class 1 areas

modeled. A summary of responses from thes e 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 highes t actual emissions when there is a significant

difference for facilities not subject to BART.

Page 53 – Table 18 is an example of our concer n 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 act ual” emission rates are significantly lower than

the “potential” emission rates and the lower rates are used as justificati on to avoid subject to

BART designation, the lower rates need to be in corporated into a federally enforceable permit

condition. The NO

x 

### emissions for the highest emitting day and potential emissions in Table 18

are similar but the SO 2 

### differences are significant. Reduction in permitted, potential emissions to

the actual highest emissions would ensure th at the facility’s (ESSROC) emissions remain

consistent with the “not subject to BART” determ ination. 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 posit ion 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 requ est from SABIC to remove the oil burning

provisions from its Part 70 Operating Permit. Th e 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-subje ct-to-BART unit, could be achieved through

Reasonable Progress as part of the Regional Haze Rule, and as such are not n ecessarily 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 reducti ons 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 gui dance. It is also specified by the Lydia

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

Ozone, PM 2.5 

### 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 determinin g 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 da te of the SIP.’ The baseline date for regional haze SIPs is

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

other purposes, to substitute for BART. Therefor e, 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 SO 2 

### controls on Boilers 2 and 3 cannot achieve 92 percent

or greater efficiency with wet FGD. Please expl ain 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 wa s to control Boiler 1 at 91% and Boiler 2 and 3 at 90%, which

still results in an overall improvement in visi bility degradation. The actual modifications

performed to the boilers were not extensive enough to trigger th e 92% removal efficiency level

requirements, as required in the re-construction crit eria 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 inform ation about the need to use higher sulfur coke

is needed. An analysis including cost compar isons 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 contributo rs, at approximately 0.188 dv. Cont ributions due to other species

are less than 0.01 dv. Therefore, any add-on cont rols 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 thes e sources. Further, thes e sources are subject to

40 CFR 63, Subpart LL, Maximu m 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 a node 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 SO 2 

### 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 limitation s at the facility that would complicate the

installation.

Comment:

A five factor analysis is needed for the Alcoa fa cility to accurately determine if SNCR or SCR

technology for NO

x 

### control is feasible. Stating the cost s and the assumption that these controls

would not be cost effective wit hout information, or data, to s upport 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 signifi cantly 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 , th e installation cost on a $ / dv basis was shown to

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

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

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

the BART alone level from Boiler 4, and woul d 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 emi ssions 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 el ectrostatic precipitator s 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 hr s/yr.) X (1 ton/2000 lbs.) =

186.97 tons/yr.

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

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

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

boiler and pollution control equipment configura tions, 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 BA RT 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, f ilterable 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 co nsider such operating costs as increased

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

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

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

### Appendix 10 - 7 Long-term Strategy

Comment:

Necessary smoke management regulations and techniques for prescrib ed burning on National

Forest land appear to be cove red 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 w ith the State to help develop

this SMP in the future.

We request that Indiana provi de language in your SIP linki ng the Regional Haze and New

Source Review programs, includi ng continued FLM coordination fo r 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 progre ss toward the national

visibility goal (40 CFR 51.307). This could be especially important fo r emissions from new

sources that were not anticipa ted in 2018 emission inventories. Please describe how new and

expanded sources of air emissions will be review ed 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 Park s Service Comments in Appendix A for IDEMs

response regarding the Long Term Strategy comm ent 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 majo r modifications of existing sources will make

reasonable progress toward the na tional visibility goal (40 CFR 51.307).

### Appendix 10 - 8 This page intentionally left blank.

### Appendix 10 - 9 

## Appendix 10 - IDEM Respon ses to US Forest Serv ice 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 th e 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 partic ipation 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 pers pective of a Federal Land Manager. I look forward

to your response required by 40 CF R 51.308(i)(3). For further infor mation, 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 - SO 2 

## and NOx Credits for Projected

Best Available Retrofit Technology

### This page intentionally left blank.SO2CREDITS FOR PROJECTED BEST AVAILABLE RETROFIT TECHNOLOGYFACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedSO2_CONTROLSO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2A B Brown GeneratingStation1 250 Dual Alkali FGD SCR+FGD250 250250 250250 250250 250250 250250 250A B Brown GeneratingStation2 250 Dual Alkali FGD SCR+FGD250 250250 250250 250250 250250 250250 250Alcoa AllowanceManagement Inc1 144Wet Limestone FGD(2008)LNB w/SOFA144144144144144144Alcoa AllowanceManagement Inc2 144Wet Limestone FGD(2008)LNB w/SOFA144144144144144144Alcoa AllowanceManagement Inc3 144Wet Limestone FGD(2008)LNB w/SOFA144144144144144144Alcoa AllowanceManagement Inc4 300Wet Limestone FGD(2008)SCR300300FGD300 300 FGD300 300 FGD300 300 FGD300 300Bailly GeneratingStation7 160 Wet Limestone SCR+FGD160 160160 160160 160160 160160 160160 160BaillyGeneratingStation8 320 Wet Limestone SCR+FGD320 320320 320320 320320 320320 320320 320Cayuga*1 500Wet Limestone (2008 -95%)FGD+LNBw/SOFA 500 500 500 500 SCR 500 500 SCR 500 500 SCR 500 500 SCR 500 500Cayuga*2 495Wet Limestone (2008 -95%)FGD+LNBw/SOFA 495 495 495 495 SCR 495 495 SCR 495 495 SCR 495 495 SCR 495 495Clifty Creek*1 217(FGD Scheduled after2014) FGD+SCR 217 217 217 217 217 217 217Clifty Creek*2 217(FGD Scheduled after2014) FGD+SCR 217 217 217 217 217 217 217Clifty Creek*3 217(FGD Scheduled after2014) FGD+SCR 217 217 217 217 217 217 217Clifty Creek*4 217(FGD Scheduled after2014) FGD+SCR 217 217 217 217 217 217 217Clifty Creek*5 217(FGD Scheduled after2014) FGD+SCR 217 217 217 217 217 217 217Clifty Creek*6 217(FGD Scheduled after2014) FGD 217 SCR 217 SCR 217 217 SCR 217 217 SCR SCR 217Dean H MitchellGenerating Station11 125 Shut Down LNB 125 125 125 125 125 125Dean H MitchellGenerating Station4 125 Shut DownComb.Optimization125125125SCR125 125SCR125Dean H MitchellGenerating Station5 125 Shut DownComb.Optimization125125125SCR125 125SCR125Dean H MitchellGenerating Station6 110 Shut DownLNB110110110SCR110 110SCR110Edwardsport7-1 40Unit will retire in 2012,IGCC will replace allthe units in 2012RetireRetireRetireRetireRetireLADCO Round 5 Runs2009 + Projected Compared to IPMExistingSO2INDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015LADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitIDEMCredit forControl(s) inMWeEPA IPM 3.0 2006 runs2009 + Projected Compared to IPM2020 Retrofit2009 + Projected Compared to LADCO2012 RetrofitLADCO 2012RetrofitIDEMCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 RetrofitIPM 2010Retrofit2009 + Projected Compared toLADCO 2018 RetrofitIPM 2015RetrofitIDEMCredit forControl(s) inMWeBART-eligible Units*MANEVU AskIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeLADCO2018RetrofitIDEMCredit forControl(s) inMWeFACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedSO2_CONTROLSO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2LADCO Round 5 Runs2009 + Projected Compared to IPMExistingSO2INDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015LADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitIDEMCredit forControl(s) inMWeEPA IPM 3.0 2006 runs2009 + Projected Compared to IPM2020 Retrofit2009 + Projected Compared to LADCO2012 RetrofitLADCO 2012RetrofitIDEMCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 RetrofitIPM 2010Retrofit2009 + Projected Compared toLADCO 2018 RetrofitIPM 2015RetrofitIDEMCredit forControl(s) inMWeBART-eligible Units*MANEVU AskIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeLADCO2018RetrofitIDEMCredit forControl(s) inMWeEdwardsport7-2 40Unit will retire in 2012,IGCC will replace allthe units in 2012 Retire Retire Retire Retire RetireEdwardsport8-1 40Unit will retire in 2012,IGCC will replace allthe units in 2012 Retire Retire Retire Retire RetireF B Culley GeneratingStation2 90 Wet Limestone FGD+LNB 90 90 90 90 90 90 SNCR 90 90 90 90 SNCR 90 90F B Culley GeneratingStation3 270 Wet Limestone FGD+SCR 270 270 270 270 270 270 270 270 270 270 270 270Frank E Ratts1SG1 122U.S. EPA settlement,plant-wide from 2009levels 42% reduction -2012, 58% - 2014 LNB122 SCR 122 122 SCR 122Frank E Ratts2SG1 121U.S. EPA settlement,plant-wide from 2009levels 42% reduction -2012, 58% - 2014 LNBSCRSCRGibson*1 630 Wet Limestone SCR+FGD630 630630 630630 630630 630630 630630 630Gibson*2 630 Wet Limestone SCR+FGD630 630630 630630 630630 630630 630630 630Gibson*3 630 Wet Limestone SCR+FGD630 630630 630630 630630 630630 630630 630Gibson*4 622 Wet Limestone SCR+FGD622 622622 622622 622622 622622 622622 622Gibson5 620 Wet Limestone SCR+FGD620 620620 620620 620620 620620 620620 620Harding Street Station(EW Stout)50 109SNCRHarding Street Station(EW Stout)60 109SNCRHarding Street Station(EW Stout)*70 435 Wet Limestone SCR435FGD435 435 FGD435 435 FGD435 435 FGD435 435 FGD435 435IPL Eagle ValleyGenerating Station3 43FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedSO2_CONTROLSO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2LADCO Round 5 Runs2009 + Projected Compared to IPMExistingSO2INDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015LADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitIDEMCredit forControl(s) inMWeEPA IPM 3.0 2006 runs2009 + Projected Compared to IPM2020 Retrofit2009 + Projected Compared to LADCO2012 RetrofitLADCO 2012RetrofitIDEMCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 RetrofitIPM 2010Retrofit2009 + Projected Compared toLADCO 2018 RetrofitIPM 2015RetrofitIDEMCredit forControl(s) inMWeBART-eligible Units*MANEVU AskIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeLADCO2018RetrofitIDEMCredit forControl(s) inMWeIPL Eagle ValleyGenerating Station4 56LNB w/SOFAIPL Eagle ValleyGenerating Station5 62LNB w/SOFAIPL Eagle ValleyGenerating Station6 99LNB w/SOFAMerom1SG1 507upgrade FGD-90%2012, upgrade to 95%2014SCR+FGD507 507507 507507 507507 507507 507507 507Merom2SG1 493upgrade FGD-90%2012, upgrade to 95%2014SCR+FGD493 493493 493493 493493 493493 493493 493Michigan CityGenerating Station12 469SCRHg ControlHg ControlPetersburg1 232 Wet Limestone FGD+LNB232 232232 232232 232 SCR232 232232 232 SCR232 232Petersburg2 407 Wet Limestone FGD+SCR407 407407 407407 407407 407407 407407 407Petersburg3 510 Wet Limestone FGD+SCR510 510510 510510 510510 510510 510510 510Petersburg4 545 Wet Limestone FGD+LNB545 545545 545 SCR545 545 SCR545 545545 545 SCR545 545R Gallagher*1 140Shut down by 2/1/12 orConvert to NG 1/1/13 LNB140140140140R Gallagher*2 140Dry Sorbent Technology1/1/11LNB140140140140R Gallagher*3 140Shut down by 2/1/12 orConvert to NG 1/1/13 LNB140140140140R Gallagher*4 140Dry Sorbent Technology1/1/11LNBR M SchahferGenerating Station14 431SCR431Hg Control 431Hg Control 431R M SchahferGenerating Station15 472LNBHg Control 472Hg Control 472FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedSO2_CONTROLSO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2LADCO Round 5 Runs2009 + Projected Compared to IPMExistingSO2INDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015LADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitIDEMCredit forControl(s) inMWeEPA IPM 3.0 2006 runs2009 + Projected Compared to IPM2020 Retrofit2009 + Projected Compared to LADCO2012 RetrofitLADCO 2012RetrofitIDEMCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 RetrofitIPM 2010Retrofit2009 + Projected Compared toLADCO 2018 RetrofitIPM 2015RetrofitIDEMCredit forControl(s) inMWeBART-eligible Units*MANEVU AskIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeLADCO2018RetrofitIDEMCredit forControl(s) inMWeR M SchahferGenerating Station17 361Wet LimestoneSCR361FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361361361R M SchahferGenerating Station18 361Wet LimestoneLNB361FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361361361Rockport*MB1 1300FGD 12/31/17 TRallowances < CAIR2012 and 2014 LNB w/OFAFGD1300 FGD1300 FGD+SCR 1300 1300 FGD1300 FGD+SCR 1300 1300Rockport*MB2 1300FGD 12/31/17 TRallowances < CAIR2012 and 2014 LNB w/OFAFGD1300 FGD1300 FGD+SCR 1300 1300 FGD1300 FGD+SCR 1300 1300State Line GeneratingStation (IN)3 187State Line GeneratingStation (IN)4 303SCRSCRSCR+HgControlSCRSCR (-HgControl)Tanners Creek*U1 140Burn only coal with nomore than 1.2lb/MMBtu annualaverageOFATanners Creek*U2 140Burn only coal with nomore than 1.2lb/MMBtu annualaverageOFATanners Creek*U3 200Burn only coal with nomore than 1.2lb/MMBtu annualaverageOFAFGD+SCR 140FGD+SCR 140Tanners Creek*U4 500Burn only coal with nomore than 1.2% sulfurcontent annual average OFAWabash River GenStation*1 85 IGCCWabash River GenStation*2 85 Shut Down 9-30-09 LNB8585Wabash River GenStation*3 85 Shut Down 9-30-09 LNB8585SNCRSNCRWabash River GenStation*4 85LNBWabash River GenStation*5 95 Shut Down 9-30-09 LNB9595SNCRSNCRWabash River GenStation*6 318TR allocation in 2014 <CAIRLNBFGD+SCR318FGD+SCR318FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedSO2_CONTROLSO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2SO2LADCO Round 5 Runs2009 + Projected Compared to IPMExistingSO2INDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015LADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitIDEMCredit forControl(s) inMWeEPA IPM 3.0 2006 runs2009 + Projected Compared to IPM2020 Retrofit2009 + Projected Compared to LADCO2012 RetrofitLADCO 2012RetrofitIDEMCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 RetrofitIPM 2010Retrofit2009 + Projected Compared toLADCO 2018 RetrofitIPM 2015RetrofitIDEMCredit forControl(s) inMWeBART-eligible Units*MANEVU AskIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeLADCO2018RetrofitIDEMCredit forControl(s) inMWeWhitewater Valley1 34.77LNBWhitewater Valley2 62.8 OtherLNB10,800 9,46310,800 13,22012,810 13,52015,882 13,97811,077 11,49615,882 11,954

IDEM Base Case EPA Basecase IDEM 2010 IDEM 2018 LADCO 2018

IDEM 2020 EPA 2020 IDEM 2012 LADCO 2012

EPA 2010 IDEM 2015 EPA 2015NOXCREDITS FOR PROJECTED BEST AVAILABLE RETROFIT TECHNOLOGYFACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedNOx_CONTROLNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxA B Brown GeneratingStation1 250Selective CatalyticReductionSCR+FGD250 250250 250250 250250 250250 250250 250A B Brown GeneratingStation2 250Selective CatalyticReductionSCR+FGD250 250250 250250 250250 250250 250250 250Alcoa AllowanceManagement Inc1 144Low NOxBurnerTechnology w/Overfire Air LNB w/SOFA 144 144144 144144 144144 144144 144144 144Alcoa AllowanceManagement Inc2 144Low NOxBurnerTechnology w/Overfire Air LNB w/SOFA 144 144144 144144 144144 144144 144144 144Alcoa AllowanceManagement Inc3 144Low NOxBurnerTechnology w/Overfire Air LNB w/SOFA 144 144144 144144 144144 144144 144144 144Alcoa AllowanceManagement Inc4 300Low NOxBurnerSelective CatalyticReductionSCR300 300300 300 FGD300 300 FGD300 300 FGD300 300 FGD300 300Bailly GeneratingStation7 160Overfire Air / SelectiveCatalytic Reduction(2008)SCR+FGD160 160160 160160 160160 160160 160160 160BaillyGeneratingStation8 320Overfire Air / SelectiveCatalytic Reduction SCR+FGD320 320320 320320 320320 320320 320320 320Cayuga*1 500Low NOxBurnerTechnology w/Separated OFAFGD+LNBw/SOFASCR500 SCR500 SCR500 SCR500Cayuga*2 495Low NOxBurnerTechnology w/Separated OFAFGD+LNBw/SOFASCR495 SCR495 SCR495 SCR495Clifty Creek*1 217Overfire Air SelectiveCatalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 217 217 217Clifty Creek*2 217Overfire Air SelectiveCatalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 217 217 217Clifty Creek*3 217Overfire Air SelectiveCatalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 217 217 217Clifty Creek*4 217Overfire Air SelectiveCatalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 217 217 217Clifty Creek*5 217Overfire Air SelectiveCatalytic Reduction FGD+SCR 217 217 217 217 217 217 217 217 217 217 217 217Clifty Creek*6 217 Overfire Air FGDSCR217 SCR217 SCR217 SCR217 SCR217Dean H MitchellGenerating Station11 125 Shut DownLNB125125125125125125Dean H MitchellGenerating Station4 125 Shut DownComb.Optimization125125125SCR125 125SCR125Dean H MitchellGenerating Station5 125 Shut DownComb.Optimization 125 125 125SCR125 125SCR125Dean H MitchellGenerating Station6 110 Shut Down LNB 110 110 110SCR110 110SCR110Edwardsport7-1 402012, IGCC willreplace all the units in2012 Retire Retire Retire Retire RetireIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeBART-eligible Units*MANEVU AskNOxLADCO2012RetrofitIDEMCredit forControl(s) inMWeINDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015EPA CreditforControl(s) inMWeEPA IPM 3.0 2006 runsIPM 2010RetrofitIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 Retrofit2009 + Projected Compared to IPMExistingIPM 2015RetrofitIDEMCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared to IPM2020 RetrofitLADCOCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared toLADCO 2018 RetrofitLADCO Round 5 RunsLADCO2018Retrofit2009 + Projected Compared toLADCO 2012 RetrofitFACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedNOx_CONTROLNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeBART-eligible Units*MANEVU AskNOxLADCO2012RetrofitIDEMCredit forControl(s) inMWeINDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015EPA CreditforControl(s) inMWeEPA IPM 3.0 2006 runsIPM 2010RetrofitIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 Retrofit2009 + Projected Compared to IPMExistingIPM 2015RetrofitIDEMCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared to IPM2020 RetrofitLADCOCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared toLADCO 2018 RetrofitLADCO Round 5 RunsLADCO2018Retrofit2009 + Projected Compared toLADCO 2012 RetrofitEdwardsport7-2 402012, IGCC willreplace all the units in2012 Retire Retire Retire Retire RetireEdwardsport8-1 402012, IGCC willreplace all the units in2012 Retire Retire Retire Retire RetireF B Culley GeneratingStation2 90Low NOxBurnerTechnology (DryBottom only) FGD+LNB90 9090 9090 90 SNCR909090 90 SNCR90 90F B Culley GeneratingStation3 270Low NOxBurnerTechnology (DryBottom only) SelectiveCatalytic Reduction FGD+SCR270 270270 270270 270270 270270 270270 270Frank E Ratts1SG1 122Low NOxBurnerTechnology (DryBottom only) OFA2008LNB122SCR122 122122SCR122 122Frank E Ratts2SG1 121Low NOxBurnerTechnology (DryBottom only) OFA2008LNBSCR121SCR121Gibson*1 630LNB w/ Overfire AirSelective CatalyticReductionSCR+FGD630 630630 630630 630630 630630 630630 630Gibson*2 630Low NOxBurnerTechnology w/Overfire Air SelectiveCatalytic Reduction SCR+FGD630 630630 630630 630630 630630 630630 630Gibson*3 630Low NOxBurnerTechnology w/Overfire Air SelectiveCatalytic Reduction SCR+FGD630 630630 630630 630630 630630 630630 630Gibson*4 622Low NOxBurnerTechnology w/Overfire Air SelectiveCatalytic Reduction SCR+FGD622 622622 622622 622622 622622 622622 622Gibson5 620Low NOxBurnerTechnology w/Overfire Air SelectiveCatalytic Reduction SCR+FGD620 620620 620620 620620 620620 620620 620Harding Street Station(EW Stout)50 109LNB w/ SeparatedOFA Selective Noncatalytic ReductionSNCR109 109109 109109 109109 109109 109109 109Harding Street Station(EW Stout)60 109LNB w/ SeparatedOFA Selective Noncatalytic ReductionSNCR109 109109 109109 109109 109109 109109 109Harding Street Station(EW Stout)*70 435LNB w/ Closedcoupled/SeparatedOFA SelectiveCatalytic Reduction SCR435 435 FGD435 435 FGD435 435 FGD435 435 FGD435 435 FGD435 435IPL Eagle ValleyGenerating Station3 43FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedNOx_CONTROLNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeBART-eligible Units*MANEVU AskNOxLADCO2012RetrofitIDEMCredit forControl(s) inMWeINDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015EPA CreditforControl(s) inMWeEPA IPM 3.0 2006 runsIPM 2010RetrofitIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 Retrofit2009 + Projected Compared to IPMExistingIPM 2015RetrofitIDEMCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared to IPM2020 RetrofitLADCOCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared toLADCO 2018 RetrofitLADCO Round 5 RunsLADCO2018Retrofit2009 + Projected Compared toLADCO 2012 RetrofitIPL Eagle ValleyGenerating Station4 56Low NOx BurnerTechnology w/Separated OFA LNB w/SOFA56 5656 5656 56565656 5656 56IPL Eagle ValleyGenerating Station5 62Low NOx BurnerTechnology w/Separated OFA LNB w/SOFA62 6262 6262 62626262 6262 62IPL Eagle ValleyGenerating Station6 99Low NOx BurnerTechnology w/Separated OFA LNB w/SOFA99 9999 9999 99999999 9999 99Merom1SG1 507Selective CatalyticReduction Low NoxBurner Technology w/Overfire Air SCR+FGD507 507507 507507 507507 507507 507507 507Merom2SG1 493Selective CatalyticReduction Low NOxBurner Technology w/Overfire Air493493493493493493Michigan CityGenerating Station12 469Selective CatalyticReductionSCR469 469469 469469 469 Hg Control 469 469469 469 Hg Control 469 469Petersburg1 232Low NOxBurnerTechnology w/ Closedcoupled/Sep. OFA FGD+LNBSCR232SCR232Petersburg2 407LNB w/ Closedcoupled/SeparatedOFA SelectiveCatalytic Reduction FGD+SCR407 407407 407407 407407 407407 407407 407Petersburg3 510LNB w/ Closedcoupled/SeparatedOFA SelectiveCatalytic Reduction FGD+SCR510 510510 510510 510510 510510 510510 510Petersburg4 545Low NOxBurnerTechnology w/ Closedcoupled/Sep. OFA FGD+LNBSCR545 SCR545SCR545R Gallagher*1 140Shut down by 2/1/12or Convert to NG1/1/13LNB140 140140 140140140140140R Gallagher*2 140Low NOxBurnerTechnology w/Overfire Air LNB140 140140 140140 140140 140140 140140 140R Gallagher*3 140Shut down by 2/1/12or Convert to NG1/1/13LNB140 140140 140140140140140R Gallagher*4 140Low NOxBurnerTechnology w/Overfire Air LNB140 140140 140140 140140 140140 140140 140R M SchahferGenerating Station14 431Overfire Air SelectiveCatalytic Reduction SCR431 431431 431431 431 Hg Control 431 431431 431 Hg Control 431 431R M SchahferGenerating Station15 472LNB (Dry Bottomonly) A 35% efficientstratified overfire airsystem was added in2008LNB472 472472 472472Hg Control 472472Hg Control 472FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedNOx_CONTROLNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeBART-eligible Units*MANEVU AskNOxLADCO2012RetrofitIDEMCredit forControl(s) inMWeINDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015EPA CreditforControl(s) inMWeEPA IPM 3.0 2006 runsIPM 2010RetrofitIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 Retrofit2009 + Projected Compared to IPMExistingIPM 2015RetrofitIDEMCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared to IPM2020 RetrofitLADCOCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared toLADCO 2018 RetrofitLADCO Round 5 RunsLADCO2018Retrofit2009 + Projected Compared toLADCO 2012 RetrofitR M SchahferGenerating Station17 361LNB w/ Closedcoupled/SeparatedOFASCR361 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361361 361361 361R M SchahferGenerating Station18 361LNB w/ Closedcoupled/SeparatedOFALNB361 361 FGD+LNB 361 361 FGD+LNB 361 361 FGD+LNB 361 361361 361361 361Rockport*MB1 1300LNB (Dry Bottomonly) (SCR 12/31/17) LNB w/OFAFGDFGDFGD+SCR 1300 1300 FGDFGD+SCR 1300 1300Rockport*MB2 1300Technology (DryBottom only) (SCR12/31/19)LNB w/OFAFGDFGDFGD+SCR 1300 1300 FGDFGD+SCR 1300 1300State Line GeneratingStation (IN)3 187State Line GeneratingStation (IN)4 303 Overfire Air303SCR303SCR303SCR+HgControl303SCR303SCR (-HgControl)303Tanners Creek*U1 140Low NOxBurnerTechnology (DryBottom only) A 30%efficient SNCR will bein place in 2010.SNCR will operateyear roundOFA140140140140140140Tanners Creek*U2 140Low NOxBurnerTechnology (DryBottom only) A 30%efficient SNCR will bein place in 2010.SNCR will operateyear roundOFATanners Creek*U3 200Low NOxBurnerTechnology (DryBottom only) A 30%efficient SNCR will bein place in 2010.SNCR will operateyear roundOFA140140140FGD+SCR 140 140140FGD+SCR 140 140Tanners Creek*U4 500 Overfire Air OFAWabash River GenStation*1 85 IGCCWabash River GenStation*2 85 Shut Down 9-30-09 LNBWabash River GenStation*3 85 Shut Down 9-30-09 LNBSNCRSNCRWabash River GenStation*4 85Low NOxBurnerTechnology w/Overfire Air LNB85 8585 8585 85858585 8585 85Wabash River GenStation*5 95 Shut Down 9-30-09 LNBSNCRSNCRWabash River GenStation*6 318Low NOxBurnerTechnology w/Separated OFA LNBFGD+SCR318FGD+SCR318FACILITY_NAMEUNITIDCapacityMWe2009 + ProjectedNOx_CONTROLNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxNOxIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeBART-eligible Units*MANEVU AskNOxLADCO2012RetrofitIDEMCredit forControl(s) inMWeINDIANA COAL-FIRED UNITS2009 + Projected Compared to IPMRetrofit 2015EPA CreditforControl(s) inMWeEPA IPM 3.0 2006 runsIPM 2010RetrofitIDEMCredit forControl(s) inMWeEPA CreditforControl(s) inMWeIPM 2020RetrofitEPA CreditforControl(s) inMWeIPM Existing2009 + Projected Compared to IPM2010 Retrofit2009 + Projected Compared to IPMExistingIPM 2015RetrofitIDEMCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared to IPM2020 RetrofitLADCOCredit forControl(s) inMWeLADCOCredit forControl(s) inMWeIDEMCredit forControl(s) inMWe2009 + Projected Compared toLADCO 2018 RetrofitLADCO Round 5 RunsLADCO2018Retrofit2009 + Projected Compared toLADCO 2012 RetrofitWhitewater Valley1 34.77Low NOxBurnerTechnology w/Separated OFAAmmonia InjectionOverfire Air LNB34.77 34.7734.77 34.7734.77 34.7734.77 34.7734.77 34.7734.77 34.77Whitewater Valley2 62.8Low NOxBurnerTechnology w/Separated OFAAmmonia InjectionOverfire Air LNB62.8 62.862.8 62.862.8 62.862.8 62.862.8 62.862.8 62.812,981 11,42012,981 11,63713,103 12,42515,703 15,95813,103 11,88015,703 15,958

EPA 2015

IDEM 2010 EPA 2010 IDEM 2015

IDEM Base Case EPA Basecase EPA 2020 IDEM 2012

IDEM 2020 LADCO 2012 IDEM 2018 LADCO 2018

## 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 fu rther 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 bu t 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 an y 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, MA RK" 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 questionAppendix 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

USEP A 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 th e 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 th row 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 conser vatism. 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 th is 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 th eir 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

‐ 6713Appendix 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 ea ch 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, the y 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 da ys 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 ea ch 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 Questio n/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 cou ld 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 kn ow 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.govAppendix 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 VO YA (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

‐ BA RT 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 a dditional 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 mo deled 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 Hawe s 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 sour ce 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 re ceptors 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.govAppendix 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 an ything. 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 deci ded 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 additi onal 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 Clas s 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 Hawe s 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 poi nts 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 thres hold 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.govAppendix 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

‐ 31 22

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 additi onal 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 Clas s 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 Hawe s 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 poi nts 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 thres hold 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.govAppendix 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: DE RF, 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 im pacts 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 Hawe s 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 sour ce 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 re ceptors 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