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DEP Response to Public and Federal Land Managers Comments

I. Response to U. S. Fish and Wildlife Service Comments: August 31, 2012, letter to 

Mr. Thomas Rogers, Division of Air Resource Management from Ms. Sandra Silva, 

Chief, Branch of Air Quality, U.S. Fish and Wildlife Service

A. General Comments

1. The U.S. Fish and Wildlife Service (FWS) acknowledges that “[o]verall, the Florida 

Draft Regional Haze SIP includes the necessary elements and offers all the information 

needed to adequately address regional haze.” It also points out that “the SIP is well 

written and a good example for other States to follow” and notes that “by 2010, Florida’s 

actual sulfur dioxide (SO2) emissions are below the 2018 projected emissions levels.”

Response: DEP appreciates these comments. DEP and the regulated sources have spent

extensive time and resources to obtain, process and make this information a part of the 

SIP.

2. FWS is pleased that a number of sources either agreed to voluntarily reduce emissions or 

were required by the State to adjust current emission control devices to reduce emissions 

in order to contribute to State’s Reasonable Progress Goals. The addition of emission 

controls as a result of a robust evaluation of Reasonable Progress is an example of how 

progress improvements can be obtained and this should be used as an example for other 

States.

Response: DEP agrees. This proposal would not have been possible without the 

participation and cooperation of the regulated sources.

B. Specific Comments

1. FWS states a preference for the VISTAS approach in selecting the sources subject to 

reasonable progress review, as opposed to the simplified DEP approach.

Response: This comment is not related to the August draft amendments. The issues 

raised were proposed in the original regional haze SIP submittal in March 2010, and 

subject to public comment at that time. EPA proposed to approve the elements of 

concern to FWS in the May 25, 2012, Federal Register notice “Approval and 

Promulgation of Air Quality Plans; State of Florida; Regional Haze State Implementation 

Plan.” Having said that, DEP points out that both approaches select most of the same 

sources for review, making them essentially equivalent.

2. BART determinations – FWS would have liked DEP to have considered all Class I areas 

within 300 kilometers, and not just the closest, in the cost effectiveness analysis, and they 

state that some permits may be missing in Exhibit 2.
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Response: DEP considered the highest visibility impact from the nearby Class I areas. 

Typically, the closest Class I area would have the highest visibility impact. DEP did not 

explicitly consider the cumulative impact of multiple Class I areas. However, DEP does 

not believe that such an analysis would have made a significant difference in any of the 

BART determinations.

With respect to permits not being included for Tampa Electric Big Bend, Gulf Power 

Crist, FPL Martin, and JEA Northside, these facilities did not need to obtain a new permit 

to support their determination.

3. Proposed Shutdowns – FWS believes that additional permit conditions are necessary for 

the City of Tallahassee Purdom and FPL Turkey Point permits to assure that the BARTeligible units will not emit pollution after the stated shutdown date.

Response: DEP disagrees with this proposition. The federally enforceable permit 

condition to no longer operate these units after the specified date is sufficient.

4. Proposed Existing Top Control – FWS acknowledges that very significant controls have 

been installed on the Tampa Electric Big Bend and Gulf Crist BART–eligible units, and 

that they likely represent BART, but that the limits imposed on these units may not 

represent top level control. FWS would have preferred a five-factor BART analysis. 

FWS also questions language that appears to accept a “better than BART” determination.

Response: DEP maintains that the control devices on these units represent the top level 

that can reasonably be installed. Every source has its own set of site-specific conditions 

and circumstances that may result in different numerical limits. It should be noted that 

EPA has proposed to approve the Tampa Electric Big Bend top level analysis in the May 

25, 2012, Federal Register notice “Approval and Promulgation of Air Quality Plans; State 

of Florida; Regional Haze State Implementation Plan.”

With regard to the FWS comment that rejects the “better than BART” claim in the 

determination, DEP agrees. This was a confusing statement that used the “and/or” 

construct. DEP is not claiming the determination is better than BART, and the phrase has 

been deleted from the final document.

5. BART Discussions for Fuel-oil and Natural Gas Fired Sources – FWS suggests that 

BART limits for these sources could be stricter, possibly requiring 0.5 percent sulfur fuel 

oil.

Response: DEP believes that its analysis of fuel sulfur levels in the BART analyses was 

sufficiently robust and consistent with the BART regulations. DEP notes that fuel prices 

are considerably higher now than in 2008-2009, as quoted by the FWS. This results in a 

less cost effective result. Upon receipt of this comment, DEP thoroughly reviewed its

analyses for these oil-fired units and determined that 0.5 percent sulfur oil would not be 

cost effective.
425

6. FPL Turkey Point BART issues – The draft permit does not seem to reflect the shutdown 

of unit 2 and the capacity limitation of unit 1. There is an insufficient NOx BART 

review.

Response: FWS’s source of confusion may have been the fact that the draft permit is a 

revision to a previous permit. The (now final) permit revision clearly shows the required 

shutdown and capacity limitation. With regard to the NOx BART analysis, DEP believes 

that its analysis was sufficient for the case-specific situation. In light of the complete 

shutdown of unit 2, the limited oil capacity of unit 1, and the small contribution to 

visibility impairment from NOx, DEP concluded the existing NOx controls to be BART.

7. FPL Martin BART issues – DEP should consider that ESP’s are BART for PM.

Response: Although FPL is planning to install ESP’s on the Martin units, DEP does not 

conclude that this control is required through a BART analysis because of low cost 

effectiveness and small impact on Class I areas.

8. FPL Manatee BART issues – DEP should consider that ESP’s are BART for PM.

Response: DEP does, in fact, conclude that this control is representative of BART and 

the emission limitation reflects this control.

9. JEA Northside BART issues – DEP should consider SCR as BART for unit 3.

Response: As explained in response to the comments from EPA below, DEP has updated 

the BART analysis to reflect the limited use of unit 3 to better illustrate why the BART 

determination is sufficient.

10. Lakeland McIntosh BART issues – DEP should consider additional control for BART.

Response: DEP considered SCR technology for NOx control and concluded it was not 

cost effective. This conclusion is supported by the fact that these units are limited use 

units, and the true visibility improvement from SCR would realistically be considerably

less than the value provided.

11. Progress Energy Crystal River BART issues – FWS questions whether the option to shut 

down by December 31, 2020, is acceptable. They also assert that the source cannot rely 

on CSAPR because of the court decision to vacate the rule.

Response: As explained in response to EPA comments at Section I.A.3. and I.A.4. 

below, DEP has revised the BART determination for Crystal River 1 and 2 to remove the 

option of later exempting out of BART and replaced its reliance on CSAPR for NOx with 

a commitment to shut down or install top level SCR technology by 2018. With regard to 

the question of whether the shutdown option by December 31, 2020, is acceptable, EPA 

guidance is clear that an analysis that shows a control option is not cost effective 

considering the useful life of the source is an acceptable BART determination. In that 

case, the annualized cost is amortized over the length of the useful life.
426

12. Gulf Power Lansing Smith BART issues – FWS suggests including the cost per desiview 

in the analysis and that DEP should consider additional NOx controls.

Response: DEP has added the cost per desiview values. DEP has also updated the 

analysis to include the cost of the DSI and made appropriate changes to the dependent 

metrics. With regard to the additional NOx controls, DEP is satisfied with the existing 

analysis and notes that given nearly zero visibility improvement with SCR control, there 

is little to be gained from analyzing intermediate controls.

13. BART Determinations for Non-EGUs – FWS suggests DEP consider greater control for 

phosphate plants.

Response: These BART determinations were not a part of the August 3, 2012, submittal.

II. Response to Florida Electric Power Coordinating Group Environmental Committee 

Comments: September 4, 2012, letter to Mr. Tom Rogers, Division of Air Resource 

Management from Ms. Amy Deese, Chair, FCG Air Subcommittee.

The Florida Electric Power Coordinating Group Environmental Committee (FCG-EC) provided 

comments consisting of suggested edits to reflect the vacatur of the CSAPR by the D.C. Circuit 

Court on August 21, 2012. DEP considered all of these suggested edits and made appropriate 

changes in the final submittal. While DEP did not always use the exact language suggested by 

the FCG-EC, the changes achieve the same underlying purpose (i.e., to reflect CSAPR’s 

vacatur).

III. Response to Gulf Power Comments: September 4, 2012, letter to Mr. Tom Rogers, 

Division of Air Resource Management from Mr. Dwain Waters, Gulf Power Special 

Projects and Environmental Assets Coordinator

Gulf Power provided additional information to DEP to answer a number of questions received in 

the other comments included and responded to herein, along with some additional preliminary 

questions from EPA and several environmental groups. The information provided relates 

exclusively to the BART determination for the Gulf Power Lansing Smith plant. DEP has made 

GP’s comments a part of the record and used much of the information therein to formulate the 

necessary responses to the comments received from EPA and environmental groups.

IV. Response to Sierra Club and National Parks Conservation Association Comments: 

September 4, 2012, letter to Tom Rogers, FDEP Division of Air Resource 

Management, from Craig Segall, Alisa Coe, and Stephanie Kodish on behalf of the 

Sierra Club, Earthjustice, and National Parks Conservation Association

A. Comments Re: CAIR and CSAPR

1. CAIR Is Not Available as an Approved Alternative to BART.
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Response: DEP’s regional haze plan as amended does not rely on CAIR as an approved 

alternative to BART.

2. The only way which Florida could attempt to rely upon CAIR would be to independently 

propose CAIR as an alternative.

Response: See the response to comment 1.

3. Proper BART determinations for Florida sources provide greater protection than CAIR.

Response: DEP’s regional haze plan has been amended to include proper BART 

determinations in place of the plan’s previous reliance on CAIR as a BART alternative.

4. CAIR must not be used to meet reasonable progress goals, or to inform Florida’s 

long‐term strategy.

Response: See the responses to Sierra Club and National Parks Conservation 

Association’s May 14, 2012 comments.

B. Comments Re: Lansing Smith & Crystal River BART Determinations

1. See the comments to the draft permits for the Lansing Smith and Crystal River permits 

which are both referenced in the BART analyses for these plants and proposed to be 

incorporated into the regional haze plan. 

Response: DEP’s responses to these comments are incorporated into Exhibit 2 along with 

the final permits.

2. The NOx BART determinations for both plants cannot rely upon CAIR or CSAPR as 

BART.

Response: The plan no longer relies on CAIR or CSAPR as BART for any of the BARTeligible sources, including Crystal River and Lansing Smith. See the responses to EPA’s 

September 4, 2012 comments below at I.A.3.
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April 2012 Pre-Hearing Submittal to EPA

Pre-Hearing Submittal Letter
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EPA Comments on Pre-Hearing Submittal
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DEP Response to EPA Comments

No response required.
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August 2012 Pre-Hearing Submittal to EPA

Pre-Hearing Submittal Letter
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EPA Comments on Pre-Hearing Submittal
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DEP Response to EPA Comments

I. Response to EPA Comments: September 4, 2012, letter to Mr. Brian Accardo, 

Director, Division of Air Resource Management from Mr. R. Scott Davis, Chief, Air 

Planning Branch, U.S. Environmental Protection Agency, Region 4

The U.S. EPA, Region 4 provided four key comments and two general comments. DEP’s 

responses are provided in the order presented in EPA’s letter.

A. Key Comments

1. The permit conditions attached and incorporated into the prehearing draft Regional Haze 

Plan were in draft form. 

Response: DEP has replaced the draft permits with the final permits in the final 

Regional Haze Plan.

2. The modeling included in the prehearing draft Regional Haze Plan overstates the actual 

impact and visibility benefits associated with JEA Northside Unit 3.

Response: DEP has reassessed the visibility impact of the Unit 3 emissions changes 

related to the review of additional SCR NOx control in light of the federally enforceable 

permit conditions that limit operation of this unit. 

In the prehearing draft submittal, DEP estimated that the additional visibility 

improvement associated with the addition of SCR on JEA Northside Unit 3 would be 

0.85 dv (at the nearest Class I area – Okefenokee). This value was based on CALPUFF 

modeling assuming that Unit 3 would operate continuously on No. 6 fuel oil for all days 

of the year. This was an illogical assumption because this unit is limited by federally 

enforceable permit to a reduced capacity based on the operation of Units 1 and 2 at this 

same facility. Units 1 and 2 are base load circulating fluidized bed boilers not subject to 

BART review. Federally enforceable permit conditions that cap the total SO2 and NOx 

emissions tie the three units together and effectively limits the operation Unit 3. Given 

the caps and the emission limits, the capacity of Unit 3 operation can be determined as 

follows.

The NOx cap is set at 3,600 tons per year for all three units combined, while the SO2 cap 

is set at 12,284 tons per year. The federally enforceable emission limits set for these 

units are : NOx: Units 1 and 2 – 0.09 lb/MMBtu; Unit 3 – 0.3 lb/MMBtu, and SO2: Units 

1 and 2 – 0.15 lb/MMBtu; Unit 3 – 1.98 lb/MMBtu. In the case where Units 1 and 2 

operate at their full capacity, Unit 3 would be limited to only 20 percent operation on oil. 

In the case of both Units 1 and 2 not being operated at all, Unit 3 would be limited to 28 

percent operation on oil. The actual operation is far closer to the former case since Units 

1 and 2 are more efficient units and cheaper to operate. In fact, over the past seven years 

the actual capacity utilization of Unit 3 has ranged from 15.9 percent to 25.3 percent.
437

This utilization includes significant use of natural gas, which is the preferred fuel for this 

unit.

This limited utilization of Unit 3 necessitates an adjustment to the visibility metric based 

on the 98th percentile of the maximum daily visibility degradation. The CALPUFF 

modeling completed for this source erroneously assumes that it operates continuously on 

oil (i.e., 100 percent capacity). The 98th percentile visibility metric is then represented as 

the 8th highest value in each year. An approximation of the 98th percentile value for 

limited operation is made by choosing a lower value in the rank order distribution that 

represents the lower probability of impact in the Class I area. For example, if the source 

operated 50 percent of the time, randomly distributed over the year, then the 98th 

percentile value is estimated as the 16th highest value of the modeling that uses 100 

percent capacity (i.e., = 8/0.5). In the Unit 3’s maximum utilization of 28 percent on oil, 

the value to select from the distribution would be the 29th highest value. Because of a 

limitation in the data presented in the spreadsheet that translates the CALPUFF results to 

the new IMPROVE formulation, only the top 22 rank visibility values are available. 

Therefore, the conservative 22nd highest value for each modeled year (representative of 

36 percent capacity utilization) will be used to represent the 98th percentile impact. 

A review of the CALPUFF modeling shows the following impacts associated with the 

22nd highest value: 2001 – 0.26 dv; 2002 – 0.17 dv, and 2003 – 0.18 dv. The highest of 

these values is 0.26 dv. This is the corrected visibility improvement expected from the 

addition of an SCR on Unit 3. This reduced improvement also changes the cost per 

desiview value provided in the pre-hearing draft from $6,130,000/dv to $20,039,000/dv.

On page 161 of the JEA Northside BART analysis, corrections have been made to reflect 

the above changes to the visibility impact. Also, on page 159, a typographical error was 

corrected to the price of 1.8 percent sulfur fuel oil from $2.67/gallon to $2.067/gallon. 

The actual calculations used in the analysis applied the correct value.

3. DEP relies on Cross State Air Pollution Rule (CSAPR) to meet NOx BART for Progress 

Energy Crystal River Units 1 and 2, however CSAPR was vacated by the United States 

Court of Appeals for the D.C. Circuit.

Response: In light of the recent court decision to vacate CSAPR, DEP has removed its 

reliance on this rule in the final submittal. In its place, Progress Energy has applied for a 

federally enforceable permit to install top level NOx control of SCR technology as their

control option. DEP has included this as its BART determination in the SIP. 

In addition, DEP has removed several general references in the document that refer to 

CAIR being replaced by CSAPR.

4. January 1, 2015 is too late for Progress Energy Crystal River Units 1 and 2 to exempt out 

of BART. EPA will not approve a BART exemption if the exemption limits are not in 

place by the effective date of EPA’s final action on a state’s regional Haze SIP.

Response: DEP acknowledges that the option that provides for future exemption for 

these units is not consistent with EPA policy. As such, this option has been removed in 

the final permit and the regional haze SIP.
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B. General Comments

1. Fuel Oil Cost Effectiveness Estimates: Several technical corrections have been made 

based on further review of the calculation used to estimate cost effectiveness. None of 

these changes affects the conclusions related to BART.

(a) FPL Martin - On pages 144-145, the following changes have been made to provide a 

more consistent comparison of the cost differential between oils of different sulfur 

contents.

From:

Change in Emissions

• Baseline emissions were based on maximum actual CEMS data for years 2001-2003 

= 17,592 tons (annual average).

• Projected future emissions were calculated using stoichiometric calculations as 

follows: 

8,650 MMBtu/hour *2 units*.003*1,000*6,700 hours*(8.1 pounds/gallon)/ 

(145*2000) = 9,712 tons.

•Baseline – future projected = 7,882 tons decrease. 

Cost Effectiveness 

• $190,328,407/7,882 tons = $24,155/ton. 

To:

Cost Effectiveness

Based on company data, the pounds of SO2 in a barrel of oil is as follows: (8.1 lb/gal 

*42 gal/bbl*2 lb SO2/lb S* fraction of S in oil); thus, at 0.7 percent sulfur oil = 4.763 

lb SO2/bbl and at 0.3 percent sulfur oil = 2.041 lb SO2/bbl.

Given the company-provided cost for oil of $114.63/bbl for 0.7 percent sulfur oil and 

$124.63/bbl for 0.3 percent sulfur oil, and noting that the cost of per ton of emissions 

can be determined as (change in $/bbl / change in lb SO2/bbl) * 2000 lb/ton, the cost 

per ton of emissions to change from 0.7 percent fuel oil to 0.3 percent is $7,348/ton.

(b) FPL Manatee

i. On page 149, the following changes have been made to provide a more consistent 

comparison of the cost differential between oils of different sulfur contents.

From:

Change in Emissions

• Baseline emissions were based on maximum actual CEMS data for years 2001-2003 

= 34,595 tons (annual average). 

• Projected future emissions were calculated using stoichiometric calculations as 

follows: 
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8,650 MMBtu/hour *2 units*.007*1,000*5,500 hours*(8.1 pounds/gallon)/ 

(145*2000) = 18,603tons. 

8,650 MMBtu/hour *2 units*.003*1,000*5,500 hours*(8.1 pounds/gallon)/ 

(145*2000) = 7,973tons. 

• Baseline – future projected = 15,992 tons decrease. 

• Baseline – future projected = 26,622 tons decrease. 

Average Cost Effectiveness 

• Fuel switch to 0.7% sulfur fuel oil = $5,452/ton. 

• Fuel switch to 0.3% sulfur fuel oil = $9,144/ton. 

To:

Cost Effectiveness

Based on company data, the pounds of SO2 in a barrel of oil is as follows: (8.1 lb/gal 

*42 gal/bbl*2 lb SO2/lb S* fraction of S in oil); thus, at 1.0 percent sulfur fuel oil 

=6.804 lb SO2/bbl, and at 0.7 percent sulfur oil = 4.763 lb SO2/bbl and at 0.3 percent 

sulfur oil = 2.041 lb SO2/bbl.

Given the company-provided cost for oil of $109.05/bbl for 1.0 percent sulfur oil, 

$114.63/bbl for 0.7 percent sulfur oil, and $124.63/bbl for 0.3 percent sulfur oil, and 

noting that the cost of per ton of emissions can be determined as (change in $/bbl / 

change in lb SO2/bbl) * 2000 lb/ton, the cost per ton of emissions to change from 1 

percent fuel oil to 0.7 percent is $5,468/ton, the cost per ton to change from 1 percent 

to 0.3 percent is $6,542/ton, and the cost per ton of emissions to change from 0.7 

percent fuel oil to 0.3 percent is $7,348/ton.

ii. Also, on page 151, the BART limit expressed as an oil sulfur limit in the 

prehearing draft has been changed to reflect the limit in terms of pounds per heat 

input, as actually in the permit.

From:

The sulfur content of fuel oils burned shall not exceed 0.7% by weight, as received at 

the plant. Blending of natural gas shall not be used to demonstrate compliance with 

the sulfur dioxide standard for “liquid fuel” in Rule 62-296.405(c), F.A.C. 

Compliance demonstrated by fuel sampling and analysis. [40 CFR 60, Subpart Da]

To: 

Sulfur dioxide emissions rate from each fossil fuel fired steam electric generator 

Units 1 and 2 shall not exceed 0.80 lb/MMBtu during any rolling 12 months. 

[Application No. 0810010-017-AC and Rule 62-210.200(PTE), F.A.C.]

(c) Lakeland Utilities McIntosh – On pages 153-154, , the following changes have been 

made to provide a more consistent comparison of the cost differential between oils of 

different sulfur contents.
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From:

Change in Emissions 

• Projected future emissions were calculated using stoichiometric calculations as 

follows: 

3,755,938 MMBtu/yr *8.3 lb fuel oil/gal * 1000 gal/150 MMBtu * 0.7% lb Sulfur / lb 

fuel oil* 2 lb SO2 / lb Sulfur * 1 ton/2000 lbs = 1,455 tons. 

• Baseline – future projected = 1,051 tons decrease. 

Cost Effectiveness 

• $8,345,694 / 1,051 tons = $7,739 /ton

To: 

Cost Effectiveness

Based on company data, the pounds of SO2 per MMBtu: (8.3 lb/gal / 0.15 

MMBtu/gal *2 lb SO2/lb S* fraction of S in oil); thus, at 2.5 percent sulfur fuel oil 

=2.767 lb SO2/MMBtu, and at 0.7 percent sulfur oil = 0.775 lb SO2/MMBtu.

Given the company-provided cost for oil of $19.649/MMBtu for 2.5 percent sulfur 

oil, and $21.871/MMBtu for 0.7 percent sulfur oil, and noting that the cost of per ton 

of emissions can be determined as (change in $/MMBtu / change in lb SO2/MMBtu) 

* 2000 lb/ton, the cost per ton of emissions to change from 2.5 percent fuel oil to 0.7 

percent is $2,231/ton. The narrative BART analysis was revised to reflect this as 

follows.

From:

Selection of BART

Because the cost of improvement is relatively high for switching to the 0.7% sulfur 

fuel, this option is generally not cost effective, however, LE proposed that new 

shipments of fuel oil for Unit 1 will be limited to 0.7% sulfur content, the same as in 

Unit 2 and proposed this low sulfur fuel oil control option for both units as BART. 

DEP concurs and establishes that new shipments of fuel oil shall be limited to 0.7% 

sulfur as this BART determination for Units 1 and 2. A federally enforceable permit 

condition assures this determination.

To:

Selection of BART

LE proposed that new shipments of fuel oil for Unit 1 will be limited to 0.7% sulfur 

content, the same as in Unit 2 and proposed this low sulfur fuel oil control option for 

both units as BART. DEP concurs and establishes that new shipments of fuel oil shall 

be limited to 0.7% sulfur as this BART determination for Units 1 and 2. A federally 

enforceable permit condition assures this determination.

(d) JEA Northside – On pages 159 and 160, the following changes have been made to 

provide a more consistent comparison of the cost differential between oils of different 

sulfur contents.
441

From:

Change in Emissions

• Baseline emissions were based on maximum actual CEMS data for years 2001-2003 

= 8,958 tons (annual average). 

• Projected future emissions were calculated using stoichiometric calculations as 

follows

10,733,024 MMBtu/yr *8.3 lb fuel oil/gal * 1000 gal/152 MMBtu * 1% lb Sulfur / lb 

fuel oil* 2 lb SO2 / lb Sulfur * 1 ton/2000 lbs = 5,861 tons. 

• Baseline – future projected = 3,097 tons decrease. 

Cost Effectiveness 

• $33,681,924 / 3,097 tons = $10,876 /ton. 

To: 

Cost Effectiveness

Based on company data, the pounds of SO2 in a gallon of oil is as follows: (8.3 lb/gal 

*2 lb SO2/lb S* fraction of S in oil); thus, at 1.8 percent sulfur fuel oil =0.2988 lb 

SO2/gal, and at 1.0 percent sulfur oil = 0.1660 lb SO2/gal.

Given the company-provided cost for oil of $2.067/gal for 1.8 percent sulfur oil, and 

$2.544/gal for 1.0 percent sulfur oil, and noting that the cost of per ton of emissions 

can be determined as (change in $/gal / change in lb SO2/gal) * 2000 lb/ton, the cost 

per ton of emissions to change from 1.8 percent fuel oil to 1.0 percent is $7,184/ton.

2. Comments Regarding Lansing Smith BART Determination:

(a) Effectiveness of the Remaining Control Technologies – The basis for the removal 

efficiencies selected for various NOx, PM, and SO2 controls should be documented 

in the BART analysis.

Response: DEP has added additional language to this section to provide the basis for 

the selection of removal efficiencies for NOx, PM, and SO2 controls.

(b) Inconsistency Between Control Effectiveness and Emission Rates – It should be 

confirmed that the controlled emissions rates used to determine BART are consistent 

with the actual expected removal efficiencies selected for each control technology.

Response: For the purpose of calculating the nominal future emission rate of a 

scrubber technology, Gulf Power (GP) used the presumptive SO2 BART level of 0.15 

lb/MMBtu. This equates to an emission reduction from the actual baseline of 89.5 

percent. DEP notes that the 0.15 lb/MMBtu limit includes startup, shutdown, and 

malfunction over a 30-day period. Thus, actual normal operation would be emitting 

at a lower rate. DEP also notes that in the visibility modeling, which used maximum 

actual 24-hour emission rates, the control efficiency used to represent scrubber 

technology was 93 percent and 91.5 percent for units 1 and 2, respectively. No 
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change in the BART determination would be made if a 95 percent reduction had been 

assumed.

(c) Compliance Costs of Dry Sorbent Injection – The cost of DSI should be included in 

the cost effectiveness analysis used to determine BART since DSI is not currently 

installed on Units 1 and 2.

Response: Given the realities that (a) the cost of the DSI will indeed be “sunk” due to 

EPA’s Mercury and Air Toxics Standard and (b) the cost of the DSI has no bearing 

on the BART determination, it is not a necessary to include it from DEP’s 

perspective. Nevertheless, for completeness, DEP has revised its BART analysis to 

include its best estimate of the cost of installing DSI technology on Lansing Smith 

Units 1 and 2 along with the associated derived metrics.

(d) Evaluation of Dry Flue Gas Desulfurization (DFGD) – The reasons for determining 

that DFGD is not BART should be included in the steps of the BART analysis 

focused on control effectiveness and compliance costs rather than the step focused on 

technical feasibility.

Response: The list of reasons for eliminating this technology from further 

consideration includes limits that would make it infeasible. For example, they refer 

to physical space limitations. They also conclude that additional control of 

particulates would be necessary, requiring a new baghouse. While the costs of these 

devices were not quantified, based on DEP’s experience with permitting these types 

of sources, DEP is comfortable in concluding that the costs for a DFGD system 

would be more costly than a WFGD system and provide less emission reduction; 

thus, there is no purpose in spending the time and resources to evaluate the cost any 

further.

(e) Control Cost Estimates – The basis for the costs selected for various NOx, PM, and 

SO2 controls should be documented in the BART analysis. 

Response: The Lansing Smith BART analysis was revised to include additional 

information on the control costs. Some of this information was supplied by Gulf 

Power and some was developed by DEP.