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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 ad dress 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 a ppreciates 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 i n 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; Stat e 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 consider ed 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 2.424

Response : DEP considered the highest visibility impact from the nearby Class I area s. T y pically, 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 a ny 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 BART

eligible units will not emit pollution after the stated shutdown date.

Response : DEP disagrees with this proposition. T he 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 E lectric 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 th at appears to accept a “better than BART” determination.

Response : DEP maintains that t he 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 t hat 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 re sults in a
less cost effective result. Upon receipt of this comment, DEP thoroughly re viewed 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 doe s 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 ex isting 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 commen ts 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 conside red SCR technology for NOx control and concluded it was not
cost effective. This conclusion is supported by the fact that these units are li mited use units, and the true vi sibility improvement from SCR would realistically be considerably
less than the val ue 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 t o 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 th e 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 tha t 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 conside r 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 Roge rs, 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 p urpose (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 r elates 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 enviro nmental 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 Clu b, Earthjustice, and National Parks Conservation Association

A. Comments Re: CAIR and CSAPR

1. CAIR Is Not Available as an Approved Alternative to BART.427

Response : DEP’s regional haze plan as amended does not rely on CAIR as an approved
alternative to BART.

2. T he only way which Florida could attempt to rely upon CAIR would be to independently propose CAIR as an alternative.

Response : See the response to c omment 1.

3. Proper BART d eterminations for Florida s ources p rovide g reater p rotection than CAIR.

Response : DE P’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.

Resp onse : 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 BART

eligible sources, including Crystal River and Lansing Smith. See the responses to EPA’s September 4, 2012 comments below at I.A.3.428 April 2012 P re
- Hearing S ubmittal to EPA

Pre

- H earing Submittal Letter429

EPA Comments on Pre

- Hearing Submittal430

DEP Response to EPA Com m ents

No response required.431 August 2012 Pre

- Hearing Submittal to EPA

Pre

- Hearing Submittal Letter432433

EPA Comments on Pre

- Hearing Submittal434435436

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 dra ft 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
i mprovement 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 fa cility. 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 emi ssion 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 on ly 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 ch eaper 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 distribut ion 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 tr anslates 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 rep resent 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 v isibility 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 Ri ver 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.438

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 ma de 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 s toichiometric 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 Effectivenes s • $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/bb l 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 s t oichiometric calculations as
follows:439 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 proje cted = 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
sul fur 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 dete rmined 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 con tents.440 From: Change in Emissions • Projected future emissions were calculated using s toichiometric 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 su lfur 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 fue l 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 B ART 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 assur es 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 Sulfu r / 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 BA RT 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 n ominal 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
malfunctio n 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. No442 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 effectiv eness 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 b earing 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 cos ts 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 t hat 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 se lected 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 an d some was developed by DEP.