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U.S. Environmental Protection Agency

Responses to Public Comments

Draft Greenhouse Gas PSD Air Permit for the Tampa Electric Company –

Polk Power Station 2-5 Combined Cycle Conversion Project

December 18, 2013
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Table of Contents

I. Introduction.......................................................................................................................3

II. EPA’s Responses to Public Comments .........................................................................3

Comments Submitted by Sierra Club.........................................................................3

Comments Submitted by Tampa Electric Company ..................................................9
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I. Introduction

The U.S. Environmental Protection Agency, Region 4 (EPA) proposed to issue a Prevention of

Significant Deterioration (PSD) permit for Greenhouse Gases to Tampa Electric Company (TECO or 

TEC) for the Polk Power Station 2-5 Combined Cycle Conversion Project (Project) on 

September 24, 2013. The public comment period for the proposal (Proposed Permit) began on 

September 24, 2013, and closed on October 25, 2013.

EPA announced the public comment period through a public notice published in The (Lakeland) Ledger

(in English) on September 24, 2013, and on Region 4’s website (in English) on September 24, 2013. 

EPA also distributed the public notice to the necessary parties in accordance with 40 CFR Part 124, 

including notices sent by email on September 24, 2013. Parties notified by EPA included agencies, 

organizations, and public members for whom contact information was obtained through a number of 

different methods, including requests made directly to EPA through Region 4’s website (or through 

other means) from parties seeking notification regarding permit actions in Florida, within the jurisdiction 

of Florida Department of Environmental Protection (FDEP), within Polk County; and other parties 

known to EPA that may have an interest in this action. 

During the public comment period, EPA received two comment letters and no requests for public 

hearing. Responses to the public comments received are available in the following sections of this 

document.

II. EPA’s Responses to Public Comments

This section summarizes all public comments received by EPA and provides our responses to those 

comments. The full text of all public comments and many other documents relevant to the permit can be 

accessed online at http://www.regulations.gov (Docket #EPA-R04-OAR-2013-0648) or on Region 4’s 

website at http://www.epa.gov/region4/air/permits/ghgpermits/tecopolkpower_ghg.html.

Comments Submitted by Sierra Club

1. Comment: Draft permit Condition IX.B(5) would allow the Polk Power Station project to 

operate using fuel oil for up to 3,000 hours combined for the four units on a 12-month rolling period 

(equal to an average of 750 hours per unit). Fuel oil may not be used more than a combined 48 hours 

per 24-hour period (equal to an average of 12 hours per unit) (Draft Permit at p. 7.) This permit 

condition therefore substantially increases the potential GHG emissions at the facility. During 

operations using fuel oil, the GHG emission limit increases to 1,235 lb CO2e/MWh for combined 

cycle operation and 1,868 lb CO2e/MWh for simple-cycle operation.

The SOB states that “the need for power production reliability and the potential for natural gas 

disruption or curtailments” precludes the use of natural gas as the sole fuel source. (SOB p.13) 

However, the Region does not include any analysis of the need for 3,000 hours of backup fuel 

operation, nor does it establish the conditions necessary for operation of the units on fuel oil. The 

draft permit would allow TECO to operate the Shady Hills facility on fuel oil whenever it is cheaper 

to do so. This proposed operation of the facility does not comply with the Clean Air Act’s 

requirement that facilities operate with the best available control technologies. The draft permit 

clearly acknowledges that the use of natural gas as a fuel source is an inherently lower emitting 
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practice than the use of fuel oil because it sets different GHG emission rates. The draft permit’s 

GHG limit is 41% higher for fuel oil than for natural gas in combined cycle operation, and 42% 

higher in simple-cycle operation. The fuel oil limits of 1,235 and 1,868 lb CO2e/MWh do not even 

come close to meeting the proposed new source performance standard of 1,100 lb/MWh for small 

stationary natural gas fired units. In short, fuel oil is an outdated and dirty technology that does not 

meet the requirements that the facility comply with BACT limits.

Despite the obviously higher pollution from fuel oil use, the Region does not provide any restrictions 

on the use of fuel oil, other than an arbitrary cap of 3,000 total hours on a 12-month rolling period 

and 1,500 hours during simple-cycle operations. This means that the facility can operate on fuel oil 

up to 3,000 hours annually regardless of whether there is any emergency, any limit to natural gas 

supply, or any risk of electric system reliability. TECO can simply switch to fuel oil whenever it 

decides that fuel oil is cheaper. The top-down BACT analysis does not allow this condition. The Region 

must set limits based on the technologies that are feasible. In this case, the use of natural gas fuel is 

clearly feasible because it is the primary purpose of the plant. The Region determined that it was 

infeasible to limit Polk Power Station to use natural gas as the sole fuel source. However, the draft 

permit’s conditions are not narrowly tailored to alleviate the concerns of reliability and natural gas 

supply disruption. Even if it were reasonable to allow the use of fuel oil in an emergency, such as a 

pipeline disruption, the draft permit’s allowance of up to 3,000 hours every year is completely arbitrary 

and would allow TECO to operate on fuel oil even absent any “reliability and risk” concerns.

The Region must revise the permit condition allowing the use of fuel oil to state that fuel oil may 

only be used during times of natural gas supply disruption due to emergency, and in no case may the 

use of fuel oil exceed 100 hours per CT annually. The Region should also include a definition of 

“emergency” conditions that warrant use of backup fuel oil, and that definition should specify that 

high natural gas prices are not by themselves an emergency. Fuel oil should only be used in cases of 

true emergency that disrupts the ability to deliver natural gas to the Polk Power Station facility. 

BACT requires the best available technology, and in this case the facility must operate on natural gas 

fuel unless it is infeasible to do so.

Response: The commenter is correct in noting that the permit does not restrict the use of ultra 

low sulfur diesel (ULSD) fuel oil to only emergency situations. Consequently, EPA did not define 

the term “emergency” for the purposes of using ULSD in the turbines. The 3,000-hour annual ULSD 

usage limit is based on information provided in the application as well as on additional information 

submitted by the applicant in response to EPA’s incompleteness determination. See correspondence 

dated December 19, 2012, in the administrative record. Specifically, the applicant explained that the 

annual allowance of 3,000 hours of ULSD operation for all four turbines combined—which is 

consistent with the previous permit limits for existing Units 2 and 3—is needed not only to enable 

the facility to meet its obligation to provide power to its customers during periods of natural gas 

interruptions or curtailments (e.g., severe weather events such as hurricanes or natural gas pipeline 

malfunctions), but also for routine testing and maintenance. Consistent with the applicant’s 

explanation, the Florida Public Service Commission (PSC) granted TECO a determination of need 

based on its finding of “a need for Polk 2-5 as proposed by TECO to maintain electric system 

reliability and integrity” and its conclusion that the project as proposed (including the 3,000-hour 

annual ULSD usage limit) “satisfies the requirement of ensuring an adequate supply of electricity at 

a reasonable cost, and it is the most cost-effective means of providing fuel diversity and supply 

reliability.” See “Final Order Granting Determination of Need for Polk 2-5 Combined Cycle

Conversion” (Jan. 8, 2013), at 2-4, in the administrative record. The commenter did not provide any 

support for a suggested annual ULSD usage limit of 100 hours or any documentation for why this 
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limit would be more appropriate than that proposed by the applicant. EPA concludes that the 

applicant provided adequate justification for requesting an annual ULSD usage limit of 3,000 hours 

for the four turbines combined.

Finally, the commenter contends that the proposed BACT limits for ULSD do not meet the 

previously proposed New Source Performance Standard (NSPS) for new electric generating units 

(EGU) (40 CFR part 60, subpart TTTT). It should be noted that EPA will withdraw this proposed 

NSPS and, on September 20, 2013, signed new GHG emission standards for new electric generating 

unit under 40 CFR part 60, subparts Da and KKKK (EPA also proposed to create a new subpart, 

subpart TTTT, as an alternate to amending subparts Da and KKKK). In the newly proposed

standard, as with the previous proposal, EPA does not distinguish between fuel type (natural gas or 

ULSD) from combustion turbines, but set a limit on the overall GHG emissions from an affected 

unit (i.e., 1,000 or 1,100 lb CO2/MWh, depending on the size of the combustion turbine). However, 

and more importantly, the newly proposed NSPS would not be applicable to existing sources that are 

not adding a new EGU. In the context of the proposed NSPS, “EGU” would be either a combustion 

turbine or a boiler, but not simply the addition of a heat recovery steam generator (HRSG) unit. 

Thus, as proposed, the NSPS would not be applicable to TECO’s proposed project to add HRSG 

units to their existing combustion turbines. Furthermore, the definition of BACT in PSD rules at 40 

CFR 52.21(b)(12) states that “in no event shall application of best available control technology result 

in emissions of any pollutant which would exceed the emissions allowed by any applicable standard 

under 40 CFR parts 60 and 61.” Thus, since the proposed NSPS is not yet an “applicable standard 

under 40 CFR parts 60 and 61,” even if this facility was within the source category covered by the 

proposed NSPS, the proposed NSPS emission limits are not a controlling floor for BACT purposes 

since the proposed NSPS is not a final action and the proposed standard may change. See EPA, 

“PSD and Title V Permitting Guidance for Greenhouse Gases” (March 2011) at 25.

2. Comment: The Polk Power Station would include duct firing as part of the HRSG. The applicant 

did not specifically address the additional emissions and loss of heat rate efficiency that results from 

duct firing. (SOB at p.12.) The Region similarly does not address any of the additional emissions or 

loss of heat rate efficiency from duct firing. The top-down BACT analysis requires the Region to 

look at cleaner production processes for achieving the additional on-peak energy that the duct 

burners would provide. Alternatives to duct burners could include battery storage, solar hybrid 

configuration (or a combination battery and solar hybrid), a small combustion turbine, or using the 

auxiliary boiler for supplemental steam. Sierra Club notes that the heat rate from duct burning is 

approximately the same, or worse, than the efficiency of new internal combustion engine generators. 

Addressing the least efficient part of the combined cycle operation of the plant—the duct burning 

peak topping generation—can significantly increase the plant’s overall efficiency without redefining 

the project. There are numerous alternatives for short-term, peak power generation at the scale 

proposed for duct burning that would achieve significant reductions in not only GHGs, but in other 

pollutants. The Region has not addressed any of these alternatives in the draft permit.

Response: According to the applicant, as part of the ten-year site plan that must be submitted 

annually to the Florida PSC showing how TECO will meet its projected load growth, this project 

was evaluated both with and without duct burners. As noted by the commenter, a stand-alone 

combustion turbine may be a suitable alternative to duct burners for supplemental steam. In the 

scenario where duct burners were not included, the applicant considered an additional simple cycle 

combustion turbine. The evaluation revealed that an additional combustion turbine would have an 

efficiency that is 20 percent worse than including duct burners. Based on information provided by 

the applicant, EPA has concluded the other alternatives mentioned by the commenter (battery 
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storage, solar hybrid configuration, or a combination thereof) would not be commercially viable to 

meet the demands of its customers (i.e., they will not be able to meet the timing criteria or scale of 

peaking capacity necessary that the duct burners will provide) and, thus, would redefine the source. 

Therefore, such alternatives were not included in the BACT process. See emails from TECO to EPA 

dated November 22, 2013, and December 13, 2013, in the administrative record.

3. Comment: The Region appropriately concluded that carbon capture and sequestration (CCS) is 

technically feasible because other facilities, such as the Bellingham Energy Center, have installed 

the technology. (SOB at p.13.) However, the Region rejected CCS on the basis that it is cost 

prohibitive. The permit record provides an inadequate basis to reject CCS on those grounds. It 

contains no site-specific analysis supporting the rejection of CCS, and it did not base its conclusion 

on a cost effectiveness analysis of the control technology.

a) The Record Lacks a Site-Specific Analysis of CCS Possibilities

The Region may not reject CCS on the basis of energy, environmental or economic impacts without 

a full analysis of site-specific factors. The applicant bears the burden of showing that a particular 

control technology is not feasible or cost-effective, and the broad conclusions in this record do not 

suffice. Considering that fossil fuel-fired power plants are the nation’s largest individual sources of 

greenhouse gas emissions, it is incumbent on proponents of new plants to characterize potential CCS 

opportunities more precisely.

TECO assumed that CCS would result in an annual cost of $103 per ton of CO2 avoided. (SOB at 

p.13.) TECO did not provide any site-specific information for this estimate, such as a request for 

proposals (RFP) or project-specific engineering analyses. Instead, TECO relied on generic statistics 

provided in a separate application in Texas (El Paso Electric’s Montana Power Station) as the basis 

for its cost estimate. The Texas project does not even contemplate a combined-cycle unit; El Paso 

Electric applied for a PSD permit to construct simple-cycle turbines.

TECO’s reliance on the El Paso Electric CCS cost estimates is particularly troubling because those 

estimates are deeply flawed. El Paso Electric’s application in Texas did not provide any site-specific 

support for its estimate of capital costs for CCS. El Paso Electric merely pulled general cost-per-ton 

estimates from a 2010 CCS Task Force report for natural gas combined cycle units, and escalated 

those costs to reflect 2012 dollars. (See Montana Power Station Application at p.49.) Neither El Paso 

Electric nor TECO made any attempt to issue or even estimate the actual costs of constructing CCS 

at their proposed facilities. Both companies merely relied on generic estimates that are several years 

old for purposes of the BACT analysis. This process does not satisfy PSD permitting requirements.

When determining if the most effective pollution control option has sufficiently adverse economic 

impacts to justify rejecting that option and establishing BACT as a less effective option, a permitting 

agency must determine that the cost-per-ton of emissions reduced is beyond “the cost borne by other 

sources of the same type in applying that control alternative.” NSR Manual at B.44; see also Steel 

Dynamics, Inc., 9 E.A.D. 165 at 202 (2000); Inter-Power, 5 E.A.D. at 135 (“In essence, if the cost of 

reducing emissions with the top control alternative, expressed in dollars per ton, is on the same 

order as the cost previously borne by other sources of the same type in applying that control 

alternative, the alternative should initially be considered economically achievable, and, therefore, 

acceptable as BACT.” (quoting NSR Manual at B.44) (emphasis original)). In this case, TECO’s 

reliance on generic data from El Paso Electric is essentially an admission that the cost effectiveness 

of CCS at its facility is the same as the “typical” case of a similarly situated facility. Based on this 
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representation, the Region therefore MUST require CCS as the BACT control technology because 

there is no site-specific basis for rejecting the control technology.

b) Basis for Rejecting CCS in Relation to Overall Costs of Project is Invalid

The Region’s basis for rejecting CCS as BACT relied on TECO’s faulty and generic cost 

effectiveness estimate of $103 per ton of CO2 avoided. The Region then extrapolated this cost based 

on an 85% removal efficiency to determine that the total capital cost of CCS would be 

approximately $380 million, or 54 percent of the total project cost. The comparison of control 

technology costs to total project costs does not comply with PSD permitting requirements.

When determining if a pollution control option has sufficiently adverse economic impacts to justify 

rejecting that option and establishing BACT based on a less effective option, a permitting agency 

must determine that the cost-per-ton of emissions reduced is beyond “the cost borne by other sources 

of the same type in applying that control alternative.” (NSR Manual at B.44.) This high standard for 

eliminating a feasible BACT technology exists because the collateral impacts analysis in BACT step 

4 is intended only as a safety valve for when impacts unique to the facility make application of a 

technology inapplicable to that specific facility. The Region inappropriately compares the cost of 

CCS to the overall costs of the proposed project. (SOB at p.13.) This is expressly prohibited by the 

NSR Manual. “[A]pplicants generally should not propose elimination of control alternatives on the 

basis of economic parameters that provide an indication of the affordability of a control alternative 

relative to the source.” (NSR Manual at p.B.31 (emphasis added).) To reject CCS, BACT requires a 

demonstration that the costs of pollutant removal are disproportionately high for the specific facility 

compared to the cost of control at other facilities. (NSR Manual, p.B.45.) No such CCS comparison 

was made here. The Region merely stated that the cost of CCS would be 54 percent of the total cost

of the current project. The Region must evaluate the incremental cost of CCS based on the amount of 

CO2 pollution that would be eliminated. It must then compare those costs to similar sources using 

that control technology. If those costs are not disproportionately high at Polk Power Station relative 

to other facilities, then there is no basis to reject CCS due to economic impact.

Response: EPA agrees that a BACT cost-effectiveness analysis generally should include a sitespecific cost estimate. Typically, a PSD permit applicant supports its BACT cost-effectiveness 

analysis with either a site-specific vendor quote or a recent vendor quote for a similar source. As 

explained in EPA’s draft NSR Workshop Manual, however, applicants may rely on other reliable 

data sources to obtain cost estimates. See draft NSR Workshop Manual at B.32-B.33. 

EPA disagrees with the commenter’s contention that TECO’s analysis did not consider site-specific 

factors in determining the cost of utilizing CCS at the Polk Power Station. Contrary to the 

commenter’s argument, TECO did not simply rely on generic statistics provided in the PSD 

application for the El Paso Electric’s Montana Power Station as the basis for its cost estimate.

Rather, TECO utilized El Paso’s cost projection as a baseline, and then adjusted the projection to 

account for site-specific parameters such as an 85 percent capture rate and annual uncontrolled CO2

emissions of 4,384,066 tons. Based on this analysis, TECO projected its annual cost for capture and 

compression only to be over $380 million. GHG transport and storage would drive the actual cost of 

utilizing CCS at the Polk Power Station much higher, particularly since Polk Power Station is a 

considerable distance away from the nearest existing CO2 pipeline. See Figure B-1 in Appendix B of 

“Report of the Interagency Task Force on Carbon Capture and Storage,” dated August 2010

(http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-2010.pdf). The added 

cost of TECO connecting Polk Power Station into the existing pipeline network is expected to be 

substantial. Furthermore, in comments on the draft permit, TECO clarified that the $380 million cost 
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is an annual recurring cost, not a one-time cost. See TECO’s comments on the draft permit dated 

October 23, 2013, in the administrative record.

The commenter correctly points out that the El Paso cost projection that TECO relied on as the basis 

for its cost project was itself based on costs obtained from a relatively recent report generated by an 

interagency task force, of which EPA was a participating member. See “Report of the Interagency 

Task Force on Carbon Capture and Storage,” dated August 2010. EPA considers the data in this 

report to be reliable for purposes of developing a rough estimate of the cost of installing CCS at the 

Polk Power Station. If this initial analysis had indicated a reasonable chance that CCS would be 

cost-effective for the Polk Power Station, EPA would have required TECO to provide a more precise 

cost estimate. However, as explained in the preliminary determination document provided with the 

draft permit, TECO’s initial analysis showed that the cost of utilizing CCS at the Polk Power Station 

far exceeds what EPA would consider to be cost-effective. Thus, EPA did not require TECO to 

perform a more detailed site-specific cost analysis.

EPA agrees that where a control technology has been successfully applied to similar sources in a 

source category, a finding that such technology is not cost-effective for a particular source generally 

should be based on the permitting agency’s determination that the cost-per-ton of emissions reduced 

is beyond “the cost borne by other sources of the same type in applying that control alternative.” 

EPA draft NSR Manual at B.44. However, EPA disagrees with the commenter’s suggestion that 

EPA’s cost-effectiveness determination must always be based solely on a cost-per-ton-of-CO2-

control metric. The NSR Workshop Manual is not a binding regulation that dictates how the 

economic impacts analysis must be conducted in all cases. See draft NSR Workshop Manual, at 1 

(October 1990) (first paragraph of Preface); In re: City of Palmdale (Palmdale Hybrid Power 

Project), PSD Appeal No. 11-07, Slip. Op. 54 n. 39 (EAB Sept. 17, 2012). 

With respect to the use of CCS for GHG control, a comparative analysis based on a cost-per-ton 

metric is currently infeasible. Because of the scant history of BACT analysis for GHG “at this time 

... there is not a wealth of GHG cost-effectiveness data from permitting actions for a permitting 

authority to review and rely on when determining what cost level is considered acceptable for GHG 

BACT.” EPA, “PSD and Title V Permitting Guidance for Greenhouse Gases” (Mar. 2011) at 43. 

Given the lack of GHG cost per ton information available at this time for specific types of facilities, 

as well as other cost variables that are commonly inherent in estimating cost effectiveness for CCS 

systems (e.g., uncertainty of CO2 contract price from pipeline operator, uncertainty of price for land 

acquisition for building pipeline to facility, etc.), we believe that it is reasonable at this time to 

evaluate the economic impacts of CCS as a percentage of the overall project cost. Furthermore, the 

Environmental Appeals Board (EAB) recently found this cost comparison approach to be reasonable 

and consistent with our GHG Guidance, explaining that elimination of CCS where it is found to be 

cost-prohibitive in comparison to the entire project “was neither inappropriate nor impermissible.” 

In re: City of Palmdale (Palmdale Hybrid Power Project), PSD Appeal No. 11-07, slip op. at 54-55 

(EAB September 17, 2012). We therefore disagree with the commenter and continue to believe that 

our rejection of CCS as GHG BACT in Step 4, based on its high cost in comparison to the overall 

project cost, was appropriate and in accordance with EPA guidance and with EAB precedent.
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Comments Submitted by TECO

Comments on the Draft Permit

4. Comment: There are multiple references in the permit, as seen in the redlined permit, to the 

emergency generator diesel engine. Since the 500 kW rating could apply to the generator or the 

engine, TEC requests that after “500 kW,” the emergency generator is specified since the generator 

is rated at 500 kW and not the diesel engine.

Response: EPA acknowledges the need for this clarification; the permit has been changed 

accordingly to clarify that the “500 kW” descriptor applies to the emergency generator rather than 

the diesel engine.

5. Comment: TEC requests “Corrected to ISO Conditions” be added to equipment list on page 4 of 

16, Section II, to reflect that the heat input rate for the CTs/HRSGs with duct burners is at ISO 

conditions. This will allow the maximum heat input rate to be corrected when the unit is not at ISO 

conditions.

Response: The equipment list to which TECO refers actually appears on page 3 of 12. 

Nonetheless, EPA inadvertently omitted this key qualifier with respect to the maximum heat input 

rate. The permit has been revised accordingly.

6. Comment: In Section II Condition C the condition that is referenced in this section should be D 

instead of E.

Response: EPA acknowledges the error in cross-referencing; the specified condition has been 

changed accordingly from “Condition IX.E” to “Condition IX.D”.

7. Comment: TEC requests in Section III Condition A, the reference to pollution control equipment 

be removed. There is no pollution control equipment associated with GHG emissions. Additionally, 

TEC requests the opacity observations requirement be removed as there are no opacity limits or 

opacity monitoring associated with GHG emissions. These requirements are both covered by the 

State of Florida PSD permit for criteria pollutants.

Response: EPA concurs that there are no air pollution control equipment associated with GHG 

emissions as well as no corresponding opacity limitations; thus, there is also no need for opacity 

observations related to GHG emissions. The permit has been revised accordingly.

8. Comment: TEC requests that Section III Condition C, be changed to reference the combination 

of the CT/HRSGs as subject to the initial startup requirements. The CTs themselves are already 

operational in simple cycle mode, compliant with the applicable requirements and will continue to 

operate in simple cycle mode during the construction of the combined cycle units. TEC has redlined 

the multiple references to this distinction throughout the permit.

Response: EPA acknowledges, for clarification purposes, the need to distinguish the subject 

units as a “CT/HRSG” combination rather than just “CTs”. The permit has been corrected 

accordingly where necessary. 
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9. Comment: In Section IV Condition A, TEC requests that the reference to reporting of any failure 

of pollution control equipment be removed as there is no pollution control equipment associated with 

GHG emissions.

Response: As previously stated, EPA concurs that there is no air pollution control equipment 

associated with GHG emissions; thus, there is no need to report any failure of such equipment. The 

permit has been revised accordingly. 

10. Comment: In Section IX, Condition B.1.a, the CTs are already in operation and currently have 

insulation in the critical areas per the OEM’s standards. TEC requests that this area of the permit be 

changed to reflect this.

Change: “insulate the unit” to “maintain insulation in the critical areas per OEM standards”

Response: EPA acknowledges that the CTs are in operation and already have insulation placed 

in the critical areas per original equipment manufacturer’s standards. Therefore, it is more 

appropriate to require that the insulation be maintained to such standards. The permit has been 

revised accordingly.

11. Comment: In Section IX, Condition B.1.b, TEC requests to change periodic cleanings of the of 

the heat exchanger surfaces to perform the inspections and clean as needed. This avoids unnecessary 

cleanings and the inspections will let TEC know if a cleaning is needed. Since excessive cleaning of 

the heat transfer surface will actually degrade the tube finning over time, unnecessary cleaning will 

have a negative effect on efficiency.

Response: EPA acknowledges TECO’s claim that excessive, unnecessary cleaning of the heat 

transfer surfaces will likely result in decreased thermal efficiency; however, EPA also understands 

the value that periodic inspections play in being able to determine when the heat transfer surfaces 

need to be cleaned. It was revealed to EPA during a recent call with the applicant that the HRSGs 

will be manufactured by Alstom and that there will likely be a service agreement between TECO and 

Alstom for the proper maintenance of the units. Therefore, the permit has been revised accordingly

to require inspections and cleanings per manufacturer’s specifications.

12. Comment: In Section IX Condition B.1.a, TEC requests the removal of the requirement to use 

inlet cooling. As part of the on – going engineering, TEC has evaluated this technology further for 

the Polk project and found that inlet air evaporative cooling will essentially have no effect on the 

combined cycle plant gross heat rate (efficiency). This is due to the fact that inlet air evaporative 

cooling adds fixed pressure drop to the combustion turbine air inlet system and reduces the 

combustion turbine exhaust temperature which subsequently reduces the temperature of the steam 

produced in the HRSGs which lowers the steam turbine efficiency. These effects offset the 

combustion turbine efficiency improvement that is achieved with inlet air cooling. Additionally, 

when in use the technology will increase the amount of fuel combusted resulting in an increase in 

GHG mass emissions.
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With Evaporative

Coolers

Without Evaporative

Coolers

Natural Gas Combined Cycle CASE 14* CASE 14B*

Ambient Temperature (oF) 90 90

Combustion Turbines in Operation 4 of 4 4 of 4

Combustion Turbine Load (%) 100% 100%

Evaporative Cooler Status (On/Off) On N/A

Duct Burner Status (On/Off) On On

Plant Gross Output (MW) 1,127 1,097

GHG Emissions (lb CO2e/hr) 990,300 961,526

Plant Gross Heat Input (MMBtu/hr HHV) 8,464 8,236

Plant Gross Heat Rate (Btu/kWh HHV) 7,509 7,507

*Data from Black & Veatch

As seen in the table above, with evaporative coolers the efficiency (i.e. plant gross heat rate) gets 

worse by 0.03% and the heat input and hourly CO2e emissions increases by 3.0%. TEC has 

evaluated the emission limits for all modes of operation when removing the inlet cooling technology 

and no change to the emission limits is necessary.

Response: Based on the updated performance and emissions data that ongoing engineering of the 

Polk Power Station has provided, EPA concurs with the TECO’s determination that inlet air 

evaporative cooling will not be a suitable means by which to maximize thermal efficiency and

minimize GHG emissions. EPA has, therefore, revised the permit to no longer require inlet air 

evaporative cooling.

13. Comment: In Section IX Condition B.2, TEC requests that the basis for the emission limits 

shown in this condition for the use of simple cycle and USLD fuel oil reflect the emission limitations 

expressed in the GHG application and subsequent addendums. The emission limit calculations relied 

upon in the application and in subsequent discussions and dialogue with EPA were expressed as in 

the table below:

GHG Emissions Limits (per CT/HRSG (combined cycle) or CT (simple cycle) on gross heat input 

basis

USLD Oil Combined Cycle 1,235 lb CO2e/MWh (corrected to ISO conditions) – 3 hour 

average

Natural Gas Simple Cycle 1,320 lb CO2e/MWh (corrected to ISO conditions) – 3 hour 

average

USLD Oil Simple Cycle 1,868 lb CO2e/MWh (corrected to ISO conditions) – 3 hour 

average

TEC requests this change because the applied for limitations were based off a 3 hour annual test at 

full load and ISO conditions and not a rolling average as described in the draft permit. TEC will 

demonstrate compliance as described in the redlined permit, Section IX Condition 10.b.
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Response: EPA acknowledges that, for operating scenarios other than combined cycle/natural 

gas, the basis (i.e., 3-hour annual test at full load and ISO conditions) for the respective emission 

limits expressed in Condition IX.B.2. does not accurately reflect what was submitted in the 

application and subsequent addendums, or presented during other discussions. This was simply an 

error on the part of EPA. EPA believes a 3-hour annual test to be both appropriate and sufficient to 

assure compliance with the emission limits for the other three operating scenarios since the facility is 

neither expected to operate in said scenarios very often nor continuously for extended periods of 

time. The permit has been revised to appropriately include the basis for the specified emission limits 

in Condition IX.B.2. and newly added Condition IX.D.10.b. 

14. Comment: In Section IX, Condition B.3 and B.5, TEC requests that the operating hours be on a 

calendar year/calendar day basis instead of a rolling average. This change will make the GHG PSD 

permit consistent with the Florida criteria pollutant PSD permit. An analysis by TEC indicates that 

rolling versus calendar year (or day) methods are essentially equivalent under the expected operating 

scenario.

Response: For the practical enforceability of the operational limits specified in Conditions 

IX.B.3. and IX.B.5., the compliance time frames need to be based on a rolling 12-month basis rather 

than a calendar year basis. This is in keeping with EPA’s guidance on limiting potential to emit in 

new source permitting. See EPA’s “Guidance on Limiting Potential to Emit in New Source 

Permitting” (June 13, 1989) at 9-10.

15. Comment: In Section IX, Condition C.3., TEC requests removal of the required use of the circuit 

breakers as electrical interrupters in the event of a power surge. Circuit breakers are used for many 

other reasons as well. Their use is not considered relevant to the issue of GHG emission control as 

such use does not affect GHG emissions.

Response: EPA acknowledges the fact that circuit breakers are used for purposes other than “as 

electrical interrupters in the event of a power surge.” EPA also understands that the methods in 

which the circuit breakers are used are not as critical as the standards to which they are maintained 

when considering GHG emissions and the control of such emissions. The first sentence of 

Condition IX.C.3. has been removed.

16. Comment: In Section IX, Condition C.4, TEC requests that the permit be revised to require 

inspection of natural gas piping components periodically instead of on a daily basis and that any 

detected leaks be repaired as soon as practicable instead of immediately. TEC currently follows 

standard industry practices to periodically inspect piping and experience with this procedure shows 

that a daily inspection is unnecessary and overly burdensome. Additionally, natural gas at Polk 

Power Station has an odorized tracer in it which will ensure that TEC will identify any potential leak 

in a reasonable time.

Response: EPA acknowledges that daily inspection of the natural gas piping components (for 

leaks) may be excessive, particularly in light of the fact that TECO already follows industry standard 

for periodic inspections of once every 4.5 months (see 49 CFR 192) and that the commercially 

available natural gas used at Polk Power Station contains an odorized tracer for relatively quick leak 

detection. Nonetheless, TECO has proposed monthly inspections of the natural gas piping 

components. See email from TECO to EPA dated December 13, 2013, in the administrative record. 

EPA believes this frequency to be sufficient based on the fact that it is considerably more rigorous 

than the aforementioned industry standard. With respect to the time frame for repairs, EPA believes 
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that the term “immediately” needs to remain since the purpose of the inspections is to reduce, if not 

eliminate, GHG emissions as methane. The permit has been revised accordingly.

17. Comment: TEC also requests that the circuit breakers be inspected periodically instead of on a 

daily basis and that Section IX Condition E.2.b be changed accordingly. TEC monitors the existing 

Polk Power Station circuit breakers for SF6 emissions in accordance with the 40 CFR Part 98 (EPA 

Mandatory GHG Reporting Rule), Subpart DD requirements. TEC also monitors the breakers 

continuously with low pressure alarms.

Response: EPA acknowledges that requiring daily visual inspections of the circuit breakers may 

be unnecessarily burdensome, particularly in light of the fact that the circuit breakers are equipped 

with low pressure sensors that are monitored continuously. As long as the sensors do not set off an 

alarm, it can be assumed that the circuit breakers are not leaking (resulting in SF6 emissions) and are 

working as designed. Furthermore, EPA acknowledges the vagueness of the term “periodic”. 

Therefore, the permit has been revised to not only remove the terms “on a daily basis” and 

“periodic” with respect to visual inspections and maintenance, but to include the requirement that 

such activities be conducted in accordance to the manufacturer’s standards.

18. Comment: In Section IX Condition F.1., TEC requests that this broad recordkeeping requirement 

be revised to apply only to the equipment addressed by the PSD GHG permit and only to 

adjustments/maintenance activities that are relevant to GHG emissions.

Response: EPA acknowledges the preference of limiting the scope of the recordkeeping 

requirements to the equipment subject to this PSD GHG permit and has no concerns doing so. 

However, EPA believes the more appropriate place to make this distinction is in opening of

Condition IX.F.1. rather than in subparagraph a. of said condition. The permit has been revised 

accordingly.

19. Comment: In addition to the comments described above, there are various administrative 

corrections that TEC requests be applied to the final permit. These corrections are shown in the 

attached redline of the draft permit.

Response: EPA acknowledges the need for these corrections (which include such errors as an 

erroneous street address for the facility, an incorrect reference to the currently effective title V 

permit, and an erroneous specification of an existing unit’s capacity). The permit has been corrected 

accordingly. See EPA’s redline/strikeout version of the permit for all changes.

Comments on the Preliminary Determination & Statement of Basis

20. Comment: In Section 3, the project construction is described as starting in February 2014. The 

project construction will begin in January 2014.

21. Comment: In Section 4.3, TEC requests that the permit conditions be incorporated into the State 

of Florida’s Title V permit as required by PSD – FL – 421, the Polk 2 Combined Cycle state criteria 

pollutant air construction permit. In the State of Florida, the conditions are incorporated into the 

Title V permit after construction of the project.
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22. Comment: In Section 6.1, Maximum Energy Efficiency, TEC requests removal of CT inlet 

cooling for the reasons explained above in Comment No. 7. There are also multiple instances in the 

Section 6.1 BACT analysis where CT inlet cooling is mentioned.

23. Comment: In step 3 & 4 of the BACT assessment, it is indicated that the estimated $380 million 

cost of CCS is 54% higher of the overall project cost. However, the $700 million cost of the project 

is a capital cost. The estimated $380 million cost of CCS is an annual recurring cost meaning that the 

cost of CCS actually is significantly higher than 54% of the one-time project cost of $700 million.

24. Comment: Step 5 of the BACT assessment should indicate that the basis for the simple cycle and 

ULSD fuel oil-firing operating mode GHG emission limits is an annual 3 – hour stack test at full 

load corrected to ISO conditions.

25. Comment: In addition to the comments described above, there are various administrative 

corrections that TEC requests be applied to the final preliminary determination and statement of 

basis. These corrections are shown in the attached redline of the preliminary determination and 

statement of basis.

Response: EPA acknowledges receipt of the above comments related to the preliminary 

determination/statement of basis. However, any resulting changes will be appropriately reflected in 

the redline/strikeout version of the permit (and summarized in the final determination) rather than a 

redline/strikeout version of the preliminary determination/statement of basis.