1 

## 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 1 8 , 20132 

## 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

................................ .................. 93

I. Introduction

The U.S. Environmental Protection Agency, Region 4 (EPA) proposed to issue a Prevention of Significant Deterioration (PSD) pe rmit 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 2 5

, 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 regar ding 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 request s 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

- 0 648 ) 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 propose d 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 emitting4

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 limit s 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 requ irements 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 perio d 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. TEC O 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

cle arly 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 ex ceed 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. T he 3,000

- hour annual ULSD

usage limit is based on information provided in the application as well as on additional informa tion submitted by the applicant in response to EPA’s incompleteness determination

. See correspondence

dated December 1 9 , 2012, in the administrative record. Specifically , the applicant explained that the

annual allowance of 3 ,000 hours of ULSD operation fo r all four turbine s 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 cu rtailments ( 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) grant ed 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) “ s atisf ies 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. T he commenter did not provide any support for a suggested annual ULSD usage limit of 100 hours or any documentation for why this5

limit would be more appropriate than that proposed by the ap plicant. EPA concludes that the applicant provided adequate justification for requesting an annual ULSD usage limit of 3 ,000 hours

for the four turbine s combined

.

Finally, the commenter contends that the proposed BACT limit s for ULSD do not meet the previously proposed N ew S ource P erformance S tandard (NSPS) for new electric generating units (EGU) ( 40 CFR part 60, subpart TTTT). It should be noted that EPA will withdr a w this proposed

NSPS and

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

unit under 40 CFR part 60, subpart s Da and KKKK (EPA also proposed to create a new subpart, subpart TTTT, as an alternate to amending subparts Da and KKKK) . In the new ly proposed standard, as with the pre vious 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 CO 2 /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 generat or ( 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, t he definition of BACT in PSD rules at 40 CFR 52.21(b)(12) st ates 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 a n “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 requi res 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 sol ar 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.

Addr essing 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 appli cant, 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

combust ion 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

t he applicant , EPA has concluded the other alternatives mentioned by the commenter (battery6

storage, solar hybrid configurati on, 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 redefin e the source. Therefore, such alternatives were not included in the BACT process

. See email s 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 Ana lysis 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 feas ible 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 charact erize 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 contemplat e 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 appli cation 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 c osts 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 g eneric 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 Man ual 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, TEC O’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 this7

representation, the Region therefore MUST re quire 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 th at 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 alterna tives 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 re moval 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 dispropor tionately 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 site

specific 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 r eliable

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 Powe r 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 projec tion as a baseline, and then adjusted the projection to

account for site

- specific parameters such as an 85 percent capture rate and annual uncontrolled CO 2 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 CO 2 pipe line

. 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 clarif ied that the $380 million cost8

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 re lied 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 St orage ,” 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 b e

cost

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

cost estimate. However, a s explained in the p reliminary d etermination 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 ap plied 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 ap plying 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

- CO 2 - 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 Palmdal e (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 T itle 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 CO 2 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). W e 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.9

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 t he “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 o mitted 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 se ction 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 c ontrol 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

o perational 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 dis tinction throughout the p ermit.

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.10

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 con trol equipmen t 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

insulatio n 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 a re 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, unnec essary 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

nee d to be cleaned. It was r evealed 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 agree ment between TECO and

Alstom for the proper maint e n ance of the units. Therefore, t he permit has be en revised a ccordingly 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 tech nology 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 t o 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 tu rbine 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.11 With Evaporative

Coolers Without Evaporative

Coo lers Natural Gas Combined Cycle CASE 14* CASE 14B* Ambient Temperature ( o F) 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 CO2

e /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 chang e 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

minimiz e 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 emis sion 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 d iscussions and dialogue with EPA were e xpressed 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 CO 2 e/MWh (corrected to ISO conditions)

– 3 hour

aver age Natural Gas Simple Cycle 1, 3 2 0 lb CO 2 e/MWh (corrected to ISO conditions)

– 3 hour

average USLD Oil Simple Cycle 1, 868 lb CO 2 e/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.12

Response: EPA acknowledges that, for o pe rating 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. do es 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 operati ng scenarios since the facility is

neither expected to operate in said scenarios very often nor contin uously 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 th e Florida criteria pollutant PSD permit. An analysis by TEC indicates that rolling versus calendar year (or day) methods are essentially equivalent under t he expected operating

scenario.

Response: For the practical enforceability of the operational limit s 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 p urposes 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 unnecess ary and overly burdensome. Additionally, natural gas at Polk Power Station has an odorized tracer in it which will ensure that TEC will identify any poten tial 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 ( s ee 49 CFR 192) and that the commercially

available natural gas used at Polk Po wer 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 beli eves 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 repair s
, EPA believes13

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

continu ously wit h 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 SF 6 emissions) and are working as designed

. Furthermore, EPA acknowledges the vagueness of the term “periodic ”. Therefore, t he 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 em issions.

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 perm it. These corrections are shown in the

attach ed 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 eff ective title V permit, and an erroneous specification o f an existing unit ’s capacit y) . 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 aft er construction of the project.14

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 ste p 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 recu rring cost meaning that the cost of CCS actually is significantly higher than 54% of the one

- time project co st 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 m ode GHG emission limits is an annual 3

– hour stack test at full

lo ad 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 det ermination and statement of basis. These corrections are shown in the attached redline of the preliminary determ ination 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.