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IN PARTNERSHIP WITH THOSE WE S ERVE 

### May 30, 2012

Mr. Tom Rogers Florida Department of Environmental Protection Division of Resource Management 2600 Blair Stone Road, MWS 5500 Tallahassee, Florida 32399-2400

Re: Seminole Electric Cooperative, Inc. (SECI) Seminole Generating Station (SGS) Units 1 and 2 Regional Haze Rule (RHR)

- Reasonable Progress (RP) Analysis

Dear Mr. Rogers:

SECI operates two solid fuel-fired electrical generating units (EGUs) at its SGS located

near Palatka, Putnam County, Florida. Operation of SGS Units 1 and 2 is currently authorized by Florida Department of Environmental Protection (FDEP) Title V Final Permit No. 1070025-017-AV, issued with an effective date of January 1, 2010, and an expiration date of December 31, 2014.

This submission is made in a cooperative effort to address RHR implementation issues resulting from recent regulatory developments related to the U.S. Environmental Protection Agency's (EPA's) Clean Air Interstate Rule (CAIR) and its successor, the CrossState Air Pollution Rule (CSAPR). CSAPR is currently stayed, and CAIR remains in effect, pending judicial review of CSAPR. Depending on the court's decision on CSAPR, SECI may revisit, revise, or withdraw this analysis and proposal.

According to Florida's RHR State Implementation Plan (SIP), SGS Units 1 and 2 are subject to RHR RP requirements. SECI proposes to meet FDEP's RP requirements for SGS Units 1 and 2 by implementing the following for each unit:

• Seek a permit modification to remove petroleum coke as an approved fuel.

• Upgrade the existing flue gas desulfurization (FGD) emissions controls to achieve a minimum sulfur dioxide (S02) removal efficiency of 95 percent or, alternatively, an equivalent S02 emissions rate of no more than 0.25 poundper million British thermal units (lbIMMBtu) of S020n a 30-day rolling average basis for both limits.

The proposed S02 emissions limits for SGS Units 1 and 2 represent top-level emissions controls and therefore satisfy FDEP's RP requirements. The following sections provide information regarding FDEP's RP requirements, existing emissions controls, historical and current S02 emissions rates, and a RP analysis and proposal for SGS Units 1 and 2.

16313 North Dale Mabry Highway P

. O

. B ox 272000 Tampa
, Florida 33688-2000 Telephone 813

. 963

. 0994 Fax 813

. 264

. 7906 www.seminole-electric

. com

### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 2



### REASONABLE PROGRESS REQUIREMENTS

The 1977 Clean Air Act Amendments established a national goal of "preventing future, and remedying existing, visibility impairment" in 156 national parks and wilderness
areas, referred to as "mandatory Class I federal areas." In response to this congressional mandate, EPA issued a rule addressing regional haze on July 1, 1999. The RHR set a long-term ultimate goal of returning visibility in the Class I areas to "natural conditions" by the year 2064. Natural conditions represent the visibility that would exist in Class I

areas without any impairment due to human activities; i.e., under prehistoric and pristine conditions.

A key component of the RHR is that states must determine reasonable progress goals (RPG) toward attaining the goal of preventing any future, and remedying any existing, impairment of visibility in mandatory Class I federal areas. In determining their RPGs,
states must consider the following four factors:

• Costs of compliance.

• Time necessary for compliance.

• Energy and nonair quality environmental impacts of compliance.

• Remaining useful life of any potentially affected sources.

In addition, states must also consider the rate of progress needed to reach natural visibility conditions by 2064. This consideration is referred to as the "uniform rate of progress,"

or the "glidepath."Protections implementing these RPG requirements have been promulgated in the Code of Federal Protections (CFR) under Chapter 40, Part 51, Subpart P,Protection of Visibility. 40 CFR 51.308 specifically addresses the regional haze program requirements. EPA has developed guidance for implementing the RPG requirements (reference the Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program revised June 1, 2007).

FDEP's draft Regional Haze Plan for Florida Class I Areas (RH Plan) submitted to EPA

on April 13, 2012, indicates that RP for Florida emissions sources will be confined to S02, since reductions in emissions of this pollutant will provide the greatest benefit to visibility improvement. The FDEP RH Plan also identifies the specific Florida emissions units that FDEP has determined are subject to RP review. The selection of Florida emissions units subject to RP review was based on the ratio of 2002 S02annuai emissions (Q, in tons) and distance (D, in kilometers [km]) from a Class I area. If the 

### Q/D ratio is 50 or greater, the emissions source was considered to have a significant impact on visibility impairment and therefore be subject to RP review. On May 25, 2012, EPA proposed to approve FDEP's analysis regarding the pollutants and source categories that most contribute to visibility impairment in Class I areas (i.e., to focus solely on S02and industrial point sources of S02emissions including EGUs and non-EGUs) and FDEP's methodolo### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 3

gy for prioritizing the most significant contributors to regional haze (i.e., use of a 

### Q/D ratio greater than 50).

A summary of SGS Units 1 and 2 

### Q/D ratios for the baseline year (i.e., 2002) and 2011

are shown in the following table. Although S02emissions for Units 1 and 2 have been reducedfrom 2002, current 2011 levels still exceed the QID 

### threshold of 50 as shown in the following table:

Parameter Units Unit 1 Unit 2



### 2002 S02 emissions tpy 10,912 12,775 2011 S02 emissions tpy 7,216 7,754

Chassahowitzka NWR Distance km 141.6 141.6 

### 2002 Q/D Ratio tpy/km 

### 77.1 90.2 

### 2011 Q/D Ratio tpy/km 

### 51.0 54.8

Okefenokee NWR Distance km 121.8 121.8 

### 2002 Q/D Ratio tpy/km 

### 89.6 104.9 

### 2011 Q/D Ratio tpy/km 59.2 63.7

Note: tpy = 

### ton per year.

Distances from SGS Units 1 and 2 to the other two Florida Class I areas, which are considered to have visibility as an important value (i.e., Everglades National Park [491.8 km] and St. Marks National Wildlife Refuge [NWR] [247.0 km]), are much greater than those shown in this table for the Okefenokee NWR. Accordingly, the Okefenokee NWR represents the constraining Class I area with respect to RP applicability based on the 

### Q/D ratio metric.

SGS Units 1 and 2 

### are subject to the requirements of the CAIR. With respect to the RHR RP requirements, EPA previously determined that emissions sources subject to the CAIR S02and nitrogen oxides (NOx) trading programs would achieve greater reasonable progress than best available retrofit technology (BART); therefore, these two pollutants would not need to be subject to a BART analysis. The CAIR requirements were also considered to satisfy the RHR requirement for a long-term strategy sufficient to achieve state-adopted RPGs.

### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 4

Due to legal challenges to CAIR, EPA issued a final rule on July 6, 2011, to replace CAIR; i.e., CSAPR. For Florida EGUs, CSAPR only requires participation in the ozone
season NOxtrading program. Similar to the approach taken for CAIR, on December 30, 2011, EPA proposed to consider EGUs subject to CSAPR to have emissions rates "better than BART" and, therefore, exempt from BART review. In its proposal, EPA included a limited disapproval of Florida's regional haze SIP with respect to BART, since CSAPR for Florida EGUs only addresses NOxemissions and therefore cannot be relied upon to control S02emissions. However, EPA's December 30,2011, proposal specifically did not disapprove Florida's RPG for 2018 noting "that the reasonable progress goals are not mandatory standards in the sense of there being consequences if they are not met, because there are inherent uncertainties in projecting future emissions and resulting visibility conditions." EPA also noted the requirement for midcourse reviews of the status of the RPGs and a correction to a state's RH SIP in the event current implementation strategies

are not sufficient in meeting the RPGs. In addition, on December 30, 2011, the court stayed CSAPR and left CAIR in effect pending judicial review.



### UNITS 1 AND 2 S02 EMISSIONS CONTROL SYSTEMS

SGS Units 1 and 2 are solid fuel, dry-bottom, wall-fired units each with a maximum heat input of 7,172 million British thermal units per hour (MMBtu/hr). Units 1 and 2 are currently authorized to bum coal as the primary fuel but are also authorized to bum a blend of coal and petroleum coke up to a maximum of 30 percent by weight petroleum coke. The maximum sulfur content of petroleum coke may not exceed 7.0 percent by weight on
a dry basis. This sulfur content limit for petroleum coke is 2.3 times the design coal nominal sulfur content of 3.0 percent by weight. Units 1 and 2 are each equipped with S02continuous emissions monitoring systems as required by the Acid Rain Program and CAIR.

In addition to electrostatic precipitators for control of particulate matter (PM), 10w-NO x burners, and selective catalytic reduction (SCR) forNO x contro1 and an alkali injection system to control emissions of sulfuric acid mist, Units 1 and 2 are each equipped with
wet FGD scrubbers to control S02emissions. The original FGD controls were upgraded in 2010 to comply with CAIR and other air regulatory initiatives (e.g., the Clean Air Mercury Rule). Improvements to the FGD systems included scrubber module modifications, upgrades to the module's mist eliminator wash system, expansion of the oxidation air system, and upgrades to the existing sparger rings in the absorber recycle tanks. Following these upgrades, the allowable S02emissions rate for Units 1 and 2 was reduced from 1.2 to 0.67 1b/MMBtu.



### UNITS 1 AND 2 S02 EMISSIONS RATES

Table 1 provides a summary of 2002 and 2007 through 2011 S02emissions rates for SGS Units 1 and 2. Data shown was obtained from the EPA Clean Air Markets Website and

### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 5

SEcr annual operating reports. As shown in Table 1, current actual S02emissions are well below the 2002 baseline levels reflecting the FGD upgrades that were made in 2010.

REASONABLE PROGRESS ANALYSIS AND PROPOSAL



### Wet FGD technology provides the highest S02removai efficiencies for coal-fired boilers. The SGS Unit 1 and 2 FGD control systems currently achieve approximately 92-percent S02removal. SECr proposes to make additional changes to Units 1 and 2 to achieve a minimum S02removai efficiency of 95 percent or, alternatively, an equivalent S02emissions rate of no more than 0.25 Ib/MMBtu on a 30-day rolling average basis for both limits.

SEcr is presently evaluating available options to achieve the proposed S02removai efficiency or emissions limit including, but not limited to, further modifications to the internal components of the FGD scrubbers, increase in limestone recirculation rates, and increased used of dibasic acid. SECr proposes to complete its evaluation and provide FDEP with the details of the selected option by March 1, 2013.

The amount of time required to implement the selected option and achieve the proposed S02emissions limits will depend on the option's design and if construction is required. Within 1 to 3 years following option selection (i.e., no later than March 1, 2016), SECr proposes to achieve either the proposed S02emissions limit or the removal efficiency requirements.

SECI's RP proposal for SGS Units 1 and 2 is based on the following considerations:

• The proposed S02emissions limits are consistent with EPA's "presumptive" BART limits. The 40 CFR 51, Appendix Y, BART presumptive S02emissions limit for utility boilers greater than 200 megawatts (MW) is a minimum S02removai efficiency of 95 percent or anS02emissions limit of 0.15Ib/MMBtu.

• The proposed S02emissions are consistent with the top-level controls determined as BART for similar coal-fired boilers; e.g., Tampa Electric Company's Big Bend Station Units 1,2, and 3 (which EPA proposed to approve
on May 25,2012).

• Current 2011 actual Unit 1 and 2 S02emissions rates are approximately 24 and 32 percent, respectively, below 2002 baseline levels.

• The proposed S02emissions limit of 0.251b/MMBtu represents a 62.7-percent decrease from the current permit limit ofO.67Ib/MMBtu.

### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 6

• Modeling conducted by the Visibility Improvement State and Tribal Association of the Southeast indicates that the 2018 base control scenario will result in visibility improvements approximately equal to the uniform rates of progress for the Class I areas affected by Florida emissions sources. Since the 2018 base control scenario does not include visibility improvements due
to S02emissions reductions from emissions units subject to RP, actual visibility improvement in 2018 is expected to be better than the uniform rates of progress; i.e., the glidepaths are expected to be achieved in 2018 without further emissions reductions from RP emissions sources.

• EPA's May 25,2012, proposed rule regarding Florida's RHR SIP noted that state RPGs are not mandatory emissions standards that must be achieved by

a particular date. The S02emissions rates proposed as RP for SGS Units 1 and 2 reflect top-level controls and will be achieved no later than March 1, 2016, and possibly as early as 2014 depending on the selected control strategy. The 2014 and 2016 compliance dates are 4 and 2 years, respectively, prior to the end of first 10-year RHR implementation period in 2018.

• Removal of petroleum coke as an authorized fuel for SGS Units 1 and 2 will reduce the potential S02loading to the FGD control systems resulting in lower potential outlet S02emissions rates.

In addition, SGS Units 1 and 2 are also subject to the recently adopted National Emissions Standards for Hazardous Air Pollutants for coal-fired steam EGUs codified as 40 CFR 63, SUbpart UUUUU. This rule, also known as the Mercury and Air Toxics Standards (MATS) or Utility MACT, was issued with an effective date of April 16, 2012, and requires the installation of maximum achievable control technology (MACT). For existing EGUs, MATS contains alternative, surrogate emissions limits for PM and S02with a compliance deadline of Apri116, 2015. As stated in 40 CFR 51, Appendix Y:

"We believe that, in many cases, it will be unlikely that states will identify emissions controls more stringent than the MACT standards without identifying control options that would cost many thousands of dollars per ton. Unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, you may rely on the MACT standards for purposes of BART."

The reasoning described herein for BART is also applicable to RP review since the two technology reviews are essentially the same.

In summary, SECI requests that FDEP determine the S02emissions limit or 95-percent FGD removal, and the implementation schedule proposed for SGS Units 1 and 2

### Mr. Tom Rogers Florida Department of Environmental Protection May 30, 2012 Page 7

represent top-level controls and thus comply with the RHR 

### and FDEP RP requirements. Please contact me at (813) 739-1224 ifthere are any questions concerning this submittal.

Sincerely,

# I~**(o/~**
Mike Roddy Director of Environmental AffairsTable 1. SGS EPA Clean Air Markets Data

Parameter Units 2002 2007 2008 2009 2010 2011

Petroleum coke sulfur content* weight % 6.23 5.49 5.49 Coal sulfur content* weight % 3.01 3.00 2.96 2.99 3.05 2.96 Unit 1 Petroleum coke amount burned* tpy 175,428 79,201 15,347 0 0 0 Coal amount burned* tpy 1,462,320 1,866,677 1,621,119 1,132,522 1,767,397 1,647,920 Heat input MMBtu/yr 48,585,738.5 47,514,835.2 38,980,523.9 29,206,823.6 46,505,474.4 41,651,671.4 S02 emissions (uncontrolled) tpy 109,874.4 120,591.2 97,547.3 67,635.7 107,754.1 97,395.7 IblMMBtu 4.52 5.08 5.00 4.63 4.63 4.68 S02 emissions (controlled) tpy 11,095.2 10,127.3 8,088.4 7,709.3 8,482.5 7,215.8 IblMMBtu 0.46 0.43 0.41 0.53 0.36 0.35 FGD S02 removal % 89.9 91.6 91.7 88.6 92.1 92.6 Unit 2 Petroleum coke amount burned tpy 169,260 109,560 16,768 0 0 0 Coal amount burned tpy 1,514,054 1,774,142 2,004,995 1,783,795 1,730,700 1,800,020 Heat input MMBtu/yr 49,474,872.9 48,617,949.2 50,653,964.3 45,703,994.0 44,789,773.0 43,100,021.5 S02 emissions (uncontrolled) tpy 112,220.8 118,377.7 120,403.2 106,530.6 105,516.8 106,385.1 IblMMBtu 4.54 4.87 4.75 4.66 4.71 4.94 S02 emissions (controlled) tpy 12,988.0 10,207.9 11,194.2 12,867.6 8,477.2 7,754.4 IblMMBtu 0.53 0.42 0.44 0.56 0.38 0.36 FGD S02 removal % 88.4 91.4 90.7 87.9 92.0 92.7

Note: tpy 

### = ton per year. MMBtulyr 

### = million British thermal units per year. IblMMBtu 

### = pound per million British thermal units.

*Data from SECI Annual Operating Reports.

# F. Lakeland McIntoshJune 2012 1 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx 

### REASONABLE PROGRESS ANALYSIS
LAKELAND ELECTRIC

– C. D. MCINTOSH, JR. POWER PLANT

– UNIT 3

INTRODUCTION This submission is made in a cooperative effort to address regional haze rule (RHR) implementation issues resulting from recent regulatory developments related to the U.S. Environmental Protection Agency’s (EPA’s) Clean Air Interstate Rule (CAIR) and its successor, the Cross -State Air Pollution Rule (CSAPR). CSAPR is currently stayed, and CAIR remains in effect, pending judicial review of CSAPR. Depending on the court’s decision on CSAPR, Lakeland Electric may revisit, revise or withdraw this analysis and proposal.

Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous sources over a wide geographic area. EPA’s regional haze regulations are contained in Title 40, Part 51 of the Code of Federal Regulations (40 CFR 51). EPA promulgated the RHR on July 1, 1999. Under Section 51.308(d)(1) of t he RHR, states must “establish goals (expressed in deciviews) that provide for reasonable progress (RP) towards achieving natural visibility conditions” for each Class I area within a state. These reasonable progress goals (RPGs) must provide for an improvement in visibility for the most impaired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period.

RPGs are interim goals and are to be established for the final year in each planning period, which is 2018 for the first planning period. The interim goals represent incremental visibility improvement over time toward the goal of natural background conditions. In determining what would constitute reasonable progress towards achieving natural visibility conditions, Section 169A(g) of the Clean Air Act (CAA) requires states to consider the following four factors:

 The costs of compliance

 The time necessary for compliance

 The energy and non-air quality environmental impacts of compliance

 The remaining useful life of existing sources that contribute to visibility impairment
In addition, states must submit a state implementation plan (SIP) and demonstrate in their SIPs how these four factors are taken into consideration in selecting the RPG for each Class I area in the state.

As part of this demonstration, states must consider the rate of progress needed to reach natural visibility conditions by 2064. This consideration is referred to as the “uniform rate of progress” or the “glidepath”. Regulations implementing these RPG requirements have been promulgated in 40 CFR 51, Subpart P

– Protection of Visibility. Section 51.308 specifically addresses the regional haze program requirements. EPA has developed guidance for implementing the RPG requirements

– reference “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program” revised June 1, 2007.June 2012 2 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx The Florida Department of Environmental Protection (FDEP) draft Regional Haze Plan for Florida Class I Areas (RH Plan) submitted to the EPA on April 13, 2012 indicates that RP for Florida emission sources will be confined to sulfur dioxide (SO 2 ), since reductions in emissions of this pollutant will provide the greatest benefit to visibility improvement. The FDEP RH Plan also identifies the specific Florida emission units that FDEP has determined are subject to RP review. The selection of Florida emission units subject
to RP review was based on the ratio of 2002 SO 2 annual emissions (Q in tons) and distance (D in kilometers) from a Class I area. If the Q/D ratio is 50 or greater, the emission source was considered to have a significant impact on visibility impairment and therefore to be subject to RP review. On May 25, 2012, EPA proposed to approve FDEP’s analysis regarding the pollutants and source categories that most contribute to visibility impairment in Class I areas [i.e., to focus solely on SO 2 and industrial point
sources of SO 2 emissions including electrical generating units (EGUs) and non- EGUs], and FDEP’s methodology for prioritizing the most significant contributors to regional haze (i.e., use of a Q/D ratio > 50). In its RH Plan, FDEP states that the Lakeland Electric McIntosh Unit 3 had a Q/D ratio greater than 50 for
the Chassahowitzka PSD Class I Area.

The RP analysis for McIntosh Unit 3 is presented in the following sections.



### RP ANALYSIS FOR MCINTOSH UNIT 3 Based on EPA’s “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program”, there are four statutory factors as previously identified that can be applied to a stationary source to evaluate potential emission control measures and the level of control that can be applied to the source to meet the visibility goals under the RPG.

Unit 3 at the McIntosh Plant is a nominal 364-megawatt (MW) fossil fuel-fired steam generator, which may burn coal, low sulfur fuel oil with maximum 0.5 percent sulfur by weight, coal with up to 20 percent petroleum coke (based on weight), high sulfur fuel oil (> 0.5 percent sulfur by weight), and natural gas or propane alone or in combination with any of the other fuels or fuel combinations. The maximum heat input rate is 3,640 million British thermal units per hour (MMBtu/hr). Unit 3 is currently subject to the SO 2 emissions limitations contained in Final Title V Permit No. 1050004- 31 -AV.

Sulfur compounds are produced in coal-fired boilers by the combustion process in which complete oxidation of the fuel-bound sulfur occurs, forming primarily SO 2 , with smaller quantities of sulfur trioxide (SO 3 ). The amount of SO 2 emissions is directly proportional to the sulfur and sulfate content in the fuel. Reducing SO 2 emissions by boiler modification is not feasible because combustion processes do not
affect SO 2 emissions. Generally, complete oxidation of sulfur in fuel is readily achieved before complete combustion of carbon, the most abundant element in fossil fuel. For pulverized coal-fired utility boilers,
SO 2 emission reduction is typically accomplished by treating the post-combustion flue gas with a flue gas desulfurization (FGD) process.June 2012 3 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx Standard FGD processes for pulverized coal-fired boilers are back-end equipment of either the wet or dry type; these are often referred to as wet and dry scrubbing, respectively. Since the early 1970s, FGD has been used extensively in the United States to control SO 2 emissions from coal-fired power plants. Indeed, the use of FGD systems was, in effect, mandated for pulverized coal-fired power plants with the promulgation of the New Source Performance Standards (NSPS) for electric utility steam generating units (i.e., 40 CFR 60, Subpart Da), which required minimum reductions between 70 and 90 percent in the potential combustion concentration of SO 2 . The most widely used systems for large-scale SO 2 removal are the calcium-based wet lime/limestone FGD systems that are recognized to have the highest levels of control. Worldwide, there are over 200,000 MW of installed wet limestone FGD systems, which represent about 80 percent of FGD systems. New wet FGD systems are capable of removing 95 to 98 percent of
SO 2 and have been accepted as Best Available Control Technology (BACT).

Unit 3 is currently equipped with a wet limestone FGD system to control SO 2 emissions. Unit 3 is subject to NSPS Subpart D, which has no minimum SO 2 reduction requirements. However, the current Title V permit requires a 65 percent reduction in SO 2 when the emissions are less than 0.75 pound per million British thermal units (lb/MMBtu) and a 90 percent reduction when emissions are greater than 0.75 lb/MMBtu.
Based on the actual SO 2 emissions reported in 2002, the FGD system reduced SO 2 emissions by
81 percent. The scrubber is of a tray tower type consisting of two absorber modules. Each module provides approximately 55 percent capacity of total unit output. The components of the scrubbing system
are listed below:

Quencher

– Flue gases exiting the electrostatic precipitator (ESP) enter the quenchers for each absorber, which condition the flue gas. Each absorber has a venturi-type quencher with a throat
27 feet long and 5 feet wide. The quench water is recirculated from the quencher sump.

Absorber Tray Tower

– After adiabatic saturation in the quencher, the gases pass up through the tray tower absorber for SO 2 removal. The limestone slurry is introduced at the top of the tray absorber from a series of spray headers. The flow is countercurrent through the 36-f oot -wide (diameter) absorber.

Demister

– Before exiting the absorber, aerosols in the flue gas are removed in a Z-shaped demister made from reinforced fiberglass material.

Associated Equipment

– Supporting the operation of the scrubber are the following equipment: absorber recirculation tank, quencher recirculation tank, and quencher and absorber recirculation pumps. The scrubber is equipped with a hot air reheat system (steam coil) and a bypass flue. The latter bypasses flue gases around the absorber system and mixes with air exiting the absorber tower. This increases the exit gas temperatures. A continuous emission monitoring system is installed to assure compliance with the SO 2 emission limit.June 2012 4 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx Additional equipment/processes supporting the scrubber system include limestone storage and handling, limestone slurry preparation system, slurry storage and transfer system, FGD blowdown, and gypsum dewatering, transfer, and storage.

Unit 3 is currently subject to the following SO 2 emissions limitations as summarized below (see Final Title V
Permit No. 1050004- 31

- AV for detailed description of emission limits and compliance conditions):

 0.80 lb/MMBtu for liquid fossil-fuel firing (3-hour, 40 CFR 60 Subpart D)

 1.20 lb/MMBtu for solid fossil-fuel firing (3-hour, 40 CFR 60 Subpart D)

 0.718 lb/MMBtu for blends of petcoke and any other fuels (30-day rolling average)

 Whenever coal or blends of coal and petroleum coke or refuse are burned, SO 2 gases discharged to the atmosphere from the boiler shall not exceed 10 percent of the potential combustion concentration (90 percent reduction), or 35 percent of the potential combustion concentration (65 percent reduction) when emissions are less than 0.75 lb/MMBtu heat input (30-day rolling average)

These SO 2 emission limits were established as BACT. Continuous burning of natural gas, low sulfur fuel oil, or combinations of these two fuels are allowed with or without the use of the FGD system. If the FGD system malfunctions or if the coal feed is interrupted due to equipment malfunction, the SO 2 emissions limit of 0.8 lb/MMBtu can be achieved by firing high sulfur fuel oil (3-hour average).

Based on the Annual Operating Report (AOR) for the most recent 5-year period, more than 95 percent of the total heat content is due to bituminous coal firing. Lakeland Electric currently buys coal from the Appalachian region, which is delivered via railcar. Based on AOR data, the actual sulfur content of the coal used in Unit 3 averages in the range between 1.2 and 1.4 percent with higher sulfur (>1.9 percent) content depending upon source/delivery.

The RP analysis requires consideration of four factors that include the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and the remaining useful life of existing sources that contribute to visibility impairment. These factors are addressed in the following sections.



### FACTOR 1

– COSTS OF COMPLIANCE The first factor to take into consideration is the “costs of compliance”. EPA’s guidance for RP suggested three factors to consider in assessing compliance costs:
a) Identify the emissions units to be controlled b) Identify the design parameters for emissions controls c) Develop cost estimates based upon those design parametersJune 2012 5 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx As described above, McIntosh Unit 3 has a wet-FGD system that was designed to achieve SO 2 removal. To achieve greater SO 2 reductions from Unit 3, the following options are available:
1) Lower sulfur content of fuel such as coal, which typically has the highest sulfur content among the fuels authorized for Unit 3; or 2) Modification of the existing FGD system to achieve additional SO 2 control; or 3) Replacement of the current FGD system with units designed to achieve 95 to 98 percent SO 2 removal.
Among the authorized fuels for Unit 3, petcoke has the highest sulfur content, an average of 3.9 percent by weight. Bituminous coal, with an average of 1.8 percent sulfur, is the fuel with next highest sulfur content. Lakeland Electric is authorized to burn up to 20 percent petcoke by weight with bituminous coal
and as a result, the average sulfur content of the combined fuel (coal and petcoke) can be as high as
3.48 percent (80 percent coal with 1.8 percent sulfur and 20 percent petcoke with 3.9 percent sulfur) due to the high sulfur content of petcoke. Based on the AOR for the most recent 5-year period, more than
95 percent of the total heat content is due to bituminous coal firing. Since coal is the most used fuel for Unit 3, petcoke (20 percent of coal) can contribute significantly to the total SO 2 emissions from the unit. Lakeland Electric believes that curtailing petcoke firing is the most cost effective solution to reduce the
sulfur content of fuel burned in Unit 3. It is estimated that 67 lb of SO 2 will be reduced for every ton of coal burned instead of combined coal and petcoke (difference between 3.48 percent sulfur and 1.8 percent
sulfur in 1 ton of fuel ).

The existing FGD system is a 30-year old Babcock & Wilcox design and is not designed to achieve 95 to 98 percent SO 2 removal without significant major upgrades in the existing equipment. Based on very preliminary assessment, the removal efficiency of the FGD system may be increased to a maximum of
95 percent with equipment improvements involving the existing FGD absorbers, slurry systems, additive systems, reheat systems, and stack(s), which may cost as much as $25 million (Lakeland Electric estimate). A detailed engineering study will be needed to properly assess the cost of such an improvement. For example, a new landfill might be required since the solid waste disposal rate will increase with additional
SO 2 absorption. If dibasic acid is used in the scrubber to achieve higher removal efficiency, the issue of specific waste water treatment procedure will need to be addressed since the waste water will have dibasic acid in it. It should also be noted that such a modification will require Unit 3 to be offline for approximately 25 to 30 days. However, as discussed in more detail in Factor 2, Lakeland Electric will be evaluating acid gas control options for complying with Utility MACT (40 CFR 63 Subpart UUUUU).

An additional/replacement wet-FGD system designed to achieve 95 to 98 percent SO 2 removal would achieve the highest level of SO 2 control while Unit 3 remains operating and available to provide electric power to its customers.

To develop a cost of a replacement wet-FGD system, information developed for the recent CSAPR was used. Capital, fixed operation and maintenance (O&M), and variable O&M are available on a dollar perJune 2012 6 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx kilowatt basis as part of EPA’s Integrated Planning Model (IPM) Base Case v. 4.10 (Se ptember 1, 2010) for Transport Rule; Documentation; Chapter 5, Emission Control Technologies. These costs models were developed by engineering contractors such as Sargent & Lundy for the wet-FGD cost model as well as other control technologies. Additionally, cost factors and methodology from the EPA Cost Control Manual were used to develop annualized costs not included in the EPA IPM cost model.

Table 1 presents the estimated costs and cost effectiveness for an additional/replacement wet-FGD for
Unit 3 to achieve a SO 2 removal of 98 percent, the highest level of control. The annualized cost was based on the amount of historical operation in baseline year of 2002 and is estimated to be about $36.3 million. The compliance target was an emission rate of 0.063 lb/MMBtu, which is equivalent to
98 percent SO 2 removal based on 2002 operation, the basis of the FDEP baseline emissions. The cost effectiveness of about $5,804 per ton of SO 2 removed was estimated using a reduction from the 2002 baseline year and an emission rate of 0.063 lb/MMBtu. It should be recognized that the estimated costs are neither specific to the McIntosh Power Plant nor the layout of Unit 3. It may not be possible to install
add -on SO 2 equipment given the spatial constraints at the site. Notwithstanding, the cost effectiveness is extremely high and unreasonable for McIntosh Unit 3, given that Unit 3 already has a wet-FGD system.



### FACTOR 2

– TIME NECESSARY FOR COMPLIANCE McIntosh Unit 3 already has operating wet-FGD systems that are generally considered the highest level of control. Unit 3 is also subject to the recently adopted National Emission Standards for Hazardous Air Pollutants (NESHAPS) for coal-fired EGUs codified as 40 CFR 63, Subpart UUUUU. This rule, also known as the Mercury and Air Toxics Standards (MATS) or Utility MACT, was issued with an effective date of April 16, 2012, and requires the installation of maximum achievable control technology (MACT). For existing EGUs, MATS contains an alternative, surrogate emission limit for SO 2 of 0.2 lb/MMBtu. The compliance deadline for this rule is April 16, 2015, with the possibility of two 1-year extensions. Unit 3 will comply with the Utility MACT in part using the existing FGD systems by the applicable compliance date. From the perspective of the time necessary for compliance, Unit 3 will comply with MACT emission limits. Lakeland Electric is currently evaluating a MATS compliance strategy which will be identified in the next
12 to 16 months. This strategy will provide options for MATS compliance that would lead to MATS compliance by the “compliance date” and ultimately achieve the RP for Unit 3. In addition, depending on the MACT compliance option(s) selected, unit operation may be curtailed temporarily to install/implement the option(s), although Lakeland Electric will take measures to minimize any such lost generation.

In contrast, the construction of additional/replacement wet-FGD to achieve comparable emissions will not have any advantage over the requirements in the Utility MACT rule. An additional/replacement wet-FGD system will at best take over 3 years to design, fabricate, and construct. An estimated schedule is presented below assuming a July 1, 2012 start date, which is highly unlikely due to the magnitude of the approvals and financing required to implement such a major project. This schedule was developed from experience with four major wet-FGD refit projects in the mid-2000s on large coal-fired units. Assuming aJune 2012 7 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx start date of July 1, 2012, additional add-on controls could not be operational before mid-2015. More likely, such a major project could not be started before mid-2013, bringing the operation date clearly beyond the compliance date for the MACT standards. Clearly, the implementation of the Utility MACT standards by April 2015 for Unit 3 accomplishes the RPG desired by FDEP and required by EPA regulations.

Wet-FGD Schedule
Activity Description Days Start Date End date Start 00 0 1

- Jul

- 12 NA Engineering & Design 730 1

- Jul

- 12 1

- Jul

- 14 Procurement 540 29

- Sep

- 12 23

- Mar

- 14 Start of Construction 00 0 1

- Jul

- 13 NA Foundation 270 1

- Jul

- 13 28

- Mar

- 14 Electrical and Piping (Initial) 180 1

- Jul

- 13 28

- Dec

- 13 Delivery of Equipment 120 23

- Mar

- 14 21

- Jul

- 14 Stack 270 28

- Mar

- 14 23

- Dec

- 14 FGD System 365 23

- Dec

- 14 23

- Dec

- 15 Process Building 120 22

- Apr

- 15 20

- Aug

- 15 Material Handling 270 21

- Jul

- 14 17

- Apr

- 15 Electrical and Piping (Final) 270 21

- Jul

- 14 17

- Apr

- 15 Commissioning 0 90 17

- Apr

- 15 16

- Jul

- 15 Operation 00 0 NA 16

- Jul

- 15
Source: Golder Associates, 2011.



### FACTOR 3

– ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS The energy and non-air quality impacts associated with an additional/replacement wet-FGD system include additional limestone usage, disposal of FGD byproducts, increased water use, and additional energy.

Wet-FGD requires about 3 percent of the energy of the unit for auxiliary power and backpressure. This is about 1.09 MW per ton of SO 2 removed. The additional energy required to meet 0.063 lb/MMBtu with the reduction estimated using the 2002 baseline emissions is 6,822 megawatt-hours (MWh).

For each ton of SO 2 removed, about 1.05 tons of limestone are required due to the reactivity and losses in the system. Approximately 2.34 tons of FGD byproducts are produced per ton of SO 2 removed. For
the estimated SO 2 removed based on 2002 emissions, an additional 6,572 tons of limestone would be required and 14,646 tons of byproducts generated. Additional process water would also be required and is estimated to be 50 gallons per ton of SO 2 removed. Based on the SO 2 removed from the 2002 emissions, about 312,953 gallons of additional water would be required. These additional impacts do not support an additional/replacement wet-FGD system.



### FACTOR 4

– REMAINING USEFUL LIFE Although there are no current plans for retirement, it was assumed that Unit 3 will remain in service for at least another 20 years for the purposes of the economic assumptions and cost estimates presented in
Table 1. Unit 3 initially started operation in September 1982.June 2012 8 123 -87563

Y: \Projects\ 2012 \ 123 -87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 RPCT.docx 

### RP DETERMINATION McIntosh Unit 3 has the pollution control technology generally recognized as achieving the highest level of control and must meet the Utility MACT standards by 2015. Adding a new wet FGD system is cost prohibitive and an exact cost of modification for the existing wet FGD system is unknown without a detailed engineering study, which may also be cost prohibitive. As a result, reduction of fuel sulfur in the form of curtailing petcoke firing is considered as RP at this time. Significant reduction in SO 2 emissions is possible by not firing petcoke in Unit 3 and Lakeland Electric proposes to stop all future use of petcoke for
Unit 3.

This determination is all the more reasonable based on the fact that this Class I Area is already achieving the “glidepath” for purposes of RPGs. Specifically, the RH Plan prepared by FDEP included analyses that predict visibility in the PSD Class I Area to be on the “glidepath” for reasonable furth er progress in 2018 (FDEP, 2012; Regional Haze Plan for Florida Class I Areas, Pre-Hearing Draft, April 13, 2012, Figure 7.2.4-7), without accounting for any additional reduction for Unit 3. Accordingly, the FDEP analysis
demonstrates that further SO 2 reduction for Unit 3 beyond that achieved by the existing wet FGD system is neither reasonable nor appropriate for purposes of meeting FDEP’s RPGs.

In addition, as described above, McIntosh Unit 3 will be required to comply with the Utility MACT standards. To meet these standards, the use of the existing wet-FGD systems will be required that will concomitantly lower emissions of SO 2 emissions and further the efforts to improve visibility in Chassahowitzka PSD Class I Area. Indeed, as stated in 40 CFR 51, Appendix Y:

“We believe that, in many cases, it will be unlikely that States will identify emission controls more stringent than the MACT standards without identifying control options that would cost many thousands of dollars per ton. Unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, you may rely on the MACT standards for purposes of BART.”TABLESJune 2012 123-87563

Additional Cost Items Cost Factors Wet-FGD Cost ($)

DIRECT CAPITAL COSTS (DCC): (1) Equipment Cost (a) Limestone FGD $549/kW Estimated from EPA IPM Retrofit Costs (a) 199,603,040.0 (b) NA 0.0 (c) NA 0.0 (3) Sales Tax Exempt 0.0 Subtotal: Total Equipment Cost (TEC) 199,603,040.0

(4) Direct Installation Costs Included in EPA IPM 0.0

Total DCC: 199,603,040.0

INDIRECT CAPITAL COSTS (ICC): (b) (1) Indirect Installation Costs (a) Engineering Included in EPA IPM (b) Construction & Field Expenses Included in EPA IPM (c) Construction Contractor Fee Included in EPA IPM (d) Owner's Costs Included in EPA IPM (2) Other Indirect Costs (a) Startup 1% of TEC 1,996,030.4 (b) Performance Test' 1% of TEC 1,996,030.4 Total ICC: 3,992,060.8

PROJECT CONTINGENCY 15% of (DCC+ICC) 30,539,265.1

TOTAL CAPITAL INVESTMENT (Total Plant Cost) (TCI): DCC + ICC+Project Contingency 234,134,365.9

DIRECT OPERATING COSTS (DOC): (1) Fixed Operation & Maintenance Cost $9.9/MWh estimated from EPA IPM CSAPR and adjusted for existing 4,645,365 SO 2 removal. Cost about 19% of the total costs for 98% removal.

-- $0 0 Total DOC: $4,645,365

INDIRECT OPERATING COSTS (IOC): (b) (1) Overhead 60% of operation and maintenance (7.72% of DOC), CCM Chapter 2 215,173.3 (2) Property Taxes 1% of total capital investment, CCM Chapter 2 2,341,343.7 (3) Insurance 1% of total capital investment, CCM Chapter 2 2,341,343.7 (4) Administration 2% of total capital investment, CCM Chapter 2 4,682,687.3 Total IOC: (1) + (2) + (3) + (4) 9,580,548.0

CAPITAL RECOVERY COSTS (CRC): CRF of 0.0944 times TCI (20 yrs @ 7%) 22,102,284.1

ANNUALIZED COSTS (AC): DOC + IOC + CRF $36,328,197

2002 Emissions Emissions (2002): (c) 2002 Baseline in FDEP RP Plan 6,994 Projected Future Emissions: Emissions based on 98% SO 2 removal from 2002 baseline. 735 Emissions Reduction (TPY)(AC): Baseline - Future Projected (TPY) 6,259 Average Cost Effectiveness ($/ton): AC/Emissions Reduction $5,804
Notes: (a) EPA Integrated Planning Model (IPM) Base Case v. 4.10 (9-1-2010) for Transport Rule; Documentation; Chapter 5. Emission Control Technologies (b) Factors and cost estimates reflect OAQPS Cost Manual, 6th Edition, January 2002. (c) Emissions for 2002 used by FDEP in selecting sources for RP analysis. Table 1. Cost Effectiveness of Wet-Flue Gas Desulfurization (FGD) at 98 Percent Removal for Lakeland Electric McIntosh Unit 3

Y:\Projects\2012\123-87563 LE McIntosh\RPCT\Final\McIntosh Unit 3 Wet FGD Cost.xlsx

# G. JEA St. Johns River Power PlantJune 2012 1 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx 

### REASONABLE PROGRESS ANALYSIS
ST. JOHNS RIVER POWER PARK UNITS 1 AND 2

INTRODUCTION This submission is made in a cooperative effort to address regional haze rule (RHR) implementation issues resulting from recent regulatory developments related to the U.S. Environmental Protection Agency’s (EPA’s ) Clean Air Interstate Rule (CAIR) and its successor, the Cross-State Air Pollution Rule (CSAPR). CSAPR is currently stayed, and CAIR remains in effect, pending judicial review of CSAPR. Depending on the court’s decision on CSAPR, JEA may revisit, revise or withdraw this analysis and proposal.

Regional haze is visibility impairment caused by the cumulative air pollutant emissions from numerous

sources over a wide geographic area. EPA’s regional haze regulations are contained in Title 40, Part 51 of the Code of Federal Regulations (40 CFR 51). EPA promulgated the RHR on July 1, 1999. Under Section 51.308(d)(1) of the RHR, state s must “establish goals (expressed in deciviews) that provide for reasonable progress (RP) towards achieving natural visibility conditions” for each Class I area within a state. These reasonable progress goals (RPGs) must provide for an improvement in visibility for the most
im paired days over the period of the implementation plan and ensure no degradation in visibility for the least impaired days over the same period.

RPGs are interim goals and are to be established for the final year in each planning period, which is 2018 for the first planning period. The interim goals represent incremental visibility improvement over time toward the goal of natural background conditions. In determining what would constitute reasonable progress towards achieving natural visibility conditions, Section 169A(g) of the Clean Air Act (CAA) requires states to consider the following four factors:

 The costs of compliance

 The time necessary for compliance

 The energy and non-air quality environmental impacts of compliance

 The remaining useful life of existing sources that contribute to visibility impairment
In addition, states must submit a state implementation plan (SIP) and demonstrate in their SIPs how these four factors are taken into consideration in selecting the RPG for each Class I area in the state.

As part of this demonstration, states must consider the rate of progress needed to reach natural visibility conditions by 2064. This consideration is referred to as the “uniform rate of progress” or the “glidepath”. Regulations implementing these RPG requirements have been promulgated in 40 CFR 51, Subpart P

– Protection of Visibility. Section 51.308 specifically addresses the regional haze program requirements. EPA has developed guidance for implementing the RPG requirements

– reference “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program” revised June 1, 2007.June 2012 2 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx T he Florida Department of Environmental Protection (FDEP) draft Regional Haze Plan for Florida Class I Areas (RH Plan) submitted to the EPA on April 13, 2012 indicates that RP for Florida emission sources will be confined to sulfur dioxide (SO 2 ) since reductions in emissions of this pollutant will provide the greatest benefit to visibility improvement. The FDEP RH Plan also identifies the specific Florida emission units that FDEP has determined are subject to RP review. The selection of Florida emission units subject
to RP review was based on the ratio of 2002 SO 2 annual emissions (Q in tons) and distance (D in kilometers) from a Class I area. If the Q/D ratio is 50 or greater, the emission source was considered to have a significant impact on visibility impairment and therefore subject to RP review. On May 25, 2012, EPA proposed to approve FDEP’s analysis regarding the pollutants and source categories that most contribute to visibility impairment in Class I areas [i.e., to focus solely on SO 2 and industrial point sources
of SO 2 emissions including electrical generating units (EGUs) and non-EGUs] , and FDEP’s methodology for prioritizing the most significant contributors to regional haze (i.e., use of a Q/D ratio > 50). In its RH Plan, FDEP states that SJRPP Units 1 and 2 had a Q/D ratio greater than 50 for the Okefenokee and
Chassahowitzka Class I areas.

The RP analysis for SJRPP Units 1 and 2 is presented in the following sections.



### RP ANALYSIS FOR SJRPP UNITS 1 AND 2

B ased on EPA’s “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program”, there are four statutory factors as previously identified that can be applied to a stationary source to evaluate potential emission control measures and the level of control that can be applied to the source to meet the visibility goals under the RPG.

SJRPP Units 1 and 2 are nominal 632 megawatt (MW) fossil fuel-fired steam generators, which may burn coal, coal with up to 30 percent petroleum coke (based on weight), new No. 2 fuel oil, and natural gas. The maximum heat input rate is 6,144 million Btu per hour (MMBtu/hr) per unit. Units 1 and 2 are equipped with a flue gas desulfurization (FGD) system to control SO 2 emissions. SJRPP is authorized to utilize solid fuel (coal and pet coke) with a sulfur content up to 4 percent. Units 1 and 2 are currently subject to the SO 2 emissions limitations contained in Final Title V Permit No. 0310045-030-AV.

Sulfur compounds are produced in coal-fired boilers by the combustion process in which complete oxidation of the fuel-bound sulfur occurs, forming primarily SO 2 , with smaller quantities of sulfur trioxide (SO 3 ). The amount of SO 2 emissions is directly proportional to the sulfur and sulfate content in the fuel. Reducing SO 2 emissions by boiler modification is not feasible because combustion processes do not
affect SO 2 emissions. Generally, complete oxidation of sulfur in fuel is readily achieved before complete combustion of carbon, the most abundant element in fossil fuel. For pulverized coal-fired utility boilers,
SO 2 emission reduction is typically accomplished by treating the post-combustion flue gas with a FGD

process.June 2012 3 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx Standard FGD processes for pulverized coal-fired boilers are back-end equipment of either the wet or dry type; these are often referred to as wet and dry scrubbing, respectively. Since the early 1970s, FGD has been used extensively in the United States to control SO 2 emissions from coal-fired power plants. Indeed, the use of FGD systems was, in effect, mandated for pulverized coal-fired power plants with the promulgation of the New Source Performance Standards (NSPS) for electric utility steam generating units (i.e., 40 CFR 60, Subpart Da), which required minimum reductions between 70 and 90 percent in the potential combustion concentration of SO 2 . The most widely used system for large-scale SO 2 removal is the calcium-based wet lime/limestone FGD systems that are recognized to have the highest levels of control. Worldwide, there are over 200,000 MW of installed wet limestone FGD systems, which represent about 80 percent of FGD systems. New wet FGD systems are capable of removing 95 to 98 percent of
SO 2 and have been accepted as Best Available Control Technology (BACT) as the highest level of control.

Units 1 and 2 are currently equipped with wet limestone FGD systems to control SO 2 emissions. The FGD systems are capable of up to 90 percent reduction in SO 2 emissions with a maximum SO 2 emissi on rate of 0.76 pound per million British thermal units (lb/MMBtu) using the worst case fuel. The scrubbers are of a tray tower type consisting of three absorber modules. Each module provides a 50-percent capacity of total unit output. The components of the scrubbing system are listed below:

Quencher

– Flue gases exiting the ESP enter the venturi-type quenchers for each absorber, which condition the flue gas. The quench water is recirculated from the quencher sump.

Absorber Tower

– After adiabatic saturation in the quencher, the gases pass up through the absorber tower(s) for SO 2 removal. The limestone slurry is introduced at the top of the tray absorber from a series of spray headers. The flow is countercurrent through the absorber.

Demister

– Before exiting the absorber, aerosols in the flue gas are removed in a demister made from reinforced fiberglass material.

Associated Equipment

– Supporting the operation of the scrubbers are the following equipment: absorber recirculation tank, quencher recirculation tank, and quencher and absorber recirculation pumps. The scrubber is equipped with a bypass flue. The latter bypasses flue gases around the absorber system and mixes with air exiting the absorber tower. This increases the exit gas temperatures and allows discharge through a non-lined stack. A continuous emission monitoring system is installed to assure compliance with the SO 2 emission limit.

Additional equipment/processes supporting the scrubber system include limestone storage and handling, limestone slurry preparation system, slurry storage and transfer system, FGD blowdown, and gypsum dewatering, transfer, and storage.

The RP analysis requires consideration of four factors that include the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and theJune 2012 4 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx remaining useful life of existing sources that contribute to visibility impairment. SJRPP currently uses wet limestone FGD that is considered to achieve the greatest reduction in SO 2 removal for coal-fired generating units. The SO 2 emission limits for coal firing are (refer to Conditions C.13, C.14 and C.15 of
Final Title V Permit No. 0310045- 030 -AV for all authorized SO 2 emission limits for SJRPP):

 1.20 lb/MMBtu heat input maximum 2-hour average and 0.76 lb/MMBtu heat input with 90% reduction of the potential combustion concentration, 30-day rolling average and 4,669 pounds per hour, or

 30% of the potential combustion concentration (70% reduction), when emission are less than 0.60 lb/MMBtu heat input.

 100% of the potential combustion concentration (0% reduction), when emission are less than 0.20 lb/MMBtu heat input.

 SO 2 emissions shall be controlled with a lime/limestone FGD system on each boiler.



### FACTOR 1

– COSTS OF COMPLIANCE

T he first factor to take into consideration is the “costs of compliance”. EPA’s guidance for RP suggested three factors to consider in assessing compliance costs:
a) Identify the emissions units to be controlled b) Identify the design parameters for emissions controls c) Develop cost estimates based upon those design parameters
As described above, SJRPP Units 1 and 2 have a wet-FGD system that was designed to achieve
90 percent SO 2 removal using up to 4 percent sulfur coal. To achieve greater SO 2 reductions from the current equipment would require either add-on SO 2 controls after the existing equipment or a replacement of the current FGD system with units designed to achieve 95 to 98 percent or greater SO 2 removal. The existing FGD systems are not designed to achieve 95 to 98 percent SO 2 removal without significant major upgrades in the existing equipment (e.g., absorber redesign to increase liquid to air ratio, construction of new wet stack, etc.). As a result, an additional/replacement wet-FGD system designed to achieve a total removal of 95 to 98 percent SO 2 removal would achieve the highest level of SO 2 control while Units 1 and 2 remain operating and available to provide electric power to its customers.

W et -FGD has been a widely available control technology for SO 2 removal over the last 30 years. To develop a cost of a replacement wet-FGD, information developed for the recent CSAPR was used. Capital, fixed operation and maintenance (O&M), and variable O&M are available on a dollar per kilowatt basis as part of EPA’s Integrated Planning Model (IPM) Base Case v. 4.10 ( September 1, 2010) for Transport Rule; Documentation; Chapter 5. Emission Control Technologies. These costs models were developed by engineering contractors such as Sargent & Lundy for the wet-FGD cost model as well as other control technologies. Additionally, cost factors from the EPA Cost Control Manual were used to costs not included in the EPA IPM cost model. EPA’s “Guidance for Setting Reasonable Progress Goals Under the Regional Haze Program” suggests that costs should be evaluated and cost estimates shouldJune 2012 5 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx be based on EPA’s Air Pollution Control Cost Manual. Annualized costs were developed using the methodology in the EPA Cost Control Manual.

Table 1 presents the estimated costs and cost effectiveness for an additional/replacement wet-FGD for
either SJRPP Units 1 or 2 to achieve an SO 2 removal of 98 percent, the highest level of control. Units 1 and 2 are identically designed units in close proximity that have a similar influence on visibility to Class I Areas. The annualized cost was based on the amount of historical operation in baseline year of 2002 and is estimated to be about $59.7 million. The cost effectiveness was determined against one half of the
2002 SO 2 emissions since both Units 1 and 2 are identical ly designed. The compliance target was an emission rate of 0.053 lb/MMBtu, which is equivalent to 98 percent SO 2 removal based on 2002 operation, the basis of the FDEP baseline emissions. The cost effectiveness of about $6,383 per ton of SO 2 removed was estimated using a reduction from the 2002 baseline year and an emission rate of 0.053 lb/MMBtu. To contrast the cost effectiveness from this baseline year, the cost effectiveness using the emissions for the latest year, 2011, was estimated. As shown in the table, the cost effectiveness from
the SO 2 emissions in 2011 was estimated to be $11,921 per ton of SO 2 removed. It should be recognized
that the estimated costs are neither specific to SJRPP nor the layout of Units 1 nor 2. It may not be possible to install add-on SO 2 equipment given the spatial constraints at the site. Notwithstanding, these cost effectiveness numbers are extremely high and considered unreasonable for SJRPP Units 1 and 2, which already have wet-FGD systems.

Increasing the existing SO 2 removal efficiency of the FGD system is possible with equipment improvements involving the existing FGD absorbers, slurry systems, additive systems, reheat systems, and stack(s). The capital costs for the potential improvements are likely in the range of $10 million to $30 million per unit. In conjunction with the equipment improvements, operating costs for increased SO 2 removal will include fixed and variable operating costs from about $3 million per year per unit to over $4.5 million per year per unit. Depending upon the options selected, up to an additional 5 percent SO 2 removal is possible. An engineering study has commenced that will include an evaluation of the sulfur content for the various range of fuels authorized for SJRPP and refine these very preliminary cost estimates. However, as discussed in more detail in Factor 2, SJRPP will be evaluating control options for complying with Utility MACT (40 CFR 63 Subpart UUUUU).



### FACTOR 2

– TIME NECESSARY FOR COMPLIANCE SJRPP Units 1 and 2 already have operating wet-FGD systems that are generally considered the highest level of control. Units 1 and 2 are also subject to the recently adopted National Emission Standards for Hazardous Air Pollutants (NESHAPS) for coal-fired EGUs codified as 40 CFR 63 Subpart UUUUU. This rule, also known as the Mercury and Air Toxics Standards (MATS) or Utility MACT, was issued with an effective date of April 16, 2012 and requires the installation of maximum achievable control technology (MACT). For existing EGUs, MATS contains an alternative, surrogate emission limit for SO 2 of
0.2 lb/MMBtu. The compliance deadline for this rule is April 16, 2015, with the possibility of two 1-yearJune 2012 6 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx extensions. Units 1 and 2 will comply with the EGU MACT in part using the existing FGD systems by the compliance date. From the perspective of the time necessary for compliance, SJRPP Units 1 and 2 will comply with MACT emission limits. SJRPP is currently evaluating a MATS compliance strategy which wil l be identified in the next 12 to 16 months. This strategy will provide options for MATS compliance that would lead to MATS compliance by the “compliance date” and ultimately achieve the RP for SJRPP Units 1 and 2. In addition, depending on the MACT compliance option(s) selected, unit operation may be curtailed temporarily to install/implement the option(s), although JEA will take measures to minimize any such lost generation.

The construction of additional/replacement wet-FGD to achieve comparable emissions will not have any advantage over the requirements in the Utility MACT rule. An additional/replacement wet-FGD will at best take over 3 years to design, fabricate, and construct. An estimated schedule is presented below assuming a July 1, 2012 start date that is highly unlikely due to the magnitude of the approvals and financing required to implement such a major project. This schedule was developed from experience with four major wet-FGD refit projects in the mid-2000s on large coal fired units. Assuming a start date of July 1

, 2012 additional add-on controls could not be operational before mid-2015. More likely, such a major project could not be started before mid- 2013 , bringing the operation date clearly beyond the compliance date for the MACT standards. Clearly, the implementation of the Utility MACT standards by April 2015 for SJRPP Units 1 and 2 accomplishes the RPG desired by FDEP and required by EPA regulations.

Wet-FGD Schedule
Activity Description Days Start Date End date Start 00 0 1

- Jul

- 12 NA Engineering & Design 730 1

- Jul

- 12 1

- Jul

- 14 Procurement 540 29

- Sep

- 12 23

- Mar

- 14 Start of Construction 00 0 1

- Jul

- 13 NA Foundation 270 1

- Jul

- 13 28

- Mar

- 14 Electrical and Piping (Initial) 180 1

- Jul

- 13 28

- Dec

- 13 Delivery of Equipment 120 23

- Mar

- 14 21

- Jul

- 14 Stack 270 28

- Mar

- 14 23

- Dec

- 14 FGD System 365 23

- Dec

- 14 23

- Dec

- 15 Process Building 120 22

- Apr

- 15 20

- Aug

- 15 Material Handling 270 21

- Jul

- 14 17

- Apr

- 15 Electrical and Piping (Final) 270 21

- Jul

- 14 17

- Apr

- 15 Commissioning 0 90 17

- Apr

- 15 16

- Jul

- 15 Operation 00 0 NA 16

- Jul

- 15



### FACTOR 3

– ENERGY AND NON-AIR QUALITY ENVIRONMENTAL IMPACTS The energy and non-air quality impacts associated with an additional/replacement wet-FGD system includes additional limestone usage, disposal of FGD byproducts, increased water use, and additional
energy.June 2012 7 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx W et -FGD requires about 3 percent of the energy of the unit for auxiliary power and backpressure. This is about 1.09 MW per ton of SO 2 removed. The additional energy required to meet 98 percent SO 2 removal from the 2002 baseline emissions is 10,189 MWh.

For each ton of SO 2 removed, about 1.05 tons of limestone is required due to the reactivity and losses in the system. Approximately 2.34 tons of FGD byproducts are produced per ton of SO 2 removed. For the
estimated SO 2 removed based on 2002 emissions, an additional 9,815 tons of limestone would be required and 21,874 tons of byproducts generated. Additional process water would be also be required and is estimated to be 50 gallons per ton of SO 2 removed. Based on the SO 2 removed from the 2002 emissions, about 467,389 gallons of additional water would be required. These additional impacts do not support an additional/replacement wet-FGD system.



### FACTOR 4

– REMAINING USEFUL LIFE Although there are no current plans for retirement, SJRPP Units 1 and 2 were assumed to remain in service for at least another 20 years for the purposes of the economic assumptions and cost estimates presented in Table 1. For reference, Unit 1 initially started operations in December 1986, while Unit 2 started operations in March 1988.



### RP DETERMINATION Given that SJRPP Units 1 and 2 must meet the Utility MACT standards by 2015 and have the pollution control technology generally recognized as achieving the highest level of control, the existing SO 2 emission limits are considered RP at this time. Wet-FGD technology is capable of reducing annual SO 2 emissions below the 2002 baseline evaluated by FDEP, which would therefore provide visibility benefits
to the relevant Class I Areas.

This determination is all the more reasonable based on the fact that this Class I Area is already achieving the “glidepath” for purposes of RPGs. Specifically, the Regional Haze Plan prepared by FDEP included analyses that predict visibility in the Chassahowitzka and Okefenokee Class I Areas to already be on the “glidepath” for reasonable further progress in 2018 (FDEP, 2012. Regional Haze Plan for Florida Class I Areas, Pre-Hearing Draft, April 13, 2012, Figures 7.2.4 -7 and 7.2.4-9), without accounting for any additional reductions from SJRPP. Accordingly, the FDEP analysis demonstrates that further SO 2 reduction for SJRPP beyond that achieved by the existing wet FGD system is neither reasonable nor appropriate for purposes of meeting FDEP’s RPGs.

Installing additional add-on controls would take at a minimum of 3 years due to the need for the continued operation of Units 1 and 2. During a construction period for Units 1 and 2, SJRPP would be required to continue to supply reliable electric power to its customers. Moreover, the wet-FGD system already achieves a high level of SO 2 removal that was established as BACT (i.e., a design of 90 percent removal). The energy and non-air quality impacts associated with any additional SO 2 controls would be additive to the energy uses of the existing FGD system. Non-air quality impacts would potentially include increasedJune 2012 8 123 -87608

Y: \Projects\ 2012 \ 123 -87608 JEA\SJRPP RP\Rev final 1\SJRPP RP.docx water use, additional solid wastes, and additional energy usage. Therefore, installing additional SO 2 controls would not be cost effective, practicable, or reasonable. SJRPP Units 1 and 2 will remain in service and in full compliance with the existing SO 2 emission limits using wet FGD.

In addition, as described above, SJRPP Units 1 and 2 will be required to comply with the Utility MACT standards. To meet these standards, the use of the existing wet-FGD systems will be required that will concomitantly lower emissions of SO 2 emissions and further the efforts to improve visibility at Class I Areas. Indeed, as stated in 40 CFR 51, Appendix Y:

“We beli eve that, in many cases, it will be unlikely that States will identify emission controls more stringent than the MACT standards without identifying control options that would cost many thousands of dollars per ton. Unless there are new technologies subsequent to the MACT standards which would lead to cost-effective increases in the level of control, you may rely on the MACT standards for purposes of BART.”

In conclusion, SJRPP will comply with Utility MACT by the MACT “compliance date” and is implementing a study for that purpose.TABLESJune 2012 123-87608

Additional Cost Items Cost Factors Wet-FGD Cost ($)

DIRECT CAPITAL COSTS (DCC): (1) Equipment Cost (a) Limestone FGD $496/kW Estimated from EPA IPM Retrofit Costs (a) 337,081,600.0 (b) NA 0.0 (c) NA 0.0 (3) Sales Tax Exempt 0.0 Subtotal: Total Equipment Cost (TEC) 337,081,600.0

(4) Direct Installation Costs Included in EPA IPM 0.0

Total DCC: 337,081,600.0

INDIRECT CAPITAL COSTS (ICC): (b) (1) Indirect Installation Costs (a) Engineering Included in EPA IPM (b) Construction & Field Expenses Included in EPA IPM (c) Construction Contractor Fee Included in EPA IPM (d) Owner's Costs Included in EPA IPM (2) Other Indirect Costs (a) Startup 1% of TEC 3,370,816.0 (b) Performance Test' 1% of TEC 3,370,816.0 Total ICC: 6,741,632.0

PROJECT CONTINGENCY 15% of (DCC+ICC) 51,573,484.8

TOTAL CAPITAL INVESTMENT (Total Plant Cost) (TCI): DCC + ICC+Project Contingency 395,396,716.8

DIRECT OPERATING COSTS (DOC): (1) Fixed Operation & Maintenance Cost $8/MWh estimated from EPA IPM CSPR with an adjustment of the 6,233,573 SO 2 removed by the existing FGD systems on a ton/removed basis. The adjustment reduce this cost by 85%.

-- $0 0 Total DOC: $6,233,573

INDIRECT OPERATING COSTS (IOC): (b) (1) Overhead 60% of operation and maintenance, CCM Chapter 2 288,739.1 (2) Property Taxes 1% of total capital investment, CCM Chapter 2 3,953,967.2 (3) Insurance 1% of total capital investment, CCM Chapter 2 3,953,967.2 (4) Administration 2% of total capital investment, CCM Chapter 2 7,907,934.3 Total IOC: (1) + (2) + (3) + (4) 16,104,607.8

CAPITAL RECOVERY COSTS (CRC): CRF of 0.0944 times TCI (20 yrs @ 7%) 37,325,450.1

ANNUALIZED COSTS (AC): DOC + IOC + CRF $59,663,631

2002 Emissions 2011 Emissions Emissions (2002 and 2011): (c) Average Emissions for Units 1 and 2 as reported in the AORs 10,631 6,288 Projected Future Emissions: Emissions at 2002 heat input and 98% SO 2 removal. 1,283 1,283 Emissions Reduction (TPY)(AC): Baseline - Future Projected (TPY) 9,348 5,005 Average Cost Effectiveness ($/ton): AC/Emissions Reduction $6,383 $11,921
Notes: (a) EPA Integrated Planning Model (IPM) Base Case v. 4.10 (9-1-2010) for Transport Rule; Documentation; Chapter 5. Emission Control Technologies (b) Factors and cost estimates reflect OAQPS Cost Manual, 6th Edition, January 2002. (c) Average emissions for Units 1 and 2 from the FDEP AORs for 2002 and 2011. Emissions for 2002 used by FDEP in selecting sources for RP analysis. Table 1. Cost Effectiveness of Wet-Flue Gas Deslfurization (FGD) at 98 Percent SO 2 Removal for SJRPP (per unit)

Y:\Projects\2012\123-87608 JEA\SJRPP RP\Rev final 1\SJRPP Wet FGD Cost.xlsx

# Verification of Shut

- down (BART & Reasonable Progress)

A. U.S. Sugar – Bryant (BART)

Items included: Letter from Florida Department of Environmental Protection to the facility confirming the permanent shut

- down of the facility. Also included are the Notice of Expiration of Title V Air Operation Permit and the Statement of Basis.

# B. IMC Port Sutton (currently Kinder Morgan)

Emission Units shut

- down: 1. EU001 – Phosphate Rock Dryer (BART)

Items included: 1 . Previous Title V operating permit (0570024

- 003

- AV) showing the Phosphate Rock Dryer as a valid unit.

2 . Current Title V operating permit (0570024

- 014

- AV) showing that the Phosphate Rock Dryer is no longer included.

### Robert H. Kinsey/IMC-Agrico Port Sutton Terminal Facility ID No.: 0570024 Hillsborough County

Initial Title V Air Operation Permit FINAL Permit No.: 0570024-003-AV

Permitting Authority: Environmental Protection Commission of Hillsborough County 1410 N. 21 st 

### Street Tampa, FL 33605 Telephone: (813) 272-5530 Fax: (813) 272-5605

[electronic file name: 0570024f.doc]

### Initial Title V Air Operation Permit FINAL Permit No.: 0570024-003-AV

Table of Contents

Section Page Number

Statement of Basis........................................................................................................ ii

Placard Page................................................................................................................... 1

I. Facility Information ............................................................................................. 2 - 3 A. Facility Description. B. Summary of Emissions Unit ID No(s). and Brief Description(s). C. Relevant Documents.

II. Facility-wide Conditions .................................................................................... 4 - 6

III. Emissions Unit(s) and Conditions...................................................................... 7 - 30

A. -001 Phosphate Rock Dryer B. -002 Railcar Unloading Scrubber -004 C17 transfer point E C. -003 Shiploading baghouse (C13 to C14 and C14 to Shiphold) -005 C12 transfer point A -006 C30 transfer point C -013 Shiphold Opening D. -007 C18 transfer point D -009 C19 transfer point G E. -008 Animal Feed Ingredient Handling F. -012 Conveyor transfer points from railcar unloading and rock dryer to storage silos G. -100 DAP Truck Unloading Station No.2Permittee: FINAL Permit No.: 0570024-003-AV Robert H. Kinsey/IMC-Agrico Facility ID No.: 0570024 P.O. Box 2000 SIC Nos.: 51 Mulberry, FL 33860-1100 Project: Initial Title V Air Operation Permit

This permit is for the operation of the Port Sutton Terminal. This facility is located at Port Sutton, Tampa, Hillsborough County; UTM Coordinates: Zone 17,360.1 km East and 3087.5 km North; Latitude: 27 ° 54’ 24” North and Longitude: 82 ° 25’ 18” West.

STATEMENT OF BASIS: This Title V air operation permit is issued under the provisions of Chapter 403, Florida Statutes (F.S.), and Florida Administrative Code (F.A.C.) Chapters 62-4, 62-210, and 62-213. The above named permittee is hereby authorized to perform the work or operate the facility shown on the application and approved drawing(s), plans, and other documents, attached hereto or on file with the permitting authority, in accordance with the terms and conditions of this permit.

Referenced attachments made a part of this permit: Appendix I-1, List of Insignificant Emissions Units and/or Activities Appendix O-1, Operation and Maintenance Plans for Particulate Control APPENDIX TV-3, TITLE V CONDITIONS (version dated 4/30/99) APPENDIX SS-1, STACK SAMPLING FACILITIES (version dated 10/07/96)

Effective Date: June 26, 2000 Renewal Application Due Date : December 28, 2004 Expiration Date: June 26, 2005

Environmental Protection Commission

of Hillsborough County

___________________________ Roger P. Stewart Executive Director RPS/AHH/sp

### Robert H. Kinsey/ IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 2
Section I. Facility Information.

Subsection A. Facility Description.

This facility consists of phosphate rock dryer, truck and railcar unloading operation for phosphate rock, animal feed ingredient (AFI) and chemicals (MAP, DAP, GTSP), product storage, and ammonia handling and storage.

The facility can dry phosphate rock using a single dryer firing natural gas or fuel oil. Wet phosphate rock can be trucked or delivered by railcar to the facility and stored outside until processed. The dried phosphate rock is stored within enclosed storage silos until transported off site by ship or barge. The majority of the dry phosphate rock handling operations are enclosed to control fugitive dust emissions.

Additionally, the terminal does receive dry phosphate rock, AFI and MAP, DAP, GTSP by railcar and truck. The products can be transferred directly to a shiphold or stored in silos (rock and AFI) or chemical storage buildings (MAP, DAP, GTSP). This facility is subject to PM-RACT and the monitoring requirements, along with daily visible emissions readings, fuel sampling, and annual PM and EPA Method 9 testing, have been determined by the Agency to satisfy the requirements of 40CFR70.6 and Chapter 62-296, F.A.C.

Also included in this permit are miscellaneous insignificant emissions units and/or activities.

Based on the initial Title V permit application received June 14, 1996, this facility is not a major source of hazardous air pollutants (HAPs).

Subsection B. Summary of Emissions Unit ID No(s). and Brief Description(s).

E.U. ID No. Brief Description -001 Phosphate Rock Dryer -002 Railcar Unloading Scrubber -003 Shiploading baghouse (C13 to C14 and C14 to Shiphold) -004 C17 transfer point E -005 C12 transfer point A -006 C30 transfer point C -007 C18 transfer point D -008 Animal Feed Ingredient Handling -009 C19 transfer point G -012 Conveyor transfer points from railcar unloading and rock dryer to storage silos -013 Shiphold Opening -100 DAP Truck Unloading Station No. 2

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 3
Please reference the Permit No., Facility ID No., and appropriate Emissions Unit(s) ID No(s). on all correspondence, test report submittals, applications, etc.

Subsection C. Relevant Documents.

The documents listed below are not a part of this permit, however, are specifically related to this permitting action.

These documents are provided to the permittee for information purposes only: Table 1-1, Summary of Air Pollutant Standards and Terms Table 2-1, Summary of Compliance Requirements Appendix A-1, Abbreviations, Acronyms, Citations, and Identification Numbers Appendix H-1, Permit History / ID Number Changes

These documents are on file with permitting authority: Initial Title V Permit Application received June 14, 1996.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 4
Section II. Facility-wide Conditions.

The following conditions apply facility-wide:

1. APPENDIX TV-3, TITLE V CONDITIONS (version dated 4/30/99), is a part of this permit. {Permitting note: APPENDIX TV-3, TITLE V CONDITIONS, is distributed to the permittee only. Other persons requesting copies of these conditions shall be provided one copy when requested or otherwise appropriate.}

2. General Pollutant Emission Limiting Standards. Objectionable Odor Prohibited. The permittee shall not cause, suffer, allow, or permit the discharge of air pollutants which cause or contribute to an objectionable odor. [Rule 62-296.320(2), F.A.C.]

3. General Particulate Emission Limiting Standards. General Visible Emissions Standard. Except for emissions units that are subject to a particulate matter or opacity limit set forth or established by rule and reflected by conditions in this permit, no person shall cause, let, permit, suffer or allow to be discharged into the atmosphere the emissions of air pollutants from any activity, the density of which is equal to or greater than that designated as Number 1 on the Ringelmann Chart (20 percent opacity). EPA Method 9 is the method of compliance pursuant to Chapter 62-297. F.A.C.. [Rule 62-296.320(4)(b)1., F.A.C.]

4. Prevention of Accidental Releases (Section 112(r) of CAA). If required by 40 CFR 68, the permittee shall submit to the implementing agency: a. a Risk Management Plan (RMP) when, and if, such requirement becomes applicable; and b. certification forms and/or RMPs according to the promulgated rule schedule. [40 CFR 68]

5. Insignificant Emissions Units and/or Activities. Appendix I-1, List of Insignificant Emissions Units and/or Activities, is a part of this permit. [Rules 62-213.440(1), 62-213.430(6), and 62-4.040(1)(b), F.A.C.]

6. General Pollutant Emission Limiting Standards. Volatile Organic Compounds (VOC) Emissions or Organic Solvents (OS) Emissions. The permittee shall allow no person to store, pump, handle, process, load, unload or use in any process or installation, volatile organic compounds (VOC) or organic solvents (OS) without applying known and existing vapor emission control devices or systems deemed necessary and ordered by the Department.

A) 

### Maintain tightly fitting cover, lids, etc. on all containers when they are not being handled, tapped, etc.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 5

B) 

### Where possible and practical, procure/fabricate a tightly fitting cover for any open trough, basin, etc. of VOC so that it can be covered when not in use. C) 

### Immediately attend to all spills/waste as appropriate.

[Rule 62-296.320(1)(a), F.A.C.; Proposed by applicant in the initial Title V permit application received June 16, 1996]

7. Reasonable precautions to prevent emissions of unconfined particulate matter at this facility in accordance with the provision in Rule 62-296.320, F.A.C. These provisions are applicable to any source, including, but not limited to, vehicular movement, transportation of materials, construction, alterations, demolition or wrecking, or industrial related activities such as loading, unloading, storing and handling. Reasonable precautions shall include, but not limited to, the following: A) Maintenance of parking areas and yards. B) Removal of particulate matter from paved areas, buildings and work areas under the control of the permittee. C) Reduce vehicular speed. Post limits, if necessary.

[Rule 62-296.320(4)(c)2., F.A.C.; Proposed by applicant in the initial Title V permit application received June 16, 1996]

8. The permittee shall notify the Air Compliance Section of the Environmental Protection Commission of Hillsborough County at least 15 days prior to the date on which each formal compliance test is to begin of the date, time, and place of each such test, and the contact person who will be responsible for coordinating and having such test conducted. [Rule 62-297.310, F.A.C]

9. Submit to the Environmental Protection Commission of Hillsborough County each calendar year on or before March 1, completed DEP Form 62-210.900(5), "Annual Operating Report for Air Pollutant Emitting Facility", for the preceding calendar year. [Rule 62-210.370(2), F.A.C.]

10. The permittee shall comply with Appendix O-1, Operation and Maintenance Plans for Particulate Control. In the event of a deviation from the monitoring parameters, the facility shall take corrective actions to remedy the situation. Notify the Environmental Protection Commission of Hillsborough County within 24 hours of the problem. The emission unit shall not be operated until the problem is corrected. A written explanation and the corrective actions implemented shall be submitted in the semi-annual report required in the TV-3 Condition Nos. 43, 44, 45. Records of inspections, maintenance, and performance parameters shall be retained for a minimum of five years and shall be made available to the Environmental Protection Commission of Hillsborough County upon request. [Rule 62-296.700(6)(e), F.A.C.]

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 6

11. When appropriate, any recording, monitoring or reporting requirements that are timespecific shall be in accordance with the effective date of this permit, which defines day

one. [Rule 62-213.440(1), F.A.C.]

12. The permittee shall submit all compliance related notifications and reports required of this permit to the Environmental Protection Commission of Hillsborough County at: Environmental Protection Commission Air Management Division 1410 North 21 st 

### Street

Tampa, FL 33605 Telephone: 813/272-5530, Fax: 813/272-5605

13. Any reports, data, notifications, certifications and requests required to be sent to the United States Environmental Protection Agency, Region 4, should be sent to: United States Environmental Protection Agency Region 4 Air EPCRA Enforcement Branch Air Compliance Section 61 Forsyth Street Atlanta, Georgia 30303 Telephone: 404/562-9099 Fax: 404/562-9095

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 7
Section III. Emissions Unit(s) and Conditions. Subsection A. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -001 Phosphate Rock Dryer

For the operation of a phosphate rock dryer designed for processing 393 TPH, annual average, of wet phosphate rock dried to approximately 2% moisture. Particulate matter emissions generated during drying operations are controlled by two Buell Dry Cyclones in parallel, followed in series by an Airetron, Model No. 261-1, Wet Cyclonic Scrubber. The rock dryer is fired on natural gas or No. 6 fuel oil with a maximum sulphur content not to exceed 2.0 % by weight.

{Permitting note(s): This emissions unit is regulated under Rule 62-296.320, F.A.C., General Pollutant Emission Limiting Standards and PM RACT under Rule 62-296.700, F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

A.1. Capacity. The maximum material handling rate of the dryer shall not exceed 575 tons/hr (TPH) in any given hour and 393 TPH on an annual average. [Rule 62-4.160(2), F.A.C. and Rule 62-210.200, F.A.C., Definitions - (PTE)]

A.2. Methods of Operation - (i.e., Fuels). The dryer shall be fired with natural gas or new fuel oil (grade No. 1 to grade No. 6 inclusive) only. The maximum sulfur content of the fuel oil shall not exceed 2.0% by weight. [Rules 62-4.160(2), F.A.C. and 62-213.440(1), F.A.C.]

A.3. Hours of Operation. This emissions unit is allowed to operate continuously, i.e., 8,760 hours/year. [Rule 62-4.160(2), F.A.C. and Rule 62-210.200, F.A.C., Definitions - (PTE)]

Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

A.4. The maximum allowable particulate emission rate shall not exceed 43.8 lbs/hr and 191.8 tons per consecutive twelve month period when the process rate exceeds 333 TPH of phosphate rock. From 200 TPH to 333 TPH, the emission limit shall be set by the

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 8
Process Weight Rate formula E= 17.31 P 0.16 

### . For a production rate of less than 200 TPH, the maximum allowable particulate emission rate shall be 0.2 lb/ton of rock dried (equivalent to a maximum particulate emissions of 40lb/hr). [Rule 62-296.320, F.A.C.]

A.5. Visible emissions from the rock dryer scrubber shall not be equal to or greater than 20 % opacity. [Rule 62-296.320(4)(b), F.A.C.]

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

A.6. Test the emissions for the following pollutant(s) annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C.:

(X) Particulates (X) Sulfur Oxides * 

### (X) Opacity

* 

### Only required if fuel oil was used to fire the dryer for more than 400 hours in the last 12 months prior to the annual compliance test. Fuel oil analysis to determine sulfur content of the fuel shall be carried out in accordance with ASTM D129-64 and may be submitted for required sulfur dioxide emission test.

A.7. Compliance with the emission limitations of Specific Condition No. A.4. and A.5. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297, F.A.C]

A.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum 575 TPH of wet phosphate rock processing rate . If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 9
[Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

A.9. The visible emissions test shall be conducted by a certified observer and be a minimum of 60 minutes in duration. The test observation period shall include the period during which the highest opacity emissions can reasonably be expected to occur and shall coincide with the particulate testing. [Rule 62-297.310(4)(a)2.,F.A.C.]

A.10. If fuel oil of any grade (No 1 to No.6 inclusive) has been used in the rock dryer for a sum total of more than 400 hours from the date of the previous compliance test, then compliance testing shall be conducted while firing fuel oil. If a test is conducted while firing natural gas, and in the 12 month period following the test, oil of any grade is burned for a sum total of more than 400 hours, then an additional visible emission test per Condition A.5. shall be conducted, while burning oil in that source, within 30 days of having exceeded the 400 hour oil burning limit. A compliance test submitted using a lower grade number fuel oil than grade No. 6 fuel oil, will automatically amend this operation permit to allow subsequent operation on less than or equal grade numbers than that lower grade number oil. [Rule 62 -2 97.310(7), and 62-4.070(3), F.A.C.]

Recordkeeping and Reporting Requirements

A.11. In order to demonstrate compliance with Specific Condition Nos. A.1, A.2, A.4, A.6. and A.10., the permittee shall maintain monthly records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-296.320, F.A.C.] a) Month, year b) Hours of Operation c) Fuel Type and Usage (gal) d) Material throughput (TPH) e) Rolling twelve month total of d) above.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 10
Subsection B. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -002 Railcar Unloading Scrubber -004 C17 transfer point E

EU No. 2 : For the operation of a railcar unloading operation. Railcars are pulled into a partially enclosed structure and unloaded through grates in the floor of the structure into six hoppers. Emissions from each hopper are vented to a dry cyclone. Butterfly valves in the riser pipe routed to each dry cyclone will be used to isolate or shut off air flow to hoppers not being used. Typically four of the six hoppers are used during unloading operations. Dry phosphate rock is transferred from the unloading hoppers to conveyor C17 for subsequent storage in silos via conveyors C19 and C38, or it is transferred for shiploading via conveyors C18, C12, and C13. Fertilizer products (Diammonium Phosphate (DAP), Monoammonium Phosphate (MAP), Animal Feed Ingredient (AFI), and Granular Triple Superphosphate (GTSP)) are transferred from the unloading hoppers to conveyor C17 for subsequent shiploading via conveyors C18, C12, and C13.

Particulate matter emissions generated from the railcar unloading of dry phosphate rock, MAP, GTSP, and AFI are controlled by six dry cyclones followed by a 100,000 ACFM Amerex Type C Venturi scrubber. Particulate matter emissions generated from the railcar unloading of DAP are controlled by the application of a dust suppressant oil applied to the product at the chemical processing facility prior to shipping. The scrubber will operate during the unloading of DAP as needed.

EU No. 4: For the operation of the C17 transfer point E. The system is used to transfer phosphate rock and chemical products (DAP, MAP, GTSP, and AFI) from Conveyor C17 to either Conveyor C18 or C19. Maximum material transfer rate is 1250 TPH for the pebble phosphate rock and chemical products, and 1800 TPH for the concentrate phosphate rock.

Particulate emissions generated during the transfer process are controlled by a 6000 ACFM Poly-Con, Model Venturi 1506MS, scrubber.

{Permitting note(s): These emissions unit is regulated under Rules 62-296.320 and 62- 296.711, F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

B.1. Capacity. The maximum product unloading rates are limited as follows:

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 11
1. Concentrate rock (phosphate rock typically 69-72 BPL grade) 1800 TPH 2. Pebble rock (phosphate rock typically 66-68 BPL grade) 1250 TPH 3. Chemical Products: MAP, DAP, GTSP, AFI 1250 TPH

[Rule 62-4.160(2), F.A.C. , Rule 62-210.200, F.A.C., Definitions - (PTE), and Construction Permit AC29-237340]

Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

B.2. The maximum allowable particulate emissions for the scrubbers shall not exceed the following for any given hour and any 12 consecutive month period: [Rules 62-4.070(3) and 62-296.711, F.A.C., Construction Permit AC29-237340, and Alternative RACT determination issued February 23, 1990]

a) EU. No. 2: based on a design flow of 100,000 ACFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 25.7 112.6 0.03 grains/dscf Visible Emissions 20% opacity

b) EU No. 4 based on a design flow of 6000 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 1.54 6.75 0.03 grains/dscf

B.3. Visible emissions from the railcar unloading structure, EU No. 4 scrubber exhaust and outside pick up points shall not be equal to or greater than 5 % opacity. [Rule 62-4.070(3) F.A.C., Construction Permit AC29-237340]

B.4. During the handling of DAP with the scrubber(s) turned off, the following conditions shall be met: [Rule 62-4.070(3) F.A.C., Construction Permit AC29-237340]

a) The opacity limitation in Specific Condition No. B.3. shall be monitored by a certified smoke reader or trained plant personnel. b) The product shall be sufficiently treated with a non-hazardous oil or dust suppressant to meet the opacity limit in Specific Condition No. B.3.

Test Methods and Procedures

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 12
{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

B.5. Test the 1)EU No. 2 scrubber exhaust and the railcar unloading enclosure concurrently and 2)EU No. 4 scrubber exhaust and outside pick up points for the following pollutant(s) ) annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C.:

(X) Particulates * 

### (X) Opacity

* 

### Scrubber Exhaust Only

B.6. Compliance with the emission limitations of Specific Condition No. B.2. and B.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be conducted by a certified observer and be a minimum of sixty (60) minutes in duration for the scrubber exhaust and thirty (30) minutes in duration for the railcar enclosure. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297, F.A.C]

B.7. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum unloading rates of 1250 TPH for pebble rock and 1800 TPH for concentrate rock (note: If dry phosphate rock handling has been and is expected to remain minimal, testing may be conducted based on the maximum unloading rate of 1250 TPH for AFI). If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions of the scrubber such as inlet pressure drop and liquor feed rate, may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

B.8. Test the emissions from the railcar enclosure for opacity at least 6 months prior to the expiration of this permit while unloading oiled DAP at 90 to 100 percent of the rate of 1250 TPH. During testing, the scrubber is not to be operated. Two copies of the test data are to be submitted to the Air Management Division of the Environmental Protection Commission of Hillsborough County. [Rule 62-297,F.A.C. and Rule 62-4.070(3), F.A.C.]

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 13

B.9. The use of dust suppressant in lieu of operating the scrubber for product other than DAP is allowed provided that IMC-Agrico Company (IMC) satisfies the following requirements: [Construction Permit AC29-237340]

a) IMC will notify the EPC prior to the deactivation of control devices for the purpose of conducting visible emission tests to demonstrate compliance with the standards. b) IMC shall conduct an initial compliance test for visible emissions at the railcar enclosure while handling each additional product. The deactivation of the control devices is limited to the time required to conduct these tests, until authorization by the EPC is issued. c) Testing shall be conducted within 90-100% of the maximum handling rate for each additional product. The actual handling rate and oil to product ratio (gallon/ton) shall be included with the test results. d) Two copies of the test results, along with the applicable permit amendment requests, shall be submitted to the Air Division of the EPC within 45 days of testing. e) The EPC shall acknowledge that the above conditions have been satisfied by amending the corresponding permits for approval and issuing.

Recordkeeping and Reporting Requirements

B.10. In order to comply with Specific Condition Nos. B.3., B.4., and B.9. the permittee shall maintain records for the most recent 5 year period. The recordkeeping shall be made available to the EPC of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but are not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Typical amount and type of dust suppressant applied (gallon/ton) for each product unloaded during the preceding month b) Certificate for smoke reader at the facility who monitored DAP or other fertilizer product unloading with the scrubber off and/or, c) Training program for trained plant personnel

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 14
Subsection C. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -003 Shiploading Baghouse -005 C12 transfer point A -006 C30 transfer point C -013 Shiphold Opening

EU No. 3 and No. 13: The operation of the a) shiploader telescopic chute and OBA chokefeeder, b) transfer of material from conveyor C14 to the shiphold, and c) final transfer point from conveyor C13 to conveyor C14. The system is used to transfer phosphate rock and chemical products (DAP, MAP, GTSP, and AFI) to the shiphold. The maximum transfer rate is 2300 TPH.

Particulate emissions generated during the transfer operation are controlled by the use of a modified Mikro-Pulsaire, Model 1F2 baghouse and/or a gantry mounted dust suppression system. The dust suppression system consists of four (4) spray headers located throughout the gantry using a surfactant chemical mixed with water.

EU No. 5: For the operation of the C12 Transfer Point A. The system is used to transfer phosphate rock and chemical products (DAP, MAP, GTSP, and AFI) from conveyor C12 to conveyor C13 at a maximum transfer rate of 2300 TPH.

Particulate emissions generated during the transfer process are controlled by a 8000 ACFM Mikro-Pulsaire, Model 80F2 baghouse.

EU No. 6.: For the operation of the C30 Transfer Point C. The system is used to transfer various grades of phosphate rock or Animal Feed Ingredients (AFI) from conveyor C30 to conveyor C12 at a maximum transfer rate of 2300 TPH.

Particulate matter emissions generated during the transfer operation are controlled by a Mikro-Pulsaire, Model 1215 -8- 80 baghouse.

{Permitting note(s): These emission units are regulated under Rule 62- 296.711(2)(b), F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

C.1. Capacity. The maximum transfer rate of material shall not exceed 2300 TPH. [Rule 62-4.160(2), F.A.C. and Rule 62-210.200, F.A.C., Definitions - (PTE)]

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Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

C.2. The maximum allowable particulate emissions for these baghouses shall not exceed the following for any given hour and for any 12 consecutive month period: [Rule 62-296.711(2)(a), F.A.C.]

a) EU No. 3 based on a design flow of 9000 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 2.31 10.12 0.03 grains/dscf

b) EU No. 5 based on a design flow of 8000 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 1.8 9.0 0.03 grains/dscf

c) EU No. 6 based on a design flow of 6000 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 1.54 6.75 0.03 grains/dscf

C.3. The maximum opacity from the baghouse exhaust and outside pickup point shall not exceed 5% and the opacity from the discharge to the shiphold shall not exceed 10%. [Rule 62-296.711(2)(a) and (b), F.A.C.]

C.4. In order to show compliance with the limits of Specific Condition Nos. C.2. and C.3., the following restrictions shall apply: [Rule 62-4.070(3)] a) All dust laden air from the transfer operation shall be vented to the baghouse. b) The dust suppression system shall be maintained in operable condition so that it can be operated at any time as necessary during the loading of dry phosphate rock, as well as other products, to maintain compliance with the permitted opacity limit of 10% opacity from the discharge to the hold of the ship. Periods of operation may include, but are not limited to start-up, trimming, and during upset conditions.

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

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C.5. Test the emissions from the 1) baghouse exhaust (EU No.3), shiphold, and C13 to C14 transfer point; 2) baghouse exhaust (EU. No.5) and the outside pick up point; and 3) baghouse exhaust (EU. No.6) and the outside pick up point for opacity annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C..

C.6 . Test the baghouse exhaust for particulate matter at least 120 days prior to the expiration date of this permit while handling dry phosphate pebble rock of approximately 68 grade. Particulate test shall be conducted under similar process rate and operating condition(s) as the visible emission test for the baghouse exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test run for the particulate matter emissions. [Rule 62-297.340(c), F.A.C.]

C.7. Compliance with the emission limitations of Specific Condition No. C.2. and C.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297, F.A.C]

C.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of 2300 TPH of handling rate for dry phosphate rock of approximately 68 grade (note: If dry phosphate rock handling has been and is expected to remain minimal, testing may be conducted based on the maximum material transfer rate of 2300 TPH for AFI). If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

C.9. The permittee is allowed to handle dust suppressant oiled DAP product with the control device turned off provided that: a) Visible emissions at the transfer point shall be less than 5 % opacity. b) The product shall be sufficiently treated with a non-hazardous oil or dust suppressant to meet the opacity limit in Specific Condition No. C.5. If a visible emission test is conducted at the transfer point, the test shall indicate

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 17
the approximate rate of usage of the dust suppressant (gal./ton) and the approximate date the DAP was oiled. The maximum storage time prior to handling shall not exceed one month. c) The maximum oiled DAP product handling rate shall be 1250 TPH as demonstrated during the initial compliance tests on October 25, 1994. d) The oiled DAP product handling rate during compliance testing shall be at approximately (90-100%) of the permitted handling rate of 1250 TPH.

C.10. The use of dust suppressant in lieu of operating the current control systems during the handling of chemical products other than DAP is allowed provided that the permittee satisfies the following requirements: [Rule 62-4.070(3), F.A.C.] a) IMC will notify the EPC prior to the deactivation of control devices for the purpose of conducting visible emission tests to demonstrate compliance with the standards. b) IMC shall conduct an initial compliance test for visible emissions at each source for visible emissions (30 minutes, EPA Method 9) at the transfer point while handling each additional product. The deactivation of the control devices is limited to the time required to conduct these tests, until authorization by the EPC is issued. c) Testing shall be conducted within 90-100% of the maximum handling rate for each additional product. The actual handling rate and oil to product ratio (gallon/ton) and maximum product storage time shall be included with the test results. d) Two copies of the test results, along with the applicable permit amendment requests, shall be submitted to the Air Division of the EPC within 45 days of testing. e) The EPC shall acknowledge that the above conditions have been satisfied by amending the corresponding permits for approval and issuing.

Recordkeeping and Reporting Requirements

C.11. In order to demonstrate compliance with Specific Condition Nos. C.1., the permittee shall maintain records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Month, year b) Hours of operation c) Material throughput (TPH) d) Rolling twelve month total of c) above.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 18

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 19
Subsection D. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -007 C18 Conveyor Transfer Point D -009 C19 Conveyor Transfer Point G

EU No. 7: For the operation of the C18 conveyor transfer point D. The system is used to transfer phosphate rock and chemical products (DAP, MAP, GTSP, and AFI) from conveyor C18 to conveyor C12. Maximum material transfer rate is 1250 TPH for pebble phosphate rock and chemical products and 1800 TPH for concentrate phosphate rock.

Particulate matter emissions generated during the transfer process are controlled by a 6000 ACFM Mikro-Pulsaire, Model 1215 -8- 80 baghouse.

EU No. 9: For the operation of the C19 Conveyor Transfer Point G. The system is used to transfer various grades of phosphate rock or Animal Feed Ingredients (AFI) from Conveyor C19 to Conveyor C38 at the maximum transfer rate of 1250 tons per hour.

Particulate matter emissions generated during the transfer process are controlled by a 5000 ACFM Mikro-Pulsaire, Model 100S -8- TR-20 baghouse.

{Permitting note(s): These emission units are regulated under Rule 62- 296.711(2)(b), F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

D.1. Capacity. The maximum transfer rate of material shall not exceed:

1. Concentrate rock (phosphate rock typically 69-72 BPL grade) 1800 TPH 2. Pebble rock (phosphate rock typically 66-68 BPL grade) 1250 TPH 3. Chemical Products: MAP, DAP, GTSP, AFI 1250 TPH

[Rule 62-4.160(2), F.A.C. , Rule 62-210.200, F.A.C., Definitions - (PTE)]

Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 20

D.2. The maximum allowable particulate emissions for these baghouses shall not exceed the following for any given hour and for any 12 consecutive month period: [Rule 62-296.711(2)(b), F.A.C.]

a) EU No. 7 based on a design flow of 6000 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 1.54 6.75 0.03 grains/dscf

b) EU No. 9 based on a design flow of 4096 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 1.05 4.6 0.03 grains/dscf

D.3. The maximum opacity from the baghouse exhaust and the outside pickup point shall not exceed 5% . [Rule 62-296.711(2)(a) and (b), F.A.C.]

D.4. In order to show compliance with the limits of Specific Condition Nos. D.2. and D.3., the following restrictions shall apply: [Rule 62-4.070(3)] a) All dust laden air from the transfer operation shall be vented to the baghouse.

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

D.5. Test the emissions from the baghouse exhaust and the outside pickup points concurrently for opacity annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C..

D.6 . Test the baghouse exhaust for particulate matter at least 120 days prior to the expiration date of this permit while handling dry phosphate pebble rock of approximately 68 grade. Particulate test shall be conducted under similar process rate and operating condition(s) as the visible emission test for the baghouse exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test run for the particulate matter emissions. [Rule 62-297.340(c), F.A.C.]

D.7. Compliance with the emission limitations of Specific Condition No. D.2. and D.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 21
A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297, F.A.C]

D.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of a) 1250 TPH of handling rate for dry phosphate pebble rock of 68 grade and b) 1800 TPH for concentrated phosphate (note: If dry phosphate rock handling has been and is expected to remain minimal, testing may be conducted based on the maximum material transfer rate of 1250 TPH for AFI). If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

D.9. The permittee is allowed to handle dust suppressant oiled DAP product with the control device turned off provided that: a) Visible emissions at the transfer point shall be less than 5 % opacity. b) The product shall be sufficiently treated with a non-hazardous oil or dust suppressant to meet the opacity limit in Specific Condition No. D.5. If a visible emission test is conducted at the transfer point, the test shall indicate the approximate rate of usage of the dust suppressant (gal./ton) and the approximate date the DAP was oiled. The maximum storage time prior to handling shall not exceed one month. c) The maximum oiled DAP product handling rate shall be 1250 TPH as demonstrated during the initial compliance tests on October 25, 1994. d) The oiled DAP product handling rate during compliance testing shall be at approximately (90-100%) of the permitted handling rate of 1250 TPH.

D.10. The use of dust suppressant in lieu of operating the current control systems during the handling of chemical products other than DAP is allowed provided that the permittee satisfies the following requirements: [Rule 62-4.070(3), F.A.C.] a) IMC will notify the EPC prior to the deactivation of control devices for the purpose of conducting visible emission tests to demonstrate compliance with the standards. b) IMC shall conduct an initial compliance test for visible emissions at each source for visible emissions (30 minutes, EPA Method 9) at the transfer point

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 22
while handling each additional product. The deactivation of the control devices is limited to the time required to conduct these tests, until authorization by the EPC is issued. c) Testing shall be conducted within 90-100% of the maximum handling rate for each additional product. The actual handling rate and oil to product ratio (gallon/ton) and maximum product storage time shall be included with the test results. d) Two copies of the test results, along with the applicable permit amendment requests, shall be submitted to the Air Division of the EPC within 45 days of testing. e) The EPC shall acknowledge that the above conditions have been satisfied by amending the corresponding permits for approval and issuing.

Recordkeeping and Reporting Requirements

D.11. In order to demonstrate compliance with Specific Condition Nos. D.1., the permittee shall maintain records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Month, year b) Hours of operation c) Material throughput (TPH) d) Rolling twelve month total of c) above.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 23
Subsection E. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -008 Animal Feed Ingredient Handling

For the operation of a truck unloading station, three storage silos, and a transfer conveyor system for animal feed ingredient storage facility. Particulate matter emissions generatedduring the loading of any silo are controlled by one common Mikro-Pulsaire Model 49S8-20 baghouse. Conveyor transfer points and the truck unloading station are covered by enclosures.

{Permitting note(s): These emission units are regulated under Rule 62- 296.711(2)(b), F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

E.1. Capacity. The maximum material handling rate shall not exceed 120 tons per hour and 300,000 tons per year of animal feed ingredient for any 12 consecutive month period. [Rule 62-4.160(2), F.A.C. and Rule 62-210.200, F.A.C., Definitions - (PTE), Construction Permit AC-22822]

E.2. Hours of Operation. The hours of operation for this emissions unit shall not exceed 2,500 hours/year. [Rule 62-4.160(2), F.A.C. and Rule 62-210.200, F.A.C., Definitions - (PTE)]

Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

E.3. The maximum allowable particulate emissions for this baghouse shall not exceed the following for any given hour and for any 12 consecutive month period: [Rule 62-296.711(2)(b), F.A.C., Construction Permit AC-22822]

a) EU No. 8 based on a design flow of 3540 DSCFM: Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 0.5 0.6 0.02 grains/dscf

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E.4. The maximum allowable unconfined particulate emissions for the enclosure shall not exceed 5.14 tons per consecutive 12 month period. [Rule 62 -4- 070(3), F.A.C. and AC-22822]

E.5. The maximum opacity from the baghouse exhaust and the outside pickup point shall not exceed 5% . [Rule 62-296.711(2)(a) and (b), F.A.C.]

E.6. In order to show compliance with the limits of Specific Condition Nos. E.1., E.3., E.4. and E.5., the following restrictions shall apply: [Rule 62-4.070(3)] a) All dust laden air from the transfer operation shall be vented to the baghouse.

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

E.7. Test the emissions from the baghouse exhaust for the following pollutant(s) annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C.:

(X) Particulate* (X) Opacity

* The particulate emission test may be waived if a test is submitted demonstrating compliance with the 5% opacity standard.

E.8 . Compliance with the emission limitations of Specific Condition No. E.3. and E.5. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297, F.A.C]

E.9. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of 120 tons per hour of animal feed ingredient. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 25
conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

Recordkeeping and Reporting Requirements

E.10. In order to demonstrate compliance with Specific Condition Nos. E.1. and E.2., the permittee shall maintain records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Month, year b) Hours of operation c) Material throughput (TPH) d) Rolling twelve month total of c) above.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 26
Subsection F. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -012 Conveyor transfer points from railcar unloading and rock dryer to storage silos

For a material (dry phosphate rock) handling operation consisting of two (2) belt conveyor transfer points and two (2) drop points serving sixteen (16) outer storage silos and seven (7) smaller inner silos. The material originates at a phosphate rock dryer and at a railcar unloading operation which have a maximum production rates as follows:

- Phosphate rock dryer: Depending on the moisture content of the rock, which is

variable and based on 575 TPH - Railcar unloading operation: 1,250 tons per hour based on an individual railcar

load.

The phosphate rock dryer and the rail car unloading can operate simultaneously to produce the maximum material handling rate for this operation.

Particulate matter emissions generated by this material handling operation are controlled by a 23,100 DSCFM Ducon Venturi Oriclone, VVO, 36/84 scrubber located at ground level directly north of the storage silos. The scrubber has three vents which pickup on: (1) outer silos 9-16, inner silos 21-23, and conveyor 27; (2) outer silo 7, inner silo 20, conveyors 38 and 44; (3) and outer silos 1-6, 8 and inner silos 17-19. The phosphate rock dryer and the railcar unloading operation are permitted above.

{Permitting note(s): These emission units are regulated under Rule 62- 296.711(2)(b), F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

F.1. Capacity. The maximum transfer rate of material shall not exceed:

1. Railcar Unloading 1250 TPH 2. Rock Dryer 575 TPH

[Rule 62-4.160(2), F.A.C. , Rule 62-210.200, F.A.C., Definitions - (PTE)]

Emission Limitations and Standards

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 27
{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

F.2. The maximum allowable particulate emissions for the scrubber shall not exceed the following for any given hour and for any 12 consecutive month period: [Rule 62-296.711(2)(b), F.A.C.]

a) EU No. 12 based on a design flow of 23100 DSCFM:

Pollutant lbs./hr. tons/yr. Emission Limitation Particulate Matter 5.94 26.01 0.03 grains/dscf

F.3. The maximum opacity from the scrubber exhaust and the outside pickup point shall not exceed 5% . [Rule 62-296.711(2)(a) and (b), F.A.C.]

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

F.4. Test the emissions from the scrubber exhaust and the outside pickup points concurrently for the following pollutant(s) ) annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty -f ive days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C.:

(X) Opacity (X) Air Flow Rate (Scrubber exhaust only) (X) Particulate Matter*

*Prior to permit renewal

F.5 . Compliance with the emission limitations of Specific Condition No. F.2. and F.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 28
62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297, F.A.C]

F.6. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum handling rate which requires the simultaneous operation of the rock dryer and the railcar (note: If dry phosphate rock handling has been and is expected to remain minimal, testing may be conducted based on the maximum material railcar unloading rate of 1250 TPH for AFI). If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

Recordkeeping and Reporting Requirements

F.7. In order to demonstrate compliance with Specific Condition No. F.1., the permittee shall maintain records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.] a) Month, year b) Hours of operation c) Material throughput (TPH) d) Rolling twelve month total of c) above.

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 29
Subsection G. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -100 DAP Truck Unloading Station No.2

For the operation of DAP truck unloading station No. 2. The trucks are driven into a partially enclosed structure and unloaded through grates in the floor of the structure. The DAP drops onto conveyor C-2 which operates at 339 fpm. Conveyor C-2 transfers the DAP to the bucket elevator C-3. The bucket elevator is capable of elevating 250 TPH. The bucket elevator transfers the DAP to conveyor C-4 at a rate of 687 fpm. Conveyor C-4 transfers the product to conveyor C-7. Conveyor C-7 transports at a rate of 621 fpm. Conveyor C-4 and C-7 are completely enclosed in a building and the DAP is coated with a dust suppressant oil to control emissions.

{Permitting note(s): These emission units are regulated under Rule 62- 296.711(2)(b), F.A.C.}

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters

G.1. Capacity. The maximum truck unloading rate shall not exceed 250 tons per hour of oiled DAP. [Rule 62-4.160(2), F.A.C. , Rule 62-210.200, F.A.C., Definitions - (PTE)]

Emission Limitations and Standards

{Permitting note: Table 1-1, Summary of Air Pollutant Standards and Terms, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

G.2. The maximum opacity from the emission unit shall not exceed 5% . [Rule 62-296.711(2)(a) and (b), F.A.C.]

Test Methods and Procedures

{Permitting note: Table 2-1, Summary of Compliance Requirements, summarizes information for convenience purposes only. This table does not supersede any of the terms or conditions of this permit.}

G.3. Test the emissions from the emission unit for the following pollutant(s) ) annually during each federal fiscal year October1 - September 30 and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of

### Robert H. Kinsey/IMC-Agrico FINAL Permit No. 0570024-003-AV Port Sutton Terminal Page 30
Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C.:

(X) Opacity

G.4 . Compliance with the emission limitations of Specific Condition No. G.2. shall be determined using EPA Method 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the unloading point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297, F.A.C]

G.5. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum handling rate described above. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2)(b), F.A.C.]

Recordkeeping and Reporting Requirements

G.6. In order to demonstrate compliance with Specific Condition No. G.1., the permittee shall maintain records of operations for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.] a) Month, year b) Hours of operation c) Material unloaded (TPH) d) Rolling twelve month total of c) above.

### Kinder Morgan Terminals Tampaplex Terminal Facility ID No.: 0570024 Hillsborough County

Title V Air Operation Permit Revision FINAL Title V Permit No.: 0570024-014-AV

Permitting Authority: Environmental Protection Commission of Hillsborough County 3629 Queen Palm Dr. Tampa, FL 33619 Telephone: (813) 627-2600 Fax: (813) 627-2660

### Title V Air Operation Permit Revision FINAL Title V Permit No.: 0570024-014-AV

Table of Contents
Section Page Number

Statement of Basis................................................................................................... ii
Placard Page............................................................................................................ 1
I. Facility Information ............................................................................................. 2 - 6 A. Facility Description. B. Summary of Emissions Unit ID No(s). and Brief Description(s). C. Relevant Documents.
II. Facility-wide Conditions .................................................................................... 7 - 12

III. Emissions Unit(s) and Conditions..................................................................... 13 - 38



### A. -002 Railcar Unloading -004 C17 Transfer Point E (C17 to C18 or C17 to C19) 

### B. -003 Shiploading Operation (C13 to C14) -005 C12 Transfer Point A (C12 to C13) -006 C30 Transfer Point C (C30 to C12) -013 Shiphold Loading (C14 to Shiphold) 

### C. -007 C18 Transfer Point D (C18 to C12) -009 C19 Transfer Point G (C19 to C38) 

### D. -008 Material Handling and Storage Silos 

### E. -012 Railcar Transfer to Storage Silos (C19 to C38) 

### F. -100 Truck and Railcar Unloading Station No. 2 and Transfer Points (C2, C3, C4, C7, C11, C94) in Storage Building Nos. 1 and 2 

### G. -102 Truck Unloading Station No. 1 and Transfer Point (C82 to C83) - 103 Transfer Points (C83, C84 and C104) in Storage Building No. 3 H. - 104 – 112 Stevedoring Operations: 104 Clamshell to Hopper(s) RH-01 and RH-02 105 RH-01 and RH-02 to Conveyor BC-01 106 Conveyor BC-01 to Radial Stacker RS-01 107 RS-01 to Conveyor BC-02 or Conveyor PC-01 108 Conveyor BC-02 to Conveyor BC-03 or PC-01 to Conveyor PC-02 109 Conveyor BC-03 to Stacker Wing or PC-02 to Radial Stacker RS-02 110 Stacker Wing to Storage Pile or RS-02 to Storage Pile 111 Front End Loader to Truck 112 

### Stevedoring at Other Berths

### Permittee: FINAL Permit No. 0570024-014-AV

Kinder Morgan Terminals Facility ID No.: 0570024 Tampaplex Terminal SIC Nos.: 51 5321 Hartford St. Project: Bulk Material Handling Tampa, FL 33619
This permit is for the revision of a phosphate rock, animal feed ingredient (AFI), fertilizer products (MAP, DAP, GTSP) and other bulk materials handling facility to include the operation of a marine vessel (stevedoring) bulk material loading and unloading operation and stockpiling. This facility is located at 4801 Port Sutton Road, Tampa, Hillsborough County; UTM Coordinates: Zone 17,360.1 km East and 3087.5 km North; Latitude: 27 ° 54’ 24” North and Longitude: 82 ° 25’ 18” West.
This Title V Air Operation Permit Revision is issued under the provisions of Chapter 403, Florida Statutes (F.S.), and Florida Administrative Code (F.A.C.) Chapters 62-4, 62-210 and 62-213. The above named permittee is hereby authorized to operate the facility shown on the application and approved drawing(s), plans, and other documents, attached hereto or on file with the permitting authority, in accordance with the terms and conditions of this permit.
Referenced attachments made a part of this permit: Appendix I-1, List of Insignificant Emissions Units and/or Activities Appendix O-1, Operation and Maintenance Plans for Particulate Control Appendix CAM APPENDIX TV-6, TITLE V CONDITIONS (version dated 6/23/2006) APPENDIX SS-1, STACK SAMPLING FACILITIES (version dated 10/07/96)

Effective Date: October 28, 2009 Renewal Application Due Date: September 16, 2012 Expiration Date: April 29, 2013

___________________________ Richard D. Garrity, Ph.D. Executive Director

RDG/LAW/law

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 2 of 38 Section I. Facility Information.
Subsection A. Facility Description.
This facility consists of truck and railcar unloading operations, a ship loading operation, silo and building storage for phosphate rock, animal feed ingredient (AFI), fertilizer products (MAP, DAP, GTSP) and other bulk materials as defined in this permit’s material handling list/group description. In addition, the facility operates a marine vessel (stevedoring) loading and unloading operation of various bulk materials.
The facility receives dry phosphate rock, AFI, and fertilizer products by truck or railcar to the facility, which is stored within enclosed storage silos or buildings until transported off site by ship or barge. The products can also be transferred directly to a shiphold from a truck or railcar. The majority of these material handling operations are enclosed and controlled through baghouses. The following is a more detailed process of this operation.
During the railcar unloading operation (EU 002), the railcars are pulled into a partially enclosed structure and bottom unloaded through grates in the floor of the structure into six hoppers. Emissions from the hoppers are vented to dry cyclones. Typically four of the six hoppers are used during unloading operations. Material can then transferred from the unloading hoppers to conveyor C17 for subsequent storage in silos via conveyors C19 and C38 (EU 012), or transferred for ship loading via conveyors C18, C12, C13 and C14. The material that will be stored in the silos can be conveyed to the outer silo Nos. 1 – 16 using a series of conveyor belts, Conveyor Belt Nos. C27, C44, and C28, or to the inner silo Nos. 17 -23 using a series of conveyor belts, Conveyor Belt Nos. C19, C38, and C29. All silos are unloaded using Conveyor Belt No. 30 prior to ship loading.
Particulate matter emissions generated from the railcar unloading operation are controlled by six parallel dry cyclones followed by a 100,000 ACFM Amerex Type C Venturi scrubber and/or by the application of dust suppressant oil applied to the fertilizer product at the chemical processing facility prior to shipping. Particulate matter emissions generated from the silo loading are controlled by a 23,100 DSCFM Ducon Venturi Oriclone, VVO, 36/84 scrubber located at ground level directly north of the storage silos.
The facility operation of the various conveyor transfer points include the following; C12 Transfer Point A (EU 005), C30 Transfer Point C (EU 006), C18 Transfer Point D (EU 007), C19 Transfer Point G (EU 009) and C17 Transfer Point E (EU 004). Particulate matter emissions generated during these transfer processes are controlled by Mikro-Pulsaire baghouses, except for C17 Transfer Point E, which is controlled by a 6000 ACFM Poly-Con, Model Venturi 1506MS, scrubber.


### The material handling and storage operation (EU 008) consists of a truck unloading station, three storage silos, and a transfer conveyor system. Material is conveyed from the truck unloading station to three storage silos using Conveyor Belt No. C92. When the material is ready for shiploading, it is unloaded from the silos and conveyed to Conveyor Belt No. C12 using Conveyor Belt No. C93, and then conveyed to Conveyor Belt Nos. C13, and C14 prior to loading on the ship. Particulate matter emissions generated during the loading of any silo are controlled by a common Mikro-Pulsaire baghouse. Particulate

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 3 of 38 matter emissions from the conveyor transfer point (C93 to C12) and the truck unloading station are controlled through the use of partial enclosures.

Trucks can unload material at the truck unloading Station No. 1. Trucks are driven into a partially enclosed structure and unload material through grates in the floor of the structure. The materials are dropped onto Conveyor Belt No. C82, which transfers the material from the truck unloading Station No. 1 to Conveyor Belt No. C83 (EU 102). This transfer point is entirely enclosed. Conveyor Belt No. C83 transfers the material to Conveyor Belt No. C84, which is located inside Storage Building No. 3 (EU 103). Inside the building there is a movable tipper which allows the storage piles to be placed at different locations within the building. Materials are moved within the building with a front end loader, which is also used to transfer the material out of the building to a hopper located on the side of the storage building. The hopper feeds Conveyor Belt No. C104, which transfers material to Conveyor Belt No. C12, using the C12 Transfer Point A associated with EU 005. Storage Building No. 3 is solely associated with Truck Unloading Station No.1. Particulate matter emissions are controlled through the use of dust suppressants (oiling) and enclosures.
Trucks can also unload material at Station No. 2 (EU 100), where they are driven into a partially enclosed structure and unload through grates in the floor of the structure. The material is conveyed into three storage silos using a series of conveyor belts, Conveyor Belt Nos. C2, C4, C7, and C94, and a bucket elevator, No. C3. Conveyor Belt No. C4 can transfer the material to either Conveyor Belt No. C7 or C11. Conveyor Belt No. C7 transfers material to Conveyor Belt No. C94 which loads the three storage silos associated with EU 008. Conveyor Belt No. C11 transfers material to Transfer Point D (EU 007). Conveyor Belt Nos. C4 and C7 are completely enclosed in Storage Building Nos. 1 and 2. 

### Material is also stored in the Blackpoint Storage Building, located on a Kinder Morgan land parcel west of the Tampaplex facility, across the TECO discharge slip. The Blackpoint Storage Building is used to store bagged product only.

The ship loading operation (EU 013) involves the loading of phosphate rock, fertilizer products, AFI and/or other bulk material, which can be conveyed either directly from the railcar, truck, storage buildings, or from the storage silos to the shiphold using a series of conveyor belts, Conveyor Belt Nos. C12, C13, and C14. A telescopic chute and an OBA chokefeeder are used to load the shiphold. Particulate matter emissions generated during the shiphold loading operation are controlled by a modified 9,000 DSCFM Mikro-Pulsaire, Model 1F2, baghouse and/or a gantry mounted dust suppression system. The dust suppression system consists of four spray headers located throughout the gantry using a surfactant chemical that is mixed with water.
Kinder Morgan is also authorized to operate a marine vessel (stevedoring) bulk material loading and unloading operation at the Kinder Morgan’s Tampaplex location and at numerous berths in Hillsborough County. The stevedoring operation involves the loading and unloading of various bulk materials that include fertilizer materials, coal, limestone, granite, bauxite, etc., onto and from marine vessels. These materials are divided into different group categories.

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 4 of 38 At the Tampaplex Terminal, material is unloaded from a ship by one of two clamshells. Theclamshell transfers the material to one of two onshore receiving hoppers. Both hoppers, RH01 and RH-02 (EU 104) are equipped with windshields and water sprays. From the hoppers, material is gravity transferred to a belt conveyor, BC-01 (EU 105), and then to a Radial Switch Stacker, RS-01 (EU 106). From RS-01, material can be transferred in two directions. From RS-01, material is gravity fed to a belt conveyor, PC-01 (EU 107), then to a second conveyor belt PC-02 (EU 108), and then to a second Radial Switch Stacker, RS-02 (EU 109). From RS-02, material is loaded directly into a truck or stockpiled on the ground (EU 110). A front-end loader loads the material into a truck (EU 111) for shipment offsite or for transporting the material to the storage areas.
If material is directed to the dual wing stacker, material from Radial Switch Stacker, RS-01, is gravity transferred to a belt conveyor, BC-02 (EU 107), then to a chute, and then to an uncovered belt conveyor, BC-03 (EU 108). Material is transferred from BC-03 to a dual wing stacker (EU 109) where it is stockpiled (EU 110) in one of two storage areas, the north and south storage areas. From the storage areas, a front-end loader loads the material into a truck (EU 111) for shipment offsite.
All conveyor belts and radial stackers have partial enclosures except for Conveyors BC-01 and BC-03. Conveyor BC-01 has side skirts only because the receiving hoppers can travel along the length of the conveyor belt and partial enclosure would hinder the movement of the receiving hoppers. Conveyor BC-03 has side skirts at the chute transfer point because it is equipped with a moveable dual-wing stacker that travels along the length of the conveyor, which prevents the installation of covers or side skirts along that length. All of the conveyors and radial stackers are equipped with a water spray system. Certain materials (i.e., bauxite, magnetite, etc.), due to their physical nature, cannot be unloaded using the conveyor system. To unload these and any other materials in a manner outlined below for offsite operations, the clamshell transfers material from the ship directly into a truck or into a receiving hopper and into a truck for shipment offsite or for storage. Bauxite is required to be coated with a dust suppressant at the first transfer point at the Tampaplex Site.
In addition the Kinder Morgan Tampaplex site can receive products onto the site from Belted Self Unloading Vessels. During this operation the vessel will be equipped with an extendable conveyor belt that would transfer product directly onto a storage pile. A front-end loader loads the material into a truck for shipment offsite.
Particulate matter (PM) emissions from these facility operations are controlled by the use of a water spray system and partial enclosures, and or dust suppressants. The facility operates a truck wheel wash to wash particulate material from truck tires prior to the trucks leaving the site.
When operating at berths other than the Kinder Morgan’s Tampaplex site, the Stevedoring operation operates as follows:
A maximum of three, portable clamshells used to either load or unload material from a ship are mounted to barges and moved to any of the Berths listed below. The clamshells may operate at a maximum of three berths simultaneously.

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 5 of 38 When material is unloaded from ships, material is transferred from the shiphold using one of the three clamshells to a portable receiving hopper, then to a truck, and then transported either offsite or to a storage pile. The receiving hoppers are equipped with windshields and a water spray system around the perimeter.
When material will be loaded into ships, trucks transport the material to the dock and the portable clamshells transfer the material from the dock into a shiphold. However, the material should not stockpiled on the dock longer than 24 hours.
The Stevedoring operation is permitted to operate at the following berths in Hillsborough County: 1, 2, 3, 23, 24, 24B, North Star Recycling Slip 30, 31, 201, 202, 204, 205, 206, 208, 209, 210, 211, 212, 214, 215, 219, 220, 223, 224, 225, 227, 230, 232, 250, 251, 252, 253, 256, 263, 264, 265, 268, 272, 273, Kinder Morgan’s Tampaplex Terminal Port Tampa

(near Picnic Island): 119 - Tampa Bulk Services Rattlesnake Point: 126 - Misener Rock Company Alafia River: Cargill Fertilizer Dock
The facility is subject to Rules 62-296.320 – General Pollutant Emission Limiting Standards and 62-296.711, F.A.C. - Materials Handling, Sizing, Screening, Crushing and Grinding Operations and Chapter 1-3.52, Rules of the EPC, which limit the visible emissions to a 5% opacity standard for all of the material handling operations. EPA Method 5 and EPA Method 9 testing have been determined by the Agency to satisfy the requirements of 40 CFR 70.6 and Chapter 62-296, F.A.C.
Also included in this permit are miscellaneous insignificant emissions units and/or activities.
Based on the Title V Air Operation Permit Revision application received October 8, 2007, this facility is not a major source of hazardous air pollutants (HAPs).



### Subsection B. Summary of Emissions Unit ID No(s). and Brief Description(s).

E.U. ID No. Brief Description
-002 Railcar Unloading -003 Shiploading Operation (C13 to C14) -004 C17 Transfer Point E (C17 to C18 or C17 to C19) -005 C12 Transfer Point A (C12 to C13) -006 C30 Transfer Point C (C30 to C12) -007 C18 Transfer Point D (C18 to C12) -008 Material Handling and Storage Silos -009 C19 Transfer Point G (C19 to C38) -012 Railcar Transfer to Storage Silos (C19 to C38) -013 Shiphold Loading (C14 to Shiphold) -100 Truck and Railcar Unloading Station No. 2 and Transfer Points (C2, C3, C4,

C7, C11, C94) in Storage Building Nos. 1 and 2 -102 Truck Unloading Station No. 1 and Transfer Point (C82 to C83)

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 6 of 38 -103 Transfer Points (C83, C84 and C104) in Storage Building No. 3 -104 - 112 Stevedoring Operation: -104 Clamshell to Hopper(s) RH-01 and RH-02 -105 RH-01 and RH-02 to Conveyor BC-01 -106 Conveyor BC-01 to Radial Stacker RS-01 -107 RS-01 to Conveyor BC-02 or Conveyor PC-01 -108 Conveyor BC-02 to Conveyor BC-03 or PC-01 to Conveyor PC-02 -109 Conveyor BC-03 to Stacker Wing or PC-02 to Radial Stacker RS-02 -110 Stacker Wing to Storage Pile or RS-02 to Storage Pile -111 Front End Loader to Truck -112 

### Stevedoring at Other Berths
Please reference the Permit No., Facility ID No., and appropriate Emissions Unit(s) ID No(s). on all correspondence, test report submittals, applications, etc.

Subsection C. Relevant Documents.
The documents listed below are not a part of this permit, however, are specifically related to this permitting action.
These documents are provided to the permittee for information purposes only: Table 1-1, Summary of Air Pollutant Standards and Terms Table 2-1, Summary of Compliance Requirements Appendix A-1, Abbreviations, Acronyms, Citations, and Identification Numbers Appendix H-1, Permit History/ID Number Changes
These documents are on file with permitting authority: Initial Title V Permit Application received June 14, 1996 Initial Title V Permit issued October 26, 2000 Title V Air Operation Permit Revision issued May 30, 2001 Title V Air Operation Permit Administrative Correction issued January 21, 2004 Title V Air Operation Permit Renewal issued April 29, 2008

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 7 of 38 Section II. Facility-wide Conditions.
The following conditions apply facility-wide:
1. General Pollutant Emission Limiting Standards. Objectionable Odor Prohibited. No person shall cause, suffer, allow, or permit the discharge of air pollutants which cause or contribute to an objectionable odor. [Rule 62-296.320(2), F.A.C. and Permit No. 0570024-015-AC]
2. General Particulate Emission Limiting Standards. General Visible Emissions Standard. Except for emissions units that are subject to a particulate matter or opacity limit set forth or established by rule and reflected by conditions in this permit, no person shall cause, let, permit, suffer or allow to be discharged into the atmosphere the emissions of air pollutants from any activity, the density of which is equal to or greater than that designated as Number 1 on the Ringelmann Chart (20 percent opacity). EPA Method 9 is the method of compliance pursuant to Chapter 62-297, F.A.C. [Rules 62-296.320(4)(b)1. & 4., F.A.C.]

3. Prevention of Accidental Releases (Section 112(r) of CAA). a. The permittee shall submit its Risk Management Plan (RMP) to the Chemical Emergency Preparedness and Prevention Office (CEPPO) RMP Reporting Center when, and if, such requirement becomes applicable. Any Risk Management Plans, original submittals, revisions or updates to submittals, should be sent to:
RMP Reporting Center Post Office Box 1515 Lanham-Seabrook, MD 20703-1515 Telephone: 301/429-5018
b. The permittee shall submit to the permitting authority Title V certification forms or a compliance schedule in accordance with Rule 62-213.440(2), F.A.C. [40 CFR 68]
4. Insignificant Emissions Units and/or Activities. Appendix I-1, List of Insignificant Emissions Units and/or Activities, is a part of this permit. [Rules 62-213.440(1), 62-213.430(6) and 62-4.040(1)(b), F.A.C.]
5. General Pollutant Emission Limiting Standards. Volatile Organic Compounds (VOC) Emissions or Organic Solvents (OS) Emissions . The permittee shall allow no person to store, pump, handle, process, load, unload or use in any process or installation, volatile organic compounds (VOC) or organic solvents (OS) without applying known and existing vapor emission control devices or systems deemed necessary and ordered by the Department.

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 8 of 38 A) Maintain tightly fitting cover, lids, etc. on all containers when they are not being handled, tapped, etc. B) Where possible and practical, procure/fabricate a tightly fitting cover for any open trough, basin, etc. of VOC so that it can be covered when not in use. C) Immediately attend to all spills/waste as appropriate. [Rule 62-296.320(1)(a), F.A.C. and Proposed by applicant in the initial Title V permit application received June 16, 1996]

6. Emissions of Unconfined Particulate Matter . Pursuant to Rules 62- 296.320(4)(c)1., 3. & 4., F.A.C., reasonable precautions to prevent emissions of unconfined particulate matter at this facility include the following requirements (see Condition 57. of APPENDIX TV-6, TITLE V CONDITIONS).

A) Post and enforce a speed limit of 10 miles per hour B) Maintain material drop points as low as possible C) Curtail operations during high wind conditions, if necessary D) Exercise good housekeeping at all times E) Application of asphalt, water, oil, chemicals or other dust suppressants to unpaved roads, yards, and open stock piles, as necessary F) Removal of particulate matter from buildings, work areas, roads and other paved areas under the control of the owner or operator of the facility to prevent entrainment, as necessary G) Maintenance of parking areas and yards H) Landscaping or planting of vegetation I) Water sprays shall be used as necessary to ensure compliance with the 5% opacity standard. [Rule 62-296.320(4)(c)2., F.A.C.; Proposed by applicant in the initial Title V permit application received June 16, 1996; and Permit No. 0570024-016-AC]
7. The permittee shall notify the Air Compliance Section of the Environmental Protection Commission of Hillsborough County at least 15 days prior to the date on which each formal compliance test is to begin of the date, time, and place of each such test, and the contact person who will be responsible for coordinating and having such test conducted. [Rule 62-297.310, F.A.C.]
8. When appropriate, any recording, monitoring, or reporting requirements that are time-specific shall be in accordance with the effective date of the permit, which defines day one. [Rule 62-213.440, F.A.C.]
9. Statement of Compliance . The annual statement of compliance pursuant to Rule 62-213.440(3)(a)2., F.A.C., shall be submitted to the Environmental Protection Commission and EPA within 60 (sixty) days after the end of the calendar year using DEP Form No. 62-213.900(7), F.A.C. [Rules 62-213.440(3) and 62-213.900, F.A.C.]

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 9 of 38 {Permitting Note: This condition implements the requirements of Rules 62- 213.440(3)(a)2. & 3., F.A.C. (see Condition 51. of APPENDIX TV-6, TITLE V CONDITIONS)}
10. Submit to the Environmental Protection Commission of Hillsborough County each calendar year on or before April 1, completed DEP Form 62-210.900(5), "Annual Operating Report for Air Pollutant Emitting Facility", for the preceding calendar year. [Rule 62-210.370(2), F.A.C.]
11. The permittee shall comply with Appendix O-1, Operation and Maintenance Plans for Particulate Control. In the event of a deviation from the monitoring parameters, the facility shall take corrective actions to remedy the situation. Notify the Environmental Protection Commission of Hillsborough County within 24 hours of the problem. The emission unit shall not be operated until the problem is corrected. A written explanation and the corrective actions implemented shall be submitted in the semi-annual report required in the TV-6 Condition Nos. 43, 44, 45. Records of inspections, maintenance, and performance parameters shall be retained for a minimum of five years and shall be made available to the Environmental Protection Commission of Hillsborough County upon request. [Rules 62-296.700(6)(e) and 62-4.070(3), F.A.C.]
12. The permittee shall submit all compliance related notifications and reports required of this permit to the Environmental Protection Commission of Hillsborough County at:

Environmental Protection Commission Air Management Division 3629 Queen Palm Dr. Tampa, FL 33619 Telephone: 813/627-2600, Fax: 813/627-2660
13. Any reports, data, notifications, certifications, and requests required to be sent to the United States Environmental Protection Agency, Region 4, should be sent to:

United States Environmental Protection Agency

Region 4 Air, Pesticides & Toxics Management Division Air and EPCRA Enforcement Branch Air Enforcement Section 61 Forsyth Street Atlanta, Georgia 30303-8960 Telephone: 404/562-9155; Fax: 404/562-9163
14. When the Environmental Protection Commission of Hillsborough County (EPC) after investigation, has good reason (such as complaints, increased visible emissions or questionable maintenance of control equipment) to believe that any applicable emission standard contained in Rules 62-204, 62-210, 62-212, 62-296, or 62-297, F.A.C., or in a

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 10 of 38 permit issued pursuant to those rules is being violated, it may require the owner or operator of the source to conduct compliance tests which identify the nature and quantity of pollutant emissions from the source and to provide a report on the results of said tests to the EPC. [Rule 62-297.310(7)(b), F.A.C. and Permit No. 0570024-015-AC]
15. The permittee shall give prior notification and obtain approval from the EPCHC for the loading and/or unloading of any new material not identified in this permit. [Rules 62-4.070(3) and 62-210.200(205), F.A.C. and Permit No. 0570024-016-AC]
16. The permittee shall provide timely notification to the Environmental Protection Commission of Hillsborough County prior to implementing any changes that may result in a modification to this permit pursuant to Rule 62-210.200(205), F.A.C., Modification. The changes do not include normal maintenance, but may include, and are not limited to, the following, and may also require prior authorization before implementation: [Rules 62- 210.300 and 62-4.070(3), F.A.C. and Permit No. 0570024-015-AC]

A) Alteration or replacement of any equipment or major component of such equipment. B) Installation or addition of any equipment which is a source of air pollution. C) The handling of any new material not identified in this permit.

17. Certification by Responsible Official (RO) . In addition to the professional engineering certification required for applications by Rule 62-4.050(3), F.A.C., any application form, report, compliance statement, compliance plan and compliance schedule submitted pursuant to Chapter 62-213, F.A.C., shall contain a certification signed by a responsible official that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete. Any responsible official who fails to submit any required information or who has submitted incorrect information shall, upon becoming aware of such failure or incorrect submittal, promptly submit such supplementary information or correct information. [Rule 62-213.420(4), F.A.C.] 18. APPENDIX TV-6, TITLE V CONDITIONS, is a part of this permit. [Rule 62-4.070(3), F.A.C.] 19. The permittee shall handle the following materials at the Tampaplex site and at all Stevedoring locations. [Rule 62-4.07(1), F.A.C. and Permit No. 0570024-016-AC] A) Group I – Dusty Fertilizers
Ammonium Sulfate Granular Sulfate of Potash Animal Feed Ingredients Standard Muriate of Potash Standard Sulfate of Potash Standard Potassium NitrateGranular Muriate of Potash Granular Sulfate of PotashMagnesium Standard Sulfate of Potash-Magnesium

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Tampaplex Terminal Project: Bulk Material Handling

Page 11 of 38 Group II – Phosphate Rock Phosphate Products Rock

Group III – Minimally Dusty Fertilizers
Ammonium Nitrate Sodium Potassium Nitrate MAP Calcium Ammonium Nitrate Compound Fertilizers DAP Potassium Nitrate Dried Sludge GTSP
Calcium Nitrate Urea Kieserite Group I V – Millscale

Millscale Group V– Moderately Dusty Non-Fertilizer Products Coal Syngypsum Clay
Petcoke Iron Ore Magnetite/Ferrous Oxides Group VI – Minimally Dusty Non-Fertilizer Products Gypsum Alumina Hydrate Filler Materials Pumice Vermiculite Peanut Hulls Wood Chips Dolomite Salt (solar) Ferrous Sulfate Glass Bio-Mass Ferro Alloys Iron Scrap (including shredded scrap metal) Granulated Furnace Slag Clinker (treated or screened) Prilled Sulfur Group VII – Coal Slag Coal Slag Group VIII – Agricultural Products Grains Grain Meals Seeds Soybeans Grain Byproducts Peas Wheat, Rye, Barley Citrus Pellets Group IX – Bauxite/Alumina and similar Dusty Cement-like Products Bauxite Alumina Slag Cement Group X - Aggregate Limestone Granite Rocks Gravel Stone Group XI – Sand and Similar Materials Sand Soil Limestone Fines

Dirt

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Tampaplex Terminal Project: Bulk Material Handling

Page 12 of 38 B) Millscale shall be treated with water or a dust suppressant at the first material

transfer point and subsequent material transfer points as necessary to meet the 5% opacity standard. C) All materials in Group IX shall be treated with a dust suppressant at the first material transfer point and subsequent material transfer points as necessary to meet the 5% opacity standard.
20. As requested by the permittee, in order to remain a synthetic minor facility with respect to the requirements of Rule 62-212.400, Prevention of Significant Deterioration, F.A.C., the maximum potential to emit (PTE) particulate matter emissions shall not exceed 249 tons per twelve consecutive month period, which is comprised of the following operations: A) Particulate Matter Emissions from the Tampaplex Operation: 51 tons B) Particulate Matter Emissions from the Stevedoring Operation: 198 tons [Rule 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]
21. In order to ensure compliance with the emission limitations in Specific Condition No. 20., the following restrictions and limitations shall apply for any consecutive twelve month period: [Rule 62-4.070(3), F.A.C. and Construction Permit No. 0570024-016-AC]

A) The maximum combined throughput amount of material handled at the Tampaplex location shall not exceed 11,826,000 tons B) The combined material throughput handled through the Stevedoring operation shall not result in that operation emitting more than 198 tons of particulate matter emissions per twelve consecutive month period.

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Tampaplex Terminal Project: Bulk Material Handling

Page 13 of 38 Section III. Emissions Unit(s) and Conditions.
Subsection A. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -002 Railcar Unloading -004 C17 Transfer Point E (C17 to C18 or C17 to C19)

EU No. 002 : During the railcars unloading operation, railcars are pulled into a partially enclosed structure and bottom unloaded through grates in the floor of the structure into six hoppers. Emissions from the hoppers are vented to dry cyclones. Butterfly valves in the riser pipe routed to each dry cyclone are used to isolate or shut off airflow to hoppers not being used. Typically four of the six hoppers are used during unloading operations. Material can be transferred from the unloading hoppers to conveyor C17 for subsequent storage in silos via conveyors C19 and C38, or transferred for ship loading via conveyors C18, C12, C13 and C14.
Particulate matter emissions generated from the railcar unloading operation are controlled by six parallel dry cyclones followed by a 100,000 ACFM Amerex Type C Venturi scrubber and/or by the application of a dust suppressant oil applied to the product at the chemical processing facility prior to shipping.

EU No. 004: The C17 transfer point E directs material from Conveyor Belt No. C17 either to Conveyor Belt No. C18 or to Conveyor Belt No. C19. Particulate matteremissions generated during the transfer process are controlled by a 6000 ACFM PolyCon, Model Venturi 1506MS, scrubber.

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
A.1. Capacity. The maximum product unloading rate shall not exceed 1800 tons/hour. [Rule 62-210.200, F.A.C., Definitions – Potential to Emit, and Construction Permit Nos. AC29-237340 and 0570024-016-AC]

Emission Limitations and Standards
A.2. The maximum allowable particulate emissions from each scrubber shall not exceed the following for any given hour and any twelve consecutive month period: a) EU No. 002 based on a design flow of 100,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 28.2 0.01 grains/dscf 6570 Visible Emissions 5% opacity

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Tampaplex Terminal Project: Bulk Material Handling

Page 14 of 38 b) EU No. 004 based on a design flow of 6,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 1.7 0.01 grains/dscf 6570 Visible Emissions 5% opacity [Rules 62-4.070(3) and 62-296.711(b), F.A.C. and Construction Permit Nos. AC29-237340 and 0570024-016-AC]
A.3. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from the railcar unloading operation and the scrubber exhaust, and from the C17 Transfer Point E and the scrubber exhaust. [Rule 62-296.711(a), F.A.C. and Construction Permit 0570024-016-AC]
A.4. During the handling of DAP with the scrubber(s) turned off, the following conditions shall be met:

a) The opacity limitation in Specific Condition No. A.3. shall be monitored by a certified smoke reader. b) The product shall be sufficiently treated with a non-hazardous oil or dust suppressant to meet the opacity limit in Specific Condition No. A.3. [Rule 62-4.070(3) F.A.C. and Construction Permit AC29-237340]

Test Methods and Procedures
A.5. Test EU 002 (scrubber exhaust and the railcar unloading enclosure) and EU No. 004 (scrubber exhaust and transfer point enclosure) for opacity once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air ManagementDivision of the Environmental Protection Commission of Hillsborough County within fortyfive days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
A.6. Test EU No. 002 for particulate matter (PM) once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62- 297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]

A.7. [Reserved.]
A.8. Test EU No. 004 for particulate matter (PM) within 120 days prior to expiration of this permit and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62- 297.310, F.A.C. [Rules 62-297.310(7)(a)4. and 62-4.070(3), F.A.C.]

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Tampaplex Terminal Project: Bulk Material Handling

Page 15 of 38 A.9. [Reserved.]
A.10. Compliance with the emission limitations of Specific Condition No. A.2. and A.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be conducted by a certified observer and be a minimum of sixty (60) minutes in duration for the scrubber exhaust and thirty (30) minutes in duration for the railcar enclosure. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297.310(4)(a)2., F.A.C.]
A.11. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum unloading rates of 1800 TPH. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions of the scrubber such as inlet pressure drop and liquor feed rate, may invalidate the test. [Rules 62-297.310(2) and 62-4.070(3), F.A.C.]
A.12. The use of dust suppressant in lieu of operating the current control system(s) during the handling of materials is allowed provided that the operation does not exceed the 5% opacity standard. [Rule 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]

Recordkeeping and Reporting Requirements
A.13. In order to demonstrate compliance with Specific Condition Nos. A.1. and A.2., the permittee shall maintain a monthly recordkeeping system for the most recent 5 year period. The records shall be made available to the EPC of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but are not limited to, the following:

a) Day, Month, Year b) Amount and type of dust suppressant applied (gallon/ton) for each oiled product unloaded during the preceding month. c) Certificate for smoke reader at the facility who monitored DAP or other fertilizer product unloading with the scrubber off. d) Hours of operation for each emission unit and scrubbers e) Amount and type of material unloaded from railcars (tons) f) Rolling twelve month total of d) and e) above for each material handled [Rule 62-4.070(3), F.A.C.]

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Tampaplex Terminal Project: Bulk Material Handling

Page 16 of 38 Subsection B. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -003 Shiploading Operation -005 C12 Transfer Point A (C12 to C13) -006 C30 Transfer Point C (C30 to C12) -013 Shiphold Loading (C14 to Shiphold)

EU Nos. 003 and No. 013: The shiphold loading operation involves the loading of phosphate rock, fertilizer products, AFI and/or other bulk material, which can be conveyed either directly from the railcar or from the storage silos to the shiphold using a series of conveyor belts, Conveyor Belt Nos. C12, C13, and C14. A telescopic chute and an OBA chokefeeder are used to load the shiphold.
Particulate matter emissions generated during the shiphold loading operation are controlled by a modified 9,000 DSCFM Mikro-Pulsaire, Model 1F2, baghouse and/or a gantry mounted dust suppression system. The dust suppression system consists of four spray headers located throughout the gantry using a surfactant chemical that is mixed with water.

EU No. 005: The C12 Transfer Point A transfers material from Conveyor Belt No. C12 to Conveyor Belt No. C13. Particulate emissions generated during the transfer process are controlled by an 8,000 DSCFM Mikro-Pulsaire, Model 80F2, baghouse.

EU No. 006.: The C30 Transfer Point C is used to transfer material from Conveyor Belt No. C30 to Conveyor Belt No. C12. Particulate matter emissions generated during the transfer operation are controlled by a 6,000 DSCFM Mikro-Pulsaire, Model 1215-8-80, baghouse.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
B.1. Capacity. The maximum transfer rate of material shall not exceed 2300 TPH. [Rules 62-210.200, Definitions - (PTE) and 62-4.070(3), F.A.C. and Construction Permit No. 0570024-016-AC]

Emission Limitations and Standards
B.2. The maximum allowable particulate matter emissions for each baghouse shall not exceed the following for any given hour and for any 12 consecutive month period:

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Tampaplex Terminal Project: Bulk Material Handling

Page 17 of 38 a) EU No. 003 based on a design flow of 9,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 7.6 0.03 grains/dscf 6570
b) EU No. 005 based on a design flow of 8,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 2.3 0.01 grains/dscf 6570
c) EU No. 006 based on a design flow of 6,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 1.7 0.01 grains/dscf 6570

[Rule 62-296.711(2)(b), F.A.C. and Permit No. 0570024-016-AC]
B.3. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from each emission source and baghouse exhaust except where material is being discharged to the hold of a ship from a conveyor system. When the conveyor and/or hatch covering is moved, an opacity of 10 percent will be allowed. [Rule 62-296.711(2)(a), F.A.C.]
B.4. In order to demonstrate compliance with the limits of Specific Condition Nos. B.2. and B.3., the following restrictions shall apply: [Rule 62-4.070(3), F.A.C.]

a) All dust laden air from each transfer operation shall be vented to the corresponding baghouse, unless the material has been treated with a dust suppressant. b) The gantry dust suppression system shall be maintained in operable condition so that it can be operated at any time as necessary during the loading of material to maintain compliance with the permitted opacity limit.

Test Methods and Procedures
B.5. Test the emissions from the following emission units for opacity once per federal fiscal year (October 1 - September 30) and submit two copies of test data to the Air ManagementDivision of the Environmental Protection Commission of Hillsborough County within fortyfive days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310, F.A.C.]

a) The shiploading operation and baghouse - Emission Unit No. 003 b) Shiphold opening- Emission Unit No. 013 c) C12 Transfer Point A and baghouse exhaust - Emission Unit No. 005 d) C30 Transfer Point C and baghouse exhaust - Emission Unit No. 006 e) Test the shiphold opening and the shiploading operation and baghouse each time a new material is handled during the loading of the ship.

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Tampaplex Terminal Project: Bulk Material Handling

Page 18 of 38 B.6. Test each emission unit for particulate matter at least 120 days prior to the expiration date of this permit. In the event that dry phosphate pebble rock is handled at the facility, a particulate matter test shall be performed on Emission Units 003 and 013. Particulate test shall be conducted under the similar process rate and operating condition(s) as the visible emission test for the baghouse exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test runs for the particulate matter emissions. [Rule 62-297.310(7)(a)3., F.A.C.]
B.7. Compliance with the emission limitations of Specific Condition No. B.2. and B.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval on the source shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the gantry dust suppression system was operating during the visible emission readings. [Rule 62-297.310(4)(a)2., F.A.C.]
B.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of handling 2300 TPH for all materials. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-297.310(2) and 62-4.070(3), F.A.C.]

B.9. [Reserved] B.10. The use of dust suppressant in lieu of operating the current control system(s) during the handling of materials is allowed provided that the operation does not exceed the 5% opacity standard. [Rule 62-4.070(3), F.A.C.]

Recordkeeping and Reporting Requirements B.11. In order to demonstrate compliance with Specific Condition No. B.1., the permittee shall maintain a monthly recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state, or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Day, Month, year b) Hours of operation for each emission unit and baghouse c) Amount and type of material loaded into ships (tons) d) Rolling twelve month total of b) and c) above for each material handled

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Tampaplex Terminal Project: Bulk Material Handling

Page 19 of 38 Subsection C. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -007 C18 Conveyor Transfer Point D (C18 to C12) -009 C19 Conveyor Transfer Point G (C19 to C38)

EU No. 007: The C18 conveyor transfer point D transfers material from Conveyor Belt No. C18 to Conveyor Belt No. C12. Particulate matter emissions generated during the transfer process are controlled by a 6000 ACFM Mikro-Pulsaire, Model 1215-8-80, baghouse.

EU No. 009: The C19 Conveyor Transfer Point G transfers material from Conveyor Belt No. C19 to Conveyor Belt No. C38. Particulate matter emissions generated during the transfer process are controlled by a 5000 ACFM Mikro-Pulsaire, Model 1215-8-80, baghouse.

The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
C.1. Capacity. The maximum transfer rate of material shall not exceed 1800 tons/hour. [Rules 62-210.200, Definitions - (PTE) and 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]

Emission Limitations and Standards
C.2. The maximum allowable particulate matter emissions from each baghouse shall not exceed the following for any given hour and for any 12 consecutive month period:
a) EU No. 007 based on a design flow of 6,000 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 1.7 0.01 grains/dscf 6570
b) EU No. 009 based on a design flow of 4,200 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 1.2 0.01 grains/dscf 6570 [Rule 62-296.711(2)(b), F.A.C. and Permit No. 0570024-016-AC]
C.3. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from each emission unit and baghouse exhaust. [Rule 62-296.711(2)(a), F.A.C.]

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Tampaplex Terminal Project: Bulk Material Handling

Page 20 of 38 C.4. In order to demonstrate compliance with the limits of Specific Condition Nos. C.2. and C.3., all dust laden air from each transfer operation shall be vented to the corresponding baghouse, unless the material has been treated with a dust suppressant. [Rule 62-4.070(3), F.A.C.]

Test Methods and Procedures
C.5. Test the emissions from each emission unit and baghouse exhaust for opacity once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
C.6. Test each emission unit for particulate matter at least 120 days prior to the expiration date of this permit. Particulate test shall be conducted under similar process rate(s) and operating condition(s) as the visible emission test for the baghouse exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test runs for the particulate matter emissions. [Rule 62-297.310(7)(a)3., F.A.C.]
C.7. Compliance with the emission limitations of Specific Condition No. C.2. and C.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the corresponding transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297.310(4)(a)2., F.A.C.]
C.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum unloading rates of 1800 TPH. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-297.310(2) and 62-4.070(3), F.A.C.]
C.9. The permittee is allowed to handle dust suppressant oiled DAP product with the control device turned off provided that: [Rule 62-4.070(3), F.A.C.]

a) Visible emissions at each transfer point shall be less than 5 % opacity. b) The product shall be sufficiently treated with a non-hazardous oil or dust suppressant to meet the opacity limit in Specific Condition No. C.3.

C.10. [Reserved]

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Tampaplex Terminal Project: Bulk Material Handling

Page 21 of 38 Recordkeeping and Reporting Requirements
C.11. In order to demonstrate compliance with Specific Condition No. C.1., the permittee shall maintain a monthly recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Day, Month, Year b) Hours of operation for each emission unit and baghouse c) Amount and type of material transferred on each conveyor system (tons) d) Rolling twelve month total of b) and c) above.

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Tampaplex Terminal Project: Bulk Material Handling

Page 22 of 38 Subsection D. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -008 Material Handling and Storage Silos
The material handling and storage operation consists of a truck unloading station, three storage silos, and a transfer conveyor system. Material is conveyed from the truck unloading station to three storage silos using Conveyor Belt No. C92. Material is unloaded from the silos and conveyed to Conveyor Belt No. C12 using Conveyor Belt No. C93 when it is ready for ship loading.
Particulate matter emissions generated during the loading of any silo are controlled by a common 3,565 ACFM Mikro-Pulsaire, Model 49S-8-20, baghouse. Particulate matter emissions from the conveyor transfer points and the truck unloading station are controlled through the use of partial enclosures.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
D.1. D.1. Capacity. The maximum material handling rate shall not exceed 120 tons per hour and 300,000 tons per year for any 12 consecutive month period. [Rules 62-210.200, Definitions - (PTE) and 62-4.070(3), F.A.C. and Construction Permit AC29-22822]
D.2. Hours of Operation. The hours of operation for this emissions unit shall not exceed 2,500 hours/year. [Rules 62-210.200, Definitions - (PTE) and 62-4.070(3), F.A.C.]

Emission Limitations and Standards
D.3. The maximum allowable particulate matter emissions from the common MikroPulsaire, Model 49S-8-20, baghouse shall not exceed the following for any given hour and for any 12 consecutive month period:
a) EU No. 008 based on a design flow of 3,200 DSCFM: Pollutant

tons/yr. Emission Limitation Particulate Matter 0.6 0.02 grains/dscf

[Rule 62-4.070(3), F.A.C. and Construction Permit Nos. AC29-22822 and 0570024-016- AC]
D.4. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from each emission unit and baghouse exhaust. [Rule 62-296.711(2)(a), F.A.C.]

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Tampaplex Terminal Project: Bulk Material Handling

Page 23 of 38 D.5. In order to demonstrate compliance with the limits of Specific Condition No. D.3., all dust laden air from the transfer operation shall be vented to the corresponding baghouse, unless the material has been treated with a dust suppressant. [Rule 62-4.070(3), F.A.C.]

Test Methods and Procedures
D.6. Test the emissions from the emission unit and baghouse exhaust for opacity once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
D.7. Test the emission unit for particulate matter at least 120 days prior to the expiration date of this permit. Particulate test shall be conducted under similar process rate(s) and operating condition(s) as the visible emission test for the baghouse exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test runs for the particulate matter emissions. [Rule 62-297.310(7)(a)3., F.A.C.]
D.8. Compliance with the emission limitations of Specific Condition No. D.3. and D.4. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test interval shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the corresponding transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297.310(4)(a)2., F.A.C.]
D.9. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum handling rate of 120 tons per hour of material. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2), F.A.C.]
Recordkeeping and Reporting Requirements
D.10. In order to demonstrate compliance with Specific Condition Nos. D.1. and D.2., the permittee shall maintain a monthly recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

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Page 24 of 38 a) Day, Month, Year b) Hours of operation of the emission unit and baghouse c) Amount and type of material unloaded from trucks (tons) into the silos d) Rolling twelve month total of b) and c) above.

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Tampaplex Terminal Project: Bulk Material Handling

Page 25 of 38 Subsection E. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -012 Railcar Transfer to Storage Silos
Material unloaded at the railcar unloading station can either be conveyed to sixteen outer storage silos (Silo Nos. 1 – 16) using a series of conveyor belts, Conveyor Belt Nos. C27, C44, and C28, or to seven smaller inner storage silos (Silo Nos. 17 -23) using a series of conveyor belts, Conveyor Belt Nos. C19, C38, and C29. All silos are unloaded using Conveyor Belt No. 30.
Particulate matter emissions generated by this material handling operation are controlled by a 23,100 DSCFM Ducon Venturi Oriclone, VVO, 36/84 scrubber located at ground level directly north of the storage silos. The scrubber has three vents which pickup on: (1) outer silos 9-16, inner silos 21-23, and conveyor 27; (2) outer silo 7, inner silo 20, conveyors 38 and 44; (3) and outer silos 1-6, 8 and inner silos 17-19.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
E.1. Capacity. The maximum railcar unloading and transfer rate of material shall not exceed 1800 TPH. [Rules 62-210.200, Definitions - (PTE) and 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]

Emission Limitations and Standards
E.2. The maximum allowable particulate matter emissions for the scrubber shall not exceed the following for any given hour and for any 12 consecutive month period:
a) EU No. 012 based on a design flow of 23,100 DSCFM: Pollutant

tons/yr. Allowable Emissions Hours of Operation/Yr Particulate Matter 6.5 0.01 grains/dscf 6570 [Rule 62-296.711(2)(b), F.A.C. and Permit No. 0570024-016-AC]
E.3. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from the emission unit and scrubber exhaust. [Rule 62-296.711(2)(a), F.A.C.]

Test Methods and Procedures
E.4. Test the emissions from the emission unit and scrubber exhaust for opacity once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough

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Page 26 of 38 County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
E.5. Test the emission unit for particulate matter at least 120 days prior to the expiration date of this permit. Particulate test shall be conducted under similar process rate(s) and operating condition(s) as the visible emission test for the scrubber exhaust. If possible, the visible emission test shall be performed simultaneously with one of the test runs for the particulate matter emissions. [Rule 62-297.310(7)(a)3., F.A.C.]
E.6. Compliance with the emission limitations of Specific Condition No. E.2. and E.3. shall be determined using EPA Methods 1, 2, 4, 5 and 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be thirty (30) minutes in duration, and the test shall be conducted concurrently on the control equipment exhaust and the corresponding transfer point. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. The test report shall indicate whether the dust suppression system was operating during the visible emission readings. [Rule 62-297.310(4)(a)2., F.A.C.]

E.7. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum material handling rate of 1800 tons/hour. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2), F.A.C.]

Recordkeeping and Reporting Requirements
E.8. In order to demonstrate compliance with Specific Condition No. E.1., the permittee shall maintain a monthly recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Day, Month, Year b) Hours of operation of the emission unit and scrubber c) Amount and type of material loaded into the silos (tons) d) Rolling twelve month total of b) and c) above.

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Tampaplex Terminal Project: Bulk Material Handling

Page 27 of 38 Subsection F. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -100 Truck and Railcar Unloading Station No. 2 and Transfer Points (C2, C3, C4,

C7, C11, C94) in Storage Building Nos. 1 and 2
Trucks and railcars are driven into a partially enclosed structure and unload material through grates in the floor of the structure. The material is conveyed into three storage silos using a series of conveyor belts, Conveyor Belt Nos. C2, C4, C7, and C94, and a bucket elevator, No. C3. Material is transferred from Conveyor Belt No. C2 to Bucket elevator No. C3 and then to Conveyor Belt No. C4. Conveyor Belt No. C4 transfers the material to either Conveyor Belt No. C7 or C11. Conveyor Belt No. C7 transfers material to Conveyor Belt No. C94 which loads the three storage silos associated with EU 008. Conveyor Belt No. C11 transfers material to Conveyor Belt No. C18 using the C18 Transfer Point D. Conveyor Belt Nos. C4 and C7 are completely enclosed in Storage Building Nos. 1 and 2.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
F.1. Capacity. The maximum unloading rate shall not exceed 250 tons per hour. [Rules 62-210.200, Definitions - PTE and 62-4.070(3), F.A.C. and Permit No. 0570024- 016-AC]

Emission Limitations and Standards
F.2. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from any emission point associated with this emission unit. [Rule 62-296.711(2)(a), F.A.C.]

Test Methods and Procedures
F.3. Test the emissions from each transfer point for opacity once per federal fiscal year (October1 - September 30) and submit two copies of test data to the Air ManagementDivision of the Environmental Protection Commission of Hillsborough County within fortyfive days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
F.4. Compliance with the emission limitations of Specific Condition No. F.2. shall be determined using EPA Method 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be thirty (30) minutes in duration. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297.310(4)(a)2., F.A.C.]

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Page 28 of 38 F.5. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum material transfer rate of 250 tons/hour. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2), F.A.C.]

Recordkeeping and Reporting Requirements

F.6. In order to demonstrate compliance with Specific Condition No. F.1., the permittee shall maintain a recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Day, Month, Year b) Hours of operation c) Amount and type of material unloaded by truck and railcar (tons) d) Rolling twelve month total of c) above

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Tampaplex Terminal Project: Bulk Material Handling

Page 29 of 38 Subsection G. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -102 Truck Unloading Station No. 1 and Transfer Point (C82 to C83) -103 Transfer Points (C83, C84 and C104) in Storage Building No. 3
Trucks are driven into a partially enclosed structure and unload material through grates in the floor of the structure. The materials are dropped onto Conveyor Belt No. C82, which transfers the material from the truck unloading Station No. 1 to Conveyor Belt No. C83. This transfer point is entirely enclosed. Conveyor Belt No. C83 transfers the material to Conveyor Belt No. C84, which is located inside Storage Building No. 3. Inside the building there is a movable tipper which allows the storage piles to be placed at different locations within the building. Materials are moved within the building with a front end loader, which is also used to transfer the material out of the building to a hopper located on the side of the storage building. The hopper feeds Conveyor Belt No. C104, which transfers material to Conveyor Belt No. C12, using the C12 Transfer Point A associated with EU 005. Storage Building No. 3 is solely associated with Truck Unloading Station No. 1.
Particulate matter emissions are controlled through the use of dust suppressants (oiling) and enclosures.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters
G.1. Capacity. The maximum truck unloading rate shall not exceed 400 tons per hour. [Rules 62-210.200, Definitions – PTE and 62-4.070(3), F.A.C. and Permit No. 0570024- 016-AC]

G.2. Hours of Operation. This emissions unit is allowed to operate continuously, i.e., 8,760 hours/year. [Rules 62-210.200, Definitions – PTE and 62-4.070(3), F.A.C.]

Emission Limitations and Standards
G.3. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from any emission point associated with the Truck Unloading Station No. 1 and the Storage Building No. 3. [Rule 62-296.711(2)(a), F.A.C.]

G.4. [Reserved]

G.5. In order to exempt the material transfer equipment referenced above from 40 CFR 60, Subpart X, the permittee shall not handle or store at the facility GTSP which is less than or equal to 72 hours old. [40 CFR 60.241(a) and (d) and Construction Permit No. 0570024-016-AC]

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Page 30 of 38 Test Methods and Procedures
G.6. Test each transfer point associated with Emission Unit Nos. 102 and 103 once per federal fiscal year (October1 - September 30) for opacity and submit two copies of test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rule 62-297.310(7)(a)4., F.A.C.]
G.7. Compliance with the emission limitations of Specific Condition No. G.3. shall be determined using EPA Method 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The EPA Method 9 test shall be thirty (30) minutes in duration. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rule 62-297.310(4)(a)2., F.A.C.]
G.8. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the maximum handling rate of 400 tons/hour. If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, then operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the input rates and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310(2), F.A.C.]

Recordkeeping and Reporting Requirements

G.9. In order to demonstrate compliance with Specific Condition Nos. G.1. and G.2., the permittee shall maintain a monthly recordkeeping system for the most recent five year period. The records shall be made available to the Environmental Protection Commission of Hillsborough County, state or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C.]

a) Day, Month, Year b) Hours of operation of each emission unit c) Amount and type of material unloaded from trucks (tons) d) Amount and type of material transferred from the Storage Building No. 3 to the Conveyor No. 12 Transfer Point A (tons) e) Written documentation, which may include shipping trails, showing the GTSP stored at the site is more than 72 hours old. f) Rolling twelve month total of c) and d) above.

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Page 31 of 38 Subsection H. This section addresses the following emissions unit(s).

E.U. ID No. Brief Description -104 Clamshell to Hopper(s) RH-01 and RH-02 -105 RH-01 and RH-02 to Conveyor BC-01 -106 Conveyor BC-01 to Radial Stacker RS-01 -107 RS-01 to Conveyor BC-02 or Conveyor PC-01 -108 Conveyor BC-02 to Conveyor BC-03 or PC-01 to Conveyor PC-02 -109 Conveyor BC-03 to Stacker Wing or PC-02 to Radial Stacker RS-02 -110 Stacker Wing to Storage Pile or RS-02 to Storage Pile -111 Front End Loader to Truck -112 Stevedoring at Other Berths
The stevedoring operation involves the loading and unloading of various bulk materials that include fertilizer materials, coal, limestone, granite, bauxite, etc., onto and from marine vessels, which can utilize up to three portable clamshell cranes. Material can also be unloaded by self unloading vessels. These materials are divided into different group categories. These operations are authorized for the Tampaplex facility and at numerous berths in Hillsborough County and include the use of hoppers, belt conveyors, radial stackers and a front-end loader.

Particulate matter (PM) emissions from these facility operations are controlled by the use of a water spray system and partial enclosures, and or dust suppressants. The facility also operates a truck wheel wash to wash particulate material from truck tires prior to the trucks leaving the site.


### These emission units are regulated under Rule 62- 296.711, F.A.C., and Chapter 1-3.52, Rules of the EPC, which limit the visible emissions to a 5% opacity standard for all of the material handling operations.
The following specific conditions apply to the emissions unit(s) listed above:

Essential Potential to Emit (PTE) Parameters H.1. In order to limit the potential to emit, the total potential particulate matter emissions from the Stevedoring operation shall not exceed 198 tons per twelve consecutive month period. [Rules 62-210.200(244), 62-4.070(3), and 62-212.300, F.A.C. and Permit No. 0570024-016-AC]
H.2. In order to ensure compliance with Facility Wide and Specific Condition Nos. 21 and H.1., respectively, the following limitations shall apply per any twelve consecutive month period: [Rule 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]
A) The Stevedoring operation is permitted to handle the following materials only:

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Page 32 of 38 Group I – Dusty Fertilizers
Ammonium Sulfate Granular Sulfate of Potash Animal Feed Ingredients Standard Muriate of Potash Standard Sulfate of Potash Standard Potassium NitrateGranular Muriate of Potash Granular Sulfate of PotashMagnesium Standard Sulfate of Potash-Magnesium Group II – Phosphate Rock Phosphate Products Rock Group III – Minimally Dusty Fertilizers
Ammonium Nitrate Sodium Potassium Nitrate MAP Calcium Ammonium Nitrate Compound Fertilizers DAP Potassium Nitrate Dried Sludge GTSP
Calcium Nitrate Urea Kieserite Group I V – Millscale

Millscale Group V– Moderately Dusty Non-Fertilizer Products Coal Syngypsum Clay
Petcoke Iron Ore Magnetite/Ferrous Oxides Group VI – Minimally Dusty Non-Fertilizer Products Gypsum Alumina Hydrate Filler Materials Pumice Vermiculite Peanut Hulls Wood Chips Dolomite Salt (solar) Ferrous Sulfate Glass Bio-Mass Ferro Alloys Iron Scrap (including shredded scrap metal) Granulated Furnace Slag Clinker (treated or screened) Prilled Sulfur Group VII – Coal Slag Coal Slag Group VIII – Agricultural Products Grains Grain Meals Seeds Soybeans Grain Byproducts Peas Wheat, Rye, Barley Citrus Pellets Group IX – Bauxite/Alumina and similar Dusty Cement-like Products Bauxite Alumina Slag Cement Group X - Aggregate Limestone Granite Rocks

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Page 33 of 38 Group X – Aggregate - continued Gravel Stone Group XI – Sand and Similar Materials Sand Soil Limestone Fines

Dirt

B) When calculating particulate matter emissions in order to demonstrate compliance with Facility Wide Condition Nos. 10 and 20 and Specific Condition No. H.1., the emission factors and control efficiencies listed below for each group of material shall be used.

Group Number Emission Factor Control Efficiency for Water Sprays Max. Number of

Transfer Points I 0.016 0.9 8 II 0.24 0.9 8 III 0.01 0.9 8 IV 6.8 0.9 8 V 0.2 0.9 8 VI 1.1 0.9 8 VII 0.067 0.9 8 VIII 0.086 0.9 8 IX 1.1 0.9 8 X 0.004 0.9 8 XI 0.31 0.9 8

C) Millscale shall be treated with water or a dust suppressant at the first material

transfer point and subsequent material transfer points as necessary to meet the 5% opacity standard. D) All materials in Group IX shall be treated with a dust suppressant at the first material transfer point and subsequent material transfer points as necessary to meet the 5% opacity standard.
Conditions Specific to the Operation at Kinder Morgan’s Tampaplex Berth
H.3. In order to ensure compliance with Specific Condition Nos. H.1., H.2., and H.8., the following limitations and restrictions shall apply: [Rule 62-4.070(3), F.A.C.]

A) The maximum throughput of the conveying system shall not exceed 1000 tons per hour of material. B) The conveyors shall have 180 degree covers except for BC-01 and BC-03. C) The receiving hoppers shall be equipped with wind shields and water sprays and the material drop height shall be minimized to the extent practicable. In no case shall the drop height be greater than 5 feet or above the top of the wind shields.

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Page 34 of 38 D) The number of transfer points shall not exceed eight. E) The permittee shall operate a maximum of two ship unloading cranes. F) In order to determine the optimum dust suppression system settings during material unloading, Kinder Morgan shall develop and maintain a DustSuppression System Operation Plan. This Plan shall be developed on a permaterial basis and shall include, but is not be limited to the recording of the following data: the material being transferred, moisture content of material, material transfer rate, weather conditions, and the water flow rate at each material transfer point, along with the number of nozzles required for operation at each transfer point to ensure compliance with the 5% opacity standard. Visible emission testing shall be performed during the development of this Plan to determine and record the specific flow rates and number of nozzles required for operation at each material transfer point to ensure compliance with the 5% opacity standard. The results of the visible emission testing performed during the development of the Operation Plan do not need to be submitted for review by the Environmental Protection Commission but shall be kept on-site and made available upon request. The Operation Plan shall be updated as material unloading conditions warrant to ensure visible emission compliance. Once an Operation Plan has been developed for a material, it shall be followed when unloading that material. The plans shall be maintained onsite and shall be made available upon request to any local, state, or federal air pollution agency. G) The permittee shall install, calibrate, and maintain flow meters for Emission Unit Nos. 104 through 110. H) The haul road down the middle of the storage pile area and to the north of the storage pile area shall be paved and maintained. I) A truck wash station shall be installed so that each truck leaving the facility exits through a washing station. J) No blowers shall be used in the vessel holds. K) Vehicles shall be completely enclosed by design or shall be enclosed with tarps prior to leaving the facility. L) The unbound (sorbed) moisture percent in petroleum coke shall not be less than 4%.
H.4. The permittee shall perform the following observations and checks on the schedule specified below. The permittee shall perform any necessary maintenance work in order to keep the equipment in good working order to minimize fugitive particulate emissions. [Rules 62-296.700(6), 62-4.070(3) and 62-213.440(1)(b)2.b., F.A.C.]
A) Daily (when in operation)

1) Inspect the water sprinkler system for proper operation, including, but not limited to, leaks and adequate wetness of material.

B) Each day of Hauling (when in operation)

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Page 35 of 38 1) Inspect the unpaved areas to ensure they are adequately wet.

2) Inspect the paved haul areas to ensure they are free of dust and debris. 3) Inspect the truck wheel wash station for proper operation.
C) Each Marine Vessel Unloading Operation (when in operation)

1) Record the maximum throughput rate for each marine vessel as measured by Belt Scale, BSC-01, in tons per hour.
D) Records of inspections, maintenance, and performance parameters shall be retained for a minimum of five years and shall be made available to any local, state, or federal air pollution control agency upon request.
Conditions Specific to Operation at the Other Berths in Hillsborough County
H.5. In order to ensure compliance with Specific Condition No. H.1., H.2., and H.8., the following restrictions and limitations shall apply during any twelve consecutive month period: [Rules 62-296.711(2)(a) and 62-4.070(3), F.A.C.]

A) The maximum transfer rate shall not exceed: Transfer Point Description Maximum Average Transfer Rate

Ship Loading 500 tons/hour Ship Unloading using Hopper (ship to hopper to truck) 500 tons/hour

B) The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from any emissions point.
H.6. In order to demonstrate compliance with Specific Condition No. H.1., H.2., and H.8., the following restrictions and limitations shall apply: [Rule 62-4.070(3), F.A.C. and Permit No. 0570024-016-AC]

A) The hopper shall be equipped with wind shields and water spray system and the material drop height minimized to the extent practicable. In no case shall the drop height be greater than 5 feet or above the top of the wind shields. B) Water or a dust suppressant shall be applied as needed to control visible emissions from the shiphold, receiving hopper, truck loading, or stockpiling. Regardless of whether or not water is used, the spray nozzles shall be set up and shall be in an operational mode during the material transfer process. C) The permittee may operate a maximum of three cranes at a maximum of three berths simultaneously. D) The hours of operation are not restricted. E) No blowers shall be used in the vessel holds. F) The number of transfer points shall not exceed eight. G) The unbound (sorbed) moisture percent in petroleum coke shall not be less than

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Page 36 of 38

4%. H) Material shall not be stockpiled at the dock for more than 24 hours. H.7. The permittee shall perform the following observations and checks on the schedule specified. The permittee shall perform any necessary maintenance work in order to keep the equipment in good working order to minimize fugitive particulate emissions. [Rules 62- 296.700(6), 62-4.070(3), and 62-213.440(1)(b)2.b., F.A.C.]

A) The hopper wind shields and water spray system shall be inspected prior to use. Maintenance or repairs shall be performed before the start of the operation. Its components shall be repaired or replaced as needed to ensure that the materials handled are moist or wetted to the extent necessary to maintain compliance with the opacity standards specified in Specific Condition Nos. H.5.B) and H.8. B) Check to ensure the petroleum coke is sufficiently coated with a dust suppressant and/or water in order to meet the opacity standards specified in Specific Condition Nos. H.5.B) and H.8. C) Records of inspections, maintenance, and performance parameters shall be retained for a minimum of five years and shall be made available to any local, state, or federal air pollution control agency upon request.

Emission Limitations and Standards
H.8. The permittee shall not cause, permit, or allow any visible emissions (five percent opacity) from any emission point or operation. [Rule 62-296.711(2)(a), F.A.C.]

Test Methods and Procedures
H.9. Test all the emission units for visible emissions at the Tampaplex site, upon the first instance of handling a new material, and annually, once per federal fiscal year (October 1 – September 30), thereafter. Each VE observation shall be made at the point of highest opacity from each transfer point. Submit two copies of the test data to the Air Management Division of the Environmental Protection Commission of Hillsborough County within 45 days of such testing. Testing procedures shall be consistent with the requirements of Rule 62-297.310, F.A.C. [Rules 62-297.310(7)(a)4., 62-297.310(8)(b), and 62-4.070(3), F.A.C.]
H.10. Test the Stevedoring operation for opacity once per federal fiscal year (October 1 – September 30) while operating at each berth other than the Kinder Morgan Tampaplex berth. Compliance with Specific Condition Nos. H.5.B) and H.8. shall be demonstrated by testing the dustiest material handled during the previous twelve months. Submit two copies of the test data to the Air Management Division of the EPC within forty-five days of such testing. Testing procedures shall be consistent with the requirements of Rule 62- 297, F.A.C. [Rules 62-297.310(7)(a)4., 62-297.310(8)(b), and 62-4.070(3), F.A.C.]
H.11. Testing of emissions shall be conducted with the source operating at capacity. Capacity is defined as 90-100% of the rated capacity listed in Specific Condition Nos.

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Page 37 of 38 H.3.A) and H.5.A). If it is impracticable to test at capacity, then the source may be tested at less than capacity; in this case subsequent source operation is limited to 110% of the test load until a new test is conducted. Once the unit is so limited, operation at higher capacities is allowed for no more than fifteen days for purposes of additional compliance testing to regain the rated capacity in the permit, with prior notification to the EPC. Failure to submit the throughput rates, moisture content of the material as received, and actual operating conditions may invalidate the test. [Rules 62-4.070(3) and 62-297.310, F.A.C.]
H.12. Compliance with the emission limitations of Specific Condition Nos. H.5.B) and H.8. shall be determined using EPA Method 9 contained in 40 CFR 60, Appendix A and adopted by reference in Rule 62-297, F.A.C. The Method 9 test shall be at least 30 minutes in duration. The minimum requirements for stack sampling facilities, source sampling and reporting, shall be in accordance with Rule 62-297, F.A.C. and 40 CFR 60, Appendix A. [Rules 62-297, 62-297.310(4)(a)2., and 62-296.711(3)(a) F.A.C.]
H.13. The permittee shall notify the Air Compliance Section of the Environmental Protection Commission of Hillsborough County at least 15 days prior to the date on which each formal compliance test is to begin of the date, time, and place of each such test, and the contact person who will be responsible for coordinating and having such test conducted. [Rules 62-297.310(7)(a)9., F.A.C.]

Recordkeeping and Reporting Requirements
H.14. In order to ensure compliance with Specific Condition Nos. H.1., H.2., and H.5., the permittee shall maintain a recordkeeping system. The records shall be maintained onsite for five years and shall be made available to any local, state, or federal air pollution agency upon request. The records shall include, but not limited to, the following: [Rule 62-4.070(3), F.A.C. and 62-213.440(1)(b)2.b., F.A.C.]

A) Operation at Kinder Morgan’s Tampaplex Berth I. Material Handling Records

1) Day, Month, Year 2) Amount, Group, and Type of each material received (tons) 3) Amount Group, and Type of each material shipped offsite (tons) 4) Monthly total of 2) and 3) above 5) Rolling twelve month total of 4) above 6) Monthly and twelve month rolling summary of particulate matter emissions from material handling. When calculating particulate matter emissions, the emission factors and control efficiencies listed in H.2.B) shall be used. 7) Records as required by Specific Condition No. H.4.

### Kinder Morgan Terminals FINAL Permit No.: 0570024-014-AV

Tampaplex Terminal Project: Bulk Material Handling

Page 38 of 38 B) When Operating at Other Berths I. Material Handling Records

1) Day, Month, Year 2) Berth No. or Location 3) Amount, Group, and Type of each material received (tons) 4) Amount Group, and Type of each material shipped offsite (tons) 5) Monthly total of 3) and 4) above 6) Rolling twelve month total of 5) above 7) Monthly and twelve month rolling summary of particulate matter emissions from material handling. When calculating particulate matter emissions, the emission factors and control efficiencies listed in H.2.B) shall be used. 8) Records as required by Specific Condition No. H.4.

# C. Tampa Electric Company – Gannon Station

Emission Units shut

- down: 1. EU001 – Unit #1 (RP)
2. EU002 – Unit #2 (RP)
3. EU003 – Unit #3 (RP)
4. EU004 – Unit #4 (BART/RP)
5. EU005 – Unit #5 (BART/RP)
6. EU006 – Unit #6 (BART/RP)

Items included: Air Construction Permit (0570040

- 019

- AC)

.

# Department of 

# Environmental Protection

Jeb Bush

. Governor·

PERMITTEE:
Tampa Electric Company P.O. Box III Tampa, Florida 33601-0111
Authorized Representative: Wade A. Maye, General Manager

PROJECT Twin Towers Office Building 2600 Blair Stone Road Tallahassee. Florida 32399-2400 Colleen M. Castille Secretary

H. L. Culbreath Bayside Power Station Air Permit No. PSD-FL-30 I C Project No. 0570040-019-AC Expires: December 31, 2007

The Tampa Electric Company operates the H. L. Culbreath Bayside Power Station in Tampa at 3602 Port Sutton Road in Hillsborough County, Florida. The electrical power plant (SIC No. 4911) was formerly known

as the F. J. Gannon Station, but was re-powered with combined cycle gas turbines firing natural gas. This permit revision authorizes: a phase of simple cycle operation for Bayside Units 3A and 3B; distillate oil as a restricted alternate fuel for Bayside Units 3A and 3B during simple cycle operation; distillate oil as an emergency backup fuel for Bayside Units 3A and 3B once converted to combined cycle operation; and an extension of the expiration date to allow construction of Bayside Units 3 and 4.
The UTM coordinates are: Zone 17,360.00 km E, 3087.50 km N.

STATEMENT OF BASIS
The permittee is authorized to install the proposed equipment and perform the work in accordance with the conditions of this permit and as described in the application, approved drawings, plans, and other documents on file with the Department. This air pollution construction permit is issued under the provisions of Chapter 403 of the Florida Statutes (F.S.), and Chapters 62-4, 62-204, 62-210, 62-212, 62-296, and 62-297 of the Florida Administrative Code (F.A.C.) and 40 CFR 52.21. Specifically, this permit is issued pursuant to the Chapter 62- 212, F.A.C. requirements for Preconstruction Review of Stationary Sources and the Prevention of Significant Deterioration (PSD) of Air Quality. The conditions of this permit do not relieve the permittee from any applicable requirement of the DEP/TECO Consent Final Judgment or the EPAITECO Consent Decree.

Michael G. Cooke, Director Effective Date Division of Air Resource Management

"Morc ProtectIOn, Less Process"

Pnn[ed on recyded paper.FACILITY DESCRIPTION Upon completing construction of all Bayside Units and retiring all coal

- fired Gannon units, the H. L. Culbreath Bayside Power Station will have a n electrical production capacity of 2845 MW based on the following nominal capacities : Bayside Unit 1 (746 MW), Bayside Unit 2 (1090 MW), Bayside Unit 3 (501 MW), and Bayside Unit 4 (508 MW). Note that the final design may not fully utilize the nameplate capacities of the existing steam

- electrical turbines. The following table summarizes t he emission units regulated by this air construction permit.

EU No. Status Emission Unit Description

001 Retired a Gannon Unit 1 – coal fired boiler (125 MW steam electrical generator)
002 Retired a Gannon Unit 2 – coal fired boiler (125 MW steam electrical generator)
003 Retired a Gannon Unit 3 – coal fired boiler (163 MW steam electrical generator)
004 Retired a Gannon Unit 4 – coal fired boiler (170 MW steam electrical generator)
005 Retired a Gannon Unit 5 – coal fired boiler (239 MW steam electrical generator)
006 Retired a Gannon Unit 6 – coal fired boiler (414 MW steam electrical generator)
008 Functional a Gannon Coal Yard
020 Operating b Bayside Unit 1A – 169 MW combined cycle gas turbine
021 Operating b Bayside Unit 1B – 169 MW combined cy cle gas turbine
022 Operating b Bayside Unit 1C – 169 MW combined cycle gas turbine
023 Operating c Bayside Unit 2A – 169 MW combined cycle gas turbine
024 Operating c Bayside Unit 2B – 169 MW combined cycle gas turbine
025 Operating c Bayside Unit 2C – 169 MW combined cycle gas turbine
026 Operating c Bayside Unit 2D – 169 MW combined cycle gas turbine
027 Proposed d Bayside Unit 3A – 169 MW combined cycle gas turbine
028 Proposed d Bayside Unit 3 B – 169 MW combined cycle gas turbine
029 Proposed e Bayside Unit 4 A – 169 MW combined cycle gas turbine
030 Proposed e Bayside Unit 4 B – 169 MW combined cycle gas turbine

a. The coal fired Gannon boilers were permanently retired on the following dates: Unit 1 (04/16/03); Unit 2 (04/15/03); Unit 3 (11/01/03); Unit 4 (10/12/03); Unit 5 (01/30/03); and Unit 6 (09/30/03). The Gannon coal yard (EU 008) remains functional. Notes

b. Bayside Unit 1 is constructed and began commercial operation on March 16, 2003. The three gas turbines comprising Bayside Unit 1 re-po wer the 239 MW steam electrical generator from Gannon Unit 5.

c. Bayside Unit 2 is constructed and began commercial operation on November 19, 2003. The four gas turbines comprising Bayside Unit 2 re- power the 414 MW steam electrical generator from Gannon Uni t 6.
d. The two gas turbines comprising Bayside Unit 3 will re

- power the 1 63 MW steam electrical generator from Gannon Unit 3. This revised permit authorizes a phase of simple cycle operation for these units.

e. The two gas turbines comprising Bayside Unit 4 wi ll re

- power the 1 70 MW steam electrical generator from Gannon Unit 4.REGULATORY CLASSIFICATION
Title III : The re

- powered facility is not a major source of hazardous air pollutants (HAPs).
Title IV : All Bayside gas turbines are subject to the Phase II Ac id Rain requirements. All Gannon boilers have been permanently shutdown and are considered “retired units” in accordance with the Acid Rain provisions.
Title V : The facility is a Title V major source of air pollution in accordance with chapter 62-213, F. A.C.
Site Certification : The facility is not subject to any specific power plant site certification requirements.
PSD : The facility is a PSD

- major facility in accordance with Rule 62 -212.400, F.A.C.
NSPS : All gas turbines are subject to the New Source P erformance Standards in Subpart GG of 40 CFR 60.
NESHAP

RELEVANT DOCUMENTS : The re

- powered facility is not a major source of hazardous air pollutants; therefore the National Emissions Standards for Hazardous Air Pollutants in Subpart YYYY of 40 CFR 63 do not apply to the ga s turbines.

The following documents are not a part of this permit; however, they are specifically related to this permitting action and are on file with permitting authority

.

**•** DEP/TECO Consent Final Judgment signed on December 7, 1999.

**•** EP A/TECO Consent De cree entered on October 5, 2000.

**•** Original Permit No. PSD

- FL

- 301 issued on March 30, 2001 including the app lication and related correspondence. This permit (Project No. 0570040 -013- AC) authorized construction of Bayside Units 1 and 2.

**•** Revi sed Permit No. PSD

- FL

- 301A issued on January 8, 2002 including the application and related correspondence. This permit (Project No. 0570040 -015- AC) included the construction of Bayside Units 3 and 4.

**•** Revised Permit No. PSD

- FL

- 301B issued on November 9, 20 04 including the application and related correspondence. This permit (Project No. 0570040 -021- AC) revised Condition 17 related to monitoring data exclusions.

**•** Application No. 0570040 -019- AC (PSD

- FL

- 301C) received on July 22, 2003 and related correspondence to make it complete.

APPENDICES The following Appendices are attached as part of this permit. Appendix A. Terminology Appendix B . Summary of the BACT Determinations and Emissions Standards Appendix E. Summary of Mass Emissions Rates Appendix GC. G eneral Conditions Appendix GG. NSPS Subpart GG Requirements for Gas Turbines Appendix XS. Semi

- Annual Continuous Monitor Systems ReportA DMINISTRATIVE R EQUIREMENTS
1. Effective Date
2. : The effective date of this permit is specified on the placard page (page 1). Permitting Authority

3. : All documents related to applications for permits to construct, operate or modify an emissions unit shall be submitted to the Bureau of Air Regulation (BAR), Florida Department of Environmental Protection (DEP), at 2600 Blair Stone Road - MS #5505, Tallahassee, Florida 32399 -2400. Copies shall also be provided to each Compliance Authority. Compliance Authority

4. : All documents related compliance activities such as reports, tests, and notifications shall be submitted to the Air Management Division of the Environmental Protection Commission of Hillsborough County at 1410 North 21 Street, Tampa, FL 33605. Copies of all such documents shall be submitted to the Air Resources Section of the Southwest District Office, Florida Dep artment of Environmental Protection, 3804 Coconut Palm Drive, Tampa, Florida 33619-8218. Terminology

5. : The terms used in this permit have specific meanings as defined in the applicable chapters of the Florida Administrative Code. Appendix A lists frequen tly used abbreviations and explains the format used to cite rules and regulations in this permit.
General Conditions

6. : The owner and operator are subject to, and shall operate under, the attached General Conditions listed in Appendix GC of this permit. [Rule 62-4.160, F.A.C.] Applicable Regulations, Forms and Application Procedures

7. : Unless otherwise indicated in this permit, the construction and operation of the subject emissions unit shall be in accordance with the capacities and specifications stated in the application. The facility is subject to all applicable provisions of: Chapter 403 of the Florida Statutes (F.S.); Chapters 62

- 4, 62

- 204, 62

- 210, 62

- 212, 62

- 213, 62

- 296, and 62

- 297 of the Florida Administrative Code (F.A.C.); and the Title 40, Parts 52, 60, 72, 73, and 75 of the Code of Federal Regulations (CFR), adopted by reference in Rule 62-204.800, F.A.C. The permittee shall use the applicable forms listed in Rule 62

- 210.900, F.A.C. and follow the application procedures in Chapter 62 -4, F.A.C. I ssuance of this permit does not relieve the permittee from compliance with any applicable federal, state, or local permitting or regulations. [Rules 62-204.800, 62-210.300 and 62-210.900, F.A.C.] PSD Expiration

8. : Approval to construct shall become invalid if construction is not commenced within 18 months of the effective date of this permit, or if construction is discontinued for a period of 18 months or more, or if construction is not completed within a reasonable time. The Department may extend the 18

- m onth period upon a satisfactory showing that an extension is justified. Such an extension does not relieve the permittee from any applicable requirement of the DEP/TEC O Consent Final Judgment or the EPA/TEC O Consent Decree. [40 CFR 52.21(r)(2)]
Permit Ex piration

9. : For good cause, the permittee may request that this PSD air construction permit be extended. Such a request shall be submitted to the Department’s Bureau of Air Regulation at least sixty (60) days prior to the expiration of this permit. Such a n extension does not relieve the permittee from any applicable requirement of the DEP/TEC O Consent Final Judgment or the EPA/TEC O Consent Decree. [Rules 62-4.070(4), 62-4.080, and 62-210.300(1), F.A.C.]
BACT Determination

10. : In conjunction with an extensio n of the 18

- month period to commence or continue construction, phasing of the project, or an extension of the permit expiration date, the permittee will be required to demonstrate the adequacy of any previous determination of Best Available Control Technol ogy (BACT) for the source. [Rule 62-212.400(6)(b), F.A.C. and 40 CFR 51.166(j)(4)]
New or Additional Conditions

11. : For good cause shown and after notice and an administrative hearing, if requested, the Department may require the permittee to conform to new or additional conditions. The Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and on application of the permittee, the Department may grant additional time. [Rule 62-4.080, F.A.C.]
Modifications : N o emissions unit or facility subject to this permit shall be constructed or modified withoutobtaining an air construction permit from the Department. Such permit shall be obtained prior to beginning construction or modification. [Rules 62-210.200 (Definitions) and 62-210.300(1), F.A.C.]
12. Application for Title IV Permit

13. : At least 24 months before the date on which the new unit begins serving an electrical generator greater than 25 MW, the permittee shall submit an application for a Title IV Acid Rain Perm it to the Region 4 office of the U.S. Environmental Protection Agency in Atlanta, Georgia and a copy to the Department’s Bureau of Air Regulation in Tallahassee. [40 CFR 72]
Title V Permit

E MISSIONS AND C ONTROLS : This permit authorizes construction of the permitted emissions u nits and initial operation to determine compliance with Department rules. A Title V operation permit is required for regular operation of the permitted emissions unit. The permittee shall apply for a Title V operation permit at least ninety days prior to expiration of this permit, but no later than 180 days after commencing operation. To apply for a Title V operation permit, the applicant shall submit the appropriate application form, compliance test results, and such additional information as the Department may by law require. The application shall be submitted to the Department’s Bureau of Air Regulation with copies to the Compliance Authority. [Rules 62-4.030, 62-4.050, 62-4.220, and Chapter 62-213, F.A.C.]

13. Unconfined Particula te Emissions

14. : During the construction period, unconfined particulate matter emissions shall be minimized by dust suppressing techniques such as covering and/or application of water or chemicals to the affected areas, as necessary. [Rule 62 -296.320(4)(c), F.A.C.]
Circumvention

15. : The permittee shall not circumvent the air pollution control equipment or allow the emission of air pollutants without this equipment operating properly. [Rule 62-210.650, F.A.C.]
Excess Emissions Prohibited

16. : Excess emissions cau sed entirely or in part by poor maintenance, poor operation, or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction, shall be prohibited. [Rule 62-210.700(4), F.A.C.] Plant Operation - Problems

T ESTING R EQUIREMENTS : If temporarily unable to comply with any of the conditions of the permit due to breakdown of equipment or destruction by fire, wind or other cause, the permittee shall notify the Compliance Authority as soon as possible, but at least within one working da y, excluding weekends and holidays. The notification shall include: pertinent information as to the cause of the problem; steps being taken to correct the problem and prevent future recurrence; and, where applicable, the owner’s intent toward reconstruct ion of destroyed facilities. Such notification does not release the permittee from any liability for failure to comply with the conditions of this permit or the regulations. [Rule 62 -4.130, F.A.C.]

17. Sampling Facilities

18. : The permittee shall provide stack testing facilities and sampling locations in accordance with Rule 62 -297.310(6), F.A.C.
Test Procedures

a. Required Sampling Time

. Unless otherwise specified in the applicable rule, the required sampling time for each test run shall be no less than one hour and no greater than four hours, and the sampling time at each sampling point shall be of equal intervals of at least two minutes. The minimum observation period for a visible emissions compliance test shall be thirty (30) minutes. The observation period shall include the period during which the highest opacity can reasonably be expected to occur. : Tests shall be conducted in accordance with all applicable requirements of Chapter 62

- 297, F.A.C.

b. Minimum Sample Volume

. Unless otherwise specified in the applicable rule or test method, the minimum sample volume per run shall be 25 dry standard cubic feet.

c. Calibration of Sampling Equipment . Calibration of the sampling train equipment shall be conducted inaccordance with the schedule show n in Table 297.310-1, F.A.C. [Rule 62-297.310(4), F.A.C.]
19. Test Notification

20. : The permittee shall notify the Compliance Authority in writing at least 30 days prior to any initial NSPS performance tests and at least 15 days prior to any other required tests . [Rule 62

- 297.310(7)(a)9, F.A.C.; 40 CFR 60.7; 40 CFR 60.8]
Calculation of Emission Rate

21. : For each emissions performance test, the indicated emission rate or concentration shall be the arithmetic average of the emission rate or concentration determined by each of the three separate test runs unless otherwise specified in a particular test method or applicable rule. [Rule 62-297.310(3), F.A.C.]

a. Required Equipment. The owner or operator of an emissions unit for which co mpliance tests are required shall install, operate, and maintain equipment or instruments necessary to determine process variables, such as process weight input or heat input, when such data are needed in conjunction with emissions data to determine the co mpliance of the emissions unit with applicable emission limiting standards. [Rule 62-297.310(5)(a), F.A.C.] Determination of Process Variables

b. Accuracy of Equipment. Equipment or instruments used to directly or indirectly determine process variables, including devices such as belt scales, weight hoppers, flow meters, and tank scales, shall be calibrated and adjusted to indicate the true value of the parameter being measured with sufficient accuracy to allow the applicable process variable to be determined within 10% of its true value. [Ru le 62-297.310(5)(b), F.A.C.]
22. Special Compliance Tests

R ECORDS AND R EPORTS : When the Compliance Authority, after investigation, has good reason (such as complaints, increased visible emissions or questionable maintenance of control equipment) to believe that any applicable em ission standard contained in a Department rule or in a permit issued pursuant to those rules is being violated, it shall require the owner or operator of the emissions unit to conduct compliance tests which identify the nature and quantity of pollutant emissions from the emissions unit and to provide a report on the results of said tests to the Compliance Authority. [Rule 62-297.310(7)(b), F.A.C.]

23. Records Retention

24. : All measurements, records, and other data required by this permit shal l be documented in a permanent, legible format and retained for at least five (5) years following the date on which such measurements, records, or data are recorded. Records shall be made available to the Compliance Authority upon request. [Rules 62-4.160(14) and 62-213.440(1)(b)2, F.A.C.] Emissions Performance Test Reports

25. : A report indicating the results of any required emissions performance test shall be submitted to the Compliance Authority no later than 45 days after completion of the last test run. The test report shall provide sufficient detail on the tested emission unit and the procedures used to allow the Compliance Authority to determine if the test was properly conducted and if the test results were properly computed. At a minimum, the test report shall provide the applicable information listed in Rule 62-297.310(8)(c), F.A.C. [Rule 62-297.310(8), F.A.C.] Annual Operating Report : The permittee shall submit an annual report that summarizes the actual operating rates and emissions from this f acility. Annual operating reports shall be submitted to the Compliance Authority by March 1st of each year. [Rule 62-210.370(2), F.A.C.]This section of the permit addresses the following emissions units.

Emissions Units 020 – 026 : Bayside Units 1 and 2 Description : Each emissions unit consists of a General Electric Model PG7241(FA) gas turbine

- electrical generator set, an automated gas turbine control system, an inlet air filtration system, an evaporative inlet air cooling system, an unfired heat rec overy steam generator (HRSG), a single exhaust stack that is 150 feet tall and 19.0 feet in diameter, and associated support equipment. The project also includes electric fuel heaters and cooling towers. Natural gas is the exclusive fuel. Heat Input : At a compressor inlet air temperature of 59° F and firing 1842 MMBtu (HHV) per hour of natural gas, each unit produces a nominal 169 MW of shaft

- driven electricity. Exhaust gases exit the stack with a volumetric flow rate of approximately 1,030,000 acfm at 220° F. Generating Capacity : The following table summarizes the electrical generating capacity for each combination of combined cycle gas turbines and steam- electrical turbines.

EU No. Bayside GT Unit GT MW, Shaft Existing Gannon ST MW, ST Total

020 1A 169 MW
No. 5 239 746 021 1B 169 MW
022 1C 169 MW
023 2A 169 MW

No. 6 414 1090 024 2B 169 MW
025 2C 169 MW
026 2D 169 MW
Totals 7 GTs 1183 MW 2 STs 653 1836
Note: GT means gas turbine. The nameplate generating capacity is shown for the steam

electrical turbines (ST). The final design may not fully utilize the nameplate generating capacity.
Controls : The efficient combustion of natural gas at high temperatures minimizes the emissions of CO, PM/PM 10 , and VOC. Firing natural gas as th e only authorized fuel minimizes emissions of SAM and SO 2 because natural gas contains only small amounts of sulfur. A selective catalytic reduction (SCR) system combined with dry low-NOx (DLN) combustion technology reduces NOx emissions. Continuous Monit ors : Each gas turbine is equipped with continuous emissions monitoring systems (CEMS) to measure and record CO and NOx emissions as well as flue gas carbon dioxide content.

A PPLICABLE S TANDARDS AND R EGULATIONS
1. BACT Determinations

2. : The emissions units ad dressed in this section are subject to Best Available Control Technology (BACT) determinations for carbon monoxide (CO), particulate matter (PM/PM 10 ), and volatile organic compounds (VOC). [Rule 62-212.400(BACT), F.A.C.] NSPS Requirements

a. Subpart A, General Provisions, including: 40 CFR 60.7 (Notification and Record Keeping), 40 CFR 60.8 (Performance Tests), 40 CFR 60.11 (Com pliance with Standards and Maintenance Requirements), 40 CFR 60.12 (Circumvention), 40 CFR 60.13 (Monitoring Requirements), and 40 CFR 60.19 (General : Each gas turbi ne shall comply with all applicable requirements of 40 CFR 60, adopted by reference in Rule 62-204.800(7)(b), F.A.C.Notification and Reporting Requirements).
b. Subpart GG, Standards of Performance for Stationary Gas Turbines as specified in Appendix GG of this permit.

E QUIPMENT
3. Construction

4. : Bayside Unit 1 is constructed and began commercial operation on March 16, 2003. Bayside Unit 2 is constructed and began commercial operation on November 19, 2003. The revised permit (P SD

FL

- 301C) does not authorize any additional construction for these units. [Application; Rule 62

- 212.400(BACT), F.A.C.] Combined Cycle Gas Turbines

5. : The permittee is authorized to install, tune, operate and maintain seven new General Electric Model PG7241(FA) gas turbines with electrical generator sets, each designed to produce a nominal 169 MW of shaft

- driven electrical power. Each unit shall be designed as a combined cycle system to include an automated gas turbine control system, an inlet air filtrat ion system, an unfired heat recovery steam generator (HRSG), a single exhaust stack that is 150 feet tall and 19.0 feet in diameter, and associated support equipment. [Applicant Request; Design] Heat Recovery Steam Generators (HRSG)

6. : Each gas turbine sys tem includes an unfired HRSG with three levels of steam conditions (high pressure, intermediate pressure, and low pressure). [Design] Automated Control System : The permittee shall install, calibrate, tune, operate, and maintain a Speedtronic TM

7. Mark VI automated control system (or better) for each gas turbine. Each system shall be designed and operated to monitor and control the gas turbine combustion process and operating parameters including, but not limited to: air/fuel distribution and staging, turbin e speed, load conditions, temperatures, heat input, and fully automated startup and shutdown. [Design; 62-212.400(BACT), F.A.C.] DLN Combustion Technology

8. : The permittee shall install, tune, operate and maintain the General Electric dry low

- NOx combustio n system (DLN 2.6 or better) to provide efficient lean premix combustion. Prior to the initial emissions performance tests for each gas turbine, the DLN combustors and automated gas turbine control system shall be tuned to reduce CO and NOx emissions. Th ereafter, each system shall be maintained and tuned in accordance with the manufacturer’s recommendations. [Design; Rule 62

- 212.400(BACT), F.A.C.] SCR System

9. : The permittee shall install, tune, operate and maintain a selective catalytic reduction (SCR)

s ystem to reduce NOx emissions from each combined cycle gas turbine. The SCR system shall consist of an ammonia injection grid, catalyst, ammonia storage, a monitoring and control system, electrical system, piping, and other ancillary equipment. The SCR s ystem shall be designed to reduce NOx emissions while minimizing ammonia slip within the permitted levels. [DEP/ TECO Consent Final Judgment; EPA/ TECO Consent Decree; Rule 62 -4.070(3), F.A.C.] Evaporative Inlet Air

- Cooling System

P ERFORMANCE R ESTRICTIONS : Each gas turbine system includes an evaporative cooling system designed to reduce the temperature of the inlet air to the gas turbine compressor. The reduced temperature provides a greater mass flow rate and increases power production with additional fuel combustion. {Permittin g Note: The installed equipment includes a water distribution system with packed media blocks of corrugated layers of fibrous material. Air passing over the system wicks moisture away from the media to create the cooling effect. } [Applicant Request; Des ign]

10. Permitted Capacity : The maximum heat input rate to each gas turbine shall not exceed 1842 MMBtu per hour while producing approximately 169 MW (shaft). The maximum heat input rate is based on acompressor inlet air temperatur e of 59° F, the higher heating value (HHV) of natural gas and expected performance levels. Heat input rates will vary depending upon gas turbine characteristics, ambient conditions, and evaporative cooling. The permittee shall provide the manufacturer’s performance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. Operating data may be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department. [Design; Rule 62-210.200(PTE), F.A.C.]
11. Allowable Fuels

12. : Each gas turbine shall fire only pipeline

- quality natural gas. The fuel sulfur content shall not exceed 2 grains per 100 SCF of natural gas based on a 12

- month rolling average. Compliance shall be demonstrated each month by compiling the daily fuel sulfur analyses provided by the pipeline vendor. Methods for determining the sulfur content of the natural gas shall be ASTM methods D4084-82, D3246-81 or equivalent methods. No other fuels are allowed. [Design; Rules 62

- 210.200(PTE); DEP/TEC Consent Final Judgment; EPA/TEC Consent Decree] Restricted Operation

13. : The hours of operation for each gas turbine are not limited (8760 hou rs per year). [ Application; Rules 62-212.400(BACT) and 62-210.200(PTE), F.A.C.] Operating Procedures

E MISSIONS S TANDARDS : The Best Available Control Technology (BACT) determinations established by this permit rely on “good operating practices” to minimize emissions. Theref ore, all operators and supervisors shall be properly trained to operate and maintain the gas turbines and pollution control systems in accordance with the guidelines and procedures established by the manufacturer. The training shall include good operating practices as well as methods to minimize emissions during startup and shutdown. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]

{Permitting Note: A summary table of the emissions standards is provided in Appendix B of this permit.}
14. Emissions Standards Based on Performance Tests

a. Ammonia Slip : Subject to the requirements of Condition : The following standards apply to each combined cycle gas turbine as determined by emissions performance tests conducted at permitted capacity. The mass emission limits are based on a compressor inlet temper ature of 59° F. The permittee shall provide the manufacturer’s performance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. Operating data sha ll be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department.

22 in this subsection , ea ch SCR system shall be designed and operated for an ammonia slip target of less than 5 ppmvd corrected to 15% oxygen based on the average of three test runs. [Rule 62 -4.070(3), F.A.C.]
b. Carbon Monoxide (CO) : CO emissions shall not exceed 28.7 pounds per hour and 7.8 ppmvd corrected to 15% oxygen based on the average of three test runs as determined by EPA Method 10. [Rule 62-212.400(BACT), F.A.C.]

c. Nitrogen Oxides (NOx) : NOx emissions shall not exceed 23.1 pounds per hour and 3.5 ppmvd corrected to 15% ox ygen based on the average of three test runs as determined by EPA Method 7E. NOx emissions are defined as oxides of nitrogen reported as NO 2 . [DEP/ TECO Consent Final Judgment; EPA/ TECO Consent Decree; 40 CFR 60.332]
d. Particulate Matter (PM/PM 10 ) : The exc lusive firing of pipeline

- quality natural gas combined with the efficient combustion design and operation of each gas turbine represent the Best Available Control Technology (BACT) requirements for particulate matter emissions. Compliance with carbon mono xideand visible emissions standards shall serve as continuous indicators of efficient combustion to minimize particulate matter emissions. No performance tests are required. [Rule 62 -212.400(BACT), F.A.C.]

e. Sulfuric Acid Mist (SAM) and Sulfur Dioxide (SO 2 ) : The exclusive firing of pipeline- quality natural gas effectively limits potential emissions of SO 2 and SAM. No performance tests are required. [Design; DEP/TEC Consent Final Judgment; EPA/TEC Consent Decree; 40 CFR 60.333]
f. Visible Emissions : Visibl e emissions shall not exceed 10% opacity, based on a 6

- minute average as determined by EPA Method 9. Except as allowed by Condition 17 of this subsection , this standard applies to all loads. [Rule 62-212.400(BACT), F.A.C.]

g. Vol atile Organic Compounds (VOC) : The exclusive firing of pipeline

- quality natural gas combined with the efficient combustion design and operation of each gas turbine represent the Best Available Control Technology (BACT) requirements for VOC emissions. Compliance with carbon monoxide standards shall serve as a continuous indicator of efficient combustion to minimize VOC emissions. No performance tests are required. [Design; Rule 62 -212.400(BACT), F.A.C.]
15. Emissions Standards Based on CEMS Data

a. Carbon Monoxide (CO) : CO emissions shall not exceed 9.0 ppmvd corrected to 15% oxygen based on a 24-hour block average of CEM S data. : The following standards apply to each gas turbine based on data collected from each required Continuous Emissions Monitoring System (CEMS).

b. Nitrogen Oxides (NOx) : NOx emissions shall not exceed 3.5 ppmvd corrected to 15% oxygen based on a 24- hour block average of CEMS data.
Each 24

- hour block average shall start at midnight each operating day and shall be calculated from 24 consecutiv e 1

- hour averages. If a unit operates less than 24 hours during the block, the 24

- hour block average shall be the average of the available valid 1

- hour averages. [Rules 62

- 212.400(BACT) and 62

- 4.070(3), F.A.C.]

S TARTUP , S HUTDOWN , M ALFUNCTION , AND L OW L OA D O PERATION
16. Excess Emissions Prohibited

17. : Excess emissions caused entirely or in part by poor maintenance, poor operation or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction, shall be prohibite d. All such preventable emissions shall be included in the compliance averages determined from the CO and NOx CEMS data. [Rule 62 -210.700(4), F.A.C.]
Alternate Standards and CEMS Data Exclusion

a. Opacity During Startup and Shutdown : During startup and shutdown, the opacity of the exhaust gases shall not exceed 10%, except for up to ten 6

- minute averaging periods in a calendar day during which the opacity shall not exceed 20%. Data f or each 6

- minute averaging period shall be exclusive from other 6-minute averaging periods. : The following permit conditions establish alternate standa rds or allow the exclusion of monitoring data for specifically defined periods of startup, shutdown, and malfunction. These conditions apply only if operators employ the best operational practices to minimize the amount and duration of emissions during such incidents.

b. Low Load Operation : Excluding startup, shutdown, malfunction, DLN tuning, compressor blade drying, and over speed trip tests, each gas turbine may operate below 50 % base load providing: the gas turbine is firing natural gas and operating in full dry low

- NOx combustion mode; the CO and NOx CEMS are functioning properly during such periods and recording valid emissions data within the span range of the monitors; and t he gas turbine remains in compliance with the CO and NOx emissions standards (24-hour block averages).c. CEMS Data Exclusion : For the following specified operational periods, CO and NOx emissions data may be excluded from the 24

- hour block compliance averages in accordance with the corresponding requirements. (1) Definitions : Rule 62

- 210.200(231), F.A.C. defines “shutdown” as the cessation of the operation of an emissions unit for any purpose. Rule 62

- 210.200(160), F.A.C. defines “malfunction” as any unavoidab le mechanical and/or electrical failure of air pollution control equipment or process equipment or of a process resulting in operation in an abnormal or unusual manner. Rule 62

- 210.200(246), F.A.C. defines “startup” as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution control device imbalances, which result in excess emissions. (2) Standard Startups, Shutdowns, and Malfunctions : For each gas turbine, no more than four 1 -hour CEMS emission averages shall be excluded from any 24

- hour block compliance average due to standard startups, shutdowns, and malfunctions (total). (3) Cold Steam Turbine Startup : “Cold steam turbine startup” means a startup after the steam turbine has been offline for 24 hours or more, or the first stage turbine metal temperature is 250° F or less. To minimize emissions, no more than one gas turbine per Bayside Unit shall be operated during a cold steam turbine startu p. No more than sixteen 1

- hour CEMS emission averages shall be excluded from the 24

- hour block compliance averages due to a cold steam turbine startup. In addition, no more than sixteen 1 -hour CEMS emission averages shall be excluded from any 24 -hour blo ck compliance average due to cold steam turbine startup. In the event of a cold steam turbine startup and standard startups, shutdowns and/or malfunctions within the same 24 hour period, a total of sixteen 1

- hour CEMS emissions averages may be excluded wi th no more than four of those sixteen 1

- hour CEMS emissions averages being excluded due to standard startups, shutdowns, and malfunctions (total)

. This condition applies only to the gas turbine being used for the cold steam turbine startup. The permittee shall notify the Compliance Authority no later than 24 hours after beginning a cold steam turbine startup. Notification may be by phone, facsimile, email, or letter. (4) Steam Turbine Startup Following an Unplanned Forced Outage : “Steam turbine startup foll owing unplanned, forced outage” means startup when the first stage turbine metal temperature is 250° F or more and occurs within 24 hours after either (1) the steam turbine inadvertently trips offline, or (2) the plant is forced to take the steam turbine o ffline for repair. To minimize emissions, no more than one gas turbine per Bayside Unit shall be operated during a steam turbine startup following an unplanned forced outage. No more than eight 1

- hour CEMS emissions averages shall be excluded from the 24

- hour block compliance averages due to a steam turbine startup following an unplanned forced outage. In addition, no more than eight 1

- hour CEMS emission averages shall be excluded from any 24

- hour block compliance average due to steam turbine startups fo llowing an unplanned forced outage. In the event of a startup following an unplanned forced outage and standard startups, shutdowns and/or malfunctions within the same 24 hour period, a total of eight 1 -hour CEMS emissions averages may be excluded with no more than four of those eight 1

- hour CEMS emissions averages being excluded due to standard startups, shutdowns, and malfunctions (total)

. This condition applies only to the gas turbine being used for steam turbine startup following an unplanned forced o utage . The permittee shall notify the Compliance Authority no later than 24 hours after beginning a steam turbine startup following an unplanned forced outage . Notification may be by phone, facsimile, email, or letter and shall include the reason for the unplanned forced outage. (5) DLN Tuning : “DLN Tuning” means operating the gas turbine at intermittent loads throughout the full load range in order to adjust and tune the dry low

- NOx (DLN) combustion system. DLNtuning shall be conducted in accordance with manufacturer’ recommendations. Emissions data collected during DLN tuning may be excluded from the 24

- hour block compliance averages

. {Permitting Note: For example, a major tuning session would occur after combustor change-out.} (6) Compressor Blade Drying : Following a compressor blade wash in accordance with the manufacturer’s recommendations , t he permittee may operate a gas turbine at very low loads to heat and dry the compressor blades. Emissions data collected while drying the compressor blades may be excluded from the 24

- hour block compliance averages

. {Permitting Note: A gas turbine would typically operate at approximately 10% of base load or less to perform compressor blade drying.} (7) Over Speed Trip Test : As a periodic maintenance practice, the permittee may perform over speed trip tests in accordance with the manufacturer’s recommendations. Emissions data collected while conducting over speed trip tests may be excluded from the 24

- hour block compliance averages

. {Permitting Note: During this tes t, the gas turbine is operated at full speed, no load (FSNL) for approximately 5 to 6 hours. The unit is gradually accelerated to 110% speed (3960 rpm) to initiate a trip and then coasts down normally. Over speed trip tests are typically performed after a long outage or a major component overhaul.} To the extent practicable, the permittee shall minimize the amount and duration of emissions during periods of startup, shutdown, malfunction, DLN tuning, compressor blade drying, and over speed trip testing. If a CEMS reports emissions in excess of an emissions standard (24

- hour block), the permittee shall notify the Compliance Authority within one working day with a preliminary report of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken to correct the problem. In addition, the Compliance Authority may request a written summary report of the incident. All emissions data allowed for exclusion shall be summarized in the Semiannual CEMS Report required in Condition 25 of this subsection.
d. Startup and Shutdown Plan : The permittee shall maintain on site a “Startup and Shutdown Plan” that describes procedures for startup and shutdown of the Bayside Units. As provided by the a uthority in Rule 62

- 210.700(5), F.A.C., the above requirements are established in lieu of the provisions of Rule 62-210.700(1), F.A.C. {Permitting Note: The durations for a cold steam turbine startup and a steam turbine startup following an unplanned forc ed outage are not typical for combined cycle units. The Bayside Units utilize the existing Gannon steam turbines. Operating procedures require one gas turbine to operate at low loads for extended periods to gradually warm the main and hot reheat steam li nes to the steam turbine as well as the steam turbine. Some steam lines are in excess of 1700 feet. Such startups are expected to occur infrequently.} [Design; Rules 62

- 4.130, 62

- 210.700(5), and 62

- 212.400 (BACT), F.A.C.; Permit No. PSD

FL -301B]
E MISSIONS P ERFORMANCE T ESTING
18. Operating Rate During Testing : Emissions performance testing shall be conducted with the emissions unit operating at permitted capacity. Permitted capacity is defined as 90 to 100 percent of the maximum operation rate allowed by th e permit. If it is impractical to test at permitted capacity, an emissions unit may be tested at less than the maximum permitted capacity; in this case, subsequent emissions unit operation is limited to 110 percent of the test rate until a new test is con ducted. Once the unit is so limited, operation at higher capacities is allowed for no more than 15 consecutive days for the purpose of additional compliance testing to regain the authority to operate at the permitted capacity. [Rule 62 -297.310(2), F.A.C.]19. Test Method

Method s : Any required tests shall be performed in accordance with the following reference methods.
Description of Method and Comments

CTM

- 027 Procedure for Collection and Analysis of Ammonia in Stationary Source : T his is an EPA conditiona l test method. The minimum detection limit shall be 1 ppm.

5 Determination of Particulate Matter Emissions from Stationary Sources : The minimum sampling time shall be two hours per run and the minimum sampling volume shall be 60 dscf per run.
7E Determi nation of Nitrogen Oxide Emissions from Stationary Sources
9 Visual Determination of the Opacity of Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources : The method shall use a continuous sampling train

.

18 Measurement of Gaseous Organic Compound Emissions by Gas Chromatography : EPA Method 18 may be used concurrently with EPA Method 25A to deduct emissions of methane and ethane from the measured VOC emissions.
20 Determination of Nitrogen Oxides, Sulfur Dioxide and Diluent Emissions from Stationary Gas Turbines
25A Determination of Volatile Organic Concentrations Except for Method CTM

- 027, the above methods are described in 40 CFR 60, Appendix A, and adopted by reference in Rule 62

- 204.800, F.A.C. Method CTM

- 027 is published on EPA’s Technology Transfer Network Web Site at “http://www.epa.gov/ttn/emc/ctm.html”. Although no specific tests are required for emissions of particulate matter and volatile organic compounds, the test methods are included fo r completeness. No other methods may be used for compliance testing unless prior written approval is received from the Department. [Rules 62 -204.800 and 62-297.100, F.A.C.; 40 CFR 60, Appendix A]
20. Initial Compliance Tests

21. : Each gas turbine shall be teste d to demonstrate compliance with the emission standards for CO, NOx, visible emissions and ammonia slip. The tests shall be conducted within 60 days after achieving at least 90% of the maximum permitted capacity, but not later than 180 days after initial operation of each gas turbine. Tests for CO and NOx shall be conducted concurrently. Certified CEMS data may be used to demonstrate compliance with the initial CO and NOx standards. The test results for ammonia slip shall also report the CO and NOx emissions recorded by the CEMS during each test run. [Rule 62-297.310(7)(a)1, F.A.C.; 40 CFR 60.335] Annual Compliance Tests : During each federal fiscal year (October 1 st to September 30 th

22. ), each gas turbine shall be tested to demonstrate compliance with the emission standards for ammonia slip and visible emissions. The test results for ammonia slip shall also report the CO and NOx emissions recorded by the CEMS during each test run. {Permitting Note: Continuous compliance with the CO and NOx standards wil l be demonstrated with certified CEMS data.} [Rules 62

- 212.400(BACT) and 62 -297.310(7)(a)4, F.A.C.] Additional Ammonia Slip Testing

a. Begin testing and reporting the ammonia slip for each subsequent calendar quarter; : If the tested ammonia slip rate for a gas turbine exceeds 5 ppmvd corrected to 15% oxygen when firing natural gas during the annual test, the permittee shall:

b. Before the ammonia slip exceeds 7 ppmvd corrected to 15% oxygen, take corrective actions that result in lowering the ammonia slip to le ss than 5 ppmvd corrected to 15% oxygen; and

c. Test and demonstrate that the ammonia slip is less than 5 ppmvd corrected to 15% oxygen within 15 days after completing the corrective actions. Corrective actions may include, but are not limited to, adding cata lyst, replacing catalyst, or other SCRsystem maintenance or repair. After demonstrating that the ammonia slip level is less than 5 ppmvd corrected to 15% oxygen, testing and reporting shall resume on an annual basis. [Rules 62-4.070(3) and 62- 297.310(7)(b), F.A.C.]

C ONTINUOUS M ONITORING R EQUIREMENTS
23. Continuous Emissions Monitoring Systems

a. Emission Averages . Compliance with the 24 -hou r standards for CO and NOx emissions shall be based on data collected by the required CEMS. The 24

- hour block shall start at midnight of each operating day and consist of 24 consecutive 1-hour blocks. If a unit operates continuously throughout the day, the 24- hour block average shall be the average of 24 consecutive 1

- hour emission averages. If a unit operates less than 24 hours during the day, the 24

- hour block average shall be the average of available valid 1

- hour emission averages collected during operation. If monitoring data is authorized for exclusion (due to startup, shutdown, malfunction, or tuning), the 24

- hour block average shall be the average of the remaining available valid 1

- hour emission averages collected during operation. Upon a request from the Compliance Authority, the NOx emission rate shall be corrected to ISO conditions to demonstrate compliance with the applicable standards of 40 CFR 60.332. : The permittee shall install, calibrate, maintain, and operate a continuous emission monitoring system (CEMS) in the exhaust stack of each emissions unit to measure an d record emissions of CO and NOx in a manner sufficient to demonstrate compliance with the CEMS emission standards of this permit. The carbon dioxide (CO 2 ) content of the flue gas shall also be monitored at the location where CO and NOx are monitored to c orrect the measured emissions rates to 15% oxygen. The oxygen content of the flue gas shall be calculated by the CEMS using the CO 2 content of the flue gas and an F- factor that is appropriate for natural gas.

b. Data Collection . T he CEMS shall be designed and operated to sample, analyze, and record CO , CO 2 , and NOx data evenly spaced over the hour. Each 1

- hour emission average shall be computed using at least one data point in each fifteen minute quadrant of the 1

- hour block during which the unit combusted fuel. Notwithstanding this requirement, each 1- hour emission average shall be computed from at least two data points separated by a minimum of 15 minutes. If the unit does not operate in more than one quadrant of a 1

- hour block, the data is insufficient to determine a 1

- hour emission average and sh all be ignored. (Example: Unit begins startup with only ten minutes remaining in the 1

- hour block. Data is insufficient to determine a 1

- hour average and is ignored.) All valid measurements or data points collected during a 1

- hour block shall be used t o calculate the 1

- hour emission averages. If the CEMS measures concentration on a wet basis, the CEMS shall include provisions to determine the moisture content of the exhaust gas and an algorithm to enable correction of the monitoring results to a dry ba sis (0% moisture). Alternatively, a curve of the flue gas moisture content versus load may be developed through manual stack test measurements and used in an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). The CO an d NOx CEMS shall express the 1 -hour emission averages and the 24 -hour block averages in terms of “ppmvd corrected to 15% oxygen”.

c. Data Exclusion . C O, CO 2 , and NOx emissions data shall be recorded by the CEMS at all times including episodes of startup, shu tdown, malfunction, and tuning. CO and NOx emissions data recorded during such episodes may be excluded from the 24

- hour block compliance averages in accordance with the requirements of Condition 17 of this sub section. All periods of data excluded due to startup, shutdown or malfunction shall be consecutive for each episode. The permittee shall minimize the duration of data excluded for startup, shutdown and malfunctions, to the extent practicable. Data recorded during startu p, shutdown or malfunction shall not be excluded if the episode was caused entirely or in part by poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented. Best operational practices shall be used to m inimizehourly emissions that occur during startup, shutdown and malfunction. Emissions of any quantity or duration that occur entirely or in part from poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be pr evented, shall be prohibited. Excluded emissions shall be summarized in the required semiannual report.
d. NOx Certification

. The NOx monitor shall be certified pursuant to 40 CFR Part 75 and shall be operated and maintained in accordance with the applicabl e requirements of 40 CFR Part 75, Subparts B and C. For purposes of determining compliance with the CEMS emission standards of this permit, missing data shall not be substituted. Instead the 24

- hour block average shall be determined using the remaining hourly data in the 24

- hour block. Record keeping and reporting shall be conducted pursuant to 40 CFR Part 75, Subparts F and G. The RATA tests required for the NOx monitor shall be performed using EPA Method 7E or 20 as defined in Appendix A of 40 CFR 60. The span for the NOx monitor shall not be greater than 10 ppmvd corrected to 15% O 2 . A dual span monitor may be used.

e. CO and CO 2 Certification

. The CO 2 monitor shall be certified pursuant to 40 CFR 60, Appendix B, Performance Specification 3. The CO m onitor shall be certified pursuant to 40 CFR 60, Appendix B, Performance Specification 4. Quality assurance procedures for each monitor shall conform to the requirements of 40 CFR 60, Appendix F, and the Data Assessment Report of Section 7 shall be made

e ach calendar quarter, and reported semi

- annually to the Compliance Authority. The RATA tests required for the CO 2 monitor shall be performed using EPA Method 3A, of Appendix A in 40 CFR 60. The RATA tests required for the CO monitor shall be performed using EPA Method 10, of Appendix A in 40 CFR 60. The Method 10 analysis shall use a continuous sampling train. The span for the CO monitor shall not be greater than 25 ppm corrected to 15% oxygen. A dual span CO monitor may be used.
f. Monitor Availability

. Monitor availability shall not be less than 95% in any calendar quarter. The report required in Condition 23 e above shall be used to demonstrate monitor availability. In the event 95% availability is not achieved, the permittee shall provide the Compliance Authority with a report identifying the problems in achieving 95% availability and a plan of corrective actions that will be taken to achieve 95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective actions or continued failure to achieve the minimum monitor availability shall be violations of this permit. {Permitting Note: Compliance with these requirements will ensure compliance with the other app licable CEMS requirements such as: NSPS Subpart GG; Rule 62

- 297.520, F.A.C.; 40 CFR 60.7(a)(5) and 40 CFR 60.13; 40 CFR Part 51, Appendix P – Minimum Emission Monitoring Requirements; 40 CFR 60, Appendix B - Performance Specifications; and 40 CFR 60, Appen dix F - Quality Assurance Procedures.} [Rules 62-4.070(3), 62-210.700(5), and 62-212.400(BACT), F.A.C.]
24. Ammonia Monitoring Requirements : The permittee shall install, calibrate, maintain and operate, in accordance with the manufacturer’s specifications, an ammonia flow meter to measure and record the ammonia injection rate through each SCR system. The permittee shall document the general range of ammonia flow rates required to meet emissions limitations over the range of gas turbine load conditions allowed in this permit by comparing NOx emissions recorded by the NOx monitor with ammonia flow rates recorded using the ammonia flow meter. During NOx monitor downtimes or malfunctions, the permittee shall operate at the ammonia flow rate that is consistent wit h the documented flow rate for the gas turbine load. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]R ECORDS AND R EPORTS
25. Semiannual CEMS Report : In addition to the reports required pursuant to 40 CFR 60.7, the permittee shall submit semiannual reports for each gas turbine summarizing the CEMS data and equipment. For each calendar quarter, the report shall include: the 24

- hour block compliance averages for each day of operation; the number of 1

- hour emission averages excluded from each 24

- hour complianc e average; the emissions rate of the excluded monitoring data; the reason for excluding monitoring data; the hours of missing data due to monitor downtime; the reason for any monitor downtime; unusual maintenance or repair of the CEMS; and a summary of any RATA tests performed. Based on operational data, the permittee shall also update the general range of ammonia flow rates required to meet NOx emissions limitations over the range of gas turbine load conditions. A report covering operations from January through June shall be submitted by July 30 th of each year. A report covering operations from July through December shall be submitted by January 30 th

26. of each year. The report due dates may be modified by the Title V permit. [Rules 62 -4.070(3) and 62-212.400(BACT), F.A.C.] Monitoring of Operations : To demonstrate compliance with the gas turbine capacity requirements, the permittee shall monitor and record the operating rate of each gas turbine on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown and malfunction). Such monitoring shall be made using a monitoring component of the CEMS required above, or by monitoring daily rates of consumption and heat content of natural gas in accordance with the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]The following conditions supplement all other valid air construction and operation permits for these units.

EU ID Status Emission Unit Description

001 Retired Gannon Unit 1 – coal fired boiler (125 MW steam electrical generator) 002 Retired Gannon Unit 2 – coal fired boiler (125 MW steam electrical generator) 003 Retired Gannon Unit 3 – coal fired boiler (163 MW steam electrical generator) 004 Retire d Gannon Unit 4 – coal fired boiler (170 MW steam electrical generator) 005 Retired Gannon Unit 5 – coal fired boiler (239 MW steam electrical generator) 006 Retired Gannon Unit 6 – coal fired boiler (414 MW steam electrical generator) 008 Functional Ga nnon Coal Yard

S HUTDOWN R EQUIREMENTS
1. Shutdown of Coal

- Fired Gannon Units

2. : Pursuant to t his federally enforceable PSD air construction permit
, the coal

- fired boilers for Gannon Units 1 through 6 (EUs 001 – 006) shall be permanently shut down no later than December 31, 2004. Based on the “Retired Unit Exemption” form submitted to the Department, all of these units have been permanently shut down and the dates of permanent retirement are: Unit 1 (04/16/03); Unit 2 (04/15/03); Unit 3 (11/01/03); Unit 4 (10/ 12/03); Unit 5 (01/30/03); and Unit 6 (09/30/03). [Permit No. PSD

- FL

- 301, as revised; EPA/TECO Consent Decree; D EP Form No. 62

- 210.900(1)(a)3, F.A.C.]
Coal Yard

3. : The Gannon coal yard (EU 008) remains operable . Coal throughput for this facility shall not exceed 2.85 million tons in any 12 consecutive months. {Permitting Note: TECO is exploring possible long term plans to use the existing coal handling capabilities as a coal storage and distribution terminal. Additional permits may be required.} [Rules 62- 4.160(2), 62

- 210.200 (PTE), and 62 -212.400(2)(a)2, F.A.C.; Permit No. 0570040-006- AC]
Permanent Bar on Combustion of Coal

4. : Commencing on January 1, 2005, the permittee shall not combust coal in the operation of any unit at this plant. [EPA/ TECO Conse nt Decree]
Revisions or Extensions : The provisions of this section shall not be extended or revised the without the prior approval of the U.S. EPA. [EPA/ TECO Consent Decree]This section of the permit addresses the following emissions units.

Emissions Units 02 7 – 030 : Bayside Units 3 and 4 Description : Each emissions unit consists of a General Electric Model PG7241(FA) gas turbine

- electrical generator set, an automated gas turbine control system, an inlet air filtration system, an evaporative inlet a ir cooling system, an unfired heat recovery steam generator (HRSG), a combined cycle exhaust stack (150 feet tall and 19.0 feet in diameter)
, a si mple cycle exhaust stack for Units 3A and 3B (114 feet tall and 18.8 feet in diameter), and associated support equipment. Each unit fires natural gas and Units 3A and 3B may fire distillate oil as a restricted alternate fuel (simple cycle) or as an emergency backup fuel (combined cycle)

. Permitted Capacity : At a compressor inlet air temperature of 59° F, the max imum heat input rate to each gas turbine is 1842 MMBtu (HHV) per hour of natural gas. At a compressor inlet air temperature of 59° F, the maximum heat input rate to each Unit 3A or 3B gas turbine is 2015 MMBtu (HHV) per hour of distillate oil. Stack Condi tions : When Units 3 and 4 are operating as combined cycle unit s at full load, exhaust gases exit the stack with a volumetric flow rate of approximately 1,030,000 acfm at 220° F for gas firing and 1,160,000 acfm at 275° F for o il firing (Unit 3 only)

. Whe n Units 3A or 3 B are operating as simple cycle units at full load, exhaust gases exit the stack with a volumetric flow rate of approximately 2,394,000 acfm at 1120° F for gas firing and 2,469,000 acfm at 1100° F for oil firing. Generating Capacity : The following table summarizes the electrical generating capacity for each combination of combined cycle gas turbines and steam- electrical turbines.

EU No. Bayside GT Unit GT MW, Shaft Existing Gannon ST MW, ST Total

027 3A 169 MW No. 3 163 501 028 3B 169 MW
029 4A 169 MW No. 4 170 508 030 4B 169 MW
Totals 4 GTs 676 MW 2 STs 333 1009
Note: GT means gas turbine. The nameplate generating capacity is shown for the steam

electrical turbines (ST). The final design may not fully utilize the nameplate generating capacity.
Controls : The efficient combustion of clean fuels minimizes the emissions of CO, PM/PM 10 , and VOC. The firing of very low sulfur fuels m inimizes potential emissions of SAM and SO 2

. Dry low

- NOx (DLN) combustion technology when firing natural gas and water injection when firing distillate oil inhibit NOx emissions. When operating in the combined cycle mode, a selective catalytic reduction (SCR) system further reduces NOx emissions. Continuous Monitors : Each gas turbine is equipped with continuous emissions monitoring systems (CEMS) to measure and record CO and NOx emissions as well as flue gas carbon dioxide content.

A PPLICABLE S TANDARDS AND R EGULATIONS
1. BACT Determinations

2. : The emissions units addressed in this section are subject t o Best Available Control Technology (BACT) determinations for carbon monoxide (CO), particulate matter (PM/PM 10 ), and volatile organic compounds (VOC). [Rule 62-212.400(BACT), F.A.C.] NSPS Requirements : Each gas turbine shall comply with Subpart GG in 40 CFR 60, the New Source Performance Standards (NSPS) for Stationary Gas Turbines, as specified in Appendix GG of this permit. In addition, each gas turbine shall comply with the applicable requirements of Subpart A in 40 CFR 60, theNSPS General Provision s , including: 40 CFR 60.7 (Notification and Record Keeping), 40 CFR 60.8 (Performance Tests), 40 CFR 60.11 (Compliance with Standards and Maintenance Requirements), 40 CFR 60.12 (Circumvention), 40 CFR 60.13 (Monitoring Requirements), and 40 CFR 60.19 (Gen eral Notification and Reporting Requirements). [40 CFR 60 ; Rule 62-204.800(7)(b), F.A.C.]

E QUIPMENT
3. Construction

a. Construction of Bayside Units 3A and 3B shall commence within 18 months after permit issuance. Otherwise , authorization to construct shall become invalid. : Bayside Unit 3 is scheduled to commence construction in May of 2005 and complete construction in 2006. Units 3A and 3B may be installed and operated a s simple cycle units and later converted to combined cycle units. Unit 4 will be added as a combined cycle unit. The permittee shall inform the Department and Compliance Authority of any substantial changes to the construction schedule including conversion of Units 3A and 3B to combined cycle operation. Pursuant to 40 CFR 52.21(r)(2):

b. Conve rsion of Units 3A and 3B to combined cycle operation shall be complete before this permit expires.

c. Construction of combined cycle Unit 4 shall be complete before this permit expires.
d. Each combined cycle unit shall include an SCR system to reduce NOx emissi ons.

e. For good cause, the permittee may request that this PSD air construction permit be extended. When processing any request for a permit extension, the Department may require revalidation of the BACT determinations or a revised netting analysis or both. [Application; Rule 62-212.400(BACT), F.A.C.]
4. Gas Turbines

5. : The permittee is authorized to install, tune, operate and maintain four new General Electric Model PG7241(FA) gas turbines with electrical generator sets, each designed to produce a nominal 169 M W of shaft

- driven electrical power. Each unit shall be designed for eventual operation as a combined cycle system to include an automated gas turbine control system, an inlet air filtration system, an unfired heat recovery steam generator (HRSG), a combin ed cycle exhaust stack ( 150 feet tall and 19.0 feet in diameter ) , and associated support equipment. Bayside Units 3A and 3B may be installed as simple cycle units and later converted to combined cycle units. Units 3A and 3B will each have a simple cycle exhaust (114 feet tall and 18.8 feet in diameter). [Applicant Request; Design] Heat Recovery Steam Generators (HRSG)

6. : Each gas turbine system shall be designed to include an unfired HRSG with three levels of steam conditions (high pressure, intermediate pressure, and low pressure). [Design] Automated Control System : The permittee shall install, calibrate, tune, operate, and maintain a Speedtronic TM

7. Mark VI automated control system (or better) for each gas turbine. Each system shall be designed and oper ated to monitor and control the gas turbine combustion process and operating parameters including, but not limited to: air/fuel distribution and staging, turbine speed, load conditions, temperatures, heat input, and fully automated startup and shutdown. [Design; 62-212.400(BACT), F.A.C.]

a. DLN Combustion Technology : Each gas turbine shall incorporate the General Electric dry low

- NOx combustion system (DLN 2.6 or better) to provide efficient lean premix combustion. Prior to the initial

e missions performance tests for each gas turbine, the DLN combustors and automated gas turbine control system shall be tuned to reduce CO and NOx emissions. Thereafter, each system shall be maintained and tuned in accordance with the manufacturer’s recomme ndations to maintain CO and Combustion ControlsNOx emissions at the optimum levels. [Design; Rule 62-212.400(BACT), F.A.C.]
b. Water Injection : The permittee shall install, operate, and maintain a water injection system on Units 3A and 3B to reduce NOx emissions from each gas turbine when firing distillate oil. The water injection system shall be tuned to achieve the permitted levels for CO and NOx emissions during simple cycle operation. Thereafter, each system shall be maintained and tuned in accordance with the manufactur er’s recommendations. The automated control system shall be programmed to establish a water

- to

- fuel ratio designed to achieve the NOx emission standard for oil firing during simple cycle operation on a 1-hour basis. [Design; Rule 62-212.400(BACT), F.A.C.]
8. SCR System

9. : The permittee shall install, tune, operate and maintain a selective catalytic reduction (SCR) system to reduce NOx emissions from each combined cycle gas turbine. The SCR system shall consist of an ammonia injection grid, catalyst, ammonia storage, a monitoring and control system, electrical system, piping, and other ancillary equipment. The SCR system shall be designed to reduce NOx emissions while minimizing ammonia slip within the permitted levels for gas firing . [DEP/TECO Consent Final Judgment; EPA/TECO Consent Decree; Rule 62 -4.070(3), F.A.C.] Evaporative Inlet Air

- Cooling System

P ERFORMANCE R ESTRICTIONS : Each gas turbine system includes an evaporative cooling system designed to reduce the temperature of the inlet air to the gas turbine compressor. The reduced temperature provides a greater mass flow rate and increases power production with additional fuel combustion. {Permitting Note: The proposed equipment includes a water distribution system with packed media blocks of corrugated layers of fibrous mater ial. Air passing over the system wicks moisture away from the media to create the cooling effect.} [Applicant Request; Design]

10. Permitted Capacity

11. : At a compressor inlet air temperature of 59° F, the maximum heat input rate to ea ch gas turbine is 1842 MMBtu (HHV) per hour of natural gas. At a compressor inlet air temperature of 59° F, the maximum heat input rate to each Unit 3A and 3B gas turbine is 2015 MMBtu (HHV) per hour of distillate oil. The maximum heat input rate s are ba sed on a compressor inlet air temperature of 59° F, the higher heating value (HHV) of each fuel and the expected performance levels. Heat input rates will vary depending upon gas turbine characteristics, ambient conditions, and evaporative cooling. The p ermittee shall provide the manufacturer’s performance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. Operating data may be adjusted for the a ppropriate site conditions in accordance with the performance curves and/or equations on file with the Department. [Design; Rule 62-210.200(PTE), F.A.C.]
Allowable Fuels

a. Natural Gas : Each gas turbin e shall fire pipeline natural gas with a fuel sulfur content of no more than 2 grains per 100 SCF of natural gas based on a 12

- month rolling average. Compliance shall be demonstrated each month by compiling the daily fuel sulfur analyses provided by the p ipeline vendor. Methods for determining the sulfur content of the natural gas shall be ASTM methods D4084 -82, D3246- 81 or equivalent methods. [Design; Rules 62

- 210.200(PTE) and 62

- 212.400(BACT), F.A.C.; DEP/TECO Consent Final Judgment; EPA/TECO Consent D ecree] : The gas turbines shall fire only the following fuels.

b. Distillate Oil – Units 3A and 3B : As a restricted alternate fuel, Units 3A and 3B may fire new No. 2 distillate oil with a maximum fuel sulfur content of no more than 0.05% sulfur by weight. During simple cycle operation, e ach gas turbine shall fi re no more than 9,722,300 gallons of distillate oil during any consecutive 12

- month period (equivalent to 700 full load equivalent hours of operation). I nitial compliance with the fuel sulfur limit shall be demonstrated by taking a sample , analyzing the

s ample for fuel sulfur, and reporting the results to each Compliance Authority before initial startup.Sampling the fuel oil sulfur content shall be conducted in accordance with ASTM D4057

- 88, Standard Practice for Manual Sampling of Petroleum and Petroleu m Products, and one of the following test methods for sulfur in petroleum products: ASTM D129

- 91, ASTM D1552

- 90, ASTM D2622

- 94, or ASTM D4294

- 90. More recent versions of these methods may be used. For each subsequent fuel delivery, the permittee shall maintain a permanent file of the certified fuel sulfur analysis from the fuel vendor. At the request of a Compliance Authority, the permittee shall perform additional sampling and analysis for the fuel sulfur content. [Design; Application; Rules 62 -210.20 0(PTE) and 62

- 212.400(BACT), F.A.C.]

c. Distillate Oil – Units 3A and 3B, Combined Cycle Operation Only : Once converted to combined cycle operation, Units 3A and 3B may be fired with new No. 2 fuel o il if and only if: (1) The Unit cannot be fired with natural ga s; (2) T he Unit has not yet been fired with No. 2 fuel oil as a back up fuel for more than 875 full load equivalent hours in the calendar year in which Tampa Electric wishes to fire the Unit with such oil; (3) The oil to be used in firing the Unit has a sulphur content of less than 0.05 percent (by weight); (4) Tampa Electric uses all emission control equipment for that Unit when it is fired with such oil to the maximum extent possible; and (5) Tampa Electric complies with all applicable permit conditions, including emissi on rates for firing with No. 2 fuel oil, as set forth in applicable preconstruction and operating permits. [EPA/TECO Consent Decree]
12. Hours of Operation

13. : The hours of operation for each gas turbine are not limited (8760 hours per year). [Application; Rule s 62-212.400(BACT) and 62-210.200(PTE), F.A.C.] Operating Procedures

E MISSIONS S TANDARDS : The Best Available Control Technology (BACT) determinations for CO, PM/PM 10 , and VOC emissions established by this permit rely on “good operating practices” to minimize emissions. Ther efore, all operators and supervisors shall be properly trained to operate and maintain the gas turbines and pollution control systems in accordance with the guidelines and procedures established by the manufacturer. The training shall include good operati ng practices as well as methods to minimize emissions during startup and shutdown. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]

{Permitting Note: A summary table of the emissions standards is provided in Appendix B of this permit.}
14. Emissions Standards - Performance Test

Pollutant s : The gas turbines shall not exceed the following standards as determined by the emissions performance tests conducted at permitted capacity.

Emission Standard s – Performance Tests Test Method Simple Cycle Operation – Units 3A and 3B Only
Carbon Monoxide (CO) ≤ 28.7 pounds per hour and 7.8 ppmvd corrected to 15% oxygen (gas) ≤ 40.5 pounds per hour and 9.0 ppmvd corrected to 15% oxygen (oil) EPA Method 10 3 test runs Nitrogen Oxides (NOx) ≤ 69.1 pounds per hour and 10.5 ppmvd corrected to 15% oxygen (gas) ≤ 320 .3 pounds per hour and 42.0 ppmvd corrected to 15% oxygen (oil) EPA Method 7E 3 test runs
Visible Emissions ≤ 10% opacity, 6

- minute block average (gas/oil) EPA Method 9 30 minutesPollutant Emission Standards – Performance Tests Test Method
Combined C ycle Operation – Units 3 and 4

Ammonia Slip Subject to the requirements of Condition 22 in this subsection , each SCR system shall be designed and operated for an ammonia slip ta rget of less than 5 ppmvd corrected to 15% oxygen for gas firing. CTM

- 027 3 test runs

Carbon Monoxide (CO) ≤ 28.7 pounds per hour and 7.8 ppmvd corrected to 15% oxygen (gas) EPA Method 10 3 test runs Nitrogen Oxides (NOx) ≤ 23.1 pounds per hour and 3.5 ppmvd corrected to 15% oxygen (gas) EPA Method 7E 3 test runs
Visible Emissions ≤ 10% opacity , 6 minute block average (gas/oil) EPA Method 9 30 minutes

a. The mass emission limits are based on full load and a compressor inlet temperature of 59° F.
b. NOx emissions are defined as oxides of nitrogen reported as NO 2

.
c. Operating data shall be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department.
d. The CO and NOx standards represent the initial standards for “new and clean” units. Subsequent compliance shall be demonstrated with data collected by the certified CEMS.

e. The efficient combustion of clean fuels represents the Best Available Control Technology (BACT) requirements for emissions of particulate matter and volatile organic compounds. Compliance with carbon monoxide and visible emissions stand ards shall serve as continuous indicators of efficient combustion to minimize emissions of these pollutants. Compliance with the fuel sulfur specifications of this permit minimizes potential emissions of sulfuric acid mist and sulfur dioxide. No performa nce tests are required for these pollutants.
f. Only the CEMS

- based CO and NOx emissions standards apply to Units 3A and 3B when firing distillate oil and operating in combined cycle mode b ecause these u nits can only fire distillate oil as an

“ emergency backu p fuel” when op erating in this mode. [Rule s 62 -4.070(3), 62-212.400(BACT), and 62 -297.310, F.A.C. ; DEP/TECO Consent Final Judgment; EPA/TECO Consent Decree; 40 CFR 60.332]
15. Emissions Standards - CEMS Dat

Pollutant a : The following standards apply to each gas turbine based on data collected from each required Continuous Emissions Monitoring System (CEMS).

CEMS

- Based Emission Standards Method Simple Cycle Operation – Units 3A and 3B Only
Carbon Monoxide (CO) ≤ 9.0 ppmvd corrected to 15% oxygen based on a 24

- hour block average (gas/oil) CO CEMS Nitrogen Oxides (NOx) ≤ 1 0.5 ppmvd corrected to 15% oxygen based on a 24

- hour block average (gas) ≤ 42.0 ppmvd corrected to 15% oxygen based on a 24

- hour block average (oil) NOx CEMS Combined Cycle Operation – Units 3 and 4
Carbon Monoxide (CO) ≤ 9.0 ppmvd corrected to 15% oxygen based on a 24

- hour block average (gas/oil) CO CEMS Nitrogen Oxides (NOx) ≤ 3.5 ppmvd corrected to 15% oxygen based on a 24

- hour block average (gas) ≤ 12.0 ppmvd corrected to 15% oxygen based on a 24

- hour block average (oil) NOx CEMSEach 24

- hour block average shall start at midnight each operating day and shall be calculated from 24 consecutive 1

- hour averages. If a unit operates less than 24 hours during the block, the 24

- hour block averag e shall be the average of the available valid 1

- hour averages. [Rules 62- 4.070(3) and 62- 212.400(BACT), F.A.C.]

S TARTUP , S HUTDOWN , M ALFUNCTION , AND L OW L OAD O PERATION
16. Excess Emissions Prohibited

17. : Excess emissions caused entirely or in part by poor mainte nance, poor operation or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction, shall be prohibited. All such preventable emissions shall be included in the compliance averages determined from the CO and NOx CEMS data. [Rule 62-210.700(4), F.A.C.]
Alternate Standards and CEMS Data Exclusion

a. Opacity During Startup and Shutdown : During startup and shutdown, the opacity of the exhaust gases shall not exceed 10%, except for up to ten 6

- minute averaging periods in a calendar day during which the opacity shall not exceed 20%. Data for each 6

- minute averaging period shall be exclusive from other 6-minute averaging periods. : The following permit conditions establish alternate standards or allow the exclusion of monitoring data for specifically defined periods of startup, shutdown, and malfunction. These conditions apply only if operators employ the best operational practices to minimize the amount and duration of emissions during such incidents.

b. Low Load Operation : Excluding startup, shutdown, malfunction, DLN tuning, compressor blade drying, and over speed trip tests, each gas turbine may operate below 50% base load providing: the gas turbine is firing natural gas and operating in full dry low

- NOx combustion mode; the CO and NOx CEMS are functioning properly during such periods and recording valid emissions data within the span range of the monitors; and the gas turbine remains in compliance with the CO and NOx emissions standards (24-hour block averages).

c. CEMS Data Exclusion : For the following specified operational periods, CO and NOx emissions data may be excluded from the 24

- hour block compliance averages in accordance with the corresponding requirements. (1) Definitions : Rule 62

- 210.200(231), F.A.C. def ines “s hutdown” as the cessation of the operation of an emissions unit for any purpose. Rule 62

- 210.200(160), F.A.C. defines “malfunction” as any unavoidable mechanical and/or electrical failure of air pollution control equipment or process equipment or of a process resulting in operation in an abnormal or unusual manner. Rule 62

- 210.200(246), F.A.C. defines “startup” as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause tem perature, pressure, chemical or pollution control device imbalances, which result in excess emissions. (2) Standard Startups, Shutdowns, and Malfunctions : For each gas turbine, no more than four 1 -hour CEMS emission averages shall be excluded from any 24 -hour block compliance average due to standard startups, shutdowns, and malfunctions (total). (3) Cold Steam Turbine Startup : “Cold steam turbine startup” means a startup after the steam turbine has been offline for 24 hours or more, or the first stage turbine met al temperature is 250° F or less. To minimize emissions, no more than one gas turbine per Bayside Unit shall be operated during a cold steam turbine startup. No more than sixteen 1

- hour CEMS emission averages shall be excluded from the 24

- hour block comp liance averages due to a cold steam turbine startup. In addition, no more than sixteen 1 -hour CEMS emission averages shall be excluded from any 24 -hour block compliance average due to cold steam turbine startup. In the event of a cold steam turbinestart up and standard startups, shutdowns and/or malfunctions within the same 24 hour period, a total of sixteen 1

- hour CEMS emissions averages may be excluded with no more than four of those sixteen 1

- hour CEMS emissions averages being excluded due to standard startups, shutdowns, and malfunctions (total)

. This condition applies only to the gas turbine being used for the cold steam turbine startup. The permittee shall notify the Compliance Authority no later than 24 hours after beginning a cold steam turbine startup. Notification may be by phone, facsimile, email, or letter. (4) Steam Turbine Startup Following an Unplanned Forced Outage : “Steam turbine startup following unplanned, forced outage” means startup when the first stage turbine metal temperature is 250° F or more and occurs within 24 hours after either (1) the steam turbine inadvertently trips offline, or (2) the plant is forced to take the steam turbine offline for repair. To minimize emissions, no more than one gas turbine per Bayside Unit shall be operated during a steam turbine startup following an unplanned forced outage. No more than eight 1

- hour CEMS emissions averages shall be excluded from the 24

- hour block compliance averages due to a steam turbine startup following an unplanned forced outage. In addition, no more than eight 1

- hour CEMS emission averages shall be excluded from any 24

- hour block compliance average due to steam turbine startups following an unplanned forced outage. In the event of a startup following an unplanned forced outage and standard startups, shutdowns and/or malfunctions within the same 24 hour period, a total of eight 1 -hour CEMS emissions averages may be excluded with no more than four of those eight 1

- hour CEMS emissions averages being excluded due to standard startup s, shutdowns, and malfunctions (total)

. This condition applies only to the gas turbine being used for steam turbine startup following an unplanned forced outage . The permittee shall notify the Compliance Authority no later than 24 hours after beginning a steam turbine startup following an unplanned forced outage . Notification may be by phone, facsimile, email, or letter and shall include the reason for the unplanned forced outage. (5) DLN Tuning : “DLN Tuning” means operating the gas turbine at intermittent loads throughout the full load range in order to adjust and tune the dry low

- NOx (DLN) combustion system. DLN tuning shall be conducted in accordance with manufacturer’ recommendations. Emissions data collected during DLN tuning may be excluded from the 24- hour block compliance averages

. {Permitting Note: For example, a major tuning session would occur after combustor change-out.} (6) Compressor Blade Drying : Following a compressor blade wash in accordance with the manufacturer’s recommendations , the permi ttee may operate a gas turbine at very low loads to heat and dry the compressor blades. Emissions data collected while drying the compressor blades may be excluded from the 24

- hour block compliance averages

. {Permitting Note: A gas turbine would typically operate at approximately 10% of base load or less to perform compressor blade drying.} (7) Over Speed Trip Test : As a periodic maintenance practice, the permittee may perform over speed trip tests in accordance with the manufacturer’s recommendations. Emissions data collected while conducting over speed trip tests may be excluded from the 24

- hour block compliance averages

. {Permitting Note: During this test
, the gas turbine is operated at full speed, no load (FSNL) for approximately 5 to 6 hours. The unit is gradually accelerated to 110% speed (3960 rpm) to initiate a trip and then coasts down normally. Over speed trip tests are typically performed after a long outage or a major component overhaul.} To the extent practicable, the permittee shall minimiz e the amount and duration of emissions during periods of startup, shutdown, malfunction, DLN tuning, compressor blade drying, and over speed trip testing. If a CEMS reports emissions in excess of an emissions standard (24

- hour block), the permittee shall notify the Compliance Authority within one working day with a preliminary report of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken tocorrect the problem. In addition, the Compliance Authority may request a written summary report of the incident. All emissions data allowed for exclusion shall be summarized in the Semiannual CEMS Report required in Condition 25 of this subsection.
d. Startup and Shutdown P lan : The permittee shall maintain on site a “Startup and Shutdown Plan” that describes procedures for startup and shutdown of the Bayside Units. As provided by the authority in Rule 62

- 210.700(5), F.A.C., the above requirements are established in lieu of the provisions of Rule 62-210.700(1), F.A.C. {Permitting Note: The durations for a cold steam turbine startup and a steam turbine startup following an unplanned forced outage are not typical for combined cycle units. The Bayside Units utilize the existin g Gannon steam turbines. Operating procedures require one gas turbine to operate at low loads for extended periods to gradually warm the main and hot reheat steam lines to the steam turbine as well as the steam turbine. Some steam lines are in excess of 1700 feet. Such startups are expected to occur infrequently.} [Design; Rules 62

- 4.130, 62

- 210.700(5), and 62

- 212.400 (BACT), F.A.C.; Permit No. PSD

FL -301C]

E MISSIONS P ERFORMANCE T ESTING
18. Operating Rate During Testing

19. : Emissions performance testing shall be conducted with the emissions unit operating at permitted capacity. Permitted capacity is defined as 90 to 100 percent of the maximum operation rate allowed by the permit. If it is impractical to test at permitted capacity, an emissions unit may be te sted at less than the maximum permitted capacity; in this case, subsequent emissions unit operation is limited to 110 percent of the test rate until a new test is conducted. Once the unit is so limited, operation at higher capacities is allowed for no mor e than 15 consecutive days for the purpose of additional compliance testing to regain the authority to operate at the permitted capacity. [Rule 62 -297.310(2), F.A.C.]
Test Methods

Method : Any required tests shall be performed in accordance with the following re ference methods.
Description of Method and Comments

CTM

- 027 Procedure for Collection and Analysis of Ammonia in Stationary Source : This is an EPA conditional test method. The minimum detection limit shall be 1 ppm.

5 Determination of Particulate Matter Emissions from Stationary Sources : The minimum sampling time shall be two hours per run and the minimum sampling volume shall be 60 dscf per run.
7E Determination of Nitrogen Oxide Emissions from Stationary Sources
9 Visual Determination of the O pacity of Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources : The method shall use a continuous sampling train.

18 Measurement of Gaseous Organic Compound Emissions by Gas Chromatography : EPA Method 18 may be used concurrently with EPA Method 25A to deduct emissions of methane and ethane from the measured VOC emissions.
20 Determination of Nitrogen Oxides, Sulfur Dioxide and Diluent Emissions from Stationary Gas Turbines
25A Determination of Volatil e Organic Concentrations Except for Method CTM

- 027, the above methods are described in 40 CFR 60, Appendix A, and adopted by reference in Rule 62

- 204.800, F.A.C. Method CTM

- 027 is published on EPA’s Technology Transfer Network Web Site at “http://www.epa .gov/ttn/emc/ctm.html”. Although no specific tests are required for emissions of particulate matter and volatile organic compounds, the test methods are included for completeness. No other methods may be used for compliance testing unless prior written a pproval isreceived from the Department. [Rules 62 -204.800 and 62-297.100, F.A.C.; 40 CFR 60, Appendix A]
20. Initial Compliance Tests

a. Simple Cycle Units 3A and 3B : Each simple c ycle gas turbine shall be tested to demonstrate initial compliance with the emissions standards for CO, NOx, and visible emissions in Condition : To demonstrate initial compliance with the emissions standards, tests shall be conducted on each gas turbine within 60 day s after achieving at least 90% of the maximum permitted capacity, but not later than 180 days after initial operation of each gas turbine. Tests shall be conducted in accordance with the following requirements.

14 of this subsection when firing natural gas and distillate oil.
b. Combine d Cycle Units 3 and 4 : Each combined cycle gas turbine shall be tested to demonstrate compliance with the emissions standards for CO, NOx, visible emissions and ammonia slip in Condition 14 of this subsection when fi ring natural gas. {Permitting Note: For combined cycle operation of Units 3A and 3B, initial tests when firing distillate oil are not required because this fuel may only be fired as a restricted emergency backup fuel.}
Tests for CO and NOx shall be condu cted concurrently. Certified CEMS data may be used to demonstrate initial compliance with the CO and NOx emissions standards. The test results for ammonia slip shall also report the CO and NOx emissions recorded by the CEMS during each test run. [Rule 6 2-297.310(7)(a)1, F.A.C.; 40 CFR 60.335]
21. Annual Compliance Tests : During each federal fiscal year (October 1 st to September 30 th

a. Simple Cycle Units 3A and 3B : Each simple cycle gas tu rbine shall be tested annually to demonstrate compliance with the standard for visible emissions in Condition ), each gas turbine is subject to the following testing requirements.

14 of this subsection when firing natural gas and when firing distillate oil (if the unit fires distillate oil for more than 400 hours during the federal fiscal year).
b. Combined Cycle Units 3 and 4 : Each combined cycle gas turbine shall be tested to demonstrate compliance with the standards for visible emissions and ammonia slip in Condition 14 of this subsection when firing natural gas. The test results for ammonia slip shall also report the CO and NOx emissions recorded by the CEMS during each test run. Units 3A and 3B shall also be tested for visible emissions if the u nit fires distillate oil for more than 400 hours during the federal fiscal year. {Permitting Note : Continuous compliance with the CO and NOx standards will be demonstrated by data collected from the certified CEMS.} [Rules 62-212.400(BACT) and 62-297.310(7)(a)3 and 4, F.A.C.]
22. Additional Ammonia Slip Testing

a. Begin testing and reporting the ammoni a slip for each subsequent calendar quarter; : If the tested ammonia slip rate for a gas turbine exceeds 5 ppmvd corrected to 15% oxygen when firing natural gas during the annual test, the permittee shall:

b. Before the ammonia slip exceeds 7 ppmvd corrected to 15% oxygen, take corrective actions that result in lowering the ammonia slip to less than 5 ppmvd corrected to 15% oxygen; and

c. Test and demonstrate that the a mmonia slip is less than 5 ppmvd corrected to 15% oxygen within 15 days after completing the corrective actions. Corrective actions may include, but are not limited to, adding catalyst, replacing catalyst, or other SCR system maintenance or repair. After demonstrating that the ammonia slip level is less than 5 ppmvd corrected to 15% oxygen, testing and reporting shall resume on an annual basis. [Rules 62-4.070(3) and 62- 297.310(7)(b), F.A.C.]C ONTINUOUS M ONITORING R EQUIREMENTS
23. Continuous Emissions Monitor ing Systems

a. Emission Averages . Compliance with the 24 -hour standards for CO and NOx emissions shall be based on data collected by the required CEMS. The 24

- hour block shall start at midnight of each operating day and consist of 24 consecutive 1-hour blocks. If a unit operates continuously throughout the day, the 24- hour block average shall be the average of 24 consecutive 1

- hour emi ssion averages. If a unit operates less than 24 hours during the day, the 24

- hour block average shall be the average of available valid 1

- hour emission averages collected during operation. If monitoring data is authorized for exclusion (due to startup, s hutdown, malfunction, or tuning), the 24

- hour block average shall be the average of the remaining available valid 1

- hour emission averages collected during operation. Upon a request from the Compliance Authority, the NOx emission rate shall be corrected t o ISO conditions to demonstrate compliance with the applicable standards of 40 CFR 60.332. : The permittee shall install, calibrate, maintain, and operate a continuous emission monitoring system (CEMS) in the exhaust stack of each emissions unit to measure and record emissions of CO and NOx in a manner sufficient to demonstrate compl iance with the CEMS emission standards of this permit. The carbon dioxide (CO 2 ) content of the flue gas shall also be monitored at the location where CO and NOx are monitored to correct the measured emissions rates to 15% oxygen. The oxygen content of th e flue gas shall be calculated by the CEMS using the CO 2 content of the flue gas and an F- factor that is appropriate for natural gas.

b. Data Collection . The CEMS shall be designed and operated to sample, analyze, and record CO, CO 2 , and NOx data evenly spaced over the hour. Each 1

- hour emission ave rage shall be computed using at least one data point in each fifteen minute quadrant of the 1

- hour block during which the unit combusted fuel. Notwithstanding this requirement, each 1

- hour emission average shall be computed from at least two data points s eparated by a minimum of 15 minutes. If the unit does not operate in more than one quadrant of a 1

- hour block, the data is insufficient to determine a 1

- hour emission average and shall be ignored. (Example: Unit begins startup with only ten minutes remaining in the 1

- hour block. Data is insufficient to determine a 1

- hour average and is ignored.) All valid measurements or data points collected during a 1

- hour block shall be used to calculate the 1

- hour emission averages. If the CEMS measures concentrat ion on a wet basis, the CEMS shall include provisions to determine the moisture content of the exhaust gas and an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). Alternatively, a curve of the flue gas moisture conten t versus load may be developed through manual stack test measurements and used in an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). The CO and NOx CEMS shall express the 1 -hour emission averages and the 24 -hour bloc k averages in terms of “ppmvd corrected to 15% oxygen”.

c. Data Exclusion . C O, CO 2 , and NOx emissions data shall be recorded by the CEMS at all times including episodes of startup, shutdown, malfunction, and tuning. CO and NOx emissions data recorded during such episodes may be excluded from the 24

- hour block compliance averages in accordance with the requirements of Condition 17 of this subsection. All periods of data excluded due to startup, shutdown or malfunction sh all be consecutive for each episode. The permittee shall minimize the duration of data excluded for startup, shutdown and malfunctions, to the extent practicable. Data recorded during startup, shutdown or malfunction shall not be excluded if the episode was caused entirely or in part by poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented. Best operational practices shall be used to minimize hourly emissions that occur during startup, shutdown and malfunction. Emissions of any quantity or duration that occur entirely or in part from poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented, shall be prohibited. Excluded emissions shall be

summa rized in the required semiannual report.d. NOx Certification

. The NOx monitor shall be certified pursuant to 40 CFR Part 75 and shall be operated and maintained in accordance with the applicable requirements of 40 CFR Part 75, Subparts B and C. For purpose s of determining compliance with the CEMS emission standards of this permit, missing data shall not be substituted. Instead the 24

- hour block average shall be determined using the remaining hourly data in the 24

- hour block. Record keeping and reporting s hall be conducted pursuant to 40 CFR Part 75, Subparts F and G. The RATA tests required for the NOx monitor shall be performed using EPA Method 7E or 20 as defined in Appendix A of 40 CFR 60. The span for the NOx monitor shall not be greater than 10 ppmvd corrected to 15% O 2 . A dual span monitor may be used.

e. CO and CO 2 Certification

. The CO 2 monitor shall be certified pursuant to 40 CFR 60, Appendix B, Performance Specification 3. The CO monitor shall be certified pursuant to 40 CFR 60, Appendix B, Per formance Specification 4. Quality assurance procedures for each monitor shall conform to the requirements of 40 CFR 60, Appendix F, and the Data Assessment Report of Section 7 shall be made each calendar quarter, and reported semi

- annually to the Complian ce Authority. The RATA tests required for the CO 2 monitor shall be performed using EPA Method 3A, of Appendix A in 40 CFR 60. The RATA tests required for the CO monitor shall be performed using EPA Method 10, of Appendix A in 40 CFR 60. The Method 10 an alysis shall use a continuous sampling train. The span for the CO monitor shall not be greater than 25 ppm corrected to 15% oxygen. A dual span CO monitor may be used.
f. Monitor Availability

. Monitor availability shall not be less than 95% in any calendar quarter. The report required in Condition 23 e above shall be used to demonstrate monitor availability. In the event 95% availability is not achieved, the permittee shall provide the Compliance Authority with a report identif ying the problems in achieving 95% availability and a plan of corrective actions that will be taken to achieve 95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective ac tions or continued failure to achieve the minimum monitor availability shall be violations of this permit. {Permitting Note: Compliance with these requirements will ensure compliance with the other applicable CEMS requirements such as: NSPS Subpart GG; Rule 62

- 297.520, F.A.C.; 40 CFR 60.7(a)(5) and 40 CFR 60.13; 40 CFR Part 51, Appendix P – Minimum Emission Monitoring Requirements; 40 CFR 60, Appendix B - Performance Specifications; and 40 CFR 60, Appendix F - Quality Assurance Procedures.} [Rules 62-4.070(3), 62-210.700(5), and 62-212.400(BACT), F.A.C.]
24. Ammonia Monitoring Requirements

R ECORDS AND R EPORTS : The permittee shall install, calibrate, maintain and operate in accordance with the manufacturer’s specifications an ammonia flow meter to measure and record the ammonia in jection rate through each SCR system. The permittee shall document the general range of ammonia flow rates required to meet emissions limitations over the range of gas turbine load conditions allowed in this permit by comparing NOx emissions recorded by the NOx monitor with ammonia flow rates recorded using the ammonia flow meter. During NOx monitor downtimes or malfunctions, the permittee shall operate at the ammonia flow rate that is consistent with the documented flow rate for the gas turbine load. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]

25. Semiannual CEMS Report : In addition to the reports required pursuant to 40 CFR 60.7, the permittee shall submit semiannual reports for each gas turbine summarizing the CEMS data and equipm ent. For each calendar quarter, the report shall include: the 24

- hour block compliance averages for each day of operation; the number of 1

- hour emission averages excluded from each 24

- hour compliance average; the emissions rate of the excluded monitoring data; the reason for excluding monitoring data; the hours of missing data due to monitor downtime; the reason for any monitor downtime; unusual maintenance or repair of theCEMS; and a summary of any RATA tests performed. Based on operational data, the permittee shall also update the general range of ammonia flow rates required to meet NOx emissions limitations over the range of gas turbine load conditions. A report covering operations from January through June shall be submitted by July 30 th of each year. A report covering operations from July through December shall be submitted by January 30 th

26. of each year. The report due dates m ay be modified by the Title V permit. [Rules 62 -4.070(3) and 62-212.400(BACT), F.A.C.] Monitoring of Operations : To demonstrate compliance with the gas turbine capacity requirements, the permittee shall monitor and record the operating rate of each gas turbine on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown and malfunction). Such monitoring shall be made using a monitoring component of the CEMS required above, or by monitori ng daily rates of consumption and heat content of natural gas in accordance with the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-212.400(BACT), F.A.C.]

# D. City of Tallahassee – Hopkins

Emission Units shut

- down: 1. EU004 – Boiler #2 (BART)

Items included: Air Construction Permit ( 0730003

- 009

- AC)

.

# Department of 

# Environmental· Protection

leb Bush Governor

PERMITTEE

City of Tallahassee, Electric Utilities Arvah B. Hopkins Generating Station 2602 Jackson Bluff Road Tallahassee, Florida 32304
Authori::ed Representative: Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400

Mr. Robert E. McGarrah, Production Superintendent

PROJECT AND LOCATION Colleen M. Castille Secretary

Air Permit No. 0730003-009-AC Arvah B. Hopkins Generating Station Facility ID No. 0730003 SIC No. 4911 Unit 2 Re-Powering Project Permit Expires: July I, 2009

This permit authorizes the construction of a General Electric 7FA combustion turbine (188 MW) and gas-fired heat recovery steam generator (HRSG) to re-power the existing Unit 2 steam turbine-electrical generator set (238 MW). The existing Unit 2 boiler will be permanently shut down as part of this project. The new equipment will be installed at the Arvah B. Hopkins Generating Station, which is located in Leon County at 1125 Geddie Road, Tallahassee, Florida.

STATEMENT OF BASIS

This air pollution construction permit is issued under the provisions of Chapter 403 of the Florida Statutes (F.S.), and Chapters 62-4, 62-204,62-210, 62-212, 62-296, and 62-297 of the Florida Administrative Code (F.A.C.) and Title 40, Parts 60 and 63 of the Code of Federal Regulations. The permittee is authorized to install the proposed equipment in accordance \vith the conditions of this permit and as described in the application, approved drawings, plans, and other documents on file with the Department.

CONTENTS

Section I. General Information Section 2. Administrative Requirements Section 3. Emissions Units Specific Conditions
Section 4. Appendices

# ~,~l~ Joseph Kahn, P.E., Director Division of Air Resource Management

",\1orc Protection, Less Process"

Primed on recycled paper_ { ,. (Date)FACILITY AND PROJECT DESCRIPTION The City of Tallahassee operates the Arvah B. Hopkins Generating Station, w hich is an existing power plant (SIC No. 4911). The plant currently consists of:

**•** Steam Generating Unit 1 (EU

- 001) is a Foster

- Wheeler Corporation Model No. SF

- 5 boiler rated at 75 MW. The unit is authorized to fire natural gas or fuel oil. It is subject to the Phase II Acid Rain provisions. The unit began commercial operation in May of 1971.

**•** Combustion Turbine 1 (EU

- 002) is a Westinghouse Model No. W191G combustion turbine rated at 16.47 MW. The unit is authorized to fire natural gas or No. 2 oil. It is not subject to NSPS Subpart GG for combustion turbine s. The unit began commercial operation in February of 1970.

**•** Combustion Turbine 2 (EU

- 003) is a Westinghouse Model No. W251G combustion turbine rated at 26.8 MW. The unit is authorized to fire natura l gas or No. 2 oil. It is not subject to NSPS Subpart GG for combustion turbines. The unit began commercial operation in September of 1972.

**•** Steam Generating Unit 2 (EU

- 004) is a Babcock & Wilcox Model No. RB

- 533 boiler rated at 238 MW. The unit is autho rized to fire natural gas or fuel oil. It is subject to the Phase II Acid Rain provisions and a Florida Power Plant Site Certification No. PA 74

- 03D. The unit began commercial operation in October of 1977.

**•** The facility also includes: fugitive VOC source s (EU

- 005) such as painting operations; general purpose engines (EU

006); and emergency generators (EU

- 007).

**•** LM 6000PC SPRINT simple cycle combustion turbine s (EU

- 031 and EU

- 032). Each unit has a capacity of approximately 50 MW and fires both natural gas and distillate oil. NOx emissions are controlled by water injection and a hot selective catalytic reduction (SCR) system. {Permitting Note: On May 10, 2004, the Department issued Permit No. 0730003

- 004

- AC, which authorized the temporary installation of 23 portable combustion turbine

- generator sets (EU

- 008 through EU

- 030) rated at approximately 5.5 MW (each) of output. The purpose of the project was to ensure reliable power during the temporary period that Combined Cycle Unit 8 at the City of Tallahasse e’s Purdom Plant was being repaired and returned to service. These units have been removed from the site and are no longer authorized to operate. } This permit authorizes shutdown of the Unit 2 boiler and the re

- powering of the Unit 2 steam turbine

- electri cal generator by installing the following equipment.

ID Emission Unit Description
033 General Electric 7FA Combined Cycle Combustion Turbine to r e-p ower Unit 2
Due to the shutdown of the Unit 2 boiler, the project avoids PSD preconstruction review for all pollutants

.
REGULATORY CLASSIFIC ATION
Title III : The facility is a potential major source of hazardous air pollutants (HAP). Title IV : The f acility operates existing units subject to the Acid Rain provisions of the Clean Air Act. Title V : The facility is a Title V major source of air pollution in accordance with Chapter 213, F.A.C. PSD : The facility is a PSD

- major facility in accordance with Rule 62

- 212.400, F.A.C. NSPS : The facility will operate u nits subject to New Source Performance Standards in 4 0 CFR 60. NEHSAP

RELEVANT DOCUMENTS : The facility will operate units subject to National Emissions Standards for HAPs in 40 CFR 63.

The following relevant documents are not a part of this permit, but helped form the basis for this permitting action: the permit application and additional information received to make it complete; the draft permit package including the Department’s Technical Evaluation and Preliminary Determination; publication and comments; and the Department’s Final Determination.1. Permitt ing Authority

2. : All documents related to applications for permits to construct
, modify , or operate emissions units at this facility shall be submitted to the Bureau of Air Regulation of the Florida Department of Environmental Protection (DEP) at 2600 Blair Stone Road (MS #5505), Tallahassee, Florida 32399

- 2400. Copies of all such related documents shall also be submitted to the Compliance Authority

. Compliance Authority

3. : All documents related to compliance activities such as reports, tests, and notifications shall be submitted to the Air Resource Section of the Department’s Northwest District Office at 160 Governmental Center, Suite 308, Pensacola, Florida 32502

- 5794

. Appendices

4. : The following Appendices are attached as part of this permit: Appendix A (Citation Format); Appendix B (General Conditions); and Appendix C ( Common Conditions) ; Appendix D (NSPS Subpart KKKK Provisions - Combustion Turbines and Duct Burners ); Appendix E (NESHAP Subpart YYYY Provisions – Combustion Turbines ) ; and Appendix F (Emi ssions Summary)

. Applicable Regulations, Forms and Application Procedures

5. : Unless otherwise indicated in this permit, the construction and operation of the subject emissions unit shall be in general accordance with the capacities and specifications stated in the application. The facility is subject to all applicable provisions of: Chapter 403 of the Florida Statutes (F.S.); Chapters 62

- 4, 62

- 204, 62

- 210, 62

- 212, 62

- 213, 62

- 296, and 62

- 297 of the Florida Administrative Code (F.A.C.); and Title 40, Part s 60 and 63 of the Code of Federal Regulations (CFR), adopted by reference in Rule 62

- 204.800, F.A.C. The terms used in this permit have specific meanings as defined in the applicable chapters of the Florida Administrative Code. The permittee shall use the a pplicable forms listed in Rule 62

- 210.900, F.A.C. and follow the application procedures in Chapter 62

- 4, F.A.C. Issuance of this permit does not relieve the permittee from compliance with any applicable federal, state, or local permitting or regulations. [Rules 62

- 204.800, 62

- 210.300 and 62

- 210.900, F.A.C.]
New or Additional Conditions

6. : For good cause shown and after notice and an administrative hearing, if requested, the Department may require the permittee to conform to new or additional conditions. The Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and on application of the permittee, the Department may grant additional time. [Rule 62

- 4.080, F.A.C.]
Modifications

7. : The permittee shall notify the Compliance Authority upon commencement of construction. No emissions unit or facility subject to this permit shall be constructed or modified without obtaining an air construction permit from the Department. Such permit shall be obtained prior to beginn ing construction or modification. [Rules 62

- 210.300(1) and 62

- 212.300(1)(a), F.A.C.] Source Obligation

8. : At such time that a particular source or modification becomes a major stationary source or major modification (as these terms were defined at the time the source obtained the enforceable limitation) solely by virtue of a relaxation in any enforceable limitation which was established after August 7, 1980, on the capacity of the source or modification otherwise to emit a pollutant, such as a restriction o n hours of operation, then the requirements of subsections 62

- 212.400(4) through (12), F.A.C., shall apply to the source or modification as though construction had not yet commenced on the source or modification. [Rule 62

- 212.400(12)(b), F.A.C.]
Title IV Permit

9. : At least 24 months before the date on which the new unit begins serving an electrical generator greater than 25 MW, the permittee shall submit an application for a Title IV Acid Rain Permit to the Department’s Bureau of Air Regulation in Tallahass ee and a copy to the Region 4 Office of the U.S. Environmental Protection Agency in Atlanta, Georgia. This permit does not specify the Acid Rain program requirements. These will be included in the Title V air operation permit. [40 CFR 72]
Title V Permit

10. : This permit authorizes construction of the permitted emissions units and initial operation to determine compliance with Department rules. A Title V operation permit is required for regular operation of the permitted emissions unit. The permittee shall apply for a Title V operation permit at least 90 days prior to expiration of this permit, but no later than 180 days after commencing operation. To apply for a Title V operation permit, the applicant shall submit the appropriate application form, complia nce test results, and such additional information as the Department may by law require. The application shall be submitted to the appropriate Permitting Authority with copies to the Compliance Authority. [Rules 62

- 4.030, 62

- 4.050, 62

- 4.220, and Chapter 6 2- 213, F.A.C.] Annual Operating Report : The permittee shall submit an annual report that summarizes the actual operating hours and emissions from this facility. Annual operating reports shall be submitted to the Compliance Authority by March 1st of each year. [Rule 62

- 210.370(3), F.A.C.]This section of the permit addresses the following emissions unit.

Emissions Unit No. 033

- General Electric 7FA Combined Cycle Unit

The unit consists of a General Electric 7FA combustion turbine , automated combustion turbine control system, a heat recovery steam generator (HRSG), a gas

- fired duct burner system , a HR S G stack, a bypass stack, and CO and NOx CEMS

. The combustion turbine will produce a nominal 188 MW and the HRSG will be used to re

- power the existing Unit 2 steam turbine

- electrical generator to produce a nominal 238 MW. In the combustion turbine , n atural gas will be fired as the primary fuel and distillate oil will be fired as a restricted alternative fuel from on site storage tanks. Based on the higher heating value of each fuel and a compressor inlet temperature of 2 5° F, the design maximum heat input rates are 1899 MMB tu per hour for gas firing and 2079 MMBtu per hour for oil firing. Natural gas will be the sole fuel for the duct burner system rated a t a maximum heat input rate of 7 65 MMBtu per hour. Nitrogen oxide emissions will be controlled by a selective catalytic reduction (SCR) system plus the dry low

- NOx (DLN) combustion system when firing natural gas and water injection when firing distillate o il. Emissions of carbon monoxide and volatile organic compounds will be minimized by the firing of clean fuels and the high combustion temperatures of the combustion turbine . Emissions of particulate matter will be minimized by the large inlet air filtra tion system and the efficient combustion of the proposed fuels. Emiss ions of sulfuric acid mist and sulfur dioxide will be minimized by the firing of natural gas as the primary fuel and the restricted firing of distillate oil ( ≤ 0.05% sulfur by weight) as a backup fuel. When firing natural gas and duct firing, exhaust gas a t 188° F will leave the HRSG and exit a stack that is 18 feet in diameter and 150 feet tall with a volumetric flow rate of approximately 1,0 16,100 acfm. When firing distillate oil and duct firing, exhaust gas at 204 ° F will leave the HRSG and exit a stack that is 18 feet in diameter and 150 feet tall with a volumetric flow rate of approximately 1,090,210 acfm. When operating in simple cycle mode with the blanking plate installed, ex haust gas at 1114 ° F will exit an emergency bypass stack that is also 18 f eet in diameter and 150 feet tall with a volumetric flow rate of approximately 2,433,700 acfm. Temperatures and gas flows assume a compressor inlet temperature of 59° F.

EQUIPMENT

1. Unit 2 Boiler – Shutdown

2. : Prior to commencing commercial operation of the new combined cycle combustion turbine
, t he permittee shall permanently shutdown and render incapable of operation the existing Unit 2 boiler

. [Application No. 0730003

- 009

- AC; Rule 62

- 212.400(12), F.A.C.] New Combined Cycle Unit

a. Combustion Turbine : The permittee is authorized to install, tune, operate, and maintain the following equipment: a General Electric 7FA combustion turbine

- electrical generator set (Model 7241 or equivalent ) ; an inlet air filtration system; a n automated combustion turbine control system ( Mark VI or equivalent) , a heat recovery steam generator (HRSG); a gas

- fired duct burner system; a HRSG stack; a bypass stack; and CO and NOx CEMS. The combustion turbine will produce a nominal 188 MW when firing natural gas with a heat input rate of 1899 MMBtu per hour. :

b. HRSG : The permittee is authorized to install, operate, and maintain a new heat recovery steam generator (HRSG) designed to recover heat energy from the combustion turbine and deliver steam to the existing Unit 2 steam turbine

- elec trical generator set

. The HRSG will be equipped with supplemental gas

- fired duct burner

s ystem having a maximum heat input rate of 7 65 MMBtu per hour ( H HV).
[ Application No. 0730003

- 009

- AC; Design]

3. Fuel Tanks

AIR POLLUTION CONTROL SY STEMS : The existing plant includes two 10,000 bbl diesel storage tanks, a 55,000 bbl No. 6 oil storage tank, and a 180,000 bbl No. 6 oil storage tank. As part of the project, the permittee is authorized to convert the 180,000 bbl No. 6 oil storage tank to store diesel (distillate oil). The converted tank and the two existing diesel tanks will supply the new combined cycle combustion turbine . [Application No. 0730003

- 009

- AC]

4. DLN Combustion : The permittee shall operate and maintain the General Electric DLN 2.6 combustion syst em (orbetter) to control NO X

5. emissions from the combustion turbine when firing natural gas. Prior to the initial emissions performance tests required for the combustion turbine , the DLN combustors and automated combustion turbine control system shall be tuned without the SCR in operation to achieve the permitted CO and NOx levels for simple cycle HRSG/SCR bypass operation . Thereafter, the system shall be maintained and tuned in accordance with the manufacturer’s recommendations or industry standards . [A pplication No. 0730003

- 009

- AC; Design] Water Injection Technology

6. : The permittee shall install, operate, and maintain a water injection system to reduce NOx emissions when firing distillate oil. Prior to the initial emissions perfo rmance tests, the water injection system shall be tuned without the SCR in operation to achieve a target NOx level of 42 ppmvd @ 15% oxygen , which represents the vendor’s specification for oil firing

. Thereafter, the system shall be maintained and tuned in accordance with the

m anufacturer’s recommendations or industry standards

. [Application No. 0730003

- 009

- AC; Design] SCR System

7. : The permittee shall install, operate, and maintain a selective catalytic reduction (SCR) system to control NOx emissions from the combustion turbine when firing either natural gas or distillate oil during combined cycle operation (including periods when steam is dumped to a condenser). The SCR system consists of an ammonia injection grid, catalyst, ammonia storage, monitoring and control system, electrical, piping and other ancillary equipment. The SCR system shall be designed, constructed and operated to achieve the permitted levels for NOx emissions . The SCR system shall be designed to achieve an ammonia slip level of 5 ppmv d @ 15% oxygen

. {Permi tting Note: In accordance with 40 CFR 60.130, the storage of ammonia shall comply with all applicable requirements of the Chemical Accident Prevention Provisions in 40 CFR 68.}
Circumvention

PERFORMANCE RESTRICT I ONS : The permittee shall not circumvent the air pollution control e quipment or allow the emission of air pollutants without this equipment operating properly. The SCR system is not required to be in operation when the unit is operating in simple cycle HRSG/SCR bypass mode. [Rule 62

- 210.650, F.A.C.]

8. Authorized Fuels

9. : The combustion turbine shall fire only natural gas and distillate oil . The maximum sulfur content of distillate oil shall not exceed 0.05% by weight. The duct burner system shall fire only natural gas. [ Application No. 0730003

- 009

- AC ; Rule 62

- 210.200(PTE), F.A.C.]

a. Combustion T urbine : T he design maximum heat input rates are 1899 MMB tu per hour for gas firing and 20 79 MMBtu per hour for oil firing based on the higher heating value of each fuel, a compressor inlet temperature of 2 5° F, and full load operation

. Heat input rates will vary depending upon combustion turbine characteristics, ambient conditions, alternate methods of operation, and evaporative cooling. The permittee shall provide manufacturer’s perfor mance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. Operating data may be adjusted for the appropriate site conditions in accordance with th e performance curves and/or equations on file with the Department. Permitted Capacities:

b. Duct Burner : The design maximum heat input rate to the duct burner system is 765 MMBtu per hour. [Rule 62

- 210.200(PTE), F.A.C.]

10. Restricted Operation

a. The hours of operation of the combusti on turbine are not limited (8760 hours per year). :

b. Distillate oil firing in the combustion turbine shall not exceed 6,926,500 MMBtu during any consecutive 12 months (equivalent to 3500 hours of full load oil firing).

c. The duct burner shall fire no more than 2,598,800 MMBtu of natural gas during any consecutive 12 months (equivalent to 3 650 hours of full load duct firing).
[ Application No. 0730003

- 009

- AC; Rule 62

- 210.200(PTE), F.A.C.]

11. Authorized Methods of Operation

a. Combined Cycle Operation : When operating a s a combined cycle unit, t he combustion turbine is authorized to fire :natural gas or distillate oil and operate the gas

- fired duct burners. For this permit, “combined cycle” shall mean operation of the combustion turbine during which heat is recovered fro m the combustion turbine exhaust in the HRSG to generate steam. This includes operation when the HRSG and SCR system are functioning, but the steam produced is dumped to a condenser

. b. Simple Cycle HRSG/SCR Bypass Operation : The combustion turbine shall fi re only natural gas with no duct firing when operating as a simple cycle unit with the exhaust bypassing the HRSG and SCR system. To operate in this manner, the unit must be cooled and a blanking plate installed to direct exhaust gases to the bypass stack . This method of operation will be an infrequent occurrence, most likely due to problems or maintenance of the HRSG
, SCR system or steam turbine

- electrical generator system

. [Application No. 0730003

- 009

- AC]
EMISSIONS STANDARDS

12. Emissions Standards

Pollutant : Emissi ons from the combined cycle unit shall not exceed the following standards.

Fuel Operating Method Emission

a Standard ppmvd @ 15% O 2 Equivalent lb/hour Averaging Period b Compliance Method

CO Gas

c C ombined Cycle 16.8 96.8 30

- day rolling avg. CO CEMS
SC / Bypass 10.0 41.7 4

- hour test avg. EPA Method 10 e
Oil Combined Cycle 21.4 142.9 30

- day rolling avg. CO CEMS
All Fuels All methods 340.10 tons

--- 12

- month rolling total CO CEMS

NOx Gas d Combined Cycle 5.0 47.8 30

- day rolling avg. NOx CE MS c SC/Bypass 9.0 61.8 4

- hour test avg. EPA Method 7E e
Oil Combined Cycle 10.0 108.4 30

- day rolling avg. NOx CEMS c Opacity All Fuels All Methods 10 % Opacity 6

- minute block avg. EPA Method 9

a. “SC/ Bypass” means operation as a simple cycle unit with t he blanking plate installed to bypass the HRSG and SCR system and exhaust directly to the bypass stack.
b. Mass emissions rate s represent the maximum equivalent “lb/hour” for the highest emitting method of operation, which includes duct firing for most cases

. Mass emissions rates are based on a compressor inlet temperature of 25° F and the higher heating value of each fuel. Maximum mass emission rates will vary based on the actual test conditions in accordance with the performance curves and/or equations. F or the combustion turbine, it is not necessary to continuously report hourly mass emissions rates with the CEMS data. See Appendix F for a summary of equivalent mass emissions rates.

c. To determine compliance with the emissions standards based on a 30

- day r olling average, each fuel will have a separate 30

- day rolling emissions standard based on CEMS data. To determine compliance with the CO emissions cap based on a 12

- month rolling total, the mass emissions rate shall be determined from all valid hourly emi ssions data including periods such as startup, shutdown, malfunction
, fuel switching, and tuning. Mass emissions may be determined from the CEMS data by using the appropriate F

- Factor for each fuel.
d. To determine compliance with the NOx emissions standards based on a 30

- day rolling average
, each fuel will have a separate 30

- day rolling emissions standard based on NOx CEMS data.

e. In addition to the m ethods specified above, data gathered by the CO CEMS and NOx CEMS may be used to demonstrate compliance in acco rdance with Conditions 26 and 27 in this section. {Permitting Note: P otential annual emissions from the combustion turbine system are : 340 tons/year of CO, 332
tons /year of NOx, 112 tons/year of PM/PM 10

, 212 tons/year of SO 2 , 40 tons/year of SAM, and 47 tons/year of VOC.Note that the project requires the shutdown of the existing Unit 2 boiler, which provided emissions decreases and allowed th e project to avoid PSD preconstruction review. Potential annual emissions are based on: the permitted emissions standards; the operational restrictions in the permit; a maximum heat input rate from firing natural gas of 1795 MMBtu per hour at compressor inlet temperature of 59° F; and a maximum heat input rate from firing distillate oil of 1979 MMBtu per hour at compressor inlet temperature of 59° F. } [Application No. 0730003

- 009

- AC; Rule 62

- 4.070(3), F.A.C; Rule 62

- 212.400(12)(Source Obligation), F.A.C. for the CO E missions Cap]

13. Ammonia Slip

a. Begin testing and reporting the ammonia slip for each subsequent calendar quarter; : The SCR system shall be designed to achieve a maximum ammonia slip of 5 ppmvd @ 15% oxygen. Actual ammonia slip levels shall not exceed 10 ppmvd @ 15% oxygen as determined by EPA Method CTM

- 027 based on the average of three test runs. I f tests indicate an ammonia slip level greater than 5 ppmvd @ 15% oxygen, the permittee shall:

b. Before the ammonia slip exceeds 10 ppmvd corrected to 15% oxygen, take correct ive actions that result in lowering the ammonia slip to less than 5 ppmvd corrected to 15% oxygen; and

c. Test and demonstrate that the ammonia slip is less than 5 ppmvd corrected to 15% oxygen within 4 5 days after completing the corrective actions.
Correctiv e actions may include, but are not limited to, adding catalyst, replacing catalyst, or other SCR system maintenance or repair. After demonstrating that the ammonia slip level is less than 5 ppmvd corrected to 15% oxygen, testing and reporting shall resume on an annual basis. [Rules 62

- 4.070(3) and 62

- 297.310(7)(b), F.A.C.]

14. Applicable NSPS Provisions

a. Pursuant to §60.4320 and Table 1 , the NSPS Subpart KKKK NOx standard for gas firi ng is 15 ppmvd @ 15% oxygen based on a 30

- day rolling average for combined cycle operation and 15 ppmvd @ 15% oxygen based on a 4

- hour rolling average for simple cycle HRSG/SCR bypass operation. : In addition to the above standards , the combustion turbine system shall be designed, operated, and maintained to achieve the following federal New Source Performance Standards (NSPS) in 40 CFR 60 : Subpart A ( General Provisions ) and Subpart KKKK (New C ombustion T urbines and D uct B urners ). In summary the emissions standards are:

b. Pursuant to §60.4320 and Table 1 , the NSPS Subpart KKKK NOx s tandard for oil firing is 42 ppmvd @ 15% oxygen based on a 30

- day rolling average for combined cycle operation.

c. Pursuant to §60.4330(a)(2), SO 2 emissions are limited in NSPS Subpart KKKK by a prohibition on the firing of any fuels that contain total potential sulfur emissions in excess of 0.060 lb SO 2 See Appendix D of this permit for the full NSPS requirements. [4 0 CFR 60, Subparts A and KKKK] /MMBtu heat input.

15. Applicable N ES HAP Provisions

EXCESS EMISSIONS : In addition to the above standards
, the combustion turbine syste m shall be designed, operated, and maintained to achieve the following federal National Emissions Standards for Hazardous Air Pollutants (NEHSAP) in 40 CFR 63 : Subpart A ( General Provisions ) and Subpart YYYY (Combustion Turbines). {Permitting Note: On August 18, 2004, EPA stayed the effectiveness of NESHAP Subpart YYYY for lean premix and diffusion flame combustion turbines. When the stay is lifted, the regulation may be revised. It is uncertain at this time whether or not the combustion turbine will b e subject to a formaldehyde limit with emissions testing or an oxidation catalyst will be required or some other set of requirements. } [40 CFR 63, Subparts A and YYYY]

{Permitting Note: The following conditions apply only to the SIP

- base d emissions s tandards specified in Condition 12 of this section. Rule 62

- 210.700, F.A.C. (Excess Emissions) cannot vary or supersede any federal NSPS, NESHAP, or Acid Rain provision.}

16. Excess Emissions Prohibited : Excess emissions caused entirely or in part by poor maintenance, poor operation or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction shall be prohibited. All such preventable emissions shall be included in any compliance determinations based on CEMS data. [Rule 62

- 210.700(4), F.A.C.]17. Definitions

a. Startup is defined as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution control device imbalances, which result in excess emissions. : Rule 62

- 210.200(Definitions), F.A.C. defines the following terms.

b. Shutdown is the cessation of the operation of an emissions unit for any purpos e.

c. Malfunction is defined as any unavoidable mechanical and/or electrical failure of air pollution control equipment or process equipment or of a process resulting in operation in an abnormal or unusual manner.

18. Excess Emissions Allowed

a. Startup : : As specified in this condition, excess emissions resulting from startup, shutdown, malfunction, fuel switches
, and DLN / SCR/WI t uning are allowed provided that operators employ the best operational practices to minimize the amount and duration of emissions during such events

. For excess emissions events that last less than the maximum dur ation allowed, only those minutes attributable to excess emissions from the event shall be excluded. When authorized, excess emissions data shall be e xcluded from a compliance determination as a continuous block attributed to the event.

1) Steam Turbine Generator Cold Startu p: No more than the first 600 minutes of CEMS data shall be excluded due to excess emissions from a steam turbine generator cold startup. A “steam turbine generat or cold startup” is defined as startup after the steam turbine generator has been offline for 24 hours or more
, or the first stage turbine metal temperature is 250oF or less. 2) Steam Turbine Generator Warm Startup: No more than the first 300 minutes of CEMS data shall be excluded due to excess emissions from a steam turbine generator warm startup. A “steam turbine generator warm startup” is defined as startup to combined cycle operation when the gas turbine has been shut down for a period of time and the fi rst stage steam turbine metal temperature is greater than 250 o
3) Steam Turbine Generator Hot Startup: No more than the first 240 minutes of CEMS data shall be excluded due to excess emissions from a steam turbine generator hot startup. A “steam turbine g enerator hot startup” is defined as start up of the steam turbine generator while the unit has been operating in the combined cycle mode with the steam being dumped to the condenser. F.

4) Simple Cycle HRSG/SCR Bypass Startup: No more than the first 30 minutes o f CEMS data shall be excluded due to excess emissions from a simple cycle gas turbine startup in which exhaust is directed to the HRSG/SCR bypass stack.
b. Shutdown : No more than the first 30 minutes of CEMS data shall be excluded due to excess emissions fro m a combustion turbine shutdown. For shutdowns of less than 30 minutes in duration, only those minutes attributable to excess emissions from shutdown shall be excluded.

c. Malfunction : No more than 120 minutes of CEMS data shall be excluded in a 24

- hour per iod due to excess emissions from malfunction. Within one (1) working day of occurrence, the owner or operator shall notify the Compliance Authority of any malfunction resulting in the exclusion of CEMS data.
d. Fuel Switch : No more than the first 30 minutes of CEMS data shall be excluded due to excess emissions from a fuel switch. For fuel switches less than 30 minutes in duration, only those minutes attributable to excess emissions from fuel switching shall be excluded.

e. DLN/SCR/ WI Tuning : No more than 72 hours of CEMS data during any consecutive 12 months shall be excluded from the CEMS compliance demonstration due to excess emissions from the necessary tuning of the dry low

- NOx ( DLN ) combustion system , the selective catalytic reduction (SCR) system, or th e water injection (WI) system

. Tuning sessions shall be performed in accordance with the manufacturer’s recommendations or industry standards. Prior to performing any DLN , SCR, or WI tuning session, the permittee shall provide the Compliance Authority wi th an advance notice (telephone, facsimile transmittal, or electronic mail) that details the activity and proposed tuning schedule. {Permitting Note: DLN tuning sessions are typically required after completion of initial construction, a combustor change

- out, a major repair, a unit overhaul, maintenance to a combustor, or other similar circumstances. During DLN or water injection tuning, the SCR system is turned off and the combustionturbine is sequentially stepped through numerous loads (including low load levels) to gather actual emissions data and operational information for use in adjusting the combustion turbine and control system.} CEMS data shall only be excluded in accordance with the procedures described in the Condition 21 of this section (CEMS Data Requirements). As authorized by Rule 62

- 210.700(5), F.A.C., the above conditions allow excess emissions only for the specifically defined periods. Data exclusion does not apply to the CO emissions cap based on a 12

- month rolling total. [Application No. 0730003

- 009

- AC; Design; Rule 62

- 210.700(5), F.A.C.]
19. Alternate Visible Emissions Standard:

CONTINUOUS EMISSIONS MONITORING SYSTEM (CEMS) REQUIREMENTS Visible emissions due to startup shall not exceed 10% opacity except for up to ten, 6

- minute averaging perio ds during a calendar day, which shall not exceed 20% opacity. [Rule 62

- 210.700(5), F.A.C.]

20. CEMS

a. CO Monitor: The CO monitor shall be certified pursuant to 40 CFR 60, Appendix B, Performance S pecification 4 or 4A. Quality assurance procedures shall conform to the requirements of 40 CFR 60, Appendix F. The annual and required RATA tests shall be performed using EPA Method 10 in Appendix A of 40 CFR 60 and shall be based on a continuous samplin g train. The CO monitor span values shall be set appropriately, considering the allowable methods of operation and corresponding emission standards.

: The permittee shall install, calibrate, maintain, and operate continuous emission monitoring syste ms (CEMS) to measure and record the emissions of CO and NO x from the combustion turbine HRSG exhaust stack in a manner sufficient to demonstrate continuous compliance with the CEMS

- based emission standards of this section. Within 60 days of achieving perm itted capacity, but no later than 180 days after first fire, a ll continuous emissions monitoring systems shall be installed
, certified and functioning properly

.

b. NO x Monitor: The NO x monitor shall be certified pursuant to the specifications of 40 CFR 75. Quality ass urance procedures shall conform to the requirements of 40 CFR 75. The annual and required RATA tests required for the NO X

c. Diluent Monitor: The oxygen (O monitor shall be performed using EPA Method 20 or 7E in Appendix A of 40 CFR 60.

2 ) or carbon dioxide (CO 2 ) content of the flue gas shall be monitored at the location where CO and NO x are monitored to correct the measured emissions rates to 15% oxygen. If a CO 2

[Rules 62

- 4.070(3), 62

- 210.800, and 62

- 297.520, F.A.C.] monitor is installed, the oxygen content of the flue gas shall be calculated using F

- factors th at are appropriate for the fuel fired. The monitor shall comply with the performance and quality assurance requirements of 40 CFR 75.

21. CEMS Data Requirements

a. Valid Hourly Averages for Compliance: Each CEMS shall be designed and operated to sample, analyze, and record data evenly spaced over the hour at a minimum of one measurement per minute. Except for a llowable emissions data exclusions, a ll valid measurements collected during an hour shall be used to calculate a 1

- hour block average that begins at the top of each hour. Each 1

- hour block average shall be computed using at least one data point in each fi fteen

- minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, a 1

- hour average shall be computed from at least two data points separated by a minimum of 15 minutes (where the unit operat es for more than one quadrant of an hour). If less than two such data points are available, there is insufficient data and the 1

- hour block average is not valid. Also, if an allowable exclusion episode should occur over two separate hourly averages, only those minutes attributed to the specific episode shall be excluded from each hour. : The CEMS shall be installed, calibrate d, maintained, and operated in the combustion turbine exhaust stacks to measure and record the emissions of CO, and NOx in a manner sufficient to demonstrate compliance with the CEMS

- based emission limits standards of this section. The CEMS shall express the results in units of ppmvd corrected to 15% oxygen.

b. 30

- day Rolling Averages : A 30

- day rolling average shall be calculated from all valid hourly average s collected during the given operating day and the previous 29 operating days. For purposes of determining compliance with the 30

- day rolling NOx s tandard, the missing data substitution methodology of 40 CFR Part 75, Subpart D, shall not be utilized. Instead, the 30

- day rolling average shall be determined using the remaining hourly data and periods of missing CEMS data are to be reported as monitor downtime in the excess emissions and monitoring performance reports. {Permitting Note: Condition 22 defines the use of “maximum per mitted emission levels” foruse when the combustion turbine operates in simple cycle mode.}

c. 12

- Month Rolling Total : By the end of each month, the CO CEMS shall also determine a 12

- month rolling total of CO emissions from the combustion turbine. The 12

- mo nth rolling total shall be based on all valid CO CEMS data collected ( including startu ps, shutdowns, and malfunctions) for the given month and the previous 11 months.
d. Data Exclusion : E xcept for monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, e ach CEMS shall monitor and record emissions during all operations including episodes of startups, shutdowns, malfunctions, and DLN tuning. Limited amounts of CEMS emissions data recorded during some of these episodes may be e xcluded from the corresponding compliance demonstration subject to the provisions of Condition 18 in this section. The permittee shall minimize the duration of data excluded for such episodes to the extent practicable.

e. Mo nitor Availability . Monitor availability for each CEMS used to demonstrate compliance shall be 95% or greater in any calendar quarter. Monitor availability shall be calculated consistent with Subpart KKKK in 40 CFR 60 and reported in the SIP and NSPS exc ess emissions reports required in Condition 36 . In the event that 95% availability is not achieved, the permittee shall provide the Department with a report identifying the problems in achieving 95% availability a nd a plan of corrective actions that will be taken to achieve 95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective actions or continued failure to achieve the minimum monitor availability shall be violations of this permit, except as otherwise authorized by the Compliance Authority. [Rules 62

- 4.070(3) and 62

- 212.400(12) , F.A.C. ; 40 CFR 75 ]

22. Simple Cycle HRSG/SCR Bypass Operation

a. Compliance with the NOx and CO emission standard s for the simple cycle HRSG/SCR bypass mode of operation shall be demonstrated by conducting initial and annual tests as required by Condition : Because the bypass stack will only be u sed in emergency situations where the HRSG
, SCR and/or steam turbine

- generator are unavailable, the permittee is not required to install CO / NOx CEMS or permanent test ports on the bypass stack. When an emergency situation occurs , the permittee shall ensur e that the unit is firing only natural gas and is properly operating with lean premix combustion (Mode 6). The permittee shall monitor the hours of operation in simple cycle HRSG/SCR bypass mode and use the following methods to determine CO and NOx emissi ons.

26 of this secti on.
b. Compliance with the 1 2- month rolling CO emissions cap, the maximum CO mass emission rate of 41.7 lb/hour shall be used to represent each hour of operation in this mode. If the unit operates in simple cycle mode for a substantial period of time, the Compliance Authority may request additional CO and NOx testing to demonstrate compliance with the standards. [Rule s 62

- 4.070(3) and 62

- 297.310(7)(b) , F.A.C.] {Permitting Note: Th e above sampling method is similar to the method allowed under the Acid Rain pr ogram for bypass stack situations as described in 40 CFR 75.17(d)(2).}

23. Ammonia Monitoring Requirements

EMISSIONS PERFORMANC E TESTING : In accordance with the manufacturer’s specifications, the permittee shall install, calibrate, operate and maintain an ammonia flow meter to measure and record the ammonia injection rate to the SCR system. The permittee shall document the general range of ammonia flow rates required to meet permitted emissions levels over the range of load conditions allowed by this permit by comparing NOx emissions reco rded by the CEM system with ammonia flow rates recorded using the ammonia flow meter. During NOx monitor downtimes or malfunctions, the permittee shall operate at the ammonia flow rate that is consistent with the documented flow rate for the combustion tu rbine load condition. [Rules 62

- 4.070(3), F.A.C.]

24. Continuous Compliance

30 : Continuous compliance with the CO and NOx emissions standards shall be demonstrated with data collected from the required continuous emissions monitoring systems (CEMS). The permittee shall submit an initial compliance report in accordance with Condition of this section. [Rules 62

- 4.070(3) and 62

- 297.310(7)(a) and (b), F.A.C.]

25. Operational Rate During Testing : Initial and subsequent performance tests shall be conducted between 90% and 100%of permitted capacity for the given compressor inlet conditions in accordance with the requirements of Rule 62

- 297.310(2), F.A.C. [Rule 62

- 297.310(7)(a) and (b), F.A.C.; 40 CFR 60.8]

26. Initial Compliance Tests

a. T he HRSG stack shall be tested on each authorized fuel in combined cycle mode to demonstrate compliance with the standards for ammonia slip and visible emissions. For each required test, emissions of CO and NOx recorded by the CEMS shall also be reported. : In accordance with the test methods specified in this section, i nitial compliance tests shall be conducted within 60 days after achieving the maximum production rate at which the units will be operated, but not later than 180 days after the initial startup.

b. T he simple cycle HRSG /SCR bypass operation shall be tested when firing natural gas in simple cycle mode to demonstrate compliance with the permitted CO and NOx emissions standards. For this method of operat ion, tests may be conducted by taking the SCR system out of service and sampling at the HRSG stack

. In addition, the installed and certified CO and NOx CEMS may be used to provide the compliance test data. These tests shall consist of at least four, 1

- ho ur test runs to determine the 4

- hour average. [Rule s 62

- 4.070(3) and 62

- 297.310(7)(a) and (b), F.A.C.; 40 CFR 60.8]

27. Annual Compliance Testing : During each federal fiscal year (October 1 st to September 30 th

a. The HRSG stack shall be tested on natural gas in combined cycle mode to demonstrate compliance with the standards for ammonia slip and visible emissions. For each required test, emissions of CO and NOx recorded by the CEMS shall also be reported. If distillate oil is fired for more than 400 hours during the federal fiscal year, the HRSG stack shall also be tested on oil in combined cycle mode to demonstrate compliance with the standards for ammonia slip and visible emissions. ), annual compliance tests shall be conducted in a ccordance with the test method specified in this section

.

b. The simple cycle HRSG/SCR bypass operation shall be tested when firing natural gas in simple cycle mode to demonstrate compliance with the permitted CO and NOx emissions standards. For this method of operation, tests may be co nducted by taking the SCR system out of service and sampling at the HRSG stack. In addition, the installed and certified CO and NOx CEMS may be used to provide the compliance test data. These tests shall consist of at least four, 1

- hour test runs to determine the 4

- hour average. [Rules 62

- 4.070(3) and 62

- 297.310(7)(a) and (b), F.A.C.; 40 CFR 60.8]

28. Test Notification

29. : The permittee shall notify the Compliance Authority in writing at least 15 days prior to any required tests. [Rule 62

- 297.310(7)(a)9, F.A.C .]
Test Methods

Method : Any required stack tests shall be performed in accordance with the following methods.
Description of Method and Comments
CTM

- 027 Procedure for Collection and Analysis of Ammonia in Stationary Source
7E Determination of Nitrogen O xide Emissions from Stationary Sources (Instrumental)
9 Visual Determination of the Opacity of Emissions from Stationary Sources
10 Determination of Carbon Monoxide Emissions from Stationary Sources
20 Determination of Nitrogen Oxides, Sulfur Dioxide an d Diluent Emissions from Stationary Gas Turbine s The methods are described in 40 CFR 60, Appendix A, and adopted by reference in Rule 62

- 204.800, F.A.C. No other methods may be used for compliance testing unless prior written approval is received from the Department. Tests shall be conducted in accordance with the appropriate test method, the applicable requirements specified in Appendix C of this permit, and the applicable NSPS and NESHAP in 40 CFR Parts 60 and 63, respectively . [Rules 62

- 204.800 and 62- 297.100, F.A.C.; 40 CFR Parts 60 and 63 ]
REPORTING AND RECORD KEEPING REQUIREMENTS

30. CEMS Report - Initial Operation : For the first two calendar quarters of operation, t he permittee shall submit a report summarizing the CO and NOx emissions as determined by CEMS data. Emissions rates shall be reported in terms ofppmvd @ 15% oxygen for the 30

- day rolling averages. CO emissions shall also be reported in “tons per month ”

. Reports shall be submitted within 30 days of each calendar quarter. [Rule 62

- 4.070( 3), F.A.C.]

31. Monitoring of Capacity

32. : The permittee shall monitor and record the operating rate of the combustion turbine on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown, malfu nction, and DLN tuning). This shall be achieved through monitoring daily rates of consumption and heat content of each allowable fuel in accordance with the provisions of 40 CFR 75 Appendix D, and recording the data using a monitoring component of the CEM S system required above. [Rule 62

- 4.070(3), F.A.C.; 40 CFR 75 ] Monthly Operations Summary

33. : By the fifth calendar day of each month, the permittee shall record the following for each fuel in a written or electronic log for the previous month and the previ ous consecutive 12 months: total heat input
rate to the combustion turbine from each fuel (MMBtu); the total heat input rate to the duct burner (MMBtu) ; and the 12

- month rolling total of CO emissions (tons) . Information recorded and stored as an electron ic file shall be available for inspection and printing within at least three days of a request by the Department. F uel consumption shall be monitored in accordance with the provisions of 40 CFR 75 Appendix D. [Rules 62

- 4.070(3), F.A.C.]
Fuel Sulfur Recor ds

34. : The sulfur content of the distillate oil shall be determined by ASTM Methods D

- 129, D

- 1552, D

2622, D

- 4294, or equivalent methods approved by the Department. For each fuel oil delivery, the permittee shall record and retain the following information: the date; gallons delivered; and a fuel oil analysis including the heat content in MMBtu/gallon, the density in pounds/gallon, the sulfur content in percent by weight, and the name of the test method used. A certified analysis supplied by the fuel oil v endor is acceptable. Alternatively, the monitoring methods specified in § 60.4370 are sufficient to demonstrate compliance with the maximum fuel sulfur levels for distillate oil established in this permit. [Rule 62

- 4.070(3), F.A.C.; 40 CFR 60.4370 ]
Stack Test Reports

35. : The owner or operator of an emissions unit for which a compliance test is required shall file a report with the Compliance Authority on the results of each such test. The required test report shall be filed with the Compliance Authority as soon as practical but no later than 45 days after the last sampling run of each test is completed. The test report shall provide sufficient detail on the emissions unit tested and the test procedures used to allow the Compliance Authority to determine if the test was properly conducted and the test results properly computed. As a minimum, the test report shall provide the applicable information specified in Rule 62

- 297.310(8), F.A.C. and summarized in Appendix C. [Rule 62

- 297.310(8), F.A.C.]

CEMS RATA R eports

36. : At least 15 days prior to conducting any Relative Accuracy Test Assessments (RATA) on a CEMS, the permittee shall notify the Compliance Authority of the schedule (letter, email, fax, or phone call). In addition to filing reports with the Departme nt’s Bureau of Air Monitoring and Mobile Sources, a summary of the RATA reports shall be submitted to the Compliance Authority within 45 days of completing the RATA. [Rules 62

- 4.070(3), F.A.C.]

a. Malfunction Notification: If NOx data will be excluded due to a malfunction, the permittee shall notify the Compliance Authority within one working day of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken to correct the pr oblem. In addition, the Compliance Authority may request a written summary report of the incident. Excess Emissions Reporting

b. SIP Excess Emissions Report : Within 30 days following the end of June and December of each year , the permittee shall submit a report to the Compliance Auth ority summarizing the following for the combustion turbine for the period : a summary of the CO and NOx compliance periods; a summary of CO and NOx data excluded due to malfunctions; a summary of the 12

- month rolling CO emissions totals; a summary of any RATA tests performed; and a summary of the CEMS systems monitor availability for each quarter during the period

.

c. NSPS Excess Emissions Reports : Within thirty (30) days following the end of June and December of each year
, the permittee shall submit a report including any applicable periods of excess emissions and monitoring systems performance as defined in 40 CFR 60 Subpart KKKK that occurred during the previous semi

- annual period to the Compliance Authority. {Permitting Note: If there are no periods of e xcess emissions as defined in Subpart KKKK , a statement to that effect may be submitted with the SIP Quarterly Report to suffice for the NSPS Semi

Annual Report.}[Rules 62

- 4.070(3), 62

- 4.130, 62

- 204.800, 62

- 210.700(6), F.A.C.; and 40 CFR 60.7, 60.4375, and 60.4395 ]
37. Initial Report on Startups : The permittee shall submit a report summarizing the following information for each startup during the first 12 months of operation: the type of startup; the sequence of events for the startup; the duration of the
st artup; CO and NOx hourly emissions averages recorded for each hour of the startup (lb/hour and ppmvd @ 15% oxygen); total CO and NOx mass emissions rates for each startup (pounds). The report is due within 60 days following the 12 th month of operation for the unit. Based on the actual information, the Department may reduce the duration of data allowed to be excluded as excess emissions due to the startup event through an air construction permit modification. [ Rule s 62

- 4.070(3) and 62

- 210.700(5), F.A.C.]

# E. City of Tallahassee – Purdom

Emission Units shut

- down: 1. EU007 – Boiler #7 (BART)

Items included: Air Construction Permit ( 1290001

- 008

- AC)

.PERMITTEE 

# Florida Department of Environmental Protection

Bob Marti n e z Cent e r 2600 Blair Stone Road
T

a llaha s see, Florida 32399-2400 Ch
, lrlil' Crhl

(
, (lI ' CI 1 1\)1

( II "'lllk, 1111 I ( l 1\

City of Tallahassee, Electric Utilities 2602 Jackson Bluff Road Tallahassee
, Florida 32304 Air Permit No. 1290001-008-AC Sam O. Purdom Generating Station Facility ID No. 1290001

Authorized Representative: BART Project
, Unit 7 W a kulla County
, Florida Mr. Robert E

. McG a rrah
, Production Superintendent

PROJECT

The City of Tallahassee operates the existing Sam O. Purdom Generating Station, which is an existing power plant (SIC No. 4911) located in Wakulla County at 667 Port Leon Drive in St. Marks
, Florida

. The Department identified existing Unit 7 at this plant as an eligible unit subject to a determination ofthe Best Available Retrofit Technology (BART) pursuant to Rule 62-296.340
, Florida Administrative Code (F

. A

. C.). Primarily fired with fuel oil and natural gas , Unit 7 began operation in 1966 and is a 621 MMBtu per hour steam generator paired with a nominal 44 MW steam-electrical generator. To satisfy the provisions of Rule 62- 296.340
, F.A.C.
, the City of Tallaha s see will shut down Unit 7

.

PERMIT CONDITION

I. Permanent Shutdown: To satisfy the provisions of Rule 62-296.340
, F.A.C.
, the permittee shall permanently shut down Unit 7 (Emissions Unit No. 007) on or before December 31
, 2013. This condition reflects the p e rmittee 's plans and intentions for the scheduled shutdown of Unit 7

. If these plans change due to some unforese e able event , the permittee must take the following actions before December 31
, 2013 : submit a BART application; obtain an air construction permit authorizing the BART control strategies ; implement the BART control strategies ; and demonstrate compliance with the BART s tandards

. Based on the duration of e x tended shutdown
, other preconstruction requirements may also apply.
[Rule 62-296.340
, F.A.C. ; Applicant ' s Request]

This air pollution construction permit is issued und e r the provisions of Chapter 403 of the Florida Statutes (F .S.)
, and Chapters 62

- 4
, 62

- 204
, 62-210
, 62-212, 62-296
, and 62-297 of the Florida Administrative Code (F

. A.C

. )

. The permittee is authorized to conduct the proposed work in accordance with the conditions of this permit and as described in the application
, approved drawings
, plans
, and other documents on file with the Department.

Executed in Tallahassee, Florida

Joseph KahJ;} Direct o r Divi s ion of' i r Resource Management

1/(li( !'(oll'( lioll f (" fll"< (\\

101011 dql 'I:J/t fl.u, I (I b ate)STATE OF FLORIDA DEPARTMENT OF ENVIRONMENTAL PROTECTION

In the Matter of an Application for Permit by: City of Tallahassee, Electric Utilities 2602 Jackson Bluff Road Tallahassee
, Florida 32304

Authorized Representative: NOTICE OF FINAL PERMIT

Air Permit No. 1290001-008-AC Sam O. Purdom Generating Station BART Project, Unit 7 Wakulla County, Florida

Mr. Robert E. McGarrah
, Production Superintendent

We received your application for Best Available Retrofit Technology (BART) for existing Unit 7 in accordance with Rule 62-296.340
, Florida Administrative Code (F.A.C.)

. Unit 7 began operation 1966 at the Sam O. Purdom Generating Station
, which is located in Wakulla County at 667 Port Leon Drive in St. Marks
, Florida. Primarily fired with fuel oil and natural gas, Unit 7 is a 621 MMBtu per hour steam generator paired with a nominal 44 MW steam -elec trical generator. Based on the Ten Year Site Plan on file with the Public Service Commission, Unit 7 is scheduled for permanent shutdown by March of2011. Enclosed is the final air construction permit
, which specifies the enforceable shutdown date for this unit and satisfies the requirements of Rule 62-296.340, F .A.C. This permit is issued pursuant to Chapter 403
, Florida Statutes. Any party to this order has the right to seek judicial review of it under Section 120.68 of the Florida Statutes by filing a notice of appeal under Rule 9.110 of the Florida Rules of Appellate Procedure with the clerk of the Department of Environmental Protection in the Office of General Counsel (Mail Station #35
, 3900 Commonwealth Boulevard, Tallahassee, Florida, 32399-3000) and by filing a copy of the notice of appeal accompanied by the applicable filing fees with the appropriate District Court of Appeal. The notice must be filed within 30 days after this order is filed with the clerk of the Department.

TV / jfk Executed in Tallahassee
, Florida.

Trina Vie l hauer
, Chief Bureau of Air Regulation

Florida Department of Environmental Protection Division of Air Resource Management. Bure a u o f Air Re g ula t ion. Air Permittin g North Section 2600 Blair Stone Road
, MS # 5505 • Ta ll aha ss ee , Florida 32399-2400City of Tallahasee Sam O

. Purdom Generating Station

CERTIFICATE OF SERVICE Air Permit No. 1290001-008-AC BART Project, Unit 7 Shutdown

The undersigned duly designated deputy agency clerk hereby certifies that this Notice of Final Permit package (including the Final Permit and Final Determination) was sent by electronic mail with received receipt requested to the persons listed below.

Mr. Robert E. McGarrah, City of Tallahassee (McGarraR @ talgov

. com) Mr. John Powell, City of Tallahassee
, Electric Utilities (PowellJ@talgov.com) Mr. Ken Kosky
, Golder Associates Inc. (Ken Kosky @ golder.com) Mr. Rick Bradburn
, NWD Office (Rick

. Bradburn @ dep.state.fl.us) Mr. Mike Halpin
, Siting Office (Mike.Halpin @ dep.state.fl.us) Ms. Kathleen Forney (Forney.Kathleen@epa.gov) Mr. Jim Little, EPA Region 4 (LittleJames@epa.gov) Mr. Dee Morse, National Park Service (Dee Morse@nps.gov)

Clerk Stamp
FILING AND ACKNOWLEDGMENT FILED , on this date, pursuant to Section 120.52(7)
, Florida Statutes
, with the designated agency clerk, receipt of which is hereby 

# / 7 Wledged 

# 1/;;;-/01

(Date)

Pag e 2 of2

# F. Fort Pierce Utilities Authority – H. D. King

Emission Units shut

- down: 1. EU007 – Boiler Unit #7 (BART)
2. EU008 – Boiler Unit #8 (BART)

Items included : Letter from facility regarding source shutdowns with Acid Rain, CAIR, and Hg Budget Retired Unit Exemption notices for Boiler Units # 7 and #8.

# RECEiVED
MAR 012011 

# Acid Rain, CAIR, and Hg Budget Retired Unit Exemption BUREAU OF AIR REGULATION For more information, see instructions and refer to 40 CFR 72.8, 96.105, 96.205, 96.305, and 60.4105; and Rules 62-214.340(2), 62·296.470, and 62·296.480, F.A.C.

This submission Is:**~** New 

# D Revised

STEP 1

Identity the unit by plant name, State, ORIS code and unit 10#. B.D. KING PLANT

Plant Name FL 0658 7

State ORIS/Plant Code Unit**ID~** Applicable Program(s):

- ACid Rain

- CAIR NO x Annual

- CAIR S02

- CAIR NO x Ozone Season

- Mercury (Hg) Budget Trading

STEP 2 Identity the date on which the unit was (or will be) permanently retired.

STEP 3 If an acid rain affected unit, identify the first full calendar year in which the unit meets (or will meet) the requirements of 40 CFR 72.8(d).

STEP 4 Read the special provisions. 5 I 311 08



# I January 1, 2009

Acid Rain Special Provisions
(1) A unit exempt under Rule 62-214.340(2), FAG., shall not emit any sulfur dioxide and nitrogen oxides starting on the date that the exemption takes effect. The owners and operators of the unit will be allocated allowances in accordance with 40 CFR Part 73, Subpart B. If the unit is a Phase I unit, lor each calendar year in Phase I, the designated representative of the unit shall submit a Phase I permit application In accordance with 40 CFR Part 72, Subparts C and D, and an annual certification report in accordance with 40 CFR 72.90 through 72.92 and is subject to 40 CFR 72.95 and 72.96. (2) A unit exempt under Rule 62-214.340(2), FAG., shall not resume operation unless the designated representative of the source that includes the unit submits a complete Acid Rain Part application under Rule 62·214.320, FAC., for the unit not less than 24 months prior to the date on which the unit is first to resume operation. (3) The owners and operators and, to the extent applicable. the desi9nated representative of a unit exempt under Rule 62-214.340(2), FAC., shall comply with the reqUirements of Chapter 62·214, F.A.C., and the Acid Rain Program concerning all periods for which the exemption is not in effect. even if such requirements arise. or must be complied with, after the exemption takes effect. (4) For any penod for which a unit is exempt under Rule 62·214.340(2), f-

.. t.

.. C .• the unit is not an Acid Rain unit and is not eligible to be an opt·in source under 40 CFR Part 74. As a non·Acid Rain Unit. the unit shall continue to be subject to any other applicable requirements under Chapter 62· 213. FAC. (5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under Rule 62-214.340(2), FAC., shall retain at the source that includes the unit records demonstrating that the unit is permanently retired. The 5·year period for keeping records may be extended for cause, at any time prior to the end of the penod, in writing by the EPA or the DEP. The owners and operators bear the burden of proof that the unit is permanently retired. (6) On the earlier of the foliowinQ dates, a unit exempt under Rule 62·214.340(2), FAC

.. shall lose its exemption and become an ACid Rain Unit: (i) the date on which the designated representative submits an Acid Rain Part application under paragraph (2); or (iiI the date on which the designated representative is required under paragraph (2) to submit an ACid Rain Part application. For fhe purpose of applying monitoring requirements under 40 CFR Part 75, a unit that loses its exemption under Rule 62-214.340(2). FAC., shall be treated as a new unit that commenced commercial operation on the first date on which the unit resumes operation.

DEP Form No. 62·210.900(1){d)· Form Effective: 3/16/08

# RECE\VE,D

# M:~R:~~~~**Aci~** Rain,

# ~AIR,**an~** Hg Budget

AIR 

## REGULATIONRetlred 

# Unit Exemption

For more information, see instructions and refer to 40 CFR 72.8, 96.105, 96.205, 96.305, and 60.4105; and Rules 62-214.340(2), 62-296.470, and 62·296.480, F.A.C.

This submission Is:**~** New 

# D Revised

STEP 1

Identify the unit by plant name, State, ORIS code and unit 10#. B.D. KING PLANT

Plant Name FL 0658 8

Stale ORISIPlant Code Unit IDII Applicable Program(s):

- ACid Rain

- CAIR NO x Annual

- CAIR S02

- CAlR NO x Ozone Season

- Mercury (Hg) Budget Trading

STEP 2 Identify the date on which the unit was (or will be) permanently retired.

STEP 3 If an acid rain affected unit, Identify the first full calendar year in which the unit meets (or will meet) the requirements of 40 CFR 72.8(d).

STEP 4 Read the special provisions. 

# I January 1. 2009

Acid Rain Special Provisions
(1) A unit exempt under Rule 62-214.340(2), FAG., shall not emit any sulfur dioxide and nitrogen oxides starting on the date that the exemp'tion takes effect. The owners and operators of the unit will be allocated allowances in accordance with 40 GFR Part 73, Subpart B. If the unit is a Phase I unit, for each calendar year in Phase I, the designated representative of Ihe unit shall submit a Phase I permit application In accordance with 40 GFR Part 72, Subparts G and D, and an annual certiiication report in accordance with 40 GFR 72.90 through 72.92 and is subject to 40 GFR 72.95 and 72.96. (2) A unit exempt under Rule 62-214.340(2), FAG., shall not resume operation unless the deSignated representative of the source that includes the unit submits a complete Acid Rain Part application under Rule 62-214.320. FAG., for the unit not less than 24 months prior to the date on which the unit is first to resume operation. (3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under Rule 62-214.340(2), FAG., shall comply with the reqUirements of Ghapter 62-214, FAG., and the Acid Rain Program concerning all periods for which the exemption is not in effect. eve;; if such requirements arise, or must be complied with. after the exemption takes effect.· (4) For any penod for which a unit is exempt under Rule 62-214.340(2), F.A.G., the unit is nol an Acid Rain unit and is not eligible to be an opt-in source under 40 CFR Part 74. As a non-Acid Rain Unit. the unit shall continue to be subject to any other applicable requirements under Ghapter 62- 213, FAG. (5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under Rule 62-214.340(2), FAG., shall retain at the source that includes the unit records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the penod. in writing by the EPA or the DEP. The owners and operators bear the burden of proof that the unit is permanently retired. (6) On the earlier of the followinQ dates, a unit exempt under Rule 62-214.340(2), FAG., shall lose its exemption and become an ACid Rain Unit: (i) Ihe date on which the designated representalive submits an Acid Rain Part application under paragraph (2); or (ii) the date on which the deSignated representative is required under paragraph (2) to submit an ACid Rain Part application. For the purpose of applying monitoring requirements under 40 GFR Part 75. a unit that loses its exemption under Rule 62-214.340(2). FAC., shall be treated as a new unit that commenced commercial operation on the first date on which the unit resumes operation.

DEP Form No. 62·210.900(1 )(d)

- Form Effective: 3/16/08STEP 4 (continued) 

## I B.D. KING PLANT**~Ianl** Name (from STEP 1)

CAIR Special Provisions
(1) A unit exempt under 40 GFR 96.105(a), 96.205(a),01' 96.305(a), shall not emit any sulfur dioxide
or nitrogen oxides starting on the date that the exemption takes effect. The DEP will allocate GAIR NOx allowances in accordance with Rule 62-296.470, F A.G. (2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under Rule 62·296.470, F.A.G., shall retain at \he source that includes the unit, records demonstrating that the unit is permanently retired. The !t-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the EPA or the DEP. The
owners and operators bear the burden of proof that the unit is permanently retired. (3) The owners and operators and, to the extent applicable, the GAIR designated representative of a unit exempt under 40 GFR 96.1 05(a)
, 96.205(a), or 96.305(a), shall comply with the applicable requirements of the GAIR NOx Annual Trading Program, the GAIR S02 Trading Program, and the GAIR NO x Ozone Season Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be conlplied with, after the exemption takes effect. (4) A unit exempt under 40 GFR 96.1 05(a), 96.205(a), 01' 96.305(a), and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not
resume operation unless the GAIR designated represenlative of the.source submits a complete GAIR Part application under Rule 62-213.420. FAG

.. for the unit before the date on which the unit

resumes operation. (5) On the earlier of the following dates, a unit exempt Wider 40 GFR 96.1 05(a), 96.205(a), or 96.305(a) shall lose its exemption:

(i) the date on which the GAIR designated representmve submits a GAIR Part application under Special Provision (4) above;

(ii) the date on which the GAIR desi9nated representative is required under Special Provision (4) above to submit an GAIR Part application for the unit; or

(iii) the date on which the unit resumes operation, if \he GAIR designated representative is not required to submit a GAIR Part application for the unit. (6) For the purpose 01 applying monitoring, reporting and record keeping requirements under 40 CFR Part 96, Subparts HH, HHH, and/or HHHH, a unitlhat loses its exemption under 40 GFR 96.1 05(a), 96.205(a), or 96.305(a), shall be treated as a unit that commences commercial operation
on the lirst date on which the unit resumes operation.

Mercury (Hg) Budget Trading Special Provisions

(·1) A unit exempt under 40 GFR 60.41 05(a) shall not emit any mercury starting on the date that the exemption takes effect. (2) The DEP will allocate Hg allowances under Rule 62-296.480. FAG. (3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 GFR 60.4105(a) shall retain at the SOIKe that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any before the end of the period, in writing by the EPA or the DEP. The
owners and operators bear the burden of proof that the unit is permanently retired. (4) The owners and operators and, to the extent applicable, the Hg designated representative of a unit exempt under 40 GFR 60.4105(a) shall comply wittllhe requirements of the Hg Budget Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (5) A unit exempt under 40 GFR 60.41 05(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the Hg designated representative of the source submits a complete Hg Budget Part application under 40 GFR 60.4122 and Rule 62-213.420, FAG., lor the unit before the date on which the unit

resumes operation. (6) On the earlier of the following dates, a unit exempt mder 40 GFR 60.41 05(a) shall lose its exemption:

(i) the date on which the Hg designated representative submits a Hg Budget Part application for the unit under Special Provision (5); (ii) the date on which the**H~** designated representatNe is required under Special Provision (5) to submit a Hg Budget Part apphcation for the unit; or

(iii) the date on which the unit resumes operation, if the Hg designated representative is not reqUired to submit a Hg Budget Part application for the Wlit. (7) For the purpose of applYing monitoring, reporting and recordkeeping requirements under 40 CFR 60.4170 through 60.4176, a unit that loses its eXl!IInption under 40 GFR 60.4105(a) shall be treated as a unit that commences operation and commercial operation on the first date on which the unit resumes operation.

DEP Form No. 62-210.900(1)(d)

- Form Effective: 3/16/08 2STEPS Make Statement of Compliance.

STEP 6

Read the certification and sign and date. 

# I B.D. KING PLANT Plant Name (from STEP 1)

Statement of Compliance I state that the unit identified above in STEP 1 was (or will be) permanently retired on the date identified in STEP 2 and will comply with the Special Provisions listed in STEP 4.

. Certification (for designated representatives or alternate designated representatives only) I am authorized to make this submission on behalf of the owners and operators of the affected
source and affected unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and mformation, includin the ossibilit of fine or im risonment.

Thomas Name

PORT PIERCE UTILITIES AUTHORITY Owner Company Name

(772) Phone Director of Electric & Gas System Title

tom@fpua.com

Date 6/30/08

DEP Form No. 62·210.900(1)(d) • Form Effective: 3/16/08 3

# G. Florida Power Corporation – Bartow

Emission Units shut

- down: 1. EU001 – Unit #1 (RP)
2. EU002 – Unit #2 (RP)
3. EU003 – Unit #3 (BART/RP)

Items included: Air Construction Permit (1030011

- 010

- AC).

# Department of 

# Environmental Protection

leb Bush Governor

PERMITTEE

Florida Power Corporation dba

. Progress Energy Florida, Inc. 100 Central Avenue, Mail Code BP39 St. Petersburg, Florida 33701
Authorized Representative: Mr. Rufus Jackson

PROJECT AND LOCATION Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Colleen M. Castille Secretary

DEP File No. 1030011-0 1O-AC Permit No. PSD-FL-381 PEF P.L. Bartow Power Plant Plant Repowering Project Pinellas County

SIC No. 4911 Expires: March 31, 2010

This permit authorizes the construction of one nominal 1,280 megawatt (MW) combined cycle unit and one nominal 195 MW simple cycle unit at the Progress Energy Florida (PEF) P.L. Bartow Power Plant located at 1601 Weedon Island Drive, St. Petersburg, Pinellas County.
Three existing fossil fuel fired steam generators designated as Units 1, 2 and 3 with a total nominal capacity of 465 MW will be shut down as part of this project.
The UTM coordinates are Zone 17,342.4 km East and 3,082.6 km North.
STATEMENT OF BASIS
This air pollution construction permit is issued under the provisions of Chapter 403 of the Florida Statutes (F.S.), and Chapters 62-4, 62-204, 62-210, 62-212, 62-296, and 62-297 of the Florida Administrative Code (F.A.C.) and Title 40, Parts 60 and 63 of the Code of Federal Regulations. The permittee is authorized to install the proposed equipment in accordance with the conditions of this permit and as described in the application, approved drawings, plans, and other documents on file with the Department.
CONTENTS
Section I. General Information Section 2. Administrative Requirements Section 3. Emissions Units Specific Conditions Section 4. Appendices

Joseph Kahn, Director Division of Air Resource

Management

"More Protection, Less Process"

Printed on recycled poper. (Date)FACILITY AND PROJECT DESCRIPTION Progress Energy Florida operates the Bartow Plant, which is an existing power plant (SIC No. 4911). The plant currently consists of:

**•** Three fossil fuel fired steam generating units designated as Units 1, 2 and 3 that produce 120, 120 and 225 megawatts (MW) of electrical power respectively;

**•** Four simple cycle units designated as Gas Combustion Turbine P eaking Units Nos. P -1, P-2, P-3 and P-4 each of which has a nominal capacity of 56 MW;

**•** Additional emissions units include a pipeline heating boiler and relocatable diesel generators; and

**•** Miscellaneous unregulated/insignificant emissions units and/or activ ities including fuel storage tanks and gas tanks that can be located at various PEF power plants. These units are listed in Appendix U of the current Title V Permit

. The project is a plant repowering that includes the construction of a nominal 1,280 MW gas-fired combined cycle unit system (“4 -on-1”) and a nominal 195 MW gas-fired simple cycle unit. The project includes and requires the shutdown of the three fossil fuel fired steam generating units (Units 1, 2 and 3) resulting in a net decrease in all PSD pollutants except for carbon monoxide ( CO ) and volatile organic compounds ( VOC ). The combined cycle unit system will consist of: four Model SGT6-5000F combustion turbine- electrical generators (CT

- electrical generators) with a nominal rating of 215 MW at IS O conditions when practicing power augmentation; four duct- fired heat recovery steam generators (HRSG’s) each equipped with a selective catalytic reduction (SCR) reactor and a nominal 500 million Btu per hour (MMBtu/hr) duct burner; and a single nominal 42 0 MW steam

- electrical generator (STG). Each CT within the combined cycle unit system will be permitted to operate in simple cycle by directing the exhaust to a bypass stack instead of the respective HRSG. Thus the project will include eight stacks measur ing approximately 120 feet in height. All CTs will be equipped with evaporative coolers to condition incoming air at high ambient temperatures and wet injection capability for nitrogen oxides control when firing fuel oil or when practicing power augmentation. Each CT will be allowed to fir e backup low sulfur (<0.05% S) distillate fuel oil for 1,000 hours per year (hr/yr). The new units are designated as Units 4 and Unit 5. The simple cycle CT

- electrical generator will have a nominal rating of 195 MW at IS O conditions and will exhaust through its own 120 foot stack. Additional ancillary equipment will include: five natural gas fired fuel heaters; two diesel fuel storage tanks; one auxiliary steam boiler; and a diesel fueled emergency fire pump. This per mit authorizes the installation the following new equipment in conjunction with the permanent shutdown of Units 1, 2, and 3.

E.U. ID Emission Unit Description

0 38 Unit 4A

– One 215 MW (ISO) Combustion Turbine with Duct

- fired Heat Recovery Steam Generator 0 39 Unit 4B

– One 215 MW (ISO) Combustion Turbine with Duct

- fired Heat Recovery Steam Generator 0 40 Unit 4C

– One 215 MW (ISO) Combustion Turbine with Duct

- fired Heat Recovery Steam Generator 0 41 Unit 4D

– One 215 MW (ISO) Combustion Turbine with Duct

- f ired Heat Recovery Steam Generator 0 42 Unit 5

– One 195 MW (ISO) Combustion Turbine 0 43 One Nominal 85,000 lb/hr (99 MMBtu/hr) Auxiliary Boiler 0 44 Five Nominal 3 MMBtu/hr Gas

- fired Process Heaters 0 45 Two Nominal 3,500,000 gallon Distillate Fuel Oil S torage Tanks 0 46 One Nominal 300 horsepower Diesel

- fueled Emergency Fire PumpREGULATORY CLASSIFIC ATION

The proposed project is subject to the following New Source Performance Standards of 40 CFR 60: Title I, Section 111, Clean Air Act, Standards of Performance for New Stationary Sources

**•** Subpart KKKK - Standards of Performance for Stationary Combustion Turbines. This rule also covers duct burners that are incorporated into combined cycle projects,

**•** Subpart Dc which applies to Small Industrial, Commercial, or Institutional Boilers, and

**•** Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

The proposed p roject is subject to the following National Emissions Standards for Hazardous Air Pollutants: Title I, Section 112, Clean Air Act, National Emissions Standards for Hazardous Air Pollutants ( NESHAP)

**•** 40 CFR 63 , Subpart YYYY – N ESHAP for Stationary Combustion Turbines.

**•** 40 CFR 63, Subpart DDDDD – N ESHAP for Industrial, Commercial, or Institutional Boiler or Pr ocess Heater. Applies to auxiliary boiler and gas heaters.

The facility is located in an area that is designated as “attainment”, “maintenance”, or “unclassifiable” for each po llutant subject to a National Ambient Air Quality Standard. The facility is classified as a “Fossil fuel

- fired steam electric plants of more than 250 million British thermal units per hour heat input”, which is one of the facility categories with the PSD applicability threshold of 100 tons per year (TPY). Potential emissions of at least one regulated pollutant exceed 100 TPY per year, therefore the facility is classified as a “Major Stationary Source” with respect to Rule 62 -212.400 F.A.C. Title I, Part C, Clean Air Act, Prevention of Significant Deterioration (PSD)

The facility operates units subject to the Acid Rain provisions of the Clean Air Act. Title IV, Clea n Air Act, Acid Rain Provisions

The facility is a Title V or “Major Source” of air pollution because the potential emissions of at leas t one regulated pollutant exceed 100 tons per year or because it is a Major Source of HAP. Regulated pollutants include pollutants such as carbon monoxide (CO), nitrogen oxides (NO Title V, Clean Air Act, Permits

X ), particulate matter (PM/PM 10 ), sulfur dioxide (SO 2 ), and volatile organi c compounds (VOC).

The new combustion turbine- electrical generators may be subject to CAIR pending finalization of DEP rules. Clean Air Interstate Rule (CAIR)

The facility was Florida Power Plant Siting Act (Siting)

not certified pursuant to Siting under 403.501-519, F.S. or Chapter 62-17, F.A.C. The proposed project is not subject to Siting because there will be no net increase in steam

RELEVANT DOCUMENTS - generated electrical power. [Design; Letter from Applicant Dated December 19, 2005]

The following relevant documents are not a part of this permit, but helped form the basis for this permitting action:

**•** Air Construction Permit application received July 31, 2006;

**•** Department’s Request for Additional Information dated August 30, 2006;

**•** Progress additiona l information received October 2 and October 26, 2006;

**•** Intent to Issue, Draft Air Construction Permit, and Technical Evaluation distributed December 13 , 2006; and

**•** Final Determination distributed concurrently with Final Air Construction Permit.1. Permitting Authority

2. : All documents related to applications for permits to construct, modify, or operate emissions units at this facility shall be submitted to the Bureau of Air Regulation of the Florida Department of Environmental Protection (DEP) at 2600 Blair Stone Road (MS #5505), Tallahassee, Florida 32399- 2400. Copies of all such related documents shall also be submitted to the Compliance Authority. Compliance Authority

3. : All documents related to compliance activities such as reports, tests, and notifications shall be submitted to the Air Quality Division of the Pinellas County Department of Environmental Management Office at 300 South Garden Avenue, Clearwater, Florida 34616. Appendices

4. : The following Appendices are attached as part of this permit: Appendix A (NSPS and NESHAP Subpart A – Identification of General Provisions); Appendix CF (Citation Format); Appendix GC (General Conditions); and Appendix CC (Common Conditions); Appendix IIII (NSPS Subpart IIII Provisions – Internal Combustion Engines); Appendi x KKKK (NSPS Subpart KKKK Provisions - Combustion Turbines and Duct Burners); Appendix YYYY (NESHAP Subpart YYYY Provisions – Combustion Turbines); Appendix BD ( BACT Determination ); Appendix DDDDD (NESHAP Subpart DDDDD - National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, or Institutional Boiler or Process Heater); Appendix Dc (NSPS Subpart Dc - Standards of Performance for Small Industrial

- Commercial

- Institutional Steam Generating Units) ; Appendix XS (Semiannual NSPS Excess Emissions Report)

. Applicable Regulations, Forms and Application Procedures

5. : Unless otherwise indicated in this permit, the construction and operation of the subject emissions unit shall be in general accordance with the capacities and specifications stated in the application. The facility is subject to all applicable provisions of: Chapter 403 of the Florida Statutes (F.S.); Chapters 62-4, 62-204, 62-210, 62-212, 62-213, 62-296, and 62-297 of the Florida Administrative Code (F.A.C.); and Title 40, Parts 60 and 63 of the Code of Federal Regulations (CFR), adopted by reference in Rule 62-204.800, F.A.C. The terms used in this permit have specific meanings as defined in the applicable chapters of the Florida Administrative Code. The permittee shall use the applicable forms listed in Rule 62-210.900, F.A.C. and follow the application procedures in Chapter 62-4, F.A.C. Issuance of this permit does not relieve the permittee from compliance with any applicable federal, state, or local permitting or regulati ons. [Rules 62-204.800, 62-210.300 and 62-210.900, F.A.C.]
New or Additional Conditions

6. : For good cause shown and after notice and an administrative hearing, if requested, the Department may require the permittee to conform to new or additional condition s. The Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and on application of the permittee, the Department may grant additional time. [Rule 62-4.080, F.A.C.]
Modifications

7. : The permittee shall notif y the Compliance Authority upon commencement of construction. No emissions unit or facility subject to this permit shall be constructed or modified without obtaining an air construction permit from the Department. Such permit shall be obtained prior to beginning construction or modification. [Rules 62-210.300(1) and 62-212.300(1)(a), F.A.C.] Construction and Expiration : The permit expiration date includes sufficient time to complete construction, perform required testing, submit test reports, and submit an application for a Title V operation permit to the Department. Authorization to construct shall expire if construction is not commenced within 18 months after receipt of the permit, if construction is discontinued for a period of 18 months or more, or if construction is not completed within a reasonable time. This provision does not apply to the time period between construction of the approved phases of a phased construction project except that each phase must commence construction within 18 months of t he commencement date established by the Department in the permit. The owner or operator of a phased construction project shall adhere to the procedures provided in 40 CFR 52.21(j)(4), adopted and by reference in Rule 62-204.800, F.A.C. For good cause, th e permittee may request that this PSD air construction permit be extended. [Rules 62-4.070(4), 62-4.080, 62-210.300(1), 62-212.400(12)(a) and 62-212.400(10)(d), F.A.C.]8. Source Obligation

9. : At such time that a particular source or modification becomes a major stationary source or major modification (as these terms were defined at the time the source obtained the enforceable limitation) solely by virtue of a relaxation in any enforceable limitation which was established after August 7, 1980, on the capacity of the source or modification otherwise to emit a pollutant, such as a restriction on hours of operation, then the requirements of subsections 62 -212.400(4) through (12), F.A.C., shall apply to the source or modification as though construction had not yet commenced on the source or modification. [Rule 62 -212.400(12)(b), F.A.C.]
Title IV Permit

10. : At least 24 months before the date on which the new unit begins serving an electrical generator greater than 25 MW, the permittee shall submit an application fo r a Title IV Acid Rain Permit to the Department’s Bureau of Air Regulation in Tallahassee and a copy to the Region 4 Office of the U.S. Environmental Protection Agency in Atlanta, Georgia. This permit does not specify the Acid Rain program requirements. These will be included in the Title V air operation permit. [40 CFR 72]
Title V Permit

11. : This permit authorizes construction of the permitted emissions units and initial operation to determine compliance with Department rules. A Title V operation permit is required for regular operation of the permitted emissions unit. The permittee shall apply for a Title V operation permit at least 90 days prior to expiration of this permit, but no later than 180 days after commencing operation. To apply for a Title V operation permit, the applicant shall submit the appropriate application form, compliance test results, and such additional information as the Department may by law require. The application shall be submitted to the appropriate Permitting Authority with copies to the Compliance Authority. [Rules 62-4.030, 62-4.050, 62-4.220, and Chapter 62-213, F.A.C.] Annual Operating Report : The permittee shall submit an annual report that summarizes the actual operating hours and emissions from this facility. Annual operating reports shall be submitted to the Compliance Authority by March 1st of each year. [Rule 62-210.370(3), F.A.C.]This section of the permit addresses the following emissions unit.
E.U.

ID Emissions Units Comprising Combined Cycle Unit 4

038 Un it 4A – One 215 MW (ISO) Combustion Turbine with Duct- fired Heat Recovery Steam Generator
039 Unit 4B – One 215 MW (ISO) Combustion Turbine with Duct- fired Heat Recovery Steam Generator
040 Unit 4C – One 215 MW (ISO) Combustion Turbine with Duct- fired He at Recovery Steam Generator
041 Unit 4D – One 215 MW (ISO) Combustion Turbine with Duct- fired Heat Recovery Steam Generator
042 Unit 5 – One 195 MW (ISO) Combustion Turbine

A PPLICABLE S TANDARDS AND R EGULATIONS
1. PSD Applicability and BACT Determinations

See Appendix BD of this permit for a summary of the final BACT determinations. [Rules 62-210.200 (Definitions) and 62-212.400, F.A.C.] : The Rules for the Prevention of Significant Deterioration (PSD) of Air Quality apply to this project and Best Available Control Technology (BACT) determinations were made for carbon monoxide (CO) and volatile organic compounds (VOC).

{Permitting Note: Th e repowering project does not trigger PSD or require a BACT determination for NO X , SO 2 , sulfuric acid mist or PM/PM 10

2. because emissions reductions from the permanent shutdown of existing fossil fueled steam generating Units 1, 2 and 3 will exceed emissions increases from the project by values grea ter than the respective significant emissions rates.} NSPS Requirements

a. Subpart A - General Provisions , including: : E ach CT shall comply with all applicable requirements of 40 CFR 60, listed below, adopted by reference in Rule 62- 204.800(7)(b), F.A.C.

**•** 40 CFR 60.7, Notification and Record Keeping

**•** 40 CFR 60.8, Performance Tests

**•** 40 CFR 60.11, Compliance with Standards and Maintenance Requirements

**•** 40 CFR 60.12, Circumvention

**•** 40 CFR 60.13, Monitoring Requirements

**•** 40 CFR 60.19, General Notification and Reporting Requirements
b. Subpart KKKK - Standards of Performance for Stationary Comb ustion Turbines: These provisions were finalized on July 6, 2006 and include requirements applicable to duct burners located in HRSGs.
3. NESHAP Requirements

E QUIPMENT A ND C ONTROL T ECHNOLOGY : The CTs are subject to 40 CFR 63, Subpart A - Identification of General Provisions and 40 CFR 63, Subpart YYYY - National Emissions Standard for Hazardous Air Pollutants for Stationary Combustion Turbines.

4. Combustion Turbines (CTs)

5. : The permittee is authorized to install, tune, operate, and maintain five Model SGT6 -5000F CT- electrical generator sets. Each CT shall include an automated control system and have dual-fuel capability. Ancillary equipment includes an inlet air filtration system, evaporative inlet air-cooling system and a nominal 120 foot exhaust stack for simple cycle operation. [Application No. 1030011-010- AC; Design] Heat Recovery Steam Generators (HRSGs) : The permittee is authorized to install, operate, and maintain four new duct -fired HRSGs that recover exhaust heat energy from four of the CTs and del iver steam to a nominal 420 MW steam turbine electrical generator. Each HRSG shall be equipped with a nominal 120 footexhaust stack for combined cycle operation. [Application No. 1030011-010- AC; Design]
6. DLN Combustion : The permittee shall install, oper ate and maintain Dry Low NO X (DLN) systems to control NO X emissions from each CT when firing natural gas. Prior to the initial emissions performance tests required for each CT, the DLN combustors and automated combustion turbine control system shall be tu ned without a selective catalytic reduction (SCR) system in operation to achieve the permitted CO, VOC and NO X

7. levels for simple cycle operation. Thereafter, each system shall be maintained and tuned in accordance with the manufacturer’s recommendations o r industry standards. [Application No. 1030011-010- AC; Design] Water Injection : The permittee shall install, operate, and maintain a water injection system to reduce NO X emissions from each CT when firing distillate fuel oil. Prior to the initial emissio ns performance tests, the water injection system shall be tuned without an SCR system in operation to achieve the NO X

8. value for simple cycle operation. Thereafter, each system shall be maintained and tuned in accordance with the manufacturer’s recommendat ions or industry standards. [ Application No. 1030011-010- AC; Design] Selective Catalytic Reduction Systems : The permittee is authorized to install, tune, operate, and maintain a selective catalytic reduction (SCR) system within each HRSG to control NO X e missions from each of the four CT/Duct- fired HRSGs comprising the combined cycle unit. The SCR system consists of an ammonia (NH 3 ) injection grid, catalyst, ammonia storage, monitoring and control system, electrical, piping and other ancillary equipment. The SCR system shall be designed, constructed and operated to achieve the permitted levels for NO X and NH 3 emissions. Operation of the SCR systems is not required whe n the NO X

9. emission limit s can be met without their use. [Application No. 1030011-010- AC; Design , and 62-210.650 (Circumvention), F.A.C.] Oxidation Catalyst Systems

10. : The permittee shall design and build the project to facilitate future installation of an oxidation catalyst system within each HRSG to control CO and VOC emissions from each of t he four CTs/Duct -fired HRSGs comprising the combined cycle unit. The permittee may install oxidation catalyst during project construction or, after notifying the Department, at a future date as described in Specific Condition 1 8.f. [Rule 62-4.070(3) F.A. C.] Ammonia Storage

P ERFORMANCE R ESTRICTIONS : In accordance with 40 CFR 60.130, the storage of ammonia shall comply with all applicable requirements of the Chemical Accident Prevention Provisions in 40 CFR 68. [Rule 62 -4.070 F.A.C.]

11. Authorized Fuels

12. : Ea ch CT shall fire only natural gas and distillate oil. The maximum sulfur content of natural gas shall not exceed 2.0 grains of sulfur per 100 standard cubic feet of natural gas. The maximum sulfur content of distillate oil shall not exceed 0.05% by weigh t. [Design; Rules 62-4.070 and 62-210.200 (Definitions – PTE) , F.A.C.; 40 CFR 60, Subpart KKKK] Permitted Capacity - Combustion Turbines : The nominal heat input rate excluding steam for power augmentation to each CT is 1,972 MMBtu per hour when firing natural gas and 1,876 MMBtu per hour when firing distillate fuel oil based on a compressor inlet air temperature of 59° F, the higher heating value (HHV) of each fuel, and 100% load. Heat input rates will vary depending upon CT characteristics, ambient conditions, alternate methods of operation, and evaporative cooling. The permittee shall provide manufacturer’s performance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of completing the ini tial compliance testing. Operating data may be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department. [Rule 62-210.200( Definitions - PTE), F.A.C.]13. Permitted Capacity - Duct Bur ners

14. : The total nominal heat input rate to the duct burners (DBs) located within each HRSG is 500 MMBtu per hour based on the higher heating value (HHV) of natural gas. Only natural gas shall be fired in the duct burners. [Rule 62 -210.200(Definitions - PTE), F.A.C.] Temporary Simple Cycle Operation of Two CTs Prior to Permanent Shutdown of Units 1, 2 and 3

a. Restriction on SC O peration : : The permittee may select any two of the five new CTs to be operated as simple cycle units prior to shutdown of Units 1, 2 and 3. The restrictions included in this condition apply only to those CTs chosen, and only during the described period. Once selected, only those CTs chosen may be operated prior to shutdown of Units 1, 2 and 3 in accordance with the following restrictions:

**•** The combined operation of the two CTs shall not exceed 1,100 hours.

**•** A NO X CEMS shall be installed and operating in each stack prior to startup of the CTs in order to collect and record data for the purpose of demonstrating compliance with this requirement. Notwithstanding the relative accuracy test audit (RATA) grace period described in 40 CFR 75 Appendix B, t he NO X

**•** T otal emissions of NO CEMS shall be fully certified in accordance with the requirements of 40 CFR 75 (including a RATA), within 30 operating days but no t later than 60 calendar days after startup of the CTs.

X from the two CTs shall not exceed 39 tons during all operation including startups, shutdowns and malfunctions as measured and recorded by the required NO X

**•** Each CT shall be stack tested to demonstrate initial compliance with the applicable Subpart KKKK NO continuous emissions m onitoring systems (CEMS) during the temporary period. Data recorded before and after CEMS certification shall be included in the calculation.

X

**•** The BACT emissions standards of specific condition 18 do not apply to these CTs prior to Unit 1, 2 and 3 shutdown. Following shutdown of Units 1, 2 and 3 all restrictions of this permit apply, including the BACT limits of specific condition 18. emission sta ndard for each fuel to be fired. The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup of each unit. Data collected during the abo ve described RATA may be used to satisfy this 60

- day test requirement provided all requirements of 40 CFR 60.8 and Subpart KKKK are met.

b. Restriction on CC Operation : No combined cycle operation of any unit is allowed prior to permanent shutdown of Units 1, 2, and 3.

c. Monthly Operations Summary : By the 10 th calendar day of each month, the permittee shall record the following in a written or electronic log for each CT for the previous month of operation: fuel consumption, hours of operation, NO X emissions in total ton s for the month, and NO X

{Permitting note: The limitation on total NO emissions in total tons for the described restricted period of operation

. Information recorded and stored as an electronic file shall be available for inspection and printing within at least three days of a request by the Departme nt. The fuel consumption shall be monitored in accordance with the provisions of 40 CFR 75 Appendix D.

X

[Rules 62-4.070(3), 62-210.200(PTE) and 62-212.400(12)(PSD Avoidance), F.A.C.; 40 CFR 60.8, and 40 CFR Subpart KKKK] emissions and adherence to the emissions standards in Specific Conditions 18, 19 and 20 along with the compliance and recordkeeping requirements of this condition will effectively ensure that emissions increases of all PSD pollutants from the selected CTs operated in SC mode prior to Unit 1, 2 and 3 shutdown will be less than their respective Significant Em issions Rates per Rule 62 -210.200 (Definitions-SER), F.A.C.}15. Restricted Operation

a. The hours of operation of the CTs are not limited (8,760 hours per year). : The permittee shall not exceed the following parameters following shutdown of Units 1, 2 and 3:

b. Distillate oil firing is limited to 1,000 hours per CT (i.e. 5,000 hours total aggregate for all five CTs) during any consecutive 12-month period.

c. Operation of the DBs is limited to 2,434 hours per DB (i.e. 9,736 hours aggregate for four DBs) during any consecutive 12 -month period. d. Power (steam) augmentation shall be limited to 1,688 hours per CT during any consecutive 12-month period.

e. Other than startup, shutdown, fuel switching or documented malfunction the CTs shall operate above 70% load during simple cycle operation. 16. Methods of Operation

a. Simple Cycle (SC) Operation: All five CTs may operate in simple cycle (SC) mode whereby the turbine exhaust gas (TEG) exits through or is diverted to a stack unassociated with a DB -fired HRSG. This method of operation will be an infrequent occurrence for the four CTs that will typically operate in combined cycle mode as described below. : Subject to the restrictions and requirements of this permit, the CTs may operate under the following methods of operation after shutdown of Units 1, 2 and 3

b. Combined Cycle (CC) Operation : The four CTs associated with combined cycle Unit 4 may operate in combined cycle ( CC) mode whereby the TEG is exhausted to their respective duct

- fired HRSGs for energy recovery in order to raise steam to drive the single steam turbine

- electrical generator (STG) subject to the restrictions of this permit.

c. Inlet Conditioning : In accord ance with the manufacturer’s recommendations and appropriate ambient conditions, the evaporative cooling systems may be operated to reduce the compressor inlet air temperature and provide additional direct, shaft- driven electrical power. d. Duct Firing : Th e DB within each HRSG may be fired with natural gas to reheat the TEG in order to provide additional steam to the STG or the CTs for power augmentation.

e. Power augmentation: Power (Steam) Augmentation (PA): Steam for PA is taken from the HRSG and is int roduced into the CT compressor discharge, thus increasing the power produced by the expander portion of the turbine. [Application; Rules 62 -210.200(PTE) and 62-212.400(BACT), F.A.C.]
E MISSIONS S TANDARDS
17. New Source Performance Standards for NO X : Emissions of NO X

Pollutant shall not exceed the following emission limits for each CT or CT/DB -fired HRSG determined pursuant to 40 CFR 60, Subpart KKKK.

Fuel Method of Operation CEMS a b Rolling Average ppmvd (uncorrected)

NO X Oil

c CT (SC) 42 on 4-hour basis CT (CC) 42 on 30-operating days basis

Gas CT (SC) 15 on 4-hour basis
CT (CC) 15 on 30-operating days basis CT & DBa. CT (SC) means operation of CT in simple cycle mode. CT(CC) means operation of CT in combined cycle without use of the DB. CT & DB means operation in combined cycle mode and using the DB. b. A CEMS for NO X shall be installed on the CT stacks and on the HRSG stacks

. Correction to 15% O 2

c. Compliance with the continuous NO is not allowed consistent with the provisions of 40 CFR 60, Subpart KKKK.

X
Refer to Appendix KKKK of this permit for the full NSPS requirements. [40 CFR 60, Subpart KKKK] standards shall be demonstrated based on data collected by the required CEMS.

18. Best Available Control Technology (BACT) Emissions Standards for CO and VO

Pollutant C : Emissions of VOC and CO shall not exceed the following emission limits for each CT or CT/DB

- fired HRSG.

Fuel Method of Operation Stack Test, 3

- Run Average

a CEMS Block Average c

ppmvd @ 15% O lb/hr 2 ppmvd @ 15% O b 2 Unit 4 HRSG St acks

CO Oil CT 8.0 40.4 8.0, 24-hr d
6, 12-month f Gas CT 4.1 20.8
CT & DB 7.6 38.3

VOC Oil

e,g CT 2.8 7.6 Not Applicable Gas CT 1.2 3.0
CT & DB 1.5 3.8 Unit 5CT and Unit 4 Bypass Stacks

CO Oil CT 8.0 40.4 Not Applicable Gas CT 4.1 20.8

VOC Oil
e CT 2.8 7.6 Not Applicable Gas CT 1.2 3.0

a. CT means operation of a combustion turbine (CT) in simple cycle or in combined cycle without use of the duct burner (DB). CT & DB means operation in combined cycle mode and using the DB. b. The m ass emission rate standards are based on a turbine inlet condition of 59° F and may be adjusted to actual test conditions in accordance with the performance curves and/or equations on file with the Department.

c. CEMS for CO are required only on the HRSG stacks. Other than startup, shutdown, fuel switching or documented malfunction the CT shall operate above 70% load during simple cycle operation. d. Compliance with the continuous 24

- hour CO standards shall be demonstrated based on data collected by the required CEMS on the HRSG stacks. The initial and annual EPA Method 10 tests associated with the certification of the CEMS instruments may also be used to demonstrate compliance with the individual standards for natural gas, fuel oil, or duct burner modes. Separate CO tests shall be conducted under simple cycle mode on the CT stacks.

e. Compliance with the VOC standards shall be demonstrated by conducting tests in accordance with EPA Method 25A on the HRSG stacks and, under simple cycle mode, on the CT stacks. Opti onally, EPA Method 18 may also be performed to deduct emissions of methane and ethane. The emission standards are based on VOC measured as methane. f. Rolling Average. Enforcement discretion may be exercised for up to 12 months with respect to the 6 ppmvd @15% O 2 limit for any CT/Duct

- fired HRSG upon notification by the permittee of intent to install oxidation catalyst. The permittee shall have 12 months to complete the oxidation catalyst installation. From time ofnotification to installation of the cat alyst all partial or complete calendar months shall be excluded from the 12

- month rolling average.
g. Compliance with the CO CEMS based limits shall be deemed as compliance with the VOC limit. [ Rule 62 -210.200(Definitions – BACT) and 62-212.400 F.A.C.]
19. New So urce Performance Standard for SO 2 : Pursuant to §60.4330(a)(2), SO 2 emissions are limited in NSPS Subpart KKKK by a prohibition on the firing of any fuels that contain total potential sulfur emissions in excess of 0.060 lb SO 2

20. /MMBtu heat input. Refer to Appendix KKKK of this permit for the full NSPS requirements. [40 CFR 60, Subpart KKKK] Measures to Limit Particulate Emissions (PM/PM 10 /Fine Particulate Matter) : The following measures and limitations , in conjunction with decreases from other units, effec tively limit combined annual PM/PM 10

a. Fuel Sulfur Limits : The sulfur concentration shall be limited to 2 grains per 100 standard cubic feet of natural gas. The sulfur concentration in the distillate fuel oil used shall be limited to 0.05 percent. Compliance with th e fuel specifications shall be demonstrated by keeping records of the fuel sulfur content. emissions to a level that ensures net emissions increases are well below the significant emission rate at which PSD applies and a subsequent BACT determination is required. These measures also minimize fine particulate emissions and formation:

b. Visible Emissions : Visible emissions shall not exceed 10 percent opacity for each 6 -minute block average. Compliance with the visible emissions standard shall be demonstrated by conducting tests in accordance with EPA Method 9. 23

c. Ammonia Emissions (Slip) Limits : Ammonia emissions shall be limited to 5 ppmvd @15% O 2

[62-212.400(12)(PSD Avoidance)] . Compliance with the ammonia slip standard shall be demonstrated by conducting tests in accordance with EPA Method s TM -027 or 320.

E XCESS E MISSIONS {Permitting Note: The following conditions apply only to the SIP- based emissions standards specified in Condition No. 18 of this section. Rule 62 -210.700, F.A.C. (Excess Em issions) cannot vary or supersede any federal provision of the NSPS or Acid Rain programs.}
21. Operating Procedures

22. : The Best Available Control Technology (BACT) determinations established by this permit rely on “good operating practices” to reduce emissions . Therefore, all operators and supervisors shall be properly trained to operate and maintain the CTs, HRSGs, and pollution control systems in accordance with the guidelines and procedures established by each manufacturer. The training shall include good operating practices as well as methods of minimizing excess emissions. [Rules 62- 4.070(3) and 62 -212.400(BACT), F.A.C.]
Alternate Visible Emissions Standard:

23. Visible emissions due to startups, shutdowns, and malfunctions shall not exceed 10% opacity except for up to ten, 6-minute averaging periods during a calendar day, which shall not exceed 20% opacity. [Rule 62-212.400(BACT), F.A.C.]

a. Startup is defined as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution control device imbalances, which result in excess emissions. [Rule 62 -210.200(245), F.A.C.] Definitionsb. Shutdown is the cessation of the operation of an emissions unit for any purpose. [Rule 62 -210.200(230), F.A.C.]

c. Malfunction is defined as any unavoidable mechanical and/or electrical failure of air pollution control equipment or process equipment or of a process resulting in operation in an abnormal or unusual manner. [Ru le 62 -210.200(159), F.A.C.]
24. Excess Emissions Prohibited

25. : Excess emissions caused entirely or in part by poor maintenance, poor operation or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction shall be prohibited. All such preventable emissions shall be included in any compliance determinations based on CEMS data. [Rule 62-210.700(4), F.A.C.]
Allowable Data Exclusions

a. Steam Turbine/HRSG System Cold Startup : For cold startup of the steam turbine system, up to 8 hours of excess emissions from any CT/HRSG system may be excluded in any 24-hour period. A cold “startup of the steam turbine system” is defined as startup of the 4 -on- 1 combined cycle system following a shutdown of the steam turbine lasting at least 48 hours. : As per the procedures in this condition, limited amounts of CO CEMS emissions data may be excluded from the corresponding SIP-based compliance demonstration, provided that best operational practices to minimize emissions are adhered to and the duration of data excluded is minimized. As provided by the authority in Rule 62-210.700(5), F.A.C., these conditions replace the provisions in Rule 62-210.700(1), F.A.C. For each CT/HRSG system, excess emissions resulting from startup, shutdown, and documented malfunctions shall not exceed two hours in any 24-hour period except for the speci fic cases listed below. A “documented malfunction” means a malfunction that is documented within one working day of detection by contacting the Compliance Authority by telephone, facsimile transmittal, or electronic mail.

{Permitting Note: During a cold startup of the steam turbine system, each CT/HRSG system is sequentially brought on line at low load to gradually increase the temperature of the steam-e lectrical turbine and prevent thermal metal fatigue. Note that shutdowns and documented malfunctions are separately regulated in accordance with the requirements of this condition.}
b. Shutdown Combined Cycle Operation : For shutdown of the combined cycle operation, up to 3 hours in any 24- hour period of excess emissions from any CT/HRSG system can be excluded

.

c. CT/HRSG System Cold Startup : For cold startup of a CT/HRSG system, up to 4 hours in any 24-hour period can be excluded. “Cold startup of a CT/HRSG s ystem” is defined as a startup after the pressure in the high

- pressure (HP) steam drum falls below 450 psig for at least a one

- hour period.
d. Simple Cycle CT Startup : For startup of a CT for the purpose of operation in simple cycle mode, up to 1 hour in any 24- hour period of excess emissions can be excluded

.

e. Fuel Switching : For fuel switching, up to 2 hours in any 24-hour period can be excluded.
26. DLN Tuning : CEMS data collected during initial or other major DLN tuning sessions shall be excluded from the CEMS compliance demonstration provided the tuning session is performed in accordance with the manufacturer’s specifications. A “major tuning session” would occur after completion of initial construction, a combustor change

- out, a major repair or maintenance to a combustor, or other similar circumstances. Prior to performing any major tuning session, the permittee shall provide the Compliance Authority with an advance notice of at least 7 days that details the activity and proposed tuning schedule. The notic e may be by telephone, facsimile transmittal, or electronic mail. [Design; Rule 62

- 4.070(3), F.A.C.]E MISSIONS P ERFORMANCE T ESTING
27. Test Methods

Method : Any required tests shall be performed in accordance with the following reference methods.
Descript ion of Method and Comments

CTM -027

320 Procedure for Collection and Analysis of Ammonia in Stationary Source. {Notes: This is an EPA conditional test method.} The minimum detection limit shall be 1 ppm. Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy
7E Determination of Nitrogen Oxide Emissions from Stationary Sources
9 Visual Determination of the Opacity of Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources {Notes: The method shall be based on a continuous sampling train.}

18 Measurement of Gaseous Organic Compound Emissions by Gas Chromatography {Note: EPA Method 18 may be used (optional) concurrently with EPA Method 25A to deduct emissions of methane and ethane from the measured VOC emissions.}
20 Determination of Nitrogen Oxides, Sulfur Dioxide and Diluent Emissions from Stationary Gas Turbines
25A Determination of Volatile Organic Concentrations No other methods may be used unless prior written approval is received from the Department. [Rules 62-204.800, F.A.C.; 40 CFR 60, Appendix A]
28. Initial Compliance Determinations : Each CT shall be stack tested to demonstrate initial compliance with the emission standards for CO, NO X , VOC, visible emissions, and ammonia slip. The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup of each unit configuration. Each unit shall be tested when firing natural gas, when using the duct burners and when firing distillate fuel oil. Reference method data collected during the required Relative Accuracy Test Audits (RATAs) may be used to demonstrate compliance with the in itial CO and NO X compliance tests . With appropriate flow measurements (or fuel measurements and approved F- factors), CEMS data may be used to demonstrate compliance with the CO mass rate emissions standards. CO and NO X

29. emissions recorded by the CEMS shal l also be reported for each run during tests for visible emissions, VOC and ammonia slip. The Department may require the permittee to conduct additional tests after major replacement or major repair of any air pollution control equipment, such as the SCR catalyst, oxidation catalyst, DLN combustors, etc. [Rule 62-297.310(7)(a)1, F.A.C. and 40 CFR 60.8] Continuous Compliance : The permittee shall demonstrate continuous compliance with the 24 -hour and 12- month CO emission standards, and the NO X

30. emissions st andards based on data collected by the certified CEMS. Within 45 days of conducting any RATA on a CEMS, the permittee shall submit a report to the Compliance Authority summarizing results of the RATA. Compliance with the CO emission standards also

serves as an indicator of efficient fuel combustion and oxidation catalyst operation, which reduces emissions of particulate matter and volatile organic compounds. [Rule 62- 212.400 (BACT), F.A.C.] Annual Compliance Tests : During each federal fiscal year (Octob er 1 st to September 30 th ), each CT shall be tested to demonstrate compliance with the emission standards for visible emissions

. CO emissions data collected during the required continuous monitor Relative Accuracy Test Audits (RATAs) may be used to demonstrate compliance with the CO standards. Annual testing to determine the ammonia slip shall be conducted while firing the primary fuel. NO X emissions recorded by the CEMS shall be reported for each ammonia slip test run.{Permitting Note: After initial compliance with the VOC standards is demonstrated, annual compliance tests for VOC emissions are not required. Compliance with the continuously monitored CO standards shall indicate efficient combustion and low VOC emissions. The Department retains the right to require VOC testing for the reasons such as exceedance of the CO limit or those given in Appendix SC, Special Compliance Tests.} [Rules 62-212.400, 62- 210.200 (243) (BACT) , 62-4.070 (3) and 62-297.310(7)(a)4, F.A.C.]
C ONTINUOUS M ONITORING R EQUIRE MENTS
31. CEM Systems : The permittee shall install, calibrate, maintain, and operate continuous emission monitoring systems (CEMS) to measure and record the emissions of CO from the HRSG stacks and NO X from all stacks in a manner sufficient to demonstrate con tinuous compliance with the CEMS emission standards of this section. Each monitoring system shall be installed, calibrated , and properly functioning prior to the initial performance tests. Within one working day of discovering emissions in excess of a CO or NO X

a. CO Monitors. The CO monitors shall be certified pursuant to 40 CFR 60, Appendix B, Performance Specification 4 or 4A within 60 calendar days of achieving permitted capacity as defined in Rule 62

- 297.310(2), F.A.C., but no later than 180 calendar days after initial startup . Quality assurance procedures shall conform to the requirements of 40 CFR 60, Appendix F, and the Data Assessment Repo rt of Section 7 shall be made each calendar quarter, and reported semiannually to the Compliance Authority. The RATA tests required for the CO monitor shall be performed using EPA Method 10 in Appendix A of 40 CFR 60 and shall be based on a continuous sampling train. The CO monitor span values shall be set appropriately considering the allowable methods of operation and corresponding emission standards. standard (and subject to the specified averaging period), the permittee shall notify the Compliance Authority.

b. NO X Monitors. Each NO X monitor shall be certified, operated, and maintained in accordance with the req uirements of 40 CFR 75. Record keeping and reporting shall be conducted pursuant to Subparts F and G in 40 CFR 75. The RATA tests required for the NO X

c. Diluent Monitors. T he oxygen (O monitor shall be performed using EPA Method 20 or 7E in Appendix A of 40 CFR 60.

2 ) or carbon dioxide (CO 2 ) content of the flue gas shall be monitored at the location where CO is monitored to correct the measured emissions rates to 15% oxygen

. If a CO 2

32. monitor is installed, the oxygen content of the flue gas shall be calcu lated using F

- factors that are appropriate for the fuel fired. Each monitor shall comply with the performance and quality assurance requirements of 40 CFR 75. CEM Data Requirements

 Data Collection : Emissions shall be monitored and recorded at all times including startup, operation, shutdown, and malfunction except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments. The CEMS shall be designed and operated to sample, analyze, and record data evenly spac ed over an hour. If the CEMS measures concentration on a wet basis, the CEM system shall include provisions to determine the moisture content of the exhaust gas and an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). Alternatively, the owner or operator may develop through manual stack test measurements a curve of moisture contents in the exhaust gas versus load for each allowable fuel, and use these typical values in an algorithm to enable correction of the monitorin g results to a dry basis (0% moisture). Final results of the CEMS shall be expressed as ppmvd of CO corrected to 15% oxygen and as ppmvd of NO :

X (uncorrected). The CEMS shall be used to demonstrate compliance with the CEMS emission standards for CO and NO X as specified in this permit. For purposes of determining compliance with the CEMS emissions standards of this permit, missing (or excluded) data shall not be substituted. Upon request by the Department, the CEMS emission rates shall be corrected to ISO conditions. Valid Hour : Hourly average values shall begin at the top of each hour. Each hourly average value shall be computed using at least one data point in each fifteen -minute quadrant of an hour, where the unit combusted fuel during that quadrant o f an hour. Notwithstanding this requirement, an hourly value shall be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour). If less than two such data points are avail able, the hourly average value is not valid. An hour in which any oil is fired is attributed towards compliance with the permit standards for oil firing. The permittee shall use all valid measurements or data points collected during an hour to calculate the hourly average values.

 24- hour Block Averages : A 24 -hour block shall begin at midnight of each operating day and shall be calculated from 24 consecutive hourly average emission rate values. If a unit operates less than 24 hours during the block, the 24- hour block average shall be the average of all available valid hourly average emission rate values for the 24 -hour block. For purposes of determining compliance with the 24-hour CEMS standards, the missing data substitution methodology of 40 CFR Part 75, subpart D, shall not be utilized. Instead, the 24-hour block average shall be determined using the remaining hourly data in the 24 -hour block. [Rule 62-212.400(BACT), F.A.C.]

 Data Exclusion: Each CEMS shall monitor and record emissions during all ope rations including episodes of startup, shutdown, malfunction, fuel switches and DLN tuning. Some of the CEMS emissions data recorded during these episodes may be excluded from the corresponding CO CEMS compliance demonstration subject to the provisions of Condition Nos. 25 and 26 of this section. All periods of data excluded shall be consecutive for each such episode and only data obtained during the described episodes (startup, shutdown, malfunction, fuel switches, DLN tuning) may be used for the appropriate exclusion periods. The permittee shall minimize the duration of data excluded for such episodes to the extent practicable. Data recorded during such episodes shall not be excluded if the episode was caused entirely or in part by poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented. Best operational practices shall be used to minimize hourly emissions that occur during such episodes. Emissions of any quantity or duration that occur entirely o r in part from poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented, shall be prohibited.

 Availability : Monitor availability for the CEMS shall be 95% or greater in any calendar quarter. The quart erly excess emissions report shall be used to demonstrate monitor availability. In the event 95% availability is not achieved, the permittee shall provide the Department with a report identifying the problems in achieving 95% availability and a plan of corrective actions that will be taken to achieve 95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective actions or continued failure to achieve the minimum monitor availa bility shall be violations of this permit. [Rules 62- 4.070(3) and 62 -212.400(12), F.A.C.; 40 CFR 75]
33. Ammonia Monitoring Requirements: In accordance with the manufacturer’s specifications, the permittee shall install, calibrate, operate and maintain an amm onia flow meter to measure and record the ammonia injection rate to the SCR system by the time of the initial compliance tests. The permittee shall document and periodically update the general range of ammonia flow rates required to meet permitted emissio ns levels over the range of load conditions allowed by this permit by comparing NO X emissions recorded by the CEM system with ammonia flow rates recorded using the ammonia flow meter. During NO X monitor downtimes or malfunctions, the permittee shall opera te at the ammonia flow rate and, as applicable for fuel oil firing, the water

- to -fuel ratio, that are consistent with the documented flow rate for the CT load condition. [Rules 62-4.070(3), F.A.C.]RECORDS AND REPORTS
34. Monitoring of Capacity

35. : The permittee shall monitor and record the operating rate of each CT and HRSG duct burner system on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown and malfunction). Such monitoring shall be made using a monitoring component of the CEM system required above, or by monitoring daily rates of consumption and heat content of each allowable fuel in accordance with the provisions of 40 CFR 75 Appendix D. [Rules 62- 4.070(3) and 62 -212.400(BACT), F.A.C.] Monthly Operations Summary : By the 10 th

36. calendar day of each month, the permittee shall record the following for each fuel in a written or electronic log for each CT for the previous month of operation: fuel consumption, hours of operation, hours of duct firing, and the updated 12-month rolling totals for each. Information recorded and stored as an electronic file shall be available for inspection and printing within at least three days of a request by the Department. The fuel consumption sha ll be monitored in accordance with the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3), 62-212.400, 62-210.200 (38) and 62- 210.200 (243)(BACT), F.A.C.]
Fuel Sulfur Records

a. Natural Gas Sulfur Limit : Compliance with the fuel sulfur limit for natural gas shall be demonstrated by keeping reports obtained from the vendor indicating the average sulfur content of the natural gas being supplied from the pipeline for each month of operation. Methods for determining the sulfur content of the natural gas shall be ASTM methods D4084-82, D4468-85, D5504-01, D6228-98 and D6667-01, D3246-81 . More recent versions of these methods or other Department approved methods may be used. : The permittee shall demonstrate compliance with the fuel sulfur limits s pecified in this permit by maintaining the following records of the sulfur contents.

b. Distillate Fuel Oil Sulfur Limit : Compliance with the distillate fuel oil sulfur limit shall be demonstrated by taking a sample, analyzing the sample for fuel sulfur, and reportin g the results to each Compliance Authority before initial startup. Sampling the fuel oil sulfur content shall be conducted in accordance with ASTM D4057 -88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, and one of the following test methods for sulfur in petroleum products: ASTM methods D5453-00, D129-91, D1552-90, D2622-94, or D4294- 90. More recent versions of these methods or other Department approved methods may be used. For each subsequent fuel delivery, the permittee shall maintain a permanent file of the certified fuel sulfur analysis from the fuel vendor or other fuel sulfur analysis performed on each delivery. At the request of a Compliance Authority, the permittee shall perform additional sampling and analysis for t he fuel sulfur content. The above methods shall be used to determine the fuel sulfur content in conjunction with the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3) and 62-4.160(15), F.A.C.]
37. Emissions Performance Test Reports : A report indicating the results of any required emissions performance test shall be submitted to the Compliance Authority no later than 45 days after completion of the last test run. The test report shall provide sufficient detail on the tested emission unit and the procedu res used to allow the Department to determine if the test was properly conducted and if the test results were properly computed. At a minimum, the test report shall provide the applicable information listed in Rule 62- 297.310(8)(c), F.A.C. and in Appendix SC of this permit. [Rule 62

- 297.310(8), F.A.C.].38.

a. Malfunction Notification: If emissions in excess of a standard (subject to the specified averaging period) occur due to malfunction, the permittee shall notify the Compliance Authority within (1) working day of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken to correct the problem. In addition, the Department may request a written summary report of the incident. Excess Emissions Reporting:

b. SIP Quarterly Permit Limits Excess Emissions Report : Within 30 days following the end of each calendar -quarter, the permittee shall submit a report to the Compliance Authority summarizing periods of CO emissions in excess of the BACT permit standards following the NSPS format in 40 CFR 60.7(c), Subpart A. Periods of startup, shutdown and malfunction, shall be monitored, recorded and reported as excess emissions when emission levels exceed the standards specified in this permit. In addition, the repor t shall summarize the CEMS systems monitor availability for the previous quarter. A summary of data excluded from SIP compliance calculations should also be provided.

c. NSPS Semi-Annual Excess Emissions Reports : Within thirty (30) days following each calen dar semi

annual period, the permittee shall submit a report on any periods of excess emissions of the applicable NSPS that occurred during the previous semi -annual period

. {Note: If there are no periods of excess emissions as defined in NSPS Subpart KKK K, a statement to that effect may be submitted with the SIP Quarterly Report to suffice for the NSPS Semi -Annual Report.} [Rules 62-4.130, 62-204.800, 62-210.700(6), F.A.C.; 40 CFR 60.7 and Subpart KKKK ]
39. Annual Operating Report: The permittee shall submit an annual report that summarizes the actual operating hours and emissions from this facility. The permittee shall also keep records sufficient to determine the annual throughput of distillate fuel oil for the fuel oil storage tank for use in the Annual O perating Report. Annual operating reports shall be submitted to the Compliance Authority by March 1st of each year. [Rule 62 -210.370(2), F.A.C.]This section of the permit addresses the following emissions units.

ID Emission Unit Description
043 One L arge Gas eous-fueled Auxiliary B oiler (99 MMBTU/h r and 85,000 lb/hr) 044 Five Small G as eous -fueled Process Heaters ( 3 MMBtu/hr)

A PPLICABLE S TANDARDS AND R EGULATIONS
1. PSD and BACT Applicability

[Rule 62 -212.400, F.A.C.] : The Rules for the Prevention of Significant Deterioration (PS D) of Air Quality apply to this project and require BACT determinations for carbon monoxide (CO) and volatile organic c ompounds (VOC) for these emissions units

.

2. NESHAP Subpart DDDDD Applicability

[40 CFR 63, Subpart DDDDD - National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, or Institutional Boiler or Process Heater] : The 99 MMBTU/hr (85,000 lb/hr) a uxiliary boiler is subject to all applicable requirements of 40 CFR 63, Subpart DDDDD, which applies to an industrial, commercial, or institutional boiler or process heater as defined in Sec. 63.7575 that is located at, or is part of, a major source of HAP as defined in Sec. 40 CFR 63.2.

3. NSPS Subpart Dc Applicability

[ Rule 62 -204.800(7)(b) and 40 CFR 60, Dc - Standards of Performance for Small Industrial- Commercial

Institutional Steam Generating Units, attached as Appendix Dc] : The 99 MMBTU/hr (85,000 lb/hr) au xiliary boiler is subject to all applicable requirements of 40 CFR 60, Subpart Dc which applies to Small Industrial, Commercial, or Institutional Boiler. Specifically, this emission unit shall comply with 40 CFR60.48c Reporting and Recordkeeping Requireme nts.

EQUIPMENT , CAPACITIES AND LIMITATIONS ON OPERATION
4. Equipment

5. : The permittee is authoriz ed to install, operate, and maintain one auxiliary boiler with a maximum design heat input of 99 MMBtu/hr (85,000 lb/hr) to produce steam during start up of the CTs and five 3 MMBtu/hr process heaters for the purpose of heating the natural gas supply

. [A pplicant Request; Rule 62 -210.200(PTE), F.A.C.] Hours of Operation

E MISSIONS , F UELS AND T ESTING R EQUIREMENTS : The hours of operation of the limited use gas- fueled auxiliary boiler shall not exceed 1,000 hours per year. The gas -fueled process heaters are allowed to operate continuously (8760 hour s per year). [Applicant Request; Rule 62 -210.200(PTE), F.A.C. and 40 CFR 63.7575]

6. Auxiliary Boiler Emissions Limit
CO (BACT, Subpart DDDDD) s : VOC (BACT) 0.08 lb/MMBtu, 400 ppmvd @3% O 10% Opacity, Natural Gas Specification of 2 gr S/100 SCF 2 [Rule 62 -212.400, F.A.C.; 40 CFR 60, Subpart Dc; 40 CFR 63, Subpart DDDDD]
7. Auxiliary Boiler Testing Requirements

[Rule 62 -297.310(7)(a)1, F.A.C. and 40 CFR 63.7] : This unit shall be stack tested to demonstrate initial compliance with the emission standards for CO and vis ible emissions. The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup of each combined cycle unit.8. Auxiliary Boiler Test Method

Method s : Any required tests shall be performed in accordance with the following reference methods.
Description of Method and Comments
9 Visual Determination of the Opacity of Emissions from Stationary Sour ces

10 Determination of Carbon Monoxide Emissions from Stationary Sources {Notes: The method shall be based on a continuous sampling train.}

9. Annual CO Performance Test for Auxiliary Boilers

[40 CFR 63.7515 and Rule 62-204.800(11)(b)84. F.A.C.] : Pursuant to 40 CFR 63.7515(e) permittee shall conduct an annual CO test according to Sec. 63.7520. Each annual performance test must be conducted between 10 and 12 months after the previous performance test.

10. Natural Gas Fired Process Heaters Emissions Limit
CO (BACT) s : VOC (BACT)
0.08 lb/MMBtu 10% Opacity, Natural Gas Specification of 2 gr S/100 SCF
[Rule 62 -212.400, F.A.C.]
11. Natural Gas Fired Process Heaters Testing Requirements

[Rule 62 -297.310(7)(a)1, F.A.C. and 40 CFR 60.8] : Each unit shall be stack tested to demonstrate initial compliance with the emission standards for CO and visible emissions. The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup of each combined cycle unit. As an alternative, a Manufacturer certification of emissions characteristics of the purchased model that are at least as stringent as the BACT values can be used to fulfill this requirement.

12. Natural Gas Fir ed Process Heaters Test Method

Method s : Any required tests shall be performed in accordance with the following reference methods.
Description of Method and Comments
9 Visual Determination of the Opacity of Emissions from Stationary Sources

10 Determinat ion of Carbon Monoxide Emissions from Stationary Sources {Notes: The method shall be based on a continuous sampling train.}

N OTIFICATION , R EPORTING AND R ECORDS
13. Notification

14. : Initial notification is required for the limited use 99 MMBtu/hr gas -fueled aux iliary boiler. I nitial notification is not required for the five small gas

- fueled 3 MMBtu/hr process heaters. [40 CFR 63.9, 40 CFR 63.7506(c) and Rule 62-204.800(11)(b) F.A.C.] Reporting: The permittee shall maintain records of the amount of natural gas used in the heaters and auxiliary boilers. These records shall be submitted to the Compliance Authority on an annual basis or upon request. [Rule 62- 4.070(3] F.A.C.]This section of the permit addresses the following emissions unit.

ID Emission Unit De scription
045 Two Nominal 3.5 million gallon distillate fuel oil storage tanks

A PPLICABLE S TANDARDS AND R EGULATIONS
1. PSD and BACT Applicability

NSPS A PPLICABILITY : The Rules for the Prevention of Significant Deterioration (PSD) of Air Quality apply to this project and re quire BACT determinations for volatile organic compounds (VOC) for these emissions units.

2. NSPS Subpart Kb Applicability

EQ UIPMENT , CAPACITIES AND USAGE : The distillate fuel oil tanks are not subject to Subpart Kb, which applies to any storage tank with a capacity grea ter than or equal to 10,300 gallons (40 cubic meters) that is used to store volatile organic liquids for which construction, reconstruction, or modification is commenced after July 23, 1984. Tanks with a capacity greater than or equal to 40,000 gallons (151 cubic meters) storing a liquid with a maximum true vapor pressure less than 3.5 kPa are exempt from the General Provisions (40 CFR 60, Subpart A) and from the provisions of NSPS Subpart Kb. [40 CFR 60.110b(a) and (c); Rule 62-204.800(7)(b), F.A.C.]

3. Equipment

4. : The permittee is authorized to install, operate, and maintain two 3.5 million gallon distillate fuel oil storage tank designed to provide low sulfur fuel oil to the gas turbines. [Applicant Request; Rule 62 -210.200(PTE), F.A.C.] Hours of Operation

N OTIFICATION , R EPORTING AND R ECORDS : The hours of operation are not restricted (8760 hours per year). [Applicant Request and Rule 62-210.200(PTE), F.A.C.]

5. Oil Tank Records

6. : The permittee shall keep readily accessible records showing the dimension of each storage vessel and an analysis showing the capacity of each storage tank. Records shall be retained for the life of the facility. The permittee shall also keep records sufficient to determine the annual throughput o f distillate fuel oil for each storage tank for use in the Annual Operating Report. [Rule 62 -4.070(3) F.A.C]
Fuel Oil Records: The permittee shall keep readily accessible records showing the maximum true vapor pressure of the stored liquid. The maximum true vapor pressure shall be less than 3.5 kPa. Compliance with this condition may be demonstrated by using the information from the respective M aterial Safety Data Sheets (M SDS ) for the low sulfur fuel oil stored in the tanks. [ Rule 62-4.070(3) and 62-212.400, F.A.C.]This section of the permit addresses the following emissions unit.

ID Emission Unit Description
046 One nominal 300- hp emergency diesel fire pump engine and 500 gallon fuel oil storage tank.

A PPLICABLE S TANDARDS AND R EGULATIONS
1. PSD and BACT Applicability

2. : The Rules for the Prevention of Significant Deterioration (PSD) of Air Quality apply to this project and require BACT determinations for carbon monoxide (CO) and volatile organic compounds (VOC) for these emissions units. NSPS Subpart IIII Applicability

[40 CFR 60, Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines]. : This fire pump engine is an Emergency Stationary Compression Ignition Internal Combustion Engine (Stationary ICE) and is subject to 40 CFR 60, Subpart IIII. It shall comply with 40 CFR 60, Subpart IIII only to the extent that the regu lations apply to the emissions unit and its operations (e.g. fire pumps, horsepower, model year selected).

EQUIPMENT , CAPACITIES AND USAGE
3. Equipment

4. : The permittee is authorized to install, operate, and maintain one diesel engine driven fire pump (approximately 300 hp) and an associated 500 g allon fuel oil storage tank. Hours of Operation

E MISSIONS , F UELS AND T ESTING R EQUIREMENTS: The fire pump may operate in response to emergency conditions and 40 nonemergency hours per year for maintenance testing. [Applicant Request; Rule 62 -210.200 (PTE), F.A.C.

5. Authorized Fuel

Compliance with the distillate fuel oil sulfur limit shall be demonstrated by taking a sample, analyzing the sample for fuel sulfur, and reporting the re sults to each Compliance Authority before initial startup. Sampling the fuel oil sulfur content shall be conducted in accordance with ASTM D4057-88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, and one of the following test methods for sulfur in petroleum products: ASTM methods D5453-00, D129-91, D1552-90, D2622-94, or D4294-90. More recent versions of these methods or other Department approved methods may be used. For each subsequent fuel delivery, the permittee shall maintain a permanent file of the certified fuel sulfur analysis from the fuel vend or. At the request of a Compliance Authority, the permittee shall perform additional sampling and analysis for the fuel sulfur content. : This unit shall fire low sulfur fuel oil (or superior fuel), which shall contain no more than 0.05% sulfur by weight. [Rules 62-210.200(PTE) and 62- 212.400 (BACT), F.A.C.]

6. Fire Pump Engine Emissions Limits
The fo llowing limits apply based on the size category of the fire pump located at the facility. :

Size (hp) CO (BACT, IIII) NMHC*+NO X PM (BACT for VOC, IIII) 175 and greater 2.6 gm/bhp-hr 7.8 gm/bhp-hr 0.40

Note 1. Non- Methane Hydrocarbons (NMHC) are surrogate for VOC.
7. Fire Pump Engine Certification : Manufacturer certification shall be provided to the Department in lieu of actual testing. [Rule 62-212.400 (BACT), F.A.C. and 40 CFR 60.4211]

# H. Florida Power and Light – Cape Canaveral

Emission Units shut

- down: 1. EU001 – Unit #1 (BART)
2. EU002 – Unit #2 (BART)

Items included: 1. Letter from facility with Acid Rain, CAIR, and Hg Budget Retired Unit Exemption notice for Fossil Fuel Steam Generator Unit #1.

2. Letter from facility with Acid Rain, CAIR, and Hg Budget Retired Unit Exemption notice for Fossil Fuel Steam Generator Unit #2.Florida Power & Light Company. 700 Universe Blvd. Juno Beach. FL33408



# RECEIVED

Mr. David McNeal USEP A, Region 4 Atlanta Federal Center 61 Forsyth Street, SW Atlanta, Georgia 30303-3104



### Re: Submittal of Retired Unit Exemption FPL Cape Canaveral Unit I ORIS Code 609 UnitID PCCI

Dear 

### Mr. McNeal: 

# JUl' 272010
BUREAU OF 

### AIR REGULATION

Attached is a Retired Unit Exemption Fonn (40 CFR 72.8) for the above referenced PCC 1 which is submitted for your approval. This unit was taken out of service 

### in July of 2010. I am therefore submitting the attached for your record files.

If further infonnation is desired please contact me via telephone at 561-691-2287 or Elisa Ostertag at 561-691-2341.

Designated Representative Florida Power & 

### Light

Attachment

Cc: Trina Vielhauer, Bureau of Air Regulation FDEP USEP A, Clean Air Markets Division Tammy Pratt, Cape Canaveral Environmental Specialist File

an FPL Group company

# &EPA

STEP 1 Identify the unit by facility (source) name, State, ORIS/plant code and unit 10#.

STEP 2 Indicate the program(s) that the unit is subject to:

STEP 3 Identify the date on which the unit was (or will be) permanently retired.

STEP4 If the unit is subject to the Acid Rain Program, identify the first full calendar year in which the unit meets (or will meet) the requirements of 40 CFR 72.8(d).

STEPS Read the appropriate special provisions. United States Environmental Protection Agency Acid Rain and CAIR Program OMB Nos. 2060-0258 and 2060-0570 Approval Expires 11/30/2012 

# Retired Unit Exemption

For more information, see instructions and refer to 40 CFR 72.8, 96.105, 96.205, and 96.305, or a comparable state regulation, as applicable.

This submission is:**~New** DReVised

State ORIS/Plant Code

Facility (Source) Name CAPE CANAVERAL 

### FL 000609

-Acid Rain

- CAIR NO x Annual

- CAIR S02

- CAIR NO x Ozone Season 

# I JULY " 2010


# I Janua", " -,2=.;0::...;1:....:1

__ _

Acid Rain Program Special Provisions Unit 10# PCC1

(1) A unit exempt under 40 CFR 72.8 shall not emit any sulfur dioxide and nitrogen oxides starting on the date that the exemption takes effect. The owners and operators of the unit will be allocated allowances in accordance with 40 CFR part 73 subpart B. (2) A unit exempt under 40 CFR 72.8 shall not resume operation unless the designated representative of the source that includes the unit submits a complete Acid Rain permit application under 40 CFR 72.31 for the unit not less than 24 months prior to the date on which the unit is first to resume operation. (3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under 40 CFR 72.8 shall comply with the requirements of the Acid Rain Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) For any period for which a unit is exempt under 40 CFR 72.8, the unit is not an affected unit under the Acid Rain Program and 40 CFR part 70 and 71 and is not eligible to be an opt-in source under 40 CFR part 74. As an unaffected unit, the unit shall continue to be subject to any other applicable requirements under 40 CFR parts 70 and 71. (5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 72.8**sh~ill** retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the Administrator or the permitting authority. The
owners and operators bear the burden of proof that the unit is permanently retired. (6) On the earlier of the following dates, a unit exempt under 40 CFR 72.8(b) or (c) shall lose its exemption and become an affected unit under the Acid Rain Program and 40 CFR part 70 and 71: (i) the date on which the deSignated representative submits an Acid Rain permit application under paragraph (2); or (ii) the date on which the designated representative is required under paragraph (2) to submit an Acid Rain permit application. For the purpose of applying monitoring requirements under 40 CFR part 75, a unit that loses its exemption under 40 CFR 72.8 shall be treated as a new unit that commenced commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)Retired Unit Exemption Page 2 Plant Name (from STEP 1) CAPE CANAVERAL

CAIR NOx Annual Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.1 05(a) shall not emit any nitrogen oxides, starting on the date that the exemption takes effect. (2) The permitting authority will allocate CAIR NOx allowances under 40 CFR 96 subpart EE to a unit exempt under 40 CFR 96.1 05(a). (3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 96.105(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.1 05(a) shall comply with the requirements of the CAIR NOx Annual Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (5) A unit exempt under 40 CFR 96.105(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.122 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation.

. (6) On the earlier of the following dates, a unit exempt under 40 CFR 96.1 05(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.105(b)(5); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.105(b)(5) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit. (7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under 40 CFR 96 subpart HH, a unit that loses its exemption under 40 CFR 96.105(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

CAIR S02 Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.205(a) shall not emit any sulfur dioxide, starting on the date that the exemption takes effect. (2) For a period of 5 years from the elate the records are created, the owners and operators of a unit exempt under 40 CFR 96.205(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (3) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.205(a) shall comply with the requirements of the CAIR 802 Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) A unit exempt under 40 CFR 96.205(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.222 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the unit resumes operation. ' (5) On the earlier of the following dates, a unit exempt under 40 CFR 96.205(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.205(b)(4); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.205(b)(4) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit. (6) For the purpose of applying monitoring, reporting, and record keeping requirements under 40 CFR 96 subpart HHH, a unit that loses its exemption under 40 CFR 96.205(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)Retired Unit Exemption
Page 3 Plant Name (from STEP 1) CAPE CANAVERAL

CAIR NOx Ozone Season Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.305(a) shall not emit any nitrogen oxides, starting on the date that the exemption takes effect. (2) The permitting authority will allocate CAIR NOx Ozone Season allowances under 40 CFR 96 subpart EEEE to a unit exempt under 40 CFR 96.305(a). (3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 96.305(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.305(a) shall comply with the requirements of the CAIR NOx Ozone Season Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (5) A unit exempt under 40 CFR 96.305(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.322 for the unit not less than.18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation. (6) On the earlier of the following dates, a 'unit exempt under 40 CFR 96.305(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.305(b)(5); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.305(b)(5) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit. (7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under 40 CFR 96 subpart HHHH, a unit that loses its exemption under 40 CFR 96.305(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)STEPS Read the statement of compliance and the appropriate certification statements and sign and date. Retired Unit Exemption
Page 4 Plant Name (from STEP 1) CAPE CANAVERAL

Statement of Compliance I certify that the unit identified above at STEP 1 was (or will be) permanently retired on the date identified at STEP 3 and will comply with the appropriate Special Provisions listed at STEP 5.

Certification (for Acid Rain or CAIR designated representatives or alternate Acid Rain or CAIR designated representatives Q!!h1 I am authorized to make this submission on behalf of. the owners and operators of the source and unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and 'belief true, accurate, and complete. I am aware that there are significant penalties for submitting :false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.

Name SHEILA M. WILKINSON Title DESIGNATED REPRESENTATIVE

Owner Company Name FLORIDA POWER & LIGHT

Phone 561-691-2287 Emailsheila.m.wilkinson@fpl.com

Signature Date 

# u

Certification (for certifying officials of units subject to the Acid Rain Program only) I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.

Name Title

Owner Company Name

Phone Email

Signature Date

EPA Form 7610-20 (Revised 12-2009)Florida Power & Light Company, 700 Universe Blvd, Juno Beach, FL 33408



## F=PL.

Mr. David McNeal USEP A, Region 4 Atlanta Federal Center 61 Forsyth Street, SW Atlanta, Georgia 30303-3104



### Re: Submittal of Retired Unit Exemption FPL Cape Canaveral Unit 2 ORIS 

### Code 609 UnitID PCC2

Dear Mr. McNeal: 

# RECEIVED

JUL' 27 

# 2010
BUREAU OF AIR REGULATION

Attached is a Retired Unit Exemption Form (40 CFR 72.8) for the above referenced peC2 which is submitted for your approval. This unit was taken out of service in July of 2010. I am therefore submitting the attached for your record files.

If further information is desired please contact me via telephone at 561-691-2287 or Elisa Ostertag at 561-691-2341.

# Si~j;;

# stl:~.~~ Designated Representative Florida Power & 

### Light

Attachment

Cc: Trina Vielhauer, Bureau of Air Regulation FDEP USEP A, Clean Air Markets Division Tanuny Pratt, Cape Canaveral Environmental Specialist File

an FPL Group company

# &EFJ\

STEP 1 Identify the unit by facility (source) name, State, ORIS/plant code and unit ID#.

STEP 2 Indicate the program(s) that the unit is subject to:

STEP 3 Identify the date on which the unit was (or will be) permanently retired.

STEP 4 If the unit is subject to the Acid Rain Program, identify the first full calendar year in which the unit meets (or will meet) the requirements of 40 CFR 72.8(d).

STEP 5 Read the appropriate special provisions. United States Environmental Protection Agency Acid Rain and CAIR Program OMS Nos. 2060-0258 and 2060-0570 Approval Expires 11/3012012 

# Retired Unit Exemption

For more information, see instructions and refer to 40 CFR 72.8, 96.105, 96.205, and 96.305, or a comparable state regulation, as applicable.

This submission is:**~** New 

# D Revised

State ORIS/Plant Code

Facility (Source) Name CAPE CANANVERAL FL 000609

-Acid Rain

- CAl R NO x Annual

- CAIR S02

- CAIR NO x Ozone Season 

# I
JULY " 2010


# I January " ----'2:..:0:....:1'-'-1

__ _

Acid Rain Program Special Provisions Unit ID# peC2

(1) A unit exempt under 40 CFR 72.8 shall not emit any sulfur dioxide and nitrogen oxides starting on the date that the exemption takes effect. The owners and operators of the unit will be allocated allowances in accordance with 40 CFR part 73 subpart B. (2) A unit exempt under 40 CFR 72.8 shall not resume operation unless the designated representative of the source that includes the unit submits a complete Acid Rain permit application under 40 CFR 72.31 for the unit not less than 24 months prior to the date on which the unit is first to resume operation. (3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under 40 CFR 72.8 shall comply with the requirements of the Acid Rain Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) For any period for which a unit is exempt under 40 CFR 72.8, the unit is not an affected unit under the Acid Rain Program and 40 CFR part 70 and 71 and is not eligible to be an opt-in source under 40 CFR part 74. As an unaffected unit, the unit shall continue to be subject to any other applicable requirements under 40 CFR parts 70 and 71. (5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 72.8 shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the Administrator or the permitting authority. The
owners and operators bear the burden of proof that the unit is permanently retired. (6) On the earlier of the following dates, a unit exempt under 40 CFR 72.8(b) or (c) shall lose its exemption and become an affected unit under the Acid Rain Program and 40 CFR part 70 and 71: (i) the date on which the designated representative submits an Acid Rain permit application under paragraph (2); or (ii) the date on which the designated representative is required under paragraph (2) to submit an Acid Rain permit application. For the purpose of applying monitoring requirements under 40 CFR part 75, a unit that loses its exemption under 40 CFR 72.8 shall be treated as a new unit that commenced commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)Retired Unit Exemption Page 2 Plant Name (from STEP 1) CAPE CANANVERAL

CAIR NOx Annual Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.1 05(a) shall not emit any nitrogen oxides, starting on the date that the exemption takes effect. (2) The permitting authority will allocate CAIR NOx allowances under 40 CFR 96 subpart EE to a unit exempt under 40 CFR 96.1 05(a). (3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 96.105(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.1 05(a) shall comply with the requirements of the CAIR NOx Annual Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (5) A unit exempt under 40 CFR 96.1 05(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.122 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation. (6) On the earlier of the following dates, a unit exempt under 40 CFR 96.1 05(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.1 05(b)(5); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.105(b)(5) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAl R permit application for the unit. (7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under 40 CFR 96 subpart HH, a unit that loses its exemption under 40 CFR 96.105(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

CAIR S02 Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.205(a) shall not emit any sulfur dioxide, starting on the date that the exemption takes effect. (2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 96.205(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (3) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.205(a) shall comply with the requirements of the CAIR 802 Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (4) A unit exempt under 40 CFR 96.205(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.222 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the unit resumes operation. (5) On the earlier of the following dates, a unit exempt under 40 CFR 96.205(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.205(b)(4); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.205(b)(4) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit. (6) For the purpose of applying monitoring, reporting, and recordkeeping requirements under 40 CFR 96 subpart HHH, a unit that loses its exemption under 40 CFR 96.205(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)Retired Unit Exemption

Plant Name (from STEP 1) CAPE CANANVERAL Page 3

CAl R NOx Ozone Season Trading Program Special Provisions
(1) A unit exempt under 40 CFR 96.305(a) shall not emit any nitrogen oxides, starting on the date that the exemption takes effect. (2) The permitting authority will allocate CAIR NOx Ozone Season allowances under 40 CFR 96 subpart EEEE to a unit exempt under 40 CFR 96.305(a). (3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under 40 CFR 96.305(a) shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired. (4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under 40 CFR 96.305(a) shall comply with the requirements of the CAIR NOx Ozone Season Trading Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect. (5) A unit exempl;under 40 CFR 96.305(a) and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under 40 CFR 96.322 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation. (6) On the earlier of the following dates, a unit exempt under 40 CFR 96.305(a) shall lose its exemption: (i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under 40 CFR 96.305(b)(5); (ii) The date on which the CAIR designated representative is required under 40 CFR 96.305(b)(5) to submit a CAIR permit application for the unit; or (iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit. (7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under 40 CFR 96 subpart HHHH, a unit that loses its exemption under 40 CFR 96.305(a) shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.

EPA Form 7610-20 (Revised 12-2009)STEPS Read the statement of compliance and the appropriate certification statements and sign and date. Retired Unit Exemption Page 4 Plant Name (from STEP 11 CAPE CANANVERAL

Statement of Compliance I certify that the unit identified above at STEP 1 was (or will be) permanently retired on the date identified at STEP 3 and will comply with the appropriate Special Provisions listed at STEP 5.

Certification (for Acid Rain or CAIR designated representatives or alternate Acid Rain or CAIR designated representatives only) I am authorized to make this submission on behalf of the owners and operators of the source and unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting .false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.

Name SHEILA M. WILKINSON Title DESIGNATED REPRESENTATIVE

Owner Company Name FLORIDA POWER & LIGHT

Email sheila.m.wilkinson@fpl.com

Signature Date

Certification (for certifying officials of units subject to the Acid Rain Program only) I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.

Name Title

Owner Company Name

Phone Email

Signature Date

EPA Form 7610-20 (Revised 12-2009)

# I. Florida Power and Light - Riviera

Emission Units shut

- down: 1. EU004 – Unit #4 (BART)

Items included: Air Construction Permit ( 0990042

- 006

- AC)

.

# Florida Department of

**Environmental Pro tection** 

**Bob Martinez Center 2600 Blairstone Ro**  **ad Tallahassee, Florida 32399-2400**  **Charlie Crist Governor**  **Jeff Kottk amp**  **Lt. Governor Michael W. Sole**  **Secretary**



### PERMITTEE:

**Florida Power and**

**Light Company (FPL) 700 Universe Boulevard**  **Juno Beach, Florida 33408**
Authorized Representative: **Randall R. LaBauve, Vice President DEP File No. 0990042-006-AC**  **FPL Riviera Beach Energy Center Plant Conversion Project**  **Palm Beach County SIC No. 4911**  **Expires: December 31, 2015**

PROJECT AND LOCATION **This permit authorizes the construction of one nominal 1,250 megawatts (MW) combined cycle unit and ancillary equipment at the FPL Riviera Beach Energy Center previously known as the Riviera**  **Plant. Two existing steam generators with a total nominal capacity of 600 MW will be shut down and**  **dismantled as part of this project. The proposed project will be located at 200-300 Broadway, Riviera Beach in Palm Beach County.**  **The UTM coordinates are Zone 17, 594.249 km East and 2960.632 km North.**

STATEMENT OF BASIS **This air construction permit is issued under the provisions of Chapter 403 of the Florida Statutes (F.S.), Chapters 62-4, 62-204, 62-210, 62-212, 62-296 and 62-297 of the Florida Administrative**  **Code (F.A.C.). The permittee is authorized to install the proposed equipment in accordance with the conditions of this permit and as described in the application, approved drawings, plans, and**  **other documents on file with the Department.**

CONTENTS
**Section I. General Information Section II. Administrative Requirements**  **Section III. Emissions Units Specific Conditions Section IV. Appendices** 

**Joseph Kahn, Director (Date)**  **Division of Air Resource Management**SECTION I. GENERAL INFORMATION

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 2 of 24** FACILITY DESCRIPTION **FPL operates the R i**  **viera Plant (RP), which is an existing power plant (SIC No. 4911). The plant currently consists of two steam generating units designated as Units 3 and 4 that produce 300 MW each of electrical**  **power. Units 3 and 4 use residual fuel oil and natural gas. There are two 298-foot stacks, four fuel oil storage tanks, water intake structures for once-through cooling and other ancillary equipment.**  **The project is a plant conversion that includes the construction of a nominal 1,250 MW natural gas-fueled combined cycle unit (Unit 5) and requires the permanent shutdown and dismantling of Units 3 and 4. The**  **converted plant will be called the Riviera Beach Energy Center (RBEC). Unit 5 will consist of:**

• **Three nominal 265 MW combustion turbine-electrical generators (CTG) with evaporative inlet cooling systems;** 

• **Three supplementary-fired heat recovery steam generators (HRSG) with selective catalytic reduction (SCR) reactors;** 

• **Three maximum 460 million Btu per hour, lower heating value (mmBtu/hr, LHV), natural gas-fueled duct burners (DB) located in the three HRSG (one DB/HRSG);** 

• **Three 149-feet exhaust stacks;**

• **One nominal 6.3 million gallon distillate fuel oil storage tank; and**

• **One common nominal 500 MW steam-electrical generator (STG). Unit 5 will use ultralow sulfur distillate (ULSD) fuel oil as backup fuel.**  **Additional ancillary equipment to be installed includes: a permanent auxiliary boiler; a temporary boiler used during the construction phase; two emergency generators; two process (fuel) heaters; a diesel fire pump; and a**  **gas compression station. The details of the equipment to be installed are listed in the table below. The project includes and requires the permanent shutdown and dismantling of Units 3 and 4 and the respective**  **stacks as well as four fuel oil storage tanks. When emissions from Unit 5 are considered and offset by reductions from the shut down and dismantlement of Units 3 and 4, there will not be a significant net emission**  **increase in any PSD pollutant.** {Note: Throughout this permit, the electrical generating capacities represent nominal values for the given operating conditions.}
NEW EMISSIONS UNITS **This permit authorizes construction and installation of the following new emissions units.**

ID Emission Unit Description **007 Unit 5A – one nominal 265 MW CTG with supplementary-fired HRSG 008 Unit 5B – one nominal 265 MW CTG with supplementary-fired HRSG**  **009 Unit 5C – one nominal 265 MW CTG with supplementary-fired HRSG 010 One nominal 85,000 pounds per hour (lb/hr) auxiliary boiler (99.8 mmBtu/hr)**  **011 Two nominal 10 mmBtu/hr natural gas-fired process heaters (one is a spare) 012 Seven nominal 1,340 horsepower (hp) natural gas compressors**  **013 Two nominal 2,250 kilowatts (kW) liquid fueled emergency generators 014 One nominal 300-hp emergency diesel fire pump engine and 500 gallon fuel oil storage tank**  **015 One temporary 110 mmBtu/hr natural gas-fueled boiler to be used only during construction 016 One nominal 6.3 million gallon distillate fuel oil storage tank** SECTION I. GENERAL INFORMATION

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 3 of 24** REGULATORY CLASSIFICATION **The RP is a “Major**

**S tationary Source”**  **as defined in Rule 62-210.200, Florida Administrative Code (F.A.C.). The RBEC project does not trigger the rules for the Prevention of Significant Deterioration (PSD) pursuant to**  **Rule 62-212.400, F.A.C. and does not require a best available control technology (BACT) determination. The RBEC will be a Title V or “Major Source” of air pollution**  **in accordance with Chapter 213, F.A.C. because the potential emissions of at least one regulated pollutant exceed 100 tons per year (TPY). Regulated pollutants**  **include pollutants such as carbon monoxide (CO), nitrogen oxides (NO X**  **), particulate matter (PM/PM 10**  **/PM 2.5**  **), sulfur dioxide (S**  **O 2**  **), volatile organic compounds (VOC) and sulfuric acid mist (SAM). The RBEC will be s**  **ub**

**ject to several subparts under 40 Code of Federal Regulations (CFR), Part 60 – Standards**  **of Performance for New Stationary Sources (NSPS). Unit 5 is subject to 40 CFR 60, Subpart KKKK – NSPS for Stationary Combustion Turbines that Commence Construction after February 18, 2005. This rule also**  **applies to duct burners (DB) that are incorporated into combined cycle projects. Two emergency generators will be subject to 40 CFR 60, Subpart IIII – NSPS for Stationary Compression**  **Ignition Internal Combustion Engines. Natural gas compressors will be subject to 40 CFR 60, Subpart JJJJ – NSPS for Stationary Spark Ignition**  **Internal Combustion Engines. The temporary natural gas-fueled boiler will be subject to 40 CFR 60, Subpart Db – NSPS for Industrial**  **Commercial-Institutional Steam Generating Units. The auxiliary boiler and two process (fuel) heaters will be subject to 40 CFR 60, Subpart Dc – NSPS**  **Requirements for Small Industrial-Commercial-Institutional Steam Generating Units. The RBEC will be a minor (area source) of hazardous air pollutants (HAP)**  **. The RBEC will include emission units that will be subject to certain area source provisions of 40 CFR Part 63 - National Emission Standards for**  **Hazardous Air Pollutants (NESHAP). The specific subpart is 40 CFR 63, Subpart ZZZZ – NESHAP for Stationary Reciprocating Internal Combustion Engines (RICE).**  **The RBEC will operate units subject to the Title IV Acid Rain provisions of the Clean Air Act (CAA)**

**. The RBEC is subject to the Clean Air Interstate Rule (CAIR)**  **in accordance with the Final Department Rules issued pursuant to CAIR as implemented by the Department in Rule 62-296.470, F.A.C.**  **The project is subject to certification under the Florida Power Plant Siting Act , 403.501-518, Florida Statutes**  **(F.S.) and Chapter 62-17, F.A.C.**
APPENDICES **The following Appendices are attached as part of this permit. Appendix A: Identification of General Provisions Subpart A from NSPS 40 CFR 60 and**  **Subpart A from NESHAP 40 CFR 63. Appendix GC: General Conditions.**  **Appendix Db: NSPS Subpart Db Requirements for Industrial-Commercial-Institutional Steam Generating Units.**  **Appendix Dc: NSPS Subpart Dc Requirements for Small Industrial Commercial-Institutional Steam Generating Units.**  **Appendix IIII: NSPS Requirements for Compression Ignition Internal Combustion Engines. Appendix JJJJ: NSPS Requirements for Stationary Spark Ignition Internal Combustion Engines.**  **Appendix KKKK: NSPS Requirements for Gas Turbines, 40 CFR 60, Subpart KKKK. Appendix SC: Standard Conditions.**  **Appendix XS: Semiannual NSPS Excess Emissions Report. Appendix ZZZZ: NESHAP Requirements for Stationary Reciprocating Internal Combustion Engines,**  **40 CFR 63, Subpart ZZZZ.**SECTION I. GENERAL INFORMATION

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 4 of 24** RELEVANT DOCUMENTS
**The documents li s**  **ted below are not a part of this permit; however, they are specifically related to this permitting action and are on file with the Department.** 

• **Permit application received on February 13, 2009;**

• **Department request for additional information (RAI) dated March 13, 2009;**

• **Electronic mail dated April 13, 2009 summarizing resolution of key RAI issue; and**

• **Draft permit package issued on April 17, 2009.**

• **Final Determination summarizing FPL comments and responses thereto issued concurrently with this Final permit.** SECTION II. ADMINISTRATIVE REQUIREMENTS

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 5 of 24 1.**  **Permitting Authority : All documents related to applications for permits to construct, operate or modify an**  **emissions unit shall be submitted to the Permitting Authority, which is the Bureau of Air Regulation of the Florida Department of Environmental Protection (DEP or the Department) at 2600 Blair Stone Road, MS**  **#5505, Tallahassee, Florida 32399-2400. Copies of all such documents shall also be submitted to the Compliance Authority. Telephone: (850)488-0114. Fax: (850)921-9533.** 
**2. Compliance Authority**  **: All documents related to compliance activities such as reports, tests, and notifications shall be submitted to the Southeast District Office. The mailing address and phone number of**  **the Southeast District Office are Department of Environmental Protection, Southeast District Office, 400 North Congress Avenue, Suite 200, West Palm Beach, Florida 33401. Telephone: (561)681-6632.**  **Fax: (561)681-6790.**
**3. Appendices**  **: The following Appendices are attached as part of this permit: Appendices A, Db, Dc, GC (General Conditions), IIII, JJJJ, KKKK, SC, XS and ZZZZ.** 
**4. Applicable Regulations, Forms and Application Procedures**  **: Unless otherwise specified in this permit, the construction and operation of the subject emissions units shall be in accordance with the capacities and**  **specifications stated in the application. The facility is subject to all applicable provisions of: Chapter 403, F.S.; and Chapters 62-4, 62-204, 62-210, 62-212, 62-213, 62-214, 62-296, and 62-297, F.A.C. Issuance of**  **this permit does not relieve the permittee from compliance with any applicable federal, state, or local permitting or regulations.** 

**5. New or Additional Conditions**  **: For good cause shown and after notice and an administrative hearing, if requested, the Department may require the permittee to conform to new or additional conditions. The**  **Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and on application of the permittee, the Department may grant additional time. [Rule 62-4.080, F.A.C.]** 
**6. Modifications**  **: No emissions unit shall be constructed or modified without obtaining an air construction permit from the Department. Such permit shall be obtained prior to beginning construction or modification.**  **[Rules 62-210.300(1) and 62-212.300(1)(a), F.A.C.]**

**7. Construction and Expiration**  **: The permit expiration date includes sufficient time to complete construction, perform required testing, submit test reports, and submit an application for a Title V operation permit to the**  **Department. For good cause, the permittee may request that this air construction permit be extended. Such a request shall be submitted to the Department’s Bureau of Air Regulation at least sixty (60) days prior to**  **the expiration of this permit. [Rules 62-4.070(4), 62-4.080, and 62-210.300(1), F.A.C.]**
**8. Permanent Shutdown and Dismantlement of Units 3 and 4**  **: Units 3 and 4 shall be permanently shut down and dismantled before December 31, 2012.**  **[Application and Avoidance of Rule 62-212.400(4) through (12), F.A.C.]**
**9. Source Obligation**  **: At such time that a particular source or modification becomes a major stationary source or major modification (as these terms were defined at the time the source obtained the enforceable**  **limitation) solely by virtue of a relaxation in any enforceable limitation which was established after August 7, 1980, on the capacity of the source or modification otherwise to emit a pollutant, such as a restriction on**  **hours of operation, then the requirements of subsections 62-212.400(4) through (12), F.A.C., shall apply to the source or modification as though construction had not yet commenced on the source or modification.**  **[Rule 62-212.400(12)(b), F.A.C.]**
**10. Title IV Permit**  **: At least 24 months before the date on which the new unit begins serving an electrical generator greater than 25 MW, the permittee shall submit an application for a Title IV Acid Rain Permit to**  **the Department’s Bureau of Air Regulation in Tallahassee and a copy to the Region 4 Office of the U.S. Environmental Protection Agency (EPA) in Atlanta, Georgia. This permit does not specify the Acid Rain**  **program requirements. These will be included in the Title V air operation permit. [40 CFR 72]**SECTION II. ADMINISTRATIVE REQUIREMENTS

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 6 of 24 11.**  **Title V Permit : This permit authorizes specific modifications and/or new construction on the affected**  **emissions units as well as initial operation to determine compliance with conditions of this permit. A Title V operation permit is required for regular operation of the permitted emissions unit. The permittee shall**  **apply for a Title V operation permit at least 90 days prior to expiration of this permit, but no later than 180 days after completing the required work and commencing operation. To apply for a Title V operation**  **permit, the applicant shall submit the appropriate application form, compliance test results, and such additional information as the Department may by law require. The application shall be submitted to the**  **Bureau of Air Regulation with copies to the Compliance Authority. [Rules 62-4.030, 62-4.050, 62-4.220, and Chapter 62-213, F.A.C.]** SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 7 of 24 This section of the permit addresses the following emissions units.** 

Unit 5 and associ a ted equipment Description **: Unit 5 will be comprised of emissions units (EU) 007, 008, and 009. Each EU will consist of: a CTG with automated control, inlet air filtration system and evaporative cooling, a gas-fired HRSG with DB, a**  **HRSG stack, and associated support equipment. The project also includes one STG that will serve the combined cycle unit.** 
Fuels **: Each CTG fires natural gas as the primary fuel and ULSD fuel oil as a restricted alternate fuel.** Generating Capacity **: Each of the three CTG has a nominal generating capacity of 265 MW. The STG has a nominal generating capacity of 500 MW. The total nominal generating capacity of the “3 on 1” combined cycle**  **unit is approximately 1,250 MW.** Controls **: The efficient combustion of natural gas and restricted firing of ULSD fuel oil minimizes the emissions of CO, PM/PM**  **10 , SAM, SO**  **2 and VOC. Dry Low-NO**  **X (DLN) combustion technology for gas firing and water**  **injection for oil f** 

**iring reduce NO X**  **emissions. A SCR system further reduces NO X**  **emissions.** Stack Parameters **: Each HRSG has a stack at least 149 feet tall with a nominal diameter of 22 feet. The Department may require the permittee to perform additional air dispersion modeling should the actual specified**  **stack dimensions change.**
Continuous Monitors **: Each stack is equipped with continuous emissions monitoring systems (CEMS) to measure and record CO and NO**  **X emissions as well as flue gas oxygen or carbon dioxide content.** 

APPLICABLE STANDARDS AND REGULATIONS **1. NSPS Requirements**  **: The CTG shall comply with all applicable requirements of 40 CFR 60, listed below, adopted by reference in Rule 62-204.800(7)(b), F.A.C. The Department determines that compliance with**  **the emissions standards in Condition 10 below also assures compliance with the New Source Performance Standards given in 40 CFR 60, Subpart KKKK. Some separate reporting and monitoring may be required**  **by the individual subparts.**

**a.** Subpart A, General Provisions **, including:**

• **40 CFR 60.7, Notification and Record Keeping**

• **40 CFR 60.8, Performance Tests**

• **40 CFR 60.11, Compliance with Standards and Maintenance Requirements**

• **40 CFR 60.12, Circumvention**

• **40 CFR 60.13, Monitoring Requirements**

• **40 CFR 60.19, General Notification and Reporting Requirements**
**b.** Subpart KKKK, Standards of Performance for Stationary Gas Turbines **: These provisions include standards for CTG and DB.** 
EQUIPMENT AND CONTROL TECHNOLOGY **2. Combustion Turbines-Electrical Generators (CTG)**  **: The permittee is authorized to install, tune, operate, and maintain three “G” or “H” technology CTG each with a nominal generating capacity of 265 MW. Each**  **CTG shall include an automated control system and have dual-fuel capability. Ancillary equipment includes an inlet air filtration system and an evaporative inlet air-cooling system. The CTG will utilize**  **DLN combustors. [Application and Design]**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 8 of 24 3.**  **Heat Recovery Steam Generators (HRSG) : The permittee is authorized to install, operate, and maintain**  **three new HRSG with separate exhaust stacks. Each HRSG shall be designed to recover exhaust heat energy from one of the three CTG (5A to 5C) and deliver steam to the steam turbine-electrical generator**  **(STG). Each HRSG may be equipped with a gas-fired duct burner (DB) having a maximum heat input rate of 460 mmBtu per hour (LHV).** 
**4. CTG/Supplementary-fired HRSG Emission Controls** 

**a.** Dry Low NO X (DLN) Combustion **: The permittee sh all operate and maintain the DLN system to control**  **NO X**  **emissions from each CTG when firing natural gas. Prior to the initial emissions performance tests required for each**  **CTG, the DLN combustors and automated control system shall be tuned to achieve sufficiently low CO and NO**  **X values to meet the CO and NO**  **X limits with the additional SCR control**  **technology descr ibed below. Thereafter, each turbine shall be maintained and tuned in accordance with**  **the manufacturer’s recommendations.**
**b.** Wet Injection (WI) **: The permittee shall install, operate, and maintain a WI system (water or steam) to reduce NO**  **X emissions from each CTG when firing ULSD fuel oil. Prior to the initial emissions**  **performance test s required for each CTG, the WI system shall be tuned to achieve sufficiently low CO**  **and NO X**  **values to meet the CO and NO X**  **limits with the additional SCR control technology described below. Thereafter**  **, each turbine shall be maintained and tuned in accordance with the manufacturer’s recommendations.** 

**c.** Selective Catalytic Reduction (SCR) System **: The permittee shall install, tune, operate, and maintain an SCR system to control NO**  **X emissions from each CTG when firing either natural gas or distillate fuel**  **oil. The SCR system**

**consists of an ammonia (NH 3**  **) injection grid, catalyst, ammonia storage, monitoring and co**  **ntrol system, electrical, piping and other ancillary equipment. The SCR system shall be designed, constructed and operated to achieve the permitted levels for NO**  **X and NH**  **3 emissions.** 
**d.** Oxidation Cata lyst **: The permittee shall design and build the project to facilitate possible future** **installation of an oxidation catalyst system to control CO emissions from each CTG/supplementary fired HRSG.** 

**e.** Ammonia Storage: **In accordance with 40 CFR 60.130, the storage of ammonia shall comply with all applicable requirements of the Chemical Accident Prevention Provisions in 40 CFR 68.**  **[Application and Design; Rule 62-4.070, F.A.C.]**
PERFORMANCE RESTRICTIONS

**5. Permitted Capacity – Combustion Turbine-Electric Generators (CTG)**  **: The maximum heat input rate to each CTG is 2,586 mmBtu per hour when firing natural gas and 2,440 mmBtu per hour when firing**  **distillate fuel oil (based on a compressor inlet air temperature of 59° F, LHV of each fuel, and 100% load). Heat input rates will vary depending upon CTG characteristics, ambient conditions, alternate methods of**  **operation, and evaporative cooling. The permittee shall provide manufacturer’s performance curves (or equations) that correct for site conditions to the Permitting and Compliance Authorities within 45 days of**  **completing the initial compliance testing. Operating data may be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department.**  **[Rule 62-210.200(PTE), F.A.C.]**
**6. Permitted Capacity - HRSG Duct Burners (DB)**  **: The total maximum heat input rate to the DB for each HRSG is 460 mmBtu per hour based on the LHV of natural gas. Only natural gas shall be fired in the DB.**  **[Rule 62-210.200(PTE), F.A.C.]**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 9 of 24 7.**  **Authorized Fuels : The CTG shall fire natural gas as the primary fuel, which shall contain no more than 2.0**  **grains of sulfur per 100 standard cubic feet (gr S/100 SCF) of natural gas. As a restricted alternate fuel, the CTG may fire ULSD fuel oil containing no more than 0.0015% sulfur by weight. Fuel oil may be fired up**  **to the fuel equivalent of 2,550 hours aggregated over the three CTG during any calendar year. [Rules 62-210.200(PTE), F.A.C.]** 
**8. Hours of Operation:**  **Subject to the operational restrictions of this permit, the CTG may operate throughout the year (8760 hours per year). Restrictions on individual methods of operation are specified below.**  **[Rules 62-210.200(Definitions - PTE), F.A.C.]**
**9. Methods of Operation**  **: Subject to the restrictions and requirements of this permit, the CTG may operate under the following methods of operation.** 

**a.** Combined Cycle Operation **: Each CTG/HRSG system may operate to produce direct, shaft-driven electrical power and steam-generated electrical power from the steam turbine-electrical generator as a**  **three-on-one combined cycle unit subject to the restrictions of this permit. In accordance with the specifications of the SCR and HRSG manufacturers, the SCR system shall be on line and functioning**  **properly during combined cycle operation or when the HRSG is producing steam.**
**b.** Inlet Conditioning **: In accordance with the manufacturer’s recommendations and appropriate ambient conditions, the evaporative cooling system may be operated to reduce the compressor inlet air**  **temperature and provide additional direct, shaft-driven electrical power.**

**c.** Duct Burner (DB) Firing **: When firing natural gas in a CTG, the respective HRSG may fire natural gas in the DB to raise additional steam for use in the STG or in the operation of CTG components. The**  **total combined heat input rate to the DB (all three HRSG) shall not exceed 3,697,920 mmBtu (LHV) during any consecutive 12 months.**  **[Application; Rule 62-210.200(PTE), F.A.C.]**
EMISSIONS STANDARDS

**10. Emissions Standards**  **: Emissions from each CTG/DB shall not exceed the following standards developed under state implementation plan (SIP) permitting procedures. Compliance with these limits also assures**  **compliance with the emission limitations in 40 CFR 60, Subpart KKKK.**

**Pollutant Fuel**  **Method of Operation Initial Stacks Tests**  **CEMS Rolling Average Limit ppmvd**  **a ppmvd**  **a lb/hr**  **b**

**CO d**  **Oil CTG 10.0 61.0**  **10.0, 30 unit operating days c**  **,d**

**Gas CTG & DB**  **7.6 52.7 7.5, 30 unit operating days**  **c,d**

**CTG Normal Mode 5.0 29.0**

**NO X**  **e Oil CTG**  **8.0 80.0 8 .0, 30 unit operating days**  **c,e**

**Gas CTG & DB**  **2.0 22.8 2.0, 30 unit operating days**  **c,e**

**CTG Normal Mode 2.0 19.3**

**VOC f**  **Oil CTG 6.0 18.9**  **NA**

**Gas CTG & DB**  **1.9 7.2**

**CTG Normal Mode 1.5 4.8 NH**  **3 g**  **Oil/Gas CTG, All Modes 5 NA NA** 
**SAM/SO 2**  **h Oil/Gas All Modes**  **2 gr S/100 SCF of ga s, 0.0015% sulfur fuel oil**  **Visible emissions shall not exceed 10% opacity for**

**each 6-minute block average. PM/PM**  **10 i** SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 10 of 24 a.**  **Concentration standards are given in terms of parts per million, by volume, dry at 15 percent oxygen and abbreviated as ppmvd.**  **b. The ma**  **s s emission rate standards in pounds per hour (lb/hr) are based on a turbine inlet condition of 59° F and may be adjusted**  **to actual test conditions in accordance with the performance curves and/or equations filed with the Department.** 

**c. “Unit operating day” means a 24-hour period between 12 midnight and the following midnight during which any fuel is**  **combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. [40 CFR 60.4420]**  **d. Compliance with the continuous 30-unit operating days rolling CO standard shall be demonstrated based on data collected by**  **the required CEMS. The initial EPA Method 10 tests associated with the certification of the CEMS instruments shall also be used to demonstrate initial performance guarantees for natural gas, oil, and DB mode.** 

**e. Continuous compliance with the 30-unit operating days rolling NO**  **X standards shall be demonstrated based on data collected**  **by the required CEMS and will also insure compliance with the less stringent Subpart KKKK limits of 15 and 42 ppmvd for gas and fuel oil respectively on a 30-unit operating day rolling average basis. The initial EPA Method 7E or Method 20 tests**  **associated with demonstration of compliance with 40 CFR 60, Subpart KKKK or certification of the CEMS instruments shall also be used to demonstrate compliance with the individual standards for natural gas, fuel oil, and duct burner modes during**  **the time of those tests. NO X**  **mass emission rates are defined as oxides of nitrogen expressed as nitrogen dioxide (NO 2**  **). f.**  **Compliance with the VOC standards shall be demonstrated by conducting tests in accordance with EPA Method 25A. Optionally, EPA Method 18 may also be performed to deduct emissions of methane and ethane. The emission standards are**  **based on VOC measured as methane. After initial compliance with the VOC standards is demonstrated, annual compliance tests for VOC emissions are not required.** 
**g. Compliance with the NH**  **3 slip standard shall be demonstrated by conducting tests in accordance with EPA Method CTM-027**  **or EPA Method 320. h.**  **The clean fuel sulfur specifications and visible emissions standard effectively limit the potential emissions of SAM and SO 2**  **from the CTG. Compliance with the fuel sulfur specifications shall be determined by the ASTM methods for determination of fuel sulfur as detailed in the draft permit.**  **i. The clean fuel sulfur specifications, low CO and NO**  **X limits, and the visible emissions standard will effectively limit**  **PM/PM 10**  **/PM 2.5**  **emissions. Compliance with the visible emissions standard shall be demonstrated by conducting tests in accordance with EPA Method 9.**  **[Application and Avoidance of Rule 62-212.400(4) through (12), F.A.C.; 40 CFR 60, Subpart KKKK]**
EXCESS EMISSIONS {Permitting Note: The following conditions apply only to the SIP-based emissions standards specified in Condition No. 10 of this section. Rule 62-210.700, F.A.C. (Excess Emissions) cannot vary or supersede any federal provision of the NSPS, or Acid Rain programs.}
**11. Operating Procedures**  **: The emission standards established by this permit rely on “good operating practices” to reduce emissions. Therefore, all operators and supervisors shall be properly trained to operate**  **and maintain the CTG, DB, HRSG, and pollution control systems in accordance with the guidelines and procedures established by each manufacturer. The training shall include good operating practices as well as**  **methods of minimizing excess emissions. [Rules 62-4.070(3), F.A.C.]**
**12. Alternate Visible Emissions Standard:**  **Visible emissions due to startups, shutdowns, and malfunctions shall not exceed 10% opacity except for up to ten, 6-minute averaging periods during a calendar day, which**  **shall not exceed 20% opacity. [Applicant Request and Rule 62-4.070(3), F.A.C.]**
**13. Definitions:** 

**a.** Startup **is defined as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution**  **control device imbalances, which result in excess emissions. [Rule 62-210.200(245), F.A.C.]**
**b.** Shutdown **is the cessation of the operation of an emissions unit for any purpose. [Rule 62-210.200(230), F.A.C.]** SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 11 of 24 c.**  Malfunction **is defined as any unavoidable mechanical and/or electrical failure of air pollution control equipment or pr**  **o cess equipment or of a process resulting in operation in an abnormal or unusual**  **manner. [Rule 62-210.200(159), F.A.C.]**
**14. Excess Emissions Prohibited**  **: Excess emissions caused entirely or in part by poor maintenance, poor operation or any other equipment or process failure that may reasonably be prevented during startup,**  **shutdown or malfunction shall be prohibited. All such preventable emissions shall be included in any compliance determinations based on CEMS data. [Rule 62-210.700(4), F.A.C.]** 
**15. Excess Emissions Allowed**  **: As specified in this condition, excess emissions resulting from startup, shutdown, fuel switching and documented malfunctions are allowed provided that operators employ the**  **best operational practices to minimize the amount and duration of emissions during such incidents. For each CTG/HRSG system, NO**  **X and CO emission data exclusions resulting from startup, shutdown, or**  **documented malfu nctions shall not exceed two hours in any 24-hour period except for the specific cases**  **listed below. A “documented malfunction” means a malfunction that is documented within one working day of detection by contacting the Compliance Authority by telephone, facsimile transmittal, or electronic**  **mail.**

a. STG/HRSG System Cold Startup: For cold startup of the steam turbine system, NO X and CO emission data exclusions for

any CTG/HRSG system shall not exceed eight (8) hours in any 24-hour period. A cold “startup of the steam turbine system” is defined as startup of the 3-on-1 combined cycle system following a shutdown of the steam turbine lasting at least 48 hours. {Permitting Note: During a cold startup of the STG system, each CTG/HRSG system is sequentially brought on line at low load to gradually increase the temperature of the STG and prevent thermal metal fatigue. Note that shutdowns and documented malfunctions are separately regulated in accordance with the requirements of this condition.}
b. Shutdown Steam Turbine System: For shutdown of steam turbine system, NO X and CO emission data exclusions for any C T

G/HRSG system shall not exceed three (3) hours in any 24-hour period.

c. CTG/HRSG System Cold Startup: For cold startup of a CTG/HRSG system, NO X and CO emission data exclusions sha ll not exceed four (4) hours in any 24-hour period. “Cold startup of a CTG/HRSG system” is defined as a startup after the pressure in the high-pressure (HP) steam drum falls below 450 psig for at least a one-hour period.
d. Fuel Switching: For fuel switching, NO X and CO emission data exclusions shall not exceed two (2) hours in any 24-hou r period.
**16. Ammonia Injection**  **: Ammonia injection shall begin as soon as operation of the CTG/HRSG system achieves the operating parameters specified by the manufacturer. As authorized by Rule 62-210.700(5),**  **F.A.C., the above conditions allow excess emissions only for specifically defined periods of startup, shutdown, fuel switching, and documented malfunction of the CTG.**  **[Design; Rules 62-4.070(3) and 62-210.700, F.A.C.]**
**17. DLN Tuning**  **: CEMS data collected during initial or other major DLN tuning sessions may be excluded by the permittee from the CEMS compliance demonstration provided the tuning session is performed in**  **accordance with the manufacturer’s specifications. A “major tuning session” may occur after completion of initial construction, a major repair, or other similar circumstances. Prior to performing any major tuning**  **session, where the intent is to exclude data from the CEMS compliance demonstration, the permittee shall provide the Compliance Authority with an advance notice of at least 7 days that details the activity and**  **proposed tuning schedule. The notice may be by telephone, facsimile transmittal, or electronic mail. [Design; Rule 62-4.070(3), F.A.C.]** SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 12 of 24** EMISSIONS PERFORMANCE TESTING
**18. Test Methods**  **: Required tests shall be performed in accordance with the following reference methods.**
Method Description of Method and Comments
**CTM-027**

**or 320**  **Procedure for Collection and Analysis of Ammonia in Stationary Source. {Notes:**

**This is an EPA conditional test method. The minimum detection limit shall be 1 ppm.} Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive**  **Fourier Transform Infrared (FTIR) Spectroscopy 7E Determination of Nitrogen Oxide Emissions from Stationary Sources**  **9 Visual Determination of the Opacity of Emissions from Stationary Sources**

**10 Determination of Carbon Monoxide Emissions from Stationary Sources {Notes: The method**  **shall be based on a continuous sampling train. The ascarite trap may be omitted or the interference trap of section 10.1 may be used in lieu of the silica gel and ascarite traps.}** 

**18 Measurement of Gaseous Organic Compound Emissions by Gas Chromatography**  **{Note: EPA Method 18 may be used (optional) concurrently with EPA Method 25A to deduct emissions of methane and ethane from the measured VOC emissions.}** 

**20 Determination of Nitrogen Oxides, Sulfur Dioxide and Diluent Emissions from Stationary Gas**  **Turbines 25A Determination of Volatile Organic Concentrations**  **No other methods may be used for compliance testing unless prior written approval is received from the administrator of the Department’s Emissions Monitoring Section in accordance with an alternate sampling**  **procedure pursuant to 62-297.620, F.A.C. [Rules 62-204.800 and 62-297.100, F.A.C.; 40 CFR 60, Appendix A]** 
**19. Initial Compliance Determinations**  **: Initial compliance tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after**  **the initial startup of the unit. Each CTG shall be stack tested to demonstrate initial compliance with the emission standards for CO, NO**  **X , VOC, visible emissions, and ammonia slip. Each unit shall be tested**  **when firing natur al gas, when using the duct burners and when firing distillate fuel oil. Referenced method**  **data collected during the required Relative Accuracy Test Audits (RATAs) may be used to demonstrate compliance with the initial CO and NO**  **X standards. With appropriate flow measurements (or fuel**  **measurements and**

**approved F-factors), CEMS data may be used to demonstrate compliance with the CO and NO**  **X mass rate emissions standards. CO and NO**  **X emissions recorded by the CEMS shall also be**  **reported for each run during tests for visible emissions, VOC and ammonia slip. The Department may**  **require the permittee to conduct additional tests after major replacement or major repair of any air pollution control equipment, such as the SCR catalyst, oxidation catalyst, DLN combustors, etc.**  **[Rule 62-297.310(7)(a)1, F.A.C. and 40 CFR 60.8].**
**20. Continuous Compliance**  **: The permittee shall demonstrate continuous compliance with the 30-unit operating days rolling average CO and NO**  **X emissions standards based on data collected by the certified**  **CEMS. Within 45 day s of conducting any RATA on a CEMS, the permittee shall submit a report to the**  **Compliance Authority summarizing results of the RATA. Compliance with the CO emission standards also serves as an indicator of efficient fuel combustion and oxidation catalyst operation, which reduces**  **emissions of particulate matter and volatile organic compounds. [Rule 62-4.070(3), F.A.C.; 40 CFR 60, Subpart KKKK]** SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 13 of 24 21.**  **Annual Compliance Tests : During each federal fiscal year (October 1**  **st to September 30**  **th ), each CTG shall**  **be tested to demon strate compliance with the emission standards for visible emissions and ammonia slip.**  **Testing to determine the ammonia slip shall be conducted while firing the primary fuel. NO X**  **emissions recorded by the CE**  **MS shall be reported for each ammonia slip test run. CO emissions recorded by the CEMS shall be reported for the visible emissions observation period.**  {Permitting Note: After initial compliance with the VOC standards is demonstrated, annual compliance tests for VOC emissions are not required. Compliance with the continuously monitored CO standards shall indicate efficient combustion and low VOC emissions. The Department retains the right to require VOC testing if CO limits are exceeded or for the reasons given in Appendix SC, Condition 17, Special Compliance Tests.} **[Rules 62-4.070(3) and 62-297.310(7)(a)4, F.A.C.]**
**22. Compliance for SAM, SO**  **2 and PM/PM**  **10 /PM**  **2.5 : In stack compliance testing is not required for SAM, SO**  **2 and PM/PM**  **10 /PM**  **2.5 . Com**  **pliance with the limits and control requirements for SAM, SO 2**  **and PM/PM**  **10 /PM**  **2.5 is base**  **d on the recordkeeping required in Specific Condition 28, the visible emissions standard and the C**  **O/NO X**  **continuous monitoring. [Rule 62-4.070(3), F.A.C.]**
CONTINUOUS MONIT ORING REQUIREMENTS
**23. Continuous Emissions Monitoring System(s) (CEMS)**  **: The permittee shall install, calibrate, maintain, and operate CEMS to measure and record the emissions of CO and NO**  **X from the combined cycle CTG in a**  **manner sufficien t to demonstrate continuous compliance with the CEMS emission standards of this section.**  **Each monitoring system shall be installed, calibrated, and properly functioning prior to the initial performance tests. Within one working day of discovering emissions in excess of a CO or NO**  **X standard**  **(and subject to the specified averaging period), the permittee shall notify the Compliance Authority.** 

**a.** CO Monitors: **The CO monitors shall be certified pursuant to 40 CFR 60, Appendix B, Performance Specification 4 or 4A within 60 calendar days of achieving permitted capacity as defined in Rule 62-**  **297.310(2), F.A.C., but no later than 180 calendar days after initial startup. Quality assurance procedures shall conform to the requirements of 40 CFR 60, Appendix F, and the Data Assessment**  **Report in Section 7 shall be made each calendar quarter, and reported semiannually to the Compliance Authority. The RATA tests required for the CO monitor shall be performed using EPA Method 10 in**  **Appendix A of 40 CFR 60 and shall be based on a continuous sampling train. The CO monitor span values shall be set appropriately considering the allowable methods of operation and corresponding**  **emission standards.**
**b.** NO

X Monitors: **Each NO X**  **monitor sh a**  **ll be certified, operated, and maintained in accordance with the requirements of 4**  **0 CFR 75. Record keeping and reporting shall be conducted pursuant to Subparts F and G in 40 CFR 75. The RATA tests required for the NO**  **X monitor shall be performed using EPA**  **Method 20 or 7E in A ppendix A of 40 CFR 60.** 

**c.** Diluent Monitors: **The oxygen (O 2**  **) or carbon dioxide (CO 2**  **) content of the flue gas shall be monitored at the location wh**  **ere CO and NO X**  **are monitored to correct the measured emissions rates to 15% oxygen. If a CO**  **2 monit**  **or is installed, the oxygen content of the flue gas shall be calculated using F factors that are a**  **ppropriate for the fuel fired. Each monitor shall comply with the performance and quality assurance requirements of 40 CFR 75.** 
**24. CEMS Data Requirements**  **:**

**a.** Data Collection **: Emissions shall be monitored and recorded at all times including startup, operation, shutdown, and malfunction except for continuous monitoring system breakdowns, repairs, calibration**  **checks, and zero and span adjustments. The CEMS shall be designed and operated to sample, analyze,**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 14 of 24 and record data evenly spaced over an hour. If the CEMS measures concentration on a wet basis, the**  **CEM system shall i**  **nclude provisions to determine the moisture content of the exhaust gas and an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). Alternatively, the**  **owner or operator may develop through manual stack test measurements a curve of moisture contents in the exhaust gas versus load for each allowable fuel, and use these typical values in an algorithm to**  **enable correction of the monitoring results to a dry basis (0% moisture). Final results of the CEMS shall be expressed as ppmvd corrected to 15% oxygen. The CEMS shall be used to demonstrate**  **compliance with the CEMS emission standards for CO and NO X**  **as specified in this permit. For purposes of dete**  **r mining compliance with the CEMS emissions standards of this permit, missing (or**  **excluded) data shall not be substituted. Upon request by the Department, the CEMS emission rates shall be corrected to International Organization of Standardization (ISO) conditions.** 
**b.** Valid Hour **: Hourly average values shall begin at the top of each hour. Each hourly average value shall be computed using at least one data point in each fifteen-minute quadrant of an hour, where the unit**  **combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly value shall be computed from at least two data points separated by a minimum of 15 minutes (where the unit**  **operates for more than one quadrant of an hour). If less than two such data points are available, the hourly average value is not valid. An hour in which any oil is fired is attributed towards compliance**  **with the permit standards for oil firing. The permittee shall use all valid measurements or data points collected during an hour to calculate the hourly average values.** 

**c.** 30-Unit Operating Day Rolling Averages **: Compliance shall be determined after each operating day by calculating the arithmetic average of all the valid hourly averages from that operating day and the prior**  **29 operating days. For purposes of determining compliance with the 30-unit operating day rolling CEMS standards, the missing data substitution methodology of 40 CFR Part 75, subpart D, shall not be**  **utilized. Instead, the 30-unit operating day rolling average shall be determined using the remaining hourly data in the 30-day rolling period.**  {Permitting Note: There may be more than one 30-unit operating day compliance demonstration required for CO and NO X emissions depending on the use of alternate fuels.}
**d.** Data Exclusion : **E ach CEMS shall monitor and record emissions during all operations including**  **episodes of startup, shutdown, malfunction, fuel switches and DLN tuning. Some of the CEMS emissions data recorded during these episodes may be excluded from the corresponding CEMS**  **compliance demonstration subject to the provisions of Condition Nos. 15 and 17 of this section. All periods of data excluded shall be consecutive for each such episode and only data obtained during the**  **described episodes (startup, shutdown, malfunction, fuel switches, DLN tuning) may be used for the appropriate exclusion periods. The permittee shall minimize the duration of data excluded for such**  **episodes to the extent practicable. Data recorded during such episodes shall not be excluded if the episode was caused entirely or in part by poor maintenance, poor operation, or any other equipment or**  **process failure, which may reasonably be prevented. Best operational practices shall be used to minimize hourly emissions that occur during such episodes. Emissions of any quantity or duration that**  **occur entirely or in part from poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented, shall be prohibited.** 

**e.** Data Exclusion during Installation of Oxidation Catalyst: **The permittee may exclude CO CEMS data in excess of the 7.5 ppmvd @15% O**  **2 from the 30 operating day rolling average calculation during the**  **installation of t he oxidation catalyst (which shall not exceed 12 months) provided all reasonable efforts**  **are used to minimize such emissions. However, all CEMS data must be included when determining whether there is a net emission increase [as defined in Section 62-210.200 (definitions), F.A.C.] of CO**  **greater or equal to the significant emissions rate of 100 tons per year.**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 15 of 24 f.**  Availability **: Monitor avail a**  **bility for the CEMS shall be 95% or greater in any calendar quarter. The quarterly excess emissions report shall be used to demonstrate monitor availability. In the event 95%**  **availability is not achieved, the permittee shall provide the Department with a report identifying the problems in achieving 95% availability and a plan of corrective actions that will be taken to achieve**  **95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective actions or continued failure to achieve the minimum**  **monitor availability shall be violations of this permit, except as otherwise authorized by the Department’s Compliance Authority.**  **[Rule 62-297.520, F.A.C.; 40 CFR 60.7(a)(5) and 40 CFR 60.13; 40 CFR Part 51, Appendix P; 40 CFR 60, Appendix B - Performance Specifications; 40 CFR 60, Appendix F - Quality Assurance Procedures; and**  **Rules 62-4.070(3), F.A.C.]**
**25. Ammonia Monitoring Requirements:**  **In accordance with the manufacturer’s specifications, the permittee shall install, calibrate, operate and maintain an ammonia flow meter to measure and record the ammonia**  **injection rate to the SCR system by the time of the initial compliance tests. The permittee shall document and periodically update the general range of ammonia flow rates required to meet permitted emissions**  **levels over the range of load conditions allowed by this permit by comparing NO X**  **emissions recorded by the CEM system wit**  **h ammonia flow rates recorded using the ammonia flow meter. During NO X**  **monitor downtimes or malf** 

**unctions, the permittee shall operate at the ammonia flow rate and, as applicable for fuel oil firing, the water-to-fuel ratio, that are consistent with the documented flow rate for the combustion**  **turbine load condition. [Rules 62-4.070(3), F.A.C.]**
RECORDS AND REPORTS
**26. Monitoring of** 

**Capacity : The permittee shall monitor and record the operating rate of each CTG and HRSG**  **DB system on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown, malfunction and fuel switching). Such monitoring shall be made**  **using a monitoring component of the CEMS required above, or by monitoring daily rates of consumption and heat content of each allowable fuel in accordance with the provisions of 40 CFR 75 Appendix D.**  **[Rule 62-4.070(3), F.A.C.]**
**27. Monthly Operations Summary**  **: By the fifth calendar day of each month, the permittee shall record the following for each fuel in a written or electronic log for each CTG for the previous month of operation: fuel**  **consumption, hours of operation, hours of duct firing, and the updated 12-month rolling totals for each. Information recorded and stored as an electronic file shall be available for inspection and printing within at**  **least three days of a request by the Department. The fuel consumption shall be monitored in accordance with the provisions of 40 CFR 75, Appendix D. [Rules 62-4.070(3), F.A.C.]** 
**28. Fuel Sulfur Records**  **: The permittee shall demonstrate compliance with the fuel sulfur limits specified in this permit by maintaining the following records of the sulfur contents.** 

**a.** Natural Gas: **Compliance with the fuel sulfur limit for natural gas shall be demonstrated by keeping reports obtained from the vendor indicating the average sulfur content of the natural gas being supplied**  **from the pipeline for each month of operation. Methods for determining the sulfur content of the natural gas shall be ASTM methods D4084-82, D4468-85, D5504-01, D6228-98 and D6667-01,**  **D3246-81 or more recent versions.**
**b.** ULSD Fuel Oil: **Compliance with the distillate fuel oil sulfur limit shall be demonstrated by taking a sample, analyzing the sample for fuel sulfur, and reporting the results to each Compliance Authority**  **before initial startup. Sampling the fuel oil sulfur content shall be conducted in accordance with ASTM D4057-88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, and one of**  **the following test methods for sulfur in petroleum products: ASTM methods D5453-00, D129-91,**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS A. UNIT 5 – COMBUSTION TURBINE GENERATORS (EU 007, 008, and 009)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 16 of 24 D1552-90, D2622-94, or D4294-90. More recent versions of these methods may be used. For each**  **subsequent fuel d e**  **livery, the permittee shall maintain a permanent file of the certified fuel sulfur analysis from the fuel vendor. At the request of a Compliance Authority, the permittee shall perform**  **additional sampling and analysis for the fuel sulfur content. The above methods shall be used to determine the fuel sulfur content in conjunction with the provisions of**  **40 CFR 75, Appendix D. [Rules 62-4.070(3) and 62-4.160(15), F.A.C.]**
**29. Emissions Performance Test Reports**  **: A report indicating the results of any required emissions performance test shall be submitted to the Compliance Authority no later than 45 days after completion of**  **the last test run. The test report shall provide sufficient detail on the tested emission unit and the procedures used to allow the Department to determine if the test was properly conducted and if the test**  **results were properly computed. At a minimum, the test report shall provide the applicable information listed in Rule 62-297.310(8)(c), F.A.C. and in Appendix SC of this permit. [Rule 62-297.310(8), F.A.C.].** 
**30. Excess Emissions Reporting:** 

**a.** Malfunction Notification: **If emissions in excess of a standard (subject to the specified averaging period) occur due to malfunction, the permittee shall notify the Compliance Authority within (1)**  **working day of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken to correct the problem. In addition, the Department may request a**  **written summary report of the incident.**
**b.** SIP Quarterly Permit Limits Excess Emissions Report **: Within 30 days following the end of each calendar-quarter, the permittee shall submit a report to the Compliance Authority summarizing periods**  **of CO and NO X**  **emissions in excess of the permit emission standards following the NSPS format in 40 CFR 60.7(c), Subpart**  **A. Periods of startup, shutdown and malfunction, shall be monitored, recorded and reported as excess emissions when emission levels exceed the standards specified in this permit. In**  **addition, the report shall summarize the CEMS systems monitor availability for the previous quarter.**

**c.** NSPS Semi-Annual Excess Emissions Reports **: For purposes of reporting emissions in excess of NSPS Subpart KKKK, excess emissions from the CTG are defined as: a specified averaging period over**  **which either the NO X**  **emissions are higher than the applicable emission limit in 40 CFR 60.4320; or the total sulfur con**  **t ent of the fuel being combusted in the affected facility exceeds the limit specified in**  **60.4330. Within thirty (30) days following each calendar semi-annual period, the permittee shall submit a report on any periods of excess emissions that occurred during the previous semi-annual**  **period to the Compliance Authority.** {Note: If there are no periods of excess emissions as defined in NSPS Subpart KKKK, a statement to that effect may be submitted with the SIP Quarterly Report to suffice for the NSPS Semi-Annual Report.} **[Rules 62-4.130, 62-204.800, 62-210.700(6), F.A.C.; 40 CFR 60.7, and 60.4420]**
**31. Annual Operating Report**  **: The permittee shall submit an annual report that summarizes the actual operating hours and emissions from this facility. The permittee shall also keep records sufficient to determine the**  **annual throughput of distillate fuel oil for the fuel oil storage tank for use in the Annual Operating Report. Annual operating reports shall be submitted to the Compliance Authority by April 1st of each year.**  **[Rule 62-210.370(2), F.A.C.]**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS

B. AUXILIARY BOILER AND TEMPORARY CONSTRUCTION BOILER (010 AND 015)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 17 of 24 This section of the permit addresses the following emissions units.** 

ID Emission Unit D e scription **010 One nominal 85,000 pounds per hour (lb/hr) natural gas fueled auxiliary boiler (99.8 mmBtu/hr) 015 One temporary 110 mmBtu/hr natural gas-fueled boiler to be used only during construction** 

A UXILIARY B OILER R EQUIREMENTS
**1. Equipment**  **: The permittee is authorized to install, operate, and maintain one auxiliary boiler with a maximum design heat input of 99.8 mmBtu/hr (85,000 lb/hr) to produce steam during start up of the CTG.**  **[Applicant Request; Rule 62-210.200(PTE), F.A.C.]**
**2. Hours of Operation**  **: The hours of operation of the auxiliary boiler shall not exceed 750 hours per year. [Applicant Request; Rule 62-210.200(PTE), F.A.C.]** 
**3. NSPS Subpart Dc Applicability**  **: The auxiliary boiler is subject to all applicable requirements of 40 CFR 60, Subpart Dc which applies to Small Industrial, Commercial, or Institutional Steam Generating Units.**  **Specifically, this emission unit shall comply with 40 CFR 60.48c Reporting and Recordkeeping Requirements. [**  **40 CFR 60, NSPS-Subpart Dc - Standards of Performance for Small Industrial Commercial-Institutional Steam Generating Units, attached as Appendix Dc].** 
**4. Auxiliary Boiler Emissions Limits**  **: The auxiliary boiler shall comply with the following emission limits.**

NO X CO VOC, SO 2 , PM/PM 10 **0.05 lb/mmBtu 0.08 lb/mmBtu 2 gr S/100 SCF natural gas spec and 10% Opacity**
**[Applicant request; Rule 62-4.070(3), F.A.C.]** {Permitting note: There are no Subpart Dc emission standards for auxiliary boilers fueled by natural gas.}

**5. Auxiliary Boiler Testing Requirements**  **: The auxiliary boiler shall be stack tested to demonstrate initial compliance with the emission standards for CO, NO**  **X and visible emissions. The tests shall be conducted**  **within 60 days aft er achieving the maximum production rate at which the unit will be operated, but not later**  **than 180 days after the initial startup. [Rule 62-297.310(7)(a)1, F.A.C.]**
**Test Methods : Any required tests shall be performed in accordance with the following reference methods.** 
Method Description of Method and Comments **7E Determination of Nitrogen Oxide Emissions from Stationary Sources 9 Visual Determination of the Opacity of Emissions from Stationary Sources**  **10 Determination of Carbon Monoxide Emissions from Stationary Sources**

**6. Notification**  **: Initial notification is required for the auxiliary boiler pursuant to 40 CFR 60.7.**

**7. Reporting**  **: The permittee shall maintain records of the amount of natural gas used in the auxiliary boiler. These records shall be submitted to the Compliance Authority on an annual basis or upon request.**  **[Rule 62-4.070(3), F.A.C.]**SECTION III - EMISSIONS UNITS SPECIFIC CONDITIONS

B. AUXILIARY BOILER AND TEMPORARY CONSTRUCTION BOILER (010 AND 015)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 18 of 24** T EMPORARY B OILER REQUIREMENTS
**8. Equipment**  **: The permittee is authorized to install, operate, and maintain a temporary boiler during the construction of the RBEC with a maximum design heat input of 110 mmBtu/hr.**  **[Applicant Request; Rule 62-210.200(PTE), F.A.C.]**
**9. Hours of Operation**  **: The hours of operation of the temporary boiler shall not exceed 1000 hours per year and the temporary boiler shall not operate beyond the expiration date of this permit.**  **[Applicant Request; Rule 62-210.200(PTE), F.A.C.]**
**10. NSPS Subpart Db Applicability**  **: The temporary 110 mmBtu natural gas-fueled boiler is subject to all applicable requirements of 40 CFR 60, Subpart Db which applies to Industrial, Commercial, or Institutional**  **Steam Generating Units. [**  **40 CFR 60, NSPS-Subpart Db - Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units, attached as Appendix Db].** SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS C. PROCESS HEATERS (EU 011)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 19 of 24 This section of the permit addresses the following emissions unit.** 

ID Emission Unit D e scription **011 Two nominal 10 mmBtu/hr natural gas-fired process heaters (one is a spare)**

**1. Equipment**  **: The permittee is authorized to install, operate, and maintain two 10 mmBtu/hr process heaters for the purpose of heating the natural gas supply to the CTG.**  **[Applicant Request and Rule 62-210.200(PTE), F.A.C.]**
**2. Hours of Operation**  **: The two natural gas-fueled process heaters are allowed to operate a combined total of 8760 hours per year. [Applicant Request and Rule 62-210.200(PTE), F.A.C.]** 
**3. NSPS Subpart Dc Applicability**  **: Each process heater is subject to all applicable requirements of 40 CFR 60, Subpart Dc which applies to Small Industrial, Commercial, or Institutional Boiler. Specifically, each**  **emission unit shall comply with 40 CFR 60.48c Reporting and Recordkeeping Requirements. [**  **40 CFR 60, NSPS-Subpart Dc - Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units, attached as Appendix Dc]** 
**4. Emission Limits**  **: Each natural gas fired process heater shall comply with the following emission limits.**

NO X CO VOC, SO 2 , PM/PM 10 **0.095 lb/mmBtu 0.08 lb/mmBtu 2 gr S/100 SCF natural gas spec and 10% Opacity**
**[Applicant request; Rule 62-4.070(3), F.A.C.]** {Permitting note: There are no Subpart Dc emission standards for gas-fired process heaters fueled by natural gas.}

**5. Testing Requirements**  **: Each unit shall be stack tested to demonstrate initial compliance with the emission standards for CO, NO**  **X and visible emissions. The tests shall be conducted within 60 days after achieving**  **the maximum prod u**  **ction rate at which the unit will be operated, but not later than 180 days after the initial startup. As an alternative, a Manufacturer certification of emissions characteristics of the purchased model**  **that are at least as stringent as the emission limits values can be used to fulfill this requirement. [Rule 62-297.310(7)(a)1, F.A.C.]** 
**Test Methods : Any required tests shall be performed in accordance with the following reference methods.** 
Method Description of Method and Comments **7E Determination of Nitrogen Oxide Emissions from Stationary Sources 9 Visual Determination of the Opacity of Emissions from Stationary Sources**  **10 Determination of Carbon Monoxide Emissions from Stationary Sources**

**6. Notification, Recordkeeping and Reporting Requirements**  **: The permittee shall maintain records of the amount of natural gas used in the process heaters and shall comply with the notification, recordkeeping and**  **reporting requirements pursuant to 40 CFR 60.48c and 40 CFR 60.7. These records shall be submitted to the Compliance Authority on an annual basis or upon request.**  **[Rule 62-4.070(3), F.A.C.; 40 CFR 60, Subparts A and Dc]**SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS D. COMPRESSOR STATION (EU 012)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 20 of 24 This section of the permit addresses the following emissions unit.** 

ID Emission Unit D e scription **012 Seven nominal 1,340 horsepower (hp) natural gas compressors**

**1. Equipment**  **: The permittee is authorized to install, operate, and maintain seven nominal 1,340 horsepower (hp) natural gas compressors. Maximum heat input shall not exceed 10.11 mmBtu/hr each.**  **[Applicant Request and Rule 62-210.200(PTE), F.A.C.]**
**2. Hours of Operation and Fuel Specifications**  **: Each compressor is allowed to operate continuously (8760 hr/yr). The compressors are allowed to burn natural gas only.**  **[Applicant Request and Rule 62-210.200(PTE), F.A.C.]**
**3. NSPS Subpart JJJJ Applicability**  **: These compressors are Stationary Spark Ignition Internal Combustion Engines and shall comply with applicable provisions of 40 CFR 60, Subpart JJJJ.**  **[40 CFR 60, Subpart JJJJ - Standards of Performance for Stationary Spark Ignition Internal Combustion Engines]** 
**4. NESHAPS Subpart ZZZZ Applicability**  **: These compressors are Reciprocating Internal Combustion Engines (RICE) and shall comply with applicable provisions of 40 CFR 63, Subpart ZZZZ. Pursuant to 40**  **CFR 63.6590(c) the compressors must meet the requirements of Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart JJJJ.**  **[40 CFR 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE)]** 

**5. Pollution Control Equipment**  **: Each gas compressor shall be equipped with an oxidation catalyst to control CO and VOC/hydrocarbons. [Applicant request; Rule 62-4.070(3), F.A.C.]** 
**6. Visible Emission (VE) Limit**  **: Each natural gas compressor shall comply with a visible emission limit of 10% opacity. [Applicant request; Rule 62-4.070(3), F.A.C.]** 

**7. Emissions Limits**  **: Each natural gas compressors shall comply with the following emission limits.**

Standard (manufacture date) CO ( **g/hp-hr) a**  VOC

( **g/hp-hr)** NO X

( **g/hp-hr)** P M

**(g/hp-hr)** SO 2

(ga s S spec.)
**Permit Emission Limit 0.10 0.16 1.5**  **b 0.034 2 gr/100 SCF**  **Subpart JJJJ (1/1/2008) 4.0 1.0 2.0**  **NA Subpart JJJJ (7/1/2010)**  **2.0 0.7 1.0**

**a. grams per horsepower-hour (g/hp-hr)** 
**b. Reduced to 1.0 g/hp-hr if manufacture date is 7/1/2010 or later to insure compliance with Subpart JJJJ.**  {Permitting note: Installation of an oxidation catalyst and adherence to the visible emission standard and fuel specification shall be considered sufficient to insure compliance with the listed PM limit.} **[Applicant request; 40 CFR 60, Subpart JJJJ; Rule 62-4.070(3), F.A.C.]**
**8. Compressor Testing Requirements**  **: Each unit shall be stack tested to demonstrate initial compliance with the emission standards for CO, VOC, NO**  **X and visible emissions. The tests shall be conducted within 60**  **days after achiev ing the maximum production rate at which the unit will be operated, but not later than 180**  **days after the initial startup. With the exception of visible emissions testing, manufacturer certification can be provided to the Department in lieu of actual testing.**  **[Rule 62-297.310(7)(a)1, F.A.C.; 40 CFR 60.8 and 40 CFR 60.4244]**SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS D. COMPRESSOR STATION (EU 012)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 21 of 24 9.**  **Test Methods : Any required tests shall be performed in accordance with the following reference methods.** 
Method Description of Method and Comments **7E Determination of Nitrogen Oxide Emissions from Stationary Sources 9 Visual Determination of the Opacity of Emissions from Stationary Sources** 

**10 Determination of Carbon Monoxide Emissions from Stationary Sources** 

**18 Determination of Volatile Organic Compounds Emissions from Stationary Sources** 
**[Rule 62-4.070(3), F.A.C.; 40 CFR 60, Subpart JJJJ and 40 CFR 60.8]**
**10. Notification, Recordkeeping and Reporting Requirements**  **: The permittee shall maintain records of the amount of natural gas used in the compressor station and shall comply with the notification, recordkeeping**  **and reporting requirements pursuant to 40 CFR 60.4245 and 40 CFR 60.7. These records shall be submitted to the Compliance Authority on an annual basis or upon request.**  **[Rule 62-4.070(3), F.A.C.; 40 CFR 60, Subparts A and JJJJ]**SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS E. EMERGENCY GENERATORS (013)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 22 of 24 This section of the permit addresses the following emissions units.** 

ID Emission Unit D e scription **013 Two nominal 2,250 kilowatts (kW) liquid fueled emergency generators**

**1. Equipment**  **: The permittee is authorized to install, operate, and maintain two 2,250 kW emergency generators. [Applicant Request and Rule 62-210.200(PTE), F.A.C.]** 
**2. Hours of Operation and Fuel Specifications**  **: The hours of operation shall not exceed 160 hours per year per generator. The generators shall burn ultralow sulfur diesel fuel oil (0.0015% sulfur).**  **[Applicant Request and Rule 62-210.200(PTE), F.A.C.]**
**3. NSPS Subpart IIII Applicability**  **: These emergency generators are Stationary Compression Ignition Internal Combustion Engines (Stationary ICE) and shall comply with applicable provisions of 40 CFR 60,**  **Subpart IIII, including emission testing or certification. [40 CFR 60, Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines]** 
**4. NESHAPS Subpart ZZZZ Applicability**  **: These emergency generators are Liquid Fueled Reciprocating Internal Combustion Engines (RICE) and shall comply with applicable provisions of 40 CFR 63, Subpart**  **ZZZZ. Pursuant to 40 CFR 63.6590(c) the compressors must meet the requirements of Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart IIII.**  **[40 CFR 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines (RICE)]** 

**5. Emissions Limits:**  **Each emergency generator shall comply with the following emission limits and demonstrate compliance in accordance with the procedures given in 40 CFR 60, Subpart IIII. Manufacturer**  **certification can be provided to the Department in lieu of actual testing.**

Source (model year) CO ( **g/hp-hr)** PM

( **g/hp-hr)** Hydrocarbons

( **g/hp-hr)** NO X

( **g/hp-hr) Subpart IIII (2007-2010) 8.5 0.4**  **1.0 6.9**  **Subpart IIII (2011 and later) 2.6 0.15 4.8 (NMHC**  **a +NO**  **X )** 

**a. NMHC means Non-Methane Hydrocarbons.**  **[Applicant Request; 40 CFR 60, Subpart IIII and Rule 62-4.070(3), F.A.C.]**
**6. Visible Emission (VE) Limit**  **: Each liquid-fueled emergency generator shall comply with a visible emission limit of 10% opacity. An initial VE test shall be conducted in accordance with EPA Method 9 within 60**  **days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after initial startup. [Applicant request; Rule 62-4.070(3), F.A.C.]** 

**7. Notification, Recordkeeping and Reporting Requirements**  **: The permittee shall maintain records of the amount of fuel used in the emergency generators and shall comply with the notification, recordkeeping and**  **reporting requirements pursuant to 40 CFR 60.4214 and 40 CFR 60.7. These records shall be submitted to the Compliance Authority on an annual basis or upon request.**  **[Rule 62-4.070(3), F.A.C.; 40 CFR 60, Subparts A and IIII]**SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS F. EMERGENCY FIRE PUMP (014)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 23 of 24 This section of the permit addresses the following emissions unit.** 

ID Emission Unit D e scription **014 One emergency diesel fire pump engine (< 300 hp) and a nominal 500 gallon fuel oil storage tank** 

**1. Equipment**  **: The permittee is authorized to install, operate, and maintain one diesel engine driven fire pump (<**  **300 hp) and an associated nominal 500 gallon fuel oil storage tank. [Applicant Request and Rule 62-210.200(PTE), F.A.C.]** 

**2. Hours of Operation**  **: The fire pump may operate in response to emergency conditions and 80 non emergency hours per year for maintenance testing. [Applicant Request; Rule 62-210.200 (PTE), F.A.C.]** 

**3. Authorized Fuel**  **: This unit shall fire ULSD fuel oil, which shall contain no more than 0.0015% sulfur by weight. [Applicant Request]** 
**4. NSPS Subpart IIII Applicability**  **: The fire pump engine is an Emergency Stationary Compression Ignition Internal Combustion Engine (Stationary ICE) and shall comply with applicable provisions of 40 CFR 60,**  **Subpart IIII. [40 CFR 60, Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines]** 

**5. Emissions Limits**  **: The emergency fire pump engine shall comply with the following emission limits and demonstrate compliance in accordance with the procedures given in 40 CFR 60, Subpart IIII.** 

Model Year CO ( **g/hp-hr)** NMHC + NO X

( **g/hp-hr)** PM

( **g/hp-hr) Subpart IIII (2008)**  **2.6 7.8**  **0.40 Subpart IIII (2009 or later)**  **NA 3.0**  **0.15 [Applicant Request; 40 CFR 60, Subpart IIII and Rule 62-4.070(3), F.A.C.]** 

**6. Fire Pump Engine Certification**  **: Manufacturer certification shall be provided to the Department in lieu of actual testing. [40 CFR 60.4211 and Rule 62-4.070(3), F.A.C.]** SECTION III. EMISSIONS UNIT SPECIFIC CONDITIONS G. DISTILLATE FUEL OIL STORAGE TANK (016)

**FPL Riviera Beach Energy Center Permit No. 0990042-006-AC**  **Power Plant Conversion Project 1,250 MW Combined Cycle Unit**  **Page 24 of 24 This section of the permit addresses the following emissions unit.** 

ID Emission Unit D e scription **016 One nominal 6.3 million gallon distillate fuel oil storage tank**

NSPS A PPLICABILITY
**1. NSPS Subpart Kb A**  **pplicability : The distillate fuel oil tank is not**  **subject to Subpart Kb, which applies to any storage tank with a capacity greater than or equal to 10,300 gallons (40 cubic meters) that is used to**  **store volatile organic liquids for which construction, reconstruction, or modification is commenced after July 23, 1984. Tanks with a capacity greater than or equal to 40,000 gallons (151 cubic meters) storing a**  **liquid with a maximum true vapor pressure less than 3.5 kilopascals (kPa) are exempt from the General Provisions (40 CFR 60, Subpart A) and from the provisions of NSPS Subpart Kb.**  **[40 CFR 60.110b(a) and (c); Rule 62-204.800(7)(b), F.A.C.]**

E QUIPMENT S PECIFICATIONS
**2. Equipment**  **: The permittee is authorized to install, operate, and maintain one nominal 6.3 million gallon distillate fuel oil storage tank designed to provide ultra low sulfur diesel fuel oil to the gas turbines.**  **[Applicant Request; Rule 62-210.200(PTE), F.A.C.]**

E MISSIONS AND P ERFORMANCE R EQUIREMENTS
**3. Hours of Operat**  **ion : The hours of operation are not restricted (8760 hours per year).**  **[Applicant Request; Rule 62-210.200(PTE), F.A.C.]**

N OTIFICATION , R EPORTING AND R ECORDS
**4. Oil Tank Record**  **s : The permittee shall keep readily accessible records showing the dimension of the**  **storage vessel and an analysis showing the capacity of the storage tank. Records shall be retained for the life of the facility. The permittee shall also keep records sufficient to determine the annual throughput of**  **distillate fuel oil for the storage tank for use in the Annual Operating Report. [Rule 62-4.070(3) F.A.C]**

**5. Fuel Oil Records:**  **The permittee shall keep readily accessible records showing the maximum true vapor pressure of the stored liquid. The maximum true vapor pressure shall be less than 3.5 kPa. Compliance**  **with this condition may be demonstrated by using the information from the respective MSDS for the ULSD fuel oil stored in the tank. [Rule 62-4.070(3), F.A.C.; Avoidance of 40 CFR 60, Subpart Kb]**  {Permitting Note: An evaluation of several Material Safety Data Sheets (MSDS) by the Department and applicant demonstrated that the vapor pressure is much less than 3.5 kPa for ULSD fuel oil.}

# J. Florida Power and Light – Port Everglades

Emission Units shut

- down: 1. EU003 – Unit #3 (BART/RP) 2. EU004 – Unit #4 (BART/RP)

Items included: DEP Intent to Issue Air PermitSent by Electronic Mail – Received Receipt Requested randall.r.labauve@fpl.com Mr. Randall R. LaBauve, Vice President Florida Power and Light Company (FPL) 700 Universe Boulevard, JES/JB Juno Beach, Florida 33408

Re: Project No. 0110036-010- AC Florida Power & Light Company, Port Everglades Plant PEEC Project

Dear Mr. LaBauve : On January 24, 2012 you submitted an application to construct one nominal 1,250 megawatts (MW) combined cycle unit and ancillary equip ment at the FPL Port Everglades Plant located in Broward County at 8100 Eisenhower Boulevard in Fort Lauderdale, Florida. Four existing fossil fuel- fired steam generators with a total nominal capacity of 1,200 MW will be shut down and dismantled as part o f this project. Enclosed are the following documents: the Written Notice of Intent to Issue Air Permit; the Public Notice of Intent to Issue Air Permit; the Technical Evaluation and Preliminary Determination ; and the Draft Permit with Appendices. The Pub lic Notice of Intent to Issue Air Permit is the actual notice that you must have published in the legal advertisement section of a newspaper of general circulation in the area affected by this project. If you have any questions, please contact the projec t engineer, Leigh -Ann Pell, at 850-717-9033. Sincerely, (Electronic Signature)

Enclosures

JFK /aal/ lpIn the Matter of an Application for Air Permit by: Florida Power & Light (FPL) 700 Universe Boulev ar d, JES/JB Juno Beach, Florida 33408 Authoriz ed Representative: Randall R. LaBauve, Vice President Air Permit No. 0110036

- 010

- AC Permit Expires: May 1, 2017 Minor Air Construction Permit Port Everglades Next Generation Clean Energy Center (PEEC)

Facility Location : FPL operates the existing Port E verglades Plant , which is located in Broward County at 8100 Eisenhower Boulevard in Fort Lauderdale, Florida. Project : FPL proposes to construct a nominal 1,250 megawatts (MW ) natural gas -fueled combined cycle unit (Unit 5) and ancillary equipment. The p roject includes the permanent shutdown and dismantling of four natural gas and residual fuel oil

- fired fossil fuel steam generators with a total nominal capacity of 1,200 MW and their respective 344

- foot stacks. Unit 5 will be called the Port Everglades N ext Generation Clean Energy Center. Details of the project are provided in the application and the enclosed Technical Evaluation and Preliminary Determination. Permitting Authority : Applications for air construction permits are subject to review in accordance with the provisions of Chapter 403, Florida Statutes (F.S.) and Chapters 62-4, 62-210 and 62-212 of the Florida Administrative Code (F.A.C.). The proposed project is not exempt from air permitting requirements and an air permit is required to perform the proposed work. The Division of Air Resource Management’s (DARM) Office of Permitting and Compliance is the Permitting Authority responsible for making a permit determination for this project. The Permitting Authority’s physical address is: 111 Sou th Magnolia Drive, Suite #4, Tallahassee, Florida. The Permitting Authority’s mailing address is: 2600 Blair Stone Road, MS #5505, Tallahassee, Florida 32399-2400. The Permitting Authority’s telephone number is 850/717-9000. Project File : A complete project file is available for public inspection during the normal business hours of 8:00 a.m. to 5:00 p.m., Monday through Friday (except legal holidays), at address indicated above for the Permitting Authority. The complete project file includes the Draft Permit, the Technical Evaluation and Preliminary Determination, the application, and the information submitted by the applicant, exclusive of confidential records under Section 403.111, F.S. Interested persons may contact the Permitting Authority’s projec t review engineer for additional information at the address or phone number listed above.
Notice of Intent to Issue Air Permit : The Permitting Authority gives notice of its intent to issue an air permit to the applicant for the project described above. T he applicant has provided reasonable assurance that operation of the proposed equipment will not adversely impact air quality and that the project will comply with all appropriate provisions of Chapters 62-4, 62-204, 62-210, 62-212, 62-296 and 62-297, F.A. C. The Permitting Authority will issue a Final Permit in accordance with the conditions of the proposed Draft Permit unless a timely petition for an administrative hearing is filed under Sections 120.569 and 120.57, F.S. or unless public comment received in accordance with this notice results in a different decision or a significant change of terms or conditions.
Public Notice : Pursuant to Section 403.815, F.S. and Rules 62-110.106 and 62-210.350, F.A.C., you (the applicant) are required to publish at your own expense the enclosed Public Notice of Intent to Issue Air Permit (Public Notice). The Public Notice shall be published one time only as soon as possible in the legal advertisement section of a newspaper of general circulation in the area affected by this project. The newspaper used must meet the requirements of Sections 50.011 and 50.031, F.S. in the county where the activity is to take place. If you are uncertain that a newspaper meets these requirements, please contact the Permitting Authority at above address or phone number. Pursuant to Rule 62-110.106(5) and (9),F.A.C., the applicant shall provide proof of publication to the Permitting Authority at the above address within 7 days of publication. Failure to publish the notice and provide proof of publication may result in the denial of the permit pursuant to Rule 62-110.106(11), F.A.C.
Comment s : The Permitting Authority will accept written comments concerning the proposed Draft Permit for a period of 14 days from the date of publication of the Public Notice. Written comments must be received by the Permitting Authority by close of business (5:00 p.m.) on or before the end of the 14- day period . If written comments received result in a significant change to the Draft Permit, the Permitting Aut hority shall revise the Draft Permit and require, if applicable, another Public Notice. All comments filed will be made available for public inspection.
Petitions : A person whose substantial interests are affected by the proposed permitting decision may petition for an administrative hearing in accordance with Sections 120.569 and 120.57, F.S. The petition must contain the information set forth below and must be filed with (received by) the Department’s Agency Clerk in the Office of General Counsel of th e Department of Environmental Protection, 3900 Commonwealth Boulevard, Mail Station #35, Tallahassee, Florida 32399-3000. Petitions filed by the applicant or any of the parties listed below must be filed within 14 days of receipt of this Written Notice of Intent to Issue Air Permit. Petitions filed by any persons other than those entitled to written notice under Section 120.60(3), F.S., must be filed within 14 days of publication of the attached Public Notice or within 14 days of receipt of this Written N otice of Intent to Issue Air Permit, whichever occurs first. Under Section 120.60(3), F.S., however, any person who asked the Permitting Authority for notice of agency action may file a petition within 14 days of receipt of that notice, regardless of the date of publication. A petitioner shall mail a copy of the petition to the applicant at the address indicated above, at the time of filing. The failure of any person to file a petition within the appropriate time period shall constitute a waiver of that person’s right to request an administrative determination (hearing) under Sections 120.569 and 120.57, F.S., or to intervene in this proceeding and participate as a party to it. Any subsequent intervention (in a proceeding initiated by another party) will be only at the approval of the presiding officer upon the filing of a motion in compliance with Rule 28-106.205, F.A.C. A petition that disputes the material facts on which the Permitting Authority’s action is based must contain the following information: (a) The name and address of each agency affected and each agency’s file or identification number, if known; (b) The name, address, and telephone number of the petitioner; the name, address and telephone number of the petitioner’s representative, if any, which shall be the address for service purposes during the course of the proceeding; and an explanation of how the petitioner’s substantial interests will be affected by the agency determination; (c) A statement of when and how each petitioner received noti ce of the agency action or proposed decision ; (d) A statement of all disputed issues of material fact. If there are none, the petition must so state ; (e) A concise statement of the ultimate facts alleged, including the specific facts the petitioner contends warrant reversal or modification of the agency’s proposed action; (f) A statement of the specific rules or statutes the petitioner contends require reversal or modification of the agency’s proposed action including an explanation of how the alleged facts relate to the specific rules or statutes ; and, (g) A statement of the relief sought by the petitioner, stating precisely the action the petitioner wishes the agency to take with respect to the agency’s proposed action. A petition that does not dispute t he material facts upon which the Permitting Authority’s action is based shall state that no such facts are in dispute and otherwise shall contain the same information as set forth above, as required by Rule 28-106.301, F.A.C. Because the administrative hearing process is designed to formulate final agency action, the filing of a petition means that the Permitting Authority’s final action may be different from the position taken by it in this Written Notice of Intent to Issue Air Permit. Persons whose substantial interests will be affected by any such final decision of the Permitting Authority on the application have the right to petition to become a party to the proceeding, in accordance with the requirements set forth above.
Mediation : Mediation is not av ailable in this proceeding.Executed in Tallahassee , Florida. Division of Air Resource Management Office of Permitting and Compliance (Electronic Signature)

CERTIFICATE OF SERVICE The undersigned duly designated deputy agency clerk hereby certifies that this Written Notice of Intent to Issue Air Permit package (including the Written Notice of Intent to Issue Air Permit, the Public Notice of Intent to Issue Air Permit, the Technical Evaluation and Preliminary Determination and the Draft Permit with A ppendices) was sent by electronic mail, or a link to these documents made available electronically on a publicly accessible server, with received receipt requested before the close of business on the date indicated below to the following persons. Randall R. LaBauve, FP L: randall.r.labauve@fpl.com Ken Kosky, P.E., Golder Associates : kkosky@golder.com Heather Ceron, US EPA Region 4 : ceron.heather@epa.gov Cindy Mulkey, DEP Siting Office: cindy.mulkey@dep.state.fl.us Lennon Anderson, Administrator, DEP SED: lennon.Anderson@dep.state.fl.us Cynthia Chambers, Director, Broward County EP&GMD: cchambers@broward.org Barbara Friday, DEP OPC: barbara.Friday@dep.state.fl.us Lynn Scearce, DEP OPC: lynn.scearce@dep.state.fl.us

Clerk Stamp
FILING AND ACKNOWLEDGMENT FILED
, on this date, pursuant to Section 120.52(7), Florida Statutes, with the designated agency c lerk, receipt of which is hereby acknowledged. (Electronic Signature)PERMITTEE Florida Power & Light (FPL) 700 Universe Boulev ar d, JES/JB Juno Beach, Florida 33408 Authorized Representative: Randall R. LaBauve, Vice President Air Permit No. 0110036

- 010

- AC Permit Expires: May 1, 2017 Minor Air Construction Permit
Port Ever glades Next Generation Clean Energy Center (PEEC)

PROJECT This is the final air construction permit, which authorizes the construction of one nominal 1,250 megawatts (MW) combined cycle unit and ancillary equipment at the FPL Port Everglades Plant . Four existing fossil fuel

- fired steam generators with a total nominal capacity of 1,200 MW will be shut down and dismantled as part of this project.
The facility is a power plant under Standard Industrial Classification No. 4911 and is located in Broward Count y at 8100 Eisenhower Boulevard in Fort Lauderdale, Florida. The UTM coordinates are Zone 17, 587.38 km East and 2885.25 km North. This final permit is organized into the following sections: Section 1 (General Information ); Section 2 ( Administrative Req uirements ); Section 3 (Emissions Unit Specific Conditions ); Section 4 (Appendices). Because of the technical nature of the project, the permit contains numerous acronyms and abbreviations, which are defined in Appendix A of Section 4 of this permit. As n oted in the Final Determination provided with this final permit , only minor changes and clarifications were made to the draft permit.
STATEMENT OF BASIS This air pollution construction permit is issued under the provisions of : Chapter 403 of the Florida Statutes (F.S.) and Chapters 62-4, 62-204, 62-210, 62-212, 62-296 and 62-297 of the Florida Administrative Code (F.A.C.). The permittee is authorized to conduct the proposed work in accordance with the conditions of this permit. This project is subject to the general preconstruction review requirements in Rule 62-212.300, F.A.C. and is not subject to the preconstruction review requirements for major stationary sources in Rule 62-212.400, F.A.C. for the Prevention of Significant Deterioration (PSD) of Air Q uality. Upon issuance of this final permit, any party to this order has the right to seek judicial review of it under Section 120.68 of the Florida Statutes by filing a notice of appeal under Rule 9.110 of the Florida Rules of Appellate Procedure with the clerk of the Department of Environmental Protection in the Office of General Counsel (Mail Station #35, 3900 Commonwealth Boulevard, Tallahassee, Florida, 32399-3000) and by filing a copy of the notice of appeal accompanied by the applicable filing fees with the appropriate District Court of Appeal. The notice must be filed within 30 days after this order is filed with the clerk of the Department. Executed in Tallahassee, Florida Division of Air Resource Management Office of Permitting and Compliance (Elec tronic Signature)

DRAFTCERTIFICATE OF SERVICE The undersigned duly designated deputy agency clerk hereby certifies that this Final Air Permit package (including the Final Determination and Final Permit with Appendices) was sent by electronic mail , or a link to these documents made available electronically on a publicly accessible server, with received receipt requested before the close of business on the date indicated below to the following persons. Randall R. LaBauve, FPL: randall.r.labauve@fpl.com Ken Kosky, P.E., Golder Associates : kkosky@golder.com Heather Ceron, US EPA Region 4 : ceron.heather@epa.gov Cind y Mulkey, DEP Siting Office: cindy.mulkey@dep.state.fl.us Lennon Anderson, Administrator, DEP SED: lennon.anderson@dep.state.fl.us Cynthia Chambers, Director, Broward County EP&GMD: cchambers@broward.org Barbara Friday, DEP OPC: barbara.Friday@dep.state.fl.us Lynn Scearce, DEP OPC: lynn.scearce@dep.state.fl.us

Clerk Stamp FILING AND ACKNOWLEDGMENT FILED
, on this date, pursuant to Section 120.52(7), Florida Statutes, with the designated agency clerk, receipt of which is hereby acknowledged. (Elec tronic Signature)

DRAFTFACILITY DESCRIPTION
The FPL Port Everglades Plant currently consists of four fossil fuel steam generat or that together produce approximately 1,200 megawatts (MW) of electrical power and 12 small simple cycle combustion turbine generators (CTG s ) that together produce approximately 504 MW. The steam generators use residual fuel oil and natural gas and exhaust through four 344- foot stacks. The small CTG s use natural gas and No. 2 fuel oil and exhaust through 44-foot stacks. The re are fuel oil storage tanks, water intake structures for once-through cooling and other ancillary equipment.
PROPOSED PROJECT The project includes the construction of a nominal 1,250 MW natural gas-fueled combined cycle unit (Unit 5) and requires the permanent shutdown and dismantling of the four fossil fuel steam generators

. The new unit (Unit 5) will be called the Port Everglades Next Generation Clean Energy Center and abbreviated as PEEC

. Unit 5 will consist of three nominal 250 MW CTG s and three he at recovery steam generators (HRSG ). The HRSG will utilize the waste heat from the combustion turbines to produce steam to be utilized in a single nominal 500 MW steam turbine generator

. Each of the three CTG/HRSG sets will exhaust through a 149-foot sta ck. The primary fuel for Unit 5 will be natural gas and ultralow sulfur distillate (ULSD) fuel oil will be used as backup fuel. Additional ancillary equipment to be installed includes: a n auxiliary boiler; two temporary boilers used during construction; two emergency generators; a diesel fire pump; two process heaters; and a gas compression station. Details of the equipment to be installed are listed below. This project will add the following emissions units (EU)

.

Facility ID No. 0110036

EU No. Emission Unit Description

020 Unit 5A – One nominal 250 MW CTG and HRSG

021 Unit 5B – One nominal 250 MW CTG and HRSG

022 Unit 5C – One nominal 250 MW CTG and HRSG

023 One natural gas fueled auxiliary boiler rated at 99.8 MMBtu /h our heat input [higher heating value (HHV)] or less

024 Two nominal 9.9 MMBtu /h ou r (HHV) natural gas

- fired process heaters (one is a spare)

025 Three 5,514 horsepower (hp) natural gas compressor stations

026 One 2,250 kil owatts (kW) emergency generator firing ULSD fuel oil

027 One 2 ,250 kW emergency generator firing ULSD fuel oil

028 Two temporary natural gas or ULSD fuel oil fired boilers rated at 150 MMBtu/h our (HHV)

029 One nominal 300 hp emergency diesel fire pump engine

030 One nominal 7 million gallon distillate fuel oil sto rage tank.REGULATORY CLASSIFICATION

**•** The facility is a major source of hazardous air pollutants (HAP).

**•** The facility operates units subject to the acid rain provisions of the Clean Air Act (CAA).

**•** The facility is a Title V major source of air pollution in accordance with Chapter 62 -213, F.A.C.

**•** The facility is subject to the Clean Air Interstate Rule (CAIR) in accordance with the Final Department Rules issued pursuant to CAIR as implemented by the Department in Rule 62-296.470, F.A.C.

**•** The facility is a major stationary source in accordance with Department Rule 62-212.400, F.A.C. - Prevention of Significant Deterioration (PSD).

**•** The proposed project does not trigger a PSD review and a requirement to conduct a Best Available Control Technology (BACT) pursuant to Department Rule 62-212.400, F.A.C.

**•** The proposed project includes units subject to the New Source Performance Standards (NSPS) of 40 Code of Federal Regulations Part 60 (40 CFR 60).

**•** The proposed project includes units subject to the National Emissions Standards for Hazardous Air Pollutants (NESHAP) of 40 CFR 63.

**•** The project is subject to certification under the Florida Power Plant Siting Act, 403.501-518, F.S. and Chapter 62-17, F.A.C.1. Permitting Authority

2. : The permitting authority for this projec t is the Office of Permitting and Compliance in the Division of Air Resource Management of the Department of Environmental Protection (Department). The Office of Permitting and Compliance mailing address is 2600 Blair Stone Road (MS #5505), Tallahassee, Florida 32399-2400. Compliance Authority

3. : All documents related to compliance activities such as reports, tests, and notifications shall be submitted to the Air Program of the Broward County Environmental Protection and Growth Management Department : 1 No rth University Drive, 102A, Plantation, Florida 33324. Appendices

4. : The following Appendices are a ttached as a part of this permit: Appendix A ( Citation Forma ts and Glossary of Common Terms); Appendix B (General Conditions); Appendix Subpart A (NSPS Subpa rt A and NESHAP Subpart A); Appendix Db (NSPS Subpart Db); Appendix Dc (NSPS Subpart Dc); Appendix IIII ( NSPS Subpart IIII) ; App endix KKKK (NSPS Subpart KKKK); Appendix XS (Semiannu al NS PS Excess Emission Report); Appendix ZZZZ (NESHAP Subpart ZZZZ) ; and Appendix DDDDD (NESHAP Subpart DDDDD). Applicable Regulations, Forms and Application Procedures

5. : Unless otherwise specified in this permit, the construction and operation of the subject emissions units shall be in accordance with the capacities and specif ications stated in the application. The facility is subject to all applicable provisions of: Chapter 403, F.S.; and Chapters 62-4, 62-204, 62-210, 62-212, 62-213, 62-296 and 62-297, F.A.C. Issuance of this permit does not relieve the permittee from comp liance with any applicable federal, state, or local permitting or regulations.
New or Additional Conditions

6. : For good cause shown and after notice and an administrative hearing, if requested, the Department may require the permittee to conform to new or additional conditions. The Department shall allow the permittee a reasonable time to conform to the new or additional conditions, and on application of the permittee, the Department may grant additional time. [Rule 62-4.080, F.A.C.]
Modifications

7. : The permittee shall notify the Compliance Authority upon commencement of construction. No new emissions unit shall be constructed and no existing emissions unit shall be modified without obtaining an air construction permit from the Department. Such permit sha ll be obtained prior to beginning construction or modification. [Rules 62-210.300(1) and 62-212.300(1)(a), F.A.C.] Source Obligation (a) At such time that a particular source or modification becomes a major stationary source or major modification (as th ese terms were defined at the time the source obtained the enforceable limitation) solely by virtue of a relaxation in any enforceable limitation which was established after August 7, 1980, on the capacity of the source or modification otherwise to emit a pollutant, such as a restriction on hours of operation, then the requirements of subsections 62-212.400(4) through (12), F.A.C., shall apply to the source or modification as though construction had not yet commenced on the source or modification. :

(b) At su ch time that a particular source or modification becomes a major stationary source or major modification (as these terms were defined at the time the source obtained the enforceable limitation) solely by exceeding its projected actual emissions, then the r equirements of subsections 62-212.400(4) through (12), F.A.C., shall apply to the source or modification as though construction had not yet commenced on the source or modification. [Rule 62-212.400(12), F.A.C.]8. Application for Title V Permit : This permit authorizes construction of the permitted emissions units and initial operation to determine compliance with Department rules. A Title V air operation permit is required for regular operation of the permitted emissions unit. The permittee shall apply for a Title V air operation permit at least 90 days prior to expiration of this permit, but no later than 180 days after commencing operation. To apply for a Title V operation permit, the applicant shall submit the appropriate application form, compliance test results, and such additional information as the Department may by law require. The application shall be submitted to the appropriate Permitting Authority with copies to the Compliance Authority. [Rul es 62 -4.030, 62-4.050, 62-4.220 and Chapter 62-213, F.A.C.]This section of the permit a ddresses the following emission units.

Uni t 5 ( EU Nos. 020, 021 and 022 ) Description: Unit 5 will be comprised of EU Nos. 020, 021, and 022 . Each EU will consist of: a combustion turbine generator ( CTG ) with automate d control ; inlet air filtration system and inlet air

cooling system ; gas

- fired heat recovery steam generator ( HRSG ); a HRSG stack ; and associated support equipment. The project also includes one steam turbine generator (STG) that will serve the combined c ycle unit.
Fuels: Each CTG fires natural gas as the primary fuel and ultralow sulfur distillate (ULSD) fuel oil as a restricted alternate fuel. Generating Capacity: Each of the three CTG s has a nominal generating capacity of 250 MW. The steam turbine ge nerator has a nominal generating capacity of 500 MW. The total nominal generating capacity of the “3 -on-1” combined cycle unit is approximately 1,250 MW. Design Heat Input Rating: The design heat input rating of each CTG is 2,580 MMBtu/h ou r when firing n atural gas and 2,353 MMBtu/h ou r when firing fuel oil based on a compressor inlet air temperature of 59 degrees Fahrenheit ( ° F), 60 percent (%) relative humidity, 14.7 pounds per square inch (psi) pressure, the lower heating value ( LHV) of each fuel and 100% load. Actual heat input rate will vary depending upon gas turbine characteristics, ambient conditions and inlet air -cooling.
Controls: Inherently clean fuels, lean premix combustion technology such as Dry Low

- NO X (DLN) for gas firing , w et injection for ULSD fuel oil firing and selective catalytic reduction ( SCR ).
Stack Parameter s: Each HRSG has a stack height of 149 feet with an exit diameter of 22 feet.
Continuous Monitors: Each stack is equipped with a continuous emissions monitoring system (CEMS) t o measure and record nitrogen oxides (NO X ) as well as flue gas oxygen (O 2 ) or carbon dioxide ( CO 2 ) content.

APPLICABLE STANDARDS AND REGULATIONS 1. NSPS Requirements

EQUIPMENT : The CTG s shall comply with the applicable NSPS in 40 CFR 60, including: Subpart A (General Provisions) and Subpart KKKK (Standards of Performance for Stationary Gas Turbines). See Appendix Subpart A and Appendix KKKK. [Rule 62-204.800(7)(b), F.A.C.; 40 CFR 60 Subpart A; 40 CFR 60 Subpart KKKK]

2. Combustion Turbine Generators

3. : The permittee is authorized to install, tune, operate, and maintain three CTG s each with a nominal generating capacity of 2 50 MW. Each CTG shall include an automated control system and have dual-fuel capability. Ancillary equipment includes an inle t air filtr ation system and an inlet air -cooling system. [Application No. 0110036-010- AC ] Heat Recovery Steam Generator s : The permittee is authorized to install, operate, and maintain three HRSG with separate exhaust stacks. Each HRSG shall be designed to recover exhaust heat energy from one of the three CTGs (5 A to 5 C) and deliver steam to the steam turbine generator. [Application No. 0110036-010- AC ]4.

a. Dry Low NO X (DLN) Combustion : The permittee shall employ lean premix (also called DLN ) technology within the combustors and an automated control system to control NO X emissions from each CTG when firing natural gas. The DLN combustors and automated control system shall be tuned to achieve sufficiently low CO and NO X values to meet the CO and NO X l imits with the additional SCR control technology described below. Emission Controls

b. Wet Injection : The permittee shall install, operate, and maintain a wet injection system (water or steam) to reduce NO X emissions from each CTG when firing ULSD fuel oil. The wet injectio n systems shall be tuned to achieve sufficiently low CO and NO X values to meet the CO and NO X limits with the additional SCR cont rol technology described below.

c. Selective Catalytic Reduction (SCR) System : The permittee shall install, tune, operate, and maintain an SCR system to control NO X emissions from each CTG when firing natural gas or distillate fuel oil. The SCR system consists of an ammonia injection grid, catalyst, ammonia storage, monitoring and control system, electrical, piping and other ancillary equipment.
d. Ammonia Storage: In accordance with 40 CFR 60.130, the storage of ammonia shall comply with all applicable requirements of the Chemical Accident Prevention Provisions in 40 CFR 68. [Application No. 0110036-010- AC]

PERFORMANCE RESTRICTIONS
5. Manufacturer’s Performance Curves

6. : The permittee shall provide manufacturer's performance curves (or equations) that correct combustion turbine design heat input rating and operation for site conditions to the Permitting and Compliance Authorities within 45 days of completing the initial compliance testing. Operating data may be adjusted for the appropriate site conditions in accordance with the performance curves and/or equations on file with the Department. [Rule 62-210.200(P otential to Emit - P TE), F.A.C.
Authorized Fuel

7. : The CTG s shall fire natural gas as the primary fuel, which shall contain no more than 2.0 grains of sulfur per 100 standard cubic feet (gr /100 SCF) of natural gas. As a restricted alternate fuel, the CTG s may fire ULSD fuel oil co ntaining no more than 0.0015% sulfur by weight. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] Operation : The hours of operation of Unit 5 are not limited (8 ,760 hours per year). ULSD f uel oil may be fired up to the fuel equivalent of 3,000 hours aggregated over the three CTG s during any calendar yea r. [ Application No. 0110036-010- AC; Rule 62-210.200(PTE), F.A.C.]EMISSIONS STANDARDS
8. Emissions Standards

P ollutant : Emissions from each CTG set shall not exceed the following emission standards.

Fuel Emission Standard a,b Basis Compliance Demonstration c

NO X Oil 8.0 ppmvd @15% O 2 Application 30 unit rolling operating days ( Compliance by CEMS) 42 ppmvd @15% O 2 Subpart KKKK

Gas 2.0 ppmvd @15% O 2 Application 15 ppmvd @15% O 2 Subpa rt KKKK

CO Oil 35.0 ppmvd @15% O 2 Application Avoids PSD Initial Stack Test Only 195 lb/hour

Gas 9.0 ppmvd @15% O 2 Application Avoids PSD Initial Stack Test Only 56.2 lb/hour

VOC Oil 10.0 ppmvd @15% O 2 Application Avoids PSD Initial Stack Test Only 37.0 lb/hour

Gas 1.2 ppmvd @15% O 2 Application Avoids PSD Initial Stack Test Only 4.1 lb/hour

SO 2 d Oil, Gas 2.0 gr. sulfur/100 SCF gas 0.0015% sulfur fuel oil f Application Subpart KKKK Fuel Record Keeping

PM/PM 10 /PM 2.5 e Oil, Gas 2 .0 gr. sulfur/100 SCF gas 0.0015% sulfur fuel oil f Application Avoids PSD Fuel Record Keeping

10 percent opacity Initial and Annual Visible Emissions Test g

a. Concentration standards are expressed as parts per million, by volume, dry at 15 percent oxyg en and abbreviated as ppmvd @15% O 2 . b. The m ass emission rate standards are expressed as pounds per hour (lb/hour) and are based on a turbine inlet condition of 59°F
, no inlet air

- cooling, and 100% load . The results and may be adjusted to actual test condit ions in accordance with the performance curves and/or equations filed with the Department.

c. “Unit operating day” means a 24

- hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. It is not nec essary for fuel to be combusted continuously for the entire 24

- hour period. [40 CFR 60.4420] d. The applicant requested the stated sulfur fuel limits. These satisfy the emission standards contained in NSPS Subpart KKKK.

e. The fuel sulfur specifications combined with the low NO X emission limit, efficient combustion design and operation of the combustion turbines effectively limit the potential PM/PM 10 /PM 2.5 emissions

. Compliance with the fuel specifications and visible emission standards shall serve as indicat ors of good combustion. f. Compliance with the fuel sulfur specifications shall be determined by the methods for determination of fuel sulfur as detailed in Condition 25 of this permit.
g. Compliance with the 10% opacity standard shall be demonstrated by conduct ing 30

- minute tests in accordance with EPA Method 9 - Visual Determination of Opacity. [Application No. 0110036-010- AC; Avoidance of Rule 62-212.400(4) through (12), F.A.C. ; 40 CFR 60 Subpart KKKK]EXCESS EMISSIONS {Permitting Note: The following conditions apply only to the SIP-based emissions standards specified in Condition No. 8 of this section. Rule 62-210.700, F.A.C. (Excess Emissions) cannot vary or supersede any federal provision of the NSPS, or Acid Rain programs.}
9. Alternate Visible Emissions Standard:

10. Visible emissions due to startups, shutdowns, fuel switches, and malfunctions shall not exceed 10% opacity except for up to ten, 6-minute averaging periods during a calendar day, which shall not exceed 20% opacity. [Application No. 0110036-010- AC ; Rule 62-4.070(3), F.A.C.]

a. Startup is defined as the commencement of operation of any emissions unit which has shut down or ceased operation for a period of time sufficient to cause temperature, pressure, chemical or pollution control devi ce imbalances, which result in excess emissions. [Rule 62-210.200( Definitions ), F.A.C.] Definitions:

b. Shutdown is the cessation of the operation of an emissions unit for any purpose. [Rule 62-210.200( Definitions ), F.A.C.]

c. Malfunction is defined as any unavoidable mech anical and/or electrical failure of air pollution control equipment or process equipment or of a process resulting in operation in an abnormal or unusual manner. [Rule 62-210.200( Definitions ), F.A.C.]
11. Excess Emissions Prohibited

12. : Excess emissions caused entirely or in part by poor maintenance, poor operation or any other equipment or process failure that may reasonably be prevented during startup, shutdown or malfunction shall be prohibited. All such preventable emissions shall be included in any compliance determinations based on CEMS data. [Rule 62-210.700(4), F.A.C.]
Excess Emissions Allowed

a. STG/HRSG System Cold Startup : F or cold startup of the steam turbine system, excluded emissions from any CTG/HRSG system shall not exceed eight (8) hours in any 24-hour period. A cold “startup of the steam turbine system” is defined as startup of the 3 -on-1 combined cycle system followi ng a shutdown of the steam turbine lasting at least 48 hours. : As specified in this condition, excess emissions resulting from startup, shutdown, fuel switching and documented malfunctions are allowed provided that operators employ the best operational practices to minimize the amount and duration of emissions during such incidents. For each CTG/HRSG system, excess emissions of NO X resulting from startup, shutdown, or malfunction shall be excluded from CEMS data in any 24-hour period (“any 24-hour period” means a calendar day, midnight to midnight) for the following conditions: (These conditions are considered separate events and each event may occur independently within any 24 -hour period):

{Permitting Note: During a cold startup of the STG system, each CTG/HRSG system is sequentially brought on line at low load to gradually increase the temperature of the STG and prevent therma l metal fatigue. Note that shutdowns and documented malfunctions are separately regulated in accordance with the requirements of this condition.}
b. CTG/HRSG System Cold Startup : For cold startup of a CTG/HRSG system, excluded emissions shall not exceed four (4) hours in any 24-hour period. “Cold startup of a CTG/HRSG system” is defined as a startup after the pressure in the high

- pressure (HP) steam drum falls below 450 psig for at least a one -hour period.c. CTG/HRSG System Warm Startup : For warm startup of a CTG/HRSG system, excluded emissions shall not exceed two (2) hours in any 24-hour period. “Warm startup of a CTG/HRSG system” is defined as a startup after the pressure in the HP steam drum is above 450 psig.
d. Shutdown Combined Cycle Operation: For shutdown of the combined cycle operation, excluded emissions from any gas turbine/HRSG system shall not exceed three hours in any 24 -hour period.

e. CTG /HRSG System Shutdown : For shutdown of the gas turbine/HRSG operation, excluded emissions from any gas turbin e/HRSG system shall not exceed two hours in any 24-hour period.
f. Fuel Switching : For fuel switching, excluded emissions shall not exceed two (2) hours in any 24-hour period for each fuel switch and no more than four hours in any 24-hour period for any gas turbine/HRSG system.

g. Documented Malfunction : For the gas turbine/HRSG system, excess emissions of NO x resulting from documented malfunctions shall not exceed two hours in any 24-hour period. A “documented malfunction” means a malfunction that is documented within one working day of detection by contacting the Compliance Authority by telephone, facsimile transmittal, or electronic mail.
13. Combustor Tuning

TESTING REQUIREMENTS : CEMS data collected during initial or other major combustor tuning sessions and during manufacturer required Full Speed No Load (FSNL) trip tests shall be excluded from the CEMS compliance demonstration provided the tuning session is performed in accordance with the manufacturer’s specifications. A “major tuning session” would occur after completion of in itial construction, a combustor change-out, a major repair or maintenance to a combustor, or other similar circumstances. Prior to performing any major tuning session, the permittee shall provide the Compliance Authority with an advance notice of at least one working (business) day that details the activity and proposed tuning schedule. The notice may be by telephone, facsimile transmittal, or electronic mail. [Design; Rule 62 -4.070(3), F.A.C.]

14. Operating Rate During Testing

15. : Initial and annual stack tests shall be conducted at 90% or greater of the design heat input ratings provided in emissions unit description above and corrected as described therein. If it is impracticable to test within the described range, the combustion turbin e may be tested at less than the described range. In such case, the reported mass emission rates (corrected as described in Condition 8, footnote b above) shall be further corrected by dividing the result by the percent of the design heat rating at which the test was conducted and multiplying by 100%. [Rule 62-297.310, F.A.C.; 40 CFR 60.8] Initial Compliance De monstration

16. : Initial compliance stack tests while firing natural gas shall be conducted or commence (based on averaging period) within 60 days af ter achieving the maximum production rate, but not later than 180 days after the initial startup . Initial testing on fuel oil shall be conducted or commence (based on averaging period) within 60 days of any fuel oil firing in the CTG. In accordance with the test methods specified in this permit, the combustion turbines shall be tested to demonstrate initial compliance with the mass emission rate standards for NO X , CO, VOC and with the visible emissions standard

. [Rules 62-4.070, 62-297.310(7)(a), F.A.C.; 40 CFR 60.8] Subsequent Compliance Testing : Annual compliance tests for visible emissions shall be conducted during each federal fiscal year (October 1 st to September 30 th ) while firing natural gas. Visible emissions tests shall also be performed while firing fuel oil, on each combustion turbine that is fired with fuel oil, for more than 400 hours during the federal fiscal year.{Permitting Note: After initial compliance with the VOC standards is demonstrated, annual compliance tests for VOC emissions are not required. The Department retains the authority to

r equire VOC testing for the reasons given in Appendix C, Condition 10, Special Compliance Tests.} [ Rule s 62-4.070(3) and 62-297.310(7)(a)4, F.A.C.]
17. Continuous Compliance

18. : The permittee shall de monstrate continuous compliance with the 30-unit operating days rolling average NO X emissions standards based on data collected by the certified CEMS. Within 45 days of conducting any RATA on a CEMS, the permittee shall submit a report to the Compliance Authority summarizing results of the RATA. [Rule 62-4.070(3), F.A.C.; 40 CFR 60 Subpart KKKK] Compliance for PM/PM 10 /PM 2.5

19. : In stack compliance testing is not required for PM/PM 10 /PM 2.5 . Compliance with the limits and control requirements is based on th e fuel sulfur recordkeeping required in Specific Condition 25, the visible emissions standard and CEMS for NO X (which is a PM 2.5 and condensable PM precursor). [Rule 62-4.070(3), F.A.C.]

Test Requirements

20. : The permittee shall notify the Compliance Author ity in writing at least 15 days prior to any required tests. Tests shall be conducted in accordance with the applicable requirements specified in Appendix D (Common Testing Requirements) of this permit. [Rule 62-297.310(7)(a)9, F.A.C.]
Test Methods

Method : Required initial and annual compliance stack tests shall be performed in accordance with the following reference methods.
Description of Method a
7E Determination of NO X Emissions from Stationary Sources (Instrumental Analyzer Procedure)
9 Visual Det ermination of the Opacity of Emissions from Stationary Sources
10 Determination of C O Em issions from Stationary Sources
18 b Measurement of Gaseous Organic Compound Emissions by Gas Chromatography
25A b Determination of Total Gaseous Organic Concentra tion using Flame Ionization Analyzer

a. The methods are described in 40 CFR 60, Appendix A, and adopted by reference in Rule 62

- 204.800, F.A.C. No other methods may be used for compliance testing unless prior written approval is received from the Department ’s Office of Permitting and Compliance in accordance with an alternate sampling procedure pursuant to 62

- 297.620, F.A.C. b. EPA Method 25A is used to determine VOC. EPA Method 18 may be used to determine and deduct emissions of methane and ethane from the em issions measured using Method 25A when deter mining VOC emissions. [Rule 62-204.800 F.A.C.; Rule 62-297.100 F.A.C.; 40 CFR 60 Appendix A]

MONITO R ING REQUIREMENTS
21. Continuous Emissions Monitoring System(s) (CEMS) : The permittee shall install, calibrate, mai ntain, and operate CEMS to measure and record the emissions of NO X from the combined cycle CTG s in a manner sufficient to demonstrate continuous compliance with the CEMS emission standards of this section. Each monitoring system shall be installed, calibr ated, and properly functioning prior to the initial performance tests. Within one working day of discovering emissions in excess of a NO X standard (and subject to the specified averaging period), the permittee shall notify the Compliance Authority.a. NO X Monitors: Each NO X monitor shall be certified, operated, and maintained in accordance with the requirements of 40 CFR 75. Record keeping and reporting shall be conducted pursuant to Subparts F and G in 40 CFR 75. The RATA tests required for the NO X monitor shall be performed using EPA Method 20 or 7E in Appendix A of 40 CFR 60.
b. Diluent Monitors: The O 2 or carbon dioxide ( CO 2 ) content of the flue gas shall be monitored at the location where NO X are monitored to correct the measured emissions rates to 15 % oxygen. If a CO 2 monitor is installed, the O 2 content of the flue gas shall be calculated using F-factors that are appropriate for the fuel fired. Each monitor shall comply with the performance and quality assurance requirements of 40 CFR 75.
22. CEMS Dat a Requirements

a. Data Collection : Emissions shall be monitored and recorded at all times including startup, operation, shutdown, and malfunction except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments. The CEMS shall be designed and operated to sample, analyze, and record data evenly spaced over an hour. If the CEMS measures concentration on a wet basis, the CEM system shall include provisions to determine the moisture content of the exhaust gas and an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). Alternatively, the owner or operator may develop through manual stack test measurements a curve of moisture contents in the exhaust gas versus load for each allowable fuel, and use these typical values in an algorithm to enable correction of the monitoring results to a dry basis (0% moisture). Final results of the CEMS shall be expressed as ppmvd corrected to 15% O 2 . The CEMS shall be used to demonstrate compliance with the CEMS emission standards for NO X as specified in this permit. For purposes of determining compliance with the CEMS emissions standards of this permit, missing (or excluded) data shall not be substituted. Upon request by the Department, the CEMS em ission rates shall be corrected to International Organization of Standardization (ISO) conditions. :

b. Valid Hour : Hourly average values shall begin at the top of each hour. Each hourly average value shall be computed using at least one data point in each fifteen -minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly value shall be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour). If less than two such data points are available, the hourly average value is not valid. An hour in which any oil is fired is attributed towards compliance with the permit standards for oil firing. The permittee shall use all valid measurements or data points collected during an hour to calculate the hourly average values.

c. 30-Unit Operating Day Rolling Averages : Compliance shall be determined after each operating day by calculating the arithmetic average of all t he valid hourly averages from that operating day and the prior 29 operating days. For purposes of determining compliance with the 30-unit operating day rolling CEMS standards, the missing data substitution methodology of 4 0 CFR Part 75 Subpart D, shall not be utilized. Instead, the 30-unit operating day rolling average shall be determined using the remaining hourly data in the 30-day rolling period. {Permitting Note: There may be more than one 30-unit operating day compliance demonstration required for NO X emissions depending on the use of alternate fuels.}d. Data Exclusion: Each CEMS shall monitor and record emissions during all operations including episodes of startup, shutdown, malfunction, fuel switches and combustor tuning. Some of the CEMS emissi ons data recorded during these episodes may be excluded from the corresponding CEMS compliance demonstration subject to the provisions of Condition Nos . 12 and 13 of this section. All periods of data excluded shall be consecutive for each such episode and only data obtained during the described episodes (startup, shutdown, malfunction, fuel switches, combustor tuning) may be used for the appropriate exclusion periods. The permittee shall minimize the duration of data excluded for such episodes to the exte nt practicable. Data recorded during such episodes shall not be excluded if the episode was caused entirely or in part by poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented. Best operational pra ctices shall be used to minimize hourly emissions that occur during such episodes. Emissions of any quantity or duration that occur entirely or in part from poor maintenance, poor operation, or any other equipment or process failure, which may reasonably be prevented, shall be prohibited.

e. Availability : Monitor availability for the CEMS shall be 95% or greater in any calendar quarter. The quarterly excess emissions report shall be used to demonstrate monitor availability. In the event 95% availability is not achieved, the permittee shall provide the Department with a report identifying the problems in achieving 95% availability and a plan of corrective actions that will be taken to achieve 95% availability. The permittee shall implement the reported corrective actions within the next calendar quarter. Failure to take corrective actions or continued failure to achieve the minimum monitor availability shall be violations of this permit, except as otherwise authorized by the Department’s Compliance Authorit y. [Rule 62-297.520, F.A.C.; 40 CFR 60.7(a)(5); 40 CFR 60.13; 40 CFR Part 51 Appendix P; 40 CFR

60 Appendix B - Perfor mance Specifications; 40 CFR 60 Appendix F - Q uality Assurance Procedures; Rule 62-4.070(3), F.A.C.]

RECORDS AND REPORTS
23. Monitoring of Cap acity

24. : The permittee shall monitor and record the oper ating rate of each CTG and HRSG system on a daily average basis, considering the number of hours of operation during each day (including the times of startup, shutdown, malfunction and fuel switching ). Such monitoring shall be made using a monitoring component of the CEMS required above, or by monitoring daily rates of consumption and heat content of each allowable fuel in accordance with the provisions of 40 CFR 75 Appendix D. [Rule 62-4.070(3), F.A. C.] Monthly Operations Summary

25. : By the fifth calendar day of each month, the permittee shall record the following for each fuel in a written or electronic log for each CTG for the previous month of operation: fuel consumption, hours of operation, and the updated 12-month rolling totals for each. Information recorded and stored as an electronic file shall be available for inspection and printing within at least three days of a request by the Department. The fuel consumption shall be monitored in accordanc e w ith the provisions of 40 CFR 75 Appendix D. [Rules 62-4.070(3), F.A.C.]
Fuel Sulfur Records

a. Natural Gas: Compliance with the fuel sulfur limit for natural gas shall be demonstrated by keeping reports obtained from the vendor indicating the average sulfur content of the natural gas being supplied from the pipeline for each month of operation. Methods for determining the : The permittee shall demonstrate compliance with the fuel sulfur limits specified in this permit by maintaining the following records of the sulfur contents.sulfur content of the natural gas shall be ASTM methods D4084-82, D4468-85, D5504-01, D6228-98 and D6667-01, D3246-81 or more recent versions.
b. ULSD Fuel Oil: Compliance with the distillate fuel oil sulfur limit shall be demonstra ted by taking a sample, analyzing the sample for fuel sulfur, and reporting the results to each Compliance Authority before initial startup. Sampling the fuel oil sulfur content shall be conducted in accordance with ASTM D4057-88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, and one of the following test methods for sulfur in petroleum products: ASTM methods D5453-00, D129-91, D1552-90, D2622-94, or D4294-90. More recent versions of these methods may be used. For each subse quent fuel delivery, the permittee shall maintain a permanent file of the certified fuel sulfur analysis from the fuel vendor. At the request of a Compliance Authority, the permittee shall perform additional sampling and analysis for the fuel sulfur content. The above methods shall be used to determine the fuel sulfur content in conjunction w ith the provisions of 40 CFR 75 App endix D. [Rule 62-4.070(3), F.A.C ; Rule 62-4.160(15), F.A.C.]
26. Emissions Performance Test Reports

27. : A report indicating the results of any required emissions performance test shall be submitted to the Compliance Authority no later than 45 days after completion of the last test run. The test report shall provide sufficient detail on the tested emission unit and the procedures used to allow the Department to determine if the test was properly conducted and if the test results were properly computed. At a minimum, the test report shall provide the applicable information listed in Rule 62-297.310(8)(c), F.A.C. and in Appendix C of this p ermit. [Rule 62-297.310(8), F.A.C.]

a. Malfunction Notification: If emissions in excess of a standard (subject to the specified averaging period) occur due to malfunction, the permittee shall notify the Compliance Authority within (1) working day of: the nature, extent, and duration of the excess emissions; the cause of the excess emissions; and the actions taken to correct the problem. In addition, the Department may request a written summary report of the incident. Excess Emissions Reporting:

b. SIP Quarter ly Permit Limits Excess Emissions Report : Within 30 days following the end of each calendar -quarter, the permittee shall submit a report to the Compliance Authority summarizing periods of NO X emissions in excess of the SIP permit emission standards , and the amount of authorized data excluded following the format in Appendix XS attached to this permit . Periods of startup, shutdown, malfunction, fuel switching and tuning shall be monitored and recorded at all times. In addition, the report shall summarize the CEMS systems monitor availability for the previous quarter.

c. NSPS Semi- Annual Excess Emissions Reports : For purposes of reporting emissions in excess of NSPS Subpart KKKK, excess emissions from the CTG s are defined as: a specified averaging period over which either the NO X emissions are greater than 15 ppm at 15% O 2 on a 30- day rolling average while firing natural gas and greater than 42 ppm at 15% O 2 on a 30-day rolling average while firing ultra low sulfur fuel; or the total sulfur content of the fuel being combusted in the affected facility exceeds the limit specified in 40 CFR 60.4330. Within thirty (30) days following each calendar semi -annual period, the permittee shall submit a report on any periods of excess emissions that occurred during the previous semi -annual period to the Compliance Authority.{Note: If there are no periods of excess emissions as defined in NSPS Subpart KKKK, a statement to that effect may be submitted with the SIP Quarterly Report to suffice for the NSPS Semi-Annual Report.} [Rule 62-4.130, F.A.C.; Rule 62-204.800, F.A.C.; Rule 62-210.700(6), F.A.C.; 40 CFR 60.7; 40 CFR 60.4420]
28. Annual Operating Report : The permittee shall submit an annual report that summarizes the actual operating hours and emissions from this faci lity. The permittee shall also keep records sufficient to determine the annual throughput of ULSD fuel oil for the fuel oil storage tank for use in the Annual Operating Report. Annual operating reports shall be submitted to the Compliance Authority by Ap ril 1st of each year. [Rule 62 -210.370(2), F.A.C.]This section of the permit addresses the following emissions units.

ID No. Emission Unit Description

023 One natural gas fueled auxiliary boiler rated at 99.8 MMBtu /h our heat input (HHV) or less

028 Two temporary natural gas or ULSD oil f ueled construction boilers rated at 150 MMBtu /h our (HHV)

APPLICABLE STANDARDS AND REGULATIONS
1. NSPS Requirements

a. Auxiliary Boiler: The natural gas fueled auxiliary boiler is subject to the appli cable requirements

o f NSPS Subpart Dc - Standards of Performance for Small Industrial- Commercial

- Institutional Steam Generating Units

. Specifically, this emission unit shall comply with 40 CFR 60.48c Reporting and Recordkeeping Requirements. Initial notification is required for the auxiliary boiler pursuant to NSPS Subpart A, Section 60.7. [Rules 62-204.800(8)(d); Rule 62-204.800(8 )(b) 4., F.A.C. ; NSPS Subpart A; NSPS Subpart Dc ] :

b. Temporary Construction Boilers: If applicable, the two temporary 150 MMBtu (HHV) natural gas or ULSD fuel oil boilers are subject to the requirements of NSPS Subpart Db - Standards of Performance for Industrial- Commercial

- Institutional Steam Generating Units

. {Permitting Note: The NSPS Subpart Db would only apply if the temporary construction boile r meets the applicability. The affected facility to which this subpart applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of greater than 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)). [Rules 62-204.800(8)(d), F.A.C; Rule 62-204.800(8)(b)3., F.A.C.; NSPS Subpart A ; NSPS Subpart Db ]
2. NES HAP Requi rements

3. : The auxiliary boiler and the two temporary construction boilers are subject to the applicable requirements of NESHAP Subpart A – General provisions and Subpart DDDDD – N ESHAP for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters

. [Rules 62-204.800(11)(d)1., F.A.C. ; NESHAP Subpart A ; NESHAP Subpart D DDDD ]
BACT Determinations

{Permitting Note: These BACT determinations are not pursuant to the Department’s BACT requirements pursuant to Rule 62-212.400, F.A.C. – PSD} : Determinations of the Best Available Control Technology (BACT) were conducted for SO 2 and PM pursuant to Department requirements for Fossil Fuel Steam Genera tors with less t han 250 MMBtu/hour h eat input fossil fuel boilers

.

[ Rule 62-296.406(2) and (3), F.A.C.] EQUIPMENT
4. Auxiliary Boiler

5. : The permittee is a uthorize d to install , operate, and maintain one natural gas fueled auxiliary boiler with a design heat input of capacity 99.8 MMBtu /h our (HHV) and a nominal steam rating of 85,000 lb/hour. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] Temporary Construction Boilers : The permittee is a uthorize d to install, operate, and maintain two natural gas or ULSD fuel oil fired temporary construction boilers, each with a heat input capacity of 150 MMBtu/hour (H HV) . [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.]OPERATION RESTRICTIONS
6. Auxiliary Boiler Operation

7. : The hours of operation of the auxiliary boiler shall not exceed 2,000 hours/ year . [Application No. 0110036-010- AC; 62-210.200(PTE), F.A.C.] Temporary Construction Boiler Operation

EMISSION STANDARDS : The two temporary construction boilers are allowed to operate a combined total of 3,000 hours/ year . The temporary boilers shall not operate beyond the expiration date of this permit. [Application No. 0110036-010- AC]

8. Auxiliary Boiler Emission Standards

a. Visible Emissions: Visible emissions shall not exceed 20 percentopacity except for one sixminute period per hour during which opacity shall not exceed 27 percent. :

b. Fuel Specifications: The auxiliary boiler shall fire only natural gas with a maximum sulfur content of 2.0 gr/100 SCF. {Permitting Note: NSPS Subpart Dc does not contain any emission standards for units firing onlynatural gas. NESHAP Subpart DDDDD contains only work practice standards such as annual tuneups in lieu of emission standards for units firing only natural gas.} [Application No. 0110036-010- AC; Rule 62-296.406(1), (2) and (3), F.A.C. – Visible Emissions and B ACT for PM and SO 2 ]
9. Temporary Construction Boiler Emission Standards

a. Visible Emissions: Visible emissions shall not exceed 20 percentopacity except for one sixminute period per hour during which opacity shall not exceed 27 percent. [Application No. 0110036-010- AC; Rule 62-296.406(1), F.A.C. – Visib le Emissions] :

b. Fuel Specifications : The two temporary construction boilers shall fire only natural gas with a maximum sulfur content of 2.0 gr /100 SCF or ULSD fuel oil with a sulfur content of 0.0015 percent. [Application No. 0110036-010- AC; Rule 62-296.406(2) and (3), F.A.C. – BACT for PM and SO 2 ]

c. NO X : If NSPS Su bpart Db is applicable, emissions of NO X (expressed as NO 2 ) from the two temporary construction boilers shall not exceed 0.10 lb/MMBtu heat input on a 30-day rolling basis

. [Rule 62-204.800(8)(b)3., F.A.C.; NSPS Subpart Db, Section 60.44b(a)(1)(i)] {Permitting Note: The NSPS Subpart Db would only apply if the temporary construction boiler

meets the applicability. The affected facility to which this subpart applies is each steam generating unit that commences construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the steam generating unit of greater than 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)). NESHAP Subpart DDDDD was promulgated on March 21, 2011. On December 23, 2011 EPA published notice of a full consideration of NESHAP Subpart DDDDD that is expected to be finalized by Summer 2012 thus replacing the previous version. NESHAP Subpart DDDDD does not apply to “temporary boilers” as defined in the subpart.} TESTING REQUIREMENTS
10. Auxiliary Boiler Testing Requirements : The auxiliary boiler shall be tested to demonstrate initial compliance with the emission standard for visible emissions. The te sts shall be conducted using EPA Method 9 within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup. [Rule 62-297.310(7)(a)1, F.A.C.]11. Temporary Construction Boiler Testing Requirements

a. Visible Emissions: :

Initial Test : The temporary construction boilers shall be tested to demonstrate initial compliance with the emission standard for visible emissions. The tests shall be conducted using EPA Method 9 within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup. [Rule 62-297.310(7)(a)1, F.A.C.] Continuous Opacity Monitoring System (COMS)

b. NO X : If NSPS Subpart Db is applicable, t he permittee shall install, calibrate, maintain and operate a NO X - CEMS in accordance wit h 40 CFR 60, Appendix B, PS-2 and Appendix F and for the purpose of demonstrating compliance with the emission standard of 0.10 lb/ MMBtu on a 30- day rolling basis. [Rule 62-204.800(8)(b)3., F.A.C.; NSPS Subpart Db, Section 60.46b] : If NSPS Subpart D b is applicable, i n accordance with 40 CFR 60.48b(a) the permittee shall install, calibrate, operate and maintain a COMS to continuously monitor and record opacity from the steam generating unit. The COMS shall be certified pursuant to 40 CFR 60 Appendix B, Performance Specification 1. In lieu of COMS, the applicant can submit a site -specific opacity monitoring plan to the Department for approval

.

12. Reporting : The permittee shall maintain records of the amount of natural gas used in the auxiliary boiler and the temporary construction boilers . These records shall be submitted to the Compliance Authority on an annual basis or upon request. [Rule 62-4.070(3), F.A.C.]This sec tion of the permit addresses the following emissions unit.

EU No. Emission s Unit Description

024 Two nominal 9.9 MM Btu/h ou r (HHV) natural gas

- fired process heaters (one is a spare)

1. Equipment

2. : The permittee is authorized to install, operate, and maintain two 9.9 MMBtu /h ou r (HHV) process heaters for the purpose of heating the natural gas supply to the CTGs. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] Hours of Operation

3. : The two natural gas- fueled process heaters are allowed to operate a combined total of 8 ,760 hours /year . [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] Notification, Recordkeeping and Reporting Requirements : The permittee shall maintain records of the amount of natural gas used in the process heaters. These records shall be submitted to the Compliance Authority on an annual basis or upon request. [Rule 62-4.070(3), F.A.C]This section of the permit addresses the following emissions unit.

EU No. Emission Unit Description

025 Three nominal 5,514 horsepower (hp) natural gas f ueled combustion turbine- compressors Design Heat Input Rating: The design heat input rating of each combustion turbine- compressor is 56.6 MMBtu /hr based on turbine inlet conditions at 59°F, H HV of natural gas and 100% load (51.4 M MBtu /hr, LHV). Actual heat input rate will vary depending upon gas turbine characteristics and ambient conditions.

APPLICABLE STANDARDS AND REGULATIONS 1. NSPS Requirements

EQUIPMENT : The combustion turbine- compressors shall comply with the applicable NSPS in 40 CFR 60, including: Subpart A - General Provisions and Subpart KKKK - Standards of Performance for Stationary Gas Turbines. See Appendix Subpart A and Appendix KKKK. [Rule 62-204.800(7)(b), F.A.C.; 40 CFR 60 Subpart A; 40 CFR 60 Subpart KKKK]

2. Comb ustion Turbine Compressors

E MISSIONS CONTROL : The permittee is authorized to install, tune, operate, and maintain three nominal 5,514 hp natural gas fueled combustion turbine- compressors

. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.]

3. Le an Premix Combustion:

PERFORMANCE RESTRICTIONS The permittee shall employ lean premix combustion technology such as DLN, SoLoNO X , or Dry Low Emissions (DLE) to control NO X emissions and sufficiently high combustion temperature to control CO emissions. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.]

4. Authorized Fuel

5. : The combustion turbine- compressors shall only fire natural gas, which shall contain no more than 2.0 grains of sulfur per 100 standard cubic feet (gr/100 SCF) of natural gas. [Application No. 0110036-010- AC; Rule 62-210.200(PTE), F.A.C.] Hours of Operation and Fuel Specifications

6. : The three combustion turbine- compressor s are allowed to operate a combined total of 17,520 hr/yr. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] NSPS Subpart KKKK Applicability : The compressors shall comply with all appli cable requirements of 40 CFR 60 listed below, adopted b y reference in Rule 62 -204.800(8 )(b) 78, F.A.C. [40 CFR 60 Subpart KKKK - Standards of Performance for Stat ionary Combustion Turbines]7. Emissions Standard

Pollutant s : Each combustion turbine-compressor shall comply with the following emission limits.

Emission Standard Basis Compliance a

NO X 15 .0 ppmvd @15% O 2 Application 30 unit rolling operating days ( Comp liance by CEMS) 25 ppmvd @15% O 2 Subpart KKKK
CO 2 5.0 ppmvd @15% O 2 Application, Avoids PSD Initial Stack Test Only

SO 2 b 2.0 gr. sulfur/100 SCF gas b Application Subpart KKKK Fuel Record Keeping

PM/PM 10 /PM 2.5 c 2.0 gr. sulfur/100 SCF gas Application
, Avoids PSD Fuel Record Keeping
10 percent opacity d Initial and Annual Visible Emissions Test

a. “Unit operating day” means a 24

- hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. It i s not necessary for fuel to be combusted continuously for the entire 24

- hour period. [40 CFR 60.4420] b. The applicant requested the stated sulfur fuel limits. These satisfy the emission standards contained in NSPS Subpart KKKK. Compliance with the fuel sulfur specifications shall be determined by the methods for determination of fuel sulfur as detailed in Section 3. A. Condition 25 of this permit.

c. The fuel sulfur specifications combined with the low NO X emission limit, efficient combustion design and opera tion of the combustion turbines effectively minimize potential PM/PM 10 /PM 2.5 emissions. Compliance with the fuel specifications and visible emission standards shall serve as indicators of good combustion. d. Compliance with the 10% opacity standard shall be demonstrated by conducting 30

- minute tests in accordance with EPA Method 9 - Visual Determination of Opacity. [Application No. 0110036-010- AC ; 40 CFR 60 Subpart KKKK]
8. Compressor Testing Requirements

9. : Each unit shall be stack tested to demonstrate initial compliance with the emission standards for CO, NO X and visible emissions. The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup. [Rule 62-297.310(7)(a)1, F.A.C.; 40 CFR 60.8; 40 CFR 60.4400 ]
Test Methods

Method : Any required tests shall be performed in accordance with the following reference methods.
Description of Method and Comments

7E Determination of Nitrogen Oxide Emissions from Stationary Sources

20 Determination of NO X , SO 2 and diluents emissions from stationary CTs

9 Visual Determination of the Opacity of Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources
[Rule 62-4.070(3), F.A.C.; 40 CFR 60 Subpart KKKK ; 40 CFR 60.8]
10. Notification, Recordkeeping and Reporting Requirements : The permittee shall maintain records of the amount of natural gas used in the compressor station and shall comply with the notification, recordkeeping and reporting requirements pursuant to 40 CFR 60.44375 and 40 CFR 60.7. These records shall be submitted to the Compliance Authority on an annual basis or upon request. [Rule 62-4.070(3), F.A.C.; 40 CFR 60 Subpart A; 40 CFR 60 Subpart KKKK ]The specific conditions in this section apply to the following emissions unit(s):

EU No. Brief Description
026 and 027 Two 2,250 kilowatts (kW) emergency generators ( model year 2011 and later )

APPLICABLE STANDARDS AND REGULATIONS
1. NSPS, Subpart IIII Applica bility

2. : Th e emergency generator s are Stationary Compression Ignition Internal Combustion Engines (Stationary ICE) and are subject to 40 CFR 60 Subpart IIII. The applicant shall comply with 40 CFR 60 Subpart IIII only to the extent that the regulations apply to the emission unit and its operations (e.g. non- road, emergency, displacement, capacity and model year selected). [40 CFR 60 S ubpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines; Rule 62-204.800(8)(b)79., F.A.C.] NESHAP, Subpart ZZZZ Applicability

EQUIPMENT SPECIFICATIONS : Th e emergency generators are Stationary Rec iprocating Internal Combustion Engines located at a major source of hazardou s air pollutants emissions and are subject to 40 CFR 63 Subpart ZZZZ. Because these emergency generator s are subject to regulation under 40 CFR 60 Subpart IIII, Subpart ZZZZ only requires that the emergency generator s mee t the requirements of 40 CFR 60 Subpart IIII. No further requirements of Subpart ZZZZ apply to the emergency generator s. [40 CFR 63 S ubpart ZZZZ - National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines, section 63.6590(c); Rule 62-204.800(11)(b)82., F.A.C.]

3. Equipment

EMISSIONS AND PERFORMANCE REQUIREMENTS : The permittee is authorized to install, operate, and maintain two fuel oil- fired emergency generator s. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.]

4. Hours of Operation and Fuel Specifications

5. : The hours of operation shall not exceed 100 hours/ year /unit. The generators shall burn distillate fuel oil with a sulfur content of 15 parts per million (ppm) or less. [Application No. 0110036-010- AC ; Rule 62-210.200(PTE), F.A.C.] Emergency Generator Emission Limit

Emergency Generator (> 560 kW) s :
CO ( g/kW -hr) 1 PM ( g/kW -hr) NMHC 2 +NO X ( g/kW -hr) Diesel Fuel 3 (sulfur) Model year 2011 and later 3.5 0.20 6.4 15 ppm

1. g/kW

- hr means grams per kilowatt

- hour. 2. NMHC means Non

- Methane Hydrocarbons. 3. Nonroad diesel specification of 15 ppm is from 40 CFR part 80, subpart I – Motor Vehicle Diesel Fuel; Nonroad, Locomotive, and Marine Diesel Fuel; and ECA Marine Fuel. [Application No. 0110036-010- AC ; NSPS Subpart IIII ]
6. Emergency Generator Testing Requirements : Each unit shall be stack tested to demonstrate initial compliance with the emission standards for CO , and NO X . The tests shall be conducted within 60 days after achieving the maximum production rate at which the unit will be operated, but not later than 180 days after the initial startup of this unit . As an alternative, an EPA c ertification of emissions characterist ics of the purchased model that are at least as stringent as the NSPS Subpart IIII values and the use of ultralow sulfur distillate fuel oil or nonroad diesel fuel wi th a sulfur content of 15 ppm or less can be use d to fulfill this requirement. [Rule 62-297.310(7)(a)1, F.A.C.; 40 CFR 60.8; 40 CFR 60.4211]7. Test Methods

Method : Any required tests shall be performed in accordance with the following reference methods.

D escription of Method and Comments

7E Determination of Nitrogen Oxides Emissions from Stationary Sources

10 Determination of Carbon Monoxide Emissions from Stationary Sources
NOTIFICATION, REPORTING AND RECORDS
8. Notifications

9. : Initial notifications are r equired pursuant to 40 CFR 60.7, 40 CFR 63.9, and 40 CFR 63.6590(b) (i) for the 2,250 kW emergency generator s. Reporting : The permittee shall maintain records of the amount of liquid fuel used. These records shall be submitted to the Compliance Authority on an annual basis or upon request. [Rule 62-4.070(3), F.A.C.]This section of the permit addresses the following emissions unit.

EU No. Emission Unit Description

029 One nominal 300 hp diesel fire pump engine

NSPS AND NESHAP APPLICABILITY
1. NSPS Subpar t IIII Applicability

2. : The pump engine is an Emergency Stationary Compression Ignition Internal Combustion Engine (Stationary ICE) and shall comply with applicable provisions of 40 CFR 60, Subpart IIII. [40 CFR 60, Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines]
NESHAP Subpart ZZZZ Applicability

EQUIPMENT SPECIFICATIONS : The pump engine is a Liquid Fueled Reciprocating Internal Combustion Engine (RICE) and shall comply with applicable provisions of 40 CFR 63, Subpart ZZZZ. Pursuant to 40 CFR 63.6590(c) the engines must meet the requirements of Subpart ZZZZ by meeting the requirements of 40 CFR 60, Subpart IIII. [40 CFR 63, Subpart ZZZZ - National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Int ernal Combustion Engines (RICE)]

3. Engine Driven Fire Pump s

4. : The permittee is authorized to install, operate, and maintain one nominal 300 hp emergency diesel fire pump engine. [Application No. 0110036-010- AC ] Hours of Operation

EMISSION STANDARDS: The fire pump may operate in response to emergency conditions and 100 nonemergency hours per year for maintenance testing. [Application No. 0110036-010- AC ; Rule 62-210.200 (PTE), F.A.C.]

5. Emissions Limits

Emergency Pumps (175 hp ≤ and < 600 hp) : The emergency fire pump engines shall comply with the following emission limits and demonstrate compliance in accordance with the procedures given in 40 CFR 60, Subpart IIII. [40 CFR 60.4211 and Rule 62-4.070(3), F.A.C.]

PM 1 ( g/hp -hr) NMHC 2 +NO X ( g/hp -hr) Diesel Fuel 3 (sulfur) Subpart IIII (2009 and later) 0.15 3.0 15 ppm

1. g/hp

- hr means grams per horsepower

- hour.
2. Non

- Methane Hydrocarbons
3. Nonroad diesel specification of 15 ppm is from 40 CFR part 80, sub part I – Motor Vehicle Diesel Fuel; Nonroad, Locomotive, and Marine Diesel Fuel; and ECA Marine Fuel. [Application No. 0110036-010- AC ; 40 CFR 60, NSPS Subpart IIII; and Rule 62-4.070(3), F.A.C.]

6. Fire Pump Engine Certification : Manufacturer certification shall be provided to the Department in lieu of actual testing. [40 CFR 60.4211; Rule 62-4.070(3), F.A.C.]ID No. Emission Unit Description

030 Nominal 7 Million Gallon Ultralow Sulfur Distillate Fuel Oil Storage Tank

NSPS APPLICABILITY
1. NSPS, Subpart Kb Applicability

EQUIPMENT SPECIFICATIONS : Based on the true vapor pressure of ultralow sulfur distillate fuel (< 3.5 kilopascals), the storage tank is not subject to 40 CFR 60, Subpart Kb - Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Li quid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984. [Application No. 0110036-010- AC ; 40 CFR 60.110b(b)]

2. Equipment

EMISSIONS AND PERFORMANCE REQUIREMENTS : The permittee is authorized to operate, and maintain one nominal 7 million gallon distillate fuel oil storage tank to provide fuel oil to Emission Units 020, 021, and 022 or to other units on the site. [Application No. 0110036-010- AC ]

3. Hours of Operation

NOTIFICATION, REPORTING AND RECORDS : The hours of operation are not restricted (8,760 hours per year). [Application No. 0110036-010- AC ]

4. Ultralow Sulfur Distillate Fuel Oil Records : The permittee shall keep readily accessible records showing the maximum true vapor pressure of the stored liquid. Compliance with this condition may be demonstrated by using the information from the respective manufacturers safety data sheets (MSDS) for the fuel oil stored in the tanks. [Rule 62-4.070(3) F.A.C.; avoidance of 40 CFR 60, Subpart Kb]Florida Power & Light Company, P.O

. Box 14000, Juno Beach, FI 33408-0420 Environmental Services D e partment 

# •
I=PL.

.

J a nuary 20, 2012

J eff Koerner

- Ch ief Bureau of Air Regulation Division of Air Resources Management Florida Department of Environmental Protection 2600 Blair Stone Road Ta llaha ssee, FL 32399

RE: Status U pdate To FPL's BART-Eligible U nits

Dear Mr. Koerner: 

### Via e:mail & 

### U.S. Mail



# REC E I VED

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### RESOURCE M ANAGE M E NT

Since th e 2 00 2 declaration of FPL's BART-eligible units, recent facility changes have altered the composition of our BART-eligible fl eet. At FDEP's request, FPL provides the following status update to its BART-eligible fleet:

The conversion of the Cape Canaveral Power Plant to a combined cycle natural gas-fi red plant, The Cape Ca naver a l Energy Center, ha s removed the fossil steam boilers Cape Canaveral I &2 from the population of BART-eligible Units. The n ew combined cycle gas-fi red units employ Best Available Contro l Tec hn o lo gy (BACT) as outlined in it s Air Co n struct i on penn it 0090006-00 56-AC i ss ued by the Department on July 23, 2009. The former fossil steam boilers
, demoli s hed on August 22,2010 were permitted to bum 2.5% s ulfur #6 fuel oi l and natural gas. The convers ion to hi g hly efficient combined cy cle technology u sing clean-burning n atural gas will s ub sta ntially reduce the visibility imp a irin g emissions of SO " NOx, and Particulate Matter from the si t e.

The conversion of the Rivera Power Plant to a combined cycle natural gas-fired plant, The Riviera Beach Energy Ce nt er, ha s removed the fossil steam b o iler Rivera 4 from the population of BART-eligible Units. Unit 3 at Riviera was not BART-eligible due to its in-service date, but it too was demolished as part of the conversion. T he new combined cycle gas-fired units employ Best Available Control Tec hnol ogy (BACT)

as outlined in it s Air Construction permit 0990042-006-AC i ssue d by the Department o n June 10,2009. The fonner fossil steam boiler s, demolished on June 19
, 20 11 were pennitted to burn 2.5% sulfur #6 fuel oi l and natural gas. The conversion to hi gh l y efficient comb in ed cycle technology using clean-burning natural gas will substantia ll y redu ce the visibility impairin g emissions of SO " NOx, and Particulate Malter from the site.

The planned modernization of the P ort Everg la des Power Plant to a combined cycle natural gas -fir e d plant will further r ed uce FPL's BART-eligible fleet. The Port Everglades Energy Center
, will remov e the fossil steam boilers 3& 4 from th e population of BART-eligible Units. Units 1& 2 at Port Eve r glades were

n ot BART-eligible due to their in -service d ates, h owever, they too will be demolished as part of the modernization. The n ew combined cycle gas-fired units will employ Best Available Contro l Techno logy (BACT). The Site Certification Application and the Air Const ruction Penn it Application for the POIt

FPL FLEET BART UPDATE JAN 2012.doc khvEverglades modernization are expected to be sent to the Department by the end of this month. The fossil steam boilers I through 4 are anticipated to be demolished in the fir st quarter of2013 prior to the BART compliance deadline of December 31,2013. The boilers were pennitted to bum 2.5% su lfur #6 fuel oil and natural gas

. The modernization to highly efficient c omb ined cycle technology using clean-burning natural gas will su b s tantially reduce the visibility impairing emissions of SO " NOx, and Particulate Matter from the site.

These conversions/modernizations along with new unit installations such as the We s t Co unty Energy Center, Turkey Point Unit 5, Manatee Unit 3, Martin Unit 8
, the discontinued operation of Turkey Point 2 and limited operation of Turkey Point 1 have substantially reduced the emissions of visibility impairing pollutants to the Florida airshed in s upport of the C lean Air Visibility Rule goals.

If you have any questions, or require additional infonnation, please call me at (561) 691

- 2877.

Kevin Washi on Project Manager E nvir onmenta l Services Florida Power & Light Company (561) 691-2877 kevin_ washington@fpl.com

Cc: Tom Rogers

- FDEP

- 2

- FP L FLEET BART UPDATE JA N 2012.doc k(w

# K. Lakeland Electric – Charles Larsen Memorial PP

Emission Units shut

- down: 1. EU004 – Unit #7 (BART)

Items included: A screenshot of the Facility and Unit Details from EPA’s Source Management System website showing the retirement of Unit #7.

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### FACILITY AND UNIT DETAILS Charles Larsen Memorial Power Plant, FL (ORISPL 675)

The General Tab for the unit is displayed below.

General

. Un i ts

. Generators " Owners/Operators " Representatives " Co n tacts " prog rams Unit 7: General Owners/Operators Programs

* Required information.
* Unit ID: 7
State Unit ID: ., Is this unit in Indian Country? 

### 0 Yes @ No

" Was the unit moved from another facility? 

### 0 Yes @ No Program(s): ARP,CAIRNOX
, CAIROS
, CAIRS02
, TRNOXOS Type of Unit: Dry bottom wall-fired boiler(DB) Source Category: Electric Utility NAICS Code: 221112

- Fossil fuel electric power generation Heat Input Capacity: 616.0 mmBtu Non-load Based: No Boiler Sequence Number: 464 Commence Operation Date: Commence Commercial Operation Date: 01 / 0111966 Actual Actual 90th Operating Day:

* Operating Status: Retired as of 11126 /2 007 Unit does not Serve an Electrical Generator: No Unit Description: 9/3/2008

- an RUE was received in Aug 2005 A and it was processed

. Another RUE was received in July 2008. Per Farzie Shelton
, V Last Modified: 10 / 22 /2 010 (chillock)

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### https: // camd.epa.gov /s ms / index.cfm?CFID = 44942&CFTOKEN=20984969&jsessionid=4e

... 2/28/2012