2024-30751. Air Plan Approval; Florida; Second Planning Period Regional Haze Plan

Table 1—Baseline, Current, and Natural Visibility Conditions in Florida's Class I Areas in Deciviews ( dv )

Class I area	Baseline clearest 20%	Baseline most impaired 20%	Current clearest 20%	Current most impaired 20%	Natural clearest 20%	Natural most impaired 20%
Chassahowitzka	15.60	24.52	12.41	17.41	6.00	9.03
Everglades	11.69	19.52	10.37	14.90	5.22	8.33
St. Marks	14.34	24.68	11.15	17.39	5.37	9.13

Table 2—Actual Progress for Visibility Conditions in Florida's Class I Areas in Deciviews ( dv )

Class I area	Current minus baseline for clearest 20%	Current minus baseline for most impaired 20%	Natural minus current for clearest 20%	Natural minus current for most impaired 20%
Chassahowitzka	−3.19	−7.11	−6.41	−8.38
Everglades	−1.32	−4.62	−5.15	−6.57
St. Marks	−3.19	−7.29	−5.78	−8.26

Additionally, figures 3-1, 3-2, and 3-3 of the 2021 Plan provide the URP figures on the 20 percent most impaired days for Chassahowitzka, Everglades, and St. Marks, respectively. The URPs were developed using EPA guidance and data collected from the IMPROVE monitoring network, which is used to measure visibility impairment caused by air pollution at the 156 Class I areas covered by the visibility program. All Florida Class I areas are projected to be below the 2028 URP values for the second planning period based on VISTAS' modeling. However, due to issues in the VISTAS model performance for Everglades, Florida relied on visibility modeling completed by EPA in 2019 for this Class I area.^[46] EPA modeling tended to have better performance for Everglades due to the use of an expanded modeling domain, updated boundary conditions (including marine offshore emissions), and a more recent base year, allowing for more accurate 2028 emissions and visibility projections. Thus, Florida is relying on EPA's regional haze modeling for Everglades visibility projections and RPG development.

3. EPA Evaluation: EPA is proposing to find that Florida's Haze Plan meets the requirements of 40 CFR 51.308(f)(1) because the State provides for its three Class I areas: baseline, current and natural visibility conditions for the 20 percent clearest days and most impaired days, progress to date for the 20 percent clearest days and most impaired days, the differences between the current visibility condition and natural visibility condition, and the URP for each Class I area in Florida. Further, FDEP provided a reasonable explanation for using EPA's modeling for 2028 for Everglades is appropriate in this instance as mentioned above.^[47]

C. LTS for Regional Haze

1. RHR Requirement: Each state having a Class I area within its borders or emissions that may affect visibility in a Class I area must develop a LTS for making reasonable progress toward the national visibility goal. See CAA 169A(b)(2)(B). As explained in the Background section of this document, reasonable progress is achieved when all states contributing to visibility impairment in a Class I area are implementing the measures determined—through application of the four statutory factors to sources of visibility impairing pollutants—to be necessary to make reasonable progress. See40 CFR 51.308(f)(2)(i). Each state's LTS must include the enforceable emission limitations, compliance schedules, and other measures that are necessary to make reasonable progress. See40 CFR 51.308(f)(2).

All new ( i.e., additional) measures that are the outcome of FFAs are necessary to make reasonable progress and must be in the LTS. If the outcome of an FFA and other measures necessary to make reasonable progress is that no new measures are reasonable for a source, that source's existing measures are necessary to make reasonable progress, unless the state can demonstrate that the source will continue to implement those measures and will not increase its emission rate. Existing measures that are necessary to make reasonable progress must also be in the LTS. In developing its LTS, a state must also consider the five additional factors in 40 CFR 51.308(f)(2)(iv). As part of its reasonable progress determinations, the state must describe the criteria used to determine which sources or group of sources were evaluated ( i.e., subjected to FFA) for the second planning period and how the four factors were taken into consideration in selecting the emission reduction measures for inclusion in the LTS. See40 CFR 51.308(f)(2)(iii).

States may rely on technical information developed by the RPOs of which they are members to select sources for FFA and to satisfy the documentation requirements under 40 CFR 51.308(f). Where an RPO has performed source selection and/or FFAs (or considered the five additional factors in 40 CFR 51.308(f)(2)(iv)) for its member states, those states may rely on the RPO's analyses for the purpose of satisfying the requirements of 40 CFR 51.308(f)(2)(i) so long as the states have a reasonable basis to do so and all state participants in the RPO process have approved the technical analyses. See40 CFR 51.308(f)(2)(iii).

States may also satisfy the requirement of 40 CFR 51.308(f)(2)(ii) to engage in interstate consultation with other states that have emissions that are reasonably anticipated to contribute to visibility impairment in a given Class I area under the auspices of intra- and inter-RPO engagement.

The consultation requirements of 40 CFR 51.308(f)(2)(ii) provide that states must consult with other states that are reasonably anticipated to contribute to visibility impairment in a Class I area to develop coordinated emission management strategies containing the emission reductions measures that are ( print page 105518) necessary to make reasonable progress. Section 51.308(f)(2)(ii)(A) and (B) require states to consider the emission reduction measures identified by other states as necessary for reasonable progress and to include agreed upon measures in their SIPs, respectively. Section 51.308(f)(2)(ii)(C) speaks to what happens if states cannot agree on what measures are necessary to make reasonable progress.

The documentation requirement of 40 CFR 51.308(f)(2)(iii) provides that states may meet their obligations to document the technical bases on which they are relying to determine the emission reductions measures that are necessary to make reasonable progress through an RPO, as long as the process has been “approved by all State participants.” Section 51.308(f)(2)(iii) also requires that the emissions information considered to determine the measures that are necessary to make reasonable progress include information on emissions for the most recent year for which the state has submitted triennial emissions data to EPA (or a more recent year), with a 12-month exemption period for newly submitted data.

2. State Assessment: To develop Florida's LTS, FDEP set criteria to identify sources to evaluate for potential controls outlined in section II.B, selected sources based on those criteria, considered the four CAA factors for the selected sources (or demonstrated the sources have existing effective controls as explained in IV.C.2.b. below), provided emissions limits and supporting conditions for incorporation into the SIP, and evaluated the five additional factors at 40 CFR 51.308(f)(2)(iv).

a. Source Selection Criteria: With respect to 40 CFR 51.308(f)(2)(i), Florida, through VISTAS, used a two-step source selection process: (1) Area of Influence (AoI) analysis,^[48] and (2) PSAT ^[49] modeling for sources exceeding an AoI threshold. Florida considered the four factors (or demonstrated the sources have existing effective controls as explained in IV.C.2.b. below) for sources that exceeded both the AoI and PSAT thresholds. Both sulfates and nitrates were considered in the source selection process. To identify sources having the most impact on visibility at Class I areas for PSAT modeling, Florida used an AoI threshold of greater than or equal to five percent for sulfate and nitrate combined area for all sources within and outside of the State. Sources selected at the AoI screening step for PSAT modeling are listed in table 7-11 of the 2021 Plan. Of these 18 sources, 17 sources located within Florida exceeded the AoI threshold for any Class I area in the State: Cemex Miami Cement Plant, Duke Crystal River Power Plant (Duke-Crystal River), FPL Turkey Point, Georgia-Pacific—Foley Cellulose Perry Mill (Foley), Gulf Clean Energy Center—Crist Generating Plant, Homestead City Utilities, Jacksonville Electric Authority—Northside Generating Station (JEA Northside), Mosaic Fertilizer, LLC—New Wales (Mosaic-New Wales), Mosaic Fertilizer, LLC—Riverview (Mosaic-Riverview), Mosaic Fertilizer, LLC—Bartow (Mosaic-Bartow), Nutrien White Springs Agricultural Chemicals, Inc. (Nutrien), Rayonier Performance Fibers LLC, Tallahassee City Purdom Generating Station, Tampa Electric Company—Big Bend Power Station (TECO-Big Bend), Titan-Pennsuco, WestRock Fernandina Beach Paper Mill (WestRock-Fernandina), and WestRock Panama City Paper Mill (WestRock-Panama City).

Florida, in coordination with the other VISTAS states, selected sources for further evaluation using a PSAT threshold of greater than or equal to one percent visibility impact for sulfate or nitrate. Sources both within and outside of Florida that were identified for an emissions control analysis are listed in tables 7-25 and 7-26 of the 2021 Plan, and Mosaic Fertilizer, LLC-South Pierce (Mosaic-South Pierce) is identified in section 7.6.4.1 of the 2024 Supplement. Twelve sources were selected by FDEP for an emissions control analysis. In addition, FDEP identified two additional sources in Georgia and Kentucky that were requested by FDEP for further analysis as part of the interstate consultation process. The 12 sources in Florida are: Duke-Crystal River, Foley, JEA Northside, Lakeland CD McIntosh Jr. Power Plant (CD McIntosh),^[50] Mosaic-Bartow, Mosaic-New Wales, Mosaic-South Pierce, Nutrien, Seminole Electric Cooperative Incorporated (Seminole), TECO-Big Bend, WestRock-Fernandina, and WestRock-Panama City.^[51] Because no sources exceeded the State's PSAT threshold for nitrates and because ammonium sulfate continues to be the dominant visibility impairing pollutant at Class I areas potentially impacted by Florida sources (as discussed in the following paragraphs), FDEP focused solely on evaluating potential SO₂ controls to address regional haze in potentially affected Class I areas. FDEP allowed the selected facilities to either demonstrate that units emitting greater than five tons per year (tpy) of SO₂ were already effectively controlled or complete an FFA for this pollutant.

FDEP determined that during the 2014 to 2018 timeframe, Florida's Class I areas were impacted most heavily by sulfate. See figures 2-9 through 2-11 of the 2021 Plan. In Florida's AoI analysis, Florida used extinction-weighted residence time plots to allow for a separate analysis of sulfates and nitrates. Figures 7-42, 7-43, and 7-44 of the 2021 Plan contain the sulfate extinction weighted residence time for Chassahowitzka, St. Marks, and Everglades, respectively, for the 20 percent most impaired days from 2011 to 2016. Figures 7-45, 7-46, and 7-47 contain the nitrate extinction weighted residence time for Chassahowitzka, St. Marks, and Everglades, respectively, for the 20 percent most impaired days from 2011 to 2016. The sulfate extinction weighted residence times are significantly higher (approximately ten times higher) than the nitrate extinction weighted residence times on the 20 percent most impaired days during this time period, demonstrating the importance of focusing on SO₂ emission reductions. ( print page 105519)

The Haze Plan shows the VISTAS modeled projections demonstrating that ammonium sulfate is expected to remain the dominant visibility impairing pollutant through 2028, by a factor of four or greater over ammonium nitrate at Class I areas in Florida.^[52] In section 7.4 of the 2021 Plan, FDEP explains the VISTAS analyses relied upon to support the State's focus on SO₂ control evaluations. Section 10.4.1 provides the State's responses to FLM comments on the exclusion of NOx control evaluations from the FFAs.^[53]

Additionally, in section 2.6 of the 2021 Plan, FDEP reviewed visibility monitoring data for the period 2014-2018 for Chassahowitzka, Everglades, and St. Marks. Figures 2-9 through 2-11 show the reconstructed light extinction for the 20 percent most impaired days at each Florida Class I areas, respectively. The data indicates that sulfates are the primary visibility impacting species in Florida's Class I areas during the 2014-2018 timeframe.

Furthermore, figures 7-22 (Chassahowitzka), 7-23 (St. Marks), and 7-24 (Everglades) in the 2021 Plan show that the majority of 2028 predicted nitrate light extinction on the 20 percent most impaired days at Florida's Class I areas is not caused by NO_X emissions from electric generating unit (EGU) and non-EGU point sources.^[54] At Chassahowitzka, St. Marks, and the Everglades, projected total sulfate extinction is greater than 10 Mm⁻¹ and projected total nitrate extinction is less than five Mm⁻¹.

Section I.A of the TSD to this proposed rulemaking provides a summary of the State's source selection criteria, including the technical rationale for the State's focus on SO₂ controls for the second planning period and the outcomes of the State's source selection process.

b. Consideration of the Four CAA Factors:

As discussed in section IV.C.2.b.ii ( Existing, Effective Control Demonstrations ) below, eight of the 12 selected facilities in Florida demonstrated that some or all of the selected units are effectively controlled for SO_2. FDEP stated that there is a low likelihood that cost-effective technological advancements exist that could provide further reasonable emission reductions for these sources. For the remaining selected sources, FDEP fully considered the four CAA factors as discussed in section IV.C.2.b.i below.^[55]

i. FFAs: Florida considered each of the four CAA factors for Foley, JEA Northside (Unit 3),^[56] and WestRock-Fernandina and described how the four factors were taken into consideration in selecting the measures for inclusion in the State's LTS. Florida is proposing selected permit conditions summarized below for incorporation into the SIP as measures necessary for reasonable progress for the second planning period. See section I.B of the TSD to this proposed rulemaking for additional details.

(a) Foley: Foley is a softwood Kraft Process Pulp Mill that manufactured bleached market pulps and dissolving cellulose pulps. FDEP requested that the facility complete an FFA for five units expected to emit more than five tpy of SO₂ in 2028. FDEP evaluated emissions reductions measures for SO₂ for the No. 1 Power Boiler; No. 1 Bark Boiler; and Nos. 2, 3, and 4 Recovery Furnaces.^[57 58]

No. 1 Power Boiler: The No. 1 Power Boiler serves as the secondary control device for low volume, high concentration (LVHC) non-condensable gas (NCG) and fires natural gas, No. 6 fuel oil, tall oil, and on-specification used oil. When NCGs are routed to the No. 1 Power Boiler, a pre-scrubber is used to assist with reduction of total reduced sulfur (TRS) which in turn limits SO₂ production. The Mill identified a wet scrubber and a dry sorbent injection (DSI) system as available and feasible controls for this unit. The cost evaluation for the wet scrubber resulted in an estimated cost effectiveness of $13,547/ton to reduce actual SO₂ emissions by approximately 80 tpy. FDEP determined that installation of a wet scrubber on No. 1 Power Boiler is not cost effective. As for the DSI system, the cost evaluation resulted in an estimated cost-effectiveness value of $21,727/ton to reduce actual SO₂ emissions by approximately 73 tpy, which FDEP considered not cost effective. FDEP, however, determined that existing low-sulfur fuel restrictions on this unit were necessary for reasonable progress as follows: fire only natural gas except during specified times when natural gas is unavailable or there is a physical problem at the mill that prevents the firing of natural gas, in which case the unit may fire liquid fuels; tall oil is prohibited; No. 6 fuel oil purchases must meet a sulfur content limit of no more than 1.02 percent; and the unit is only permitted to burn LVHC NCG when the No. 1 Bark Boiler is unavailable or when necessary for compliance with 40 CFR part 63, subpart S, such as for monitoring for detectable leaks for the closed vent system. Florida has identified permit conditions for these restrictions for incorporation into the SIP.

Regarding the other CAA factors, there is no time necessary to comply with the low-sulfur fuel option, and the use of low sulfur fuel did not result in non-air environmental impacts. For the wet scrubber and DSI options, FDEP states that it may take up to four years to secure funding, make the required technical changes, and perform testing and monitoring to ensure proper system operation for the installation of wet scrubbers and DSI systems. Energy and non-air environmental impacts include additional electrical costs associated with DSI and scrubber operation, and additional fresh water and wastewater disposal use for the wet scrubber. Additionally, the No. 1 Power Boiler is assumed to have 30 years or more of remaining useful life, and an interest rate of 3.25 was used when considering the annualized costs of controls.

No. 1 Bark Boiler: The No. 1 Bark Boiler serves as the primary control device for LVHC NCGs and provides the Mill with 200,000 pounds per hour (lbs/hr) (24-hour block average basis) of steam. The No. 1 Bark Boiler fires natural gas, No. 6 fuel oil, tall oil, and on-specification used oil and is equipped with a cyclone collector and ( print page 105520) a wet venturi scrubber. Currently, permit conditions for No. 1 Bark Boiler require the wet venturi scrubber to meet pH and flow rate restrictions only when the TRS pre-scrubber is not operational. For the FFA, FDEP evaluated one control option which consists of running the existing wet venturi scrubber whenever NCGs or oil are combusted in the No. 1 Bark Boiler, maintaining a minimum pH of 8 (three-hour block average), and flow rate of 1,000 gallons per minute (gpm) (three-hour block average), rather than only when the TRS pre-scrubber is unavailable. The increase in the operation of the wet scrubber requires an increase in the amount of time caustic is added to the wet scrubber which requires the addition of an antiscalant to minimize fouling and scaling due to caustic buildup in the boiler. FDEP evaluated these operational changes as technically feasible, and the cost evaluation resulted in an estimated annualized cost effectiveness of $2,627/ton to remove approximately 96 tpy of SO₂ emissions. FDEP determined this control to be cost effective. Implementing the increased operation of the wet scrubber requires adding additional caustic and scalant to the scrubber control system, which could be done with within 12 months with no negative non-air environmental impacts. The No. 1 Bark Boiler is assumed to have 30 years or more of remaining useful life, and an interest rate of 3.25 percent was used when considering the annualized costs of controls. Florida has identified permit conditions for these requirements for incorporation into the SIP.

FDEP also determined that certain existing measures are necessary for reasonable progress and proposed for incorporation into the SIP low sulfur fuel restrictions that are similar to the restrictions proposed for No. 1 Power, except the No. 1 Bark Boiler is permitted to burn wood in addition to natural gas as the primary fuel type. FDEP is proposing permit conditions reflecting these requirements for incorporation into the SIP.

Nos 2, 3, and 4 Recovery Furnaces: The three recovery furnaces are low-odor, non-direct contact evaporator units that burn the organic material present in black liquor (a byproduct in the Kraft Mill process). The furnaces fire natural gas, No. 6 fuel oil, No. 2 fuel oil, tall oil, ultra-low sulfur diesel, on-specification used oil, and methanol (methanol is only fired in select furnaces). Foley considered adding several common flue gas desulfurization (FGD) systems to the recovery furnaces, including spray dryer absorbers (SDA), DSI, and conventional wet scrubbers. Considering the antiquated design of the furnaces, FDEP found the addition of a wet scrubber to be the only feasible control technology.

FDEP identified a wet scrubber as a potential control option for the recovery furnaces, but noted that it is not aware of the installation of a wet scrubber on any recovery furnaces across the country. The cost effectiveness to add a wet scrubber was estimated at values of: $7,779/ton to reduce SO₂ by approximately 592 tons annually for Recovery Furnace No. 2; $5,197/ton to reduce SO₂ by approximately 1,050 tons annually for Recovery Furnace No. 3; and $6,587/ton to reduce SO₂ by approximately 831 tons annually for Recovery Furnace No. 4. FDEP determined that adding a wet scrubber was not cost effective. FDEP estimated that it would take up to four years to install new controls at the recovery furnaces. Typical energy and non-air quality impacts of compliance include caustic and sulfuric acid costs, additional electrical costs associated with scrubber operation, additional fresh water for scrubber needs and wastewater disposal. It is assumed that the recovery furnaces have at least 30 years of remaining useful life, and an interest rate of 3.5 percent was used when considering the annualized costs of controls.

FDEP determined that the following existing measures at the recovery furnaces are necessary for reasonable progress: burn black liquor as the primary fuel; natural gas and liquid fuels may supplement recovery operations; a maximum sulfur content of 1.02 percent for purchased No. 6 fuel oil; and a SO₂ emissions cap of 3,200 tons per consecutive 12 operating months as measured by a continuous emissions monitoring system (CEMS).

State Conclusions: Regarding the No. 1 Power Boiler, FDEP determined that there were no cost-effective emission reductions for the No. 1 Power Boiler and determined that the existing measures at the No. 1 Power Boiler are necessary for reasonable progress. Thus, FDEP proposed low-sulfur fuel restrictions for incorporation into the SIP for the No. 1 Power Boiler as described above.

Regarding the No. 1 Bark Boiler, FDEP determined that continuously running the wet venturi scrubber with added caustic and scalant to maintain a minimum pH of 8 is cost-effective and, therefore, the State has determined that these controls are necessary for reasonable progress. FDEP also determined that certain existing low sulfur fuel restrictions are necessary for reasonable progress and proposed low sulfur fuel restrictions that are similar to the restrictions proposed for the No. 1 Power Boiler.

Regarding the Nos. 2, 3, and 4 Recovery Furnaces, after conducting a site visit at Foley and discussing the physical constraints and reviewing the costs, FDEP determined that installation of a wet scrubber located after the electro-static precipitator (ESP) is not cost-effective and, therefore, the existing measures described above for the Nos. 2, 3 and 4 Recovery Furnaces are necessary for reasonable progress.

FDEP identified permit conditions reflecting these new and existing SO₂ measures in the “Materials to be Incorporated into the SIP” section of the Second 2024 Supplement for incorporation into the regulatory portion of the Florida SIP.

(b) JEA Northside (Unit 3): JEA Northside is a power plant located in north Jacksonville. The main sources of SO₂ emissions at JEA Northside are Nos. 1 and 2 (EU 026 and EU 027) circulating fluidized-bed (CFB) Boilers and the No. 3 (EU 003) Boiler. FDEP conducted an FFA for JEA Northside's No. 3 Boiler. For the Nos. 1 and 2 CFB Boilers, Florida relied on an existing effective controls demonstration, as discussed below in section IV.C.2.b.ii.

The No. 3 Boiler is a natural gas-fired electric utility steam generating unit as defined in 40 CFR 63.10042 that fires natural gas and limited amounts of No. 6 fuel oil. The FFA for the No. 3 Boiler identified the following available controls: using lower sulfur No. 6 fuel oil (from 1.8 percent to 1.0 percent), using ultra-low sulfur No. 2 fuel oil, or installing a wet FGD system. The cost effectiveness values for each control option are as follows: switching to a lower sulfur No. 6 fuel oil is $3,053/ton of SO₂ removed, reducing emissions by 49.9 tpy; switching to No. 2 fuel oil is $7,334/ton of SO₂ removed, reducing emissions by 122.81 tpy; and installing a wet FGD system is $177,856/ton of SO₂ removed.^[59]

Regarding the other CAA factors, FDEP estimated that it would take nine months to one year to complete a switch to No. 2 or No. 6 fuel oil because a boiler outage of approximately two to ( print page 105521) three months would be necessary to perform the new burner installation, and the State found no non-air environmental impacts from a switch. FDEP estimates installing a wet FGD system would take 36 months based on EPA's Integrated Planning Model (IPM) estimates and the need for engineering design, equipment procurement, and installation, and testing. Regarding energy and non-air environmental impacts of the wet FGD, FDEP states that there are energy penalties due to the pressure drop through the absorbers and the energy usage by auxiliary systems and estimates that the total energy impacts would be about 30,000 megawatt-hours for the maximum possible operation of Unit 3 currently authorized. Operation of wet FGD will also require the delivery, handling, and storage of limestone; the handling and disposal of FGD by-product ( i.e., gypsum); and the use of process water. FDEP determined the remaining useful life factor for each control option to be 30 years and used a 3.25 percent interest rate when considering the annualized costs of controls.

State Conclusions: Regarding JEA Northside Unit 3, FDEP determined that switching to No. 2 fuel oil and installing a wet FGD system are not cost effective, and therefore, are not necessary for reasonable progress. FDEP determined that switching to a lower sulfur No. 6 fuel oil is cost effective, and selected it as a measure necessary for reasonable progress for JEA Northside Unit 3.

FDEP identified permit conditions reflecting this new SO₂ measure in the “Materials to be Incorporated into the SIP” section of the 2021 Plan for incorporation into the regulatory portion of the Florida SIP.^[60]

(c) WestRock-Fernandina: WestRock-Fernandina is a fully integrated Kraft linerboard mill that produces linerboard from wood pulp and pulp derived from recycled corrugated containers. The Mill conducted projects totaling $15.9 million in capital costs in 2016 and 2017 to reduce both actual and allowable SO₂ emissions so that modeled allowable emissions would demonstrate compliance with the 2010 SO₂ NAAQS. Table 7-31 in the 2021 Plan shows the decrease in emissions levels that have occurred since the 2016-2017 timeframe. The last line in table 7-31 contains the updated, projected emissions from this facility. The largest SO₂ sources at the Mill are the No. 5 and No. 7 Power Boilers and the No. 4 and No. 5 Recovery Boilers.

The No. 5 Power Boiler burns carbonaceous fuel such as biomass, natural gas, ultra-low sulfur diesel (ULSD), or No. 2 fuel oil. Currently, this unit is prohibited from using No. 6 fuel oil or being used as a backup NCG control device unless otherwise approved by FDEP's Division of Air Resource Management. Additionally, an engineering analysis must be submitted providing reasonable assurance that the boiler can comply with SO₂ emissions standards of 15.0 lb/hour based on a 3-hour block average, as determined by data collected from a CEMS, during all periods of operation except when operating as a backup control device firing NCGs. The FFA for the No. 5 Power Boiler identified installation of a wet scrubber, installation of a wet scrubber with a stack liner, or installation of a DSI system as potential additional controls. The cost effectiveness values of these additional controls are as follows: installing a wet scrubber is $285,615/ton of SO₂ removed; installing a wet scrubber with stack liner is $298,499/ton of SO₂ removed; and installing DSI is $277,093/ton of SO₂ removed. According to the FFA, it would take at least four years to install a wet scrubber or DSI system, and there are energy and non-air environmental impacts that would result from installing these controls, such as an increase in water and electricity usage and wastewater generation. The No. 5 Power Boiler is assumed to have a remaining useful life of 20 years or more; however, FDEP conservatively used a lifetime of 30 years to annualize costs and used a 3.25 percent interest rate when considering the annualized costs of controls. FDEP determined that these controls are not cost effective.

The No. 7 Power Boiler serves as a backup NCG control device and fires coal, oil, or natural gas. The FFA for the No. 7 Power Boiler identified reducing coal usage to 125 tons per day (tpd), installing a wet scrubber after the existing ESP, installing a DSI with an existing ESP, installing SDA with new fabric filter, or removing all coal firing as potentially available controls. The cost effectiveness values of these controls are as follows: reducing coal usage is a cost savings of $1,868/ton of SO₂ removed; installing a wet scrubber is $5,641/ton of SO₂ removed, reducing emissions by 1,222 tpy; installing a wet scrubber with stack liner is $6,028/ton of SO₂ removed, reducing emissions by 1,222 tpy; installing DSI is $8,776/ton of SO₂ removed, reducing emissions by 748 tpy; installing an SDA is $16,398/ton of SO₂ removed, reducing emissions by 1,184 tpy; and removing all coal firing is $7,374/ton of SO₂ removed, reducing emissions by 1,171 tpy. WestRock-Fernandina indicated they would need until 2024 to fully implement the coal reduction option but could begin limiting coal usage as early as 2022, because the Mill is contractually obligated to purchase a set amount of coal through 2021. There were no energy or non-air quality environmental impacts associated with the reduction of coal usage. The installation of a wet scrubber would increase water and electricity usage and wastewater generation. The installation of a DSI system or an SDA system would increase solid waste and electricity usage. The No. 7 Power Boiler fly ash is currently used in cement manufacturing but would have to be landfilled if contaminated with sorbent. The No. 7 Power Boiler has approximately 20 years or more of useful life remaining; however, FDEP conservatively used a useful life of 30 years to annualize the costs. FDEP used a 3.25 percent interest rate, a 98 percent control efficiency for FGD, a 60 percent control efficiency for DSI, a 95 percent control efficiency for SDA, and a 97 percent control efficiency for removing all coal in the calculations for No. 7 Power Boiler.

The No. 4 Recovery Boiler fires black liquor solids or No. 2 fuel oil and uses natural gas or No. 2 fuel oil for startup. No. 5 Recovery Boiler fires black liquor solids or No. 6 fuel oil and burns natural gas or No. 2 fuel oil for startup only. Currently, the SO₂ emissions from Nos. 4 and 5 Recovery Boilers recovery boilers shall not exceed 150.0 lb/hour based on a 3-hour block average as determined by data collected from a certified CEMS or other methods approved by the Division of Air Resource Management. Alternatively, Nos. 4 and 5 Recovery Boilers may comply with the combined SO₂ emissions cap which shall not exceed 300.0 lb/hour based on a 3-hour block average as determined by data collected from a certified CEMS. The FFA for the Nos. 4 and 5 Recovery Boilers identified the installation of wet scrubber as a potential additional control for each recovery boiler. FDEP determined that the cost effectiveness for the wet scrubber is $282,375/ton of SO₂ removed for the No. 4 Recovery Boiler and $169,425/ton of SO₂ removed for the No. 5 Recovery Boiler.^[61] FDEP ( print page 105522) determined that WestRock-Fernandina would need a minimum of four years to install a wet scrubber and concluded that there are energy and non-air environmental impacts associated with the installation of a wet scrubber, including increased water and electricity usage and wastewater generation. The Nos. 4 and 5 Recovery Boilers are assumed to have 20 years of remaining useful life.

State Conclusions: For WestRock-Fernandina's No. 7 Power Boiler, FDEP determined that removing all coal-firing or installing a wet scrubber, DSI, or SDA are not cost effective, and are therefore not necessary for reasonable progress. For the No. 7 Power Boiler, FDEP determined that reducing coal usage to 125 tpd is cost effective and is a measure that is necessary for reasonable progress.^[62] Thus, FDEP identified the permit conditions reflecting this new SO₂ measure for WestRock-Fernandina's No. 7 Power Boiler in the “Materials to be Incorporated into the SIP” sections ^[63] of the 2021 Plan and appendix A-1 of the 2024 Supplement for incorporation into the regulatory portion of the Florida SIP. These conditions may be found in permit number 0890003-072-AC of the 2021 Plan and 0890003-074-AC and of the 2024 Supplement.

For WestRock-Fernandina's No. 5 Power Boiler, FDEP determined that neither the installation of a wet scrubber—with or without the stack liner—nor the installation of a DSI system were cost effective. Likewise, FDEP determined that installation of wet scrubber for Nos. 4 and 5 Recovery Boilers was not cost effective. Therefore, FDEP determined that existing measures at the No. 5 Power Boiler and the Nos. 4 and 5 Recovery Boilers are necessary for reasonable progress. These existing measures, contained in permit number 0890003-046-AC, were already incorporated into the SIP through the Nassau County Florida SO₂ Attainment Plan SIP revision approved by EPA on July 3, 2017 (82 FR 30749).^[64] A list of the specific conditions included for regional haze informational purposes may be found in the “Materials Submitted for Informational Purposes Only” section, in appendix A-6 of the 2024 Supplement.

ii. Existing, Effective Control Demonstrations: As described in section 7.6.4.1 of the 2021 Plan, FDEP proposed existing SO₂ measures as necessary for reasonable progress for incorporation into the Florida SIP for the affected units at the following eight facilities: Duke-Crystal River, JEA Northside, Mosaic-Bartow, Mosaic-New Wales, Mosaic-South Pierce, Nutrien, Seminole, and TECO-Big Bend. FDEP contends that these sources are effectively controlled and are unlikely to have additional controls available for reasonable progress.

Regarding Duke-Crystal River, Florida is proposing for adoption into the SIP permit conditions that require compliance with a limit of 0.20 pound per million British thermal units (lb/MMBtu) of SO₂ for the fossil fuel steam generating Unit 4 and Unit 5 in lieu of performing a detailed FFA for these units. This emission limit is the alternative emission limit currently applicable to Duke-Crystal River under the Mercury and Air Toxics Standards (MATS) rule.^[65] Including this emission limit in the SIP would also have the effect of removing the hydrogen chloride MATS compliance option for Duke-Crystal River. Florida concluded that these units are effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. Therefore, Florida is proposing for adoption into the SIP permit conditions for the 0.20 lb/MMBtu SO₂ emission limitation and additional permit conditions that allow the citrus combined cycle station Units 1A, 1B, 2A, and 2B to combust only pipeline natural gas.^[66]

Regarding JEA Northside, Florida proposed for adoption into the SIP permit conditions for Units 1 and 2 that include an SO₂ limit of 0.15 lb/MMBtu, and the MATS-based SO₂ emission limit of 0.20 lb/MMBtu.^[67] Florida is proposing both the SO₂ limit of 0.15 lb/MMBtu and the SO₂ emission limit of 0.20 lb/MMBtu as reflecting effective controls for JEA Northside Units 1 and 2 because the SO₂ emission limit of 0.15 lb/MMBtu had exemptions during period of startup, shutdown, and malfunction. The MATS limit applies continuously and has work practice standards which apply during startup and shutdown. Florida concluded that this unit is effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. Therefore, Florida is proposing for incorporation into the SIP permit conditions for the 0.20 lb/MMBtu emission limitation.

Regarding Mosaic-Bartow, Florida reviewed existing SO₂ measures at three sulfuric acid plants (SAPs) at the facility, Nos. 4 through 6. This facility reduced SO₂ emissions to bring the Hillsborough-Polk nonattainment area into attainment for the 2010 SO₂ NAAQS, including upgrades to the catalyst beds. The SO₂ generated in these systems is catalytically oxidized to sulfur trioxide (SO₃) over the catalyst beds at a rate of 99.7 percent or higher. The facility is required to comply with a three-unit cap of 1,100 pounds/hour on a 24-hour block average as determined by continuous emission monitoring system (CEMS). Each SAP at the facility is required to meet a limit of four pounds (lbs) SO₂ per ton of 100 percent sulfuric acid produced. Florida states that this limit is consistent with the SO₂ best available control technology (BACT) determinations for sulfur burning, double-absorption sulfuric acid plants with cesium-promoted catalysts at a range of 3.0 to 4.0 lbs per ton in EPA's RACT/BACT/LAER Clearinghouse (RBLC) database.^[68] Florida concluded that these units are effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. These SO₂ limits are already incorporated into Florida's SIP.^[69]

Regarding Mosaic-New Wales, Florida reviewed existing SO₂ measures at five SAPs at the facility, Nos. 1 through 5. This facility also reduced SO₂ emissions to bring the Hillsborough-Polk nonattainment area into attainment for the 2010 SO₂ NAAQS. The facility was required to comply with a five-unit SO₂ ( print page 105523) emissions cap of 1,090 lbs per hour on a 24-hour block average as determined by CEMS. SAP Nos. 1-3 are each required to meet an SO₂ limit of 3.5 lbs per ton of 100 percent sulfuric acid produced on a 24-hr rolling average and four lbs per ton on a three-hour rolling average. SAPs 4 and 5 are each required to meet a limit of four lbs per ton of sulfuric acid produced. Florida affirms that this limit is consistent with the SO₂ BACT determinations for sulfur burning, double-absorption sulfuric acid plants with cesium-promoted catalysts which appear in a range of 3.0 to 4.0 lbs per ton of sulfuric acid produced in EPA's RBLC database. Florida concluded that these units are effectively controlled for SO_2, and additional reasonable controls are unlikely to be found. These SO₂ limits are already incorporated into Florida's SIP.^[70]

Regarding Mosaic-South Pierce, FDEP requested that the facility evaluate whether any additional measures were available to reduce SO₂ .^[71] Specifically, FDEP requested that Mosaic-South Pierce complete an FFA for SAPs Nos. 10 and 11 or demonstrate that those units were already effectively controlled for SO₂ . Sulfuric Acid Plants Nos. 10 and 11 are double absorption sulfuric acid systems equipped with two absorption towers in series to react SO₃ with water to produce sulfuric acid. The SO₂ generated in a double absorption system's sulfur furnace is catalytically oxidized to SO₃ over catalyst beds at a very high rate (99.7 percent or greater), which results in relatively low SO₂ emissions as compared to a single absorption system. The second bed uses a cesium-promoted catalyst, which increases the overall SO₂ -to-SO₃ conversion rate. FDEP determined that the SAPs Nos. 10 and 11 at Mosaic-South Pierce are effectively controlled for SO₂ based on a review of EPA's RBLC database which identified the combination of dual absorption design and cesium-promoted catalysts as BACT for sulfur-burning, non-single absorption column sulfuric acid plants and are therefore unlikely to have additional SO₂ controls identified as part of an FFA. Florida has identified permit conditions for incorporation into the SIP that prohibit combined SO₂ emissions from SAPs 10 and 11 from exceeding 750 lbs SO₂ per hour on a 24-hour block average as determined by CEMS.^[72]

Regarding Nutrien, this facility has recently completed significant work to reduce SO₂ emissions to achieve SO₂ limits imposed by a consent decree entered on February 26, 2015.^[73] As part of the consent decree, Nutrien was required to reduce SO₂ emissions and meet more stringent SO₂ emission limits at SAPs C, D, E, and F. Nutrien elected to permanently shut down SAPs C and D in 2014, reducing SO₂ emissions from these SAPs to zero. On March 31, 2017, FDEP issued permit No. 0470002-107-AC to Nutrien to complete upgrades on SAP E and SAP F, which included changing out and augmenting the converter catalyst in the SAPs, allowing them to meet new SO₂ emission limits of 2.6 lbs per ton on a three-hour rolling average (excluding startups and shutdowns) and 2.3 lbs per ton limit on a 365-day rolling average (including startups and shutdowns), as required by the consent decree. Nutrien was required to comply with these limits on January 1, 2018, for SAP F and January 1, 2020, for SAP E. Additionally, on January 1, 2023, an 840 lbs/hour SO₂ limit on a 24-hour block averaging period was applied to the combined emissions from SAP E and F.^[74] Florida states that these limits are consistent with recent BACT determinations made for similar double-absorption, sulfur-burning SAPs. Florida concluded that this unit is effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. Florida did not identify the permit conditions from Permit No. 0470002-132-AC, issued on September 22, 2022, for incorporation into the SIP because they have already been incorporated through Florida's Supplemental SSM SIP as approved by EPA on August 4, 2023 (88 FR 51702).^[75]

Regarding TECO-Big Bend, this facility has accepted the MATS SO₂ limit of 0.20 lb/MMBtu for fossil fuel steam generators No. 3 (EU003) ^[76] and No. 4 (EU004). This emission limit is the alternative emission limit currently applicable to TECO-Big Bend under the MATS rule. Including this emission limit in the SIP would also have the effect of removing the hydrogen chloride MATS compliance option for TECO-Big Bend. Florida concluded that this unit is effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. Therefore, Florida identified permit conditions with these SO₂ limits for Unit 4 at TECO-Big Bend for incorporation into the Florida SIP.^[77]

Regarding Seminole, this facility accepted the MATS SO₂ limit of 0.20 lb/MMBtu for the steam electric generator No. 1 (EU001) and No. 2 (EU002) in the same manner as discussed with TECO-Big Bend in the preceding paragraph. Florida concluded that this unit is effectively controlled for SO₂ emissions and that additional reasonable controls are unlikely to be found. Therefore, Florida identified permit conditions with these SO₂ limits for incorporation into the Florida SIP.^[78]

Section I.B of the TSD to this proposed rulemaking provides a more detailed summary of the State's assessment of Florida's FFAs and existing effective controls, and the associated emissions control measures proposed for incorporation into the Florida SIP.

c. Documentation of Technical Basis: With respect to emissions information documentation pursuant to 40 CFR 51.308(f)(2)(iii), section 4 of the 2021 Plan explains the State's use of emissions inventories to develop the plan with additional documentation provided in appendix B. Florida, through VISTAS, developed a 2011 statewide base year emissions inventory which was used to project emissions out to 2028, the end of the second planning period.^[79] FDEP also evaluated emissions data from 2017, the year of the most recent triennial emissions data available ( print page 105524) at the time of the development of the 2021 Plan. Statewide emissions from the 2014 and 2017 National Emissions Inventories (NEIs) are provided in tables 13-11, 13-12, and 13-13 of the 2021 Plan for PM_2.5, NO_X, and SO₂, respectively.

With respect to cost and engineering information documentation pursuant to 40 CFR 51.308(f)(2)(iii), section 7.8 of the Haze Plan details the State's analysis of the FFAs for Foley, JEA Northside, and WestRock-Fernandina located in appendix G which evaluated the four factors, including the cost of compliance factor, and provided detailed cost calculations for potential new control measures assessed as part of the engineering analyses. In addition, section 7.6.4.1 of the 2021 Plan describes the State's analysis of seven sources with existing, effective SO₂ measures: Duke-Crystal River, JEA Northside (Units 1 and 2), Mosaic-Bartow, Mosaic-New Wales, Nutrien, Seminole, and TECO-Big Bend ^[80] and the 2024 Supplement summarizes existing, effective SO₂ measures at Mosaic-South Pierce in section 7.6.4.1 on pages 5-6 of the narrative and in appendix B-2 of the 2024 Supplement.

With respect to monitoring information documentation pursuant to 40 CFR 51.308(f)(2)(iii), the State assessed baseline (2000-2004), current (2014-2018), and natural visibility conditions for Florida's Class I areas in section 2 of the 2021 Plan with supporting information located in appendix C.

With respect to modeling information documentation pursuant to 40 CFR 51.308(f)(2)(iii), sections 5 and 6 of the 2021 Plan describe the modeling methods used to develop the plan with additional documentation provided in appendix E and results of the RPG modeling in section 8 of the plan. Appendix D contains AoI analyses documentation. Section I.E of the TSD to this proposed rulemaking provides a more detailed summary of the State's assessment of documentation of the technical basis for the 2021 Plan under 40 CFR 51.308(f)(2)(iii).

d. Assessment of the Five Additional Factors in 40 CFR 51.308(f)(2)(iv):

With respect to 40 CFR 51.308(f)(2)(iv), Florida considered each of the five additional factors in developing the State's LTS and evaluated their relevancy for the second period. With respect to 40 CFR 51.308(f)(2)(iv)(A), FDEP assessed emission reductions due to ongoing air pollution control programs, including measures to address RAVI, in the development of the State's 2011 baseline and 2028 projected emission inventories. The impact of these existing and on the way air pollution control programs are reflected in the 2028 RPGs for the Florida Class I areas, except for the measures listed in section 8.2 of the 2021 Plan.

With respect to 40 CFR 51.308(f)(2)(iv)(B), FDEP evaluated measures in the State designed to mitigate the impacts of construction activities in section 7.9.2 of the 2021 Plan. Florida's rules for air quality control include requirements to prevent fugitive dust from becoming airborne and also limit the opacity of fugitive emissions to equal to or less than 20 percent. The requirements of Florida rule 62-296.320, F.A.C., General Pollutant Emission Limiting Standards, include preventive measures for construction activities to prevent fugitive dust from becoming airborne.^[81] FDEP also noted that fine soils were a relatively minor contributor to visibility impairment at the Class I areas in Florida from the baseline period of 2000-2004 through to the recent period of 2014-2018, as discussed in section 2.4.2 and shown in figures 2-1 through 2-5 (2000-2004 period); figures 2-6 through 2-8 (2009-2013 period); and figures 2-9 through 2-13 (2014-2018 period) of the 2021 Plan. Thus, any fine soil contributions to regional haze from Florida construction activities are relatively minor.

With respect to 40 CFR 51.308(f)(2)(iv)(C), FDEP discussed source retirement and replacement schedules in section 8.2.2 of the 2021 Plan, which describes existing and planned source retirements by 2028.

With respect to 40 CFR 51.308(f)(2)(iv)(D), FDEP explained that particulate organic matter (POM) is the second most important contributor to fine particle mass and light extinction on the 20 percent most impaired and 20 percent clearest days in Florida Class I areas during the baseline period. POM and elemental carbon (a component of PM_2.5) are associated with wildfires, prescribed wildland fires, agricultural burning, and biogenic emissions from vegetation. Elemental carbon is a relatively minor contributor to visibility impairment at the Class I areas in Florida as discussed in section 2.4.2 and demonstrated in figures 2-1 through 2-5. Florida has a certified Smoke Management Plan (SMP) which was most recently updated in 2013. The Florida Forest Service operates a burn authorization program that considers the potential for smoke from the burn impacting smoke sensitive receptors ( e.g., airports, roads, hospitals, and urban areas). The SMP contains provisions to help minimize air pollutant and regional haze impacts. Florida's SMP may be found in appendix G-4 of the 2021 Plan for reference only.

With respect to 40 CFR 51.308(f)(2)(iv)(E), in section 7 of the 2021 Plan, FDEP evaluates the anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the period addressed by the LTS in development of the 2028 RPGs for the Florida Class I areas. Section 7.2 of the 2021 Plan identifies control measures included in the VISTAS 2028 emissions inventory. The 2028 RPGs are identified in section 8 of the 2021 Plan and section 8.2.2 includes source retirements and replacements for Florida sources. Section I.D of the TSD to this proposed rulemaking provides a more detailed summary of the State's assessment of the five additional factors in 40 CFR 51.308(f)(2)(iv).

e. Interstate Consultation: FDEP consulted with states and RPOs that identified Florida sources as impacting those states' (or states within the RPOs') Class I areas. FDEP consulted with the two states with one or more sources exceeding Florida's PSAT threshold at one or more of Florida's Class I areas.

i. State/RPOs Requesting Consultation with Florida:

a. MANE-VU's Ask: The following summarizes the conclusions of consultation related to the MANE-VU Ask ^[82] for Florida. Section I.F of the TSD to this rulemaking provides a more detailed summary of the State's assessment of Florida's interstate consultation pursuant to 40 CFR 51.308(f)(2)(ii).

In a letter dated August 25, 2017, MANE-VU requested that 14 states, including Florida, address the “Asks” outlined in the letter on the basis that Florida sources exceeded the visibility impact threshold set by MANE-VU for at least one Class I area in the MANE-VU region. On October 16, 2017, MANE-VU initiated consultations with the states including Florida. Florida ( print page 105525) disagreed with MANE-VU's assertion that Florida's statewide emissions are impacting visibility at MANE-VU Class I areas. Florida's viewpoints are reflected in the January 27, 2018, letter from VISTAS to MANE-VU. To resolve the disagreement, Florida sent a response letter on January 19, 2018, to MANE-VU and noted several disagreements with MANE-VU's analysis. Florida documented the State's responses and viewpoints with respect to the MANE-VU Ask in section 10 and appendices F-4 of the 2021 Plan. Florida believes that the State fulfilled the consultation requirements under 40 CFR 51.308(f)(2)(ii) by the State's participation in a series of five MANE-VU consultation calls held during the period from October 20, 2017, to March 23, 2018, and by the State's documented responses to MANE-VU. Thus, FDEP determined that no further action is required under the RHR to address MANE-VU's requests.

b. Georgia's Request for Consultation with Florida:

In a letter dated November 24, 2020, the Georgia Environmental Protection Division requested that FDEP share Florida's FFA for its sources that impact Georgia's Class I areas—Cohutta, Okefenokee, and Wolf Island. Georgia, through VISTAS analysis, identified five Florida sources that had greater than one percent sulfate impact on at least one of Georgia's Class I areas,^[83] including Nutrien, Foley, WestRock-Fernandina, JEA Northside, and Seminole. As described above, the Haze Plan includes FFAs or existing effective control analyses for these five facilities and identifies permit conditions that are incorporated into Florida's SIP or are proposed for incorporation into the SIP. The permit conditions proposed for incorporation are identified in the “Materials to be Incorporated into the SIP” sections of the 2021 Plan, the 2024 Supplement, and the Second 2024 Supplement for incorporation into the regulatory portion of the Florida SIP.

Florida responded to Georgia in a letter dated December 18, 2020, acknowledging that the Florida sources identified by Georgia met Florida's selection criteria and would be evaluated in FFAs.

ii. Other States with Sources Contributing to Regional Haze at Florida's Class I Areas:

Consultation with other states with sources contributing to regional haze at Florida's Class I areas is discussed in section 10 and appendix F of the 2021 Plan. As listed in table 7-26 of the 2021 Plan, Florida requested an FFA of two sources in two other states because these sources exceeded the State's sulfate PSAT threshold at one or more of Florida's Class I areas: Georgia Power Company—Plant Bowen (Plant Bowen) in Georgia and Tennessee Valley Authority-Shawnee Fossil Plant (TVA-Shawnee) in Kentucky. At the time of plan submission, FDEP documented in section 10 of the 2021 Plan that the State had not yet received a response from Georgia related to Plant Bowen or from Kentucky for TVA-Shawnee.^[84] Additionally, FDEP consulted with Alabama on Sanders Lead Co. since that facility had initially ranked greater than Florida's one percent threshold for PSAT contribution. Alabama provided additional information in a letter showing that this facility's recent SO₂ emissions have significantly reduced from the initial 2028 projections.^[85] In the 2021 plan, FDEP stated that a scrubber went online in late 2019 and reduced the worst-case potential emissions from 7,961.1 tpy to approximately 1,400 tpy of SO₂ which brought Sanders Lead Co. well below the one percent PSAT. Therefore, Alabama did not select the facility for a control evaluation.

3. EPA Evaluation: EPA reviewed Florida's FFAs, determinations of controls necessary for reasonable progress, and submitted permit conditions. Based on this review, EPA proposes to determine that Florida's LTS meets the requirements of 40 CFR 51.308(f)(2)(i) through (iv).

a. Source Selection Criteria: EPA proposes to find that Florida has satisfied the requirements of 40 CFR 51.308(f)(2)(i) with respect to its description of source selection criteria, the outcomes of the source selection process, and the basis for using the AoI and PSAT thresholds and other criteria to select sources. Specifically, Florida provided: appendix B, which details how the State, in conjunction with VISTAS, created emissions inventories relied upon by the State for its Haze Plan; appendix C, which provides monitoring and meteorological data used to support selection of sources; and appendix D, which provides analyses supporting the AoI approach. In addition, FDEP summarized in the 2021 Plan the specific data that Florida used for its source selection analyses, including the AoI and PSAT analyses and results. FDEP followed EPA's 2019 Guidance recommendations to use 2028 emissions projections to select sources and checked the accuracy of its 2028 estimations by electing to evaluate differences between 2017-2019 emissions and 2028 emissions projections in section 7.6.5 of the 2021 Plan.

EPA proposes to find that Florida captured a reasonable set of in-state sources contributing to visibility impairment at Class I areas for the following reasons. AoI and PSAT are acceptable and well-established methods for selecting sources for a control analysis and they enable the identification of the sources that have the largest impacts on visibility at Class I areas in Florida and neighboring states.^[86] Using a five percent AoI threshold and a one percent PSAT threshold, the State identified twelve Florida sources for a control evaluation that are projected to have the highest impact on visibility at both in-state and out-of-state Class I areas at the end of the second planning period.

Additionally, statewide SO₂ emissions are expected to decrease in the second planning period from 2017 levels of 78,173 tpy of SO₂ to projected 2028 levels of 66,979 tpy of SO₂ (approximately a 14 percent reduction), and statewide NO_X emissions are expected to decrease from 2017 levels of 414,369 tpy NO_X to projected 2028 levels of 265,453 tpy NO_X (approximately a 36 percent reduction).^[87] Additional emissions reductions which have not been reflected in the 2028 emissions projections and 2028 RPGs include the following: CD McIntosh, which permanently shut down Unit 3 in 2021; Foley, which had permanently ceased operations by May 2024; ^[88] OUC Stanton, which announced that it will end coal-firing by the end of 2027; and WestRock—Panama City, which ( print page 105526) permanently ceased operations in June 2022. Specific to second planning period visibility improvement, visibility conditions in Florida's Class I areas in 2028 are estimated to improve since the 2014-2018 period by 0.62 deciview (Chassahowitzka), 0.95 deciview (Everglades), and 0.96 deciview (St. Marks). When considered in relation to the amount of visibility improvement needed to reach natural conditions starting from the 2014-2018 period, these projected visibility improvements expected during the second planning period represent approximately the following amount of progress: 7.40 percent improvement (Chassahowitzka), 13.70 percent improvement (Everglades), and 11.62 percent improvement (St. Marks).^[89] Based upon a comparison of the most recently available 20 percent most impaired days IMPROVE data (2018-2022)^[90] to the 20 percent most impaired days data from the end of the first planning period (2014-2018),^[91] in the first four years of the second planning period Florida's Class I areas have already achieved the following amount of additional progress towards natural conditions: 4.5 percent (Chassahowitzka), 8.1 percent (Everglades), and 16.59 percent (St. Marks).^[92] Also, Florida is appropriately focused on controlling point source SO₂ emissions based on data showing ammonium sulfate is the dominant visibility impairing pollutant at the Florida Class I areas_.

b. Consideration of the Four CAA Factors:

i. FFAs: EPA proposes to find that FDEP's reasonable progress determinations and conclusions for the selected sources are reasonable and that Florida submissions satisfy the requirements of 40 CFR 51.308(f)(2)(i) as discussed below.^[93]

a. Foley: Regarding Foley, EPA proposes to find FDEP's determinations of measures that are necessary for reasonable progress are reasonable as described below.

The State evaluated available and technically feasible SO₂ controls based on, where applicable, estimated values of capital costs, annualized costs, and cost per ton of emission reductions, consistent with recommendations in the Cost Manual.

For the No. 1 Power Boiler, the State evaluated adding a wet scrubber with an estimated cost of $13,547/ton, and DSI with an estimated cost of $21,727/ton and determined that these controls are not cost effective.

FDEP determined that existing measures are necessary for reasonable progress. Specifically, the No. 1 Power Boiler shall fire only natural gas except for periods of natural gas curtailment, pipeline disruptions, or physical mill problems that otherwise prevent the firing of natural gas in this unit. For future additions of No. 6 fuel oil to the common tank, the maximum sulfur content shall be 1.02 percent by weight with compliance determined by maintaining records of fuel deliveries, analytical methods, and results of analysis. Tall oil is no longer an authorized fuel.

For the No. 1 Power Boiler, EPA proposes to find that FDEP's determination to impose limitations for existing measures is reasonable and necessary for reasonable progress.

For No. 1 Bark Boiler, as the unit was already equipped with a wet venturi scrubber, Florida considered operating scenarios to achieve additional SO₂ emissions reductions, and determined that running the wet venturi scrubber with requirements on minimum pH and flow rate whenever a LVHC-NCG or oil is fired is cost-effective and necessary for reasonable progress, resulting in a 51 percent reduction in SO₂ emissions annually. EPA proposes to find that FDEP's determination to require more frequent operation of the wet venturi scrubber for the No. 1 Bark Boiler is reasonable and that this measure is necessary for reasonable progress. Additionally, EPA proposes to find that FDEP's determination to impose the low-sulfur fuel restrictions for the No. 1 Bark Boiler that are similar to the restrictions proposed for No. 1 Power Boiler (except the No. 1 Bark Boiler is permitted to burn wood in addition to natural gas as the primary fuel type) is reasonable and that these measures are necessary for reasonable progress.

For the recovery boilers, the State evaluated wet scrubbers with estimated costs of $7,779/ton for Recovery Furnace No. 2; $5,197/ton for Recovery Furnace No. 3; and $6,587/ton for Recovery Furnace No. 4. Florida determined that these measures were not cost effective, but proposed existing measures as necessary for reasonable progress. EPA proposes to find that FDEP's determination to impose requirements for the following existing measures—black liquor as the primary fuel; natural gas and liquid fuels as supplements to recovery operations; a maximum sulfur content of 1.02 percent for purchased no. 6 fuel oil; and a SO₂ emissions cap of 3,200 tons per consecutive 12 operating months as measured by CEMS—is reasonable and that these measures are necessary for reasonable progress.

Therefore, EPA proposes to incorporate into the Florida SIP the permit conditions from permit number 1230001-121-AC that are identified in the “Materials to be Incorporated into the SIP” section of the Second 2024 Supplement.^[94]

b. JEA Northside: Regarding JEA Northside Unit 3,^[95] EPA proposes to find that FDEP's determinations regarding applicable controls for this source at JEA Northside are reasonable. The State evaluated available and technically feasible SO₂ controls that were based on, where applicable, estimated values of capital costs, annualized costs, and cost per ton of emission reductions, consistent with recommendations in the Cost Manual. For NGS Unit 3, EPA proposes to find FDEP's determination that switching to lower sulfur No. 6 fuel oil at $3,053/ton of SO₂ removed is necessary for reasonable progress is reasonable. Thus, EPA proposes to incorporate into the Florida SIP the permit conditions from ( print page 105527) permit number 0310045-057-AC that are listed under “Materials to be Incorporated into the SIP” section of the 2021 Plan.^[96]

c. WestRock-Fernandina: EPA proposes to find FDEP's determinations regarding applicable controls for the sources at WestRock-Fernandina are reasonable. The State evaluated available and technically feasible SO₂ controls based on, where applicable, estimated values of capital costs, annualized costs, and cost per ton of emission reductions, consistent with recommendations in the Cost Manual.

Regarding the No. 7 Power Boiler, FDEP evaluated removing coal as a fuel ($7,374/ton), reducing coal usage (cost savings $1,868/ton), FGD without and with a stack liner ($5,641/ton and $6,028/ton, respectively), DSI ($8,776/ton), and SDA ($16,398/ton). EPA proposes to find FDEP's determination for the No. 7 Power Boiler that reducing coal usage to 125 tpd is cost-effective is reasonable, and proposes to find that reducing coal usage is necessary for reasonable progress for the No. 7 Power Boiler.^[97] Therefore, EPA proposes to incorporate into the Florida SIP the permit conditions from permit number 0890003-072-AC that are listed under the “Materials to be Incorporated into the SIP” section of the 2021 Plan; ^[98] and the permit condition from permit number 0890003-074-AC and listed in appendix A-1 of the 2024 Supplement.

Regarding the No. 5 Power Boiler, FDEP evaluated a wet scrubber system without and with a stack liner ($285,615/ton and $298,499/ton, respectively) and DSI ($277,093/ton). For the Nos. 4 and 5 Recovery Boilers, FDEP evaluated a wet scrubber system at $282,375/ton and $169,425/ton, respectively. EPA proposes to find FDEP's determination that existing SO₂ measures at the No. 5 Power Boiler and the Nos. 4 and 5 Recovery Boilers previously approved into the SIP ^[99] are necessary for reasonable progress is reasonable.

ii. Existing, Effective Control Demonstrations:

EPA proposes to find that certain existing SO₂ measures at the affected units of the eight facilities evaluated for existing, effective control demonstrations are necessary for reasonable progress, and thus, EPA proposes to include these measures in the SIP.

EPA proposes to find that FDEP's proposed adoption of the 0.20 lb/MMBtu MATS limit for the fossil fuel steam generating Unit 4 and Unit 5 at Duke-Crystal River and the permit requirements that allow the citrus combined cycle station Units 1A, 1B, 2A, and 2B to combust only pipeline natural gas is reasonable. The 2019 Guidance provides several scenarios in which EPA believes it may be reasonable for a state not to select a particular source for further analysis. One such scenario is applicable to Duke-Crystal River—a coal-fired EGU that has add-on FGD and meets the applicable alternative SO₂ emission limit of 0.2 lb/MMBtu in the MATS rule. The 2019 Guidance states that it is unlikely that an analysis of control measures for a source already equipped with a scrubber and meeting a 0.20 lb/MMBtu limit or having fuel combustion units that is restricted to combust only pipeline natural gas per enforceable requirements would conclude that even more stringent control of SO₂ is necessary to make reasonable progress. See 2019 Guidance at 23.

EPA evaluated FGD control efficiency data at Units 4 and 5 at Duke-Crystal River and calculated that the existing FGD systems routinely achieve 96.2-98.9 percent yearly average SO₂ removal efficiencies based on 2017-2023 data during periods when coal is one of the fuel sources consumed, with a seven-year average (2017-2023) SO₂ removal efficiencies of 97.0 and 96.8 percent, respectively.^[100] Therefore, for Duke-Crystal River's Units 4 and 5, EPA proposes to find it reasonable that an FFA would likely result in the conclusion that no further SO₂ emissions controls (including FGD upgrades) are necessary for reasonable progress. Therefore, EPA proposes to find that FDEP's determination that these existing SO₂ measures are necessary for reasonable progress and must be adopted into the SIP is reasonable.

EPA proposes to find as reasonable FDEP's determination that an SO₂ limit of 0.15 lb/MMBtu in combination with the MATS-based SO₂ emission limit of 0.20 lb/MMBtu at CFB Boilers 1 and 2 at JEA Northside demonstrate existing, effective SO₂ measures for these units. Regarding FGD control efficiencies at CFB Boilers 1 and 2 JEA Northside, EPA evaluated data from 2017-2023 and calculated that the existing FGD systems routinely achieve 94.8 to 96.6 percent yearly average SO₂ removal efficiencies when consuming coal, having seven-year average (2017-2023) SO₂ removal efficiencies of 95.8 percent.^[101] Therefore, EPA proposes to find FDEP's determination that an FFA would likely result in the conclusion that no further SO₂ emissions controls (including FGD upgrades) is reasonable and that these measures are necessary for reasonable progress. Therefore, EPA proposes to find that the proposed emissions limits are necessary for reasonable progress and must be adopted into the SIP.

EPA proposes to find as reasonable FDEP's determination that Mosaic-Bartow's SAPs 4, 5, and 6 have existing, effective controls. Currently, these units use dual absorption process with cesium catalyst to control SO₂ emissions and restrictions in the SIP to limit the three SAPs at the facility to four lbs/ton of 100 percent sulfuric acid produced, which is consistent with controls identified in EPA's RBLC. In addition, the facility has a three-unit cap at 1,100 lbs/hour on a 24-hour block average and had recent upgrades to reduce SO₂ emissions. Thus, EPA proposes to find FDEP's determination that SAPs 4, 5, and 6 are effectively controlled reasonable, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls these measures are necessary for reasonable progress.

EPA proposes to find that FDEP's determination is reasonable that existing SO₂ measures at Mosaic-New Wales' SAPs 1-5, which use dual absorption process with cesium-promoted catalyst, constitute existing, effective SO₂ controls. The combination of the dual absorption design and the cesium-promoted catalysts represents BACT for sulfur-burning, non-single absorption column SAPs in accordance with the RBLC. Current restrictions in the SIP limit the Nos. 1-3 SAPs to 3.5 lbs/ton of 100 percent sulfuric acid produced on a 24-hr rolling average and four lbs/ton of sulfuric acid produced on a three-hour rolling average, while SAPs 4 and ( print page 105528) 5 are each required to meet a limit of 4.0 lbs/ton of sulfuric acid produced. In addition, the facility has a five-unit cap at 1,090 lbs/hour on a 24-hour block average. Thus, EPA proposes to find FDEP's determination reasonable that SAPs 1-5 have effective SO₂ control measures for Mosaic-New Wales, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls are necessary for reasonable progress.

EPA proposes to find that FDEP's determination is reasonable that existing SO₂ measures at Mosaic-South Pierce's SAPs 10 and 11, which use dual absorption process with cesium-promoted catalyst, constitute existing effective SO₂ controls. The combination of the dual absorption design and the cesium-promoted catalysts represents BACT for sulfur-burning, non-single absorption column SAPs in accordance with the RBLC. Current restrictions in the SIP impose a 750 lbs/hour SO₂ limit on a 24-hour block average. Thus, EPA proposes to find FDEP's determination reasonable that Mosaic-South Pierce's SAPs 10 and 11 have effective SO₂ control measures, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls these measures are necessary for reasonable progress.

EPA proposes to find that FDEP's determination that Nutrien's SAPs E and F have existing effective controls for SO₂ is reasonable. Nutrien's SAPs E and F currently use dual absorption process with cesium catalyst. Current restrictions in the SIP impose SO₂ emission limits at 2.6 lbs/ton, three-hour rolling average; 2.3 lbs/ton, 365-day rolling average, which applies during periods of shutdown and startup; and 840 lbs/hour on a 24-hour block averaging period. The facility elected to complete upgrades on SAP E and SAP F, which included changing out and augmenting the converter catalyst in the SAPs to meet the limits. EPA proposes to find that the State adequately demonstrates that Nutrien's SAPs E and F are effectively controlled, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls are necessary for reasonable.

EPA proposes to find that FDEP's determination that TECO-Big Bend has existing effective controls for SO₂ for Unit 4 is reasonable. TECO-Big Bend's SO₂ emissions are limited by the MATS limit of 0.20 lb/MMBtu which FDEP is proposing to incorporate into the SIP. Regarding FGD control efficiencies at Unit 4 at TECO-Big Bend, EPA evaluated data from 2017-2023 for Unit 4 and calculated that the existing FGD system routinely achieves 92.2-97.1 percent yearly average SO₂ removal efficiencies during periods when coal is one of the fuel sources consumed, with a seven-year average (2017-2023) SO₂ removal efficiency of 95.8 percent.^[102] As mentioned above, Unit 3 at TECO-Big Bend was permanently retired from electric generation service on April 26, 2023, and therefore, Florida's demonstration of existing, effective controls is no longer relevant and no further action is required by EPA.^[103] Therefore, EPA proposes to find FDEP's determination that TECO-Big Bend Unit 4 is effectively controlled is reasonable, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls (including FGD upgrades) are necessary.

Lastly, EPA proposes to find that FDEP's determination that Seminole has existing effective controls for SO₂ for steam electric generators Nos. 1 and 2 is reasonable. The MATS SO₂ limit of 0.20 lb/MMBtu applies to the Seminole facility, and Florida identified this emission limit for incorporation into the SIP. Regarding FGD control efficiencies at Unit Nos. 1 and 2 at Seminole during periods when coal is one of the fuel sources consumed, EPA evaluated data from 2017-2023 and calculated that the existing FGD systems routinely achieve 96.5-97.3 percent yearly average SO₂ removal efficiencies, with a seven-year average (2017-2023) SO₂ removal efficiency of 96.8 percent.^[104] Therefore, EPA proposes to find FDEP determination reasonable that Seminole Unit Nos. 1 and 2 are effectively controlled, and that an FFA would likely result in the conclusion that no further SO₂ emissions controls (including FGD upgrades) are necessary.

c. Documentation of Technical Basis: With respect to 40 CFR 51.308(f)(2)(iii), EPA proposes to find that Florida adequately documented cost, engineering, emissions, modeling, and monitoring information to determine the measures that are necessary to make reasonable progress for the following reasons. With regard to emissions information, as required by the RHR, the State included the required years of the most recent triennial emissions inventory (2017) and the most recent annual SO₂ emissions data for specific sources (2019) available at the time of the development of the 2021 Plan. FDEP provided actual emissions inventory data for 2011, 2014, and 2017, and emissions projections for 2028 in its Haze Plan. Specifically, table 4-1 provides a 2011 emissions inventory for Florida which includes the visibility impairing pollutants and carbon monoxide. Emissions from the 2014 and 2017 NEIs are provided in tables 13-11, 13-12, and 13-13 for PM_2.5, NO_X, and SO₂, respectively. For all Florida facilities with emissions of either SO₂ or NO_X greater than 100 tpy in 2017, table 7-28 (SO₂) includes actual emissions for 2017, 2018, and 2019, and 2028 (remodeled) projected emissions. With regard to cost and engineering information, the State provided the underlying cost calculations associated with the cost summaries in section 7.8 of the Haze Plan for Foley, JEA Northside, and WestRock-Fernandina, and the proposed FFAs in appendix G provide engineering analyses evaluating potential new control measures. With regard to monitoring data, the State provided IMPROVE data for the modeling base period plus baseline, current (2014-2018), and natural conditions for all VISTAS Class I areas with more detailed data provided for the Florida Class I areas. With regard to modeling information, the State documented the modeling input and outputs and assumptions in the Haze Plan and the results of the modeling related to RPGs and PSAT source impacts at Class I areas.

d. Assessment of Five Additional Factors in 40 CFR 51.308(f)(2)(iv):

EPA proposes to find that Florida has satisfied the requirements of 40 CFR 51.308(f)(2)(iv) because FDEP considered each of the five additional factors, discussed the measures the State has in place to address each factor (or discussed why such measures are not needed), and where relevant, explained how each factor informed FDEP's and VISTAS' technical analyses for the second planning period.

With respect to 40 CFR 51.308(f)(2)(iv)(A), EPA proposes to find that FDEP adequately addressed the requirement to assess emission reductions due to ongoing air pollution control programs, including measures to address RAVI, through the State's emissions inventory work for the base year of 2011 as projected out to 2028.

With respect to 40 CFR 51.308(f)(2)(iv)(B), EPA proposes to find that Florida adequately addressed this requirement to evaluate measures to mitigate the impacts of construction activities by describing a state regulation that addresses control of fugitive airborne dust and considering ( print page 105529) the minor impact fine soils have on visibility.

With respect to 40 CFR 51.308(f)(2)(iv)(C), EPA proposes to find that Florida adequately addressed source retirement and replacement schedules by summarizing existing and planned source retirements in section 8.2.2 in the 2021 Plan.

With respect to 40 CFR 51.308(f)(2)(iv)(D), EPA proposes to find that Florida adequately addressed the requirement to consider the State's basic smoke management practices for prescribed fire used for agricultural and wildland vegetation management purposes and smoke management programs. The State describes its SMP to mitigate PM_2.5 emissions associated with prescribed burning and highlights its burn authorization program, operated by Florida's Forest Service, that considers the potential impact of smoke at sensitive receptors.

With respect to 40 CFR 51.308(f)(2)(iv)(E), EPA proposes to find that Florida assessed the anticipated net effect on visibility due to projected changes in point, area, and mobile source emissions over the second planning period in development of the 2028 RPGs for the Florida Class I areas. FDEP also identifies control measures included in the VISTAS 2028 emissions inventory and source retirements and replacements. FDEP used the 2011 base year emissions inventory to project emissions from various source sectors to 2028, the end of the second planning period. FDEP, through VISTAS, completed CAMx modeling to estimate visibility impairment in 2028 based on projected 2028 emissions from the 2011 base year inventory and using IMPROVE monitoring data for 2009-2013. As mentioned previously, atmospheric ammonium sulfate is the largest contributor to visibility impairment in Class I areas in the Southeast. VISTAS emission sensitivity modeling determined that the most effective way to reduce ammonium sulfate is to reduce SO₂ emissions from EGUs and non-utility industrial point sources.

e. Interstate Consultation: Based on the consultation documentation described in section III.C.2.e of this document and section I.F. of the TSD to this proposed rulemaking, EPA proposes to find that Florida has met the requirements under 40 CFR 51.308(f)(2)(ii) to consult with those states with Class I areas that Florida emissions impact for visibility and to consult with those states whose sources are impacting Florida's Class I areas.^[105] Additionally, Florida appropriately responded to and documented requests from MANE-VU to address upwind emissions from sources in VISTAS states. Lastly, FDEP completed the requested emissions control analyses for the five facilities and provided the State's analyses and conclusions of these analyses in section 7.6 and 7.8 of the 2021 Plan and 2024 Supplement.

EPA also proposes to find that FDEP appropriately consulted with other states, namely Kentucky, Georgia, and Alabama regarding specific sources that are reasonably anticipated to contribute to visibility impairment at Class I areas in Florida in accordance with 40 CFR 51.308(f)(2)(ii). EPA proposes to conclude that Florida appropriately documented its interstate consultations regarding Florida sources reasonably anticipated to contribute to visibility impairment at Class I areas outside of the State and sources in other states reasonably anticipated to contribute to visibility impairment at Florida's Class I areas.^[106]

D. RPGs

1. RHR Requirement: Section 51.308(f)(3) contains the requirements pertaining to RPGs for each Class I area. Section 51.308(f)(3)(i) requires a state in which a Class I area is located to establish RPGs—one each for the most impaired and clearest days—reflecting the visibility conditions that will be achieved at the end of the planning period as a result of the emission limitations, compliance schedules and other measures required under paragraph (f)(2) to be in states' LTS, as well as implementation of other CAA requirements. The LTS, as reflected by the RPGs, must provide for an improvement in visibility on the most impaired days relative to the baseline period and ensure no degradation on the clearest days relative to the baseline period. Section 51.308(f)(3)(ii) applies in circumstances in which a Class I area's RPG for the most impaired days represents a slower rate of visibility improvement than the URP calculated under 40 CFR 51.308(f)(1)(vi). Under 40 CFR 51.308(f)(3)(ii)(A), if the state in which a mandatory Class I area is located establishes an RPG for the most impaired days that provides for a slower rate of visibility improvement than the URP, the state must demonstrate that there are no additional emission reduction measures for anthropogenic sources or groups of sources in the state that would be reasonable to include in its LTS. Section 51.308(f)(3)(ii)(B) requires that if a state contains sources that are reasonably anticipated to contribute to visibility impairment in a Class I area in another state, and the RPG for the most impaired days in that Class I area is above the URP, the upwind state must provide the same demonstration.

2. State Assessment: Florida identified the 2028 RPGs for each of its Class I areas in deciviews. Florida's RPGs are listed in table 3.

Table 3—Florida Class I Areas' 2028 RPGs and URP in Deciviews ( dv )

Class I area	2028 RPG clearest 20%	2028 RPG most impaired 20%	2028 URP
Chassahowitzka	12.54	16.79	18.36
St. Marks	11.59	16.43	18.26
Everglades	9.88	13.95	15.06