EPA proposes approval of Florida haze findings for power plants

The U.S. Environmental Protection Agency is proposing to approve certain Best Available Retrofit Technology (BART) and reasonable progress determinations related to several coal-fired power plants included in a regional haze state implementation plan (SIP) amendment submitted by the Florida Department of Environmental Protection (FDEP), on Sept. 17.

These BART and reasonable progress determinations are for sources that are subject to the Clean Air Interstate Rule (CAIR) and were initially included in a July 31 draft regional haze SIP amendment submitted by FDEP for parallel processing and re-submitted in final form as part of the state’s Sept. 17 regional haze SIP amendment, EPA said in a Dec. 10 Federal Register notice.

In this action, EPA also proposes to find that Florida’s Sept. 17 amendment corrects the deficiencies that led to the proposed May 25 limited approval and proposed December 2011 limited disapproval of the state’s entire regional haze SIP, and that Florida’s SIP meets all of the regional haze requirements of the Clean Air Act (CAA). EPA is therefore withdrawing the previously proposed limited disapproval of Florida’s entire regional haze SIP and proposing full approval. EPA is taking comment on this proposed approval until Jan. 9, 2013.

EPA’s December 2011 proposed limited disapproval of Florida’s regional haze SIP was based on the state’s initial reliance on CAIR to satisfy both BART requirements and the requirement for a long-term strategy (LTS) sufficient to achieve the state-adopted reasonable progress goals (RPGs). Florida’s Sept. 17 SIP amendment replaced reliance on CAIR to satisfy the BART and reasonable progress requirements for its affected electricity generating units (EGUs) with case-by-case BART and reasonable progress control analyses. An August decision by the U.S. Court of Appeals for the D. C. Circuit to vacate the Cross-State Air Pollution Control Rule (Transport Rule) and keep CAIR in place ensures that any emissions reductions associated with CAIR are sufficiently permanent and enforceable for purposes of this action, EPA noted.

EPA is now proposing to take two related actions. First, EPA is proposing to approve the remaining BART and reasonable progress determinations in Florida’s Sept. 17 regional haze SIP amendment not previously addressed in EPA’s November final action. Second, EPA is proposing to find that Florida’s Sept. 17 SIP amendment corrects the deficiencies that led to the December 2011 proposed limited disapproval and the May 25 limited approval of the state’s regional haze SIP and that the regional haze SIP as a whole now meets the regional haze requirements of the CAA.

EPA said it has recognized that prior to the earlier CAIR court remand, the state’s reliance on CAIR to satisfy BART for NOX and SO2 for affected CAIR EGUs was fully approvable and in accordance with federal regulations. In addition, CAIR remains in place until EPA develops a suitable replacement. However, the Florida facilities with EGUs that previously relied on CAIR to satisfy their BART and reasonable progress obligations for SO2 and NOX will eventually not be subject to CAIR. FDEP also recognized that CAIR’s replacement might not satisfy the regional haze requirements for Florida. Accordingly, FDEP initiated an effort to reassess BART and reasonable progress for all of the facilities that had relied on CAIR to meet regional haze obligations.

In its April 13 draft regional haze SIP amendment, FDEP addressed 13 of the 31 EGUs subject to reasonable progress analysis and 12 of the 23 facilities with BART-eligible EGUs. In its July 31 draft amendment, Florida addressed the remaining 18 reasonable progress units and the remaining 11 facilities with BART-eligible EGUs subject to CAIR (a total of 20 EGUs). The state’s Sept. 17 amendment finalized these BART and reasonable progress determinations addressed in its April 13 and July 31 draft SIP amendments, and on Nov. 29, EPA finalized full approval of the BART determinations addressed in the April 13 amendment.

Various units included in Sept. 17 version of state plan

A portion of the state’s Sept. 17 regional haze SIP amendment addresses 18 of the EGUs subject to CAIR and a reasonable progress analysis. Ten of these emissions units are also subject to BART review under the Regional Haze Rule (RHR): Florida Power and Light—Manatee Units 1-2 ; FPL—Turkey Point Units 1-2; Gulf Power—Crist Unit 7; JEA – Northside-SJRPP Unit 3; Progress Energy Florida—Anclote Units 1-2; and PEF—Crystal River Units 1-2.

Florida conducted individual reasonable progress control reviews only on the remaining eight EGUs at five facilities: Gainesville Regional Utilities – Deerhaven (Unit 5); Lakeland Electric—C.D. McIntosh (Unit 6); JEA— Northside/SJRPP (Units 16-17); PEF—Crystal River (Units 3-4); and Seminole Electric (SECI) – (Units 1-2).

The results of FDEP’s reasonable progress analyses for the eight remaining EGUs are summarized below by facility, followed by EPA’s assessment.

GRU Deerhaven – GRU’s Deerhaven Unit 5 is a nominal 251 (MW) coal-fired EGU. SO2 emissions are currently controlled with a dry flue gas desulfurization (FGD) system designed to achieve a target outlet SO2 emissions rate of 0.12 lb/MMBtu). This dry FGD came on-line in 2009, providing reductions in SO2. Due to the addition of the dry FGD, FDEP has issued a federally enforceable permit condition that limits SO2 emissions to 5,500 tons per year. Thus, no further analysis of this source is required for this implementation period.

PEF Crystal River – Units 4 and 5 at Crystal River are coal-fired EGUs, each rated at 760 MW. (Note that the EPA notice keeps referring to Crystal River Units 3 and 4, but Unit 3 is nuclear so it is obviously referring to Units 4-5). SO2 emissions are controlled with wet FGD systems that came on line in 2009 and 2010 and are designed to reduce emissions by 97%. Wet FGD systems are considered by FDEP to be the top-level SO2 emissions control system for coal-fired boilers, and the SO2 emissions from these units are limited to 0.27 lb/MMBtu, based on a 30-day rolling average, through a federally enforceable permit. While lower sulfur coal is potentially available from the Powder River Basin (PRB), PRB coal is a sub-bituminous coal with unique combustion characteristics that would require additional operational modifications to ensure continued safe and reliable unit performance. Moreover, the transportation of this coal from Wyoming to Florida would be cost prohibitive and produce secondary environmental impacts, EPA noted. Installing additional add-on controls for PRB firing would take several years due to PEF’s need to continue operating the units as baseload. After considering the four reasonable progress factors for PEF Crystal River, FDEP determined that the existing wet FGD systems at the current, permitted emissions limits satisfy the reasonable progress requirements for this implementation period.

SECI Seminole Units 1 and 2 – These are solid fuel, dry-bottom, wall-fired units with a maximum heat input of 7,172 MMBtu/hr generating 736 MW each. Units 1 and 2 are currently authorized to burn coal as the primary fuel but are also authorized to burn a blend of coal and petroleum coke with up to a maximum of 30% by weight petroleum coke. The maximum sulfur content of the petcoke may not exceed 7% by weight on a dry basis (2.3 times the coal sulfur content of 3.0% by weight). Units 1 and 2 are each equipped with a wet FGD to control SO2 emissions. FDEP has determined that wet FGD technology provides the highest SO2 removal efficiencies for coal-fired boilers. However, certain upgrades are available to improve the FGDs to achieve 95% removal efficiency, and while not quantified, the company has agreed to incur the costs to achieve this removal efficiency. In addition to the FGD controls for SO2, the facility is equipped with electrostatic precipitators (ESPs) for control of PM; low NOX burners and selective catalytic reduction (SCR) for NOX control; and an alkali injection system to control sulfuric acid mist. The wet FGD controls were installed in 1984 and upgraded in 2010 to comply with CAIR and other air regulatory programs (e.g., the Utility Mercury and Air Toxics Standards (MATS) rule). Following these upgrades, the allowable SO2 emissions rate for Units 1 and 2 was reduced from 1.2 to 0.67 lb/MMBtu on a 30-day rolling average basis. The FGD control systems on Units 1 and 2 currently achieve about 92% SO2 removal, and SECI proposes to make additional changes to Units 1 and 2 to achieve a minimum SO2 removal efficiency of 95% or, alternatively, to achieve an equivalent SO2 emissions rate of no more than 0.25 lb/MMBtu on a 30-day rolling average basis for both units. SECI will complete its evaluation of FGD upgrades and provide FDEP with the selected option by March 1, 2013. Compliance with the 95% SO2 removal efficiency or the alternate emissions limit of 0.25 lb/MMBtu SO2 will be achieved by March 1, 2016.

Lakeland Electric C.D. McIntosh – C.D. McIntosh Unit 6 is a nominal 364-MW fossil fuel-fired EGU that fires coal and up to 20% petcoke, low sulfur fuel oil, high sulfur fuel oil and natural gas or propane. Unit 6 is subject to a federally enforceable permit condition that limits SO2 emissions to: 0.80 lb/MMBtu for liquid fossil-fuel firing (3-hour average); 1.2 lb/MMBtu for solid fossil-fuel firing (3-hour average); 0.718 lb/MMBtu for blends of petcoke and any other fuels (30-day rolling average); and whenever coal or blends of coal and petroleum coke or refuse are burned, SO2 gases discharged to the atmosphere from the boiler shall not exceed 10% of the potential combustion concentration (90% reduction), or 35% of the potential combustion concentration (65% reduction), when emissions are less than 0.75 lb/MMBtu heat input (30-day rolling average). For the most recent five-year period, more than 95% of the total heat content is due to bituminous coal firing. Unit 6 is currently equipped with a wet limestone FGD. The current title V permit requires a 65% reduction in SO2 when the emissions are less than 0.75 lb/MMBtu (30-day rolling average) and a 90% reduction when emissions are greater than or equal to 0.75 lb/ MMBtu (30-day rolling average). Based on the actual SO2 emissions reported in 2002, the FGD system reduces SO2 emissions by 81%. Lakeland considered several changes and upgrades to the wet FGD system to further reduce SO2, including lower sulfur fuel, FGD modifications, and complete replacement of the FGD system. Among the authorized fuels for Unit 6, petcoke has the highest sulfur content (average of 3.9% sulfur by weight), and bituminous coal (average of 1.8% sulfur by weight) is the fuel with next highest sulfur content. Lakeland Electric is authorized to burn up to 20% 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 2.2% (80% coal with 1.8% sulfur and 20% petroleum coke with 3.9% sulfur). Lakeland believes that curtailing petcoke firing is the most cost-effective solution to reduce SO2 emissions. FDEP has determined that the existing wet FGD system at the current, permitted emissions limits with the elimination of petcoke as an authorized fuel meets reasonable progress requirements for this implementation period.

JEA St. Johns River Power Park – JEA’s SJRPP Emissions Units 16 and 17 (commonly referred to as Boilers 1 and 2) are fossil fuel-fired EGUs rated at 679 MW each with a maximum heat input rate of 6,144 MMBtu/hr per boiler. The boilers are fired with pulverized coal, a coal blend with a maximum of 30% petcoke by weight, natural gas, new No. 2 distillate fuel oil (startup and low-load operation), and “on specification” used oil. The maximum coal or petcoke-coal blend sulfur content cannot exceed 4% by weight, and the maximum sulfur content of the No. 2 fuel oil is 0.76% by weight. Federally enforceable permit conditions limit SO2 emissions when burning coal to 1.2 lb/ MMBtu on a maximum two-hour average and 0.76 lb/MMBtu on a 30-day rolling average. Units 16 and 17 are equipped with wet FGD systems capable of up to 90% reduction in SO2 emissions with a maximum SO2 emissions rate of 0.76 lb/MMBtu (30-day average) using the worst-case fuel. FDEP determined that the existing FGD systems at the current, permitted emissions limits satisfy the reasonable progress requirement for the implementation period.

EPA proposes to find that Florida fully evaluated all control technologies available at the time of its analysis and applicable to: GRU Deerhaven Unit 5; PEF—Crystal River Units 4 and 5; SECI Units 1 and 2; Lakeland Electric—C.D. McIntosh Boiler Unit 6; and JEA SJRPP Units 16 and 17. Accordingly, EPA is proposing to approve the reasonable progress determinations for these eight units for the first implementation period.

List of 20 BART-eligible units was whittled down

The state’s Sept. 17 amendment identified 20 BART-eligible units at 11 facilities with EGUs that were subject to CAIR and found subject to BART that were included in the state’s July 31 draft SIP amendment. Florida determined that the City of Tallahassee Arvah B. Hopkins Unit 1 was not subject to BART. In addition, two of the remaining BART-eligible sources — Reliant Energy Indian River Units 2-3 and PEF Anclote Units 1-2 — made changes to their operations in order to ensure that allowable emissions would not cause visibility impacts to exceed a threshold. EPA proposes to agree with Florida’s findings that these five units are not subject to further BART review.

Florida determined that the remaining 15 BART-eligible units at eight facilities were subject to BART. The state’s evaluations and conclusions are summarized below by facility, followed by EPA’s assessment.

Gulf Power Crist – Gulf Power’s Crist plant consists of four active fossil fuel-fired EGUs (Units 4, 5, 6, and 7), two of which are BART-eligible units (Units 6 and 7). Pulverized coal is the primary fuel for Units 6 and 7, and natural gas, fuel oil, and on-specification used oil are used as supplemental fuels in all four of the units. The facility operates a wet FGD system to control SO2 emissions from Units 4–7 by 95%; low NOX burners (LNB) and SCR (designed to achieve no less than an 85% reduction) to control NOX emissions from Units 6 and 7; and cold side ESPs to control PM emissions from Units 6 and 7. FDEP determined that existing controls at Units 6 and 7 represent the most stringent controls available, thus satisfying the BART requirements for SO2, NOX, and PM. No new limits or changes to existing limits were adopted for BART.

FPL Martin – The Martin plant consists of two oil- and natural gas-fired conventional fossil fuel steam EGUs (Units 1 and 2), two oil- and natural gas-fired combined cycle units (Units 3 and 4), four oil- and natural gas-fired combined-cycle combustion turbines (Unit 8), and associated support equipment. Only Units 1 and 2 are subject to BART. Units 1 and 2 each have a maximum capacity of 863 MW and are equipped with LNB to reduce NOX emissions and multi-cyclones with fly ash reinjection to control PM emissions. Separate from the BART determination, FPL is currently planning to install ESPs for the purpose of controlling PM emissions from Units 1 and 2. The projected ESP installation date is first quarter of 2014 for Unit 1 and the fourth quarter of 2014 for Unit 2. FDEP has determined that existing controls at the current, permitted emissions limits for the affected pollutants SO2, NOX, and PM are BART for Martin.

FPL Manatee – The Manatee plant consists of two oil- and natural gas-fired 800-MW (900 MW gross capacity) conventional steam EGUs (Units 1 and 2), a “4 on 1” gas-fired combined cycle unit (Unit 3A–3D), and miscellaneous insignificant emissions units. Only Units 1 and 2 are BART-eligible. Each of these two units is equipped with ESPs for PM and a FGR system along with reburn and staged combustion for NOX. In addition, FPL recently submitted a permit application to FDEP seeking an increase in the natural gas capacity of these units from 5,670 MMBtu/hr to 8,650 MMBtu/hr to displace the use of more residual fuel oil which will raise the allowable natural gas capacity in the permit to equal the oil-firing permit capacity. The proposed increased utilization of natural gas is also expected to reduce SO2, PM, and NOX emissions from Units 1 and 2. In addition, FDEP has determined that SO2 emissions and visibility impacts can be reduced by switching to low sulfur fuel oil with a maximum of 0.7% sulfur content or to a mixture of low sulfur fuel oil containing a maximum of 1.0% sulfur and natural gas in a ratio not to exceed the SO2 emissions limit of 0.80 lb/MMBtu heat input. FDEP has determined that the controls already in place, or soon to be in place, at the current, permitted emissions limits for NOX and PM are BART for Units 1 and 2.

Lakeland Electric C.D. McIntosh – This plant has two BART-subject units. Unit 1 is a pre-NSPS boiler with a nominal rating of 985 MMBtu/hr fired by natural gas and fuel oil and no emissions controls. Emissions Unit 5 (commonly referred to as Unit 2 or Boiler 2) is a NSPS subpart D boiler with a nominal rating of 1,185 MMBtu/hr heat input equipped with FGR for NOX control and no add-on PM or SO2 controls. FDEP has determined that the use of 0.7% sulfur fuel oil and existing controls achieving the current, permitted emissions limits for the affected pollutants – SO2, NOX, and PM – are BART for Units 1 and 2.

JEA Northside – Unit 3 at this plant – which is next to the SJRPP and covered by the same air permitting – is the only BART-eligible unit. It is a pre-NSPS boiler with a nominal rating of 564 MW that is fired by natural gas, landfill gas, residual fuel oil, and used oil and is equipped with LNB. Units 1 and 2 are repowered units that were converted to circulating fluidized bed boilers firing mainly petcoke and coal (about 10%) fuel blends. As part of the repowering of Units 1 and 2, JEA made a commitment to reduce SO2, NOX, and PM emissions to 10% below the 1994 and 1995 baseline years used in the permitting of the repowering project. As a result, emissions caps for each of these pollutants were incorporated into the federally enforceable permit. Because the repowered units are more efficient and better controlled, operation of Unit 3 was reduced when the new repowered units became operational. Based on the operation of Unit 3 on oil, the emissions cap that most limits operation is the NOX cap, which is limited by a federally enforceable title V permit to 3,600 tons per year for Units 1, 2, and 3 over a 12-month rolling average. Based on the sulfur content of the fuels used in Unit 3 in 2002, this annual NOX limit restricts SO2 emissions from oil firing to about 9,000 tons per year if Units 1 and 2 are not operating, equivalent to a capacity factor of about 21% at the authorized emissions rate. If Units 1 and 2 are fully operational (the usual case), Unit 3 is limited to a maximum of 3,506 tons of SO2 per year, equivalent to a capacity factor of approximately 8% at the authorized emissions rate. FDEP has determined that the limited use of fuel oil and the controls already in place at the current, permitted emissions limits are BART for Unit 3.

Gulf Power Lansing Smith – This plant consists of two coal-fired EGUs (Units 1 and 2), two simple cycle peaking units, two combined cycle combustion turbines, and miscellaneous insignificant emissions units. Units 1 and 2 are subject to BART and burn coal, distillate fuel oil, or on-spec used fuel oil. Unit 1 has a maximum authorized heat input rate of 1,944.8 MMBtu/hr and Unit 2 has a maximum authorized heat input rate of 2,246.2 MMBtu/hr. Units 1 and 2  are both equipped with hot and cold side ESPs and selective non-catalytic reduction (SNCR). Unit 1 is also equipped with LNB with high momentum injection ports, and Unit 2 has LNB with an overfire air control system. FDEP has determined that the controls already in place at the current, permitted emissions limits for NOX and PM are BART for Units 1 and 2. FDEP has also determined that SO2 emissions and visibility impacts can be further reduced by switching Units 1 and 2 to lower sulfur coal and installing dry sorbent injection (DSI) using trona as a reagent and that these control measures are BART for SO2. Gulf Power stated that the use of lower sulfur Colombian coal can result in lower SO2 with no added capital investment and that switching Units 1 and 2 to lower sulfur coal would reduce SO2 emissions by approximately 25%. Gulf Power estimated that the use of DSI with trona injection combined with lower sulfur coal would have a SO2 removal efficiency of 48% corresponding to a SO2 emissions rate of 0.74lb/MMBtu on a 30-day rolling average.

FPL Turkey Point – FPL’s Turkey Point facility consists of two residual fuel oil- and natural gas-fired 440 MW fossil fuel steam EGUs (Units 1 and 2); five fuel oil-fired black start 2.75 MW diesel peaking generators supporting Units 1 and 2; a natural gas-fueled 1,150 MW combined cycle unit (Unit 5); and associated equipment. Units 1 and 2 are subject to BART and are each equipped with LNB and multi-cyclones with ash reinjection. In 2009, FDEP issued a PM-only BART determination for Units 1 and 2 that imposed a 20% visible emissions limit, a 0.7% sulfur fuel oil restriction, and upgrades to the multi-cyclones to achieve a 0.07 lb/ MMBtu PM emissions rate. In addition, the determination required FPL to conduct a PM control device additive study to determine if a 0.05 lb/ MMBtu emissions rate could be achieved. FPL completed the study in 2010 showing that the lower limit was not achievable using a calcium-based additive. In September 2011, FPL submitted a revised PM BART proposal to eliminate the requirement to upgrade the multi-cyclones on Unit 1 and to continue to use the existing multi-cyclone to meet a limit of 0.07 lb/ MMBtu as BART for this unit based on the limited use of oil in Unit 1 and FPL’s conclusions that the visibility impacts from PM are negligible and that there is little incremental visibility benefit of a new dust collector. Subsequent to the request to change the PM BART limitations, FPL submitted a new proposed BART determination to FDEP that addresses SO2 and NOX. FDEP determined that Unit 1 will meet SO2 BART by restricting the use of fuel oil to 8,760,000 MMBtu/year heat input (equivalent to a capacity factor of 25%) and by reducing the sulfur content of the fuel fired in Unit 1 to 0.7% by weight as soon as practicable but no later than Dec. 31, 2013. A permit also requires the permanent shutdown of Unit 2 as soon as practicable but no later than Dec. 31, 2013. FDEP determined that the controls already in place at the current, permitted emissions limits for NOX and PM are consistent with the original BART determination for Unit 1 made by FDEP in 2009 that required the multi-cyclones to meet a 0.07 lb/MMBtu limit for PM.

PEF Crystal River – This provision affects the coal-fired Units 1 and 2 at the plant, which are older and smaller than Units 4 and 5 (again, Unit 3 is nuclear). Units 1 and 2 are tangentially-fired, dry-bottom boilers with a nominal generation capacity of 440.5 and 523.8 MW, respectively, that may burn bituminous coal or a bituminous coal and bituminous coal briquette mixture. Distillate fuel oil may be burned as a startup fuel. Each unit has an ESP to control PM and LNB to control NOX. PEF has proposed to satisfy SO2 and NOX BART requirements through an approach that would allow the company to select one of two compliance options. The first option would require the installation of a dry FGD and SCR to these units by 2018. The second would shut down these units by Dec. 31, 2020, with no new controls being installed. PEF has requested that it have until Jan. 1, 2015, to state which option it will pursue because it was in the process of ownership change (a takeover by Duke Energy (NYSE: DUK)) and decisions on how these units will be addressed in response to other federal regulations are uncertain. FDEP believes that either of the two options meet the BART requirements, and FDEP has allowed PEF until Jan. 1, 2015, to choose an option.

EPA said it proposes to approve Florida’s BART analyses and determinations for the units identified above because the analyses were conducted in a manner that is consistent with EPA’s BART Guidelines and EPA’s Air Pollution Control Cost Manual and because Florida’s conclusions reflect a reasonable application of EPA’s guidance to these sources.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.