The Issue Whether the Governor and Cabinet sitting as the Siting Board should approve (on appropriate conditions) or deny petitioners' application for a certificate authorizing construction and operation of the proposed Cedar Bay Cogeneration Project, an electrical power plant?
Findings Of Fact As far as the evidence showed, petitioners never analyzed the costs of a natural gas facility as compared to those of a coal-fired facility. According to uncontroverted testimony, however, natural gas is not commercially available in the quantities necessary to fire the plant. If fueled by natural gas, instead of by coal as proposed, the Cedar Bay Cogeneration Project would require 50 million cubic feet of natural gas per day, on a firm basis. Natural Gas Availability The Florida Gas Transmission system, a branch of which (the "Brooker lateral") serves People's Gas System, the only local distribution company in Jacksonville, (RT.60) has no transmission capacity not already fully allocated to existing users. Among Florida Gas Transmission Company's customers are other power plants, including some operated by Jacksonville Electric Authority. Florida has "roughly 6,000 megawatts of power [generating capacity] that is primarily gas fired . . . [and] another 5,000 megawatts of power [generating capacity] that uses natural gas as a secondary fuel." RT.62. It would take more than "the entire capacity of the Florida Gas Transmission system to move . . . the fuel required to generate . . . 6,000 megawatts." Id. Jacksonville Electric Authority buys natural gas on an interruptible basis, because it has been unable to obtain a commitment to a constant or "firm" supply. The Florida Gas Transmission Company has plans to expand its transmission capacity by 100 million cubic feet a day to a total of 925 million cubic feet a day in 1991 or early 1992. But allocation of the increase -- an issue in obtaining approval from the FERC -- has already been accomplished, and the expansion will make no firm capacity available to new users. Talk of another expansion has already begun, but so far the company has done little more than collect questionnaires (which suggest demand for double the existing service.) At one time, liquefied natural gas came from Algeria to Elba Island near Savannah, Georgia, by ship. A 20- inch pipeline connects the terminal with the Sonat system on the mainland. But no Sonat pipeline comes within some 150 miles of Jacksonville, and shipments of liquefied natural gas to Elba Island ceased with the decline of oil prices after the mid-l970s. At present, the Florida Gas Transmission Company has a monopoly in Jacksonville and peninsular Florida. But `a system. in southern Georgia "called Mobile Bay" (RT.77) has plans to extend a 12-inch pipeline from an existing line near Live Oak to Jacksonville. With respect to some or all of this planned capacity, "certain commitments have been made." RT.59. Under pressure, the proposed 12-inch pipeline could transmit over 40 million cubic feet of natural gas a day, but only if that much gas reached Live Oak, and "the South Georgia system is constrained during certain parts of the year," RT.59, as it is. From the fact that a pipeline is to be constructed to bring less natural gas to Jacksonville than would be required to fuel the Cedar Bay project it might be inferred that the project itself would justify construction of a pipeline. But the opinion of petitioners' expert, Mr. Van Meter that natural gas is not an available or reasonable fuel for the Cedar Bay Cogeneration Project (RT.65, 74, 79) -- and would not have been even if natural gas had been planned for earlier -- went unrebutted. Likewise unrebutted was the testimony of another of petitioners' experts that, from an economic standpoint, "Base load power plants['] most desirable fuels would be coal and nuclear." RT. 103. Construction Dewatering The applicants have modified their dewatering plan, and now propose new construction techniques for the railcar unloading facility; sequential installation of underground pipes; sequential excavation of pump pits; and an advanced effluent treatment system. (RT. 147, 149-52, 171-76, 178, 185-92; AES Ex. 4R) A cofferdam or groundwater barrier encircling the railcar unloading area would drastically reduce the amount of groundwater seeping into the excavation during construction. (RT. 173; AES Ex. 4R, 7R). Sheet piling is to be driven into perimeter trenches filled with bentonite cement. (RT. 174-75; AES Ex. 4R, 7R, 8R). Using a jet grouting technique, a five- to ten-foot thick seal would be created underneath the planned excavation. (RT. 175-76; AES Ex. 4R, 7R, 9R). Steel tie-back rods would strengthen the cofferdam, and a pump would move seepage to the surface from a sump designed to collect groundwater seeping through the cofferdam and up through the grout into the excavation. (RT. 176-77; AES Ex. 4R, 7R) The modified construction techniques now proposed would reduce maximum groundwater drawdown outside the cofferdam from approximately the 30 feet below grade originally contemplated to a currently anticipated level of approximately 5.5 feet below grade. (RT. 279; AES Ex. 10R). Excavations to install circulating water piping and to create pits to house runoff pumps would be scheduled to keep down the volume of dewatering effluent at any given time. (RT. 178-79, AES Ex. 4R) Installing a cofferdam, jetting in grauting, and sequencing construction, as now proposed, would reduce dewatering effluent flows from the 1000 to 2000 gallons per minute originally contemplated to no more than 200 gallons per minute. (RT. 180, 185; AES Ex. 4R, pp. 1 and 2) In another modification, the applicants now propose an advanced treatment system to improve the quality of (a diminished quantity of) dewatering effluent, prior to its introduction into Seminole Kraft's cooling water system. The proposed treatment system would employ as many as five treatment technologies, if needed, to ensure that cooling water system discharges to the St. Johns River containing dewatering effluent would meet Class III water quality standards. Equipment necessary to bring each technology to bear would be on site and available for use before dewatering began. (RT. 151, 185, 193, 196; AES Ex. 4R) Mixing dewatering effluent with lime would remove dissolved metals from solution. Then a clarifier would precipitate and separate solids. These first two stages of the treatment process now proposed comprise the whole of the treatment process originally proposed. (RT. 149-50, 185-68; AES Ex. 4R) Additional treatment, as needed, would include sand filtering, to eliminate the need for any turbidity mixing zone (RT. 151, 190, 198, 201; AES Ex. 4R); using a carbon filter to remove organic compounds (and some heavy metals), obviating the need for a phenol mixing zone (RT. 190-191, 198, 201; AES Ex. 4R); and, finally, selective ion exchange, to provide additional metals removal, if needed. (RT. 151, 191, 201-02; AES Ex. 4R) The applicants are to ascertain and report the quality of effluent as long as dewatering takes place. They must use a composite sampling method once a week for the first month. Thereafter they may use a single "grab" sample, but must continue assessing effluent quality once a week until dewatering ceases. The proposed monitoring program must be capable of detecting whether water quality standards are being met. (RT. 166, 195, 321-22; AES Ex. 4R). The applicants' modified dewatering plan is an environmental improvement over the previous plan and would ensure compliance with water quality standards. (RT. 193, 196, 261) DER has recommended and the applicants have agreed to accept modified Conditions III.A.12. (Construction dewatering), III.A.13 (Mixing Zones), and III.A.14. (Variances to Water Quality Standards). (RT. 152; AES Ex. SR as modified by the Joint Recommended Order filed November 1990). Based upon the applicants' modified dewatering plan, a reasonable allocation of water for construction dewatering is a maximum daily withdrawal not to exceed .288 million gallons. Modified Condition V.D. is reasonable and the applicants accept its terms. (RT. 254, 294-295; SJRWMD Ex. IR) Water for Cooling Purposes The applicants now propose to use either reclaimed water or river water for cooling, to the extent practicable, in an effort to avoid using groundwater as the permanent, primary source of cooling water. September drought conditions caused record low readings for the Floridan aquifer at 23 monitoring wells in the northern part of the St. Johns River Water Management "District, including wells in Duval County." RT. 248. The original proposal called for withdrawing four million gallons of water a day from the Floridan aquifer for cooling, when power generation begins. Under the modified proposal, groundwater would still be used as makeup for the steam or power generation system, as service water, and for potable purposes, but (except in emergencies) not for cooling, assuming the applicants obtain the regulatory approval they would be obliged to seek. The applicants have agreed to accept modified Condition XXV (Use of Water for Cooling Purposes). (RT. 155-158, 204-208; AES Ex. 6R, 12R, 13R) Condition IV.C. has been modified to reflect the reduced withdrawal of groundwater that would be necessary if groundwater is not used for cooling. For the next seven years, a maximum annual withdrawal from the Floridan aquifer for non- cooling uses of no more than 530.7 million gallons and a maximum daily withdrawal of no more than 1.45 million gallons represent amounts that are considered reasonably necessary and efficient. Unless the City of Jacksonville has agreed, on or before December 1, 1990, to supply reclaimed water for cooling, the applicants will redesign the cooling system so that river water can be used for cooling. Salt in the Broward and St. Johns rivers requires the use of highly corrosion-resistant materials for certain system components. Constructing these system components with such materials would enable the cooling system to use river water, reclaimed water from the City, or Seminole Kraft wastewater. (RT. 155-56, 159-60, 216-17; AES Ex. 6R). If river water is used, existing Seminole Kraft intake and discharge structures would be utilized. In order to reduce ill effects on aquatic organisms, the applicants would install screening and filter systems upstream of the pumps. Brackish river water must be changed or "cycled" more often than groundwater, lest evaporation cause scaling that would clog the system. The volume of river water required for cooling tower makeup is estimated at approximately 14 million gallons per day. Because cooling with river water would require more water, the applicants propose to increase piping and valve sizes for the cooling system. (RT. 155-57, 168, 215-16, 219-20; AES Ex. 6R) Modified Condition XXV specifies a procedure for amending site certification to require use of one of two primary cooling water sources: reclaimed water from the City or surface water from the Broward or St. Johns rivers. The applicants have agreed to apply within six months for modifications concerning design and operation of the plant cooling system. The application must contain information necessary to demonstrate that operation of the cooling system without using groundwater as the primary cooling water source would comply with all relevant non-procedural agency standards or qualify for a variance. The application must also detail the reasons for selection of one requested source over other possible sources. There would be no delegation to DER's Secretary for determinations under Condition XXV. Final authority to render determinations under Condition XXV would remain with the Siting Board. (RT. 207, 269; SJRWMD Ex. 2R) As drafted by the parties, modified proposed Condition xxv provides that groundwater may be utilized for cooling only in the event that neither river water nor reclaimed water from the City of Jacksonville obtains necessary environmental approvals of the preferred primary cooling sources are denied on the grounds of unavailability, or environmental or economic impracticability, as set forth in the condition. (RT. 207, 228-30; AES Ex. 12R) The applicants modified cooling system plans and modified Condition XXV, as drafted by the parties, are designed to ensure that the cooling system will use either river water or reclaimed water, to the extent it is economically and environmentally practicable. Use of either of these sources for this proposed cooling facility is viewed by the SJRWMD as equally appropriate to fulfill its conservation and reuse standards and the state water policy, which require consumptive users to utilize, to the extent practicable, the lowest quality water suitable for the proposed use. (RT. 242-43, 299-300) The applicants have stipulated that it is economically feasible and practicable for them to pay $.18-1/2 per thousand gallons for reclaimed water without phosphorous treatment or $.22 per thousand gallons for treated reclaimed water, unless expenditures have already been made to construct the cooling system to utilize river water. They also stipulated that the river water cooling option is economically feasible and practicable, if the facility is authorized to operate with the same type of cooling tower discharge operation variances granted to the St. Johns River Power Park. (RT. 206, 218, 245, 295j AES Ex. 12R) The St. Johns River Power Park, a power plant in Duval County which was certified under the Florida Electrical Power Plant Siting Act, utilizes river water for cooling tower makeup and discharges its cooling tower blowdown into the St. Johns River. When river water is used for cooling, evaporation increases concentrations of pollutants already in the river. The St. Johns River Power Park's certification conditions include variances from Class III water quality standards which allow the facility to operate its cooling system with river water. These variances have been granted for two-year periods, with the permittee being required to obtain variance renewals every two years in order to continue operation of the cooling system. (RT. 206, 218-19, 288-89). Salt drift as well as concentrations of pollutants in the blowdown are being assessed. RT. 284. Use of Seminole Kraft's current wastewater is not mentioned in modified Condition XXV, as drafted by the parties. By the time the Cedar Bay cogeneration facility needs cooling water, the Seminole Kraft plant may have become a cardboard recycling facility, which would discharge a different and potentially more useful wastewater than is currently being discharged by Seminole Kraft. The precise quality of any such future effluent cannot be predicted with a high degree of certainty at this time. (RT. 222-23, 238-43) But the applicants should "evaluate the practicability under [SJRWMD] rules of utilizing Seminole Kraft wastewater . . . [using] the best information . . . available," (RT. 243) during the post- certification proceeding new Condition XXV calls for, at least if reclaimed water is unavailable from the City of Jacksonville. If a primary source of cooling water other than groundwater proves unavailable or environmentally or economically impractical, as set out in modified Condition XXV, a maximum annual withdrawal from the Floridan aquifer for all facility uses not to exceed 1,990 million gallons and a maximum daily withdrawal not to exceed seven million gallons are reasonable for a period of seven years. (RT. 211,12, 296-97; AES Ex. 14R) In the event groundwater became the primary cooling source, proposed Condition xxv would require the applicants to implement their groundwater mitigation plan. (RT. 207, 229-30; AES Ex. 12R). Under this plan, the applicants would fund a free- flowing well inventory in Duval County. Additionally, they would provide a contribution of $380,000 per year for plugging free- flowing wells to reduce discharges from these wells by seven million gallons a day, if discharges of such magnitude are found. Thereafter, the applicants' annual contributions, which are to continue as long as groundwater is used for cooling, would fund a water conservation and reuse grants program in Duval County. The plan represents not only a water conservation measure but also serves as an economic incentive to the applicants to pursue necessary approvals for use of another primary cooling water source. Overall Evaluation Hamilton S. Oven, Jr. testified without contradiction that the project as now proposed "would produce minimal adverse effects on human health . . . the environment the ecology of the land and its wildlife . . . [and] the ecology of state waters and their aquatic life." RT.277. He also testified that the applicants' proposal would comply "with relevant agency standards." (RT.273) (although the evidence showed variances would be needed for cooling tower blowdown, at least if reclaimed water is not used.) Mr. Oven explained that he used permitting agencies' "criteria as a measuring stick to show compliance and to try to produce the minimal adverse impacts as allowed by regulatory policy." RT.274. Like Mr. Oven, Stephen Smallwood, Director of DER's Division of Air Resources Management interprets "minimal" as used in the Florida Electric Power Plant Siting Act to mean "minimal with respect to the standards of the agencies." DER's Exhibit No. 2R, P. 11. Otherwise, he explained, "[Y]ou'd have to perhaps conclude . . . that you couldn't license any coal-fired units [. T]hey'd either all have to be natural-gas fired or . . . nuclear or . . . solar." Id. DER staff concluded that the proposed Cedar Bay Cogeneration Project effects a reasonable balance between the need for the project and the environmental impacts associated with the project. On this basis, DER recommended that the project be certified subject to recommended conditions of certification.
Recommendation It is, accordingly, RECOMMENDED: That the Siting Board grant the site certification application filed by AES Cedar Bay, Inc. and Seminole Kraft Corporation, as amended, subject to the agreed conditions of certification attached to the recommended order as an appendix, and on condition that the facility use reclaimed wastewater as cooling tower make-up within seven years of beginning operation. DONE and ENTERED this 29th day of May, 1990, in Tallahassee, Leon County, Florida. ROBERT T. BENTON, II Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 29th day of May, 1990. APPENDIX CONDITIONS OF CERTIFICATION When a condition is intended to refer to both AES Cedar Bay, Inc. and Seminole Kraft Corp., the term "Cedar Bay Cogeneration Project or the abbreviation "CBCP" or the term "permittees" will be used. Where a condition applies only to AES Cedar Bay, Inc. the term "AES Cedar Bay, Inc." or the abbreviation "AESCB" or the term "permittee," where it is clear that AESCB is the intended responsible party, will be used. Similarly, where a condition applies only to Seminole Kraft Corp., the term "Seminole Kraft Corp." or the abbreviation "SK" or the term "permittee," where it is clear that SK is the intended responsible party, will be used. The Department of Environmental Regulation may be referred to as DER or the Department. BESD represents the City of Jacksonville, Bio-Environmental Services Division. SJRWMD represents the St. Johns River Water Management District. GENERAL The construction and operation of CBCP shall be in accordance with all applicable provisions of at least the following regulations of the Department Chapters 17-2, 17-3, 17-4, 17-5, 17-6, 17-7, 17-12, 17-21, 17-22, 17-25 and 17-610, Florida Administrative Code (F.A.C.) or their successors as they are renumbered. AIR The construction and operation of AESCB shall be in accordance with all applicable provisions of Chapters 17-2, F.A.C. In addition to the foregoing, AESCB shall comply with the following condition of certification as indicated. Emission Limitations for AES Boilers Fluidized Bed Coal Fired Boilers (CFB) The maximum coal charging rate of each CFB shall neither exceed 104,000 lbs/hr, 39,000 tons per month (30 consecutive days, nor 390,000 tons per year (TPY). This reflects a combined total of 312,000 lbs/hr, 117,000 tons per month, and 1,170,000 TPY for all three CFBs. The maximum wood waste (primarily bark) charging rate to the No. 1 and No. 2 CFBs each shall neither exceed 15,653 lbs/hr, nor 63,760 TPY. This reflects a combined total of 31,306 lbs/hr, and 127,521 TPY for the No. 1 and No. 2 CFBs. The No. 3 CFB will not utilize woodwaste, nor will it be equipped with wood waste handling and firing equipment. The maximum heat input to each CFB shall not exceed 1063 MMBtu/hr. This reflects a combined total of 3189 MMBtu/hr for all three units. The sulfur content of the coal shall not exceed 1.7% by weight on an annual basis. The sulfur content shall not exceed 3.3% by weight on a shipment (train load) basis. Auxiliary fuel burners shall be fueled only with natural gas or No. 2 fuel oil with a maximum sulfur content of 0.3% by weight. The fuel oil with a maximum sulfur content of 0.3% by weight. The fuel oil or natural gas shall be used only for startups. The maximum annual oil usage shall not exceed 160,000 gals/year, nor shall the maximum annual natural gas usage exceed 22.4 MMCF per year. The maximum heat input from the fuel oil or gas shall not exceed 1120 MMBtu/hr for the CFBs. The CFBs shall be fueled only with the fuels permitted in Conditions 1a., 1b and 1e above. Other fuels or wastes shall not be burned without prior specific written approval of the Secretary of DER pursuant to condition XXI, Modification of Conditions. The CFBs may operate continuously, i.e. 8760 hrs/yr. Coal Fired Boiler Controls The emissions from each CFB shall be controlled using the following systems: Limestone injection, for control of sulfur dioxide. Baghouse, for control of particulate. Flue gas emissions from each CFB shall not exceed the following: Pollutant lbs/MMBtu Emission lbs/hr Limitations TPY TPY for 3 CFBs CO 0.19 202 823 2468 NOx 0.29 308.3 1256 3767 SO2 0.60(3-hr avg.) 637.8 -- -- 0.31(12 MRA) 329.5 1338 4015 VOC 0.016 17.0 69 208 PM 0.020 21.3 87 260 PM10 0.020 21.3 86 257 H2SO4mist 0.024 25.5 103 308 Fluorides 0.086 91.4 374 1122 Lead 0.007 7.4 30 91 Mercury 0.00026 0.276 1.13 3.4 Beryllium 0.00011 0.117 0.5 1.5 Note: TPY represents a 93% capacity factor. MRA refers to a twelve month rolling average. Visible emissions (VE) shall not exceed 20% capacity (6 min. average), except for one 6 minute period per hour when VE shall not exceed 27% capacity. Compliance with the emission limits shall be determined by EPA reference method tests included in the July 1, 1988 version of 40 CFR Parts 60 and 61 and listed in Condition No. 7 of this permit or be equivalent methods after prior DER approval. The CFBs are subject to 40 CFR Part 60, Subpart Da; except that where requirements within this certification are more restrictive, the requirements of this certification shall apply. Compliance Tests for each CFB Initial compliance tests for PM/PM10, SO2, NOx, CO, VOC, lead, fluorides, mercury, beryllium and H2SO4 mist shall be conducted in accordance with 40 CFR 60.8 (a), (b), (d), (e), and (f). Annual compliance tests shall be performed for PM. SO2, NOx, commencing no later than 12 months from the initial test. Initial and annual visible emissions compliance tests shall be determined in accordance with 40 CFR 60.11(b) and (e). The compliance tests shall be conducted between 90-100% of the maximum licensed capacity and firing rate of each permitted fuel. The following test methods and procedures of 40 CFR Parts 60 and 61 or other DER approved methods with prior DER approval shall be used for compliance testing: Method 1 for selection of sample site and sample traverses. Method 2 for determining stack gas flow rate. Method 3 or 3A for gas analysis for calculation of percent O2 and CO2. Method 4 for determining stack gas moisture content to convert the flow rate from actual standard cubic feet to dry standard cubic feet. Method 5 or Method 17 for particulate matter. Method 6, 6C, or 8 for SO2. Method 7, 7A, 7B, 7C, 7D, or 7E for nitrogen oxides. Method 8 for sulfuric acid mist. Method 9 for visible emissions, in accordance with 40 CFR 60.11. Method 10 for CO. Method 12 for lead. Method 13B for fluorides. Method 25A for VOCs. Method 101A for mercury. Method 104 for beryllium. Continuous Emission Monitoring for each CFB AESCB shall use Continuous Emission Monitors (CEMS) to determine compliance. CEMS for opacity, SO2, NOx, CO, and O2 or CO2, shall be installed, calibrated, maintained and operated for each unit, in accordance with 40 CFR 60.47a and 40 CFR 60 Appendix F. Each continuous emission monitoring system (CEMS) shall meet performance specifications of 40 CFR 60, Appendix B. CEMS data shall be recorded and reported in accordance with F.A.C. Chapter 17-2, F.A.C., and 40 CFR 60. A record shall be kept for periods of startup, shutdown and malfunction. A malfunction means any sudden and unavoidable failure of air pollution control equipment or process equipment to operate in a normal or usual manner. Failures that are caused entirely or in part by poor maintenance, careless operation or any other preventable upset condition or preventable equipment breakdown shall not be considered malfunctions. The procedures under 40 CFR 60.13 shall be followed for installation, evaluation and operation of all CEMS Opacity monitoring system data shall be reduced to 6-minute averages, based on 36 or more data points, and gaseous CEMS data shall be reduced to 1-hour averages, based on 4 or more data points, in accordance with 40 CFR 60.13(h). For purposes of reports required under this certification, excess emissions are defined as any calculated average emission concentration, as determined pursuant to Condition No. 10 herein, which exceeds the applicable emission limit in Condition No. 3. Operations Monitoring for each CFB Devices shall be installed to continuously monitor and record steam production, and flue gas temperature at the exit of the control equipment. The furnace heat load shall be maintained between 70% and 100% of the design rated capacity during normal operations. The coal, bark, natural gas and No. 2 fuel oil usage shall be recorded on a 24-hr (daily) basis for each CFB. Reporting for each CFB A minimum of thirty (30) days prior notification of compliance test shall be given to DER's N.E. District office and to the BESD (Bio-Environmental Services Division) office, in accordance with 40 CFR 60. The results of compliance test shall be submitted to the BESD office within 45 days after completion of the test. The owner or operator shall submit excess emission reports to BESD, in accordance with 40 CFR 60. The report shall include the following: The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h), any conversion factors used, and the date and time of commencement and completion of each period of excess emissions (60.7(c)(1)). Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the furnace boiler system. The nature and cause of any malfunction (if known) and the corrective action taken or preventive measured adopted (60.7(c)(2)). The date and time identifying each period during which the continuous monitoring system was inoperative except for zero and span checks, and the nature of the system repairs of adjustments (60.7(c)(3)). When no excess emissions have occurred or the continuous monitoring system has not been inoperative, repaired, or adjusted, such information shall be stated in the report (60.7(c)(4)). The owner or operator shall maintain a file of all measurements, including continuous monitoring systems performance evaluations; monitoring systems or monitoring device calibration; checks; adjustments and maintenance performed on these systems or devices; and all other information required by this permit recorded in a permanent form suitable for inspection (60.7(d)). Annual and quarterly reports shall be submitted to BESD as per F.A.C. Rule 17-2.700(7). Any change in the method of operation, fuels utilized, equipment, or operating hours or any other changes pursuant to F.A.C. Rule 17-2.100, defining modification, shall be submitted for approval to DER's Bureau of Air Regulation. AES - Material Handling and Treatment The material handling and treatment operations may be continuous, i.e. 8760 hrs/yr. The material handling/usage rates shall not exceed the following: Handling/Usage Rate Material TPM TPY Coal 117,000 1,170,000 Limestone 27,000 320,000 Fly Ash 28,000 336,000 Bed Ash 8,000 88,000 Note: TPM is tons per month based on 30 consecutive days, TPY is tons per year. The VOC emissions from the maximum No. 2 fuel oil utilization rate of 240 gals/hr, 2,100,000 gals/year for the limestone dryers; and 8000 gals/hr, 160,000 gals/year for the three boilers are not expected to be significant. The maximum emissions from the material handling and treatment area, where baghouses are used as controls for specific sources, shall not exceed those listed below (based on AP-42 factors): Particulate Emissions Source lbs/hr TPY Coal Rail Unloading Coal Belt Feeder neg neg neg neg Coal Crusher 0.41 1.78 Coal Belt Transfer neg neg Coal Silo neg neg Limestone Crusher 0.06 0.28 Limestone Hopper 0.01 0.03 Fly Ash Bin 0.02 0.10 Bed Ash Hopper 0.06 0.25 Ash Silo 0.06 0.25 Common Feed Hopper 0.03 0.13 Ash Unloader 0.01 0.06 The emissions from the above listed sources and the limestone dryers are subject to the particulate emission limitation requirement of 0.03 gr/dscf. However, neither DER nor BESD will require particulate tests in accordance with EPA Method 5 unless the VE limit of 5% opacity is exceeded for a given source, or unless DER or BESD, based on other information, has reason to believe the particulate emission limits are being violated. Visible Emissions (VE) shall not exceed 5% opacity from any source in the material handling and treatment area, in accordance with F.A.C. Chapter 17-2. The maximum emissions from each of the limestone dryers while using oil shall not exceed the following (based on AP-42 factors, Table 1, 3-1, Industrial Distillate, 10/86): Pollutant lbs/hr Estimated TPY Limitations TPY for 2 dryers PM/PM10 0.25 1.1 2.2 SO2 5.00 21.9 43.8 CO 0.60 2.6 5.2 NOx 2.40 10.5 21.0 VOC 0.05 0.2 0.4 Visible emissions from the dryers shall not exceed 5% opacity. If natural gas is used, emissions limits shall be determined by factors contained in AP-42 Table 1. 4-1, Industrial 10/86. The maximum No. 2 fuel oil firing rate for each limestone dryer shall not exceed 120 gals/hr, or 1,050,000 gals/year. This reflects a combined total fuel oil firing rate of 240 gals/hr, and 2,100,000 gals/year, for the two dryers. The maximum natural gas firing rate for each limestone dryer shall not exceed 16,800 CF per hour, or 147 MMCF per year. Initial and annual Visible Emission compliance tests for all the emission points in the material handling and treatment area, including but not limited to the sources specified in this permit, shall be conducted in accordance with the July 1, 1988 version of 40 CFR 60, using EPA Method 9. Compliance test reports shall be submitted to BESD within 45 days of test completion in accordance with Chapter 17- 2.700(7) of the Florida Administrative Code. Any changes in the method of operation, raw materials processed, equipment, or operating hours or any other changes pursuant to F.A.C. Rule 17-2.100, defining modification, shall be submitted for approval to DER's Bureau of Air Regulation (BAR). Requirements for the Permittees Beginning one month after certification, AESCB shall submit to BESD and DER's BAR, a quarterly status report briefly outlining progress made on engineering design and purchase of major equipment, including copies of technical data pertaining to the selected emission control devices. These data should include, but not be limited to, guaranteed efficiency and emission rates, and major design parameters such as air/cloth ratio and flow rate. The Department may, upon review of these data, disapprove the use of any such device. Such disapproval shall be issued within 30 days of receipt of the technical data. The permittees shall report any delays in construction and completion of the project which would delay commercial operation by more than 90 days to the BESD office. Reasonable precautions to prevent fugitive particulate emissions during construction, such as coating of roads and construction sites used by contractors, regrassing or watering areas of disturbed soils, will be taken by the permittees. Fuel shall not be burned in any unit unless the control devices are operating properly, pursuant to 40 CFR Part 60 Subpart Da. The maximum sulfur content of the No. 2 fuel oil utilized in the CFBs and the two unit limestone dryers shall not exceed 0.3 percent by weight. Samples shall be taken of each fuel oil shipment received and shall be analyzed for sulfur content and heating value. Records of the analysis shall be kept a minimum of two years to be available for DER and BESD inspection. Coal fired in the CFBs shall have a sulfur content not to exceed 3.3 percent by weight. Coal sulfur content shall be determined and recorded in accordance with 40 CFR 60.47a. AESCB shall maintain a daily log of the amounts and types of fuel used and copies of fuel analysis containing information on sulfur content and heating values. The permittees shall provide stack sampling facilities as required by Rule 17-2.700(4) F.A.C. Prior to commercial operation of each source, the permittees shall each submit to the BAR a standardized plan or procedure that will allow that permittee to monitor emission control equipment efficiency and enable the permittee to return malfunctioning equipment to proper operation as expeditiously as possible. Contemporaneous Emission Reductions This certification and any individual air permits issued subsequent to the final order of the Board certifying the power plant site under 403.509, F.S., shall require, that the following Seminole Kraft Corporation sources be permanently shut down and made incapable of operation, and shall turn in their operation permits to the Division of Air Resources Management's Bureau of Air Regulation, at the time of submittal of performance test results for AES's CFBs: the No. 1 PB (power boiler), the No. 2 PB, shall be specifically informed in writing within thirty days after each individual shut down of the above reference equipment. This requirement shall operate as a joint and individual requirement to assure common control for purpose of ensuring that all commitments relied on are in fact fulfilled. WATER DISCHARGES Any discharges into any waters of the State during construction and operation of AESCB shall be in accordance with all applicable provisions of Chapters 17-3, and 17-6, Florida Administrative Code, and 40 CFR, Part 423, Effluent Guidelines and Standards for Steam Electric Power Generating Point Source Category, except as provided herein. Also, AESCB shall comply with the following conditions of certification: Plant Effluents and Receiving Body of Water For discharges made from the AESCB power plant the following conditions shall apply: Receiving Body of Water (RBW) - The receiving body of water has been determined by the Department to be those waters of the St. Johns River or Broward River and any other waters affected which are considered to be waters of the State within the definition of Chapter 403, Florida Statutes. Point of Discharge (POD) - The point of discharge has been determined by the Department to be where the effluent physically enters the waters of the State in the St. Johns River via the SKC discharge outfall 001, which is the existing main outfall from the paper mill emergency overflow to the Broward River. Thermal Mixing Zones - The instantaneous zone of thermal mixing for the AESCB cooling system shall not exceed an area of 0.25 acres. The temperature at the point of discharge into the St. Johns River shall not be greater than 95 degrees F. The temperature of the water at the edge of the mixing zone shall not exceed the limitations of Section 17-3.05(1)(d), F.A.C. Cooling tower blowdown shall not exceed 95 degrees F as a 24-hour average, nor 96 degrees F as an instantaneous maximum. Chemical Wastes from AESCB - All discharges of low volume wastes (demineralizer regeneration, floor drainage, labs drains, and similar wastes) and chemical metal cleaning wastes shall comply with Chapter 17-6, F.A.C. at OSN 006 and 007 respectively. If violations of Chapter 17-6 F.A.C. occur, corrective action shall be taken by AESCB. These wastewaters shall be directed to an adequately sized and constructed treatment facility. pH - The pH of the combined discharges shall be such that the pH will fall within the range of 6.0 to 9.0 at the POD to the St. Johns River and shall not exceed 6.5 to 8.5 at the boundary of a 0.25 acre mixing zone. Polychlorinated Bipheny Compounds - There shall be no discharge of polychlorinated bipheny compounds. Cooling Tower Blowdown - AESCB's discharge from Outfall Serial Number 002 - Cooling Tower Blowdown shall be limited and monitored as specified below: a. Parameter Discharge Limit Monitoring Frequency Requirement Type Discharge Flow (mgd) Report 1/day Totalizer Discharge Temp (F) Instantaneous Maximum Continuous Recorder Total Residual Instantaneous Continuous Recorder Oxidants Maximum-.05 mg/l Time of Total 120 minutes Continuous Recorder Residual Oxidant per day Discharge (TR) Iron Instantaneous 1/week grab Maximum-0.5 mg/l pH 6-9 1/week grab There shall be no detectable discharge of the 125 priority pollutants contained in chemicals added for cooling tower maintenance. Notice of any proposed use of compounds containing priority pollutants shall be made to the DER Northeast District Office not later than 180 days prior to proposed use. Samples taken in compliance with the monitoring requirements specified above shall be taken at OSN 002 prior to mixing with any other waste stream. Seminole Kraft Corporation (SKC) shall shut down the mill's once thru cooling system upon completion of the initial compliance tests on the AESCB boilers conducted pursuant to Condition II.A.7. SKC shall inform the DER NE District Office of the shutdown and surrender all applicable operating permits for that facility. Combined Low Volume Wastes shall be monitored at OSN 006 with weekly grab samples. Discharge limitations are as follows: Daily Max Daily Avg Oil and Grease 20.0 mg/l 15.0 Copper-dissolved 1.0 mg/l* N/A Iron-dissolved 1.0 mg/l* N/A Flow Report N/A Heavy Metals Report (See Below) The pH of the discharge shall not be less than 7.0* standard units and shall be monitored once per shift, unless more frequent monitoring is necessary to quantify types of nonchemical metal cleaning waste discharged. Serial number assigned for identification and monitoring purposes. Heavy metal analysis shall include total copper, iron, nickel, selenium, and zinc. *Limits applicable only to periods in which nonchemical metal cleaning waste is being discharged via this OSN. Length of composite samples shall be during the periods (s) of nonchemical metal cleaning waste generation and discharge and shall be adequate to quantify differences in sources of waste generated (air preheater vs. boiler fireside, etc.). Chemical Metal Cleaning AESCB's discharge from outfall serial number 007 - metal cleaning wastes discharged to the Seminole Kraft treatment system. Such discharges shall be limited and monitored by the permittee as specified below: a. Effluent Characteristic Discharge Limits Monitoring Requirements Instantaneous Max Measurement Frequency Sample Type Flow - m3/day (MGD) - 1/batch Pump log Copper, Total 1.0 mg/l 1/ grab Iron, Total Batches 1.0 mg/l Report 1/ 1/batch grab logs Chemical metal-cleaning wastes shall mean process equipment cleaning including, but not limited to, boiler tubes cleaning. Waste treated and discharged via this OSN shall not include any stream for which an effluent guideline has not been established (40 CFR Part 423) for total copper and total iron at the above levels. Samples taken in compliance with the monitoring requirement specified above shall be taken at the discharge from the metal-cleaning waste treatment facility(s) prior to mixing with any other waste stream. Storm Water Runoff - During construction and operation discharge from the storm water runoff collection system from a storm event less than the once in ten year twenty-four hour storm shall meet the following limits and shall be monitored at OSN 003 by a grab sample once per discharge, but not more often than once per week:* Discharge Limits Effluent Characteristic Instantaneous Maximum Flow (MGD) Report TSS (mg/l) 50 pH 6.0-9.0 During plant operation, necessary measures shall be used to settle, filter, treat or absorb silT.containing or pollutanT.laden storm water runoff to limit the suspended solids to 50 mg/l or less at OSN 003 during rainfall periods less than the 10-year, 24-hour rainfall. Any underdrains must be checked annually and measures must be taken to insure that the underdrain operates as designed. Permittees will have to modify the underdrain system should maintenance measures be insufficient to achieve operation of the underdrains as designed. AES Cedar Bay must back flush the exfiltration/underdrain system at least once during the first six months of calendar each year. These backflushings must occur no closer than four calendar months from each other. In advance of backflushing the exfiltration/underdrain systems, the permittees must notify BESD and SJRWMD of the date and time of the backflushing. Control measures shall consist at the minimum of filters, sediment, traps, barriers, berms or vegetative planting. Exposed or disturbed soil shall be protected as soon as possible to minimize silt, and sedimenT.laden runoff. The pH shall be kept within the range of 6.0 to 9.0 in the discharge to the St. Johns River and 6.5 to 8.5 in the Broward River. Special consideration must be given to the control of sediment laden runoff resulting from storm events during the construction phase. Best management practices erosion controls should be installed early during the construction period so as to prevent the transport of sediment into surface waters which could result in water quality violations and Departmental enforcement action. Revegetation and stabilization of disturbed areas should be accomplished as soon as possible to reduce the potential for further soil erosion. Should construction phase runoff pose a threat to the water quality of state waters, additional measures such as treatment of impounded runoff of the use of turbidity curtains (screens) in on-site impoundments shall be immediately implented with any releases to state waters to be controlled. It is necessary that there be an entity responsible for maintenance of the system pursuant to Section 17- 25.027, F.A.C. Correctional action or modification of the system will be necessary should mosquito problems occur. AES Cedar Bay shall submit to DER with copy to BESD, erosion control plans for the entire construction project (or discrete phrases of the project) detailing measures to be taken to prevent the offsite discharge of turbid waters during construction. These plans must also be provided to the construction contractor prior to the initiation of construction. All swale and retention basin side slopes shall be seeded and mulched within thirty days following their completion and a substantial vegetative cover must be established within ninety days of seeding. Boiler Blowdown Discharge from boiler blowdown to the cooling tower from outfall serial Number 004 shall be limited and monitored as specified below: Effluent Discharge Limits Monitoring Characteristic Requirements Daily Sample Measurement Maximum Type Frequency TSS 30.0 grab 1/Quarter Oil and Grease 15.0 grab 1/Quarter Flow - Calculation 1/Quarter Construction Dewatering Discharge of construction dewatering to the SKC once-through cooling system from outfall serial number 005 shall be limited and monitored as specified below: Effluent Characteristic Discharge Limits Monitoring Requirements Instantaneous Maximum Measurement Frequency Sample Type Flow - m3/day (MGD) - daily Totalizer Turbidity (NTU) 164 1/week grab Aluminium mg/l 1.5 1/week grab Copper mg/l 0.046 daily composite Iron mg/l 0.3 1/week grab Lead mg/l 0.5 1/week grab Mercury mg/l 0.002 1/week grab Phenol ug/l 35.7 daily grab TSS mg/l 50.0 1/week grab pH 6.0-9.0 1/week grab Variance - In accordance with the provisions of Section 403.201 and 403.511(2), F.S., AES Cedar Bay is hereby granted a variance to water quality standards of Chapter 17- 3.121, F.A.C. for copper subject to the following conditions. AES Cedar Bay shall treat the construction dewatering discharge so as not to exceed 0.046 milligrams per liter for copper in the effluent from the dewatering treatment system. AES Cedar Bay shall do sufficient bench testing to demonstrate that it can meet the above limit for copper. AES Cedar Bay shall notify DER and BESD of the bench testing, and allow DER and BESD to be present if they so desire to observe the bench testing. In addition, AES Cedar Bay shall determine the amount of treatment and removal provided for iron, aluminum and lead by the method of treatment selected for copper. A report shall be submitted to DER and BESD summarizing the results of the bench testing of the proposed treatment technique. The variance shall be valid beginning with the start of dewatering and lasting until the end of construction dewatering but not to exceed a period of two years (not including periods of interruption in the construction dewatering). The Secretary has been delegated the authority to grant additional variances or mixing zones from water quality standards should AES Cedar Bay demonstrate any to be necessary after consideration of comments from the parties, public notice and an opportunity for hearing, pursuant to section 120.57 F.S., with final action by the Siting Board if a hearing is requested. In the absence of such final action by the Secretary, compliance with water quality standards shall be measured at the designated POD to the St. John River unless a zone of mixing is granted. Project discharge descriptions - Dewatering water, outfall 005, includes all surficial groundwater extracted during all excavation construction on site for the purpose of installing structures, equipment, etc. Discharges to the SKC once through cooling water system at a location to be depicted on an appropriate engineering drawing to be submitted to DER and BESD. Final discharge after treatment is to the St. Johns River. The permittee shall report to BESD the date that construction dewatering is expected to begin at least one week prior to the commencement of dewatering. Mixing zones - The discharge of the following pollutants shall not violate the Water Quality Standards of Chapter 17-3, F.A.C., beyond the edge of the designated instantaneous mixing zones as described herein. Such mixing zones shall apply when the St. Johns River is in compliance with the applicable water quality standard. Plant Dewatering Operations for two years from the date construction dewatering commences: Parameter Mixing Zone Aluminum 125,600 m2 31 acres Copper " 31 " Iron " 31 " Lead " 31 " Turbidity 12,868 m2 3.2 " Phenol 12,868 " 3.2 " The permittee shall report the date construction dewatering commences to the BESD. During operation of CBCP for the life of the facility: Iron 125,600 m2 (31 acre) mixing zone Chlorine 0 - not measurable in river Temp 1,013 m2 (0.25 acre) pH 1,013 m2 (0.25 acre) Variances to Water Quality Standards - In accordance with the provisions of Sections 403.201 and 403.511(2), F.S., permittees are hereby granted variances to the water Quality Standards of Chapter 17-3.121, F.A.C. for the following: During construction dewatering for a period not to exceed two years -- copper. The Secretary of DER may authorize variances for aluminum, iron, and lead upon a showing that treatment for copper can not bring these metals into compliance, however, any variance granted shall not cause or allow an exceedance of acute toxicity standards. During Operation -- iron. Such variances shall apply only as the natural background levels of the St. Johns River approach or exceed those standards. In any event, the discharge from the CBCP shall comply with the effluent limitations set forth in Paragraph III.A.12. At least 90 days prior to start of construction, AES shall submit a bioassay program to assess the toxicity of construction dewatering effluent to the DER for approval. Such program shall be approved prior to start of construction dewatering. Sanitary wastes from AESCB shall be collected and discharged for treatment to the SKC domestic wastewater treatment plant. Water Monitoring Programs Necessity and extent of continuation, and may be modified in accordance with Condition No. XXI, Modification of Conditions. Chemical Monitoring - The parameters described in Condition III.A. shall be monitored during discharge as described in condition III A. commencing with the start of construction or operation of the CFBs and reported quarterly to the Northeast District Office: Coal, Ash, and Limestone Storage Areas - runoff from the coal pile, ash and lime stone storage areas shall be directed to the SK waste-water treatment facility for discharge under its existing waste-water permit. Monitoring of metals, such as iron, copper, zinc, mercury silver, and aluminum, shall be done once a month during any month when a discharge occurs at OSC 008 or once per month from the collection pond. The ground water levels shall be monitored continuously at selected wells as approved by the SJRWMD. Chemical analysis shall be made on samples from all monitored wells identified in Condition III.F. below. The location, frequency and selected chemical analysis shall be as given in Condition IV.F. The ground water monitoring program shall be implemented at least one year prior to operation of the CFBs. The chemical analysis shall be in accord with the latest edition of Standard Methods for the Analysis of Water and Waistwater. The data shall be submitted within 30 days of collection/analysis to the SJRWMD. GROUND WATER Prior to the construction, modification, or abandonment of a production well for the SK paper mill, the Seminole Kraft must obtain a Water Well Construction Permit from the SJRWMD pursuant to Chapter 40C-3, Florida Administrative Code. Construction, modification, or abandonment of a production well will require modification of the SK consumptive use permit when such construction, modification or abandonment is other than that specified and described on SK's consumptive use permit application form. The construction, modification, or abandonment of a monitor well specified in condition IV.H. will require the prior approval of the Department. All monitor wells intended for use over thirty days must be noticed to BESD prior to construction or change of status from temporary to permanent. Well Criteria, Tagging and Wellfield Operating Plan Leaking or inoperative well casings, valves, or controls must be repaired or replaced as required to put the system back in an operative condition acceptable to the SJRWMD. Failure to make such repairs will be cause for deeming the well abandoned in accordance with Chapter 17.21.02(5), Florida Administrative Code, Chapter 373.309, Florida Statutes and Chapter 366.301(b), and .307(a), Jacksonville ordinance code. Wells deemed abandoned will require plugging according to state and local regulations. A SJRWMD issued identification tag must be prominently displayed at each withdrawal site by permanently affixing such tag to the pump, headgate, valve or other withdrawal facility as provided by Section 40C-2.401, Florida Administrative Code. The SK must notify the SJRWMD in the event that a replacement tag is needed. The permittees must develop and implement a Wellfield Operating Program within six (6) months of certification. This program must describe which wells are primary, secondary, and standby (reserve); the order of preference for using the wells; criteria for shutting down and restarting wells; describe AES Cedar Bay and SKC responsibilities in the operation of the well field, and any other aspects of well field management operation, such as who the well field operator is and any other aspects of wellfield management operation. This program must be submitted to the SJRWMD and a copy to BESD within six (6) months of certification and receive District approval before the wells may be used to supply water for the AES Cedar Bay Cogeneration plant. Maximum Annual Withdrawals Maximum annual withdrawals for AESCB from the Floridan aquifer must not exceed 1.99 billion gallons. Maximum daily withdrawals from the Florida aquifer for the AESCB must not exceed 7.0 million gallons. The use of the Floridan aquifer potable water for control of fugitive dust emissions is prohibited when alternatives are available, such as treated discharges, shallow aquifer wells, or stormwater. The use of Floridan aquifer potable water for the sole purpose of waste stream dilution is prohibited. Water Use Transfer The SJRWMD must be notified, in writing, within 90 days of the transfer of this certification. All transfers are subject to the provisions of Section 40C-2.351, Florida Administrative Code, which state that all terms and conditions of the permit shall be binding of the transferee. Emergency Shortages Nothing in this certification is to be construed to limit the authority of the SJRWMD to declare a water shortage and issue orders pursuant to Section 373.175, Florida Statutes, or to formulate a plan for implementation during periods of water shortage, pursuant to Section 373.246, Florida Statutes. In the event of a water shortage, as declared by the District Governing Board, the AESCB shall adhere to reductions in water withdrawals as specified by the SJRWMD. Monitoring and Reporting The permittee shall maintain records of total daily withdrawals for the AESCB on a monthly basis for each year ending on December 31st. These records shall be submitted to the SJRWMD on Form EN-3 by January 31st of each year. Water quality samples shall be taken in May and October of each year from each production well. The samples shall be analyzed by an HRS certified laboratory for the following parameters: Magnesium Sulfate Sodium Carbonate Potassium Bi-Carbonate (or alkalinity if pH is 6.9 or lower) Chloride Calcium All major ion analysis shall be checked for anion-cation balance and must balance within 5 percent prior to submission. It is recommended that duplicates be taken to allow for laboratory problems or loss. The sample analysis shall be submitted to the SJRWMD by May 30 and October 30 of each year. AESCB shall mitigate any adverse impact caused by withdrawals permitted hereinon legal uses of water existing at the time of permit application. The SJRWMD has the right to curtail permitted withdrawal rates or water allocations if the withdrawals of water cause an adverse impact on legal uses of water which existed at the time of permit application. Adverse impacts are exemplified but not limited to: Reduction of well water levels resulting in a reduction of 10 percent in the ability of an adjacent well to produce water; Reduction of water levels in an adjacent surface water body resulting in a significant impairment of the use of water in that water body; Saline water intrusion or introduction of pollutants into the water supply of an adjacent water use resulting in a significant reduction of water quality; or Change in water quality resulting in either impairment or loss of use of a well or water body. The AESCB shall mitigate any adverse impact cause by withdrawals permitted herein on adjacent land uses which existed at the time of permit application. The SJRWMD had the right to curtail permitted withdrawal rates of water allocations if withdrawals of water cause any adverse impact on adjacent land use which existed at the time of permit application. Adverse impacts are exemplified by but not limited to: Significant reduction in water levels in an adjacent surface water body; Land collapse or subsidence caused by a reduction in water levels; or Damage to crops and other types of vegetation. Significant increases in Chloride levels such that it is likely that wells from the plant or those being impacted from the plant, will exceed 250 mg/l. Ground Water Monitoring Requirements After consultation with the DER, BESD, and SJRWMD, AESCB shall install a monitoring well network to monitor ground water quality horizontally and vertically through the aquifer above the Hawthorm Formation. Ground water quantity and flow directions will be determined seasonally at the site through the preparation of seasonal water table contour maps, based upon water level data obtained during the applicant's preoperational monitoring program. From these maps and the results of the detailed subsurface investigation of site stratigraphy, the water quality monitoring well network will be located. A ground water monitoring plan that meets the requirements of Section 17-28.700(d), F.A.C., shall be submitted to the Department's Northeast District Office for review. Approval or disapproval of the ground water monitoring plan shall be given within 60 days of receipt. Ground water monitoring shall be required at AESCB's pelletized ash storage area, each sedimentation pond, the lime mud storage area, and each coal pile storage area. Insofar as possible, the monitoring wells may be selected from the existing wells and piezometers used in the permittees preoperational monitoring program, provided that the wells construction will not preclude their use. Existing wells will be properly sealed in accordance with Chapter 17-21, F.A.C., whenever they are abandoned due to construction of facilities. The water samples collected from each of the monitor wells shall be collected immediately after removal by pumping of a quantity of water equal to at least three casing volumes. The water quality analysis shall be performed monthly during the year prior to commercial operation and quarterly thereafter. No sampling or analysis is to be initiated until receipt of written approval of a site-specific quality assurance project plant (QAPP) by the Department. Results shall be submitted to the BESD by the fifteenth (15th) day of the month following the month during which such analysis were performed. Testing for the following constituents is required around unlined ponds or storage areas: TDS Cadmium Conductance Zinc pH Copper Redox Nickel Sulfate Selenium Sulfite Chromium Color Arsenic Chloride Beryllium Iron Mercury Aluminum Lead Gross Alpha Conductivity shall be monitored in wells around all lined solid waste disposal sites, coal piles, and wastewater treatment and sedimentation ponds. Leachate Zone of Discharge Leachate from AESCB's coal storage piles, lime mud storage area or sedimentation ponds shall not cause or contribute to contamination of waters of the State (including both surface and ground waters) in excess of the limitations of Chapter 17-3, F.A.C., beyond the boundary of a zone of discharge extending to the top of the Hawthorne Formation below the wastelandfill cell or pond rising to a depth of 50 feet at a horizontal distance of 200 feet from the edge of the landfill or ponds. Corrective Action When the ground water monitoring system shows a potential for this facility to cause or contribute to a violation of the ground water quality standards of Chapter 17-3, F.A.C., at the boundary of the zone of discharge, the appropriate ponds or coal pile shall be bottom sealed, relocated, or the operation of the affected facility shall be altered in such a manner as to assure the Department that no violation of the ground water standards will occur beyond the boundary of the zone of discharge. CONTROL MEASURES DURING CONSTRUCTION Storm Water Runoff During construction, appropriate measures shall be used to settle, filter, treat or absorb silT.containing or pollutanT.laden storm water runoff to limit the total suspended solids to 50 mg/1 or less and pH to 6.0 to 9.0 at OSN 003 during rainfall events that are lesser in intensity than the 10-year, 24-hour rainfall, and to prevent an increase in turbidity of more than 29 NTU above background in waters of the State. Control measures shall consist at the minimum of sediment traps, barriers, berms or vegetative planting. Exposed or disturbed soil shall be protected as soon as possible to minimize silT. and sedimenT.laden runoff. The pH shall be kept within the range of 6.0 to 9.0 at OSN 003. Stormwater drainage to the Broward River or St. Johns River shall be monitored as indicated below: Monitoring Point Parameters Frequency Sample Type *Storm water drainage BOD5, TOC, sus- ** ** to the Broward River pended solids, from the runoff turbidity, dis- treatment pond solved oxygen, pH, TKN, Total phosphorus, Fecal Coliform, Total Coliform Oil and grease ** ** *Monitoring shall be conducted at suitable points for allowing a comparison of the characteristics of preconstruction and construction phase drainage and receiving waters. **The frequency and sample type shall be as outlined in a sampling program prepared by the applicant and submitted at least ninety days prior to start of construction for review and approval by the DER Northeast District Office. The District Office will furnish copies of the sampling program to the BESD and SJRWMD and shall indicate approval or disapproval within 60 days of submittal. Sanitary Wastes Disposal of sanitary wastes from construction toilet facilities shall be in accordance with applicable regulations of the Department and the BESD. Environmental Control Program Each permittee shall establish an environmental control program under the supervision of a qualified person to assure that all construction activities conform to good environmental practices and the applicable conditions of certification. A written plan for controlling pollution during construction shall be submitted to DER and BESD within sixty days of issuance of the Certification. The plan shall identify and describe all pollutants and waste generagted during construction and the methods for control, treatment and disposal. Each permittee shall notify the Department's Northeast District Office and BESD by telephone within 24 hours if possible if unexpected harmful effects or evidence of irreversible environmental damage are detected by it during construction, shall immediately report in writing to the Department, and shall within two weeks provide an analysis of the problem and a plan to eliminate or significantly reduce the harmful effects or damage and a plan to prevent reoccurrence. Construction Dewatering Effluent Maximum daily withdrawals for dewatering for the construction of the railcar unloading facility must not exceed 1.44 million gallons, except during the first 30 days of dewatering. Dewatering for the construction of the railcar unloading facility shall terminate no later than nine months from the start of dewatering. Should the permittee's dewatering operation create shoaling in adjacent water bodies, the permittee is responsible for removing such shoaling. All offsite discharges resulting from dewatering activities must be in compliance with water quality standards required by DER Chapters 17-3 and 17-4, F.A.C., or such standards as issued through a variance by DER. SAFETY The overall design, layout, and operation of the facilities shall be such as to minimize hazards to humans and the environment. Security control measures shall be utilized to prevent exposure of the public to hazardous conditions. The Federal Occupational Safety and Health Standards will be complied with during construction and operation. The Safety Standards specified under Section 440.56, F.S., by the Industrial Safety Section of the Florida Department of Commerce will also be complied with. CHANGE IN DISCHARGE All discharges or emissions authorized herein to AESCB shall be consistent with the terms and conditions of this certification. The discharge of any pollutant not identified in the application or any discharge more frequent than, or at a level in excess of, that authorized herein shall constitute a violation of this certification. Any anticipated facility expansions, production increases, or process modification which will result in new, different or increased discharges or expansion in steam generating capacity will require a submission of new or supplemental application to DER's Siting Coordination Office pursuant to Chapter 403, F.S. NONCOMPLIANCE NOTIFICATION If, for any reason, either permittee does not comply with or will be unable to comply with any limitation specified in this certification, the permittee shall notify the Deputy Assistant Secretary of DER's Northeast District and BESD office by telephone as soon as possible but not later than the first DER working day after the permittee becomes aware of said noncompliance, and shall confirm the reported situation in writing within seventy-two (72) hours supplying the following information: A description and cause of noncompliance; and The period of noncompliance, including exact dates and times; or, if not corrected, the anticipated time the noncompliance is expected to continue, and steps being taken to reduce, eliminate, and prevent recurrence of the noncomplying event. FACILITIES OPERATION Each permittee shall at all times maintain good working order and operate as efficiently as possible all of its treatment or control facilities or systems installed or used by the permittee to achieve compliance with the terms and conditions of this certification. Such systems are not to be bypassed without prior Department (Northeast District) after approval and after notice to BESD except where otherwise authorized by applicable regulations. ADVERSE IMPACT The permittees shall take all reasonable steps to minimize any adverse impact resulting from noncompliance with any limitation specified in this certification, including, but not limited to, such accelerated or additional monitoring as necessary to determine the nature and impact of the noncomplying event. RIGHT OF ENTRY The permittees shall allow the Secretary of the Florida Department of Environmental Regulation and/or authorized DER representatives, and representatives of the BESD and SJRWMD, upon the presentation of credentials: To enter upon the permittee's premises where an effluent source is located or in which records are required to be kept under the terms and conditions of this permit; and To have access to and copy all records required to be kept under the conditions of this certification; and To inspect and test any monitoring equipment or monitoring method required in this certification and to sample any discharge or emissional pollutants; and To assess any damage to the environment or violation of ambient standards. SJRWMD authorized staff, upon proper identification, will have permission to enter, inspect, and observe permitted and related CUP facilities in order to determine compliance with the approved plans, specifications, and conditions of this certification. BESD authorized staff, upon proper identification, will have permission to enter, inspect, sample any discharge, and observe permitted and related facilities in order to determine compliance with the approved plans, specifications, and conditions of this certification. REVOCATION OR SUSPENSION This certification may be suspended, or revoked pursuant to Section 403.512, Florida Statutes, or for violations of any Condition of Certification. CIVIL AND CRIMINAL LIABILITY This certification does not relieve either permittee from civil or criminal responsibility or liability for noncompliance with any conditions of this certification, applicable rules or regulations of the Department, or Chapter 403, Florida Statutes, or regulations thereunder. Subject to Section 403.511, Florida Statutes, this certification shall not preclude the institution of any legal action or relieve either permittee from any responsibilities or penalties established pursuant to any other applicable State Statutes or regulations. PROPERTY RIGHTS The issuance of this certification does not convey any property rights in either real or personal property, tangible or intangible, nor any exclusive privileges, nor does it authorize any injury to public or private property or any invasion of personal rights, nor any infringement of Federal, State or local laws or regulations. The permittees shall obtain title, lease or right of use to any sovereign submerged lands occupied by the plant, transmission line structures, or appurtenant facilities from the State of Florida. SEVERABILITY The provisions of this certification are severable, and, if any provision of this certification or the application of any provision of this certification to any circumstances is held invalid, the application of such provision to other circumstances and the remainder of the certification shall not be affected thereby. DEFINITIONS The meaning of terms used herein shall be governed by the definitions contained in Chapter 403, Florida Statutes, and any regulation adopted pursuant thereto. In the event of any dispute over the meaning of a term used in these general or special conditions which is not defined in such statutes or regulations, such dispute shall be resolved by reference to the most relevant definitions contained in any other state or federal statute or regulation or, in the alternative, by the use of the commonly accepted meaning as determined by the Department. REVIEW OF SITE CERTIFICATION The certification shall be final unless revised, revoked, or suspended pursuant to law. At least every five years from the date of issuance of this certification or any National Pollutant Discharge Elimination Control Act Amendments of 1972 for the plant units, the Department shall review all monitoring data that has been submitted to it or it's agent(s) during the preceding five- year period for the purpose of determining the extent of the permittee's compliance with the conditions of this certification of the environmental impact of this facility. The Department shall submit the results of it's review and recommendations to the permittees. Such review will be repeated at least every five years thereafter. MODIFICATION OF CONDITIONS The conditions of this certification may be modified in the following manner: The Board hereby delegates to the Secretary the authority to modify, after notice and opportunity for hearing, any conditions pertaining to consumptive use of water, reclaimed water, monitoring, sampling, ground water, surface water, mixing zones, or variances to water quality standards, zones of discharge, leachate control programs, effluent limitations, air emission limitations, fuel, or solid waste disposal, right of entry, railroad spur, transmission line, access road, pipelines, or designation of agents for the purpose of enforcing the conditions of this certification. All other modifications shall be made in accordance with Section 403.516, Florida Statutes. FLOOD CONTROL PROTECTION The plant and associated facilities shall be construed in such a manner as to comply with the Duval County flood protection requirements. EFFECT OF CERTIFICATION Certification and conditions of certification are predicated upon design and performance criteria indicated in the application. Thus, conformance to those criteria, unless specifically amended, modified, or as the Department and parties are otherwise notified, is binding upon the applicants in the preparation, construction, and maintenance of the certified project. In those instances where a conflict occurs between the application's design criteria and the conditions of certification, the conditions shall prevail. NOISE To mitigate the effects of noise produced by the steam blowout of steam boiler tubes, the permittees shall conduct public awareness campaigns prior to such activities to forewarn the public of the estimated time and duration of the noise. The permittees shall comply with the applicable noise limitations specified in Environmental Protection Board Rules or The City of Jacksonville Noise Ordinance. USE OF RECLAIMED WATER AESCB The AESCB shall design the Cogeneration Facility so as to be capable of using reclaimed and treated domestic wastewater from the City of Jacksonville for use as cooling tower makeup water. Reclaimed water shall be utilized as soon as it becomes available. Ground water may be used only as a backup to the reclaimed water after that time. Before use of reclaimed water from the City by the permittee, it will be treated to a level suitable for use as cooling tower makeup water. Reclaimed water used in the AESCB cooling tower shall be disinfected prior to use. Disinfectant levels in the cooling tower makeup water shall be continuously monitored, prior to insertion in the cooling tower. The reclaimed water shall be treated so as to obtain no less than a 1.0 mg/liter free chlorine residual after fifteen (15) minutes contact time or its equivalent. Chlorination shall occur at a turbidity of 5 Nephlometric Turbidity Units (NTU) or less, unless a lesser degree of disinfection is approved by the Department upon demonstration of successful viral kill. Within 120 days following issuance of a modification to the City of Jacksonville's DER wastewater discharge permit allowing Jacksonville, as part of its comprehensive reuse plan, to supply reclaimed water to the Cedar Bay Cogeneration Project, AES Cedar Bay, Inc. shall submit a request for modification to DER for use of reclaimed water for cooling purposes, seeking to make any necessary modifications to their facility and the conditions of certification as may be necessary to allow use of reclaimed water. Its request shall include plans, technical analyses, and modelling needed to evaluate the environmental effects of the proposed modifications. Its request for modification shall also include a financial analysis of the costs of any necessary modifications to its facility, additional operating costs, and the financial impact of these additional costs on AES Cedar Bay, Inc. If DER requires data or analyses concerning the cogeneration facility or its operation, or its discharges or emissions in order to evaluate Jacksonville's application to modify its domestic wastewater discharge permit, AES will supply the necessary information in a timely fashion. The Secretary, as prescribed in Condition XXI, Modification of Conditions, may modify the conditions of certification contained herein as may be necessary to implement the use of reclaimed water. The use of reclaimed water shall be contingent upon a determination of it being financially practicable, and it meeting applicable environmental standards. Prior to any such action by the Secretary, the Secretary shall request and consider a report by the SJRWMD as to the request for modification for the use of reclaimed water by AES Cedar Bay, Inc. Possible Use of Reclaimed Water The use of reclaimed water as described above shall not be limited to cooling tower makeup. Reuse water, if available may be used for fugitive particulate emission control, washdown, and any other feasible use for non-potable water which would not require additional treatment. ENFORCEMENT The Secretary may take any and all lawful actions as he or she deems appropriate to enforce any condition of this certification. Any participating agency (federal, state, local) may take any and all lawful actions to enforce any condition of this certification that is based on the rules of that agency. Prior to initiating such action the agency head shall notify the Secretary of that agency's proposed action. BESD may initiate any and all lawful actions to enforce the conditions of this certification that are based on the Department's rules, after obtaining the Secretary's written permission to so process on behalf of the Department. ENDANGERED AND THREATENED SPECIES Prior to start of construction, AESCB shall survey the site for endangered and threatened species of animal and plant life. Plant species on the endangered or threatened list shall be transplanted to an appropriate area if practicable. Gopher Tortoises and any commensals on the rare or endangered species list shall be relocated after consultation with the Florida Game and Fresh Water Fish Commission. A relocation program, as approved by the FGFWFC, shall be followed. PETROLEUM STORAGE TANKS AES Cedar Bay shall provide clean-up of the #1 underground diesel fuel storage tank site, which is listed under the EDI program, in accordance with F.A.C. Chapter 17-770. AES shall complete an Initial Remedial Action (IRA) in accordance with Rule 17-770.300, F.A.C., prior to construction dewatering. DER and BESD will receive written notification ten working days prior to initiation of the IRA. AES shall determine the extent of contamination. AES Cedar Bay shall then design and install a pump and treatment system at the site, which will create a reverse hydraulic gradient that will prevent the further spread of the contamination by the dewatering operation. This plan shall be submitted to DER and BESD for approval, thirty days prior to the start of construction dewatering, and shall be implemented prior to commencement of the dewatering operation. Furthermore, AES Cedar Bay shall submit a Quality Assurance Report (CAR) and a Remedial Action plan (RAP), in accordance with a F.A.C. Chapter 17-770 to DER for approval with copies to BESD thirty days prior to the start of construction dewatering. AES Cedar Bay shall provide complete site rehabilitation in accordance with F.A.C Chapter 17-770. AES Cedar Bay shall develop a QAPP, CAR, and RAP as required and in accordance with Chapter 17-700, F.A.C. for the site listed in XXVIII, C and D below, and submit these plans to DER for approval with copies to BESD thirty days prior to the start of construction dewatering. Prior to construction dewatering, at the underground diesel fuel storage tank #2 site, AES Cedar Bay shall: Perform an IRA with F.A.C. Rule 17-770.300. Determine the extent of down gradient contamination and submit that information to BESD, and DER prior to installation of the well described in paragraph C.4 below. Establish a series of groundwater level monitoring wells at intervals of approximately 250 feet from the coal unloading site to the #2 tank for determination of the groundwater dewatering cone of influence. Daily groundwater levels shall be recorded for each of these wells during construction dewatering. A background well with a continuous water level recorder shall be installed, at a site that would not be influenced by the dewatering operations, to determine ambient conditions at the site. Install a monitoring well with a continuous water level recorder which will be used to trigger implementation of the RAP. The well will be located 150 feet down gradient from the boundary of the plume of contamination determined above in XXVII C.2. If the epiezometric head in the trigger well drops 6 inches below ambient conditions as compared to the background well, then AES Cedar Bay shall notify DER and BESD of a verified drop of 6 inches or more in the trigger well within three working days and the appropriate portion of the RAP shall be implemented by AES Cedar Bay. AES Cedar Bay shall submit a plan for the location and construction of the monitoring wells described above in paragraph C.3 and C.4 to DER and BESD for approval. AES Cedar Bay shall submit monthly reports of the groundwater level recordings to DER and BESD. Prior to construction dewatering, at each of the following tank sites: underground diesel fuel storage tank #3; underground #6 fuel oil shortage tank #5; above-ground #6 fuel oil storage tank #2: "pitch tank" located North of the lime kilns; AES Cedar Bay shall: Install 2 down gradient monitoring wells. AES Cedar Bay shall submit a plan for location and construction of these 8 wells to DER and BESD for approval. BESD shall have the opportunity to observe the construction of these wells. Sample the above reference wells for parameters listed in 17-770.600(8), F.A.C. In addition, AES Cedar Bay shall sample the monitoring wells at the above-ground tank sites for acetone and carbon disulfide. AES Cedar Bay shall split samples with BESD if BESD so requests and submit a report of the analytical results to DER and BESD within ten days of receipt of analysis by AES Cedar Bay. If contamination is found in the above reference wells in excess of the clean-up criteria referenced in 17- 770.730(5)(a)2., F.A.C., a QAPP, CAR and an RAP will be development and, DER and BESD shall be provide with that information prior to the installation of the well described in paragraph D.4 below. Install a trigger well with a continuous water level recorder which will be located 150 feet down gradient from the boundary of the plume of contamination determined above in XXVIII.D.3. If the piezometric head in the trigger well drops 6 inches below ambient conditions as compared to the background well then AES Cedar Bay shall notify DER and BESD of a verified drop of 6 inches or more in the trigger well within three working days and the appropriate portion of the RAP shall be implemented by AES Cedar Bay. AES Cedar Bay shall submit a plan for the location and construction of the monitoring wells described above in paragraph D.4, to DER and BESD for approval. AES Cedar bay shall submit monthly reports of the groundwater level recordings to DER and BESD. Implementation of the appropriate portion of the RAP shall commence within 14 days of the determination that the construction dewatering cone of depression will reach any of contaminated sites. AES Cedar Bay shall monitor the construction dewatering effluent from their treatment system, once a week during dewatering, for the following criteria: Benzene 1 ugle; Total VOA 40 ug/l Total Naphthalenes (Total-naphthalenes = methyl napthalenes) 100 ugle; and Total Residual Hydrcarbons 5 mg/l. If the concentrations of contaminants in the effluent rise above those in the above list, AES Cedar Bay shall take corrective actions to return concentrations to acceptable levels. If any disagreement arises regarding this condition, the parties agree to submit the matter for an expedited hearing to the DOAH and shall request assignment of the hearing officer who has heard the case, if possible, pursuant to 403.5064, F.S. The informal dispute resolution process shall be used. COPIES FURNISHED: Terry Cole, Esquire Scott Shirley, Esquire Oertel, Hoffman, Fernandez & Cole, P.A. 2700 Blairstone Road Suite C Tallahassee, FL 32301 Betsy Hewitt, Esquire Department of Environmental Regulation 2600 Blairstone Road Tallahassee, FL 32399-2400 Kathryn Mennella, Esquire St. Johns River Water Management District P.O. Box 1429 Palatka, FL 32178-1429 Richard L. Maguire, Esquire Towncentre, Suite 715 421 West Church Street Jacksonville, FL 32202 Katherine L. Funchess, Esquire Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 William C. Bostwick, Esquire 1550-2 Hendricks Avenue Jacksonville, FL 32201 Daniel H. Thompson General Counsel Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, FL 32399-2400 Dale H. Twachtmann, Secretary Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, FL 32399-2400 =================================================================
Findings Of Fact On September 12, 1995, Petitioner became a Florida Power customer. He received electricity service in his name at an apartment located at 2950 N. Pinehill Road #31, Orlando, Florida. From September 1994, through December, 1994, Petitioner occupied the apartment at 2950 N. Pinehill Road #31, Orlando, Florida. Petitioner's meter indicated he used 827 Kwh from September 12, 1994, through October 4, 1994. Petitioner's meter indicated he used 1525 Kwh from October 4, 1994, through November 2, 1994. Petitioner's meter indicated he used 1548 Kwh from November 2, 1994, through December 5, 1994. Petitioner's final bill was for December 5, 1994, through December 28, 1994. The meter indicated he used 221 Kwh for this final period. Respondent's tariff sheet 8.05 filed with the Commission sets forth the length of time within which Respondent must disconnect a customer's service after receiving a disconnect order. Respondent must disconnect service within 3 days of receiving the disconnect order. On December 26, 1994, Petitioner requested that his service be disconnected on December 27, 1994. Respondent disconnected Petitioner's service on December 28, 1994. On January 12, 1995, Petitioner's meter was tested in St. Petersburg, Florida. Petitioner's meter registered 99.96 percent accuracy.
Recommendation Based on the foregoing findings of fact and conclusions of law, it is, RECOMMENDED that the Commission enter a Final Order finding that Respondent acted in compliance with applicable law and did not overbill Petitioner. RECOMMENDED in Tallahassee, Leon County, Florida, this 2nd day of January, 1995. DANIEL S. MANRY, Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 2nd day of January, 1995. COPIES FURNISHED: Rodney Gaddy, Esquire Florida Power Corporation 3201 34th Street, South St. Petersburg, Florida 33711-3828 Thomas Fuller Post Office Box 617217 Orlando, Florida 32861 Robert D. Vandiver, General Counsel Florida Public Service Commission Gerald L. Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Noreen S. Davis, Director Division of Legal Services Florida Public Service Commission Gerald L. Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850
The Issue The issue in this case is whether the Siting Board should grant a site certification to Gainesville Regional Energy Center, LLC (GREC) for the construction and operation of a 100-megawatt (MW) biomass-fired electrical power plant in Gainesville, Florida, pursuant to Sections 403.501 through 403.518, Florida Statutes.
Findings Of Fact Introduction On November 30, 2009, GREC filed with DEP an Application for the construction and operation of a net 100 MW (gross 116 MW), biomass-fired electrical power plant at GRU's Deerhaven power plant complex. GREC seeks to place the biomass plant in service on or before December 31, 2013, which is the deadline for eligibility for a federal renewable-energy grant under the American Recovery and Reinvestment Act of 2009. GREC is a subsidiary of American Renewables, LLC, which develops, builds, and operates renewable-energy facilities. American Renewables, LLC, is jointly owned by affiliates of three corporations that develop, operate, invest, and manage various types of energy projects. American Renewables, LLC, recently obtained permits for a similar biomass plant, also of 100 MW net, in Nacogdoches, Texas. This plant, which is expected to begin commercial operation in late 2012, has a power purchasing agreement with Austin Energy, a municipal utility owned by the City of Austin. American Renewables, LLC, recently sold the Nacogdoches plant to a subsidiary of Southern Company. GRU is a municipal utility of the City of Gainesville. GRU owns and operates a power generation, transmission, and distribution system to serve its 93,000 customers and its wholesale customers, which include the City of Alachua and Clay Electrical Cooperative, Inc. In addition to owning a 1.4- percent share of the Progress Energy Florida Crystal River Unit Three, GRU owns three power supply facilities, which generate a summer net capacity of 608 MW. Of these, the largest is Deerhaven, which generates 440 MW net. A former mayor of the City of Gainesville, Intervenor served on the utility committee of the City Commission and participated in utility planning for GRU. Intervenor lives less than 10 miles from the Deerhaven site and regularly walks outdoors, works in his yard, and bicycles in the area. He enjoys canoeing on local waterways and observing wildlife, such as eagles, hawks, and owls. Identifying himself as a "locavore," Intervenor favors locally grown food. Application According to the Application, the GREC site consists of 131 acres within the Deerhaven site in northwest Gainesville and north central Alachua County--eight miles from downtown Gainesville to the southeast and seven miles from downtown Alachua to the northwest. The Deerhaven site is within a 1146- acre parcel owned by the City of Gainesville. The Deerhaven site includes several units. Unit 1 generates 88 MW by way of a natural gas or oil-fired steam unit. Unit 2, which was certified in 1978, generates 235 MW (sometimes described as 250 MW) by way of a pulverized coal-fired unit. Unit 3 generates 76 MW by way of a natural gas or oil-fired, simple-cycle combustion turbine unit. Deerhaven also includes two 19-MW, simple-cycle combustion turbine units. If the Siting Board issues a certificate for the GREC site, GRU would not be required to decertify any part of its site; instead, GRU's certificate would be modified to reflect the certification issued to GREC. The GREC site abuts the northwest boundary of the GRU's existing generating facilities at Deerhaven. The GRU facilities immediately east of the GREC site are an ash landfill, brine landfill, and large stormwater management pond. Abutting these facilities to the east are ash settling ponds and a wastewater treatment sludge disposal cell, and, abutting these facilities farther to the east, is a large coal pile. A spur of the CSX rail line, which is used for coal deliveries to Deerhaven Unit 2, terminates just south of the GREC site. Except for secondary access roads and unpaved trails, no Deerhaven facilities occupy the GREC site. Immediately west of the GREC site is a site used by the Alachua County Public Works Department for an office and other facilities. Also west of the GREC site is a radio tower and undeveloped land. The southernmost extent of the GREC site fronts on U.S. Route 441, which is lined by intermittent commercial and retail uses in this area. Across U.S. Route 441, over one-half mile from the GREC site, is the nearest residential subdivision, which is called Turkey Creek. The Application reports that, in the early 2000s, the City of Gainesville purchased an additional 2328 acres of timberland north and east of the Deerhaven site for buffer and potential expansion. The entire area, including the GREC site, was historically devoted to agriculture and pine silviculture, but the GREC site is now occupied by ditches, swales, some forested communities, and the roads and trails previously mentioned. According to the Application, the GREC facility will feature a bubbling fluidized bed boiler (BFBB) and conventional steam turbine generator. Except during startup, when the boiler will consume natural gas until it reaches operating temperatures, the BFBB will burn a wide range of clean, woody biomass fuels in a dense, fluidized sand bed at the bottom of the furnace and also in the area above the bed. The biomass fuel will be derived from logging residue, mill residue, and urban wood waste derived from tree trimming. The BFBB will combust one million tons per year (tpy) of biomass. To obtain the fuel, GREC will enter into contracts with suppliers within 75 miles of the site. GREC will incorporate in supplier contracts requirements of sustainability and incentives for good stewardship in silvicultural practices. Suppliers will chip or grind the wood at offsite locations and then truck the woody materials to the GREC site. Each truck arriving at the site will be weighed and unloaded, so that the woody biomass can be placed in a fuel storage area until it is needed. The high combustion temperatures reached by the BFBB and the implementation of the requirement for clean woody fuel will, the Application reports, limit the generation of pollutants. As described in the Application, GREC will employ three additional pollution-control measures: 1) a selective catalytic reduction (SCR) system to reduce emissions of nitrogen dioxide (NO2); 2) a fabric filter baghouse to reduce emissions of particulate matter (PM); and 3) dry sorbent injection (DSI) to reduce emissions of sulfuric acid mist (SAM), hydrogen chloride (HCl), and hydrogen fluoride (HF). The Application states that GREC will not emit any industrial wastewater from the site. By recycling and reusing water, GREC expects that its water use, primarily to replace water lost to evaporation in its mechanical cooling tower, will be 1.4 million gallons per day, which will be taken from the Upper Floridan Aquifer. GRU has agreed to reduce its water withdrawals by the same amount prior to commencement of operations by GREC. The GREC site will also include an administration building, a warehouse, several stormwater detention ponds, water and wastewater treatment facilities, storage facilities for the fly ash and sand from the BFBB, two emergency diesel engines, and a switchyard. Linear facilities, several of which extend slightly off of the GREC property, include roads, sanitary sewer and natural gas pipelines, and a 138-kV transmission line and switchyard. The Application describes various alternatives considered by GRU to the GREC biomass plant. The no-action alternative is implicitly considered and dismissed in a discussion of the age of GRU's other power-generation equipment- 25 years; prevailing power demand during the summer peak season- -441 MW; and the year of projected capacity shortfall--2023. Among other alternatives, GRU considered renewable sources-- geothermal, solar, biogas from landfills, waste-to-energy, wind, and biomass--and conventional sources--natural gas, coal, coal combusted in a fluidized bed, coal gasification, and nuclear. In 2007, the City of Gainesville decided not to pursue coal due to climate-change concerns. Governor Crist's executive order on climate change also discouraged the submittal of coal- based applications to the Siting Board. In January 2008, after having solicited and received a round of nonbinding proposals identifying various options, the City of Gainesville invited three vendors, including the predecessor of American Renewables, to submit binding proposals. The resulting proposals discussed eight options--all of which used biomass as the exclusive fuel source. At a meeting in May 2008, the City Commission unanimously voted to accept the American Renewables proposal. The City of Gainesville has identified numerous benefits from the GREC project. These include enhancing the integrity and reliability of the generating system, reducing the average age of the generating system, producing reasonably priced electricity, diversifying fuel sources, avoiding the price fluctuations of fossil fuels, hedging the risks of anticipated carbon-constraint legislation (if biomass is treated preferentially under such legislation), reducing construction and operation risks, reducing open burning of biomass products in forestry operations, reducing landfilling of woody biomass, and supporting the silviculture industry. The site plan depicts the location of all of the components of the GREC facility. By groupings from west to east, the GREC components are the fuel-storage area, which consists of separate wood piles that are described in detail below; parking, offices, a warehouse, a control room, fire pumps, a water treatment facility, and water tanks; a 50-foot wide band of unoccupied land; a switchyard with transmission line running to a new GRU switchyard at U.S. Route 441, the switchyard control room, the steam turbine, fuel day bins connected to the storage area by a conveyor, the boiler, a baghouse, and an aqueous ammonia storage area; and a cooling tower. These components are concentrated on the north side of the site, farthest from U.S. Route 441, and toward the east side of the site, nearest GRU's Deerhaven operations. The boiler, steam turbine, emissions-control equipment, boiler stack, and cooling tower are 3200 feet northwest of U.S. Route 441 and 2200 feet east of the public works department. The GREC switchyard will transform the power to 138-kV. The transmission lines run along the access road to the new GRU switchyard, which is on U.S. 441 in a small outparcel from the GRU parcel. The GRU switchyard will transmit the power to the existing GRU 138-kV transmission lines along U.S. Route 441. GREC will construct the new GRU switchyard and the 300 feet of new 138-kV transmission to the existing transmission lines. The Application depicts two areas of 100-year floodplain. The northern of these areas is at the northmost part of the GREC parcel. The east end of this floodplain will be converted to three stormwater ponds, and the west end will remain an undisturbed wetland. The southern of the two floodplains is in the area of the new GRU switchyard. The only encroachments on this floodplain will be the access road and transmission line; otherwise, the southern floodplain is left undeveloped. The Application states that the nearest fire station is 3.4 miles to the south, and the nearest hospitals are 6.3 and 8.3 miles to the south. Solid waste will be transferred ultimately to the New River regional landfill in Raiford, which has a projected life of more than 50 years at current filling rates. The City of Gainesville lies at a peninsular divide. To the east, water drains to the Atlantic Ocean by way of the Ocklawaha River and St. Johns River. At the site, water drains into the Gulf of Mexico by way of Turkey Creek, the Santa Fe River, and the Suwannee River. Drainage from a small part of the northern end of the site reaches the Santa Fe River by way of the Rocky Creek drainage basin. The surface waters around the GREC site are Class III waters. About 72 percent of the GREC site is vegetated by hardwood-conifer mixed and coniferous plantation. The former classification reflects selective thinning of timber, and the latter category reflects a human-altered community. Another ten percent of the onsite vegetation is wetland forested mixed. No naturally occurring aquatic communities occupy the GREC site. The swales are seasonally wet, but not hydrologically connected to other surface waters, at least up to the design storm. Silviculture has heavily influenced the terrestrial flora communities. Two biologists, one of whom specializes in wildlife, conducted a wildlife survey on the mornings of May 27 and 28, 2009. Among listed animal species, the biologists saw, heard, or found evidence of no listed species on the site, which is presently and will continue to be fenced for security reasons. As to listed species, the biologists found only an abandoned burrow that had probably been used by a gopher tortoise and offsite use by alligators and listed bird species. The biologists found no listed plant species at the GREC site. Five important plant species occur within five miles of the GREC site, but these are found in the San Felasco Hammock Preserve State Park, which is 1.5 miles west of the site, immediately west of the Turkey Creek residential subdivision. As for the potential use of the GREC site by listed wildlife species, the wildlife biologist found moderate potential for only the Eastern Indigo snake, snowy egret, tricolored heron, Southeastern American kestrel, and Florida sandhill crane. The nearby presence of the American alligator, little blue heron, white ibis, and wood stork (roosting only) would also suggest moderately likely use of the GREC site by these listed species. Longstanding onsite silvicultural practices, including drainage, clearing, and road-building, have disrupted the upland natural plant communities and facilitated their displacement by such nuisance exotics as cogongrass, torpedo grass, and Chinese tallow. The wetlands communities have also been stressed, as evidenced by the presence of dead cypress trees, gaps in natural wetlands vegetation, and opportunistic wetlands vegetation, such as duckweed and various vines. Suggestive of the post-developed state of the GREC site, the Deerhaven operations also stress the fauna, but the stormwater ponds attract a large number of wetland- and water-dependent species. The Application states that the predominant winds are from the northeast and west-southwest. The average wind speed is 2.6 meters per second. Calm winds occur 26 percent of the time, primarily in the summer. Situated 55 miles from the Gulf of Mexico and 70 miles from the Atlantic Ocean, the GREC site is shielded by enough land mass to reduce or eliminate the destructive effects of most tropical storms. The Application states that ambient air quality is a product of meteorology, atmospheric chemistry, and pollution emissions. Meteorology controls the distribution, dilution, and removal of pollutants. Atmospheric chemistry controls the transformation of primary pollutants into secondary pollutants. Primary pollutants are discharged directly from the source and, for GREC, will include nitrogen oxides (NOx), sulfur dioxide (SO2), carbon monoxide (CO), and particulate matter (PM), or, traditionally, soot, although, as a fugitive emission, PM is better considered as dust from the biomass fuel, except when the source is ash residue. For GREC, the most important secondary pollutant is ozone, which forms from the combination of NOx and volatile organic compounds (VOCs) in sunlight. The Application states that the U.S. Environmental Protection Agency (EPA) has established national ambient air quality standards (AAQS) for six pollutants: SO2, NO2, CO, lead, ozone, and PM, which comprises PM10 and PM2.5. Title I, Part A, Clean Air Act. The latter two pollutants are, respectively, PM not greater than 10 microns and PM not greater than 2.5 microns. Primary air quality standards for these criteria protect human health, and secondary air quality standards for these criteria protect the environment and physical property. For all six AAQS criteria, the EPA has not designated the relevant area a nonattainment area. The record does not suggest that the EPA has designated any part of Florida a nonattainment area for any of the AAQS pollutants. For the AAQS pollutants, then, the relevant area has acceptable air quality in terms of air impacts on human health. Unlike the Clean Air Act programs involved in this case, the AAQS program focuses exclusively on human health and does not balance impacts to human health or the environment against issues of economic productivity. EPA has developed an air quality index that describes air quality in relative terms. Good is the highest rating and means that air pollution poses little or no risk. Moderate means that air pollution may be a moderate health concern to a very small number of persons. Unhealthy for sensitive groups means just that, and healthy groups are unlikely to be affected. Unhealthy means that air pollution may cause everyone to begin to experience health effects, and sensitive groups may experience more serious health effects. The two remaining classifications are very unhealthy and hazardous. For 2007, the EPA classified the air quality in Alachua County as 315 days of good, 44 days of moderate, and 6 days of unhealthy for sensitive groups. For 2008, the EPA classified the number of good days as only 258. In general, the EPA classifies the air quality of Alachua County as good with the main pollutant adversely affecting air quality as ozone. For Alachua County, stationary fuel combustion generates about 91 percent of the SO2, about 28 percent of the NOx, about 14 percent of the PM2.5, about six percent of the PM10, and nearly none of the CO and VOCs. Another Clean Air Act program of interest in this case is the National Emission Standards for Hazardous Air Pollutants (NESHAP), which is Title I, Part A, § 112, of the Clean Air Act. The NESHAP regulatory scheme focuses on enumerated hazardous air pollutants (HAPs). For Alachua County, HAPS are not attributable primarily to stationary fuel combustion. The Application states that 86 percent of these pollutants were emitted from mobile and area small sources, such as dry cleaners and gas stations. The main feature of the GREC facility is, of course, the boiler. Emitting 95 percent of the total emissions of the GREC facility, the BFBB consists of sieved natural sand, which is maintained in suspension by a fluidizing air system. The fluidization yields an expanded combustion zone within the boiler with high turbulence, intimate solids-to-gas contact, and a high heat transfer rate. While combusting biomass fuels, the bed temperatures range from 1350 to 1700 degrees. (All temperatures are Fahrenheit.) Overfire air, usually 200 degrees hotter, is introduced to complete the combustion of volatile gases, such as CO. Flue gas leaving the 179-foot-high boiler passes through emission control equipment before discharging through a single 230-foot-high stack. The fabric filter baghouse will capture PM. As described in the Application, the baghouse comprises 12 filter compartments, each containing 250-350 bags that are six inches in diameter and 14- to 26-feet long. At the bottom of the baghouse is a hopper to collect ash. As PM forms on the bags, it forms a filter cake that increases the filtration efficiency of the bags. But once the air pressure drops to specified limits, high-pressure air pulses are directed, automatically, into each bag, loosening the caked fly ash and depositing it in the hopper below. Downstream of the baghouse, the SCR will reduce NOx from the flue gas stream by using a catalyst and a reactant (ammonia gas) to dissociate NOx into nitrogen gas and water vapor. The BFBB technology--especially the DSI--combined with low sulfur biomass fuel and the naturally occurring calcium in the wood ash, will control SO2, SAM, HCl, and HF emissions. Each business day, 130-150 trucks with wood chips will arrive at the GREC facility. They will proceed to a drive- through structure, which contains three truck dumpers and three receiving hoppers. From the hoppers, the fuel will be conveyed to a fuel processing system, where a metal detector and magnetic separator will remove metals, a disc screen will remove oversized chips, and a hammer hog will reduce the oversized chips to the design size of three inches or less. This equipment is located in an enclosed building with a dust- collection system. The processed fuel is conveyed outside to the fuel storage area. One wood pile will have an automatic stacker/reclaimer that will be able to deposit, churn, mix, and remove nearly the entire pile. Another wood pile, conical in shape, has a fixed stacker, and the material will be moved by bulldozers and front-end loaders. This rolling stock will transfer some of the wood chips to a smaller, manual-reclaim pile that will also be contoured by bulldozers and front-end loaders. A fourth, much smaller pile will be maintained for the delivery of presized material, mainly sawdust. As originally sized, the wood piles are intended to store sufficient fuel for 15-20 days of operations. In the Application, the automatic stacker/reclaimer pile is specified to be 85 feet high, but, after consultation with the Gainesville Fire Department, as detailed below, GREC agreed to reduce the height of this pile to 60 feet. The fixed stacker pile is 60 feet high, and the manual-reclaim pile is 35 feet high. The automatic stacker/reclaimer pile is 400 feet by 400 feet, and the manual-reclaim pile is 400 feet by 465 feet. GREC will manage the separate wood piles to maintain the design moisture content in the fuel, which is about 50 percent, but also to ensure that no portion of the stored wood remains in the pile for too long. In general, GREC intends to use fuel on the basis of first-fuel-in, first-fuel-out, to avoid problems of odor and spontaneous combustion, the latter of which is discussed in detail below. Fly ash from the boiler and baghouse filter will be collected dry and transported pneumatically to an onsite storage silo. From there--if needed, after stabilization with water-- the ash will be transported--enclosed, if still in dry form--for use as a soil supplement or, if such use is unavailable, to an approved offsite landfill. Another means of controlling emissions is ensuring that the biomass is suitably clean. The design biomass is forest residue, mill residue, precommercial tree thinnings, used pallets, and urban wood waste, which is predominantly the trimmings of landscape contractors. Supplementary fuels may include herbaceous matter and agricultural residues (such as rice hulls and straw, but not animal matter or manure). The GREC facility will not accept painted, treated, or coated wood, construction and demolition debris, or municipal solid waste. Relying on four investigations of the adequacy of the supply of available biomass resources, GRU determined that ample supplies exist within a 75-mile radius of the GREC site. Within 75 miles of the GREC site lie 6.44 million acres of timberland, of which 81 percent is privately owned. To discourage practices among its biomass suppliers that would reduce ecosystem biodiversity, GREC will impose upon them sustainability requirements that will mandate that they comply with the Division of Forestry's best management practices (BMPs) for timber operations and will prohibit the delivery of stumps (to avoid erosion in the source area) and biomass generated from the conversion of natural forests to plantation forests or from nonnative species, unless the nonnative-species biomass is generated from a forest restoration project. To enforce these sustainability requirements, the power purchase agreement between GRU and GREC requires GREC to obtain annual audits by an independent forestry consultant to assess supplier compliance, incorporate the sustainability requirements into its supplier contracts, require that suppliers identify each load with information sufficient to disclose the source of the fuel and the crew that obtained it, inspect at least 10 percent of all incoming fuels to ensure compliance with the sustainability requirements, require that suppliers maintain documentation for each load for three years, conduct semiannual inspections of all suppliers to investigate operations and recordkeeping, require suppliers to attend annual training seminars conducted by GREC, and suspend deliveries for at least one year from any supplier found to be noncompliant three times in a single year. To encourage practices among its supplies that will maintain or increase ecosystem biodiversity, GREC will pay premiums of $0.50 or $1.00 per delivered ton of biomass to suppliers that adhere to an approved forest certification program that is more demanding than the Division of Forestry's best management practices. The Application analyzes boiler and facility emissions in terms of New Source Review (NSR) for Prevention of Significant Deterioration (PSD), which is Title I, Part C, of the U.S. Clean Air Act, 42 U.S.C. §§ 7401, et seq. (Clean Air Act). Although this regulatory program is the subject of the air construction permit case, PSD analysis provides a useful framework for addressing the air impacts from the GREC facility. Among other things, NSR requires, for pollutants subject to PSD review, that the facility control emissions by the best available control technology (BACT), which is the maximum degree of reduction for each PSD-regulated pollutant, using available and feasible technology and taking into account energy, environmental, and economic impacts and other costs. The Application states that the BFBB will emit NOx, SO2, lead, mercury, CO, VOCs, PM/PM10, and SAM. Except for the lead, mercury, and SAM, the emissions exceed the PSD emissions rate and trigger PSD review. The annual emissions for the BFBB are: NOx--416.4 tpy; SO2--243.9 tpy; CO--713.8 tpy; VOCs--77.3 tpy; total PM--249.8 tpy; and SAM--5.9 tpy. The diesel emergency generator and firewater pump add small increments to these emissions. The other sources of pollution at the facility emit PM of various sizes. Four sources of material handling present the opportunity for fugitive emissions of PM. Fugitive emissions are nonpoint-source emissions that, although inadvertent, may be projected and modeled. These four sources are transfer points, material processing areas, wood piles, and fuel bins. To the extent practicable, all transfer points will be enclosed. The vents in storage silos will be equipped with appropriately sized air filters. Water will be used to control dust on the wood piles. The primary roads will be paved, and GREC will sweep and water them to control dust. GREC will water any unpaved trails. After applying all practicable controls, the Application projects material-handling annual fugitive PM emissions to be 11.6 tpy of PM, 2.3 tpy of PM10, and 0.34 tpy of PM2.5. These PM fugitive emissions compare to annual point-source PM emissions-- all assumed to be PM2.5--of 28 tpy. For the pollutants subject to PSD review--NOx, SO2, CO, VOCs, PM, and PM10--the Application states that GREC's employment of BACT will be directed primarily toward the BFBB. The Application assures: "The proposed configuration of the BFB combustor, DSI, baghouse, and SCR is considered the most stringent emission control technology train available for biomass-fired boilers and to represent BACT for the GREC BFB boiler." Application, Chapter 4, p. 4-49. (GREC's later agreement, as detailed below, to provide even more stringent pollution control technology does not necessarily undermine the force of this assurance in the Application; it would appear instead that the newer technology represents the most most stringent emission control technology train available for biomass-fired boilers.) NOx emissions will be limited by staging the combustion in the bed and lower furnace area. Combustion staging and flue gas recirculation reduce the flame temperatures, so as to reduce the formation of thermally generated NOx. By providing more than three seconds residence time at temperatures above 1500 degrees, the BFBB will minimize VOC and CO emissions. SO2 emissions will be limited by several means, starting with the bubbling bed furnace where sufficient amounts of calcium, sodium, and potassium will be available from the biomass ash to capture SO2 in the boiler. The DSI will further control SO2 emissions. PM/PM10 emissions will be limited by the baghouse's fabric filters, which, after exposure to the alkaline sorbent added by the DSI, will also remove SAM, HCl, and HF. CO and VOCs, which are formed by incomplete combustion of organic compounds contained in the biomass fuel, will be controlled by the duration of residence time, furnace temperatures, and good air mixing in the furnace. Through dispersion modeling of air impacts, GREC determined that the facility would not violate any PSD increment, although the GREC facility will emit, under the PSD program, significant emission rates of NOx, SO2, CO, PM, PM10, and ozone/VOCs. These matters are discussed in detail below. The Application states that wood contains trace amounts of mercury. Combustion at 1500 degrees vaporizes the mercury into gaseous elemental mercury. Subsequent cooling may produce elemental mercury, particle-bound mercury, and oxidized mercury compounds, which is also known as reactive gaseous divalent mercury (RGM). The baghouse filters might capture some of these mercury emissions, although GREC's analysis conservatively assumed that they would not. Of the 16.7 pounds per year of all forms of mercury projected to be emitted by the GREC biomass plant, about 70 percent of it, according to GREC's conservative assumptions, will be elemental mercury and 30 percent of it will be RGM. The former has long residence time in the atmosphere and travels long distances, and the latter deposits locally and regionally. By comparison, annual anthropogenic emissions of mercury in the United States were 145 tons in 2005, including 48 tons from power plant emissions. In 1999, mercury emissions from Florida coal-fired plants were 1923 pounds. Worldwide, anthropogenic emissions of mercury account for two-thirds of total mercury emissions, the remainder being from natural causes, such as volcanic eruptions and oceans. The Application considered wet and dry deposition rates of mercury in the Santa Fe River basin. After calculating an average areal wet deposition rate from the GREC facility, the Application concludes that it is 6000 times less than the average areal wet deposition at the nearest location for which such data are available. The Application also concludes that the wet plus dry deposition rate of mercury from the GREC facility will be 400 times less than the wet-only rate at the comparison location. Among the socio-economic benefits of the GREC facility, construction will generate $48 million of payroll, largely for local and regional labor, and $160 million in nonengineered construction equipment purchases. Operation will result in the employment at the facility of 44 fulltime employees, initially earning $4 million annually. NonGREC employment will include truck drivers and operators of wood- processing equipment. Incompleteness Determination and GREC Response On January 11, 2010, after consulting with affected agencies, DEP determined that the Application was incomplete. Among the issues in DEP's determination were several raised by the Florida Fish and Wildlife Conservation Commission (FWC): GREC relied inappropriately on the Florida Land Use and Cover Forms Classification System (FLUCFCS) for identification of plant communities that provide wildlife habitat; 2) GREC failed to identify the survey methodology (e.g., time of year and types of observed activities) and to perform a desktop review prior to "appropriate surveys," which "should be conducted during the [reproductive] season particular to each species"; 3) for the three isolated wetlands to be impacted by construction, GREC failed to conduct an amphibian breeding season survey targeting at least the gopher frog and consider the flatwoods salamander, due to the dominance of flatwoods soils on the site, when designing the survey; and 4) GREC failed to detail the maintenance conditions for wetland buffers to address wildlife functions, not merely stormwater functions. FWC concluded that it could not determine potential impacts to wildlife from the Application or conditions that should attach to certification. By Completeness Responses and Amendment to [Application] dated February 2010, GREC responded to the incompleteness determination. Responding to the issues raised by the FWC, GREC stated: 1) DEP forms and rules approved the use of the FLUCFCS system; 2) GREC had already performed the requested desktop review and detailed the survey methodology, but GREC agreed to a preclearing survey using FWC-approved methodologies and at times likely to maximize the observation of the subject species and further agreed to coordinate with FWC any mitigation methodologies for listed species impacted by construction; 3) the three isolated wetlands, which did not contain standing water, even during the wet season, were of no significant breeding or foraging habitat value and GREC declined to include methods for the flatwoods salamander because of extensive alteration of the land and the absence of such salamanders within five miles of the site, but GREC agreed to include in the preclearing survey methods for the gopher frog; and 4) GREC agreed to maintain wetland buffers in their current vegetative state. By letter dated March 4, 2010, DEP determined that the Application was complete. DEP Report By Electrical Power Plant Site Certification Project Analysis Report dated July 12, 2010 (DEP Report), DEP analyzed the proposed GREC facility in light of the Application and the applicable requirements of law. In terms of wetlands impacts, the DEP Report notes that GREC had proposed to mitigate for the destruction of 0.44 acres of low-functioning wetlands by placing in a conservation easement 10.25 acres of higher-functioning onsite wetlands and 12.33 acres of uplands buffer. The DEP Report stated that DEP's Wetlands Section did not object to this proposal. The DEP Report states that the studies that GREC had commissioned supported a finding that, annually, the supply of biomass exceeded GREC's need by at least five times. The DEP Report reports that Agriculture Commissioner Charles Bronson had recently concluded that biomass energy production encourages the sustainability of Florida's forests by discouraging their conversion into other uses through the creation of a market for low-value biomass materials, such as forest residues and premarket thinnings. The DEP Report states that fluidized bed combustion technology has been used since the 1970s and burns a wide variety of fuels "cleaner and more efficiently" than do other forms of combustion. According to the DEP Report, the Jacksonville Electric Authority uses two circulating fluidized bed boilers at its Northside Generating Station for burning coal, and this technology has reduced emissions by ten percent. According to the DEP Report, the BFBB is better at burning fuel with higher moisture content and lower heating values, so it is more suitable for burning biomass. The DEP Report approves the Application's BACT analysis. The DEP Report notes that GREC will increase the emissions of three (or four if the PMs are counted separately) PSD-regulated pollutants above significant emission rates: PM, PM10, CO, and VOCs. Among the more important determinations in the DEP Report is that GREC's NOx and SO2 emissions will be offset with emissions reductions achieved by new air pollution control technology installed by GRU at Deerhaven in 2009. The DEP Report notes that the DEP Division of Air Resource Management had determined that the Application complies with all applicable federal and state air pollution regulations, and the final air construction permit will be incorporated into the conditions of certification (COC). The DEP Report reviews the comments of the various reviewing agencies. The agencies approving the Application without condition were the PSC, North Central Florida Regional Planning Council, Department of Community Affairs, Division of Historical Resources of the Department of State, City of Gainesville, and Division of Forestry. The agencies approving the Application with conditions were the Suwannee River Water Management District, which required a condition that the GREC facility's groundwater withdrawals of 1.4 million gallons per day be offset by a reduction of 1.4 million gallons per day of groundwater withdrawals by GRU at Deerhaven before GREC operation may commence; the FWC; and the Department of Transportation, whose conditions are irrelevant to this case. In a letter dated June 10, 2010, FWC recommended five COCs. First, if the site plan is modified to impact listed species, GREC must coordinate with FWC and the U.S. Fish and Wildlife Service to identify necessary conservation measures. Second, GREC must evaluate impacted wetlands on a case-by-case basis and establish compatible-use buffer zones and wetland protection buffers around all wetlands, appropriate to the site's wildlife inventory, in accordance with the U.S. Fish and Wildlife Service's guidelines for wetlands buffers. Third, for gopher tortoises, GREC must investigate the need to obtain from FWC a conservation permit or temporary exclusion permit, if the project will impact gopher tortoises, their burrows, or their habitat. Fourth, GREC must avoid impacts to bald eagle nests, where possible. Where impacts are unavoidable, GREC must obtain from FWC the information necessary for an FWC eagle-nest-removal permit and must implement the minimization and conservation measures identified in the FWC Bald Eagle Management Plan. If nests occur prior to or during construction, GREC must make efforts to avoid construction activities during nesting season or when eagles are present at other times. Fifth, whenever practical, GREC must avoid land-clearing and construction during the active breeding season for the wading and crane-like birds protected by Florida Administrative Code Rules 68A-27.003, 68A- 27.004, and 68A-27.005, and, if nesting activities are detected, GREC must monitor the nesting activities during clearing and construction, except, for sandhill cranes, GREC must cease clearing and construction until the nestlings have fledged. Based on the Application, the approvals by reviewing agencies, and all other relevant material, the DEP Report recommends that the Siting Board certify the GREC facility, subject to the attached COCs. Conditions of Certification Dated July 12, 2010, the COCs are general and specific conditions for the construction and operation of the GREC facility. COC General Condition A.VII. provides that certification is "predicated upon preliminary designs, concepts, and performance criteria described in the [Application] or in support of certification." This provision effectively incorporates the Application into the COCs. COC General Condition A.VI.A. incorporates the air permits that GREC must obtain under Title I, Part C, and Title V of the Clean Air Act. This condition provides that a violation of either of these permits, the former of which is a construction permit and the latter of which is an operation permit, is a violation of the site certificate. COC General Condition A.XXIV.A. provides that modifications, amendments, or renewals of the air construction permit or Title V operating permit modify the site certificate, and, in case of conflict, the more stringent provisions control. COC Specific Condition B.I.D. provides that fly ash may be used as a soil supplement, after initial testing and DEP approval, or transported offsite and disposed of in a permitted landfill. COC Specific Condition B.I.D.6. requires reasonable precautions when loading, unloading, and transporting fly ash to control fugitive emissions. COC Specific Condition B.III incorporates the five items addressed by the FWC in June 10, 2010, letter, which is detailed above. COC Specific Condition B.III.C. requires: Prior to clearing and construction, the licensee shall conduct species-specific surveys for all listed species that may occur within the certified area The results of those detailed surveys shall be provided to the FWC and coordination shall occur with the FWC and appropriate permitting agency on proposed impact mitigation methodologies. COC Specific Condition B.IV. incorporates all but one of the items addressed by the Suwannee River Water Management District. COC Specific Condition B.IV.A. allows GREC to withdraw 1.4 million gallons per day when the plant is fully operational, but there is no provision conditioning this withdrawal on an equal reduction in withdrawals by GRU. The materiality of this omission is revealed by the water management district's staff report, which is attached to the COCs. The staff report anticipates that a COC that "will reduce allocated quantities for Deerhaven . . . by 1.4 [million gallons per day]." If the GREC site certificate is not conditioned upon an offsetting reduction in groundwater withdrawals by GRU, the water management district's approval cannot be assumed. Other Findings Wildlife Phillip W. Simpson, wildlife ecologist and chief scientist of Environmental Consulting and Technology, Inc., performed wildlife surveys on the GREC site in Spring 2009 and late Summer/early Fall 2009, using standard FWC methodology, including a desktop review of the literature in advance of a survey. Mr. Simpson found one abandoned burrow, formerly occupied by a gopher tortoise. He found five listed, wetlands- dependent species elsewhere on the GRU site: alligator, little blue heron, snowy egret, white ibis, and wood stork. The GREC site is largely unavailable for wildlife use and has little potential for future wildlife use. Anthropogenic alterations to onsite natural systems have been extensive and persistent, as long-term silviculture was replaced by the uses associated with the construction and operation of a large power- plant complex featuring a coal-powered generator. At this stage, GREC, its consultant, and FWC have adequately identified actual and potential wildlife that may use the site and actual and potential wildlife habitat. Intervenor's major objection is to the post- certification, preclearing wildlife survey required by FWC and the COCs. This objection is misplaced. The post-certification survey is not taking the place of pre-certification surveys of a scope reasonable to the conditions prevailing at the site. A post-certification, preclearing survey for this fenced site adjacent to the intense uses associated with a power plant complex is a sensible precaution for the gone-today, here- tomorrow quality of wildlife utilization, primarily by birds. Other FWC-derived COCs amply address the unlikely contingency of a late discovery of probable impacts to wildlife by requiring coordination with FWC and adding specific provisions for gopher tortoises, eagles, wading birds, and crane-like birds. GREC has provided reasonable assurance that the construction or operation of the facility will not cause adverse impacts to any listed wildlife species or their habitat. Fire The wood piles present a risk of fire from spontaneous combustion. Microbial metabolic action within the pile can generate sufficient heat to cause the wood pile to combust. The primary safeguard against this risk is proper fuel management to minimize the heat buildup within the pile. One way to manage the fuel for fire safety is to mix the wood piles to aerate the piles and prevent hot spots. Another way to manage the fuel is to ensure that the fuel is not allowed to remain in the pile too long. GREC's first-fuel-in, first-fuel-out policy limits the age of any part of the wood pile. The implementation of this policy is further assured by the fact that the fuel loses heat value over time, so GREC will gain more burn for the dollar by combusting the fuel sooner, rather than later. The ratio of stored fuel to combustion rates suggests that all fuel will be turned over within 20 days--probably sooner, after the late revision lowering the automatic stacker/reclaimer pile by 25 feet, which is described immediately below. Anecdotal evidence suggests that 20 days' residence in the wood pile is well short of the age of fuel that has spontaneously combusted in piles in the past. The stormwater management system will also enhance fire safety by draining rainwater and runoff from the piles and discouraging the ongoing saturation of the fuel piles. Excessive, intermittent saturation of the pile may encourage the microbial activity that can lead to combustion. As part of the local review that took place for the GREC facility, Gainesville Fire Department representatives met three times with GREC representatives to address fire safety, as the Development Review Board of the City of Gainesville reviewed the GREC proposal. As a result of these meetings, GREC agreed to a number of changes to assure substantial compliance with the National Fire Protection Association (NFPA) standards for the management of wood storage areas. As noted above, one change after consultations with the fire department was to reduce the automatic stacker/reclaimer pile from 85 feet to 60 feet. This reduces the risk of fire by making it easier to mix the entire pile and reduces the volume of fuel stored onsite and, thus, the time that that the fuel may remain unused in the wood pile. Secondarily, this change also reduces the volume of fuel available to burn in an unintended fire. To conform to NFPA standards, GREC also agreed to place low barrier walls between the fuel piles; to drive stakes around the perimeter of the piles, so inspectors could more easily check that the piles are not migrating or expanding; and to insert temperature probes into the piles to allow timely detection and elimination of hot spots that might otherwise develop into fires. A revised site plan, as reflected in Exhibits 50A, 50B, and 50C, incorporates the barrier walls and perimeter stakes identified above, as well as the layout of the fire main and fire hydrants that loop the fuel storage area and some access issues for firefighting equipment, which may weigh as much as 30 tons. Subject to the addition of COCs incorporating these fire-safety changes that followed consultation with the Gainesville Fire Department, GREC has provided reasonable assurance that the operation of the facility will not cause adverse impacts from the risk of fire in the wood piles. Air Impacts NOx and SO2 NOx and SO2 emissions are regulated for a number of reasons. NOx combines with VOCs to form ozone, so regulatory efforts to limit ozone focus on NOx, and SO2, itself a threat to human health, is regulated as a precursor to PM2.5. NOx and SO2 also combine to form acid rain. The BFBB is responsible for all of the SO2 produced at the GREC facility, which is 171 tpy. The BFBB is responsible for nearly all of the NOx produced at the GREC facility--416 tpy. An emergency generator and fire pump engine add another 1.72 tpy of NOx, for a total of 418 tpy of NOx. On July 12, 2010, DEP issued a permit to GRU imposing enforceable and permanent reductions on Deerhaven Unit 2's emissions of NOx and SO2--418 tpy of the former and 171 tpy of the latter. These reductions were achieved by GRU's installation of more effective pollution control technology. Under NSR/PSD, GREC may net out its emissions of NOx and SO2 by taking into account these offsetting GRU reductions because GREC and GRU constitute one major stationary source, under NSR/PSD permitting. Offsetting the increased emissions of GREC with the decreased emissions of GRU is authorized by the proximity of the two operations and their common operational control. Specifically, GRU controls GREC's operations through their power purchasing agreement, which gives GRU the authority to dispatch the power generated by the GREC facility, to determine when the biomass plant will start up and shut down, to control the amount of electricity that the GREC biomass plant will produce while operating, and the voltage of such electricity. GRU will also supply the switchyard and transmission lines by which GREC-produced power will enter the power grid and will distribute GREC-produced power among GRU customers. GRU will also supply the natural gas that GREC requires for start up and the electricity that GREC requires for start-up and stand-by operations. GRU even agreed to reduce its groundwater withdrawals by 1.4 million gallons per day, so GREC could withdraw an equal amount of groundwater for its operations. Contrary to Intervenor's contention, this aggregate treatment of GRU and GREC is not a legal fiction designed to circumvent BACT under the NSR/PSD program. On these facts, it would be much easier to prove that the independence of GREC is a legal fiction and that GREC serves as GRU's contractor, ushering the biomass plant through certification, permitting, the acquisition of supplier contracts, and start up, perhaps then to sell it to GRU at the same late stage that GREC sold the Nacogdoches plant. But whatever the precise relationship between the two entities is, or proves to be, at this stage, without doubt, GRU controls GREC. Contrary to Intervenor's contention, the emissions reduction achieved by GRU at Deerhaven cannot somehow be disregarded in this case and "banked" as a gain in achieving cleaner air. From all appearances, GRU pursued this emissions reduction--and certainly the permit modification enforcing the emissions reduction against GRU permanently--for the same reason that it agreed to reduce its groundwater withdrawals. The reason is not an abundance of good will among corporate partners working shoulder to shoulder in providing America's power needs or a gestalt moment of environmental awareness. GRU effected this emissions reduction as a strategic decision to enable GREC to come online sooner and provide GRU with a reliable source of power from a plant much newer than any that it has in place at Deerhaven. This is the economic reality of the closer-than- armslength relationship that exists between GRU and GREC. The netting of NOx and SO2 emissions means that GREC effectively emits no such pollutants. But to put GREC's offset emissions into context, Deerhaven Unit 2 produces roughly 2.5 times the power that the GREC plant will produce. Even after the July 2010 emission reductions, Deerhaven Unit 2 is permitted to emit 3381 tpy of NOx emissions and 8005 tpy of SO2 emissions. If the GREC plant were scaled up to Deerhaven Unit 2's capacity, the GREC biomass plant would produce about one-third as much NOx and one-twentieth as much SO2. Nothing in the record suggests that GREC's relatively low emissions of NOx and SO2--even without regarding to netting--presents a significant risk to human health or the environment. GREC has provided reasonable assurance that the operation of the GREC facility will not cause adverse air impacts in the form of NOx and SO2 emissions. 2. Hazardous Air Pollutants Hazardous air pollutants (HAPs) are identified and regulated under NESHAP. The EPA has designed numerous compounds as hazardous air pollutants, including HCl, HF, certain metals, and various organic compounds, including dioxins, which Intervenor has elected to treat separately and are considered in the next subsection. Based on the information contained in the Application, the potential emissions by the GREC facility's emissions of HCl and HF, as well as total HAPs, were sufficiently high to trigger MACT case-by-case review. In Appendix A of the Application, the HCl and HF emissions were projected to be 36 tpy and 71 tpy, respectively, and total HAPs were 114 tpy. However, after DEP representatives advised GREC representatives that their HCl and HF projections seemed very high, based on their experience with comparable facilities, GREC representatives met with representatives of the boiler manufacturer, Metso, to determine if they could implement more stringent emission control technology to reduce HAPs emissions sufficiently to avoid triggering MACT case-by-case review, which would have added several months to the review process. On February 2010, GREC presented to DEP a revised set of projections of HAPs emissions that were just beneath the thresholds calling for MACT case-by-case review, which are 10 tpy for any single HAP and 25 tpy of all HAPS. The revised projections called for 9.72 tpy of HCl and HF, each, and 24.7 tpy of all HAPs. GREC justified these revised projections by several means. First, Metso reconsidered the chlorine and fluorine concentrations in the clean woody biomass to be received by the GREC facility, reevaluated the chemical reactions, and reduced its earlier assumptions. Second, Metso and GREC selected a more effective sorbent, trona, which reduces the emissions of HF and HCl. Third, Metso and GREC increased the amount of sorbent to be injected into the flue gas system, which will further reduce emissions of HF, HCl, and SO2. Fourth, Metso and GREC changed the catalyst in the SCR, which will remove HAPs more effectively. Fifth, Metso and GREC increased the size and optimized the design of the fabric filter baghouse, which will further reduce stack emissions of PM, but also HAPs to a lesser degree. These are not paper adjustments, but are actual investments in technology that will cost GREC millions of dollars. Intervenor is skeptical, partly due to the proximity of the revised projections to the regulatory thresholds. Interestingly, the actual projection for HF is much less than 9.72 tpy. Metso and GREC selected 9.72 tpy for HF to allow them some margin of error in the projections. GREC's motivation was obviously to a avoid a sub-threshold breach of a projected emissions limit and the resulting regulatory intervention of DEP. Metso's motivation probably arises from the fact that, to induce GREC to purchase its boiler, Metso provided GREC a guarantee that, at least initially, the boiler will meet these revised HAPs emissions limitations. So, the proximity to regulatory thresholds, at least for HF, is not a ground for suspicion, as Intervenor implies. As revised, the pollution control systems controlled HAPs, and other pollutants, as follows: 1) good combustion practices in the BFBB control PM, CO, VOCs, and HAPs generally; the fabric filter baghouse controls emissions of PM10, PM2.5, and HAPs; 3) clean biomass fuel, reaction with alkaline fly ash, and the DSI control SO2 and SAM; 4) the ammonia-based SCR controls NOx, VOCs, and HAPs generally; and 5) high-efficiency drift eliminators in the cooling tower control PM. The last factor supporting the revised HAPs projections is that the GREC facility will monitor a wide range of HAPs, as well as PSD pollutants, in accordance with the following program: 24-hour, 30-day, and 12-month continuous emission monitors (CEMS) for SO2 and NOx; an initial and annual stack test for SAM; a 30-day CEMS for CO; an initial stack test and 12-month CEMS for HCl and HF; an initial and annual stack test and 12-month CEMS for the HAPs projected to total 24.7 tpy; an initial and annual stack test for PM/PM10; and an initial and annual stack test for visible emissions and VOCs. Finally, the GREC facility's HAPs emissions are offset by decreases in emissions of HCl and HF, as well as SAM and mercury, as a result of the enhanced pollution control technology adopted by GRU at Deerhaven. Although these reductions, which are all greater than the emissions of these pollutants by the GREC facility, are not enforceable, for the certification case, they are relevant in assessing the air impacts from the GREC facility. Subject to the addition of COCs incorporating these revisions in pollution control technology, including the above- described CEMS, GREC has provided reasonable assurance that the operation of the GREC facility will not cause adverse air impacts in the form of HAPs, including HF, HCl, and total HAPs. 3. Dioxins Dioxins are compounds that result from the combustion of chlorine-containing materials, including wood. The family of "dioxins" includes furans and polychlorinated biphenyls (more commonly known as PCBs), which all are within the family of persistent organic pollutants. Common sources of dioxins include boilers, electrical power plants, municipal and medical waste incinerators, crematoriums, cement kilns, forest fires, household fireplaces, cigarette smoking, pulp production, and open burning. Dioxins have been associated with cancer and disorders of the immune, skin, digestive, and reproductive systems, where dioxins may act as endocrine disruptors. Work with rats suggests that a major effect of excessive dioxin exposure in utero is upon the reproductive system of the fetus. Dioxins are persistent. Their half lives in the environment range from 30 to 40 years. Because they are hydrophobic and accumulate in fatty tissue, dioxins enjoy half lives of 7-12 years in humans. Humans acquire dioxins by breathing, skin contact, consuming water, consuming food, breastfeeding, and transplacental movement while in utero. The last three means are the principal routes of human exposure. The virtually safe dose, or reference dose, for dioxins is low: one picogram per kilogram per day. One picogram is one-trillionth of one gram, although an EPA work in progress may lower this reference dose to 0.7 picograms per kilogram per day. For the late 1990s, the EPA estimated that the average American acquired 6-10 picograms per kilogram per day, later reducing this estimate to 6-8 picograms per kilogram per day. The EPA estimate for children, including breast-fed infants, is five to seven times higher, around 40 picograms per kilogram per day. This is about 60 times higher than the virtually safe dose. The trends for dioxin levels are good. In its 2006 reassessment of dioxin, the EPA reported that dioxin levels in the environment had decreased by over 90 percent since the late 1980s. Over roughly the same period, the Centers for Disease Control reported that dioxin concentrations in human blood had decreased 80 percent, although decreases in dioxin concentrations in human fatty tissue over the same period of time are likely less. To some extent, the pollution control equipment will limit dioxin emissions, especially the redesigned fabric baghouse and SCR catalyst. Also, the temperature of the air leaving the stack will be about 310 degrees--90 degrees below the temperature at which dioxins form. But dioxin emissions are not explicitly addressed in the certificate and air construction permit. Although the 24.7 tpy limit on HAPs applies to dioxins, which are HAPs, this limit would provide little in the way of assurance as to most dioxins. The reason for the failure to address dioxins for the GREC facility is that it will not emit them in significant amounts. ECT principal engineer, Thomas Davis, who has considerable experience in air pollution control technology, analyzed the potential for dioxin emissions from the GREC boiler. Mr. Davis found five fluidized bed boilers for which relevant data were available on the rate of dioxin emissions. He then applied the emissions rate to the GREC boiler. Mr. Davis determined that the GREC boiler will likely emit .11 grams per year of all dioxins and about .012 grams per year of 2,3,7,8 TCDD, the most potent dioxin. Expressed in another way, the .11 grams per year of total dioxins emitted by the GREC boiler is 110,000,000,000 picograms per year or 301,369,860 picograms per day. If the average person--young and old--weighs 50 kilograms, this emission rate translates to about 6 million picograms per kilogram per day. If the population of Alachua County were 250,000 persons, then the daily exposure, without regard to dispersion patterns, would be 24 picograms per day. For many reasons, 24 picograms of dioxins per kilogram per day of exposure represents only a starting point in the calculations necessary to grasp the limited extent of the dioxin exposure posed by the GREC boiler. An adjustment of one order of magnitude is suggested by the fact that Mr. Davis calculated the emissions rate of most toxic 2,3,7,8 TCDD at one- tenth the rate of the dioxins family. This means that the most toxic dioxin is produced at the rate of only 2.4 picograms per kilogram per day. An even larger adjustment is required because the GREC biomass plant will displace substantial open burning that presently takes place in North Florida. The result will be a large net reduction in dioxin emissions. How much and over what area is hard to say, partly due to the replacement of dispersed burning with point-source combustion. The record supports an estimate that about half of the biomass to be combusted by GREC would have been open burned. Using this estimate, the open burning of this biomass would have produced dioxin emissions of 3-8 grams per year. GREC has effectively replaced these dioxin emissions with .11 gram per year. The record does not support another adjustment for dioxin exposures based on dispersed emissions of 3-8 grams per year and a point-source emission of .11 grams per year. However, if the dispersed emissions are closer to agricultural areas, due to food consumption as the primary means of consumption, as opposed to inhalation, this adjustment would probably inure to the benefit of GREC. Calculations by two witnesses confirm the insubstantial impact posed by the GREC boiler in terms of dioxins. Mr. Davis also calculated dioxin dispersal patterns for air and deposition and found that the average annual maximum concentration was .000000000149 micrograms per liter of air per and the average annual wet and dry deposition rate was .0000000000206 grams per square meter. These are reassuringly low numbers. Making more elaborate dioxin calculations, Dr. Christopher Teaf, an expert in environmental chemistry, toxicology, and human health risk assessment, performed a large number of calculations in the most conservative manner possible, such as by assuming that all dioxins were 2,3,7,8 TCDD and treating the emissions from the GREC boiler as new emissions (i.e., disregarding the fact that GREC's dioxin emissions displace far greater dioxin emissions from open burning). Dr. Teaf showed that air concentrations and wet and dry deposition rates were well below--usually, by one or more orders of magnitude--recently published EPA regional screening levels for air, water, and soil. Intervenor's argument for COCs to limit dioxin emissions and require a CEMS to detect their presence misses a couple of points. The GREC boiler will result in a net reduction in dioxin emissions, and its netted dioxin emissions are not, themselves, significant. GREC has provided reasonable assurance that the operation of the GREC facility will not cause adverse air impacts in the form of dioxins. 4. Fugitive Emissions Fugitive, non-stack emissions of PM refer to emissions that escape the GREC facility, not emissions that are discharged through the stack. Fugitive PM emissions may escape the facility from the roads, the wood piles, and anywhere that sufficiently fine particles are capable of suspension into the air column and transport offsite. Most of the fugitive PM emissions may be regarded as wood dust, although the fugitive emissions from ash may be regarded as soot. But the risks from fugitive emissions of PM appear to be associated more with their size, than their composition. Inhaled, PM causes respiratory and cardiovascular events, including stroke and heart attack. In the relatively large segment of the population with respiratory distress or asthma- like conditions, inhaled PM exacerbates these background conditions. Recent research is investigating whether PM can cause oxidative stress to human DNA. Not all PM has the same effect on human health. The finer the particle, the greater the risk to human health. Or, as Dr. Teaf prefers to characterize it, the larger the particle, the less the risk to human health. There is no reference dose for PM2.5, and EPA will be requiring Florida to add NSR/PSD review for PM2.5 by May 2011, but this will impose limits on stack emissions, not fugitive emissions. According to Appendix A of the Application and DEP's technical evaluation for the air construction permit, the GREC facility is expected to emit 130.4 tpy of filterable PM and 281.2 tpy of PM10. According to Appendix A, the GREC facility is expected to emit 278.3 tpy of PM2.5. According to Appendix A, these totals include PM fugitive emissions--all from material handling--of 11.6 tpy, 2.3 tpy, and 0.34 tpy. As noted above, material handling encompasses the four means by which fugitive emissions will escape the GREC facility. In contrast to stack PM emissions, fugitive PM emissions do not appear especially responsive to attempts to control them through advanced pollution control technology. For the most part, then, GREC must deal with fugitive PM emissions with operational elements, usually in the form of best management practices (BMPs). The air construction permit section 2, specific condition 11 prohibits any person from allowing the emissions of unconfined PM from any activity "without taking reasonable precautions to prevent such emissions." The air construction permit technical evaluation includes Tables 16 and 17, which are BMPs adopted by GREC for wood pile management and fugitive dust emissions, respectively. GREC must update these BMPs prior to start up and include them in the Title V operating permit that it must later obtain. Table 16 requires GREC to manage the wood piles to avoid excessive wind erosion, such as by wetting the pile as necessary and avoiding contouring the pile on windy days. Table 17 requires the covering or partial enclosing of fuel conveyor systems and drop points, as well as the enclosure of the hoppers where trucks dump their loads. All enclosed areas will have local ventilation and fabric filter dust collectors. All major roads at the facility must be paved and swept and wetted, as necessary to minimize fugitive dust emissions. GREC also controls fugitive PM emissions by ensuring that the fly ash and bottom ash are handled in a way that minimizes the release of dust. If trucks dump extra fine woody material, screens will separate such fines because they have a higher value as potting medium. Given the projected moisture content of 50 percent and the size of the chips, the potential for fugitive dust from the wood piles may not be great. Much of the fugitive emissions from the GREC facility will be captured by existing vegetation, on the south, west, and north of the GREC site. To the east is the GRU Deerhaven plant complex. Most of the dust will fall on the surrounding GRU site, especially along the south fenceline, according to dispersal modeling done by Mr. Davis. Some will fall on the county public works site to the west. Relatively little of the dust will make it south to U.S. 441 or further south to the nearest residential area. By way of comparison, Mr. Davis estimated that forest wildfires produced one order of magnitude more PM and PM2.5 than GREC will emit. Subject to the addition of COCs incorporating these BMPs and operational elements for the control of fugitive PM emissions, GREC has provided reasonable assurance that the operation of the GREC facility will not cause adverse air impacts in the form of fugitive PM emissions. Need for Facility Balanced Against Environmental Consequences As explained in the Conclusions of Law, the PSC has established the need for the GREC facility, and its determination is an irrebuttable fact in this case. As noted in the Conclusions of Law, the only need analysis in this case is provided by the PSC, pursuant to Section 403.519, but the statutory certification criterion of the broad interests of the public covers the considerations immediately below. Because the certification statute requires balancing and reasonableness, these considerations of broad interests of the public are framed as needs to be balanced against environmental consequences. The construction and operation of this relatively large project will serve regional needs for new employment and business opportunities and thus stimulate the regional and local economies. Biomass suppliers and their vendors and contractors will hire new employees to produce the trimmings and thinnings, process them into wood chips, and transport the chips to the GREC facility. The ripple effect of this economic activity will be felt throughout north Florida as these suppliers purchase new equipment for the production, processing, and transporting of the massive amounts of biomass that the GREC facility will require. The GREC facility will support the large and important pulp industry in north Florida. Leading the world in the production of pulp, the United States produces 30 percent of the world's pulp products. If a country, the southern United States would be the world leader in the production of pulp products. The addition of an important new biomass market will strengthen the alliance of industry, landowners, and markets that helps to secure America's preeminent position in the production of pulp. At the same time, the pricing of biomass material, as compared to traditional timber products, ensures that the newly developed market for biomass will not distort sound silvicultural practices. The highest value timber resources are for poles and veneer, and, in north Florida, suitable timber prices out at about $70-90 per ton. Pulpwood brings about $50 per ton. As boiler fuel, woody resources yield only about $20 per ton. The relative value of timber as biomass fuel is thus sufficiently low to deter the conversion of standing timber for this purpose. Instead of undermining sound silvicultural practices, the new market for biomass materials will enhance the viability of forestry resources and thus serve regional environmental needs. By requiring sustainable silviculture and rewarding good stewardship among its biomass suppliers, GREC promotes the health of north Florida's vast timber resources and increases the natural functions served by these resources, when compared to silvicultural practices that do not conform to these standards. The creation of a large biomass market will serve the broad public interest by slowing or reversing recent losses of timberland. Less than half of the timber plantation harvested in the past ten years has been replanted. The conversion of even short-rotation timberland to urban uses is a serious problem, even in north Florida, in terms of impacts to natural resources, such as groundwater and wildlife habitat. The GREC facility provides new incentives for replanting. On a smaller scale, the GREC facility will provide incentives to landowners who selflessly replant more valuable timber products, in terms of natural functions, such as longleaf pine, that may offer less economic return than other products that provide the opportunity for quicker harvest. One such person, Virgil Allison of Crescent City, testified that he recognized that he would not live to see the economic benefit of his recent replanting of longleaf and loblolly pine, but he would have benefitted, if the GREC facility were already in operation, from the creation of a market for the nearly 100 acres of underbrush that he recently cleared in order to create better growing conditions for his forest. Not only does the clearing of underbrush produce better growing conditions, it also removes the fuel for catastrophic, unnaturally intense forest fires. Together with thinning, clearing of underbrush reduces the risk of, and damage from, invasive pests. Also among the broad public interest served by the GREC facility is reduced consumption of valuable landfill space that will result from burning biomass, rather than landfilling it. Other needs, such as the diversification of fuel supplies are within the matters addressed by the PSC. The sole environmental consequence that requires a revision of the COCs arises from an apparent oversight by DEP. In the attached COCs derived from the Suwannee River Water Management District, DEP has incorporated the water management district's permission for GREC to withdraw 1.4 million gallons per day of groundwater, but has neglected to incorporate the water management district's requirement, discussed above, that GRU reduce its groundwater withdrawals by an equal amount. This omission converts the one-stop permitting of site certification to no-stop permitting, as least as to groundwater withdrawals, and, uncorrected, would allow GREC to withdraw a large volume of groundwater, essentially over the objection of the water management district and without analysis by DEP or the Siting Board. Subject to the addition of a COC conditioning GREC's right to withdraw 1.4 million gallons per day of groundwater on an enforceable revision of a GRU certificate or permit to reduce its right to withdraw an equal amount of groundwater, GREC has provided reasonable assurance that the need for the GREC facility, considering the broad public interests that will be served by the facility, outweighs any adverse environmental consequences of the facility.
Recommendation It is RECOMMENDED that, subject to the conditions set forth in the preceding paragraph, the Siting Board enter a final order granting the site certificate for the construction and operation of the GREC facility. DONE AND ENTERED this 1st day of November, 2010, in Tallahassee, Leon County, Florida. S ROBERT E. MEALE Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 1st day of November, 2010. COPIES FURNISHED: Lea Crandall, Agency Clerk Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Tom Beason, General Counsel Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Mimi Drew, Secretary Department of Environmental Protection Douglas Building 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 David S. Dee, Esquire Young Van Assenderp, P.A. 225 South Adams Street Suite 200 Tallahassee, Florida 32301-1700 Toni Sturtevant, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Thomas W. Brown, Esquire Brannon, Brown, Haley & Bullock, P.A. Post Office Box 1029 Lake City, Florida 32056-2029 Jennifer Brubaker, Esquire Florida Public Service Commission 2450 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Matthew G. Davis, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Kimberly Clark Menchion, Esquire Department of Transportation 605 Suwannee Street, Mail Station 58 Tallahassee, Florida 32399 Scott Koons North Central Florida Regional Planning Council 2009 Northwest 67th Place, Suite A Gainesville, Florida 32653 David L. Wagner, Esquire 12 Southeast First Street Gainesville, Florida 32601 Jonathan F. Wershow, Esquire 204 Southeast First Street Post Office Box 1260 Gainesville, Florida 32602 Laura Kammerer Bureau of Historic Preservation R. A. Gray Building 500 South Bronough Tallahassee, Florida 32399 Marian B. Rush, Esquire Rush & Glassman 11 Southeast 2nd Avenue Gainesville, Florida 32601 Forrest Watson Department of Agriculture & Consumer Services Division of Forestry 3125 Conner Boulevard Tallahassee, Florida 32399-1650 Patricia Anderson Department of Health Environmental Engineering 4042 Bald Cypress Way Tallahassee, Florida 32399-1742 Marion Joseph Radson, Esquire Office of the City Attorney Post Office Box 1110 Gainesville, Florida 32602-1110 Kelly K. Samek, Esquire Florida Fish and Wildlife Conservation Commission 620 South Meridian Road Tallahassee, Florida 32399 Thomas Bussing 1832 Northwest 11th Road Gainesville, Florida 32605 Mick G. Harrison, Esquire 205 North College Avenue, Suite 311 Bloomington, Indiana 47404
The Issue The issue to be resolved in this proceeding is whether certification should be granted to the Orlando Utilities Commission ("OUC"), Kissimmee Utility Authority ("KUA"), Florida Municipal Power Agency ("FMPA"), and Southern Company – Florida, LLC ("Southern-Florida") for Curtis H. Stanton Unit A at the Stanton Energy Center in Orlando, Florida, in accordance with the pertinent provisions of Sections 403.501 through 403.518, Florida Statutes.
Findings Of Fact OUC is a 28 percent owner of Unit A of the Curtis H. Stanton Energy Center. FMPA is a 3.5 percent owner of Unit A of the Curtis H. Stanton Energy Center. KUA is a 3.5 percent owner of Unit A of the Curtis H. Stanton Energy Center. Southern- Florida is a 65 percent owner of Unit A of the Curtis H. Stanton Energy Center. Stanton Unit 1 (net rating of 440 MW) and Unit 2 (net rating of 446 MW), and associated facilities, are existing certified coal-fired units at the site. Stanton Units 1 and 2 operate under Certification Order PA 81-14, originally issued on December 15, 1982, and supplemented on December 17, 1991, for the addition of Stanton Unit 2. The Certification Order has been subsequently modified in April 1993, July 1995, December 1997, and August 1998. These units went into commercial operation in 1987 and 1996, respectively. The Stanton Energy Center site is certified for ultimate certification of 2,000 MW of coal or natural gas-fired capacity. The Stanton Energy Center site, which is located approximately 10 miles southeast of Orlando, encompasses approximately 3,280 acres in eastern Orange County. Of the 3,280 acres, 1,100 acres have been allocated for development of power generation and support facilities. The proposed Stanton Unit A will be constructed on approximately 60 acres of that 1,100 acres. DEP is an agency of the State of Florida designated as the lead agency for the review and evaluation of site certification applications, in accordance with the various provisions of the Florida Electrical Power Plant Siting Act, Sections 403.501-403.518, Florida Statutes, and related rules cited and discussed elsewhere herein. Notice of the certification hearing was accorded to all parties entitled thereto as well as to the general public. The existing Stanton Energy Center began commercial operation in 1987. It currently consists of two coal-fired units known as Units 1 and 2, two natural draft cooling towers, a cooling water supply pond, a solid waste disposal area, an electrical switchyard, transmission lines, a railroad spur, access roads, and a reclaimed water pipeline. The on-site facilities of the Stanton Unit A project will consist of a General Electric 7FA combined cycle unit consisting of two combustion turbines, two heat recovery steam generators ("HRSGs"), a steam turbine generator, cooling tower, wastewater treatment facilities, fuel oil and water storage tanks, and natural gas delivery and metering facilities. Additionally, a new 230 kV transmission line will be constructed to connect Stanton Unit A with OUC’s existing on-site Stanton Energy Center Substation No. 17. The connecting line will be totally within the certified site. Stanton Unit A will have a total nameplate rating of 791 mega volt amperes ("MVA") and a nominal rating of approximately 633 MW. PSC Need Determination On May 14, 2001, the Public Service Commission issued Order No. PSC-01-1103-FOF-EM determining the need for the proposed combined cycle Stanton Unit A to be constructed at Stanton Energy Center. Scheduling Mobilization and physical construction of Stanton Unit A are scheduled to begin the fourth quarter of 2001, with commercial operation commencing October 2003. Generating Units Stanton Unit A will be a General Electric 7FA combined cycle unit consisting of two combustion turbines, two HRSGs, and a steam turbine generator. The unit will burn natural gas as a primary fuel and will be capable of burning low sulfur No. 2 oil as backup fuel. With the addition of Stanton Unit A, the generating capacity at the Stanton Energy Center will be a nominal 1,519 MW. Transmission Facilities OUC’s existing transmission system consists of 26 substations interconnected through approximately 302 miles of 230 kV and 115 kV lines and cables. The addition of Stanton Unit A will require the construction of a new, on-site, 230kV transmission line to connect Stanton Unit A with the existing on- site Stanton Energy Center Substation No. 17. The total length of the transmission line will be approximately 3,000 feet. The transmission line will be a single-circuit, heavy-duty, single- pole transmission line. The transmission line structures will be steel poles with drilled concrete pier foundations or self- supporting concrete poles. Both structure types will be capable of supporting a double-circuit configuration. In conjunction with the proposed transmission line, the existing OUC Substation No. 17 will be expanded to the west to accommodate the new 230 kV transmission line. The proposed transmission line route will be located entirely within the existing Stanton Energy Center property. Construction of a portion of the line will require clearing approximately 0.4 acres of cypress strand and permanently filling 0.57 acres of herbaceous wetlands. Overall, adverse environmental impacts from the construction of the new transmission line are expected to be minimal. The proposed transmission line has been routed to minimize impacts on wetlands as much as possible. Orange County and OUC have determined that mitigation for such impacts consists of the granting of a conservation easement of in-kind wetlands to offset the wetland impacts. Natural Gas Pipeline Lateral A 4-1/2 mile long, 16-inch lateral to a FGT line in Orange County will provide the natural gas to fuel Stanton Unit A. The pipeline lateral will originate at the crossing of the 26-inch FGT gas supply line and OUC's railroad corridor, which is 2-1/2 miles south of the Stanton Energy Center, and will terminate at Stanton Unit A. OUC owns a 300-foot wide corridor that contains a railroad spur, unimproved maintenance road, and a 230 kV transmission line. The gas pipeline will be installed within this existing corridor. All fuel handling and metering facilities will meet the applicable requirements as specified in Chapter 25-12, Florida Administrative Code, and will meet all applicable requirements of the United States Department of Transportation ("DOT") (49 Code of Federal Regulations, Part 192) as amended by the Materials Transportation Bureau. Wastewater Treatment Process wastewaters consist of oil/water separator effluent, chemical wastes, steam cycle (boiler) blowdown, and evaporative cooling tower blowdown. Oil/water separator effluent will be routed to the existing Stanton Energy Center recycle basin where it will be reused in Stanton Units 1 and 2 flue gas desulfurization and ash systems. Cooling tower and evaporative cooler blowdown will be treated in a new brine concentrator system. The brine concentrator system recovers a large amount of the water in the blowdown and recycles it to the cooling towers. Boiler blowdown from the HRSGs will be routed to the Stanton Unit A cooling tower for reuse. Sanitary wastewater produced during normal plant operations will be collected and routed to a new septic system and tile field. The 30 new employees expected to be associated with Stanton Unit A will increase sanitary wastes by approximately 900 gallons per day ("gpd"). Well Field Groundwater withdrawals are currently taken from the two existing on-site, deep wells that serve the Stanton Energy Center. The Stanton Energy Center site is currently authorized to pump up to two million gallons per day ("mgd") for plant service water, demineralization, drinking and sanitary water. This allocation will also supply Stanton Unit A service water, potable water, and demineralization demands. In lieu of using additional groundwater, the Applicants have agreed to diligently and in good faith pursue an agreement with Orange County to transfer up to 8.0 mgd of surface water (including stormwater/surficial groundwater) from the adjacent Orange County Landfill property for use at the Stanton Energy Center facility. Fuel Supply and Storage A new 1.68 million gallon, above-ground fuel oil (No. 2) storage tank will be added at the Stanton Energy Center for Stanton Unit A. The construction, materials, installation, and use of the bulk storage tank will conform to American Petroleum Industry ("API") Standard 650, American Institute of Steel Construction ("AISC"), American Society for Testing and Materials ("ASTM"), National Electric Code ("NEC"), and Occupational Safety and Health Administration ("OSHA") standards. The location of the storage tank is indicated on the Site Arrangement, Figure 2.1-3 of the Supplemental Site Certification Application, Volume 2. Fuel will be delivered to the vertical oil storage tanks by tanker truck and/or rail. The containment area for each fuel oil tank is provided by an earthen berm. The berm is designed to meet the DEP requirements to provide containment for both 110 percent of the storage capacity of the largest tank within the impoundment and a sufficient allowance for the design (10 year, 24 hour) rainfall storm event (approximately 7 inches). In addition, the containment area is constructed with a synthetic liner. The liner is sufficiently impermeable to ensure that no oil can escape by infiltrating through the liner and soil and into surface or groundwaters, as required by DEP regulation. The fuel oil truck unloading station is located northwest of the existing coal units, as indicated on the Site Arrangement. The station spill containment consists of above- ground and double-walled below grade piping running to the storage tanks outside and inside the earthen berm area. The station also includes a manually operated isolation valve and a check valve immediately adjacent to the unloading station. This allows immediate isolation of the piping system from a spill at the delivery truck and prevents backflow spillage of oil from the system. The existing Spill Prevention, Control and Countermeasures Plan and Facility Response Plan will be modified as required to include Stanton Unit A facilities. Foundation Stability The strata beneath the Stanton Energy Center site to a depth of about 200 feet are divided into five stratigraphic layers: a surficial sand layer, an intermediate cohesive layer, a lower sand layer, a lower cohesive layer, and limestone bedrock. The surficial sand layer consists of 32 to 71 feet of heterogeneous arrangement of loose to dense, gray to brown sand, silty sand, and clayey sand, with an intermittent thin clay layer. Underlying the surficial layer is 4 to 15 feet of soft to stiff, gray to brown highly plastic clay, sandy clay, and silty clay, with occasional shell fragments. The intermediate cohesive layer varies in thickness from 78 to 81 feet. Foundations for Stanton Unit A are to be similar to the foundation types utilized for Stanton Units 1 and 2. Heavily loaded, settlement sensitive structures within the existing Stanton Energy Center are supported on deep foundations consisting of friction piling. More lightly loaded structures are anticipated to be supported on shallow footings or mats. The existing Stanton Units 1 and 2 foundations have been performing very satisfactorily since installation. Archeological and Historic Sites In March 1981, the Florida Department of State, Division of Archives, History, and Records Management determined that the existing site did not contain significant archaeological or historical resources. Construction of Stanton Unit A is unlikely to affect any properties listed, or eligible for listing, in the National Register. Land-Use Compatibility The new construction at Stanton Energy Center will not generate sufficient noise to negatively affect any local residents. Construction noise levels for foundation construction and equipment erection are estimated to be approximately 55 decibels ("dBA") at the north property boundary and approximately 45 dBA at the nearest residence. The site clearing stage noise emissions are anticipated to be 5 dBA less than the equipment erection noise emissions. Noise levels during operation will decrease from that which is expected during site clearing and construction. The construction noise associated with Stanton Unit A is not anticipated to be significant. The undeveloped surrounding area, as well as the vegetative buffer and physical distance to the nearest residences, will all mitigate the intermittent disturbance. Traffic impacts of Stanton Unit A construction are expected to have a slight impact on area roadways. However, this temporary impact will not have any lasting, significant adverse impact on the roadways and intersections in the vicinity of the Stanton Energy Center. During operation of Stanton Unit A, no significant impacts on area traffic are expected and no new off- site roads or road improvements will be required. Socioeconomic Impacts The construction of Stanton Unit A will have a positive impact on the local economy, providing approximately 300 jobs at the peak of construction during the 24-month construction period. The vast majority of the construction work force is expected to be filled by workers already residing in the study area, which consists of Brevard, Osceola, Orange, Lake, and Seminole Counties. The estimated construction payroll is $28 million (in 2001 dollars). There will be no significant, long-term increase in demand by the Stanton Energy Center for public services, either directly or indirectly, through an increase in population attributable to increased staffing. While the influx of the construction work force may increase the demand for services from local governments and nearby service providers, representatives of these entities have indicated that they have more than enough service capacity to accommodate the construction work force. Air Quality The Stanton Unit A combustion turbine is subject to pre-construction review requirements under the provisions of Chapter 62-212.400, Florida Administrative Code. The Stanton Energy Center is located in Orange County, an area designated as an attainment area for all criteria pollutants in accordance with Rule 62-204.360, Florida Administrative Code. The Stanton Unit A combustion turbine is subject to review under Rule 62-212.400, Florida Administrative Code, Prevention of Significant Deterioration ("PSD"), because the potential emission increases for particulate matter/particulate matter less than 10 microns ("PM/PM10"), carbon monoxide ("CO"), volatile organic compounds ("VOC"), sulfur dioxides ("SO2"), and nitrogen oxides ("NOX") exceed the significant emission rates given in Chapter 62-212, Table 62-212.400-2, Florida Administrative Code. The PSD review consists of a determination of Best Available Control Technology ("BACT") for PM/PM10, CO, VOC, SO2 and NOX, an air quality impact analysis, and an assessment of the Stanton Unit A Project’s impact on general commercial and residential growth, soils, vegetation, and visibility. The Stanton Unit A combustion turbine will increase emissions of six pollutants at levels in excess of PSD significant amounts: PM10, CO, SO2, NOX, VOC, and sulfuric acid mist ("SAM"). PM10, SO2, and NOX are criteria pollutants and have defined national and state ambient air quality standards ("AAQS"), PSD increments, and significant impact levels. CO and VOC are criteria pollutants and have only AAQS and significant impact levels defined. The only Class I area near the Stanton Energy Center is the Chassahowitzka National Wildlife Refuge, located approximately 140 km west-northwest of the site. An air quality analysis, undertaken in accordance with computer modeling procedures approved in advance with the DEP, demonstrated that the Stanton Unit A Project resulted in no significant air quality impacts in the area surrounding the proposed facility. Therefore, further air quality impact studies, which would include AAQS and PSD increment impact analyses for these pollutants, were not required. Under the Clean Air Act, the Stanton Unit A project would be classified as a "process unit" of hazardous air pollutants ("HAP"), thereby requiring an analysis to determine if the Stanton Unit A Project would have a potential to emit 10 tpy of any one HAP or 25 tpy of any combination of HAPs. Maximum Achievable Control Technology ("MACT") applicability calculations were performed and revealed that no individual HAP has a potential to be emitted in excess of 10 tpy and no combination of HAPs has a potential to be emitted in excess of 25 tpy from operation of the Stanton Unit A Project. It was determined that the need to apply MACT is therefore not required pursuant to Section 112 of the Clean Air Act. The Stanton Unit A combustion turbine’s air emissions are expected to cause only minimal or insignificant impacts on vegetation, soil, or wildlife. A regional haze analysis was performed which showed that operation of the Stanton Unit A combustion turbine will not result in adverse impacts on visibility in the vicinity of the Chassahowitzka National Wildlife Refuge. Short-term increases in the labor force during the construction phase will not result in permanent or significant commercial and residential growth in the vicinity of the Stanton Unit A Project. Any resulting air emissions from residual growth will not be significant because the increase in population due to the operation of the Stanton Unit A Project will be very small. BACT and Emission Rates A BACT analysis was required as part of the PSD review. The BACT review for the Stanton Unit A combustion turbine was conducted for PM/PM10, CO, NOX, SO2, and VOC. DEP determined that BACT for the Stanton Unit A combustion turbine particulate matter (PM/PM10) emissions was good combustion controls during natural gas and fuel oil firing. The BACT for the particulate emissions from the Stanton Unit A cooling tower is determined to be the use of drift eliminators with a control efficiency of 0.002 percent. DEP determined that BACT for the Stanton Unit A combustion turbine for CO emissions was good combustion controls to achieve an emission limit of 17 ppmvd at 15 percent O2 on a 24- hour average for normal operation on natural gas and 14 ppmvd at 15 percent O2 for normal operation on fuel oil. An oxidation catalyst will be installed, if necessary, to meet these emission limits. DEP determined that BACT for the Stanton Unit A combustion turbine for NOx emissions consists of using dry low NOX burners with selective catalytic reduction ("SCR") to achieve an emission limit of 3.5 ppmvd at 15 percent O2 when burning natural gas. This limit shall apply whether or not the unit is operating with its duct burner on and/or in power augmentation mode. The emissions of NOX with the combustion turbine operating on fuel oil shall not exceed 10.0 ppmvd at 15 percent O2. DEP determined that BACT for the Stanton Unit A combustion turbine for VOC emissions is good combustion controls to achieve an emission limit of 2.7 ppmvd at 15 percent O2 with the CT firing fuel oil. The emission limit is 3.6 ppmvd at 15 percent O2 with the CT firing natural gas (without power augmentation) and 6.3 ppmvd at 15 percent O2 (with power augmentation). DEP determined that BACT for the Stanton Unit A combustion turbine for SO2 consists of firing natural gas and up to 1,000 hours per consecutive 12-month period of 0.05 percent sulfur fuel oil. DEP determined preliminarily that the Stanton Unit A Project will comply with all applicable state and federal air pollution regulations provided that the BACT determination is implemented. Industrial Wastewater The Stanton Energy Center has five major sources of wastewater. These are sanitary wastes, oil/water separator effluent, cooling tower blowdown, chemical wastes and boiler blowdown. Oil/water separator effluent will be routed to the existing Stanton Energy Center recycle basin where it will be reused in Stanton Units 1 and 2 flue gas desulfurization and ash systems. Cooling tower and evaporative cooler blowdown will be treated in a new brine concentrator system. Sanitary wastes will be routed to a new septic tank/tile field system. Boiler blowdown from the HRSGs will be routed to the Stanton Unit A cooling tower for reuse. See also Findings of Fact 14 and 15. It is estimated that 0.4 mgd of cooling tower blowdown, resulting from operation of Stanton Unit A, will be returned to the cooling tower as makeup water. Remaining wastewater streams will be reused or recycled at the Stanton site. The HRSGs and pre-boiler piping will be chemically cleaned during commissioning. The steam generators will also be periodically cleaned during the life of the unit. The acid and alkaline cleaning wastes resulting from this process will be immediately neutralized on-site. The treated cleaning wastes will be disposed of off-site by a licensed contractor. Waste Disposal Stanton Unit A will generate no solid waste from the energy generation process. Stanton Unit A will generate solid waste associated with the brine concentrator treatment of the cooling tower blowdown. This waste is combined with the solid discharge waste produced by the treatment of the blowdown from Stanton Units 1 and 2. Therefore, the addition of Stanton Unit A will require no new landfills or solid waste disposal areas. Waste oil will be generated by Stanton Unit A operation. Three processes generate waste oil: combustion turbine cleaning, false starts of the combustion turbines, and oil/water separator operation. This waste oil is hauled off-site as needed by a licensed contractor for ultimate disposal. Surface Water Hydrology and Water Quality Impacts The Stanton Unit A project is designed to be a zero discharge facility for industrial wastes. Stanton Unit A will use a mechanical draft cooling tower; makeup water will come from the existing Makeup Water Supply Storage Pond, which receives treated effluent from the Orange County Easterly Water Reclamation Facility. Stanton Unit A will require an additional 2.91 million gallons of treated wastewater per day for water lost due to evaporation and drift and for blowdown. Cooling tower blowdown will be directed to and treated in a cooling tower blowdown treatment system. There are no sizeable surface water bodies on the Stanton Energy Center site. Small segments of the Cowpen Branch and the Hart Branch extend into the site; however, these small streams are within the buffer zone on the site that will not be affected by construction activities. Runoff from the construction area will be contained in a collection basin. Construction of Stanton Unit A will have no significant impact on the Cowpen Branch, the Hart Branch, or on-site wetlands. Site preparation for construction of the proposed Unit A facilities will occur in an area that was used for construction laydown for Stanton Unit 2 construction. The Stanton Unit A storm water drainage system was designed to comply with all applicable federal, state, and local regulations regarding discharge into surface waters. Runoff from areas not disturbed by construction or operations will be directed to natural drainage systems within the area. Runoff from disturbed areas will be directed to a drainage system and then routed to the stormwater pond north of the Stanton Unit A location. Groundwater Hydrology and Impacts from Water Withdrawal During construction, dewatering will be necessary for construction of heavy equipment foundations, underground utilities, circulating water lines, and miscellaneous pits and sumps. Dewatering activity is expected to last no more than 120 days with total withdrawal of less than 1 mgd. Discharge from dewatering activities will be sent to the Stanton Unit A storm water pond. The dewatering effects will be temporary and limited to the power block area. The groundwater system will return to its original state after completion of the dewatering. The proposed Stanton Unit A Project will not cause any saltwater intrusion in the area. The Stanton Energy Center currently uses groundwater withdrawn from two 850 gallon per minute ("gpm") Floridan Aquifer wells. Stanton Units 1 and 2 are currently authorized to use approximately 2 million gpd of groundwater. In lieu of using additional groundwater for Stanton Unit A, the Applicants have agreed to diligently and in good faith pursue an agreement with Orange County to transfer up to 8.0 million gallons per day of surface water (including stormwater/surficial groundwater) from the adjacent Orange County Landfill property for use at the Stanton Energy Center facility. Ecological Resources The Stanton Energy Center occupies 3,280 acres. Stanton Units 1 and 2 currently occupy approximately 310 acres of land and approximately 1,100 acres have been scheduled for power development. The Stanton Unit A facilities will be constructed on the same area used for construction equipment/materials laydown during construction of Stanton Units 1 and 2; the area was, thus, previously disturbed. This 60-acre area is generally maintained grassland, but will be cleared and grubbed for construction of Stanton Unit A. The proposed new transmission line will connect Stanton Unit A with OUC’s existing Stanton Energy Center Substation No. 17. The land between Stanton Unit A and Substation No. 17 is mostly undeveloped/native area dominated by pine flatwoods and cypress wetland vegetative communities. In addition to the undeveloped/native area, there is an access road that was once used as an alternative route to the Stanton Energy Center. The surface water bodies crossed by the transmission line corridor are limited to an artificial surface water (borrow ditch) and isolated cypress strand and herbaceous wetland. The anticipated impacts on these water bodies were minimized to the extent practicable by the siting of the corridor. Approximately 0.57 acres of jurisdictional wetlands will be impacted. An Environmental Resource Permit application has been submitted to the United States Army Corps of Engineers for construction of the transmission line. The Stanton Energy Center, including the proposed Stanton Unit A, will not discharge effluent from the site into surface waters; no impacts to aquatic life from such discharge are, therefore, expected. A review of potential impacts to threatened and endangered species was conducted based on habitat types that occur at the Stanton Energy Center. Lists of threatened and endangered species obtained from the United States Fish and Wildlife Service and from the Florida Fish and Wildlife Conservation Commission ("FFWCC") were reviewed and field surveys were conducted. No critical habitat for federally listed species occurs on Stanton Energy Center property. Protected species that are known to occur on Stanton Energy Center property include the eastern indigo snake, the gopher tortoise, the Florida pine snake, the Florida scrub jay, the Kirtland's warbler, the American kestrel, the bald eagle, the fox squirrel, the black bear, and the red-cockaded woodpecker. Monitoring of the red- cockaded woodpecker is required by the Conditions of Certification for Stanton Units 1 and 2 and will also be performed for Stanton Unit A. Site preparation will not permanently impact wildlife habitat. However, wildlife species may be temporarily displaced from adjacent communities by the noise, fugitive dust, and activity associated with construction. Impacts from Flooding and Hurricanes The 100-year flood elevations on the Stanton Energy Center property vary from approximately 60 feet mean sea level ("MSL") at the northeast corner of the property to approximately 90 feet MSL at the southwest corner. All Stanton Unit A facilities will be located above the 100-year flood elevation. Noise Impacts Noise emissions attributable to construction activities are highly variable, depending upon the location and operating load of the construction equipment. Noise emissions during site clearing and preparation will be dominated by diesel engine noise. Site clearing and facility start-up will generally result in minimal noise emissions. The one significant noise emission associated with facility start-up will be steam blowout of the HRSG and steam lines. Construction activities will be scheduled during daytime and evening periods (7:00 a.m. to 10:00 p.m.) to the fullest extent possible. Any nighttime construction will be limited to low noise activities as much as possible. Noise emissions are regulated under Chapter 15, Article V, of the Orange County Code. The predicted A-weighted noise emissions will satisfy the code criteria at the nearest residential locations. Traffic All roadways serving the construction and operational traffic of Stanton Energy Center have adequate capacity to handle the increase in traffic generated by construction and operation of Stanton Unit A. A new paved "loop" road will be constructed around the Stanton Unit A generation building and connected to the Stanton Energy Center road system. During Stanton Unit A construction, there will be some traffic congestion. However, this impact will be temporary and will not have a lasting, significant adverse impact on the existing levels of service on affected local roads or highways. To lessen the impact of the construction traffic congestion, OUC will encourage transportation demand management techniques to reduce the number of temporary, construction-related vehicle trips on the road networks. Since construction of Stanton Unit A is expected to have no greater impacts than those resulting from construction of Stanton Units 1 or 2, no additional improvements to roadways or traffic control systems are deemed necessary. Consistency with the Local Comprehensive Plans and Land Development Codes The Stanton Energy Center was initially certified by the Siting Board on December 15, 1982 for an ultimate site capacity of 2,000 MW. Stanton Unit A is consistent with the ultimate certification and the applicable zoning and land use plans of Orange County. As a result, no land use hearing was required for the Stanton Unit A Project because the previously certified ultimate site capacity will not be exceeded and the land required for the construction and operation of Stanton Unit A is within the boundaries of the previously certified site. Therefore, the Stanton Energy Center is consistent and in compliance with the applicable sections of the Orange County Comprehensive Plan, the East Central Florida Regional Planning Council Interim Strategic Regional Policy Plan, the State Comprehensive Plan, and the applicable local land use and zoning ordinances. Solid Waste Solid waste collection and disposal services at the Stanton Energy Center will be coordinated with the appropriate contractors to assure that all applicable regulations are met. Public Services Public services such as police, fire, and emergency medical services are available and sufficient to meet the needs of Stanton Energy Center. Variances Orange County will require no variances for operation of the Stanton Unit A and its associated facilities. Agency Positions and Stipulations In testimony entered at the certification hearing, the DEP, through its expert witness, Hamilton S. Oven, rendered an opinion that the Stanton Unit A Project would comply with all applicable DEP statutes, rules, policies and criteria including, but not limited to, those concerning air quality, water quality, stormwater, wetlands, solid waste, industrial wastewater and domestic wastewater, if the facility is built and operated in accordance with the Department's Conditions of Certification contained in DEP-2. Furthermore, Mr. Oven rendered an opinion that the Stanton Unit A Project can comply with the Conditions of Certification in DEP-2 and recommended that the Stanton Unit A Project be approved. In testimony entered at the certification hearing, the SJRWMD, through its expert witness, James J. Hollingshead, rendered an opinion that the Stanton Unit A Project meets all the standards, rules, and policies of SJRWMD applicable to the Stanton Unit A Project, including compliance with the SJRWMD's reasonable, beneficial use criteria. Accordingly, SJRWMD's staff and the governing board of the SJRWMD recommend certification and approval of the Stanton Unit A Project. The DEP, DOT, Department of Community Affairs ("DCA"), FFWCC, Orange County, and the SJRWMD have recommended certification of the proposed Stanton Unit A Project, including its associated facilities, subject to recommended Conditions of Certification. Those recommended Conditions of Certification are attached to the DEP Staff Analysis Report as Appendix 1. The East Central Florida Regional Planning Council ("ECFRPC") determined that use of the site for this industrial use is consistent with the ECFRPC's Strategic Regional Policy Plan. No state, regional, or local agency recommended denial of certification.
Conclusions For the Orlando Utilities Commission, Kissimmee Utility Authority, and Florida Municipal Power Agency: Tasha O'Dell Buford, Esquire Young, van Assenderp, Varnadoe & Anderson, P.A. 225 South Adams Street Post Office Box 1833 Tallahassee, Florida 32302-1833 For Orlando Utilities Commission: Thomas B. Tart, Esquire Orlando Utilities Commission 500 South Orange Avenue Orlando, Florida 32801 For Southern-Florida, L.L.C.: Lawrence N. Curtin, Esquire Holland & Knight, LLP 315 South Calhoun Street, Suite 600 Tallahassee, FL 32302-0810 For the Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection Office of General Counsel 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 For the St. Johns River Water Management District: Kris H. Davis, Esquire Charles A. Lobdell, III, Esquire St. Johns River Management District Post Office Box 1429 Palatka, Florida 32178-1429 For Orange County: Anthony J. Cotter, Esquire Assistant County Attorney Orange County Attorney’s Office Post Office Box 1353 Orlando, Florida 32801-1353
Recommendation Having considered the foregoing, it is, therefore, RECOMMENDED that the Orlando Utilities Commission, Kissimmee Utility Authority, Florida Municipal Power Agency, and Southern- Florida, LLC, be granted certification, pursuant to Chapter 403, Part II, Florida Statutes, for the location, construction, and operation of proposed Stanton Unit A and its associated facilities, as described in the Supplemental Site Certification Application and as modified by the preponderant evidence of record supportive of the above findings of fact and conclusions of law, and in accordance with the Conditions of Certification, which are incorporated herein and made a part hereof by reference. DONE AND ENTERED this 23rd day of July, 2001, in Tallahassee, Leon County, Florida. CHARLES A. STAMPELOS Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 23rd day of July, 2001. COPIES FURNISHED: Tasha O'Dell Buford, Esquire Young, van Assenderp, Varnadoe & Anderson, P.A. 225 South Adams Street, Suite 200 Post Office Box 1833 Tallahassee, Florida 32302-1833 Preston T. Robertson, Esquire Fish and Wildlife Conservation Commission 620 South Meridian Street, Room 108 Bryant Building Tallahassee, Florida 32399-1600 Cathy Beddell, Esquire Public Service Commission 2540 Shumard Oak Boulevard Tallahassee, Florida 32399 Lawrence N. Curtin, Esquire Holland & Knight, LLP 315 South Calhoun Street Post Office Box 810 Tallahassee, Florida 32302-0810 Ruth A. Holmes, Esquire South Florida Water Management District 3301 Gun Club Road West Palm Beach, Florida 33416 Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard The Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 Charles Lee, Sr., Vice President Florida Audubon Society 1331 Palmetto Avenue, Suite 110 Winter Park, Florida 32789 Kris H. Davis, Esquire Charles A. Lobdell, III, Esquire St. Johns River Water Management District Post Office Box 1429 Palatka, Florida 32178-1429 Andrew S. Grayson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Thomas B. Tart, Esquire Orlando Utilities Commission 500 South Orange Avenue Orlando, Florida 32801 Anthony J. Cotter, Esquire Orange County Attorney's Office 201 South Rosalind Avenue, Third Floor Post Office Box 1353 Orlando, Florida 32801 Sheauching Yu, Esquire Department of Transportation 605 Suwannee Street Hayden Burns Building, Mail Station 58 Tallahassee, Florida 32399-0458 Greg Golgowski, Acting Executive Director East Central Florida Regional Planning Council 631 North Wymore Road, Suite 100 Maitland, Florida 32751 Frederick M. Bryant, Esquire Florida Municipal Power Agency 2061-2 Delta Way Tallahassee, Florida 32303 John J. Fumero, Esquire South Florida Water Management District 3301 Gun Club Road West Palm Beach, Florida 33416 Katherine Manella, Esquire St. Johns River Water Management District Post Office Box 1429 Palatka, Florida 32178-1429 Hamilton S. Oven Department of Environmental Protection 2600 Blair Stone Road, Mail Station 48 Tallahassee, Florida 32399 Kathy C. Carter, Agency Clerk Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000 Teri L. Donaldson, General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000
The Issue Whether Tampa Electric Company's (Tampa Electric) application for site certification of existing Big Bend Generating Station Units 1, 2, and 3 and authorization to construct and operate the Big Bend Unit 1 Modernization Project should be approved under section 403.5175, Florida Statutes.
Findings Of Fact Based on the evidence adduced at the hearing within the scope of this proceeding, the following findings of fact are made: The Parties Tampa Electric is the applicant for site certification of Units 1, 2, and 3, and for approval of the Modernization Project at its Big Bend Power Station (Big Bend). Tampa Electric provides electric service to more than 734,000 residential, commercial, industrial, and governmental customers in west-central Florida. Its service territory includes all of Hillsborough County and portions of Polk, Pasco, and Pinellas counties. Its existing electric generating units are located at five facilities in the service territory, and consist of diverse generating technologies, including coal and natural gas-fired steam units, natural gas-fired combined-cycle and combustion turbine units, an integrated coal-gasification combined-cycle unit, and renewable solar energy facilities. DEP is the state agency charged with administering the Electrical Power Plant Siting Act (PPSA) contained in part II of chapter 403. DEP's Siting Coordination Office (Siting Office) coordinates the site certification process, receives comments from affected agencies, and prepares the Project Analysis Report (PAR) that contains DEP's recommendation to approve or deny the requested certification and the proposed Conditions of Certification. Intervenor, Sierra Club, is a national non-profit environmental advocacy organization. A key component of Sierra Club's mission is to advocate for the use of clean energy sources. Standing Sierra Club's members are concerned about continued reliance on fossil fuels and related climate change impacts, including sea level rise, increased storm surge, severe weather events, and coastal flooding. In Florida, Sierra Club has more than 30,000 members, including more than 2,000 members who live, work, and recreate in the Tampa Bay area and some near Big Bend in Hillsborough County. Sierra Club promotes outdoor activities, and many of its Florida members organize and participate in outdoor recreation for people of all ages. Sierra Club members who testified at the certification hearing take their own kids and others picnicking, kayaking, canoeing, and on service projects throughout South Florida and the Tampa Bay area. Sierra Club members, who testified at the certification hearing live in the vicinity of Big Bend, are Tampa Electric customers and enjoy outdoor recreation, such as boating in Tampa Bay and visiting the beaches. Sierra Club members who testified at the certification hearing have been injured by and suffered the effects of climate change impacts, including sea level rise, increased storm surge, severe weather events, and coastal flooding. The substantial environmental interests of Sierra Club's Florida members in the Tampa Bay area include the potential adverse effects of climate change to which Tampa Electric's greenhouse gas emissions would allegedly contribute. Thus, a substantial number of Sierra Club's Florida members' substantial interests could reasonably be affected by climate change impacts, including sea level rise, increased storm surge, severe weather events, and coastal flooding in the Tampa Bay area. Climate Change Sierra Club's expert, Harold Wanless, Ph.D., provided testimony on various aspects of the general topic of climate change. Dr. Wanless testified that climate change is a complex, worldwide issue, with contributions from many different sources. The primary is carbon dioxide emissions resulting primarily from human activities, including the combustion of fossil fuels. Dr. Wanless testified about his predictions regarding global sea level rise, storm surge, and hurricane activities in the coming years. He opined that all of this should be taken into account in the design and evaluation of a project such as the Modernization Project, but concurred that there are no current regulatory standards, other than the Hillsborough County Code of Ordinances discussed below, which address these issues. Dr. Wanless conceded that his predictions were more extreme based on a comparison with government data, to which he also cited. He advocated the immediate cessation of burning fossil fuels, and that the solution must happen "one car, one power plant at a time." Dr. Wanless also acknowledged that the timing and landfall of individual storm events, such as hurricanes, cannot be specifically attributed to human-induced global warming. From a regulatory standpoint, the United States Environmental Protection Agency's (EPA) guidance for permitting for greenhouse gases states: As a general matter, GHG emissions contribute to global warming and other climate changes that result in impacts in the environment and society. However, due to the global scope of the problem, climate change modeling and evaluations of risks and impacts of GHG emissions currently is typically conducted for changes in emissions orders of magnitude larger than the emissions from individual projects that might be analyzed in PSD permit reviews. Quantifying these exact impacts attributable to the specific GHG source obtaining a permit in specific places is not currently possible with climate change modeling. Given these considerations, an assessment of the potential increase or decrease in the overall level of GHG emissions from a source would serve as the more appropriate and credible metric for assessing the relative environmental impact of a given control strategy. Tampa Electric Ex. 22, p. 000296, ¶ 2 (quoting PSD and Title V Permitting Guidance for Greenhouse Gases, March 2011). Big Bend Power Station Site The Big Bend Power Station Site (the Site) is an existing electrical generating facility located on approximately 1,722 acres of property owned by Tampa Electric. It is approximately ten miles south of Tampa in the unincorporated southwestern portion of Hillsborough County, also known as Apollo Beach. Its address is 13031 Wyandotte Road, Gibsonton, Florida. Approximately 1,096 acres of the Site is currently certified under the PPSA. The SCA sought certification of an additional 92 acres, for a total of 1,188 acres. The Site has been used for power generation since 1970. The main fossil fuel generating facilities are in the northwestern portion of the Site located on land created by spoil materials from dredging the barge access channel to the Site in the late 1960s. The Site contains four coal and natural gas-fired steam electric generating units, a combustion turbine generator peaking unit, and associated facilities. The Site contains the approximately 20 MW Big Bend I Solar Project that was placed into service in 2017 and an area for the approximately 33 MW Solar II Solar Project, which will be constructed in the future. Each of the four coal and natural gas fired steam electric generating units uses what is known as a Rankine process to generate electricity. That process consists of taking high-pressure water and converting it in a boiler to high-pressure, high-temperature steam. The steam is then utilized in a steam turbine to convert the energy in the steam into mechanical energy. The mechanical energy provided by the steam is then used by the electrical generator associated with the steam turbine to create electrical energy. The steam leaving the steam turbine is condensed back to water by the condenser and pumped back into the boiler to complete the process. Onsite facilities associated with electric generation include: boiler and steam turbine generator buildings; air pollution control equipment; three exhaust stacks; water and wastewater treatment facilities; cooling water intake and discharge structures and canals; coal delivery and storage facilities; gypsum storage areas; coal combustion residuals beneficial use storage and handling facilities; electrical enclosures; transmission lines; substation; natural gas pipeline; and water storage and stormwater management facilities. The Site also contains a Manatee Viewing Center and the Florida Conservation and Technology Center, which is a partnership between Tampa Electric, the Florida Aquarium, and the Florida Fish and Wildlife Conservation Commission (FWCC). Other facilities located on the Site include the STI Ash Beneficiation facility and the Tampa Bay Water desalination plant. Portions of the Site were originally certified pursuant to the PPSA in 1981 for the construction and operation of Unit 4. That certification included associated facilities, which are shared with Units 1, 2, and 3, such as coal delivery and storage areas. Units 1, 2, and 3 were not subject to the PPSA because those units were constructed and operational in the 1970s prior to the effective date of the PPSA. In addition to the Modernization Project, Tampa Electric sought certification of the associated facilities for Units 1, 2, and 3, and an approximately 92-acre adjacent parcel, which would increase the certified site area to approximately 1,188 acres. Proposed Modernization Project The Modernization Project would retire Unit 2 and repower Unit 1 as a clean natural gas-fired two-on-one combined- cycle generating facility on an approximately nine-acre portion of the Site. The Unit 1 boiler would be repowered with a new natural gas-fired combined-cycle unit that would utilize Unit 1's existing steam turbine generator. Upon completion, the repowered Unit 1 would have a nominal net generating capacity of 1,090 MW. Tampa Electric selected two General Electric (GE) combustion turbine generators, each with a nominal generating capacity of 370 MW, for the new combined-cycle unit. Hot exhaust gases would be used to generate steam in two heat recovery steam generators, which would be routed to the steam turbine generator. The combustion turbine generators would be capable of operating in simple-cycle mode. The Modernization Project would include construction of new onsite associated facilities, such as electrical equipment enclosures, a gas metering station, water pumps, fin- fan coolers, transformers, an emergency diesel generator, fire protection systems, hydrogen and carbon dioxide storage tanks, an ammonia skid, and stormwater management systems. Existing Unit 1's steam turbine generator, the boiler/turbine structure, once-through cooling system, condenser, intake/discharge structures, the generator step-up transformer, the auxiliary tower, and various electrical and control systems would be refurbished and used for the repowered Unit 1. Other existing infrastructure and systems such as the demineralized water system, potable water and sanitary wastewater onsite service interconnections with Hillsborough County public services, and existing access roads, would also be used. An administration office building would be located on an approximately 1.4-acre area north of the intake canal and southeast of the plant facilities. Temporary use of several areas for construction laydown and parking, barge delivery of larger equipment, and workspace for the gas pipeline horizontal directional drilling (HDD) activities will cover approximately 44 acres. The existing 230 kilovolts (kV) transmission lines to the onsite substation would be upgraded. A new 230 kV transmission line interconnection would be constructed from the combined-cycle facilities to the existing substation. An elevated pipe bridge across the intake canal would be constructed to carry steam from the heat recovery steam generators to the repowered Unit 1 steam turbine generator. The pipe bridge will also be used to support miscellaneous pipes, cable trays, and a personnel access walkway. A new onsite natural gas pipeline interconnection would run east from the combined-cycle plant to a metering station tie-in along the north side of an existing access road located south of the barge canal. From the metering station, the pipeline would continue east to existing gas supply pipeline interconnection, located east of Wyandotte Road within the onsite railroad spur loop. The Unit 1 once-through-cooling water (OTCW) aging circulating water pumps would be replaced in-kind. The cooling water intake structure (CWIS) would be upgraded to include modified traveling water screens and a fish-return system consistent with applicable federal regulations. Fish-holding tanks for the repowered Unit 1 fish return system would be constructed in the deconstructed Unit 2 CWIS area. There would be no changes to the OTCW system serving Units 3 and 4. Construction activities for the Modernization Project would begin in July 2019, with commercial operation of the facility in simple-cycle mode in June 2021. Commercial operation of the combined-cycle plant would begin in January 2023. Unit 2 would continue to operate firing natural gas from the date of certification until 2021 when it would be retired. Environmental and Other Impacts from Existing Site Utilization Historical aerial photographs of southwestern Hillsborough County showed largely undeveloped lands with agricultural activity. Current land uses include transportation and utilities, agricultural activities along with upland non- forested areas and some wetland areas. The existing Big Bend generating facilities and associated facilities were primarily located on artificial fill dredged from Tampa Bay. These areas were heavily impacted by industrial activities associated with power generation. Other areas of the Site, located south of the existing generating facilities, were less impacted by industrial activities. Those industrial activities began in the 1970s and continue to the present time. The developed nature of the Site resulted in low vegetative diversity, limited wetlands, and limited wildlife habitat. There have been significant air emissions from existing Units 1, 2, 3, and 4 since each began operating. As explained below, the units have been capable of burning natural gas or coal since 2015, and Units 1, 2, and 3 have used only natural gas since mid-2017. Prior to mid-2017, those units' coal emissions were significantly higher than the emissions associated with burning natural gas. The air emissions from Big Bend are regulated by state and federally delegated air permitting programs. Air quality in the area is affected by emissions not only from Big Bend, but from a number of surrounding sources. For example, there are approximately 27 major sources of pollutants in Hillsborough County, including hospitals, airports, transportation, power production, and manufacturing. Ambient air quality standards were established for the protection of health and welfare- related concerns and those standards are currently being met in the area of the Site based on review of recent monitoring information. The SCA included a copy of Tampa Electric's application to DEP for a separate air permit to construct the Modernization Project under Florida's federally approved PSD preconstruction review program. DEP published a Notice of Intent to Issue Air Construction Permit No. 0570039-119-AC (Air Permit) for the Modernization Project on June 16, 2018. Sierra Club submitted comments on June 15, 2018, regarding the Air Permit, which were received and considered by DEP in the final Air Permit. However, no challenge was filed to the Air Permit, which was subsequently issued in final form on July 16, 2018. Big Bend has regulated wastewater discharges. Units 1, 2, 3, and 4 are steam electric generators that use water for cooling purposes. Cooling water is withdrawn from the man-made intake canal through CWIS 1 for Units 1 and 2 and CWIS 2 for Units 3 and 4. After being pumped through the condensers, the cooling water is discharged through outfalls into the man-made discharge canal on the south side of Big Bend. This activity is regulated in accordance with the requirements of National Pollutant Discharge Elimination System (NPDES) Permit FL000817. This NPDES permit is administered by DEP under a federally approved program. The cooling water discharge is the largest volume of surface water discharge from Big Bend. Preexisting stresses to aquatic systems are associated with the electrical generating operations at Big Bend, particularly effects from entrainment and impingement and the thermal effects of the cooling water discharge. The stresses have diminished with the use of fine mesh screens. The cooling water is heated when discharged as a result of cooling the condensers. When the cooling water is drawn from the intake canal by pumps and routed into the units, it contains organisms and fish that become trapped in the water and drawn through the intake structures and through the condensers. This causes mortality from entrainment and exposure to heat or impingement on the screens that are associated with the CWIS facilities. The CWIS for Units 1 and 2 has coarse screens that catch large fish and crabs. The CWIS for Units 3 and 4 has coarse and fine mesh screens that trap much smaller organisms that can be returned, alive, to the bay. These aspects are regulated by the federal Clean Water Act and the NPDES permit. Ecological surveys and studies of impingement and entrainment at Big Bend began in 1970 prior to the start-up of Big Bend Unit 1 and have continued through 2013. The thermal limitations were determined to be protective of indigenous shellfish, fish, and wildlife and were permitted to continue. The fine mesh screen system was determined to constitute best technology for reducing entrainment for Units 3 and 4, which satisfied certain federal Clean Water Act requirements. A renewal NPDES permit application is pending and additional review of these aspects will occur. Solid waste materials are produced at Big Bend as a result of the operations. The combustion of coal produces a number of byproducts, including gypsum solids from the flue gas desulfurization equipment and fly ash from the electrostatic precipitators, both of which are air pollution control devices for the facilities. Bottom ash and slag are also produced. These materials are left over after the combustion process and are the noncombustible materials. Economizer ash is also produced as a result of the process. The fly ash byproduct is conveyed to the Separation Technologies, Inc., facility located on an area leased from Tampa Electric at the Big Bend site. The product is separated and reused by cement companies. Bottom ash is stored in surface impoundments and conveyed hydraulically for beneficial reuse as a raw material for other products. Economizer ash is stored in a surface impoundment, and the slag material is stored for future recycling in bins. Approximately 95 percent of the coal combustion residuals are recycled for beneficial use. Materials that are not useable are sent for disposal to approved landfills. Management of coal combustion residuals, including monitoring and inspection requirements are contained in a Coal Combustion Residuals Management Manual. The manual also contains an emergency response plan, which includes communication protocols for specific local, state, and public notifications. The locations of the facilities for the storage of bottom ash, fly ash, and recycling areas are shown on an aerial in the manual, as is the east gypsum storage area. The active coal combustion residual materials storage areas are equipped with liners to prevent groundwater discharges. The facilities are subject to the federal coal combustion residuals rule. The south gypsum storage area and the economizer ash impoundments are in the process of being closed. The Coal Combustion Residuals Management Manual was developed as a component of an April 10, 2001, consent order between Tampa Electric and DEP. The consent order implemented projects that resulted in all the coal combustion residuals storage units being lined and fully contained to prevent contact of the coal combustion residuals, process water, and stormwater runoff with the environment. Previously, those areas were identified as potential release points to groundwater. Groundwater monitoring did not show any exceedances. Environmental and Other Benefits of the Modernization Project Technology and Emissions The Modernization Project includes repowering of Unit 1 into a highly efficient, state of the art, natural gas- fired two-on-one combined-cycle generating power plant using the existing steam turbine generator for Unit 1 along with other equipment. Repowered Unit 1, a combined-cycle generating facility, would consist of two combustion turbine generators, two heat recovery steam generators, and the existing steam turbine electrical generator from Unit 1. Tampa Electric selected the advanced, large-frame GE Model 7HA.02 combustion turbine generator for the Modernization Project. In combined-cycle mode, these large combustion turbine generators are the most efficient electric generating technology currently available for utility scale power plants. The combined-cycle plants can achieve an efficiency of more than 60 percent, compared to combustion turbine generators alone in simple cycle mode at 35 to 38 percent and coal fired steam electric generating plants at 32 to 42 percent. When a combustion turbine generator is operated alone in simple-cycle mode, hot exhaust gases from the combustion turbine generator are released to the atmosphere. In combined- cycle configuration, the hot exhaust gases from the combustion turbine generator are used to produce steam in the heat recovery steam generator and the steam is used to drive the steam turbine electrical generator to generate approximately 50 percent more electricity without using additional fuel, resulting in the efficiencies. Sierra Club's expert witness, Ranajit Sahu, Ph.D., testified that the use of the existing steam turbine generator would result in a difference in generation compared to the use of a new steam turbine generator. Dr. Sahu testified that the increase in performance would be 13 MW. Tampa Electric's expert witness, Kristopher Stryker, testified that Dr. Sahu's opinion was not based on the latest study, which showed that the performance differential between the new steam turbine generator and the refurbished steam turbine generator was 5 MW, which is less than one-half of one percent of the total output of the facility. Mr. Stryker further testified that since extensive modifications would be required to the foundation to install a new steam turbine generator, a 5 MW increase in performance did not justify those modifications. Bypass stacks would be located between the combustion turbine generators and the heat recovery steam generators, which would allow the initial simple-cycle operation of the combustion turbine generators and also allow simple cycle operation in the future in the event that there is a reason to do so. The refurbished steam turbine generator would only be used when the facility is operating in combined-cycle mode. The capacity of the combined-cycle unit is a nominal 1090 MW which would be the output at an average ambient temperature of 70 degrees Fahrenheit. Each combustion turbine generator has a nominal capacity of 370 MW, and the steam turbine generator has a nominal capacity of 350 MW. The combined-cycle facility would be designed with technologies to control air emissions. The two combustion turbine generators would be equipped with dry low-nitrogen oxide combustors to control nitrogen oxide air emissions. The heat recovery steam generators would be equipped with selective catalytic reduction systems to further reduce nitrogen oxide emissions. Emissions of other regulated air pollutants, including sulfur dioxide, volatile organic compounds, and particulate matter, would be controlled through the use of low sulfur, clean burning natural gas as the only fuel fired in the combustion turbine generators, along with advanced combustion equipment and operational practices. The Modernization Project would minimize greenhouse gas emissions through the repowering of Unit 1 with clean burning natural gas, highly efficient combined-cycle electric generating technology, the retirement of Unit 2, and further reductions by dispatching other existing units in the system less often. The Modernization Project was evaluated during the Air Permit process. It was determined that the PSD program was not applicable because the Modernization Project would not result in a net increase in emissions from the Big Bend facility. Based upon the evaluation process for systemwide emissions that was conducted in accordance with the applicable requirements, it was determined that the addition of the Modernization Project would result in a substantial net reduction in emissions in most cases, including a net decrease in greenhouse gas emissions of over two million tons per year. The Modernization Project is projected to result in significant reductions in emissions compared to the continued operation of Units 1 and 2 firing either coal or natural gas as a primary energy source. R. James Rocha, Tampa Electric's expert in resource planning, prepared projections using a Planning and Risk simulation model showing system-wide yearly energy produced or megawatt-hours (MWh) and the resultant yearly systemwide British Thermal Units (BTUs) or fuel use. First, for the case in which the Modernization Project is not constructed and Units 1 and 2 continue to operate into the future; and second, for the case in which the Modernization Project is constructed and Units 1 and 2 cease operations in 2021. The model is essentially an hourly dispatch simulation of the units in the Tampa Electric generating system taking into account a number of operational, fuel, probabilistic outage and planned maintenance outage scenarios, and other variables to develop a reliable estimate of the future operations of the system to meet the hourly needs of customers. Using a complex model, such as that used by Mr. Rocha, is a standard practice in the utility industry for forecasting the hourly dispatch of the system. Outputs from the modeling and emission limits in existing permits, standard emission factors for natural gas, and heat input numbers, were then provided to William Karl, an expert in air quality analyses. Mr. Karl developed calculations of projected emissions reflecting continued operation of Units 1 and 2 burning coal and natural gas, or coal only into the future, compared to projected emissions from the operation of the Modernization Project into the future. In Tampa Electric Exhibit 27, Mr. Karl showed the current carbon dioxide emission rates for Units 1 and 2 operating with coal as a primary energy source and operating with natural gas only, compared to the expected performance of the Modernization Project. The emission rates were expressed in pounds per MWh of energy produced. The Modernization Project carbon dioxide emission rate was projected to be 737 pounds per MWh of energy produced. Units 1 and 2 operating on natural gas only, each had a carbon dioxide emission rate of 1,250 pounds per MWh. Units 1 and 2 operating primarily on coal each had a carbon dioxide emission rate of 2,180 pounds per MWh. Both comparisons demonstrated substantial reductions in the carbon dioxide emission rate of the Modernization Project compared to Units 1 and 2. With Tampa Electric Exhibit 28, Mr. Karl showed the projected Tampa Electric systemwide reduction in greenhouse gas and criteria pollutant emissions if the Modernization Project was constructed compared to Units 1 and 2 continuing to operate primarily on coal during the period of 2017 through 2046. This resulted in a projected reduction in greenhouse gas emissions of 50,500,000 tons and a reduction in emissions of criteria pollutants of 213,000,000 pounds during the period of 2017 through 2046. With Tampa Electric Exhibit 29, Mr. Karl showed the projected Tampa Electric systemwide reduction in greenhouse gas emissions and all criteria pollutants with the Modernization Project constructed compared to operating Units 1 and 2 on natural gas only. This resulted in projected reductions in greenhouse gas emissions of 18,500,000 tons and projected reductions of all criteria pollutants of 21,000,000 pounds over the period of 2017 through 2046. Sierra Club disputed that reduction credit should be given for the comparison of projected emissions from the Modernization Project to projected emissions from Units 1 and 2 continuing to operate using coal as a primary energy source. Sierra Club argued that Tampa Electric's decision to stop using coal in Units 1 and 2 was made prior to filing the SCA, and existing permits were modified to reflect that fact. Therefore, no benefit should be claimed for reduced air emissions resulting from a comparison of emissions of Units 1 and 2 burning coal projected into the future. However, testimony from Paul Carpinone confirmed that if the Modernization Project is not constructed, Tampa Electric intends to continue operating Units 1 and 2, and a return to coal use remains an option. Mr. Rocha explained that based on pricing, it could make sense for the customers to return to coal in Units 1 and 2 if the Modernization Project is not approved. Mr. Carpinone also testified that permit modifications would be required to return the units to coal use. If it is assumed that coal would not be used at all in the future, the construction of the Modernization Project would result in substantial decreases in air emissions. These are projected as decreases of 18,500,000 tons of greenhouse gases and 21,000,000 pounds in all other criteria pollutants as compared to continuing to operate Units 1 and 2 on natural gas only. Although the evidence may support downward adjustment to the projected reductions in emissions resulting from the comparison of the Modernization Project to continuing Units 1 and 2 on coal based on the time it could take to obtain the necessary permit modifications to return to coal, these projected reductions should still be considered as environmental benefits of the Modernization Project. Therefore, the preponderance of the evidence demonstrated that the Modernization Project would operate at a substantially lower emission rate for greenhouse gases than the emission rates for Units 1 and 2 on natural gas or on coal. Water Use The most substantial water use for the Modernization Project would be the OTCW supply from Hillsborough Bay. The existing station is currently authorized to withdraw a combined 1,440 million gallons per day (MGD) for cooling purposes. Primarily as a result of the retirement of Unit 2 in 2021 eliminating Unit 2's cooling water requirements, the Modernization Project would reduce cooling water withdrawals by 25 percent to a maximum of 1,080 MGD. Environmental benefits associated with the reduced cooling water withdrawals would include reductions in impingement and entrainment associated with reduced intake flows and velocity. Also, reduced fish mortality because of new fish friendly modified traveling screens and fish return system that would be installed at CWIS 1, where there previously were no such facilities. The fish return system would allow aquatic organisms washed from the modified traveling screens to be discharged back into Hillsborough Bay at a location that would minimize the potential for re-impingement. Domestic and sanitary wastewater service for Big Bend with the Modernization Project would be provided by interconnection with the Hillsborough County wastewater system similar to existing operations. Potable water for the facility would also be provided by Hillsborough County, but the volume of backup service water use would be significantly reduced. There would be a number of changes to the service water uses. These would include elimination of the auxiliary cooling tower associated with Unit 2, reduction of flue gas desulfurization system makeup water from county effluent, use of county effluent for wash down associated with the combined-cycle unit, and rerouting and reuse of several other relatively minor water streams. Wastes Nonhazardous and potentially hazardous waste generated during operation of the Modernization Project would be managed in accordance with applicable federal, state, and local regulations. The use of natural gas, which does not produce solid wastes, would further reduce the need for onsite solid waste management units for disposal areas, and any waste generated would be disposed of at an offsite permitted solid waste or hazardous waste management facility. Eliminating coal use at Units 1 and 2 along with the Modernization Project, there would be a decrease in the use of coal at the Site. This would lead to production of less coal combustion residuals and reduce the need for storage and handling of those residuals. Stormwater Management The Modernization Project would include onsite stormwater management. The stormwater management system would serve areas that include the combined-cycle and combustion turbine generator areas, onsite construction laydown and parking areas, barge unloading and laydown area, new office building area, and remote construction laydown area. Tampa Electric's stormwater system design expert, Darrel Packard, was the lead civil engineer for the Modernization Project. Mr. Packard testified about the purpose of the stormwater management system and its design and benefits. The stormwater management system would convey runoff from developed areas in a controlled manner and attenuate the stormwater peak flow such that the discharge is not greater than the current discharge conditions. The system would provide water quality benefits through retention and Best Management Practices to minimize and control the discharge of nitrogen and phosphorus. The stormwater system would also address the potential for flooding by the use of appropriately sized pipes and ditches to convey runoff from developed areas and discharge runoff into stormwater ponds that meet the regulatory requirements. Offsite flooding would also be prevented by attenuating the peak discharges that might be increased due to development. Regulatory requirements applicable to the stormwater system include required sediment basins, Best Management Practices such as silt fences, the requirement to control a one-inch runoff from the developed areas, provision of a littoral zone of approximately 35 percent of the pond surface area, and the retention of a one-inch volume of runoff for at least 120 hours prior to discharge. Half of that volume would be contained over 60 hours after the rainfall event. In addition, the design would be sufficient to control the 25-year stormwater runoff event, which is roughly 8.2 inches over 24 hours. The Modernization Project would include installation of a floodwall surrounding repowered Unit 1 to protect it from flooding. Mr. Packard's testimony provided details about the design and dimensions of the floodwall. Tampa Electric Exhibit 12 showed the details of the elevation of the floodwall. Beginning from a published datum referred to as NAVD88 or North American Vertical Datum of 1988 reflected at 0.00 elevation on the exhibit, the existing grade was shown at elevation 8.3 feet above NAVD88. The top of the floodwall was depicted at elevation 18.029 feet above NAVD88, meaning that the total elevation of the flood protection would be 18.029 feet above NAVD88. The design basis for the floodwall height took into account the elevation of the 100-year flood for facilities that are in a defined federal Emergency Management Agency (FEMA) AE Zone. Based on current FEMA flood maps, the Modernization Project is in the AE Zone, and the 100-year flood elevation is 12 feet above NAVD88. Another 2.5 feet were added to the 12-foot, 100-year flood elevation. The Hillsborough County Code of Ordinances specified the use of the American Society of Civil Engineers Standard for Flood Resistant Design and Construction (ASCE Standard) 24-05. The Modernization Project would fall into Category 3 for the ASCE Standard 24-05, adding two feet. The applicable Hillsborough County Ordinance required an additional six inches, resulting in a total minimum flood protection height of 14.5 feet. The design of the floodwall was 18.029 feet above NAVD88 and the amount by which it exceeded the 14.5-foot regulatory requirement provides a margin to account for uncertainties such as sea level rise. The FEMA flood maps for the area are under revision and have not yet been finalized. Under section 403.5185, a proposed revised map not yet in effect is not applicable to this SCA. However, a comparison of the currently effective and the preliminary flood maps showed that the flood zone for the Modernization Project would not change. Sierra Club's expert, Dr. Sahu, opined that since the Modernization Project concerns electric power generation facilities, there should be heightened scrutiny and flood protection requirements. However, Dr. Sahu's testimony did not dispute the Modernization Project's compliance with the applicable regulatory requirements. The Hillsborough County Code of Ordinances defines "critical facilities" as those for which even a slight chance of flooding might be too great. That definition of "critical facilities" does not include power plants. The design details for the floodwall followed ASCE Standard 7-10 for the minimum design load requirements for buildings and other structures. The floodwall was designed considering two design cases. When the cases were considered, essentially three checks were made for wall stability, which included values obtained from the geotechnical report plus calculations performed by the geotechnical engineers. Dr. Sahu questioned the design basis of the floodwall in terms of its ability to withstand the forces that the wall was designed to withstand. His criticism was mainly based on a lack of ability to review final detailed design plans. DEP's witness, Cynthia Mulkey, explained in her testimony that final design plans are not required for every aspect of the project. Ms. Mulkey testified that it was not unusual that final detailed design plans were not available at the time the application was being processed. The applicable nonprocedural requirement pertaining to this issue was contained in the Hillsborough County Code of Ordinances, Part A, SCC 8-1-Hillsborough County Construction Code, and the FEMA flood map. Dr. Sahu's testimony did not dispute the Modernization Project's compliance with these regulatory requirements. Socioeconomic Benefits Construction and operation of the Modernization Project is expected to provide significant benefits to the economy of Hillsborough County and the State of Florida through increased employment and revenues during construction and operation of the project. Direct benefits from construction will include employment and payroll for an average monthly employment of approximately 250 workers, as well as the purchase of equipment and materials. Approximately $300 million of construction expenditures for materials and services would occur during the construction period from 2019 through approximately mid-2023. Approximately $210 million would be spent in the local area. Once the repowering project begins operations, tax revenues and operational and maintenance expenditures would be in the range of $18 million per year. The majority of construction wages would be spent within Hillsborough County. Anticipated annual property tax revenue and sales tax revenue would be $8.4 million and $1.26 million respectively. The peak construction employment would be approximately 500 workers, and this would occur in the most labor intensive construction period in 2021. Land Use and Zoning The applicable Hillsborough County future land use (FLU) map designation for the Modernization Project and barge offloading areas is Heavy Industrial. Electrical generation plants and expansions of electrical power plants are among the allowed uses within this FLU designation. The remote construction laydown area is designated Community Mixed Use-12 which allows for light industrial multipurpose use. Areas associated with the Modernization Project are located within either Manufacturing or Planned Development-Industrial zoning districts. On June 1, 2018, Hillsborough County found the additional 92 acres, as well as the proposed activities, consistent with its existing land use plans and zoning ordinances. Impacts from Construction of the Modernization Project Environmental Impacts The site certification process includes only state, regional, and local requirements. Federal permits issued by the state under federally approved or delegated permit programs that were sought, or modified, in association with the Modernization Project are processed separately from the SCA. These include the Air Permit, the NPDES Permit, and the United States Army Corps of Engineers (USACE) Section 404 application. Tampa Electric would apply for applicable federally delegated stormwater discharge permit(s), including requirements for a comprehensive Stormwater Pollution Prevention Plan, prior to construction. During construction, stormwater would be managed to meet the requirements of those federal permits. As previously found, the stormwater management system for the Modernization Project would be designed to treat the first inch of runoff from the 25-year, 24-hour storm event and would meet federal, state, regional, and local requirements. During operation, contact stormwater runoff from the power block and equipment areas would be collected and treated through a new oil/water separator and routed to a new contact water transfer sump prior to discharge to the existing coal field pond. Noncontact stormwater runoff from the facility area would be collected and routed to a stormwater detention pond for treatment prior to discharge to the barge canal. The Modernization Project would create a new internal outfall for the reverse osmosis (RO) concentrate, and the OTCW discharge from Unit 2 would cease. The NPDES discharge compliance point would include the combined cooling water discharge from Units 1, 3, and 4, and the treated effluent from the flue gas desulfurization treatment plant, as well as the RO concentrate to Hillsborough Bay, a Class III marine water, via the onsite discharge canal. Low-volume industrial wastewater generated by the Site primarily includes floor and equipment drains, water treatment equipment waste, and service cooling tower and boiler blowdown. These waste streams are routed to a system of lined ponds, a reclaimed water storage pond, and bottom ash ponds for containment or reuse within the facility, and the same practice would continue with the Modernization Project. Groundwater monitoring around the water storage ponds is required under the facility's industrial wastewater permit No. FLA017047 and would continue to be a requirement of the Site License. The Modernization Project would include construction of stormwater detention ponds during the beginning stages of the Modernization Project development activities to provide stormwater storage and treatment for onsite runoff during construction. Because of the disturbed nature of the Site, preparation would require minimal clearing and grading. Erosion, sedimentation, and runoff control measures, both pre- and post-construction, will meet applicable nonprocedural requirements of part IV of chapter 373, Florida Statutes, Florida Administrative Code Chapter 62-330, and applicable Hillsborough County land development regulations. Best Management Practices (BMPs) and a sediment control plan would also be implemented during site construction. Monitoring of construction runoff and the operation and maintenance of BMPs for erosion and sediment control would be undertaken as required by applicable construction permits, such as the NPDES Generic Permit for Stormwater Discharge from Large and Small Construction Activities contained in Florida Administrative Code Chapter 62-621. Under current operation, the Site does not withdraw groundwater for plant processes or potable water uses nor will the Modernization Project use groundwater as a source. The Site relies on treated effluent from Hillsborough County and recycled water for its process needs. There would be no consumptive use nor anticipated impact to groundwater supply due to the Modernization Project. Site preparation and facility construction activities may have potential short-term effects on groundwater in the shallow surficial aquifer in the immediate area of the combined- cycle facilities from temporary dewatering activities. Because of the temporary and localized nature of potential dewatering activities and the direction of the flow from east to west of the Floridan aquifer in the area, construction of the Modernization Project is not anticipated to have significant adverse impacts to on or offsite groundwater resources. Construction and operation of the Modernization Project would impact approximately 55 acres of the approximately 1,188-acre certified Site. The Site has been utilized for industrial purposes for the past 50 years. Therefore, most of the land was previously disturbed and not prime habitat for wildlife species. Both uplands and wetlands are located onsite but are considered low-quality and contain a mixture of nuisance exotic and native species. Construction of the Modernization Project would not result in permanent impacts to wetlands. In fact, over 99 percent of the wetlands and surface waters onsite would remain intact. An approximately 0.18-acre portion of a low- quality wetland is proposed to be temporarily cleared for workspace during the construction of the gas pipeline interconnection. Once construction is complete, this area would be allowed to revegetate naturally. Other potential impacts proposed include: an additional 0.02 acres of permanent impact to surface waters/water bodies for the construction of a new pipe bridge across the existing intake canal; temporary impacts in the barge canal due to the spud columns; and approximately 0.01 acres of a man-made, roadside ditch would be filled for construction of a new culverted driveway for access to the remote construction laydown and/or parking area. The wetland proposed for clearing is considered a lower quality wetland, and impacts would be offset by the purchase of mitigation bank credits or onsite mitigation, if necessary. Secondary impacts to preserved wetland communities would be minimized by maintaining an average 25-foot and minimum 15-foot buffer surrounding wetlands where no construction activities would occur. Impacts from the in-water work during construction of the intake canal pipe bridge would be mitigated with the use of turbidity barriers. Existing Units 3 and 4 and the repowered Unit 1 would continue to discharge through separate outfalls into the Site's 4,500-foot discharge canal that leads to Hillsborough Bay through an inlet at the north end of Apollo Beach. The south side of the discharge canal is bordered by a sheet pile seawall that serves as a thermal barrier to the adjacent shallow waters in North Apollo Bay, minimizing thermal impacts to surface waters in this area. Adverse changes in hydrologic or water quality conditions in the existing intake and discharge canals or Hillsborough Bay are not expected to result from operation of the Modernization Project. The existing Site's OTCW discharge provides a primary thermal refuge for the local population of West Indian manatees, and seagrass along the southern boundary of the discharge canal provides food for the manatees that winter in the canal. The area outside the discharge canal and the canal itself are designated as manatee protection areas under both state and federal laws. The Site's NPDES permit includes a manatee protection plan that contains requirements for timely communication with manatee recovery program personnel and for production of adequate warm water during the winter months. Because of these required measures, projected reductions in the effluent temperature and total thermal loading in the discharge canal from operation of repowered Unit 1 and retirement of Unit 2 are unlikely to adversely impact manatees. Noise Noise impacts resulting from construction activities are expected to be minimal and mitigated by the distance between the construction area of the power block and the site boundaries, and the fact that the construction activities will take place mainly on an existing power plant site that is currently operational. Average noise levels during the loudest construction activities are projected to be between 62 and 66 A-weighted decibels (dBA) at the northern property boundary, and noise levels from construction activities will be lower at all other property boundaries. Under the rules of the Hillsborough County Environmental Protection Commission, Chapter 1-10, Noise Pollution, construction activities occurring during the hours of 7:00 a.m. and 6:00 p.m. are exempt from the noise rule if reasonable steps are taken to abate the noise. The construction activities, however, are expected to be below the 70 dBA level applicable to industrial land use category. Noise resulting from the operation of the Modernization Project would not have any adverse impact on the existing noise levels in the general vicinity of the Big Bend Power Station. Archeological and Historic Sites Based on results of cultural resource assessments conducted in 1979, no significant archaeological or historical sites were found or are expected to be found at the Site. A survey conducted in January of 2018 did not identify any previously recorded archaeological sites. In the event that any archaeological resources are encountered during construction activities, the Florida Division of Historical Resources will be notified and consulted to determine appropriate actions. Safety Issues Shawn Copeland, vice president of safety for Tampa Electric, testified on safety issues associated with Big Bend. Tampa Electric has safety programs at the different generating stations, as well as for the operating areas. The programs are designed to provide a safe environment for workers and compliance with regulations and standards. The safety programs apply to Big Bend and are designed to create a safe work environment and also public protection. There is an Emergency Action Plan for Big Bend. The plan provides basic information for initial emergency actions. Actions and procedures for reporting emergencies, procedures for emergency evacuation, procedures to account for personnel after an evacuation, procedures to be followed by employees performing rescue or medical duties, and procedures to be followed by employees remaining to conduct critical plant operations prior to evacuation. The Emergency Action Plan primarily focuses on events related to fires, medical, natural gas, and severe weather emergencies. There are specific emergency evacuation plans for each type of event. The storm preparedness procedures contained in the Emergency Action Plan do not apply to hurricanes, but rather storms that are more sudden. Hurricane preparedness is addressed in the Big Bend Station Storm Preparedness Procedures, revised May 9, 2018, which consists of approximately 151 pages of information and checklists applicable when hurricanes or hurricane-related events are approaching. Emergencies of all types are addressed by the All Hazard Notification Flowchart, which provides protocols for communications and activities to be taken during the occurrence of suspicious activities or an unexpected emergency at the plants. In addition to the foregoing, Big Bend has an Integrated Contingency Plan dated December 2018. The purpose of the Integrated Contingency Plan is to focus on emergency prevention and preparedness and provide rapid, effective protection of human health and the environment during an emergency caused by a chemical release or other physical hazardous release. The objectives of the Integrated Contingency Plan are to establish: (i) means of recognizing an emergency; rapid notification procedures to avoid delay in response; an organizational structure for accountability; initial assessment and response procedures to isolate and stabilize the incident; (v) sustained response procedures to mitigate the consequences of the incident; and (vi) post- incident investigations to document and eliminate the incident causes. The scope of the plan covered involves hazards or releases associated with hazardous waste, oil, and petroleum products, substances subject to the emergency planning and Community Right-to-Know Act requirements, federal workplace requirements for emergency response plans, Florida requirements governing release prevention and response for pollutants stored in regulated tanks, radiation hazards, and federal and state requirements for response to an air release of asbestos containing fibers. The plan provides protection from these hazards for both workers and the public. The Coal Combustion Residuals Management Manual assists the facility in maintaining compliance with permits and environmental procedures and preventing unauthorized releases to the environment, while maximizing beneficial use of this material and minimizing generation of additional wastes. Mr. Stryker detailed the design standards that apply or would be used in the design of the Modernization Project including the natural gas pipeline lateral. The generating facility additions were designed by an internationally recognized engineering firm with significant experience designing similar projects throughout North America and Florida, including one for Tampa Electric. Sound engineering practice will be utilized, and all applicable laws and regulations and required codes, such as the Florida Building Code and the Hillsborough County Code requirements, would be met. The natural gas lateral, in addition to adhering to good engineering practices and industry requirements, is subject to review by the Florida Public Service Commission (PSC). The PPSA and SCA Process The PPSA created a centrally coordinated process for review and evaluation of electrical generating facilities at the state and local level on the basis of adopted standards and recommendations of the reviewing agencies. DEP, through the Siting Office, is responsible for coordinating and processing the SCA and maintaining the Site License for the life of the electrical generating facility. The SCA was filed with DEP on April 18, 2018. DEP submitted the application to DOAH, along with a proposed schedule for processing the SCA for approval by the ALJ. The SCA was distributed to the reviewing agencies that review the SCA for completeness and ultimately submit agency reports containing recommendations. Each agency conducts a review as to the compliance of the SCA with the statutory and administrative requirements within the respective agencies' jurisdiction and also provides a report containing a recommendation of approval or denial of the Modernization Project, including any proposed Conditions of Certification. Following initial agency review, the SCA was determined to be incomplete, and additional information was requested. Tampa Electric submitted the additional information requested on June 27, 2018, and the SCA was determined to be complete on July 19, 2018. The Southwest Florida Water Management District (SWFWMD), the FWCC, the Florida Department of Transportation (DOT), the Florida Department of Economic Opportunity (DEO), the Florida Department of State, Division of Historical Resources (DHR), and the DEP were the state and regional agencies reviewing the SCA. As required by the PPSA, the local government in whose jurisdiction the project would be located was also included. Hillsborough County, as well as the Environmental Protection Commission of Hillsborough County, reviewed the SCA. The state, regional, and local agencies supported the Modernization Project. The agencies determined that the Modernization Project would comply with all applicable non- procedural requirements when constructed and operated in conformance with the proposed Conditions of Certification. SWFWMD, FWCC, DOT, DHR, and Hillsborough County proposed Conditions of Certification to which Tampa Electric agreed. DEP prepared a PAR summarizing the substantive review by the agencies, including DEP's review of the applicable environmental regulations by all the relevant divisions within DEP. The PAR contains DEP's recommendation, taking into account all of the information received from Tampa Electric and the various reviewing agencies, that the SCA should be approved subject to the proposed Conditions of Certification. Tampa Electric has agreed to accept the proposed Conditions of Certification in the PAR. With the exception of DEP, the reviewing agencies waived their rights to be a party and to participate in the certification hearing by not filing the notice required to do so. Need Determination The SCA was filed and processed under the provisions of section 403.5175, which provides for the certification of existing, uncertified units that were not previously subject to the provisions of the PPSA. The SCA requested certification of existing Units 1, 2, and 3, and the authorization to repower Unit 1 and retire Unit 2 after continuing to operate until 2021. Units 1, 2, and 3 are not subject to the PPSA unless the steam electric generating capacity was expanded after the effective date of the PPSA. The preponderance of the evidence established that repowering Unit 1 would not result in an expansion of the steam electric generating capacity, Unit 2 would continue to operate as currently operated until its retirement in 2021, and Unit 3 would continue to operate as currently operated into the future, so there is no expansion of steam electric generating capacity at either of those facilities. The Unit 1 repowering project would use the existing steam turbine electrical generator that is currently used for Unit 1. The electrical generating rating or capacity of a facility is found on a nameplate on the generator. The nameplate capacity of existing Unit 1 steam turbine electrical generator is 445.5 MW. The maximum steam electric generating capacity of the combined-cycle, after the repowering, would be 360 MW. This is because the steam produced in the heat recovery steam generators would limit the amount of electricity that can be produced using the steam. It would be well below the existing capacity of the steam turbine electrical generator for Unit 1. There would not be an expansion of steam electrical generating capacity as measured by the nameplate of the existing Unit 1 steam turbine electrical generator. Therefore, the provisions of the PPSA that require a need determination are not triggered. Ms. Mulkey testified that DEP defines "expansion" as an increase in steam generation. In addition, early in the process, DEP's Siting Office considered the PPSA applicability issues. DEP evaluated the information provided by Tampa Electric and consulted with PSC staff to determine whether the Modernization Project should be subject to a need determination. Because the combined-cycle facility that would repower Unit 1 has the capacity to produce sufficient steam to generate only 360 MW, no expansion of steam turbine electrical generating capacity would occur. The PSC staff and DEP agreed that proceeding under the provisions of section 403.5175 was appropriate. Mr. Stryker testified to other projects where repowering did not go through the site certification process. One such project involved the repowering of Tampa Electric's Gannon Station with a combined cycle unit using the existing steam turbine electrical generator for the repowered units. A similar repowering project was carried out by then Progress Energy at the Bartow facility. The Progress Energy project, although not increasing steam electric generating capacity as a result of the repowering, actually used an entirely new steam electric generator unit. Notwithstanding this difference, DEP concluded that the Bartow repowering project was not subject to the PPSA because it did not increase steam electric generating capacity. Sierra Club's expert, Dr. Sahu, testified that Tampa Electric's consideration of only the steam-generated electricity to determine whether a need determination was required was factually incorrect and misleading. He opined that evaluating only the steam component of the generation for purposes of determining the applicability of the PPSA was not appropriate since the PPSA is 40 years old and the manner in which electricity is generated has changed during that period of time. Instead, he suggests that the entire facility should be looked at, rather than just the steam component. However, Ms. Mulkey testified that for purposes of evaluating whether the Modernization Project would be subject to a need Determination, the focus was on whether there would be an expansion of steam electrical generating capacity defined as an increase in steam generation. It was appropriate to focus on the steam generation component, and the PSC did not express any concerns with this approach. Notice, Outreach, Public Hearing All notices required by the PPSA were provided. Tampa Electric published the required Notice of Filing for Electrical Power Plant Site Certification on May 7, 2018, Notice of Land Use Consistency Determination on Electrical Power Plants Site on June 20, 2018, Notice of Certification Hearing on November 2, 2018, and Notice of Rescheduled Certification Hearing on January 4, 2019, all in the Tampa Bay Times. DEP notices were published in the Florida Administrative Register. Tampa Electric engaged in public outreach for the SCA. The public outreach included newspaper notifications, direct mailing, establishing a website for the SCA, and a phone number to call for questions concerning the SCA. There was one direct mailing consisting of 8,948 direct letters to landowners within three miles of the Site and in accordance with the PPSA. Tampa Electric representatives also met with various elected officials to discuss the Modernization Project. A copy of the SCA was made available for public inspection at Tampa Electric's main office on Tampa Street in downtown Tampa, and a copy of the SCA was also made available at the John F. Germany Hillsborough County Public Library on Ashley Street in Tampa. Those SCAs were updated as appropriate. As part of the certification proceeding, a public hearing was held on March 11, 2019, from 6:00 p.m. until 9:00 p.m. At the hearing, comments were accepted from those who expressed a desire to speak. Thirty-nine members of the public testified. Twenty-six members of the public spoke in opposition, and 13 members of the public spoke in favor of the Modernization Project. The public hearing was recorded and transcribed as part of the Transcript of the certification hearing.
Recommendation Based on the foregoing Finding of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a final order approving certification of Tampa Electric Company, Big Bend Power Generating Station's, existing Units 1, 2, and 3; and authorizing the Modernization Project, subject to the Conditions of Certification contained in DEP's Project Analysis Report. DONE AND ENTERED this 30th day of May, 2019, in Tallahassee, Leon County, Florida. S FRANCINE M. FFOLKES Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 30th day of May, 2019. COPIES FURNISHED: Lawrence N. Curtin, Esquire Kevin W. Cox, Esquire Holland & Knight, LLP 315 South Calhoun Street, Suite 600 Tallahassee, Florida 32301 (eServed) Kelley F. Corbari, Esquire Michael J. Weiss, Esquire Kirk S. White, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed) Diana A. Csank, Esquire Julie Kaplan, Esquire Aaron Messing Matthew E. Miller, Esquire Sierra Club 50 F Street Northwest, 8th Floor Washington, DC 20001 (eServed) Kathleen Riley Sierra Club 50 F Street Northwest, 8th Floor Washington, DC 20003 Theresa Lee Eng Tan, Esquire Florida Public Service Commission 2450 Shumard Oak Boulevard Tallahassee, Florida 32399 (eServed) Andrew S. Grayson, Esquire Florida Fish and Wildlife Conservation Commission 620 South Meridian Street Tallahassee, Florida 32399 (eServed) Marva M. Taylor, Esquire Hillsborough County 601 East Kennedy Boulevard Tampa, Florida 33601 (eServed) Vivian Arenas-Battles, Esquire Southwest Florida Water Management District 7601 U.S. Highway 301 Tampa, Florida 33637 (eServed) Kimberly Clark Menchion, Esquire Department of Transportation 605 Suwannee Street, Mail Station 58 Tallahassee, Florida 32399 (eServed) Jon F. Morris, Esquire Department of Economic Opportunity 107 East Madison Street, Mail Station 110 Tallahassee, Florida 32399 (eServed) Richard Thomas Tschantz, Esquire Environmental Protection Commission 3629 Queen Palm Drive Tampa, Florida 33619 (eServed) Sean Sullivan Tampa Bay Regional Planning Council 4000 Gateway Center Boulevard, Suite 100 Pinellas Park, Florida 33782 Jason Aldridge Division of Historical Resources Department of State R.A. Gray Building 500 South Bronough Street Tallahassee, Florida 32399-0250 Carlos A. Rey, Esquire Department of State R.A. Gray Building 500 South Bronough Street Tallahassee, Florida 32399-0250 (eServed) Ronald W. Hoenstine, Esquire Department of Environmental Protection Douglass Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed) Andres Restrepo, Esquire Sierra Club 520 Carpenter Lane Philadelphia, Pennsylvania 19119 Joshua Douglas Smith, Esquire Sierra Club 2101 Webster Street Oakland, California 94612 (eServed) Kathryn E.D. Lewis, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed) Tara R. Price, Esquire Holland and Knight, LLP 315 South Calhoun Street, Suite 600 Tallahassee, Florida 32302 (eServed) Lea Crandall, Agency Clerk Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed) Justin G. Wolfe, General Counsel Department of Environmental Protection Legal Department, Suite 1051-J Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed) Noah Valenstein, Secretary Department of Environmental Protection Douglas Building 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 (eServed)
The Issue Pursuant to Section 403.508(2), Florida Statutes, the sole issue for determination in this case is whether the proposed site for the Petitioner’s electrical power plant “is consistent and in compliance with existing land use plans and zoning ordinances.” (All statutory references are to the 2001 codification of the Florida Statutes.)
Findings Of Fact The Petitioner Calpine intends to license, construct, own, and operate a new electrical power plant in unincorporated Indian River County, Florida. Calpine filed an application with DEP under the PPSA for the proposed electrical power plant, which is known as the Blue Heron Energy Center ("the Project"). The Site for the Blue Heron Energy Center The site (“Site”) for the Blue Heron Energy Center is located in southeastern Indian River County, approximately 5 miles southwest of the City of Vero Beach. The Site is approximately 50.5 acres in size and is currently undeveloped. The primary vegetation on the Site is pine flatwoods. The Site contains two small wetlands that will be preserved. The general area surrounding the Site is a mixture of agricultural, industrial, institutional, utility and residential land uses. The Interstate 95 ("I-95") corridor is adjacent to the west side of the Site. Just west of the I-95 corridor are two existing electrical transmission line corridors operated by Florida Power & Light Company ("FPL"). There is an existing natural gas pipeline owned by Florida Gas Transmission Company located between the two electrical transmission line corridors. The Indian River County Correctional Institution is located directly northwest of the Site. Farther to the north are Indian River County's landfill and several industrial (citrus processing) facilities. There also is one single-family residence located north of the Site. The eastern boundary of the Site is adjacent to 74th Avenue, which is adjacent to a drainage ditch known as the Lateral C Canal. A citrus grove and an industrial wastewater sprayfield are located on the east side of the Lateral C Canal. The southern boundary of the Site abuts the border between Indian River County and St. Lucie County. The I-95 corridor and undeveloped lands lie south of the Site in St. Lucie County. Southeast of the Site, in St. Lucie County, is a residential development known as Spanish Lakes Fairways. The Site is separated from this residential development by a drainage ditch, a berm, and an existing buffer of mature trees and dense vegetation. Description of the Proposed Blue Heron Project The Blue Heron Energy Center will involve the construction and operation of a combined cycle, natural gas- fired, electrical power plant that will generate approximately 1080 MW (nominal). The Blue Heron Project will be built in two phases, each generating approximately 540 MW (nominal). The first phase of the Project will include two combustion turbines, two heat recovery steam generators, a steam turbine, exhaust stacks, cooling towers, a treatment and storage system for process water, a treatment system and detention basin for storm water, an operations control center, transformers and related switching gear, and other ancillary structures and features. The second phase of the Project will be similar to the first phase. The Blue Heron Energy Center will connect to Florida's electrical grid with two overhead transmission lines that will extend west from the Site approximately 1400 feet (over I-95) to the existing FPL transmission lines. The Project will obtain natural gas by installing an underground pipe that will extend from the Site approximately 1400 feet to the west (under I-95) to where the Project will interconnect with the natural gas pipeline systems operated by Gulfstream and Florida Gas Transmission Company. Calpine has obtained options to purchase the land west of the Site where Calpine's gas pipeline corridor and electrical transmission line corridor will be located. The primary source of cooling and process water for the Blue Heron Energy Center will be surface water (storm water), which will be obtained from the Lateral C Canal or the County's proposed stormwater park. Potable water and domestic wastewater services will be provided by Indian River County. No groundwater will be used by the Project. The Blue Heron Project will not discharge any industrial or domestic wastewater to any surface water or groundwater. Existing Land Use Plans and Zoning Ordinances The Site is designated Agricultural (AG-1) in Indian River County's Comprehensive Plan. Under the Comprehensive Plan, the AG-1 designation allows for the construction of electrical power plants, like the Project, as "public facilities." Indian River County has adopted land development regulations and zoning districts that implement the intent of the County’s Comprehensive Plan. Under the zoning code, like the Comprehensive Plan, the Site is located in an Agricultural (A-1) district. The County’s zoning code expressly allows the construction of "public and private utilities, heavy" as a special exception use in A-1 zoning districts. The County's zoning code defines "utilities, public or private, heavy" to include "all major electrical generation plants (generating fifty (50) megawatts or more)." Thus, the A-1 zoning designation for the Site allows the development of the Project as a special exception use. Special Exception Use Section 971.05 of the County Code sets forth the procedures and criteria for obtaining the County's approval of a special exception use. Among other things, Section 971.05(9) of the County Code requires an applicant for a special exception use to demonstrate that the proposed project is consistent with the County's Comprehensive Plan and zoning code. Calpine has worked with the County to ensure that every aspect of the Blue Heron Energy Center will comply with the County's criteria. Consistent with the requirements of Section 971.05 of the County Code, Calpine filed an application with the County for approval of a special exception use and conceptual site plan for the Blue Heron Project. The Special Use Exception Application ("SUEA") fully described the Project, including the corridors for the proposed transmission lines and natural gas pipeline. The County’s staff reviewed Calpine’s SUEA and recommended approval, subject to certain conditions. On August 9, 2001, the County's Planning and Zoning Commission held a duly noticed public hearing and then recommended approval of Calpine’s SUEA, with conditions. On September 18, 2001, the Indian River County Board of County Commissioners ("County Commission") held a duly noticed public hearing and then approved Calpine’s SUEA, with conditions. It is "typical" for the County to include conditions as part of the County's approval for a special exception use. If Calpine complies with the County's conditions for its special exception use, the County will "automatically approve the final site plan" for the Blue Heron Project. No one appealed the County Commission's approval of Calpine’s SUEA and the deadline for filing an appeal has passed. Consistency With Land Use Plans and Zoning Ordinances The County staff, the Planning and Zoning Commission, and the County Commission considered whether the Project is consistent and in compliance with the County's Comprehensive Plan and zoning ordinances, pursuant to Section 971.05 of the County Code, and then they approved the Project, with conditions. The evidence presented in the Land Use Hearing demonstrated that the Site is consistent and in compliance with Indian River County’s Comprehensive Plan. The evidence also demonstrated that the Site is consistent and in compliance with Indian River County’s zoning ordinances. In the Prehearing Stipulation, Indian River County, St. Lucie County, the Florida Department of Community Affairs, the Treasure Coast Regional Planning Council, the Florida Department of Environmental Protection, the Florida Department of Transportation, the Florida Public Service Commission, the Florida Fish and Wildlife Conservation Commission and the St. Johns River Water Management District either agreed with or did not dispute Calpine’s assertion that the Site is consistent and in compliance with existing land use plans and zoning ordinances. Indian River County also stipulated that it supports Calpine’s plan to construct and operate the Blue Heron Project on the Site. Public Notice of the Land Use Hearing On December 11, 2000, Calpine published a “Notice of Filing of Application for Electrical Power Plant Site Certification” in the Vero Beach Press-Journal, which is a newspaper of general circulation published in Indian River County, Florida. On October 9, 2001, the Administrative Law Judge issued an “Order Granting Continuance and Re-Scheduling Land Use Hearing” and served a copy of his Order on all of the parties to this proceeding. The Judge’s Order stated that the Land Use Hearing would be conducted on February 6, 2002. On December 14, 2001, Calpine published a “Notice of Land Use and Zoning Hearing on Proposed Power Plant Facility” in the Vero Beach Press-Journal. On December 14, 2001, the Department published notice of the Land Use Hearing in the Florida Administrative Weekly. The public notices for the Land Use Hearing satisfy the informational and other requirements set forth in Section 403.5115, and Rules 62-17.280 and 62-17.281(4), Florida Administrative Code.
Conclusions For Petitioner Calpine Construction Finance Company, L.P.: David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 For the Florida Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399 For Audubon of Florida and the Pelican Island Audubon Society: Kevin S. Doty, Esquire Hatch & Doty, P.A. 1701 A1A, Suite 220 Vero Beach, Florida 32963
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Land Use Final Order in this case finding that the Site of the Blue Heron Energy Center is consistent and in compliance with the existing land use plans and zoning ordinances. DONE AND ORDERED this 5th day of March, 2002, in Tallahassee, Leon County, Florida. ___________________________________ J. LAWRENCE JOHNSTON Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 5th day of March, 2002. COPIES FURNISHED: James V. Antista, General Counsel Florida Fish and Wildlife Conservation Commission Bryant Building 620 South Meridian Street Tallahassee, Florida 32399-1600 Ross Stafford Burnaman, Esquire Florida Fish and Wildlife Conservation Commission Bryant Building 620 South Meridian Street Tallahassee, Florida 32399-1600 Paul Bangel, Esquire County Attorney's Office 1840 25th Street Vero Beach, Florida 32960 Kathy Beddell, Esquire Harold Mclean, General Counsel Florida Public Service Commission 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 Kevin S. Doty, Esquire Hatch & Doty, P.A. 1701 Highway A1A, Suite 220 Vero Beach, Florida 32963-2206 Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard The Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 Charles Lee, Sr., Vice President Florida Audubon Society 1331 Palmetto Avenue Suite 110 Winter Park, Florida 32789 Terry E. Lewis, Esquire Lewis, Longman & Walker, P.A. 1700 Palm Beach Lakes Boulevard Suite 1000 West Palm Beach, Florida 33401 Daniel S. McIntyre, Esquire St. Lucie County 2300 Virginia Avenue 3rd Floor Administrative Annex Fort Pierce, Florida 34952 Cari L. Roth, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Roger G. Saberson, Esquire 70 Southeast Fourth Avenue Delray Beach, Florida 33483 Colin M. Roopnarine, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Jennifer B. Springfield, Esquire St. Johns River Water Management District Post Office Box 1429 Palatka, Florida 32178-1429 Sheauching Yu, Esquire Department of Transportation 605 Suwannee Street Haydon Burns Building, Mail Station 58 Tallahassee, Florida 32399-0458 Kathy C. Carter, Agency Clerk Office of General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard The Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 Teri L. Donaldson, General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard The Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000
The Issue The issue in this case is whether Kenneth Tuch is liable to Florida Power and Light Company for receipt of unmeasured electric energy and if so, what amount is due?
Findings Of Fact Kenneth Tuch resides alone at 1924 N.E. 25th Street, Ft. Lauderdale, Florida. He receives his electric current from Florida Power and Light Company. In June of 1985, an employee of American Cable Company went to Mr. Tuch's home to investigate a complaint about the quality of cable television reception at the Tuch residence. The employee noticed that the air conditioning was on in the Tuch residence while he was investigating the complaint. When following the cable lines outside the home, he noticed the electric meter was not operating. He provided this information to Florida Power and Light which sent two employees to the Tuch residence on June 20, 1985. They found the air conditioning and swimming pool pump were on, but the electric meter disk did not turn. The meter seal was opened and the meter was removed from its socket, and photographed. The photographs demonstrate that the potential clip of the meter was open. The potential clip is used when testing a meter. When it is open no registration of electric current is made. The meter was originally placed at the Tuch residence in 1960. The potential clip could not have been open then, for it never would have registered any electric consumption were that the case. The potential clip would not have fallen into the open position on its own. There was tampering with the potential clip because a screw in the slot in the center of the clip had been tightened to keep the clip in the open position. In addition, the picture of the potential clip and the screws (FP&L Exhibit 5) show wear and tear on the screw. Marks on the area around the screw slot in the center of the potential clip show that the clip has been slid back and forth. These facts prove a deliberate attempt to divert unmeasured electricity. The meter seal consists of a wire bail of a horseshoe shape which fits into a rectangular base body approximately 1 and 1/4 inches by 3/4 inch by 1/8 inch. The seal removed from Tuch's meter bears the inscription on one side "77 FP&LS" and on the other side, the numbers "0379126". The condition of the seal was such that by tugging on the wire bail, it would loosen from the body of the seal, and open, but the bail could be replaced into the seal body giving the impression on casual observation that the seal was intact. While the inscription on the seal indicates that it is a genuine Florida Power and Light seal, it is not in the condition in which seals are originally placed. It is not possible to open the wire bail of a seal and thereby gain access to the meter canopy without tampering with the seal. The billings for consumption of electricity at the Tuch residence show an erratic pattern of monthly electric consumption during the period for which Florida Power and Light has records available, January 1982 through June 1986. For the years 1982 through 1984, Mr. Tuch was billed for an average of 11,022.33 kilowatts per year. On June 20, 1985, the meter at the Tuch residence was replaced with a new meter which was locked in place. Readings were taken from the new meter on June 21, June 27, July 2 and July 9. During those 19 days, 1,063 kilowatts had been consumed for an average use of 55.9 kilowatts per day. This equals 1,677 kilowatts for a 30 day period. An average percentage of use chart was introduced into evidence as the basis for distributing the total yearly kilowatt consumption based upon seasonal variations in consumption. According to the chart 9.8 percent of the total kilowatts used by Florida Power and Light customers in 1985 were consumed in the July billing period. That being so, the total estimated annual usage given a July bill of 1,677 kilowatts would be 17,112 kilowatts. The total additional billing on that basis for 1982, 1983, 1984 and 1985 (through the date of the discovery of the tampering) would be $1,829.57. A potential problem with this methodology for determining annual usage is that it extrapolates a bill for a one year period based on readings taken over only 19 days. As a check on the method Florida Power and Light also placed in evidence the readings for approximately six months actual usage after replacement of the meter which had been tampered with. Mr. Tuch used 7,865 kilowatts during the 172 day period from June 20 through December 31, 1985. This was an average use of 45.72 kilowatts per day. When multiplied by 365 days the estimated yearly usage is 16,690 kilowatts. This results in a billing $17.52 lower than the extrapolation and shows the reasonableness of using the 19 day period to project annual usage. The electric meter removed from Mr. Tuch's residence was tested, but due to its age was then destroyed. Florida Power and Light rendered its additional bill two months later. Mr. Tuch therefore did not have the opportunity to inspect or test the meter. Florida Power and Light tested the meter appropriately before it was destroyed and it was accurately registering current flow when the potential clip was closed. If this case involved questions about the accuracy of the registration on the meter which had been removed, Mr. Tuch's inability to test the meter would have seriously impaired the fairness of this proceeding. The testimony and photographic evidence, which is accepted, is that the potential clip was open, and thus the meter would register no use of current at all. Essentially the meter had been turned on and off. This tampering caused the underregistration, not inaccuracy of the meter's measurement ability. In this case, the inability to test the old meter did not prejudice Mr. Tuch. Florida Power and Light is not entitled to recover $157. 88 in investigative costs. The witness proffered to testify about investigative costs was listed in interrogatories as a witness on matters of corporate policy. See Notice of Serving Answers to Interrogatories filed April 21, 1986. While it may be corporate policy to bill those who divert current for investigative charges, the exhibit purporting to set out the costs incurred in the Tuch investigation was admitted to show the corporate form for recording charges. No evidence of the charges in this specific case was admitted (Transcript 196-97). 1/
Recommendation It is RECOMMENDED that a final order be entered by the Public Service Commission requiring Kenneth Tuch to pay Florida Power and Light $1,829.57 for current diverted. If such payment is not made, electric service to Mr. Tuch's residence at 1924 N.E. 25th Street, Ft. Lauderdale, Florida, should be discontinued. DONE AND ORDERED this 29th day of January, 1987, in Tallahassee, Florida WILLIAM R. DORSEY, JR. Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32301 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 29th day of January, 1987.
Findings Of Fact The Respondent, Florida Department of Health and Rehabilitative Services, is an agency of the State of Florida charged with the responsibility, inter alia, for setting and enforcing health and safety standards for hospitals located within the state. In furtherance of this function, the Department has adopted rules set out Chapter 10D-28, Florida Administrative Code. Among these rules are provisions which set standards for hospital construction which are designed to assure the fire and electrical safety of patients, staff and visitors to hospitals. The Department enforces its rules by licensing or certifying hospitals which comply with them, and by refusing licensure or certification to those which do not. The Department's Rule 10D-28.79, Florida Administrative Code, relates to codes and standards for the physical plant of new and existing hospitals. The rule does not set out code provisions, but rather adopts various construction and life safety codes by reference. Rule 10D-28.79(5) provides in pertinent part: The following codes and regulations are herein adopted by the licensing agency [the Department], and it shall be the responsibility of the sponsor [licensed hospitals] to consult such codes for compliance with all matters not specifically set forth in this chapter. Standard Building Code, 1976 edition, Group I, Institutional Occupancy. National Fire Protection Association No. 101, Life Safety Code 1973 Edition; Appendix B of this Code adopts several other NFPA standards, which shall be met . . . This rule became effective on January 1, 1977. Copies of the codes that were adopted by reference did not accompany the rules as the were filed with the Office of the Secretary of State. The Life Safety Code is a publication of the National Fire Protection Association (NFPA). Appendix B to the Code, which is referenced in the Department's Rule 10D-28.79(5)(b) is titled "Referenced Publications" and provides in part as 7 follows: The following publications are referenced by this Life Safety Code and thereby comprise a part of the requirements or recommendations to the extent called for by the Code or Appendix A, respectively. The Appendix goes on to list more than fifty publications, including the 1971 National Electric Code, which is another publication of the National Fire Protection Association. The crux of this proceeding is a single paragraph of this publication. Paragraph 517-51(a) sets an electrical performance standard to be met in hospital areas where "electrically susceptible patients" are housed. The paragraph provides: In electrically susceptible patient areas the maximum 60-hertz alternating-current potential difference between any two conducting surfaces within thee reach of a patient, or those persons touching the patient, shall not exceed five millivolts measured across 500 ohms under normal operating conditions or in case of any probable failure. The Department has interpreted its Rule 10D-28.79(5)(b) as adopting as performance standards the provisions of all of the codes set out in Appendix B of the 1973 Life Safety Code, including the 1971 National Electric Code, and paragraph 517-51 thereof. There are conflicting provisions in the various Life Safety and Electrical Codes that the Department has adopted, and contends that it has adopted through its adoption of Appendix B of the 1973 Life Safety Code. The Department resolves these conflicts by requiring hospitals to develop solutions which will meet the provisions of all of the codes. The provisions of paragraph 517-51(a) of the 1971 National Electric Code are considerably more strict than similar provisions set out in later editions of the National Electric Code, including the 1975, 1978 and 1981 Codes. The Department contends that hospitals must comport with the most strict of these requirements, i.e. the ones set out in paragraph 517-51(a) of the 1971 Code. The Petitioner Memorial Hospital of Jacksonville is an accredited, licensed hospital in the State of Florida. Memorial Hospital is presently in the process of constructing a three million dollar renovation, including a renovation to its critical care unit. In order to comply with the provisions of paragraph 517-51(a) of the 1971 National Electric Code, Memorial Hospital would need to expend approximately $55,000 that would not need to be expended in order to comply with provisions of other codes. Memorial Hospital has requested a variance from the Department from the requirement of complying with this provision. The Petitioner St. Vincent's Medical Center is an accredited, licensed hospital located in Jacksonville, Florida. St. Vincent's Medical Center is currently involved in a project to renovate and add space to its existing facilities, including a thirty-two bed critical care unit. In order to comply with the provisions of paragraph 517-51(a) of the 1971 National Electric Code, St. Vincent's would be forced to expend from $75,000 to $80,000 which would not be necessary in order to comply with the provisions of other codes. St. Vincent's Medical Center has requested a variance from the requirements of that provision from the Department. Halifax Hospital Medical Center is an accredited, licensed hospital located in Daytona Beach, Florida. Halifax Hospital has been advised that it would be required to comply with the provisions of paragraph 517-51(a) of the 1971 National Electric Code in renovating and expanding its critical care unit. While the precise cost of complying with the provision cannot be determined, it is evident that Halifax Hospital would be required to expend more money to comply with the provision than would be required to comply with other provisions. The Petitioner Shands Teaching Hospital and Clinics, Inc., is an accredited, licensed hospital located in Gainesville, Florida. Shands Hospital is presently in the process of expanding and renovating its facility, including its critical care unit. Shands Hospital has been advised by the Department that it would need to comply with the provisions of paragraph 517-51(a) of the 1971 National Electric Code in connection with the critical care unit. The cost of complying with this provision would be approximately $140,000 over the cost of complying with other provisions. No evidence was presented with respect to the Petitioner Variety Children's Hospital. The Department's interpretation of its Rule 10D-28.79 as having adopted by reference the performance standard set out at paragraph 517-51(a) of the 1971 National Electric Code is in error. While the Department's rule references Appendix B to the 1973 Life Safety Code, it provides only that that Appendix adopts several other standards which must be met. While the Appendix references the 1971 National Electric Code, it adopts only the provisions of the 1971 National Electric Code and the other referenced publications to the extent that they are otherwise adopted in the 1973 Code or Appendix A thereto. Paragraph 517-51(a) of the 1971 Code is not referenced in Appendix A to the 1973 Life Safety Code, nor in any other pertinent place. The Department has, albeit erroneously, interpreted its rules as adopting paragraph 517-51(a) of the 1971 National Electric Code. This interpretation is being uniformly applied by the Department, and therefore itself constitutes a rule. The interpretation has not itself been adopted as a rule other than through the provisions of Rule 10D-28.79. The 1971 National Electric Code was not filed with the Office of the Secretary of State when Rule 10D-28.79 was filed, and is not generally available. It has been replaced by subsequent editions of the National Electric Code and is no longer generally available to members of the public at large. The effect of the Department's interpretation of its rules as adopting the standard set out in paragraph 517-51(a) is to require hospitals to install "isolated power sources" in critical care units. The standard by its terms applies to areas of a hospital where electrically susceptible patients are housed. Such patients are housed in operating rooms, rooms where highly flammable anesthetics are used, and in critical care units. Other standards adopted by the Department expressly require installation of isolated power sources in operating rooms and in rooms where flammable anesthetics are used. The fact that these are "wet" areas and areas where flammable materials are kept justifies those requirements. These conditions do not apply to critical care units. The electrically susceptible patients who are housed in critical care units are patients who have catheters inserted into their bodies, and extensions from the catheters protruding outside their bodies. The most common such patient is a patient with a pacemaker attached to his or her heart. With such patients an electrical device outside the body is connected through a catheter into a vein, and eventually to an area close to or actually at the heart. These patients are electrically susceptible because low levels of electrical current that might flow through the catheter could kill the patient. A power source of less than 100 millivolts if attached to the catheter in such a way that current could flow through the catheter could have the effect of fibrillating a patient's heart and killing him. This is much less power than would do any damage to a person under normal conditions, and considerably less voltage than would commonly result from short circuits or other malfunctions in equipment powered by conventionally grounded power sources. The amount of voltage that would be available given a fault or short circuit condition can be reduced through use of isolated power systems. Such a system includes a transformer which provides a demarcation between the incoming or primary power line, which is conventionally grounded, and the outgoing or secondary line. The secondary line is isolated from ground, neither wire being connected to ground. The secondary line runs into circuit breakers then to receptacles about the room. All of this equipment is installed in an electrical box. A monitor or gauge is installed on the face of the box. The monitor visually displays the extent of degradation of the secondary line, i.e. , whether the secondary line has become grounded. By observing the monitor, it is possible to avoid grounding a patient so that electrical currents cannot pass through the patient. The Department maintains that the 1971 Code standard can be met only through installation of isolated power sources. Under some fault circumstances this is correct, and, no other practical technology exists to meet the standard under any fault circumstances. Imposition of the standard set out at paragraph 517-51(a) of the 1971 National Electric Code is arbitrary and unreasonable. In the first place, no known technology can meet the standard. Even an isolated power system will meet the standard only in the case of line-to-ground faults. In cases where ground is lost, the isolated power system will not stay within the standard. The Department's action in requiring hospitals to install line isolation monitors thus meets the standard only under one fault circumstance, and it is not the one that most commonly occurs. Even as to those faults for which the line isolation monitor will accomplish the meeting of the 1971 standard, there is no valid reason for requiring their installation. The goal of protecting an electrically susceptible patient from electrocution can be easily and reliably accomplished by protecting the catheter from contact with electrical power sources. Basically, in order to create an electrical incident, or a shock, one part of a person's body has to touch some metal, another part has to touch some metal, and some current has to flow. This can be broken down into eight steps that would need to occur for a patient to be shocked: First, a power source or power line has to run close to the patient. Second, the line has to be exposed and touch metal. Third, the metal has to become live. Fourth, the metal must become ungrounded. Fifth, the patient has to touch the metal directly or through some conductive path. Sixth, a second conductive surface (more metal) has to be available. Seventh, the patient has to touch it. Eighth, the current has to be at a level that will cause harm. If any of these things does not happen, there will not be a shock. During the 1960's and early 1970's, the fact that very low levels of electrical current could cause fibrillation of the heart was not understood. This fact has been understood now for some time, and hospitals have looked to avoid placing patients in circumstances where the eight steps can occur. Looking at the problem in this manner allows hospitals to focus on what factors can easily be eliminated. Current practice is not to ground things which do not have to be grounded. It had previously been the practice to ground all of the metal around the patient, creating a "bathtub" effect. The line isolation monitor serves to eliminate the eighth of these steps by, in at least one fault circumstance, allowing only very low levels of current to flow. The other steps can be more easily eliminated. One means of accomplishing that is to isolate the power source to the catheter. Thus, battery powered equipment is now typically used, rather than equipment that attaches directly to the main power source. Furthermore, catheters protruding from a patient's body are now insulated, and critical care unit personnel are instructed not to touch them unless they are wearing rubber gloves. The taking of these steps eliminates the possibility for electrocution of an electrically susceptible patient through low voltage currents (microshock). There have been no documented deaths of patients through such microshock anywhere in the world since 1972. Even in that instance, which occurred in the United Kingdom, the accident did not happen in a critical care unit, but rather in an operating unit. The circumstances of the incident were that a hospital had been callously negligent in allowing its equipment to be modified so that inadequate switches were attached to an operating table and open current lines were exposed. Blood from a patient flowed to the open lines, and electrocution resulted. This incident bears no relevance to the instant rule. In the first place, it occurred in an operating room, where isolated power systems are properly required. In the second place, the hospital staff was incredibly negligent about its procedures and equipment. In addition to the fact that isolated power systems no longer accomplish any valid purpose in preventing microshock, there are disadvantages to their use. These disadvantages include: (1) Line isolation monitors limit the amount of power that is available at bedside in critical care units. There is a need for considerable available power at bedside, and line isolation monitors limit available power, and can contribute to power interruptions. (2) A component is added to the power distribution system so that an additional point of failure exists. (3) The isolation system is installed at the head of beds in a critical care unit, thus interfering with the possibility of putting other equipment in that place. (4) Isolated power systems with their transformers and monitors can produce an annoying hum. (5) Isolated power systems give off heat. (6) Line isolation monitors which go with isolated power systems can cause interference with other devices, such as electroencephalograms and electrocardiograms. (7) Several models of isolated power systems, including those required under the 1971 National Electric Code, require special electrical receptacles, thus limiting the use of various appliances in a critical care unit. (8) Personnel have to be trained as to the nuances of isolated power systems, and as to the meaning of readings on the monitor. (9) Isolated power systems can give personnel a false security and cause carelessness in preventing the factors which could cause and electrical current to flow through a catheter. Except for electrically susceptible patients as described herein, there is no reason to require installation of isolated power sources in critical care units. Petitioners have contended that other regulations of the Department which relate to the setting of fire protection standards in hospitals constitute invalid exercises of delegated legislative authority. No evidence was presented as to how these standards specifically affect any of the Petitioners. No evidence was presented to establish that any of the Petitioners are in any way injured or adversely affected by the rules.
The Issue The issue to be determined in this case is whether the Governor and Cabinet, sitting as the Siting Board, should grant certification to New Hope for the expansion of the Okeelanta cogeneration facility to a total net steam electrical generating capacity of 140 megawatts (”MW”).
Findings Of Fact The Applicant The Applicant, New Hope Power Partnership, is a Florida partnership that owns the existing Okeelanta cogeneration Facility. Ex. 1 at 1-1, 3-1. New Hope will also own the Project. See id. The Site The Facility is located in an unincorporated area in western Palm Beach County, Florida. Ex. 1 at 2-1; Ex. 4 at 6; T It is approximately six miles south of South Bay and two miles west of U.S. Highway 27. Id. The Facility is located on a site (the ”Site”) that is approximately 82.1 acres in size. Ex. 1 at 2-1; Ex. 4 at 8; T 19. The Site is adjacent to Okeelanta Corporation’s existing sugar mill, sugar refinery, and sugarcane fields. Ex. 1 at 2-1; Ex. 4 at 6; T 17, 20. The Surrounding Area There are large buffer areas around the Site. See Ex. 1 at 2-1, 2-2, 2-4; Ex. 4 at 6; T 17-18. Almost all of the land within five miles of the Site is used for agricultural purposes (sugarcane farming). Id. The community nearest the Site is South Bay. Ex. 1 at 2-2; Ex. 4 at 6; T 17. The nearest home is more than 3.5 miles northeast of the Site. Ex. 1 at 2-4; Ex. 5 at 9; T 17-18. The Facility is adjacent to an existing electrical substation (Florida Power & Light Company’s Okeelanta Substation). See Ex. 1 at 1-2. An existing electrical transmission line connects the Facility to the substation. Ex. 1 at 3-1. The Existing Facility The Facility uses biomass fuels (e.g., bagasse from the sugar mill; clean wood waste) to generate steam and up to 74.9 MW of electricity (net). Ex. 1 at 1-1, 3-1; Ex. 4 at 6-7; T 18. The Facility supplies steam to the sugar mill during the sugarcane harvest (October through March) and it supplies steam to the refinery throughout the year. Ex. 1 at 1-2, 3-1; Ex. 4 at 7; see T 18. Excess steam from the Facility is used to generate electricity, which is sold to utility companies, including Florida Power & Light Company. Ex. 1-3; Ex. 4 at 7; See T 50-51. The existing Facility includes three steam boilers, one steam turbine/electrical generator, a cooling tower, an electrical switchyard, materials handling and storage facilities for biomass fuels, and ancillary equipment. Ex. 1 at 2-1, 3-1; Ex. 4 at 7; T 20-21. The Expansion Project The Expansion Project will increase the Facility’s electrical generating capacity by 65 MW (net), creating a total generating capacity of 140 MW (net). Ex. 1 at 1-1, 1-3, 2-1; Ex. 4 at 7; T 18. The Expansion Project will involve the installation of a new turbine/electrical generator, a cooling tower, and related equipment at the Site. Ex. 1 at 1-3, 2-1; Ex. 4 at 8; T 19. Construction of the Expansion Project Approximately 0.5 acres of the Site will be occupied by the new equipment that will be installed for the Expansion Project. Ex. 1 at 2-1; Ex. 4 at 8; T 19. The construction of the Project will occur in disturbed upland areas that already are used for industrial operations. Ex. 1 at 3-2, 4-1; Ex. 4 at 9; T 20. No construction will take place in any wetland, wildlife habitat, environmentally sensitive area, or 100-year flood plain. Ex. 1 at 2-2, 2-18, 4-1; Ex. 4 at 9; T 20. No new electrical transmission lines will need to be built to accommodate the additional electrical power generated by the Expansion Project. See Ex. 1 at 3-1, 6-1. During construction, there will be a temporary increase in sound levels due to the heavy equipment associated with the construction process. Ex. 1 at 4-9 through 4-10; Ex. 5 at 9; T 42-43. Given the remote location of the Site, the sounds generated by the construction of the Expansion Project will not interfere with human activities or otherwise cause a nuisance at any residential locations. Id. The construction of the Expansion Project will result in a temporary increase in traffic on some roads near the Site, but these roads will continue to operate at acceptable traffic levels. Ex. 1 at 4-8 through 4-9; Ex. 5 at 9; T 42. Operation of the Expansion Project The Facility currently operates at its full capacity during the sugarcane harvest. See Ex. 30, Technical Evaluation at 2. The Expansion Project will enable the Facility to operate at its full capacity year-round. See Ex. 1 at 3-1 through 3-2; Ex. 30, Technical Evaluation at 2. Although the Facility will generate more electricity after the Expansion Project is completed, the basic operation of the Facility will not change. Ex. 4 at 10; Ex. 5 at 6; T 22. The Facility has a water use permit issued by the South Florida Water Management District, which authorizes the Facility to use water from the Miami/North New River Canal System, the surficial aquifer, and the Floridan aquifer. Ex. 1 at 3-11; Ex. 5 at 7; T 40-41. The Okeelanta Corporation also may provide water to the Facility, in accordance with the SFWMD water use permit for the Okeelanta Corporation’s sugar mill. Ex. 5 at 7; T 41. After the Expansion Project is completed, the amount of water used by the Facility will increase, commensurate with the increased use of the Facility. Ex. 5 at 7; DEP Ex. 2, Staff Analysis Report at 3; T 41. The additional water will be obtained from the cooling pond/rock pit located at the adjacent sugar mill. Id. In March 2005, the SFWMD issued a water use permit that allows the Okeelanta Corporation to increase the amount of water provided to the Facility from 0.4 mgd to 2.0 mgd. Ex. 37; see T 41. The Facility’s stormwater and process water are routed to a 600-acre area that is divided into four percolation basins. Ex. 1 at 3-16; Ex. 5 at 8; T 41. Each basin is used on a rotating basis--i.e., the basin is used for percolation for one year and then it is used for growing sugarcane for three years. Ex. 5 at 8; T 41. Each percolation basin is designed to hold all of the Facility’s process water, plus all of the contact and non-contact stormwater runoff from a 100-year, three-day storm event. Id. The Facility does not discharge any stormwater or process water to any surface water. Ex. 1 at 5-9; Ex. 5 at 8; T 41-42. The Facility’s use of the percolation ponds has not caused and is not expected to cause any violations of any ground water quality standards. Ex. 5 at 8. The Facility generates fly ash and bottom ash from the combustion of biomass fuels. Ex. 1 at 3-16, 5-10; Ex. 5 at 9; T 42. These materials are taken to a landfill for disposal. Id. The operation of the Expansion Project will not have any significant impacts on traffic. Ex. 1 at 5-17; Ex. 5 at 9; T 42. The local roads will continue to operate at an acceptable level of service. Id. Air Quality Regulations The Facility must comply with New Source Performance Standards (”NSPS”) and Best Available Control Technology (”BACT”) requirements, both of which impose strict limits on the Facility’s airborne emissions. See Ex. 1 at 3-5; Ex. 30, Technical Evaluation at 3. The Facility also must comply with Ambient Air Quality Standards (”AAQS”) and Prevention of Significant Deterioration (”PSD”) standards, which establish criteria for the protection of ambient air quality. Id. The Facility previously was reviewed and approved under the PSD program. Ex. 1 at 3-5; Ex. 5 at 6; Ex. 30, Technical Evaluation at 2; T 39-40. The DEP has determined that the Expansion Project is not subject to PSD pre-construction review. Ex. 5 at 6; Ex. 30, Technical Evaluation at 5; T 38. The cooling towers will be the only new source of air pollution associated with the Expansion Project. Ex. 1 at 3-5; Ex. 5 at 6; T 38. The water droplets leaving the cooling tower will evaporate, causing small amounts of particulate matter to enter the atmosphere near the Site. Ex. 5 at 6; T 38. However, the emissions from the cooling tower are so small that the cooling tower is exempt from the permitting requirements established by the DEP. Id. Best Available Control Technology A BACT determination is required for each pollutant for which PSD review is required. Ex. 1 at 3-5; Ex. 5 at 7; DEP Ex. 2, Staff Analysis Report at 15. BACT is a pollutant- specific emission limit that provides the maximum degree of emission reduction, after taking into account the energy, environmental, and economic impacts and other costs. Ex. 1 at 3-5; Fla. Admin. Code R. 62-210.200(38). As part of its BACT analyses for the Facility, DEP determined that mechanical cyclone dust collectors and an electrostatic precipitator (”ESP”) will control the Facility’s emissions of particulate matter, a selective non-catalytic reduction system (”SNCR”) will control oxides of nitrogen (”NOx”), use of low-sulfur fuels will control sulfur dioxide emissions, and proper facility design and operating methods will control other pollutants. Ex. 1 at 3-6 through 3-8; Ex. 30, Draft Permit at D-1; T 40. Accordingly, these air pollution control systems and techniques are utilized at the Facility. Id. The Facility also uses an array of continuous emissions monitors to ensure that the Facility is continuously in compliance with the BACT emission limits. Ex. 1 at 5-14; Ex. 30, Draft Permit at E-1 through E-2. Protection of Ambient Air Quality The EPA has adopted ”primary” and ”secondary” National Ambient Air Quality Standards (”NAAQS”). See Ex. 1 at 2-21. The primary NAAQS were promulgated to protect the health of the general public with an adequate margin of safety. See Ex. 1 at 2-21; see also 42 U.S.C.A. § 7409(b) (1997). The secondary NAAQS were promulgated to protect the public welfare, including vegetation, soils, visibility and other factors, from any known or anticipated adverse effects associated with the presence of pollutants in the ambient air. Id. Florida has adopted EPA’s primary and secondary NAAQS, and has adopted some Florida AAQS (”FAAQS”) that are more stringent than EPA’s NAAQS. See id. The Facility’s potential impacts on ambient air quality were evaluated by DEP, based on the continuous operation of the Facility at full load, following completion of the Project. Ex. 30, Technical Evaluation at 4. DEP concluded that the maximum impacts from the Facility will not cause or contribute to any violations of AAQS. Ex. 1 at 5-10 through 5- 14; Ex. 5 at 6-7; Ex. 30, Technical Evaluation at 4; Ex. 5 at 6; T 39. Other PSD Analyses The PSD program provides protection for those areas that have good air quality. See Ex. 1 at 2-22; Ex. 30, Technical Evaluation at 3-4. Different areas of Florida have been designated as PSD ”Class I” or ”Class II” areas, depending upon the level of protection that is to be provided under the PSD program. Id. In this case, the Project is located in a PSD Class II area. Id. The nearest PSD Class I area is the Everglades National Park (”Everglades”), which is approximately 92 kilometers (”km”) south of the Site. Ex. 1 at 2-22. The DEP’s analyses demonstrate that the Facility’s impacts on ambient air quality will not violate any applicable PSD requirement for the Class I and Class II areas. Ex. 1 at 5- 14; Ex. 5 at 6; Ex. 30, Technical Evaluation at 4; DEP Ex. 2, Staff Analysis Report at 16-17; T 39. Compliance With Air Standards New Hope has provided reasonable assurance that the Expansion Project and the Facility will comply with all of the applicable air quality standards and requirements. Ex. 5 at 7; Ex. 30; DEP Ex. 2, Staff Analysis Report at 17; T 38-40. Environmental Benefits of the Project The Expansion Project will provide environmental benefits. Ex. 1 at 7-3 through 7-4; Ex. 5 at 10; T 43-44. For example, the Project will be capable of producing approximately 65 MW (net) of electricity in Southeast Florida, which needs new electrical generating capacity. Ex. 1 at 7-3 through 7-4; Ex. 5 at 10; T 43-44. The Expansion Project will also enhance fuel diversity by using renewable biomass fuels to generate electricity. Id. Over 20 years, the Project may displace the use of approximately 5,600,000 barrels of oil worth nearly $170,000,000 (assuming oil prices of $30 per barrel). Id. In addition, the Expansion Project will beneficially reuse clean wood waste, which otherwise would likely be placed in a landfill for disposal. Ex. 1 at 7-4; Ex. 5 at 10; T 44. The Facility receives wood waste and biomass materials from Miami-Dade County, the Palm Beach County Solid Waste Authority, and approximately 25 private recycling companies, thus assisting them with their solid waste management programs. Ex. 5 at 10; T 44. The Facility also burns melaleuca trees that have been removed pursuant to land clearing programs for the eradication of this nuisance species. Ex. 5 at 10. Socioeconomic Benefits of the Project The Expansion Project will provide jobs for an average of 70 construction workers during the 12-month construction phase of the Project. Ex. 1 at 7-1 through 7-2; Ex. 5 at 10; T 43. Approximately $3.5 million will be paid in wages for construction employees working on the Expansion Project. Id. Consistency with Land Use Plans and Zoning Ordinances The proposed use of the Site is consistent and in compliance with Palm Beach County’s comprehensive land use plan and zoning ordinances. Ex. 1 at 2-2 through 2-4; Ex. 4 at 16; Ex. 23; Ex. 24; Ex. 38; Ex. 39; T 28-29. The Facility and Project have both been reviewed and approved by the Palm Beach County Board of County Commissioners. Ex. 4 at 11-12; Ex. 23; Ex. 24; T 23-25. Compliance with Environmental Standards New Hope has provided reasonable assurance that the Facility and Project will comply with all of the nonprocedural land use and environmental statutes, rules, policies, and requirements that apply to the Project, including but not limited to those requirements governing the Project’s impacts on air quality, water consumption, stormwater, and wetlands. Prehearing Stipulation at 24, paragraph 5.B.3.; Ex. 5 at 11; DEP Ex. 2, Staff Analysis Report at 22; T 44-45, 60. The location, construction and operation of the Facility and Project will have minimal adverse effects on human health, the environment, the ecology of the State’s lands and wildlife, and the ecology of the State’s waters and aquatic life. Ex. 5 at 12; DEP Ex. 2, Staff Analysis Report at 20; T 45-46, 61-62. The Facility and Project will not unduly conflict with any of the goals or other provisions of any applicable local, regional or state comprehensive plan. Ex. 4 at 16; Ex. 23; Ex. 24; Ex. 38; Ex. 39; T 28-29. The Conditions of Certification establish operational safeguards for the Facility and Project that are technically sufficient for the protection of the public health and welfare. Ex. 5 at 13; T 46-47, 61. Agency Positions and Conditions of Certification On November 18, 2004, the PSC issued an Order (No. PSC-04-1105A-FOF-EI) granting New Hope’s petition for determination of need for the Expansion Project. Ex. 22; DEP Ex. 2, Staff Analysis Report at 4-6, 12-13. The PSC determined, consistent with the criteria of Section 403.519, Florida Statutes, that the Expansion Project is needed. Id. The DEP, DOT, DCA, and SFWMD all recommend certification of the Expansion Project, subject to the Conditions of Certification. Prehearing Stipulation at 10-11, 13-16. New Hope has accepted, and has provided reasonable assurance that it will comply with, the Conditions of Certification. Prehearing Stipulation at 24-25, paragraph V.B.4; Ex. 5 at 11-12; T 45, 61-62. Public Notice of the Certification Use Hearing On September 29, 2004, New Hope published a ”Notice of Filing of Application for Electrical Power Plant Site Certification” in the Palm Beach Post, which is a newspaper of general circulation published in Palm Beach County, Florida. Ex. 31; see also Ex. 5 at 16; T 49. On October 1, 2004, the Department published ”Notice of Receipt of Application for Power Plant Certification” in the Florida Administrative Weekly. Ex. 35; see also Ex. 5 at 16; T 49. On February 2, 2005, New Hope published notice of the Certification Hearing in the Palm Beach Post. Ex. 33; see also Ex. 5 at 16; T 49. On February 4 and 11, 2005, the Department published notice of the Certification Hearing in the Florida Administrative Weekly. Ex. 36; see also Ex. 5 at 16; T 49. The public notices for the Certification Hearing satisfy the informational and other requirements set forth in Section 403.5115, Florida Statutes, and Florida Administrative Code Rules 62-17.280 and 62-17.281(4). Prehearing Stipulation at 24, paragraph V.B.2,3; Ex. 5 at 17; T 49, 63-64.
Conclusions For Petitioner New Hope Power Partnership (”New Hope”): David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 For the Florida Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order granting certification for the expansion of the Okeelanta Cogeneration Facility to a total capacity of 140 MW (net), in accordance with the Conditions of Certification, DEP Exhibit 3. DONE AND ENTERED this 31st day of March, 2005, in Tallahassee, Leon County, Florida. S CHARLES A. STAMPELOS Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 31st day of March, 2005. COPIES FURNISHED: David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 Scott Goorland, Esquire Office of General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 James V. Antista, General Counsel Florida Fish and Wildlife Conservation Commission 620 South Meridian Street Tallahassee, Florida 32399-1600 Roger Saberson, General Counsel Treasure Coast Regional Planning Council 70 Southeast 4th Avenue Delray Beach, Florida 33483 Jennifer Brubaker, Esquire Public Service Commission Division of Legal Services 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0863 Leslie Bryson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399 Sheauching Yu, Esquire Department of Transportation 605 Suwannee Street Mail Station 58 Tallahassee, Florida 32399-0458 Sarah Nall, Esquire 9341 Southeast Mystic Cove Terrace Hobe Sound, Florida 33455 Denise M. Nieman, Esquire Palm Beach County Attorney's Office 302 North Olive Avenue, Suite 601 West Palm Beach, Florida 33401-4705 Raquel A. Rodriguez, General Counsel Office of the Governor The Capitol, Suite 209 Tallahassee, Florida 32399-1001 Kathy C. Carter, Agency Clerk Department of Environmental Protection Office of General Counsel Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000
