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)
Findings Of Fact Petitioner owns and operates a 0.175 million gallon per day sewage treatment plant known as the Gramercy Park Sewage Treatment Plant, located north of Parke Avenue, 1/4 mile west of Haverhill Road, West Palm Beach, more specifically located at latitude 26 degrees 45' 52", longitude 80 degrees 07' 10", Palm Beach County, Florida. Petitioner's sewage treatment plant is of trickling filter design with tertiary filters discharging treated effluent to percolation ponds with an overflow provided to Canal EPB-10 which ultimately discharges to the South Florida Water Management District C-17 canal. The sewage treatment plant serves approximately 650 connections. Petitioner has operated under a series of DER Temporary Operating Permits from on or about November 16, 1973, until January 1, 1981. These permits required petitioner to upgrade and modify the sewage treatment facility to achieve DER requirements for treatment efficiency and ultimately to design, finance, and construct a connection to the East Central Regional Sewage Treatment Plant for final sewage treatment and disposal. Petitioner's most recent Temporary Operation Permit, No. DT 50-5339, contains the following Specific Condition: The issuance of this permit is based upon the permittee's request of 1/5/78 and in consideration of any comments from the public received pursuant to the Public Notice in the Palm Beach Post 1/23/78. It is issued to give the permittee a reasonable period of time to design, finance and construct a connection to the East Central Regional Sewage Treatment Facility for ultimate treatment and disposal of the Gramercy Park sewage. When the connection is placed in service, the treatment plant covered by this permit will be abandoned and dismantled. The schedule for construction of the connection to the East Central Regional Sewage Treatment Facility and abandonment of this treatment plant must be adhered to and is as follows: Preliminary engineering and approval - 7/79 Final design and construction permit - 11/79 Financing complete 7/79 Contract award - 1/80 Purchase of equipment complete - 5/80 Start of construction - 1/81 Completion of construction - 1/81 Abandonment of treatment facility and diversion of flow to the East Central Regional Sewage Treatment Facility - 1/81 Petitioner received, accepted, and operated pursuant to TOP No. DT 50-5338, and never objected to its conditions. Petitioner was informed through DER correspondence dated March 8, 1978, that the referenced permit would not be effective unless accepted by Petitioner. That correspondence also informed Petitioner of its right to an Administrative Hearing if it objected to any portion of said permit. Petitioner did not request an Administrative Hearing or otherwise object to the provisions of DER Permit No. 50-5339. Petitioner's sewage treatment plant is currently not in compliance with Florida Administrative Code Rule 17-6.060(1)(a)1., requiring secondary treatment of sewage. In its present condition, the sewage treatment plant is incapable of meeting the requirements of that rule. Petitioner's most recent application (No. DT 50-62817) for a Temporary Operating Permit was denied by DER by Final Order dated March 4, 1983. Petitioner did not appeal the Final Order. DER issued a Notice of Intent to Deny Application No. DT 50-62817 on February 4, 1983. Petitioner did not request an Administrative Hearing on the Notice of Intent to Deny. DER has indicated by letter dated May 26, 1983, that no further discharge from the sewage treatment plant into Canal EPB-10 will be permitted. Petitioner has failed to comply with Condition 1 of Permit No. DT 50- 5339, in that it has not abandoned its sewage treatment plant and has not diverted flow to the East Central Regional Sewage Treatment facility. Such diversion is technologically feasible and the East Central Regional Sewage Treatment Facility is available to handle the flow from Petitioner's facility.
Recommendation Based on the foregoing, it is RECOMMENDED that Respondent enter a Final Order finding Petitioner guilty of the allegations contained in Counts One through Three of its, Notice of Violation, and requiring the previously directed sewage plant phaseout. DONE and ENTERED this 30th day of August, 1983, in Tallahassee, Florida. COPIES FURNISHED: William E. Sundstrom, Esquire 1020 East Lafayette Street Suite 103 Tallahassee, Florida 32301 R. T. CARPENTER 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 30th day of August, 1983. Paul R. Ezatoff, Jr., Esquire Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32301 Victoria Tschinkel, Secretary Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32301 ================================================================= AGENCY FINAL ORDER ================================================================= STATE OF FLORIDA DEPARTMENT OF ENVIRONMENTAL REGULATION CONSOLIDATED UTILITIES COMPANY, INC., Petitioner, vs. DOAH Case No. 83-352 OGC Case No. 82-0581 STATE OF FLORIDA DEPARTMENT OF ENVIRONMENTAL REGULATION, Respondent. /
Findings Of Fact Trans/Circuits is a manufacturer of electronic printed circuit boards located at 210 Newman Way, Lake Park, Florida. Trans/Circuits' manufacturing operation involves the deposition of copper on plastic boards and the use of a lead or tin etch resist in order to create an electrically conducting circuit board. In the course of the manufacturing process, rinsewaters are used which become contaminated with copper and lead from the manufacturing process. These rinsewaters undergo chemical treatment to remove the metals and other contaminants, and are then discharged into an unlined percolation pond located behind Trans/Circuits' facility. About 36,000 gallons of effluent are discharged into the pond every day. The percolation pond discharges into ground water underlying Trans/Circuits' facility which groundwaters contain less than 3000 milligrams per liter (mg/l) of total dissolved solids. Trans/Circuits uses a Havviland brand wastewater treatment system. The system at present does not provide treatment sufficient to remove copper, fluoride, and lead from the wastewater effluent in compliance with the DER class G-II groundwater standards for these metals, i.e., 1.0 mg/l of copper, 1.5 mg/l of fluoride, and .05 mg/l of lead. Trans/Circuits has exceeded the effluent limitations for copper and lead at almost all times since at least June 1984. Trans/Circuits is not likely to comply with those standards for at least six months, by Trans/Circuits' own admission. The Operating Permit Application, Case No. 83-3676 Trans/Circuits requested a hearing to contest the DER Notice of Intent to Deny the application for an operating permit. The burden of proof and burden of going forward is therefore on Trans/Circuits to show that it is entitled to issuance of the operating permit. In this regard, Trans/Circuits did not introduce into the case any evidence relating to the operating permit application and did not introduce the application, itself. Further, Trans/Circuits did not present any evidence that its installation will abate or prevent pollution, or that it can provide reasonable assurances that the system which it seeks to operate will not discharge, emit or cause pollution. The Trans/Circuits facility has never been in compliance with DER standards and cannot provide assurances that it will be in compliance at anytime in the foreseeable future. Further Trans/Circuits has been operating without an operating permit at least since October 1983. The Month-to-Month Authorization, Case No. 84-0191 On September 17, 1982, DER issued a Notice of Violation and Orders for Corrective Action (NOV) to Trans/Circuits. The NOV alleged that Trans/Circuits violated provisions of Chapter 403, Florida Statutes, and DER rules in operation of its industrial waste water treatment and disposal system. Trans/Circuits requested and received an informal conference to discuss the allegations of the NOV, which conference was held on October 20, 1982. At the informal conference, DER and Trans/Circuits reached agreement on a resolution of the issues raised by the NOV. On November 4, 1982, a Consent Order was issued by DER, setting forth the parties' agreement and requiring Trans/Circuits to perform certain corrective actions. In the consent order, Trans/Circuits agreed not to discharge industrial wastewaters into waters of the state "without an appropriate and valid permit authorizing such discharge or having otherwise obtained Department authorization." At the time the consent order was issued, Trans/Circuits was operating pursuant to a DER construction permit which was issued for the purpose of allowing Trans/Circuits to make certain modifications to its treatment system to bring the system into compliance with DER effluent standards. The construction permit expired in January 1983, but Trans/Circuits continued to operate. About one month after the construction permit expired, DER notified Trans/Circuits that it was violating the consent order by operating without DER authorization. The parties met to discuss the matter, and agreed that Trans/Circuits would cease operation for one week to conduct bench-scale testing to identify problem areas and possible corrective actions. Trans/Circuits did cease operation and conduct the testing as agreed. Trans/Circuits presented the data resulting from their bench scale testing to DER, and represented that it had identified problem areas that needed correction. DER evaluated the data and agreed to allow Trans/Circuits to operate for a limited time to gather plant effluent quality data which would form the basis for DER's decision whether to allow operation to continue. DER did not take enforcement action to have Trans/Circuits cease operation at that time because DER wanted to give Trans/Circuits time to show that it could comply with the effluent standards as it claimed it could. On March 23, 1983, DER notified Trans/Circuits that there had been a significant improvement in the plant's ability to produce effluent of acceptable quality, and DER authorized Trans/Circuits to make modifications in order to improve effluent quality. DER at that time gave Trans/Circuits authorization to operate for an indefinite period, with the condition that DER would rescind its approval if the program of sampling and system approval did not continue. Trans/Circuits accepted the authorization on DER's terms. On April 12, 1983, DER granted Trans/Circuits' month-to-month authorization to operate ". . . provided continued improvement is made in your system's operation and the Department can reasonably anticipate system compliance." This authorization was in response to a request from Trans/Circuits for 90-day temporary operating approval in order to demonstrate that the system could comply with state standards. By letter dated October 5, 1983, DER withdrew its authorization for month-to-month operation of Trans/Cirouits' facility because it believed that compliance with state standards could no longer be reasonably anticipated. Despite Trans/Circuits' best efforts, the facility was not in compliance and DER had no assurance that continued operation would bring the facility into compliance within a reasonable amount of time. Trans/Circuits has never ceased operation since DER withdrew its month-to-month operating approval. Trans/Circuits has not had a DER permit for construction or operation of the facility since the expiration of their last construction permit in January, 1983. At a meeting on December 1, 1983, Trans/Circuits' general manager admitted that he was aware that Trans/Circuits' was in violation of the terms of the consent order by continuing to operate without DER authorization. Analysis of Trans/Circuits' plant effluent for April 1983, shows that average lead levels were 0.21 parts per million (ppm) (or mg/l), average fluoride levels were 2.45 ppm, while average copper levels were 0.51 ppm. These were the effluent levels existing when Trans/Circuits was granted its month-to- month approval for operation. Since the month-to-month authorization was granted, the majority of Trans/Circuits' effluent samples have not complied with the DER standards for lead, copper, and fluoride. Since April 16, 1984, five percent or less of Trans/Circuits' effluent samples have complied with the effluent standards for lead and copper. In the week or two prior to hearing, the majority of effluent samples contained lead at a concentration of 0.2 to 0-5 ppm (with some higher), and contained copper at a concentration of between 2 and 3.5 ppm (with some higher). The most recent data available indicate that Trans/Circuits is not in compliance with the effluent standards for lead, copper and fluoride. Daily average effluent concentrations for lead and copper are significantly greater now than they were when DER issued its month-to-month authorization. Groundwater samples just outside Trans/Circuits' property show violations of the DER standards for lead. The evidence shows that Trans/Circuits effluent quality has not improved since April 1983. Effluent concentrations of lead and copper have actually increased significantly since October 1983, when DER withdraw its month-to-month authorization. Trans/Circuits does not even expect to know before December 1984, whether its present system can attain compliance with effluent standards. The Construction Permit Application On March 8, 1984, Trans/Circuits applied to DER for a permit to construct modifications and improvements to the existing Havviland wastewater treatment system. Although the stated purpose of the requested construction was to upgrade the system to achieve compliance with the Riviera Beach Sewer Use Code so as to allow a sewer tie-in, Trans/Circuits had abandoned that purpose by the time of the hearing. Trans/Circuits now seeks to upgrade the systems so that the effluent can comply with the applicable standards for discharge to ground water. When DER received the application, it was reviewed by a DER engineer to see if it was complete. The engineer determined it was not complete, and notified Trans/Circuits on April 6, 1984, that additional information was needed to complete the review process, all of which information was necessary to determine whether a permit should be issued for the requested construction. Trans/Circuits' general manager objected to the request for additional information, claiming that all the requested information was not necessary to review the application. However, at the request of Trans/Circuits' counsel, a meeting was held between representatives of Trans/Circuits and DER to discuss the request for information that was needed for review of the application. Trans/Circuits thereafter, withdrew their objections, and agreed to provide the requested information. Trans/Circuits responded to DER's request for additional information on June 27, 1984, at 3:30 P.M. the day prior to hearing. Trans/Circuits delivered a packet of information to DER at that time that purported to be the requested information. Also at that time, however, Trans/Circuits told DER that it had already performed some of the construction for which a permit was sought, and that it was not sure what, if any, of the remaining construction would be undertaken. The information that was submitted to DER was not all of the information requested by DER. No flow diagram was submitted and waste effluent analysis was lacking. Without this information, it is impossible to determine whether or not reasonable assurance has been provided by Trans/Circuits that DER standards will be met. Even if all of the requested information had been submitted, DER could not issue a construction permit to Trans/Circuits because its future construction plans are now only speculative. Trans/Circuits does not know what modifications it intends to construct, or when exactly such modifications will be made. All that is certain is that Trans/Circuits does not intend any longer to construct the modifications for which it made application. DER evaluates applications to determines whether all proposed modifications works as a system. Trans/Circuits is the applicant for this permit and has the burden of showing that it is entitled to issuance of the permit. Here Trans/Circuits failed to present any evidence of what construction it actually plans to do, let alone that the purposed construction meets the criteria and that it is entitled to the permit.
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED: That a Final Order be entered by the State of Florida Department of Environmental Regulation: Denying Trans/Circuits application for an operation permit; Denying Trans/Circuits application for a construction permit; and Withdrawing the month-to-month authorization for Trams/Circuits' operation. DONE and ENTERED this 19th day of September, 1984, in Tallahassee, Florida. DIANE K. KIESLING 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 19th day of September, 1984.
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 =================================================================
The Issue The issues to be resolved in this proceeding are: whether the Governor and Cabinet, sitting as the Siting Board, should approve the application of Progress Energy Florida (PEF) to certify and license the construction and operation of a 2200 megawatt (MW) (nominal) nuclear electrical generating facility and associated facilities, including electrical transmission lines; and, if so, what conditions of certification should be imposed.
Findings Of Fact Background Florida Power Corporation, doing business as Progress Energy Florida, Inc. (PEF), provides electricity and related services to approximately 1.7 million customers in the state of Florida. PEF's retail service area spans 35 counties over about 20,000 square miles in central and west Florida. In Florida, PEF operates and maintains more than 43,600 miles of distribution and transmission lines that serve a population of more than 5 million people. PEF owns and operates a diverse mix of electrical generating units in Florida, including approximately 47 combustion turbines, 5 combined cycle units, 12 fossil units, and one nuclear unit at PEF's Crystal River Energy Complex (CREC). The CREC is located in northwest Citrus County approximately four miles west of U.S. Highway 19 on the Gulf of Mexico. There are five generating facilities within the CREC; four units are coal-fired and one is a nuclear unit. PEF considered locating new nuclear generating capacity at the CREC, but determined that would concentrate too much electrical generation at one site. PEF proposes to build and operate a two-unit nuclear- powered electrical generating facility in Levy County (LNP). Directly associated facilities include a heavy haul road used for construction (Levy County), two site access roads (Levy County), and cooling water intake and discharge pipelines (Levy and Citrus Counties). PEF also seeks certification of nine transmission corridors associated with eleven electrical transmission lines: Citrus 1 and 2 Transmission Lines — proposed LNP to proposed Citrus Substation, two 500-kV Transmission Lines (Levy and Citrus Counties), also referred to as the "LPC" Lines; Crystal River Transmission Line — proposed LND to existing CREC Switchyard, one 500-kV Transmission Line (Levy and Citrus Counties), also referred to as the "LCR" Line; Sumter Transmission Line — proposed LNP to proposed Central Florida South Substation, one 500-kV Transmission Line (Levy, Citrus, Marion, Sumter and Lake Counties and Municipalities of Wildwood and Leesburg), also referred to as the "LCFS" Line; Levy North Transmission Line — proposed LNP to existing 69-kV Inglis-High Springs Transmission Line, one 69-kV Transmission Line for LNP construction/administration (Levy County), also referred to as the "IS" Line; Levy South Transmission Line — proposed LNP to existing 69-kV Inglis-Ocala Transmission Line, one 69-kV Transmission Line for LNP construction/administration (Levy County and Town of Inglis), also referred to as the "IO" Line; Brookridge Transmission Line — existing CREC Switchyard to existing Brookridge Substation, one 230 kV Transmission Line (Citrus and Hernando Counties), also referred to as the "CB" Line; Brooksville West Transmission Line — existing Brookridge Substation to existing Brooksville West Substation, one 230-kV Transmission Line (Hernando County), also referred to as the "BBW" Line; Crystal River East 1 and 2 Transmission Lines — proposed Citrus Substation to existing Crystal River East Substation, two 230-kV Transmission Lines (Citrus County), also referred to as the "CCRE" Lines; and Polk-Hillsborough-Pinellas Transmission Line — existing Kathleen Substation to existing Lake Tarpon Substation, one 230-kV Transmission Line (Polk, Hillsborough and Pinellas Counties and municipalities of Tampa, Plant City and Oldsmar), also referred to as the "Kathleen" Line. Need for the Project The PSC issued its Final Order determining the need for the Project on August 12, 2008. The PSC found: "a need for Levy Units 1 and 2, taking into account the need for electric system reliability and integrity"; "a need for Levy Units 1 and 2, taking into account the need for fuel diversity"; "a need for Levy Units 1 and 2, taking into account the need for base-load generating capacity"; "a need for Levy Units 1 and 2, taking into account the need for adequate electricity at a reasonable cost"; "[t]here are no renewable energy sources and technologies or conservation measures taken by or reasonably available to PEF which might mitigate the need for Levy Units 1 and 2"; and "Levy Units 1 and 2 will provide the most cost-effective source of power." The PSC also found a need for the associated transmission lines. New transmission lines are required to interconnect and integrate the proposed plant into PEF's existing transmission grid and to reliably deliver bulk power to PEF's load centers. Load flow studies were conducted by PEF system planners to identify the appropriate transmission end- points and voltages. The proposed transmission lines in PEF's proposed corridors satisfy the need for transmission lines as determined by the PSC. Public Notice and Outreach PEF has engaged in extensive public outreach for the selection of the LNP site and for the transmission line corridors. With regard to the plant portion of the Project, PEF's outreach efforts have included communications with local community leaders, press releases, communications with state and federal legislators, dissemination of information to the general public and property owners in the vicinity of the plant via mailings and open houses, and participation in community and advisory groups. With regard to the electrical transmission line portion of the Project, public involvement has been key to the corridor selection process. PEF developed a Community Partnership for Energy Planning (CPEP) process to gain feedback from members of the community in a manner that would most effectively involve the community in the transmission line corridor selection process. Through the CPEP process, PEF established leadership teams in three geographic regions: Hillsborough, Pinellas, Pasco, and Polk Counties; Citrus, Hernando, and Levy Counties; and Lake, Marion, and Sumter Counties. The leadership teams identified and selected more than 100 community representatives to participate in regional Utility Search Conferences. The Utility Search Conferences involved intensive two-day discussions of local issues and the future of electricity supply in the region. The purpose of the conferences was to inform the participants about the Project, to gain public input, and to allow participants to nominate community members to become part of the Community Working Groups for the remainder of the Project. PEF formed the Community Working Groups to further study and refine the recommendations of the conferences as well as to provide ongoing input to PEF throughout the Project. PEF also held open houses in February and March 2008 to involve the public in the transmission line corridor selection process. PEF used newspaper advertisements, press releases, and direct mail letters to facilitate public awareness of the open houses. Over 2,900 people attended the open houses, and PEF received completed written questionnaires from 2,071 attendees. The goal of PEF's public outreach program (with regard to both the plant and transmission lines) was to provide information in a transparent manner to the public and to provide ample opportunity and many avenues for the public to provide input during all phases of the Project. In total, PEF has conducted over 40 public presentations and sent communications to more than 125,000 property owners and stakeholders regarding the Project. Many of PEF's outreach efforts have been beyond the efforts required by law. Pursuant to Section 403.5115(6), Florida Statutes, PEF provided direct notice by mail of the filing of the SCA to all landowners whose property and residences are located within: three miles of the proposed main site boundaries of the LNP; one-quarter mile of a transmission line corridor that only includes a transmission line as defined by Section 403.522(22), Florida Statutes; and (3) one-quarter mile for all other linear associated facilities extending away from the main site boundary. PEF timely submitted a list of the landowners and residences notified to DEP's Siting Coordination Office (SCO), as required by Section 403.5115(6)(b), Florida Statutes. PEF made copies of the SCA available at two of its offices and ten public libraries. In addition, PEF provided copies to all local governments and agencies within whose jurisdiction portions of the Project will be located. DEP made an electronic version of the document available on its website. On June 19, 2008, PEF published notice of the filing of the SCA in the Ocala Star-Banner, the Hernando Today, the Tampa Tribune, The Lakeland Ledger, The Villages Daily Sun, the Levy County Journal, the Orlando Sentinel, the Gainesville Sun, the Citrus County Chronicle, the Sumter County Times, the Hernando Times, and the North Pinellas Times, satisfying the requirements of Section 403.5115(1)(b), Florida Statutes, and Florida Administrative Code Rule 62-17.281(3). On December 18, 2008, PEF published notice of the certification hearing in the same newspapers, satisfying the requirements of Section 403.5115(1)(e), Florida Statutes, and Florida Administrative Code Rule 62-17.281(7). PEF published amended notices of the site certification hearing in the same newspapers on February 17, 2009. DEP also published notices in the Florida Administrative Weekly. All notices required by law were timely published and/or provided in accordance with Section 403.5115, Florida Statutes. Agency Reports and Stipulations Agency reports and proposed conditions of certification on the plant-related facilities of the Project were submitted to DEP by: (1) the PSC; (2) DCA; (3) SWFWMD; (4) Levy County; (5) FWC; (6) the Withlacoochee Regional Planning Council; and (7) DOT. All of these agencies either recommended approval of the Project or otherwise did not object to certification. Although Citrus County did not file an agency report, it recommended approval of the LNP in the prehearing stipulation of the parties. Affected state, regional, and local agencies reviewed the SCA and submitted to DEP reports concerning the impact of the transmission lines on matters within their respective jurisdictions and proposed conditions of certification, as required by Section 403.507(2), Florida Statutes. None of the agencies involved in the review process have recommended that the proposed electrical transmission line corridors be denied or modified. On September 25, 2008, DEP issued its written analysis on the transmission line portion of the Project, incorporating the reports of the reviewing agencies and proposing a compiled set of conditions of certification. The conditions of certification were subsequently revised to reflect agreed-upon language. DEP recommended that the PEF proposed transmission line corridors be certified subject to the conditions of certification. On January 12, 2009, DEP prepared a Staff Analysis Report (SAR) compiling all of the agency reports on the power plant, proposing conditions of certification, and making an overall recommendation. DEP recommended certification of the Project subject to conditions of certification. The conditions of certification attached to the SAR have been superseded by the Fourth Amended Conditions of Certification filed by DEP as DEP Exhibit 1 on March 23, 2009. PEF is committed to constructing the LNP in accord with these conditions. Plant and Associated Facilities2 Project Overview PEF's proposed nuclear-powered electric generating facility (the LNP) will be located in Levy County. The LNP site is east of U.S. Highway 19 and approximately four miles north of the Town of Inglis and the Levy-Citrus County border. The LNP site contains approximately 3,105 acres, with the two reactors and ancillary power production support facilities located near the center of the site. The majority of the LNP site is currently active silviculture and is unimproved. The proposed heavy haul road and pipelines will be located in corridors south of the LNP site. Two site access roads will tie into U.S. Highway 19 west of the site and proceed east to the main plant area. PEF also owns a second 2,000-acre tract contiguous with the southern boundary of the LNP site, which provides access to a water supply in the Cross Florida Barge Canal (CFBC) as well as containing the heavy haul road and electrical transmission line corridors that exit the LNP site. Project Description The LNP will include two 1,100 megawatt (MW) (nominal) generating units (LNP 1 and LNP 2) designed by Westinghouse Electric Company, LLC (Westinghouse). The reactor design has received an official design certification from the NRC and is referred to as the Westinghouse AP1000 Reactor (AP1000). The AP1000 is a standardized, advanced passive pressurized-water nuclear reactor. PEF proposes to place LNP 1 in commercial service by 2016 and LNP 2 in commercial service by 2017. In the AP1000, the reactor core heats water which flows through the reactor cooling system in the primary loop. The reactor coolant pump circulates water through the reactor core. A pressurizer is used to maintain a constant pressure in the primary loop. The heated water flows to the steam generator and through a combination of U-shaped tubes, transferring heat to a separate, independent closed-loop water system, or the secondary loop. Inside the steam generator, the water in the secondary loop boils and is separated in dryers which produce high quality steam. The reactor, the four coolant pumps, and the two steam generators are contained in the containment shield building for each unit. Within the shield building, a steel containment structure surrounds the reactor and steam generators. A passive cooling water tank, which will provide emergency cooling, sits in the top of the containment shield building. The steam in the secondary loop is routed to the adjacent turbine building where it goes into a high-pressure turbine and then three low pressure turbines. The steam produces the force to turn the turbines, which then turn the electrical generator. Electricity is then sent to the on-site switchyard for transmission. The steam exhausting from the turbines moves into the condenser where it comes into contact with the cold surfaces of the tubes in the condenser, which contain water circulating from the cooling tower. The steam condenses back to water. The condensed water is collected in the bottom of the condenser and pumped back into the steam generator. The cycle then repeats. Other components of the AP1000 design include an annex building which contains the main control room; a fuel handling area where new fuel is received and spent fuel is stored; and a diesel generator building. Two cooling towers, three stormwater runoff ponds, and one electrical transmission 500 kV switchyard serving both units are also to be located near the generating units. Each LNP unit will be equipped with a recirculating cooling water system, including a cooling tower, that supplies cooling water to remove heat from the main condensers. The cooling tower makeup water system supplies water to the cooling tower to replace water consumed as a result of evaporation, drift, and blowdown. The LNP's cooling water intake will be located on the CFBC. Cooling water will be conveyed to the LNP site via pipelines. The proposed corridor for the cooling water intake and wastewater discharge pipelines is approximately 13 miles long and 0.25 miles wide. The intake pipeline corridor extends south from the LNP site to the CFBC. The wastewater discharge corridor then turns westerly along the CFBC for six miles before turning south along the western side of an existing PEF transmission line and enters the CREC. As part of its pending application for an NPDES permit, PEF has proposed that LNP wastewater be released into the existing CREC discharge canal. Materials needed to construct the LNP will be delivered via: (1) U.S. Highway 19; and (2) a barge slip on the CFBC in conjunction with the heavy haul road for large components. The heavy haul road, to be used primarily during construction, will be co-located with the makeup and blowdown pipeline corridor south of the LNP site. Federally-Required Approvals The LNP is also subject to the construction and operation approval of the NRC. As part of the federal permitting process for nuclear power plants, PEF has submitted a Combined Operating License Application (COLA) to the NRC. PEF submitted the COLA for the LNP on July 30, 2008. The NRC's review is in progress, and a decision on the application is expected in late 2011. PEF has also requested a Limited Work Authorization (LWA) from the NRC. The LWA request covers the installation of a perimeter diaphragm wall and preliminary foundation work for the two units, and related buildings that are not nuclear safety-related items. An NRC-certified design for the AP1000 allows an applicant for NRC COL approval to avoid readdressing matters that the NRC has already considered when reviewing an individual COLA that uses that standard design. This approach is expected to provide more predictability and reduce the NRC's licensing review process. For PEF, the advantages of a standard design include the ability to apply lessons learned from other projects being constructed ahead of the LNP, as well as improved performance in cost and scheduling. PEF is seeking certification under the PPSA prior to completion of the NRC approval because state site certification will allow PEF to begin early site preparation (such as access roads) and will allow PEF to proceed to acquire property rights within the electrical transmission corridors. The NRC regulates radiological effluents and monitoring at nuclear power plants. The state of Florida does not have regulations specifically applicable to regulation of spent nuclear fuel. Under NRC regulations, nuclear power plants are required to have radiological environmental monitoring programs (REMPs). Part of the REMP is an offsite dose calculation manual (ODCM). The Florida Department of Health (FDOH), Bureau of Radiation Monitoring, performs much of the monitoring in the ODCM at nuclear power plants under an agreement with the NRC. See 42 U.S.C. § 2021(b); Florida Administrative Code Chapter 64E-5. The FDOH also monitors groundwater wells in the vicinity of a nuclear plant for numerous parameters, including radiological releases. In addition to the separate NRC approvals, PEF has filed applications with DEP for [a federally-required Prevention of Significant Deterioration (PSD) air construction permit under the federal Clean Air Act, a National Pollutant Discharge Elimination System (NPDES)] permit under the federal Clean Water Act, and (in accordance with 403.506(3), Florida Statutes) a state-required environmental resource permit (ERP) from DEP for construction of a new barge slip on the CFBC. DEP issued the final PSD air construction permit on February 20, 2009. DEP has not taken final agency action on the pending NPDES permit application. Federally-required permits issued by the DEP under the Clean Air Act and Clean Water Act are not subject to the PPSA. The PPSA provides that federal permits are reviewed and issued separately by the DEP, but in parallel with the PPSA process to the extent possible. Upon issuance, these federal permits will be incorporated into the conditions of certification. The separate DEP-issued ERP will also be incorporated by reference into the final site certification. Water Use The LNP has two primary needs for water: (1) saltwater to cool the steam condensers (circulating water); and (2) freshwater for power generation and component cooling (service water). Freshwater will be drawn from the upper Floridan aquifer. Saltwater will be supplied from the Gulf of Mexico via the CFBC. A circulating water system can be designed to use either freshwater or saltwater. Common design practice is to use the most abundant source; so saltwater was selected for the LNP. The service water system components for the LNP are established by Westinghouse for the AP1000 standard design and require freshwater. The service water system for the AP1000 reactor has been designed to provide an efficient means of cooling plant components with a relatively small demand for freshwater. Most of the water to be used at the LNP site will be needed for steam condenser cooling which will take place in two cooling towers; one for each unit. The source for cooling tower makeup water will be surface saline water withdrawn from the CFBC. Approximately 122 million gallons per day (mgd) will be withdrawn from the CFBC for cooling water needs. A new intake structure would be constructed on the canal bank at a site south of the LNP site and west of the Inglis Lock on the CFBC, approximately 6.5 miles inland from the Gulf of Mexico. Saltwater will be pumped from the CFBC and directed into the cooling tower basin. The circulating water system is a closed-cycle cooling system and is the primary heat sink for the plant during normal operation. Circulating water pumps direct water to the steam condenser to cool the steam after it passes through the main turbines. The heated saltwater is then returned to the cooling towers where it is cooled by air flow and returned to the cooling tower basin. The LNP recirculating cooling water will be cooled by induced draft, counter-flow, mechanical cooling towers. For each unit's cooling tower, there are 44 cooling tower cells, grouped into two banks of 22 cells each. Each of the cooling tower cells will be approximately 75-feet tall. The total length of each 22-cell cooling tower is approximately 1,200 feet. The LNP will have a continuous need to utilize cooling water. Most of the water loss in the cooling towers is a result of evaporation of the water being cooled in the cooling towers. A small amount of circulating water is lost from the cooling towers as liquid droplets entrained in the exhaust air steam. This is known as "drift." When water evaporates from the cooling tower, minerals and solids are left behind. As more water evaporates, the concentration of these materials increases. This concentration is controlled by continuously releasing and replenishing some water from the tower. Accordingly, both saltwater and freshwater are continuously discharged from the plant to help maintain proper water chemistry. This continuous release of water is called "blowdown" and, as proposed in PEF's pending NPDES application, it will be discharged to the discharge canal for the CREC and then into the Gulf of Mexico, a Class III marine water. The LNP will require up to 1.58 mgd, annual average, of freshwater. This freshwater will be used for plant operations, fire suppression, potable water needs, and demineralized water needs. Groundwater will be withdrawn from four supply wells at the south end of the PEF-owned property south of the LNP site. The AP1000 service water system requires freshwater for use in component cooling. The service water system provides cooling water for the nonsafety-related component cooling water heat exchangers. Demineralized water is processed to remove ionic impurities and dissolved oxygen and is used for plant operations that require pure water, primarily the feed water and condensate systems used in power production. When operational, the LNP site must be capable of supplying potable water to approximately 800 employees and visitors daily. Potable water will also be needed for onsite construction. The fire protection system will be capable of providing water to points throughout the plant where wet system fire suppression could be required. The fire suppression system is designed to supply water at a flow rate and pressure sufficient to satisfy the demand of automatic sprinkler systems and fire hoses for a minimum of 2 hours. Cooling Water Intake Structure The LNP cooling water intake structure (CWIS) will be located on the berm that forms the north side of the CFBC approximately 3 miles south of the LNP, downstream of the Inglis Lock. The CWIS will withdraw surface water into four intake pipelines (two for each nuclear unit) that will convey water to the cooling tower basins for use in the cooling towers. These 54-inch diameter pipelines will generally be buried to a minimum depth of five feet. The pipelines will cross over the Inglis Lock Bypass Channel located north of the CFBC on an approximately 33-foot-wide utility bridge. For each of the LNP units, the CWIS will contain three 50 percent capacity makeup pumps, each with a design flow rate of 23,800 gallons per minute (gpm). Two pumps will provide normal cooling tower makeup flow requirements for each unit. The third spare pump will be in standby mode and automatically start if one of the operating pumps shuts down for any reason. A dual-flow traveling screen upstream of each makeup pump will screen floating and suspended materials in the CFBC water. The screen opening will be 3/8-inch. The screens will be sized to ensure that the through-screen water velocity is no more than 0.5 feet per second (fps) to reduce the impingement and entrainment of aquatic life that could enter the pump bay. The velocity of the water in the intake bay upstream of the traveling screens (the approach velocity) will be about 0.25 fps. Upstream of the traveling screens will be trash racks (also referred to as bar racks). These are a series of steel bars (4 inches apart) to prevent large objects from entering the CWIS. Potential Impacts of Surface Water Intake Cooling water will be withdrawn via the CWIS from a section of the CFBC that extends approximately 7 miles from the Inglis Lock west to the Gulf of Mexico. Operation of the Inglis Lock was discontinued in 1999; the lock separates Lake Rousseau (to the east) from this section of the CFBC. This section of the CFBC has a continuous opening to the Gulf of Mexico. The CFBC bisects the Withlacoochee River, severing the original hydraulic connection between Lake Rousseau and the Lower Withlacoochee River. To maintain flow to the Lower Withlacoochee River which is north of the CFBC, the Inglis Lock Bypass Channel and associated Inglis Lock Spillway were built adjacent to the Inglis Lock (north of the CFBC). Flows in the CFBC are primarily a result of tides coming in and out from the Gulf of Mexico and, to a lesser extent, rainfall. Periodically, freshwater is released from Lake Rousseau into the CFBC via the Inglis Dam. Also, there is some groundwater seepage into the CFBC as well as minor leakage from the Inglis Lock. Residence time for water in the CFBC near the proposed CWIS is currently over 200 days; there is very little outflow. Waters in the CFBC downstream of the Inglis Lock vary in salinity seasonally, with tidal influences, and depending on freshwater releases from the Inglis Dam. On average, the salinity in the area of the CFBC where the intake structure is proposed to be located is approximately 10 parts per thousand (ppt). As the CFBC approaches the Gulf of Mexico, salinity increases, averaging over 20 ppt and as high as 30 ppt. The CFBC ranges from approximately 200-to-260 feet wide. There is vegetation along the banks, as well as riprap, the latter consisting of huge rocks to limit erosion. The upper end of this section of the CFBC has algal blooms during the summer and muddy, silty bottom conditions that limit biological activity. The CFBC does not have seagrass beds that serve as aquatic habitat, except downstream where it joins with the Gulf of Mexico. The CFBC does not serve as significant habitat for endangered fish species, such as the Gulf Sturgeon or Smalltooth Sawfish. Although freshwater and saltwater species may use the CFBC occasionally, it does not serve as significant spawning habitat for any migratory, sport, or commercial fish species. Pursuant to the proposed conditions of certification, pre- operational monitoring and sampling in the CFBC will be used to identify any changes in the use of that canal by such fish species. With regard to the remnant section of the Withlacoochee River between the Inglis Dam and the CFBC (Old Withlacoochee River, or OWR), the biota in the middle and lower reaches of that waterbody currently show the effects of variable salinity levels; these areas are characterized by organisms typically found in marine conditions. The upper reach of the OWR has species normally found in freshwater systems. Aquatic species in the OWR are affected by periodic releases from the Inglis Dam. The LNP CWIS hydraulic zone of influence on the CFBC extends about 5 miles to the west down the approximately 7-mile long CFBC. The hydraulic zone of influence defines the point at which the flow of the CFBC would be affected by the CWIS, under static conditions. In its biological analysis, PEF assumed that potential intake impacts would extend beyond this hydraulic zone of influence. After installation and operation of the LNP CWIS, the dominant forces affecting flow conditions in the CFBC will continue to be primarily tidal activity and releases from Lake Rousseau. The CFBC will become more saline. However, installation and operation of the LNP CWIS will improve flow conditions in the CFBC by adding consistent and very slow upstream movement of about 122 mgd. The LNP CWIS will cause the saline-freshwater transition zone to move up the remnant channel of the OWR, south of the CFBC. The increased salinity is not expected to affect the small enclave of freshwater organisms living in that upper segment of the OWR. Potential adverse impacts from a CWIS include entrainment (when organisms smaller than the screen openings enter the cooling water) and impingement (when organisms larger than the screen openings become trapped on the screen). Potential impacts of entrainment and impingement will be minimized because the LNP CWIS will utilize a closed-cycle recirculating cooling water system which will reduce the amount of cooling water required by approximately 90 percent; the through-screen velocity will be 0.5 fps or less; and the LNP will not disrupt thermal stratification in the CFBC. Under federal law, DEP will make the final determination of compliance with Section 316(b) of the Clean Water Act requirements in the NPDES permit. The LNP CWIS is not expected to pose a threat to threatened or endangered species or migratory, sport, or other fish species. Monitoring for fish species in the CFBC will be undertaken under the FWC's proposed conditions of certification to identify any actual impacts to such species and the need for any mitigation for such impacts. Locating the CWIS near the Inglis Lock on the CFBC will result in less entrainment and impingement impacts compared to potential locations closer to the mouth of the CFBC or in nearby off-shore waters. Proposed conditions of certification require PEF to submit a post-certification survey and monitoring plan for the CFBC and Withlacoochee River to assess actual impacts of the withdrawals for the LNP on these water bodies. If, after review of the annual reports required by these conditions by FWC, DEP, and SWFWMD, there is an indication of adverse impacts, PEF must submit a CFBC and/or Withlacoochee River mitigation plan to mitigate those impacts. As part of its pending NPDES permit application, PEF submitted a "316(b) Demonstration Study" to address compliance with intake standards applicable to the LNP CWIS. Final agency action on the NPDES permit application, including a determination of compliance with Section 316(b) regulations, has not been taken by DEP. Under 40 C.F.R., Subpart I, Sections 125.80-125.89, if pre- and post-operational monitoring demonstrates unacceptable adverse impacts associated with the CWIS, operational and technological improvements to the CWIS may be required. Under the proposed conditions of certification, the final NPDES permit for the LNP will be incorporated by reference into the conditions of certification. Operation of the CWIS is expected to have a negligible impact on saltwater intrusion in the area bounded to the south by the CFBC and to the north by the Lower Withlacoochee River. The waters of the CFBC are marine waters. There currently is stratification in the CFBC, with higher salinity along the bottom of the water column. The change in density of water in the CFBC as a result of the increased salinity due to the LNP's proposed water use in the CFBC is not expected to affect freshwater resources. The tide in the CFBC currently fluctuates 2-3 feet twice per day. The construction of the CFBC and the bisection of the Withlacoochee River have resulted in reduced freshwater flows in the lower portion of the Withlacoochee River north of the CFBC. There is no direct connection between the CFBC and the Lower Withlacoochee River (north of the CFBC). The flow in the By- pass Channel provides less freshwater from Lake Rousseau to the Withlacoochee River than historically flowed into the lower portion of the River. This has caused saltwater to move up the Lower Withlacoochee River, particularly during periods of low flow. SWFWMD has evaluated restoration of the River to its original condition, but has not advocated reconnection. Reconnection of the Withlacoochee River or downstream impoundment of the CFBC probably would not prevent the impacts of increased salinity in the Lower Withlacoochee River during periods of low freshwater flow. Although no agency is currently pursuing a project of this type, DEP has proposed a condition of certification to address future public projects for the maintenance, preservation, or enhancement of surface waters requiring modifications to the CFBC. Potential Impacts to Manatees Manatees use the Withlacoochee River and the CFBC year round, but primarily during the warmer months. The CFBC, including the area of the LNP intake, is not listed as critical habitat for manatees under the federal Endangered Species Act. Construction activities in the CFBC can take place in a manner reasonably likely to avoid adverse impacts to manatees. The FWC has proposed conditions of certification designed to protect manatees from adverse impacts of in-water construction through monitoring and mitigative measures. Compliance with these conditions will minimize impacts to manatees. The operation of the LNP cooling water intake structure (CWIS) is not likely to adversely impact manatees. The potential impacts of the LNP CWIS on manatees will be minimized by the system design and location. Additionally, DEP and FWC have proposed conditions of certification requiring PEF to submit a final CWIS plan for review by FWC prior to construction of the CWIS with regard to manatee safety issues. Potential impacts to manatees from barge traffic on the CFBC related to delivery of Project components and materials for the construction of the LNP is not expected to adversely impact manatees. FWC has proposed conditions of certification to protect manatees during in-water construction. Compliance with the proposed conditions of certification will minimize potential impacts to manatees. Impacts of Groundwater Withdrawals The LNP's proposed groundwater use meets all of the SWFWMD's water use criteria. To demonstrate that the proposed groundwater withdrawals associated with LNP operations will comply with the SWFWMD water use criteria, including not causing unacceptable adverse environmental impacts, PEF performed a groundwater modeling analysis using the SWFWMD's District-Wide Regulation Model 2 (DWRM2) groundwater flow model. The DWRM2 is an acceptable groundwater flow model for evaluating the effects of groundwater withdrawals. The DWRM2 modeling demonstrated that the proposed groundwater withdrawals would not lower surficial aquifer levels to the point of causing unacceptable adverse impacts to wetlands and other surface waters, or interfere with existing legal users. Groundwater pumping for the LNP is not expected to adversely impact Lake Rousseau, the Withlacoochee River, or other streams or springs in the Project area. Groundwater withdrawals for the LNP are likewise not expected to induce saline water intrusion, cause the spread of pollutants in the aquifer, adversely impact any offsite land uses, cause adverse impacts to wetland systems, or adversely impact any other nearby uses of the aquifer system. To confirm the values used in the groundwater flow model supporting the application, proposed certification conditions require that an aquifer performance testing plan be submitted by PEF, approved by the SWFWMD, and implemented. If leakance and transmissivity values derived from actual onsite well tests differ more than 20 percent from values determined through earlier modeling, PEF is required to revise its groundwater model to incorporate the aquifer test results and undertake further modeling. Updated groundwater modeling results will be used to determine whether alternative water supplies or additional mitigation will need to be implemented. To help ensure that the proposed groundwater use does not cause unacceptable adverse environmental impacts, SWFWMD and DEP recommended that conditions be included in the site certification requiring an environmental monitoring plan to evaluate the condition of surface waters and wetlands in areas that could potentially be affected by groundwater withdrawals. Monitoring will continue for a minimum of five years after groundwater withdrawals reach a quantity of 1.25 mgd on an annual average basis. Annual monitoring summaries will be submitted. If, after five years, this monitoring demonstrates that no adverse impacts of groundwater withdrawals are occurring or predicted, PEF may request that monitoring be discontinued. Groundwater withdrawals will be metered and reported to DEP and SWFWMD on a monthly basis. Proposed conditions of certification require periodic water quality sampling be performed on the withdrawn groundwater to ensure no adverse impacts to water quality. Proposed conditions also address ongoing monitoring and compliance by requiring a full compliance report every five years throughout the life of the LNP, to demonstrate continued reasonable assurance that the groundwater use is meeting all of the applicable substantive water use requirements set forth in SWFWMD rules. The SWFWMD has not established water reservations or minimum flows or levels for any waterbody in the vicinity of the LNP. Therefore, the use of water from the CFBC and from the ground will not violate any currently established water reservation or minimum flow or level. Fracture sets (also called solution channels) are small openings through which groundwater moves. Fracture sets are only an issue in groundwater flow if preferential flow paths develop near one of the solution channels. Preferential flow paths tend to develop near existing springs. There are no springs on the LNP site, and subsurface investigations did not reveal any evidence of solution channels under the site. PEF also proposes to withdraw groundwater as part of the dewatering needed for plant construction. PEF proposes to install an impervious diaphragm wall around and below the foundation excavations for each nuclear unit to minimize water flow into the construction site. It is anticipated that dewatering at each unit could last as much as two years. Additional construction dewatering will also be necessary in some locations for installation of the pipelines and other linear facilities. Naturally-occurring groundwater collected during dewatering and excavation activities will be directed into stormwater runoff ponds and allowed to filter back into the ground to recharge the surficial aquifer. Dewatering is expected to cause only a modest amount of drawdown of the surficial aquifer. Construction-related dewatering activities will be approved by DEP and SWFWMD on a post-certification basis after final construction designs are submitted. Potential Surface Water Discharge Impacts The LNP will have a combined wastewater discharge comprised of several wastewater streams. Blowdown from the cooling towers will comprise about 98 percent of the LNP wastewater. The blowdown will be combined with significantly smaller quantities of plant wastewaters, treated plant sanitary wastewater, and occasionally stormwater. LNP wastewaters consist of effluents from process equipment, floor drains, laboratory sample sinks, demineralized water treatment system effluent, and treated steam generator blowdown. Wastewaters will be processed before discharge. The treatment systems include oil separators (to separate oily wastes from the rest of the waste stream) and a wastewater retention basin (to settle out suspended particles). The combined LNP wastewater, as proposed by PEF in its pending NPDES permit application, will be piped to the CREC and released into the existing CREC discharge canal which flows into the Gulf of Mexico. The cooling tower blowdown discharges from the LNP will include saltwater blowdown from the plant recirculating cooling water system and freshwater blowdown from the service water cooling system; the vast majority of this will be saltwater blowdown from the plant recirculating cooling water system. The normal 2-unit recirculating water blowdown rate is expected to be 57,400 gallons per minute (gpm) or 81.4 mgd, and the maximum blowdown rate is expected to be about 59,000 gpm or 84.9 mgd. The 2-unit service water blowdown rate is expected to vary from about 130 gpm during normal operation, to a maximum of about 400 gpm. The CREC currently has two NPDES permits authorizing discharges to surface waters of the State. CREC Units 1, 2, and 3 are cooled with once-through cooling water from the CREC intake canal that is then discharged into the Gulf of Mexico via the existing CREC discharge canal. Once-through cooling water is cooling water that is released after condensing the steam, without being recycled in a cooling tower system. CREC Units 4 and 5 have cooling towers that receive make-up water from the CREC discharge canal and release blowdown into the discharge canal. The discharges for all five CREC units are released to the Gulf of Mexico through a single discharge canal at the CREC site. PEF has proposed to utilize the CREC discharge canal for the LNP discharge; however, the final location will be subject to approval as part of DEP's final agency action on PEF's pending application for an NPDES permit. The wastewater flow at the CREC is limited under the existing CREC NPDES permits to 1,898 mgd during the summer and 1,613 mgd during the winter. The expected day-to-day total wastewater flow from the LNP will be 83.4 mgd, with a conservative maximum total flow rate of 87.9 mgd. The proposed LNP discharge would be equivalent to 4-5 percent of the permitted discharge from the CREC. The design temperature of the LNP wastewater discharge is 89.1ºF, which is expected to be met more than 99.5 percent of the time. This LNP design temperature is cooler than the existing permitted temperature of the existing combined CREC discharge (96.5ºF). Even the expected worst case temperature of the LNP discharge (96.4ºF), will be cooler than the existing temperature limit applicable to CREC. With the addition of the LNP discharge, the CREC is expected to continue to meet its existing thermal permit limit. The addition of the LNP wastewater to the CREC discharge canal is not expected to significantly change the existing area of thermal impact associated with existing CREC discharges. Evaluation of the Project wastewater in this certification proceeding indicates that impacts to flora and fauna, including seagrasses and shellfish beds, will be minimized. PEF has committed to a condition of certification requiring the post-certification submittal of a surface water monitoring plan to DEP to ensure there will be no adverse impacts to seagrasses. The finding related to shellfish beds is supported by a letter from the Florida Department of Agriculture and Consumer Services to the DEP stating that "[r]eclassification of the shellfish harvesting areas will not be necessary if the Project is built as proposed." The LNP wastewater is projected to meet the limits defined under 10 C.F.R. Part 20. Evaluation of the LNP wastewater discharge in this certification proceeding indicates that impacts to surface water quality will be minimized. Adding the LNP discharge to the CREC discharge canal is not expected to have an adverse impact on manatees. The LNP discharge structure at the CREC is likewise not expected to cause adverse impacts to manatees that may be present in the CREC discharge canal. Evaluation of the LNP wastewater in this certification proceeding indicates that impacts to benthic invertebrates, fish, and other organisms in the Gulf of Mexico will be minimized. The discharge is not expected to have adverse impacts on endangered fish species. Proposed conditions of certification require PEF to submit a discharge monitoring plan to ensure that the addition of the LNP wastewater to the CREC discharge does not cause adverse impacts. If, after review of the annual reports required under these conditions by FWC, DEP, and SWFWMD, there is an indication of adverse impacts, PEF must submit a mitigation plan to address those impacts. DEP's final agency action on PEF's application for an NPDES permit for the LNP, if issued, will include final action on compliance with water quality standards and will be incorporated by reference into the conditions of certification. Surface Water Management System The LNP surface water management system consists of pipes and ditches that collect and convey stormwater from the plant area into onsite wet treatment ponds before discharge. Stormwater along the heavy haul road will be collected in roadside swales. The plant area will be raised approximately eight feet. Stormwater will drain from this area into three stormwater ponds. Any cross-flows from the plant site toward the raised areas will pass around the site through culverts or ditches. The stormwater ponds and swales are sized to treat stormwater releases to meet SWFWMD rules. In addition, all construction-related surface water management facilities will comply with SWFWMD's surface water management criteria. The design and proper construction and operation of the surface water management system will satisfy SWFWMD's water quantity and water quality criteria in Rules 40D-4.301 and 40D- 4.302. PEF has committed to a post-certification submittal of detailed stormwater design information to address floodplain impacts as required by section 4.7 ("Historic basin storage") of the SWFWMD Basis of Review for Environmental Resource Permit Applications (adopted in Rule 40D-4.091, which is incorporated by reference in Rule 62-330.200(3)(e)). Solid Waste Disposal There will be no onsite disposal of hazardous waste during construction of the LNP. All hazardous waste will be handled in accordance with applicable federal, state, and local regulations. Contractors will be responsible for having detailed procedures in place to handle hazardous waste. During operation, hazardous waste will be managed and disposed of in accordance with federal and state regulations under the federal Resource Conservation and Recovery Act. PEF has procedures in place for management and control of hazardous materials; such materials will be disposed of offsite through permitted facilities. All solid waste generated during construction will be disposed of at a permitted offsite landfill. There will be no onsite disposal of solid waste. Non-nuclear solid waste generated during operation of the LNP will be disposed of offsite at a permitted landfill. A proposed condition of certification precludes processing or disposal of solid waste onsite. Air Emissions, Controls, and Impacts The LNP is a nuclear-fueled power generating facility that will use uranium dioxide pellets in fuel rods. The LNP will also use a relatively small amount of diesel fuel in its emergency diesel generators, ancillary generators, and fire pump engines. Therefore, the LNP will not emit the typical types and quantities of air pollutants from fossil-fueled power generation such as sulfur dioxide, nitrogen oxides, particulates or carbon dioxide (CO2). The sources of air emissions at the LNP will include the two banks of mechanical draft cooling towers and diesel- fueled emergency power generators and fire pump engines. Air pollutants that will be emitted during normal facility operation will be limited to particulate matter (PM), both more than and less than 10 microns in diameter, which will be emitted from the low profile cooling towers. There will be a small amount of air emissions from the diesel-fueled emergency power generators and fire pump engines; however, these emissions are only expected to occur during the few hours per month when the engines are run for maintenance and testing purposes. There will be no other significant sources of air emissions from operation of the LNP. PM emissions from the draft cooling towers will occur as a result of the entrainment of a small amount of water, as small-diameter droplets, in the exhaust stream from the towers. Particulate matter, consisting of the naturally occurring dissolved solids that will be present in the cooling water, will be contained in these entrained droplets. The droplets and the associated suspended solid particulate matter are known as cooling tower "drift." The amount of cooling tower "drift" is controlled through the use of very high efficiency mist eliminators that will be in the cooling tower. The use of high efficiency mist eliminators on the LNP cooling towers is consistent with state and federal regulations that require the use of Best Available Control Technology to limit such air emissions. The LNP will be located in Levy County which is currently attaining all ambient air quality standards for all pollutants. The LNP will not have an adverse or discernible impact on ambient air quality at the LNP site, or at any location, for any regulated air pollutant. The LNP will not generate power by combusting any fuel. Therefore, there will be no measurable greenhouse gas emissions, including carbon dioxide, during normal plant operation. The estimated CO2 emissions from a natural gas-fired combined-cycle generating facility capable of generating the same amount of electricity as the LNP is approximately 6.4 million tons per year. For comparison, the estimated CO2 emissions from the LNP, which result from periodic testing of the facility's diesel-powered emergency equipment, is only 618 tons/year. Visible plumes from the cooling towers will remain very close to the cooling towers (within approximately 300 feet) under most meteorological conditions. The occurrence of visible vapor plumes at offsite locations is expected to be infrequent. The operation of the cooling towers is expected to have no significant or adverse impacts due to ground level fogging on any roadway or at offsite locations during plant operation. The maximum predicted offsite solids deposition rate from operation of the LNP cooling towers is six pounds per acre per month immediately adjacent to the nearest LNP property boundary. This is below the de minimis adverse impact threshold of nine pounds per acre per month published by the NRC. The rate of deposition is predicted to decrease rapidly and significantly with increasing distance from the plant. Operation of the LNP cooling towers is not expected to cause discernible impacts on any natural resources, including surface waters or wetlands. Noise Impacts of Construction and Operation The noise limits applicable to the LNP site are set by the Levy County Code of Ordinances. The noise limits defined by the County ordinance for the area surrounding the LNP site are 65 dBA from 7 a.m. to 10 p.m. and 55 dBA from 10 p.m. to 7 a.m. There are no other local, state, or federal noise regulations that apply to the plant. PEF conducted noise impact evaluations for construction and operation of the LNP. Ambient noise levels were measured at six locations around the LNP site. Noise levels were conservatively estimated by adding the composite average noise levels that would be generated by construction equipment during the loudest phases of construction. Equipment sound propagation factors were obtained from industry references. The noise model known as CADNA/A was used to predict noise levels at onsite and offsite locations, including the nearest residences for both construction and operation. The noise levels during construction activities and during normal maximum operation of the LNP plant site are projected to be below the Levy County noise limits for all hours at all offsite locations, including the locations of the nearest residences. Due to the large buffer surrounding the developed area of the site, and the relatively low noise levels associated with the LNP, there are not expected to be any significant or adverse noise impacts during construction or operation of the LNP. Wetlands and Terrestrial Ecology (Plant and Transmission Line Corridors) The proposed LNP site has been used for many decades for the production of pine. The clearing of native vegetation, furrowing, bedding, planting, and harvesting (primarily for pine) has altered the site from a natural Florida landscape into a monotypical landscape in both upland and wetland areas with reduced functional attributes. There are no open water bodies or streams on the LNP site. There are some flow-way connections between some of the wetlands, but they are not of the kind that will support long- term fish habitat or aquatic insect communities. Due to the silvicultural nature of the site and recent clearing, the ideal complement of biodiversity on the LNP site is no longer present. The predominant wildlife species are those that tolerate a mono-specific pine tree habitat, such as deer, turkey, and wild hogs. While pre-application surveys indicate that protected species occur at and in the vicinity of the LNP site, several of Florida's listed species are not likely to extensively use the LNP site. Impacts to State-listed and important wildlife species that have been documented or may occur on the LNP site and adjacent uplands will be further minimized under the proposed conditions of certification, including pre-construction wildlife surveys and consultation with FWC on the results and needed measures to avoid and mitigate such impacts. Historically, the 3,105-acre LNP site was dominated by forested cypress wetland systems. However, over the last century or more, those have been harvested and allowed to re- grow, so that many of the wetlands are no longer dominated by cypress trees. Today, most of the forested wetland systems in the footprint of development have been cleared of trees. The anticipated maximum wetland impacts for the entire Project, including the impacts from associated facilities and electrical transmission lines, are estimated to be 765 acres. These impacts are estimated to be: 13.3 acres of open water; 638.4 acres of forested wetlands; and 113.0 acres of herbaceous wetlands. Approximately one-half of the wetland impacts are expected to occur on the LNP site and one-half are expected to occur offsite. The Project's 765-acre wetland impact is a conservative estimate, including long-term and short-term impacts that are the result of direct dredging and filling as well as temporary disturbance. It is likely that the actual impact will decrease as the routing of facilities is refined within the electrical transmission and other corridors and on the LNP site. Based on these anticipated wetland impacts and the functions being provided by these wetlands, PEF calculated the proposed maximum wetland functional loss for the LNP to be 410.9 functional units, as determined under Florida's Uniform Mitigation Assessment Methodology (UMAM) contained in Rule Chapter 62-345. The UMAM scoring indicates that, on average, the wetlands being impacted have approximately one-half of the functional ecological value of an ideal wetland system. To comply with the applicable SWFWMD ERP rules under the PPSA process, PEF must offset the wetland impacts caused by the construction and operation of the LNP, associated transmission lines, roads, and pipelines. PEF submitted to DEP a Wetlands Mitigation Plan for the Progress Energy Levy Nuclear Plant and Associated Transmission Lines (WMP). A primary value of the WMP is an overall increase in ecological function provided across several thousand acres in a regionally-significant location. This regional landscape-level ecosystem benefit substantially augments the value of local-scale mitigation activities. The proposed mitigation for the LNP will potentially achieve greater offset of wetland impacts from a regional perspective and is expected to provide significant long-term ecosystem benefit. The WMP identifies a series of possible scenarios from which the appropriate and ultimate mitigation can be derived. Because impacts are still being refined as corridors are narrowed into actual routes, the information in the WMP is designed to demonstrate that there is available and desirable mitigation to affect the final degree of wetlands impacts, once calculated. The comprehensive mitigation plan, as described in the WMP, is an acceptable alternative to traditional "in-basin" mitigation. DEP conceptually approved this WMP with the understanding that more detailed information will be submitted when final routes are established and actual wetland impacts are known. The amount of mitigation PEF will undertake will be based on the amount of wetlands actually impacted. A condition of certification has been included to require submittal of refinements to the mitigation plan for DEP's approval following final certification. PEF looked at ways to reduce and eliminate wetland impacts at several levels, including site selection, routing of roadways, and commitments through discussions with agencies to further reduce impacts as transmission line routes are selected within the transmission corridors. The Project is designed to comply with SWFWMD ERP criteria in Rules 40D-4.301 and 4.302. There are not expected to be unacceptable secondary wetlands impacts due to the construction of the Project. Under SWFWMD rules, as long as a disturbance is at least 25 feet from a wetland, secondary impacts are deemed avoided. For the LNP site, unimpacted wetlands are dozens to thousands of feet away from Project development. Further, the rural and remote location of the facility, along with the high level of security associated with a nuclear facility (i.e., fencing, buffering, and reduced public access) makes causally-connected offsite development unlikely (with regard to the LNP site). The LNP will comply with the cumulative impact requirements of Section 373.414(8), Florida Statutes. The conceptual WMP is designed to be regionally significant and provides ecological benefits beyond the calculated UMAM functional value increase. For example, the WMP has the potential to connect the Goethe State Forest to the historic floodplain of the Withlacoochee River, which will maintain and enhance a large natural wildlife corridor. The LNP is not anticipated to adversely affect the value or functions provided to fish and wildlife and listed species, including any aquatic and wetland species, or other related-water resources. There are no documented listed aquatic or wetland-dependent species that might be adversely affected by construction at the plant site. Impacts to wetland dependent species will be further minimized under the proposed conditions of certification, including pre-construction wildlife surveys and consultation with FWC on the results. PEF has addressed all of the wildlife issues subject to the site certification process. The FWC has recommended certification, subject to conditions related to surveying of development areas and appropriate buffers for species prior to clearing, construction, and development to ensure appropriate relocation or mitigation opportunities and implementation of management activities to ensure the long-term well-being of the species. Project wetlands impacts are not expected to adversely affect the quality of receiving waters with respect to the applicable water quality criteria for those receiving waters, or adversely affect fishing or recreational values or marine productivity. Through implementation of the WMP, construction of the Project is not expected to adversely affect the current condition and relative value of the functions being performed by wetlands. Transportation The primary roadways in the vicinity of the LNP are U.S. Highway 19 (U.S. 19) and County Road 40 (C.R. 40). U.S. Highway 19 is a Florida DOT-maintained, four-lane arterial roadway west of the Project site. C.R. 40 is a Levy County- maintained, two-lane roadway approximately five miles to the south of the plant site. The Levy County Comprehensive Plan has adopted level of service (LOS) standards for roadways within Levy County. While LOS standards do not apply to temporary construction traffic, PEF evaluated the impacts of both LNP construction and operation traffic on adjacent roadways. This evaluation shows that future traffic levels with the addition of the Project construction and operation traffic are projected to be less than one-half the adopted LOS standards for U.S. 19 and C.R. 40. Roadway links during construction and operation of the LNP are projected to operate within adopted LOS standards. Socioeconomic Impacts and Benefits There is an approximate population of 4,700 persons within a five-mile radius of the LNP site. This equates to a population density of approximately 60 people per square mile. The closest towns to the LNP site are Inglis and Yankeetown, which are located approximately 4.1 miles and 8.0 miles southwest of the LNP site, respectively. The total cost of the LNP, including the proposed electrical transmission lines, is approximately $17 billion. The LNP construction workforce is expected to peak at approximately 3,300 workers in 2014. The operation workforce will consist of approximately 800 employees, with an additional 800 workers needed every 18 months for between 20 and 30 days to refuel the facility. PEF sees retention rate benefits when hiring locally and would like to employ the local workforce for construction and operation of the LNP. PEF has programs in place to train local residents to become part of the future workforce for the LNP. These programs focus on both construction and operation personnel and include programs or potential programs at Bronson High School, Chiefland High School, Dixie County High School, the Withlacoochee Technical Institute, and Santa Fe Community College. PEF is also working in partnership with Dunnellon High School (which draws students from Levy, Citrus, and Marion Counties) on a Power Academy to prepare students for the construction and operation of the LNP. PEF has a successful nuclear engineering program partnership with the University of Florida to train both nuclear engineers and plant operators, including the use of a first-of-its-kind digital training simulator. PEF has provided grants to modernize the nuclear facilities at the University of Florida. In 2005, there were approximately 395,000 workers in the region (defined as a 50-mile radius around the LNP, including Levy, Citrus, Marion, Alachua, Dixie, Gilchrist, Hernando, and Sumter Counties). Specific to construction of a nuclear power plant, there were 4,900 heavy construction workers in the region in 2006. It is probable that more of these 4,900 workers will be available due to rising unemployment rates across the region. Unemployment rates for the three counties immediately surrounding the LNP site have risen from around four percent in 2005 to eight percent in late 2008. There is sufficient housing available in the region to accommodate both LNP construction and operation employees. Construction of the LNP is not expected to significantly increase the number of pupils in the surrounding school systems. The school systems in the region of the LNP will be able to accommodate the increased number of pupils as a result of LNP operations workers and their families. Public services and facilities in the region of the LNP are sufficient to absorb any incremental population growth associated with construction and operation workers and their families. Construction of the LNP will have little, if any, impact on recreational facilities and uses in the area around the LNP site in Levy and Citrus Counties. During LNP operation, recreational facilities and uses will not be impacted. There are no officially-designated landmarks within five miles of the LNP site. The peak construction workforce in 2014 will result in approximately $152 million in annual earnings. Construction earnings in other years will also be substantial. In addition to jobs and earnings, the construction of the LNP will contribute an estimated $263 million annually to the regional economy via direct, indirect, and induced goods and services. The direct social and economic impacts of the LNP operation are expected to include approximately 800 direct jobs; 1,100 indirect or induced jobs; and associated increases in sales, property tax, and output revenues. These operations workers are expected to generate over $53 million in annual payroll. The LNP overall is expected to contribute nearly $521 million annually to the regional economy via direct, indirect, and induced goods and services. Local property tax collections will begin when Unit 1 is brought on-line, resulting in approximately $63 million in tax revenue to Levy County in the first year of operation. Annual property tax collections in Levy County of approximately $18 million are projected to increase by $104 million once both LNP units are operational. Archaeological and Historic Sites Construction and operation of the LNP will not adversely impact archaeologically significant sites or historic standing structures. The Project complies with all federal and state standards for identification and protection of archaeological sites. Field surveys of the plant site, the corridor extending south to the CFBC, and the pipeline corridor to the CREC did not reveal any archaeological sites or historic standing structures eligible for listing in the National Register of Historic Places (NRHP). The Florida State Historic Preservation Officer (SHPO) concurred with PEF's survey methodology and the determination that no sites are NRHP- eligible. PEF has guidelines designed to protect historic sites, landmarks, artifacts, and archaeological sites in the event of an inadvertent discovery. The Florida SHPO has concurred with PEF's approach to protect inadvertent discoveries during land-disturbing activities. Land Use PEF filed applications with Levy County for a comprehensive plan amendment and special exception zoning approval for the LNP. Those applications were approved and are now final. The majority of the existing land use on the LNP site is silviculture, and the property is unimproved. The primary existing land use of the property to the south of the LNP, where the heavy haul road, water pipelines, and other facilities will be located, is likewise silviculture and otherwise unimproved. The properties along the blowdown pipeline corridor to the CREC are primarily vacant and largely unimproved. The nearest residence to the LNP is approximately 1.5 miles to the northwest of the power block generating facilities, measured from the edge of the nearest power block to the residence. The electrical generating facilities are designed with a minimum 1,000-foot setback from the property line of any property not under the control of PEF. A natural 100-foot vegetative buffer is required to be maintained around the LNP's perimeter where the adjacent property is not under PEF's control. Given the setbacks, the perimeter vegetation, and the 250-foot maximum height limitation under Levy County's special exception for the LNP, the physical structures at the LNP site will not be visible from surrounding properties at ground level. The location of the LNP is consistent with the existing and future land uses surrounding the site. The cooling water blowdown pipelines are located to have the least impact on the existing land uses in the area. The LNP will have little impact on land uses in the vicinity. The LNP is consistent with the Levy County Comprehensive Plan and land development regulations (LDRs), the Strategic Regional Policy Plan of the Withlacoochee Regional Planning Council, and the State Comprehensive Plan contained in Chapter 187, Florida Statutes. Electrical Transmission Lines Project Description Generally, the purpose of electrical transmission lines is to transmit large amounts of electricity from a generating facility to one or more substations. Transmission lines operate at voltages above 69 kilovolts (kV). Bulk power, generally operating at 230-kV or 500-kV, is transferred from the generating plant to the substation. At the substation, the voltage of the electricity is changed through transformers and other electrical equipment for further transportation or distribution directly to customers. PEF is seeking certification of nine proposed corridors for transmission lines associated with the LNP. A proposed corridor is associated with each of the proposed transmission lines identified in Findings of Fact 182-189. All of the proposed transmission lines will directly support the construction and operation of the LNP. Corridor Selection Methodology PEF established a multi-disciplinary team to identify a corridor for each of the proposed transmission lines. The role of this team was to select a proposed corridor for certification for each line based on an evaluation of environmental, land use, socioeconomic, engineering, and cost considerations. The multi-disciplinary team was composed of experts in transmission line design, land use planning, system planning, real estate acquisition, corporate communications, and environmental disciplines as they relate to transmission lines. The multi-disciplinary team engaged in four major steps in this process. The first was to establish and define a project study area for each transmission line. The second step was to conduct regional screening and mapping. The third step was to select and evaluate candidate corridors using both quantitative and qualitative analysis. The fourth step was to select the proposed corridors and identify the boundaries of those corridors. Data collection was performed in connection with this effort from the databases of federal, state, regional, and local agencies and organizations, as well as from the public in a series of conferences and open houses described in Findings of Fact 8-11. A number of field studies, internal meetings, and individual and small group meetings were held with members of the public as a part of the process. In defining the project study area for each transmission line, the multi-disciplinary team considered the starting and ending points for the lines and other linear facilities in these areas. Within each study area, the multi-disciplinary team gathered regional screening data from a variety of sources to identify the different types of opportunities and potential constraints for siting a transmission line in the project study areas, such as various environmental and land use features, existing infrastructure, archeological and historical sites, roads, railroads, rivers, waterbodies, and similar features. The multi-disciplinary team evaluated each corridor using quantitative environmental, land use, and engineering criteria. Relative weights for each quantitative criterion were developed and validated with input from agency representatives and the public during the public outreach portion of the corridor selection process. The weights were applied to the quantitative values for the criteria for each candidate corridor segment and the scores were tabulated for all candidate corridors. The candidate corridors were then ranked in order from best to worst based on quantitative weighted scores. The high-ranking candidate corridors were then evaluated using predetermined qualitative criteria which do not lend themselves easily to quantification, such as the types of wetlands and vegetation present, safety, constructability considerations, and other similar considerations. Based on the quantitative and qualitative evaluation of the high-ranking candidate corridors, the multi-disciplinary team ultimately chose the nine proposed corridors. Once the proposed corridors were selected, the multi-disciplinary team refined the boundaries of each of the PEF proposed corridors. The team developed corridor boundaries of varying widths by narrowing the corridor to avoid siting constraints where practicable or widening the corridor to take advantage of siting opportunities. Transmission Line Design A transmission line generally consists of a steel or concrete structure, the conductor, which is attached to the structure by an insulator, and overhead groundwires used for lightning protection and communications for the protection and control systems located in the substation. Access roads and structure pads are also associated with transmission lines. The Project’s 230-kV and 69-kV transmission lines will be constructed using single-shaft tubular steel or spun concrete structures. The conductors will be attached to the structures with braced line post or V-string insulators. The braced line post arrangement is a compressed construction design which minimizes the amount of right-of-way needed. The V-string insulator design allows longer span lengths due to the increased strength of this assembly. Typical heights will range from 80 to 145 feet for the 230-kV structures and 60 to 90 feet for the 69-kV structures. The 500-kV transmission lines will be constructed using tubular steel H-frame or monopole structures. The conductors will be attached to the structures with V-string insulators which provide the necessary strength and minimize the amount of right-of-way needed. Structure heights will range from 110 to 195 feet. The span length between structures and the pole height will vary due to natural or man-made constraints such as wetlands, waterbodies, property boundaries, existing utility poles, utility lines, and roadways. The typical spans between structures supporting 230- kV transmission lines will range from approximately 500 to 700 feet for the braced line post structures and 700 to 1,400 feet for the V-string structures. The typical spans between structures supporting 69-kV transmission lines will range from approximately 250 to 600 feet. The typical spans between structures supporting 500-kV transmission lines will range from approximately 1,000 to 1,500 feet. Access roads and structure pads will be constructed only where necessary. When new roads are required, they will typically be 18 feet wide and unpaved, with the top elevation, two feet above the expected seasonal high water line. Generally, the existing ground will be leveled, a geotextile fabric will be installed, and compacted sand and gravel will be added to arrive at the desired road elevation. Culverts will be installed as required to maintain preconstruction waterflows. Structure pads will typically be 70 feet wide and 100 feet long and unpaved, with the top elevation, two feet above the expected seasonal high water line. The size of the structure pads will vary depending upon the heights of the structures supported and other site-specific factors. The designs for these access roads and structure pads have been used by PEF in the past and have been previously approved in Florida. Design Standards The transmission lines will be designed in compliance with all applicable design codes and standards. These include the National Electrical Safety Code, the standards of the North American Electrical Reliability Corporation, DEP's regulations on electric and magnetic fields, applicable local government requirements such as noise ordinances, and the DOT Utility Accommodation Manual. PEF's own internal design standards incorporate appropriate provisions or guidance from design codes and standards of the American Society of Civil Engineers, the Institute of Electrical and Electronics Engineers, and American Society of Testing Materials, the American National Standards Institute, and the American Concrete Institute. Transmission Line Construction PEF will work with the regulatory agencies and landowners to determine where the rights-of-way, transmission structures, access roads, and structure pads should be located. As rights-of-way are being selected, they will be surveyed to facilitate acquisition of the necessary property interests. After the right-of-way is established within the certified corridor, the initial phase of construction involves clearing the right-of-way. Where the proposed right-of-way is in uplands, the right-of-way clearing for the project will consist of vegetation and tree removal as necessary. Where the proposed right-of-way is in wetlands, vegetation will be cleared utilizing restrictive clearing techniques as necessary for specific sites. Restrictive wetlands clearing will be done by hand, with chainsaws or low ground-pressure shear or rotary machines, to reduce soil compaction and damage to vegetation. The cut material will be removed from the right-of-way utilizing either low ground-pressure equipment or temporary construction mats. Care will be taken to minimize rutting and disturbance of root mat. After the right-of-way is cleared, any necessary access roads and structure pads will be constructed. Existing access roads and structure pads will be used whenever practicable. Where a transmission line will be constructed adjacent to an existing transmission right-of-way, improvements to the associated access roads and paths may be made. Where adequate access roads or structure pads do not exist, new roads and pads will be constructed. The next phase of construction will involve the erection of the structures. All structures will be supported with engineered foundations. Tangent structure foundations will normally consist of either direct buried structures with concrete backfill or reinforced-concrete drilled piers. Structures may also utilize guys and anchors at angle and deadend structures to help support the load. Transmission structures are generally delivered to the site using semi-trucks with open trailers and are assembled onsite as close as possible to the foundation. Typically, the structures are framed with the structure arms and insulator assemblies while lying on the ground. During the assembly process, poles are maneuvered into place using cranes and other lifting equipment to facilitate connections. Once assembled, a crane is used to lift the structures for final placement on the foundation. After the structures are erected, conductor installation will commence. The process of installing conductors involves stringing a pilot line into each structure stringing block to form a continuous connection between stringing end points. This pilot line is then used to pull the conductor into position. The conductor is then tensioned to design specifications, transferred to the support clamp, and clipped into position. The operation is performed on all overhead ground wires and conductors. Typical equipment used in the conductor installation operation includes bucket trucks, wire pulling equipment, guard structures, wire reels, trailers, tensioners, and support vehicles. The final stage of construction will be right-of-way restoration which includes removal of all construction equipment and supplies, grading the right-of-way if needed, and planting or seeding of the disturbed area if needed. During all stages of construction, PEF will maintain traffic on any adjacent county, state, or federal roadways in compliance with DOT regulations. Sedimentation management techniques, including turbidity screens, temporary culverts, silt fences or staked hay bales, and the seeding or mulching of side slopes, will be utilized to minimize potential impacts to water quality from erosion and sedimentation. Corridor Descriptions The LNP will add approximately 185 miles of new 69- kV, 230-kV, and 500-kV transmission lines to be placed within nine proposed corridors. The proposed corridors provide significant opportunities for collocation with other linear facilities such as roads and transmission lines which provides the opportunity to reduce costs, the amount of new access road construction, impacts to wildlife habitat, and other impacts. The width of the proposed corridors varies along the routes to provide flexibility within the corridors to avoid impacts to existing developments, large wetland areas, and other features. After certification, and following the selection of rights-of- way, the boundaries of the corridors will be reduced to those of rights-of-way. The first proposed corridor is associated with the Citrus 1 and 2 lines. The Citrus lines are also referred to as the "LPC" transmission lines and the proposed corridor is referred to as the LPC corridor. The Citrus lines are two 500- kV transmission lines that will connect the LNP to the proposed Citrus Substation, which is not a facility for which PEF is seeking certification. The Citrus 1 and 2 lines will be located in Levy and Citrus Counties. This proposed corridor is approximately seven miles long and one mile wide. The LPC Corridor begins at the LNP site boundary and proceeds south on PEF-owned property south of the LNP site. Through the southern property, the LPC Corridor is collocated with the proposed Sumter and Crystal River 500-kV lines, the Levy South Administration 69-kV line, and is adjacent to the proposed LNP heavy haul road and water pipeline corridors. Continuing south, the LPC Corridor remains collocated with the Sumter and Crystal River lines as well as PEF's existing IO 69-kV line at some locations. The LPC corridor will cross C.R. 40, the CFBC and Inglis Island (which is wedged between the LWR and the CFBC), and will terminate at the proposed Citrus Substation located just north of PEF's existing Crystal River Central Florida transmission line in Citrus County. The second proposed corridor is associated with the Crystal River line, which is also referred to as the "LCR" transmission line and the corridor is referred to as the LCR Corridor. The Crystal River line is a 500-kV transmission line that connects the LNP to the existing CREC switchyard in Citrus County. The Crystal River line will be located within Levy and Citrus Counties. The LCR Corridor is approximately 14 miles long and one mile wide. It begins at the LNP site boundary and proceeds south on the PEF-owned property south of the LNP site. Through the southern property, the LCR corridor is collocated with the proposed Sumter and Citrus 1 & 2 500-kV lines, and the Levy South Administration 69-kV line, and is adjacent to the proposed LNP heavy haul road and water pipeline corridors. Continuing south, the corridor remains collocated with the Sumter and Citrus 1 & 2 lines as well as PEF's existing IO 69-kV line in some locations. The LCR Corridor will cross C.R. 40, the CFBC and Inglis Island, and will enter the existing PEF Crystal River to Central Florida transmission line right-of-way. At this point, the LCR Corridor turns west and follows the general alignment of the existing PEF Crystal River to Central Florida Transmission right-of-way into the CREC where it terminates at the CREC 500-kV switchyard. The third proposed corridor is associated with the Sumter line, which is also referred to as the "LCFS" transmission line. This corridor is referred to as the LCFS Corridor. The Sumter line is a 500-kV transmission line that will connect the LNP to the proposed Central Florida South Substation in Lake and Sumter Counties, which is not a facility for which PEF is seeking certification. The Sumter line will be located in Levy, Citrus, Marion, and Sumter Counties. The LCFS Corridor is approximately 59 miles long and ranges in width from approximately 1,000 feet to one mile wide. For most of its length, the 500-kV LCFS Corridor is collocated with the existing PEF transmission lines, except in the vicinity of the Central Florida South Substation, where it is collocated with the Florida Turnpike. The LCFS Corridor begins at the LNP site boundary and proceeds south on the PEF-owned property south of the LNP site. It will be collocated with the proposed Citrus 1 & 2 and Crystal River 500-kV lines and the Levy South Administration 69-kV line. The LCFS Corridor crosses C.R. 40, the CFBC and Inglis Island, and continues south until reaching the existing PEF Crystal River to Central Florida transmission line right-of-way. At that point, the LCFS Corridor turns east and follows the existing transmission line right-of-way through Citrus and Marion Counties for approximately 45 miles. The corridor turns southeast crossing into Sumter County and crosses S.R. 44 and I-75. The remaining five miles of the LCFS Corridor follows the general alignment of the Florida Turnpike to the southeast and terminates in the area of the proposed Central Florida Substation near Wildwood. The fourth proposed corridor is associated with the Crystal River East 1 & 2 lines, which are also called the "CCRE" transmission lines. This is the CCRE Corridor. The Crystal River East lines are two 230-kV transmission lines that will connect the proposed Citrus Substation to the existing Crystal River East Substation in Citrus County. The lines will be located entirely within Citrus County. The CCRE Corridor is approximately 2.7 miles in length and one mile wide. The west end of the north boundary of the corridor is approximately one- half mile west of U.S. 19 and runs east approximately one-half mile north of West Dunnellon Road (CR-488). The west end of the south boundary of the corridor starts approximately 1 mile west of U.S. 19 and runs east along the northern boundary of the existing PEF transmission right-of-way. At a point approximately 0.3 miles east of U.S. 19, the corridor shifts south approximately one-half mile and continues east for another mile. The corridor also includes five existing 115-kV, 230-kV and 500-kV transmission lines and the Crystal River East Substation. The fifth and sixth proposed corridors are associated with the Levy North and South lines, which are also referred to as the "IS" and "IO" transmission lines. The Levy North and South lines are 69-kV transmission lines required to supply power for the construction and administration of the LNP. These lines will be located entirely within Levy County, and are mostly located on property owned by PEF in the immediate vicinity of the proposed LNP. The IS Corridor is approximately 373 feet in length and 400 feet wide. The IO Corridor is approximately 4.5 miles in length and one mile wide. The IO Corridor will begin at the south boundary of the LNP site and extend south to encompass the existing 69-kV transmission line located south of C.R. 40 in Levy County. The IS Corridor will begin at the west boundary of the LNP site and extend west to encompass the existing 69-kV transmission line that is located parallel to and east of U.S. 19 in Levy County. The seventh proposed corridor is associated with the Brookridge line, which is also referred to as the "CB" transmission line. The corridor is referred to as the CB Corridor. The Brookridge line is a 230-kV transmission line that will connect the existing CREC to the existing Brookridge Substation in Hernando County. The Brookridge line will be located in Citrus and Hernando Counties. The overall length of the CB corridor is approximately 38 miles and ranges in width from approximately 1,000 feet to one mile. The corridor begins at the CREC switchyard and proceeds east towards the existing Crystal River East Substation then southeast to S.R. 44. The corridor collocates with existing transmission line rights-of- way. At S.R. 44, the corridor turns south, following the existing PEF 115-kV transmission right-of-way. Approximately one mile south of Centralia Road, the corridor turns east and ends at the existing Brookridge Substation. The eighth proposed corridor is associated with the Brooksville West line, which is also called the "BBW" transmission line. The corridor is referred to as the BBW Corridor. The Brooksville west line is a 230-kV transmission line that will connect the existing Brookridge Substation to the existing Brooksville West Substation in Hernando County. This line will be located entirely within Hernando County. The overall length of the BBW Corridor is approximately three miles and one-half mile wide. The BBW Corridor exits the Brookridge Substation, collocated with PEF's existing 500/230/115-kV transmission line right-of-way, and travels along Sunshine Grove Road to the south. It terminates at the Brooksville West Substation. The ninth and final proposed corridor is associated with the Kathleen line, which is also called the "PHP" transmission line. The corridor is referred to as the PHP Corridor. The Kathleen line is a 230-kV transmission line that will connect the existing Kathleen Substation in Polk County to the existing Lake Tarpon Substation in Pinellas County. The Kathleen line will be located in Polk, Hillsborough, and Pinellas Counties. The overall length of the PHP Corridor is approximately 50 miles, and it ranges in width from approximately 300 feet to 1000 feet. The corridor begins at the Kathleen Substation and travels west. It crosses U.S. 98 and turns south along the existing transmission line right-of-way to the Griffin Substation. At the Griffin Substation, the corridor turns west paralleling C.R. 582. The corridor crosses U.S. 301 and turns north and then west and crosses I-75, continuing northwest and following the existing transmission right-of-way, and then crosses I-275 and the Veteran's Expressway to the Lake Tarpon Substation. No alternate corridors were proposed for any of the nine proposed transmission line corridors. For each PEF- proposed transmission line corridor, the proposed corridor is the only corridor for the respective line that is proper for certification in this proceeding. For each of the proposed corridors, engineering features of interest, natural resource features, and land use features have been identified and depicted on maps, aerial images, and photographs, which have been utilized in the analysis of the corridors. Operational Safeguards The operational safeguards for each of the transmission lines proposed by PEF are technically sufficient for the public welfare and protection. Each transmission line will be designed, constructed, operated, and maintained in compliance with all applicable codes, standards, and industry guidelines, including: the National Electric Safety Code; the North American Electric Reliability Corporation; the American National Standards Institute; applicable local government requirements; the DOT Utility Accommodation Guide; and PEF's internal design standards, which incorporate appropriate provisions or guidance from design codes and standards of the American Society of Civil Engineers, the Institute of Electrical and Electronics Engineers, the American Society of Testing Materials, the American National Standards Institute, and the American Concrete Institute. Each of the transmission lines proposed by PEF will be constructed, operated, and maintained in compliance with the applicable standards which regulate the electric and magnetic fields associated with new transmission lines. Compliance with the electric and magnetic field requirements has been calculated for each of the configurations that may be utilized for the Project. The results were then compared to the requirements contained in DEP's Rule 62- 814.450(3). The maximum expected values from all configurations for the electric fields and for the magnetic fields are within the values set forth in the rule. The calculations were performed in accordance with the rule requirements, using the maximum voltage and current for each configuration. Operation of any of these transmission lines at maximum voltage and current is not a likely condition. At normal operating levels of voltage and current, the electric fields produced by the transmission lines will be less than calculated at the maximum operating conditions, and the magnetic fields produced will be about 50 percent less than calculated at the maximum operating conditions. The levels of electric and magnetic fields at the edge of the rights-of-way associated with the transmission lines are similar to levels that are experienced by exposure to common household appliances. Transmission lines can generate audible noise as a result of build-up of particles on the conductor. This is known as corona. During periods of fair weather, particulate matter can collect on the conductor causing low levels of audible noise. During rain events, the particles are washed off and replaced with water droplets on the conductor that create a condition that can result in slightly higher levels of audible noise. The noise levels experienced during rainfall events are temporary and masked by the sound of rain falling on vegetation and other surfaces, and the noise is reduced as soon as the water droplets evaporate from the conductor. The expected levels of noise have been calculated using an industry standard software program known as the Bonneville Power Administration Corona Field Effects Program. The calculations performed for each of the transmission lines demonstrate that the maximum audible noise levels at the edge of the right-of-way will be less than the noise levels from most rainfall events or conversational speech at a distance of five feet. The calculated noise levels are expected to comply with all applicable noise ordinances. The operation of the proposed transmission lines is expected to cause minimal interference with radio and television reception in the vicinity of the transmission lines. Radio and television interference can be produced by corona on transmission line conductors or as a result of faulty equipment. Based upon the studies that have been performed, it is not expected that significant interference will occur. Beginning on July 12, 2009, the Federal Communications Commission has directed all television station operators to convert their transmissions to digital format. Digital signals are unaffected by electric fields or weather disturbances. In the event any homeowner or business experiences abnormal interference as a result of the transmission lines, PEF will investigate the complaints and mitigate impacts appropriately. Part of the BBW Corridor has an existing natural gas pipeline and a proposed additional natural gas pipeline that will be operated by Florida Gas Transmission Company. Safety concerns will be addressed in a licensing agreement allowing the pipeline company to utilize the right-of-way. Such collocation is common throughout Florida. The licensing agreement will require that the pipeline company comply with all applicable safety requirements for pipeline operation and will require that the pipeline design be reviewed by an independent engineering company to ensure that the pipeline can be safely operated given the constraints of the design and the proximity of transmission lines. This will ensure that the pipeline can be safely operated near the transmission lines and the electric current. Compliance with Nonprocedural Standards of Agencies The construction, operation, and maintenance of each of the proposed transmission lines in the proposed corridors is expected to comply with the applicable nonprocedural requirements of agencies. The parties have agreed that the conditions of certification found in DEP Exhibit 1 are the applicable nonprocedural requirements of the state, regional, and local agencies with regulatory jurisdiction over the transmission lines. PEF has agreed to construct, operate, and maintain the transmission lines in the proposed corridors in compliance with the conditions of certification. No variances or exemptions from applicable state, regional, or local standards or ordinances have been requested or are needed for construction, operation, and maintenance of these transmission lines. Consistency with Local Government Comprehensive Plans and Land Development Regulations There are a number of different land uses within the nine proposed corridors ranging from open lands, recreational lands, mining and agricultural lands, public and conservation lands, commercial uses, and residential. The construction of the transmission lines in the respective proposed corridors is not expected to impact the existing land uses or change those land uses. The location of the transmission lines in the proposed corridors is appropriate from a land use perspective. The construction, operation, and maintenance of the transmission lines in the respective corridors are compatible with all types of existing land uses occurring in the vicinity of those corridors. Each of the proposed transmission lines will be constructed, operated, and maintained in the proposed corridors consistent with applicable provisions of local government comprehensive plans and land development regulations. After certification of the LNP, each proposed transmission line will be located and constructed established rights-of-way, including easements acquired after certification of the respective corridors. Construction of transmission lines on such established rights-of-way is excepted from the definition of "development" contained in Section 163.3164(6), Florida Statutes. To the extent that comprehensive plans or land development regulations of the local governments crossed by the transmission lines include provisions that are applicable to non-development activities, the transmission lines in each of the designated corridors will be consistent and in compliance with those requirements. Meet Electrical Energy Needs of the State In an Orderly, Timely and Reliable Fashion Each proposed transmission line will be constructed, operated, and maintained in the proposed corridor to meet the electrical energy needs of the state in an orderly, reliable, and timely fashion. The anticipated schedule for the transmission line portion of the Project calls for the permitting, licensing and engineering activities, right-of-way acquisition, and construction to be carried out such that the transmission lines are constructed and operating in 2015 in advance of certain construction and start-up activities for LNP Unit 1. The proposed corridors maximize collocation opportunities for the transmission lines, enabling the collocated transmission lines to be constructed in a more timely and efficient manner. PEF will make all practicable efforts to minimize the impacts to traffic from the proposed transmission lines. PEF will comply with conditions of certification proposed by DOT and local governments to facilitate the orderly construction, operation, and maintenance of each of the transmission lines in the proposed corridors. Reasonable Balance Between the Need and the Impacts Each of the transmission lines is essential to meet the need identified by the PSC. PEF has a long history of reliably constructing, operating, and maintaining similar transmission lines throughout Florida. Each of the transmission lines is designed to comply with stringent reliability standards such as the National Electrical Safety Code and the standards of the North American Electric Reliability Corporation. The construction, operation, and maintenance of the transmission lines in the proposed corridors will meet the need identified by the PSC. The PSC determined that there is a reliability need for additional base-load capacity by 2016. Levy Units 1 and 2 will add 2200 MW of capacity, and new transmission lines are necessary to accommodate this capacity on the electrical power system. The required transmission facilities include those necessary to connect the LNP to PEF's existing grid and to reliably integrate the additional capacity into the existing transmission system. PEF cannot meet the need identified by the PSC without these proposed transmission lines. PEF's proposed corridors were chosen using a multidisciplinary team of experts to minimize impacts on the environment. Each transmission line will be constructed, operated, and maintained in the designated corridor with minimal adverse environmental impacts. The corridor selection process involved regional screening to minimize inclusion of areas of ecological constraints. Each corridor maximizes utilization of previously disturbed areas, where possible. The corridor width has been selected for each corridor to provide flexibility for selection of the final right-of-way to provide the ability to avoid ecological resources within the corridor to the extent practicable. No adverse impacts to air quality are anticipated as a result of the construction or operation of the transmission lines. Each of the transmission lines will be constructed, operated, and maintained in the proposed corridor with minimal, if any, adverse impact to water quality. Each transmission line will be constructed, operated, and maintained in the proposed corridor with minimal adverse impact to fish and wildlife, including protected animal species. The presence of protected animal species was an important consideration during the corridor selection process, and each corridor avoids areas with known concentrations of protected species occurrences to the extent practicable. The agreed-upon conditions of certification require that preconstruction surveys be conducted, and the results will be submitted to the FWC for analysis. Mitigation, as appropriate, may be required. Each transmission line will be constructed, operated, and maintained in the proposed corridor with minimal adverse impact to water resources, including wetlands. Water resources, including wetlands, were an important consideration during the corridor selection process and were avoided to the extent practicable. Structures will not be constructed in major water bodies. The spans between structures will be varied to avoid wetland areas and other sensitive areas, where practicable. Herbaceous wetland communities, including marsh and wet prairie wetlands, can continue to grow underneath the proposed transmission lines. Best management practices will be utilized during construction to ensure that impacts to water bodies and other water resources are minimized. Each transmission line will be constructed, operated, and maintained in the proposed corridor with minimal adverse impacts to other natural resources, including protected plant species and wildlife habitat. The presence of protected plant species and wildlife habitat were important considerations during the corridor selection process and were avoided to the extent practicable. Wildlife habitat in the vicinity of each of the corridors with collocation opportunities has been altered from its natural state for construction and maintenance of the linear facility already there. This will minimize potential impacts. Minimize Adverse Effects Using Reasonable and Available Methods PEF will use reasonable and available methods during construction, operation, and maintenance of the transmission lines in the proposed corridors to minimize adverse effects on human health, the environment, and the ecology of the land and its wildlife and the ecology of state waters and their aquatic life. Construction, operation, and maintenance of the transmission lines in the designated corridors will comply with the limits for electric and magnetic fields established by DEP in Rule Chapter 62-814 and by the National Electric Safety Code and related standards. In the corridor selection process, collocation opportunities were considered to be a significant criterion, and the corridors were chosen in a way that maximizes collocation with existing linear facilities. This is advantageous because existing linear facilities often provide existing access, and collocation can minimize the need for new access roads and structure pads and the need for new clearing, generally minimizing impacts. PEF will avoid wetlands and water bodies to the extent practicable by varying the length of the spans between structures. PEF will use restrictive clearing practices on forested wetlands, removing vegetation selectively. In cases in which fill is required, PEF will install culverts to maintain water movement. PEF will allow certain vegetation to re-grow, or re- vegetate, in the rights-of-way of the transmission lines following construction, which will maintain suitable habitat for certain listed species. Wetland impacts that cannot be avoided will be appropriately mitigated. Prior to final rights-of-way determination and the beginning clearing in the rights-of-way for the transmission lines, surveys for protected plant and animal species will be conducted to verify their presence or absence in the proposed transmission line right-of-way for each of the lines. In the event that protected plants or animals cannot be avoided, efforts will be made to relocate the individuals in consultation with the FWC and the United States Fish and Wildlife Service, or to provide appropriate mitigation in accordance with the conditions of certification. PEF has agreed to comply with the conditions of certification in the construction, operation, and maintenance of each of the transmission lines. The conditions require measures to eliminate or minimize potential impacts to the environment, including impacts to the ecology of the land and its wildlife and the ecology of state waters and their aquatic life. Serve and Protect the Broad Interest of the Public The construction, operation, and maintenance of the transmission lines in the proposed corridors will serve and protect the broad interests of the public. The public's interest is served through the provision of safe, reliable, and cost-effective electric service. The transmission lines are essential for providing that service. The public outreach program carried out by PEF provided the public with an avenue to voice their concerns. Concerns expressed were considered in the selection process. The corridor selection process maximized collocation opportunities for the selection of each of the corridors, where practicable. By following existing linear features where possible, the corridors and the ultimate rights-of-way can conform to existing development patterns and minimize intrusions into surrounding areas. Collocation reduces costs and impacts. The existing land uses found within the corridors are compatible with each of the proposed transmission lines in part because the corridors are collocated with linear facilities to the extent feasible. The transmission lines that are proposed can coexist with the types of development that are found along each of the corridors. As a result of the process utilized by the multidisciplinary team, the corridors minimize the number of homes that may be affected and avoid public and conservation lands to the maximum degree practicable. The transmission lines will minimize the impacts on cultural and historical resources by avoiding those areas where practicable and by performing a preconstruction survey in consultation with DEP and the Division of Historical Resources to determine the appropriate action should such resources be found. Disruption to traffic during the construction of each of the transmission lines is expected to be minor. PEF will comply with conditions of certification proposed by DOT and local governments to ensure minimization of traffic impacts. Radio and television interference as a result of the operation of the transmission lines will be minimal, and any impacts will be addressed by PEF. The expected noise levels from the transmission lines will be similar to the noise levels resulting from rainfall events and conversation at five feet. The calculated noise levels will comply with all applicable noise ordinances and requirements. The electric and magnetic fields produced by the transmission lines will comply with the applicable standards established by the DEP. Southern Alliance for Clean Energy (SACE) Following the withdrawal of the other intervenors in this proceeding, SACE was the only remaining party opposing certification of the Project. In the prehearing stipulation of the parties, SACE appears to raise five basic issues: (a) there must be express conditions in the agency reports to address impacts to wetlands, fish, wildlife, water resources, and necessary mitigation should the Project not be completed; (b) adverse impacts to wetlands and water resources; (c) business risks of "significant delay, default or abandonment"; (d) risks to fish, marine wildlife, and vegetation; and (e) agency reports must address risks to water resources, wetlands, fish, marine wildlife, and vegetation. SACE did not offer the testimony of any witnesses or present any evidence in this proceeding on these or any other issues. With regard to SACE's first issue, SACE has failed to identify which of the reviewing agencies neglected to propose appropriate conditions or what additional conditions are necessary. In any event, the record shows that DEP, FWC, and SWFWMD all proposed extensive conditions in their agency reports related to protection of wetlands, fish, wildlife, water resources, and/or mitigation of Project-related impacts. With regard to wetlands mitigation, if the Project is not completed, PEF will perform mitigation necessary to compensate for wetlands actually impacted. See Finding of Fact 126. SACE's second contention is that the Project will cause adverse impacts to wetlands and water resources. As detailed in Findings of Fact 73, 115-131, 133-134, PEF has presented competent, substantial evidence that the LNP will not cause adverse impacts to wetlands or to water resources that are not fully offset by mitigation. SACE did not present any contrary evidence. Further, as indicated in Findings of Fact 124-126, 130, and 134, PEF has proposed a comprehensive wetlands mitigation plan that will offset any adverse impacts to wetlands caused by the construction of the LNP. SACE did not present any evidence that this mitigation plan, which has been conceptually approved by the DEP, is inadequate to protect wetlands or meet regulatory requirements. SACE's third contention is related to business risks of "significant delay, default or abandonment." These matters are not relevant under the PPSA criteria, Section 403.509(3), Florida Statutes, but are instead addressed by the PSC. A petition for a determination of need for a new nuclear plant must include a cost estimate, base revenue requirements, and information related to joint ownership discussions. See § 403.519(4)(a), Fla. Stat. The PSC has already determined that the Project is needed, specifically finding that "Levy Units 1 and 2 will provide adequate electricity at a reasonable cost." Under Section 403.519(4), Florida Statutes, the PSC is the "sole forum" for a determination of need. Reconsideration of factors already considered by the PSC in this proceeding is improper. Further, the record does not support SACE's contention regarding alleged business risks. PEF presented uncontroverted evidence that LNP Units 1 and 2 are on schedule to be in service in the 2016/2017 timeframe and that procurement activities have begun. See Finding of Fact 21. SACE's fourth issue relates to adverse impacts to fish, marine wildlife, and vegetation. As detailed in Findings of Fact 51, 56, 61, 62, 69–72, 88–92, and 131-133, PEF presented competent, substantial evidence that the LNP will not cause adverse impacts to fish, marine wildlife, or vegetation. SACE did not present any contrary evidence. Finally, SACE contends that the agency reports must address risks to water resources, wetlands, fish, marine wildlife, and vegetation. Again, SACE has failed to identify which agency reports failed to address these alleged risks. SACE likewise has not identified any specific regulatory requirement for such evaluations of environmental risks beyond the evaluations provided by the agencies. The record shows that DEP, FWC, SWFWMD, and Levy County all addressed risks to water resources, wetlands, fish, marine wildlife, and/or vegetation in their agency reports and proposed conditions of certification related thereto. Public Comment and Public Testimony Sworn oral public testimony was received from approximately 69 individuals and unsworn public comment was received from approximately 16 individuals during the portion of the final hearing devoted to that purpose. Many of the individuals who provided public testimony also submitted written comments. Three written comments were received from members of the public who did not attend one of the public comment sessions. Thirty hours were devoted to allowing members of the public to comment on the Project over six separate sessions. Members of the public testified both in favor of and in opposition to the Project. Several members of the public commented on the benefits of nuclear power in general and the economic benefits of the LNP specifically. Many others spoke in favor of the extensive public outreach conducted by PEF on the Project. Numerous members of the public spoke of PEF's history of being a good corporate neighbor. The individuals who testified in opposition to the Project raised a wide range of questions and concerns. Many of these concerns and questions are addressed by the evidence and are discussed by reference to the relevant Findings of Fact. However, several were outside the scope of the matters considered in this certification hearing. Several members of the public expressed concerns that the Project is not needed, is too costly, and should be deferred in favor of other energy alternatives. But the PSC already considered those issues in certifying a need for the Project. The PSC's determinations are binding, and those issues were not reconsidered in this certification hearing. Several members of the public expressed concerns related to radiological safety, storage of nuclear waste, and radioactive effluent contamination of groundwater via "fracture sets." Radiological issues raised by SACE were stricken because they were preempted by federal regulation under the Supremacy Clause of the United States Constitution. As a result, radiological safety issues were not considered in the certification hearing. The LNP must be approved by the NRC which regulates radiological safety of nuclear power plants. However, there was evidence that the Florida Department of Health monitors groundwater and other media in the vicinity of nuclear plants, and PEF's subsurface investigation did not reveal any evidence of fracture sets below the LNP site. See Finding of Fact 79. Some members of the public expressed concerns regarding potential infrastructure and lifestyle changes to the Town of Inglis. Specifically, members of the public raised concerns related to strain on local public services; traffic impacts; limits on development due to the LNP; and concerns that financial benefits will go only to Levy County and, more specifically, not the Town of Inglis. First, it should be noted that, along with other affected local governments, the Town of Inglis was provided a copy of PEF's nine-volume SCA on June 2, 2008. The Town of Inglis did not file a notice of intent to be a party to this proceeding pursuant to Section 403.508(3), Florida Statutes, and thus waived its right to be a party. In addition, the Town had the opportunity to submit an agency report or to propose conditions of certification pursuant to Section 403.507, Florida Statutes, but did not. As acknowledged in public testimony by one of the Town Council members, the Town of Inglis's Council is unanimously in favor of the LNP. Nonetheless, as detailed in Findings of Fact 143-146, PEF presented competent substantial evidence that public services and facilities in the region of the LNP (which includes the Town of Inglis) are sufficient to absorb any incremental population growth associated with construction and operation workers and their families. PEF also presented evidence that roadways in the vicinity will continue to operate at or above their adopted level of service capacities. See Findings of Fact 135-137. Further, there is no evidence that development will be restricted as a result of the LNP. Current limitations around the CREC related to increases in density are the result of Citrus County's Comprehensive Plan, not the CREC or state regulatory requirements. Finally, while significant tax revenues will go to Levy County, PEF presented evidence that the LNP's operation will contribute $521 million annually to the regional economy, which includes the Town of Inglis. See Finding of Fact 148. By way of comparison, although PEF's CREC is in Citrus County (and outside the Crystal River city limits), the Crystal River City Manager testified that PEF has been good for the Citrus County school system, has provided jobs for residents, and has been very helpful to efforts in the community. Other members of the public expressed concerns that the new jobs created by the LNP will not go to local residents. As indicated in Finding of Fact 141, PEF has and will continue to make efforts to train and employ local residents at the LNP. Other members of the public expressed concern that increased salinity in the CFBC would cause saltwater intrusion in the Lower Withlacoochee River. There is no connection between the CFBC and the Lower Withlacoochee River. While the LNP's withdrawals from the CFBC will increase salinity in the CFBC somewhat, it will not cause increased salinity in the Lower Withlacoochee River. See Findings of Fact 66-67. A member of the public expressed concern that PEF's proposed location for the CWIS would prevent future reconnection of the Withlacoochee River in an effort to provide more freshwater to the Lower Withlacoochee River.3 As detailed in Finding of Fact 68, options for reconnection of the Withlacoochee River have been evaluated by SWFWMD, but would not provide adequate increased freshwater flow to the Lower Withlacoochee River. Another issue raised during the public testimony sessions was the impact of cooling tower drift on vegetation surrounding the LNP. As indicated in Findings of Fact 103-104 and 110-111, PEF presented uncontroverted expert testimony that cooling tower drift will not adversely impact natural resources, including wetlands and surface waters. Several residents of Hernando County expressed concern that a portion of the BBW transmission line as proposed along Sunshine Grove Road is incompatible from a public safety standpoint with existing and proposed natural gas pipelines in this same area. PEF presented evidence, however, that this type of collocation of transmission lines and gas pipelines is commonplace throughout Florida. Further, it was not demonstrated that such collocation is prohibited under or contrary to applicable law or agency regulation. Some of these residents focused their concern on whether locating the BBW transmission line in proximity to a natural gas pipeline would be inconsistent with PEF's internal collocation guidelines, which these residents believe prohibit such collocation because an unsafe operating condition will result. As noted by Hernando County’s attorney and DEP's Siting Administrator, there is no basis in statute, ordinance, or rule to require PEF to comply with its internal guidelines. In any event, PEF presented evidence that the purpose of its internal collocation guidelines is to ensure the safety of persons involved in the construction and installation of a pipeline in proximity to an existing transmission line. Further, PEF is bound by the conditions of certification to comply with requirements of the National Electric Safety Code as they relate to induced currents that might affect a gas pipeline. See DEP Ex. 1, p. 76, Condition XLII(H). Other residents were concerned that construction of the BBW transmission line would be unsafe due to the presence of an existing natural gas pipeline. The conditions of certification require, however, that PEF comply with applicable federal Occupational Safety and Health Standards during construction of each of the transmission lines. The conditions of certification also require PEF to contact the Sunshine State One Call service to locate underground utilities prior to construction activities. Finally, after PEF selects its ultimate location for the BBW transmission line, Hernando County and other agencies will have the opportunity to review the proposed location and notify the DEP Siting Coordination Office if it believes that the construction of the transmission line within the selected right-of-way cannot be accomplished in accordance with the conditions of certification. See DEP Ex. 1, p. 65-66, Condition XXXV(A).
Conclusions For Progress Energy Florida: Douglas S. Roberts, Esquire Brooke E. Lewis, Esquire Hopping Green & Sams, P.A. Post Office Box 6526 Tallahassee, Florida 32314-6526 Lawrence Curtin, Esquire Gigi Rollini, Esquire Holland & Knight, LLP 315 South Calhoun Street, Suite 600 Tallahassee, Florida 32301-1872 For the Department of Environmental Protection: W. Douglas Beason, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 For Levy County: Anne Bast Brown, Esquire Levy County Attorney 380 South Court Street Bronson, Florida 32621-6517 For Hillsborough County: Marva M. Taylor, Esquire Hillsborough County Attorney's Office 601 East Kennedy Boulevard, 27th Floor Tampa, Florida 33602-4156 For City of Tampa: Janice McLean, Esquire Office of the City Attorney Old City Hall, 5th Floor 315 East Kennedy Boulevard Tampa, Florida 33602-5211 For the Southern Alliance for Clean Energy: E. Leon Jacobs, Esquire Williams & Jacobs 1720 South Gadsden Street, Suite 201 Tallahassee, Florida 32301-5506
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Siting Board enter a Final Order: Approving PEF's Application for Certification to build, operate, and maintain a two-unit nuclear powered electrical generating facility in Levy County, Florida, including a heavy haul road, site access roads, and cooling water intake and discharge pipelines, subject to the conditions of certification set forth in DEP Exhibit 1, as amended; and Approving PEF's Application for Certification to build, operate, and maintain each of the following electrical transmission line corridors as associated facilities, as described above and subject to the conditions of certification set forth in DEP Exhibit 1, as amended: Citrus 1 and 2 Transmission Lines, Crystal River Transmission Line, Sumter Transmission Line, Levy North Transmission Line, Levy South Transmission Line, Brookridge Transmission Line, Brooksville West Transmission Line, Crystal River East 1 and 2 Transmission Lines, and Polk-Hillsborough-Pinellas Transmission Line. DONE AND ENTERED this 15th day of May, 2009, in Tallahassee, Leon County, Florida. S J. LAWRENCE JOHNSTON 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 15th day of May, 2009.
The Issue The issue to be resolved in this proceeding is whether the Governor and Cabinet, sitting as the Siting Board, should issue a final order granting certification to Progress Energy Florida (“PEF”), to construct and operate a new 530 megawatt (“MW”) natural gas-fired electrical power plant in Polk County, Florida. The proposed site for the Project is located at PEF’s existing Hines Energy Complex, southwest of Bartow, Florida.
Findings Of Fact Background Progress Energy Florida, previously known as Florida Power Corporation, is an electric utility that provides electricity in a 35-county service area in Florida. This service area stretches from the Panhandle through the center of the state and includes the western coast of Florida north of Tampa Bay. PEF currently serves approximately 1.5 million customers in this service area. PEF has been providing electric service in Florida for over 100 years. PEF’s current generating capacity is 9,174 megawatts. The Company currently operates 14 different power plant facilities in the state. PEF has a customer growth rate of 1.7 percent per year. (Hunter, Tr. 14- 15; PEF Ex. 10, Slide 2). The PEF Hines Energy Complex is located in the southwest portion of Polk County, Florida, approximately 3.5 miles south of the city of Bartow. The community of Homeland is located one mile northeast of the Hines site. County Road 555 runs through the Project site. The Hines site contains approximately 8,200 acres of reclaimed phosphate mine lands. The area around the larger Hines site has been dominated by phosphate mining operations, including mines, settling ponds, sand tailings, gypsum stacks, and chemical beneficiation plants. The adjacent land uses consist almost entirely of active phosphate mining or mined and reclaimed lands. (PEF Ex. 6, Zwolak at 5-6; PEF Ex. RZ-2; PEF Ex. 1 at 2-1). In the late 1980’s, PEF began planning to meet the needs of future growth in customer demand for electricity and decided to identify a site that allowed for a wide variety of possible generation technologies, while at the same time meeting the ecological and regulatory requirements for building new generation. PEF solicited the help of a team of local community, educational, and environmental leaders to evaluate over 50 potential sites in Florida and South Georgia. This two- year process culminated in 1991 with the selection of the Hines site, then known as the Polk County site. (PEF Ex. 6, Hunter at 4). In January 1994, the Governor and Cabinet, acting as the Siting Board, certified the Hines Energy Complex for an ultimate site capacity of 3,000 megawatts (MW) of generating capacity fueled by either natural gas, coal gas or fuel oil, and also granted certification for the construction and operation of an initial 470 MW combined cycle unit known as Power Block 1. Power Block 1 began operation in 1999. In 2001, the Siting Board also granted certification for the construction and operation of Hines Power Block 2, a 530 MW combined cycle unit. Power Block 2 began operation in 2003. In 2003, certification was granted by the Siting Board for Power Block 3, which is currently under construction, and expected to be in service by late 2005. (PEF Ex. 6, Hunter at 5; PEF Ex. 1, Preface at 1-2; FDEP Ex. 2 at 1). The original certification proceeding that culminated in the 1994 certification included extensive evaluations of the worst case capacity constraints and potential environmental effects of the operation of the expected 3,000 MW of capacity. Those evaluations included assessments of air quality impacts, water quality and wildlife impacts, water use, noise impacts, socioeconomic impacts and benefits, traffic impacts of construction and operation, and other impacts of the entire planned capacity of 3,000 MW. This original evaluation significantly reduces the time and expense for processing the Supplemental Site Certification Application and allows PEF to respond more quickly to the growth in demand for electrical generating facilities. The ultimate site capacity determination assures PEF that the Hines Energy Complex site has adequate air, water, and land resources to accommodate additional electrical generating facilities. The 1994 certification also established that the full 3,000 MW of generating capacity and the Hines site are consistent with the local land use plans and zoning regulations of Polk County. (PEF Ex. 1, Pre-1 to Pre-2 at 2.4 to 2.5). The Hines Energy Complex contains a number of existing facilities and is divided into several major areas. The plant island is the location for the existing and future power generation facilities. It is approximately 704 acres. A 722- acre cooling pond, that is being expanded to approximately 1200 acres, has been constructed on the site, along with a 311-acre brine pond. A buffer and mitigation area has been created along the eastern portion of the Hines site containing approximately 2,498 acres. These areas serve as a wildlife corridor as well. Approximately 3500 acres of the site are designated for water crop areas to supply captured rainfall for use in the power plant. (PEF Ex. 6, Hunter at 3; PEF Ex. JJH-4; PEF Ex. 1 at 2- 1). The Hines Energy Complex is interconnected to the electrical grid through multiple existing electrical transmission lines. A new 20 mile long 230 kV transmission line to connect the Hines Site to the existing PEF West Lake Wales Substation is being permitted separately. Natural gas is delivered to the Hines Energy Complex by two existing natural gas pipelines, which will serve Power Blocks 1, 2, 3, and 4. Fuel oil is also burned in the existing units and is delivered by truck and stored in an onsite storage tank. A new fuel oil unloading station and a new fuel and storage tank will be added to serve Power Block 4. (PEF Ex. 6, Hunter at 6, 8; PEF Ex. 1 at 3-1; Tr. 17). Project Overview The Hines Power Block 4 is a 530 MW combined-cycle power plant to be fueled primarily with natural gas. Fuel oil will be used as a backup fuel. The proposed Power Block 4 will be located entirely within the existing Hines Energy Complex site. The unit will be located west of Power Blocks 1, 2 and 3. All construction activities for Power Block 4 will occur within an approximately 5-acre portion of the plant island. (PEF Ex. 1, at 3-2, 4-1; PEF Ex. 6, Robinson at 5; Exs. JMR 4 and 5). Need for Power Block 4 On November 23, 2004, the FPSC issued a Final Order determining the need for the PEF’s Hines Power Block 4 Project. The FPSC determined that the Hines Power Block 4 will be needed by 2007 to maintain electric system reliability and integrity for PEF. This was based upon an evaluation of PEF’s load forecast and maintenance of its required 20 percent reserve margin of generating capacity above the firm demand of PEF’s customers. Power Block 4 adds to the diversity of PEF’s generating assets in terms of technology, fuel, age, and functionality. Operational flexibility is provided by Power Block 4’s dual fuel capability. The FPSC also found that the Hines Power Block 4 will contribute to the provision of adequate electricity at reasonable cost. The FPSC concluded that PEF, in proposing the Hines Power Block 4, had identified the least cost alternative compared to other options, including outside proposals from third parties. There are no cost-effective conservation measures available that might mitigate PEF’s need for Hines Power Block 4. In conclusion, the FPSC determined that PEF met the statutory requirements under Section 403.519, Florida Statutes, for the Commission to grant the determination of need for Hines Power Block 4. (PEF Ex. 3). Project Schedule and Construction The proposed Power Block 4 is similar to the existing Hines Power Blocks 1, 2, and 3, which exist or are currently under construction at the Hines site. The proposed combustion turbines for the new unit are two advanced General Electric 7FA combustion turbines, designed for dual fuel operation. Engineering of the units will commence in December 2005 and on- site construction will begin no later than the first quarter of 2006. The new unit is proposed to be in service by December 1, 2007. (PEF Ex. 6, Robinson at 4, 13-14). Construction activities will be initiated by the preparation of the five-acre site for construction. This will include mobilization of contractors and subcontractors along with plant construction project management personnel. Existing construction laydown and parking areas will be utilized for Power Block 4. On-site construction will begin with the installation of the circulating water piping and pilings for structural foundations. Power Block 4 will be mechanically complete by June 2007. (PEF Ex. 6, Robinson at 14). The construction workforce for Power Block 4 is expected to average about 145 employees over the two-year construction period. Peak construction employment is estimated at 350 employees. The construction payroll is expected to be $15 million annually. Based upon prior experience during construction of Power Blocks 1, 2, and 3, it is expected that most construction workers will be drawn from the Polk County and Central Florida areas. Construction employees are expected to commute daily to the job site. Traffic improvements have already been made in the vicinity of the Hines Energy Complex. Traffic impacts related to construction of Power Block 4 will not require additional road improvements. (PEF Ex. 1 at 4-16 to 4-17). No new roads will be required to support construction of Power Block 4 as the existing plant access road will be used during construction. Major project components will be delivered to the Hines site by rail or by truck. No off-site upgrade of rail or road facilities is expected to be necessary. All oversized deliveries will receive necessary Florida Department of Transportation (“DOT”) approvals. (PEF Ex. 1 at 3-20, 4-3; PEF Ex. 6, Robinson at 14-15). Most major earthwork activities for construction for the Power Block 4 construction area were performed during initial site development activities that were completed in 1996. There are no expected impacts to land in the Project area except for minor grading, installation of foundation systems and infrastructure piping, the new control/administration building, and the new fuel oil tank. (PEF Ex. 1 at 4-1). Heavily loaded and structural foundation loads such as the heat recovery steam generators, combustion turbines, steam turbines, and step-up transformers will be supported by deep foundations. These foundations will include deep foundations such as pilings similar to those used for Power Blocks 1, 2, and Lightly loaded foundations will use spread foundations. Construction dewatering will occur primarily at excavations for the circulating water intake structure and the discharge head wall in the cooling pond. Other additional limited dewatering may occur, depending upon the amount of rainfall and the depth of other excavations onsite. Dewatering would be performed using well points or open pit sump pumps, which have a very localized impact area. Dewatering effluent will be routed to the existing on-site stormwater collection ditches for return to the existing cooling pond. (PEF Ex. 6, Robinson at 12-13; PEF Ex. 1 at 4-7). The entire Project area is outside the 100-year flood zone. There will be no construction impacts to either on-site or off-site water bodies or wetlands as a result of construction activities. (PEF Ex. 1 at 2-2, 4-5). On-site construction activities will not have any measureable adverse ecological impacts. The five-acre Project area has already been cleared and graded in anticipation of construction of Power Block 4 and other future units. The Power Block 4 area is primarily bare soil, with very sparse weedy vegetation of low-ecological functional value. This habitat is suitable for few animals and exhibits low plant species diversity. It will not support populations of threatened and endangered species or species of special concern. There are no jurisdictional or non-jurisdictional wetlands that would be impacted by the development of Power Block 4 and the on-site portion of the new transmission line. Mitigation for wetland impacts on the Hines Energy Complex occurred as part of the original permitting process for the Hines Energy Complex. (PEF Ex. 6, Bullock at 5-6; PEF Ex. 1 at 4-10 to 4-12). Construction noise impacts from construction of all phases up to the 3,000 MWs of ultimate site capacity were analyzed as part of the 1992 certification application. It was shown at that time that the applicable noise criteria would be complied with during construction of each future phase. An updated analysis of construction noise from Power Block 4 reaffirmed the earlier analysis and demonstrated no adverse impacts from construction noise. The nearest residences are approximately 2.9 miles from the plant site. The Project construction noise levels will be less than the existing noise levels measured near these residences. Construction noise will have an insignificant effect on noise levels. (PEF Ex. 6, Osbourn at 15-16; PEF Ex 1 at 4-17 to 4-19). During construction, the most prevalent construction air emissions will be fugitive dust, generated by site grading, excavation, vehicular traffic, and other construction activities. Dust control measures will be used and will typically require moisture conditioning of construction areas and roadways. Disturbed areas will also be stabilized by mulching or seeding as soon as practical. Crushed rock may also be used in high traffic areas. It is not expected that these air emissions from construction will present any significant air quality problems during the construction period. (PEF Ex. 1 at 4-14 to 4-16). Project Description Power Block 4 will be similar to the existing Power Blocks 1, 2, and 3 at the Hines site. Power Block 4 is a new combined cycle unit of approximately 530 MWs. It will consist of two advanced GE 7 FA combustion turbines (“CT”) designed for dual fuel operation, using primarily natural gas and low sulfur fuel oil as a backup fuel. Each CT will connect to an electrical generator, capable of generating approximately 170 MWs of electricity. Each CT in Power Block 4 will be paired with a heat recovery steam generator (“HRSG”) which will extract heat energy from the CT’s exhaust gas. The HRSG is essentially a boiler that turns heat in the CT’s exhaust, which would be otherwise wasted, into steam. The steam produced in both HRSGs is used to drive a single steam turbine, which will produce an additional 190 MWs of electricity. (PEF Ex. 6, Robinson at 4 to 5; PEF Ex. JMR-2; FDEP Ex. 2 at 1-10). The normal operating mode for Power Block 4 will be for both CTs to be in operation providing steam from their respective HRSGs to the single steam turbine. However, Power Block 4 can be operated in other ways, depending on the need for electricity. One CT can be operated at full load, producing steam from its HRSG that would power the steam turbine at half load while the other CT and HRSG are idle. The unit will be operated between 30 percent load and full load in the combined cycle mode while meeting its air emission permit requirements. (PEF Ex. 6, Robinson at 4-5). Natural gas will be the principal fuel used in Power Block 4. Gas will be delivered by two existing gas pipelines that serve the Hines Energy Complex. A new on-site gas pipeline will be constructed to supply natural gas to the new Power Block 4 from the two on-site natural gas meter regulation stations. Fuel oil will be delivered by truck to a new fuel unloading facilities and stored in a new on-site fuel storage tank adjacent to Power Block 4. (PEF Ex. 1 at 3-4; Tr. 27). The existing on-site electrical switchyard will be expanded to provide electrical transmission interconnection for Power Block 4. The on-site segment of a new 230 kV transmission line between the Hines Site and the PEF West Lake Wales electrical substation is included in the project for certification. (PEF Ex. 6, Robinson at 6; Tr. 17). Pursuant to the authorization under the 1994 site certification, a 10,000 gallon per day domestic wastewater treatment plant will treat additional on-site domestic and sanitary wastewaters from on-site showers, lavatories, toilets, and drinking fountains for Power Block 4. The treated effluent is directed to the on-site cooling pond as makeup water. Potable water is provided from an existing on-site approved potable water system which is adequate to support Power Blocks 1, 2, 3, and 4. Potable water is supplied from well water and is treated and chlorinated for on-site uses such as drinking, washing, showers, and other uses. A new on-site water distribution line will be installed to support Power Block 4 and the new control and administration building. (PEF Ex. 6, Robinson at 12; PEF Ex. 1 at 3-11 to 3-12). Solid wastes that may be generated by Power Block 4 include circulating water systems screenings, sanitary waste solids, water treatment filter backwash solids, and solid wastes produced in the course of operating and maintaining the unit. Office wastes are expected to be the biggest component of these wastes. These wastes will be disposed of in differing ways. Circulating water systems screenings and water filter backwash will be recycled on-site to the extent possible. All other solid wastes will be disposed of off-site in appropriate facilities. PEF has a corporate commitment to waste minimization. This includes extensive recycling of waste products, reduction at the source, and elimination of most hazardous waste storage. This corporate commitment will be implemented on a continuing basis at the Hines Energy Complex. (PEF Ex. 6, Robinson at 12; PEF Ex. 1 at 3-18). Water Use and Supply The existing cooling pond will supply cooling water and other water needs for Power Block 4. Makeup water to the cooling pond is obtained from direct precipitation, reclaimed treated municipal effluent, on-site stormwater runoff, recycled plant blowdown and wastewaters, water cropping, and groundwater. (PEF Ex. 1 at 3-7 to 3-9). The process steam in the steam turbine is cooled to the liquid state in a steam condenser. The rejected heat from the steam is transferred to water pumped from the existing cooling pond into the circulating water system and then returned to the cooling pond. The heat rejected from the power plant results in forced evaporation above and beyond the natural evaporation that occurs in the cooling pond. The circulating water system equipment for Power Block 4 will include two new circulating water pumps capable of pumping 60,000 gallons per minute. An additional intake structure will be constructed at the cooling pond to support these pumps. (PEF Ex. 6, Robinson at 7-8; PEF Ex. 1 at 3-9 to 3-10). All process water needs for Power Block 4 will be supplied from the existing cooling pond. Water is pumped from the pond to the water treatment area located east of the existing power blocks. The water is processed for use either as service water or as demineralized water. Service water is used for washdown of equipment and other uses. The higher quality demineralized water is used for makeup to the steam-condensate- feedwater cycle in the HRSGs to replace steam cycle losses. Demineralized water is also used when firing low sulfur fuel oil in the CTs to control NOx emissions. (PEF Ex. 6, Robinson at 8- 9, Osbourn at 7; PEF Ex. 1 at 3-12 to 3-13). The reverse osmosis equipment in the demineralized water system produces a brine reject that will be pumped to the existing on-site brine pond for evaporation. The only other wastewater streams from Power Block 4 will come from the boiler blowdown and from floor drains located throughout the facility. Boiler blowdown results from removal of a portion of the water cycling in the HRSG to control the buildup of solids in that water. Boiler blowdown is collected and pumped back to the cooling pond without further treatment. Areas that contain lubricating oil equipment or where fuel lines run above ground will have containment curbs or walls. Wastewater streams from these areas that may contain oil will be routed to the existing oil water separator to remove oil contamination prior to being pumped to the cooling pond. Any collected oil is properly disposed. All wastewaters are collected and processed as appropriate and pumped back to the cooling pond. The cooling pond has no discharge to area surface waters. (PEF Ex. 6, Robinson at 9-10; PEF Ex. 1 at 3-12 to 3-16; FDEP Ex. 2 at 13). The cooling pond at the Hines Energy Complex experiences both natural and forced evaporation. The forced evaporation is that additional evaporation above and beyond natural evaporation and is caused by the heat rejected from the power plant. The total annual average evaporation rate from the cooling pond from natural evaporation and from heat rejected by Power Blocks 1, 2, 3 and the proposed Power Block 4 is approximately 10 million gallons per day. This is an increase in evaporation of 2.2 million gallons per day for Power Block 4. This loss of water needs to be replenished to keep the cooling pond operating and keep the plant continuing in operation. (PEF Ex. 6, Robinson at 7-8; PEF Ex. 1 at 3-9). It has been determined that, over the long term, Power Block 4 will require an average annual daily water supply of 2.4 million gallons per day. This is needed to replace evaporation from the pond and to supply the process water needs for the new unit. (PEF Ex. 1 at 3-8). The existing Conditions of Certification for the Hines Energy Complex authorize the use of up to 17.5 million gallons per day of groundwater beginning with the third generating unit at the Hines Energy Complex. The water needs for Power Block 4 will be supplied from these previously approved quantities of groundwater. The existing Units 1 and 2 utilize a mix of treated wastewater from on-site and off-site sources and captured rainfall to supply cooling and process water needs for Power Blocks 1 and 2. (PEF Ex. 1 at 3-7 to 3-9; PEF Ex. 6, Hunter at 7; FDEP Ex. 2, Appendix IV, SWFWMD Agency Report at 7). Under the Conditions of Certification, no groundwater will be withdrawn to supplement the cooling pond until the operating level in the cooling pond falls to 160 feet. The proposed on-site withdrawals were previously evaluated as part of the initial certification proceeding in 1994 and were found to have no adverse impacts. The proposed on-site withdrawals of groundwater for Power Block 4 will not have any adverse impacts on existing legal users of water in the vicinity of the Project, on- and off-site wetlands, or to off-site land uses. PEF has investigated other reasonably obtainable sources of water in the region and found none that could meet the needs for Power Block (PEF Ex. 1, Vol. 2, Appendix 10.6; FDEP Ex. 2, App. IV, SWFWMD Agency Report at 8-9). PEF has undertaken several efforts to minimize the use of groundwater through the use of water conservation practices, as required by the Conditions of Certification in the 1994 site certification. These measures include the use of water conserving electric generation technologies, recycling of all wastewater streams, and the design of the power plant as a “zero discharge” facility. PEF is also continuing to investigate other sources of water supply for the Hines site. (FDEP Ex. 2, App. IV, SWFWMD Agency Report at 8). Power Blocks 1 and 2 are supplied water from the on- site water cropping system and on-site and off-site treated wastewaters. The capture and reuse of rainfall is an integrated part of PEF’s efforts to reduce dependence on the Upper Floridan aquifer as a source of water. In addition, recycled plant wastewaters, treated wastewater from the City of Bartow, and nearby industrial and power plants are the other primary sources of water for Hines Power Blocks 1 and 2. The City of Bartow currently provides approximately 2.0 million gallons per day of treated wastewater for use at the Hines Energy Complex. (PEF Ex. 1, Hunter at 7; FDEP Ex. 2, App. IV, SWFWMD Agency Report at 6-8). Air Emissions The primary air pollutants emitted from Hines Power Block 4 will include nitrogen oxides (“NOx”), carbon monoxide (“CO”), particulate matter (“PM”), and sulfur oxides such as sulfur dioxide. The primary cause of the air emissions from the new unit will be the combustion of natural gas and distillate oil in the CTs. Emissions of NOx and CO will result from the combustion process. Emissions of PM and sulfur dioxide result from trace impurities in the fuel itself. (PEF Ex. 6, Osbourn at 4-5; Tr. 35-37). Air emissions from Power Block 4 will be minimized through the inherent efficiency of the combined cycle technology, as well as the use of natural gas and light oil, use of combustion controls, and use of post-combustion control technology for nitrogen oxide emissions. Natural gas is the cleanest of fossil fuels and contains minimal amounts of impurities. Light oil is also very low in impurities and its use will be limited to up to 1,000 hours per year per combustion turbine. Natural gas and light oil burn very efficiently, thus minimizing the formation of air pollutants. Emissions are also minimized through the use of advanced combustion control technology in the combustion turbine, specifically dry, low NOx combustion controls for firing natural gas, and use of water injection when firing light oil. A post-combustion control technology, selective catalytic reduction (“SCR”) will be used to further reduce NOx emissions from Power Block 4. (PEF Ex. 6, Osbourn at 5-6; Tr. 35). The Hines Power Block 4 is required to meet best available control technology (“BACT”) requirements, which limits air pollution emission rates. The Project must also comply with ambient air quality standards (“AAQS”) and prevention of significant deterioration (“PSD”) increment standards, which establish levels of air quality which must be met. (PEF Ex. 6, Osbourn at 6-7; PEF Ex. 1 at 3.5 to 3-6; FDEP Ex. 2 at 6, 17). Hines Power Block 4 is required to undergo PSD review because it is a new source of air pollution that will emit some air pollutants above the threshold amounts established under the PSD program. PSD review was required for air emissions of PM, sulfur dioxide, NOx, CO, and sulfuric acid mist because these emissions are greater than the established PSD thresholds. (PEF Ex. 6, Osbourn at 7). The BACT analysis for Hines Power Block 4 is part of the evaluation of air emissions control technology under the PSD regulations and is applicable to all pollutants for which PSD review is required. BACT is a pollutant-specific emission standard that provides the maximum degree of emission reduction, after taking into account the energy, environmental, and economic impacts and other costs. (PEF Ex. 6, Osbourn at 6-7; FDEP Ex. 2 at 6). For NOx, FDEP has preliminarily determined for this facility a BACT emission limit of 2.5 parts per million when firing natural gas, and 10 parts per million when firing low sulfur fuel oil. These emission levels will be achieved by the use of dry low NOx combustion technology when firing natural gas, use of water injection when firing fuel oil, and use of SCR technology. (PEF Ex. 6, Osbourn at 8; FDEP Ex. 2 at 9, 21, Table 4). Emissions of carbon monoxide will be controlled using good combustion techniques. Sulfur dioxide emissions, including sulfuric acid mist, will be controlled through the use of clean fuels. Particulate matter emissions will be controlled through the use of clean fuels, natural gas, and low sulfur fuel oil. Fuel oil firing will be limited to a maximum of about 1,000 hours per year. (PEF Ex. 6, Osbourn at 7-9; PEF Ex. 10, Slide 15; Tr. 36-37). The air emissions from Power Block 4 cannot be permitted at a level that would cause or contribute to a violation of federal and state AAQS for the six criteria air pollutants or PSD increments for sulfur dioxide, NOx, and PM. The PSD increments refer to the amount of incremental air quality deterioration allowed from a new air pollution source. Polk County is classified as a Class II area for PSD purposes. The nearest Class I PSD area within which limited increases in air pollutant concentrations are allowed is the Chassahowitzka National Wilderness Area. (PEF Ex. 6, Osbourn at 9-11; FDEP Ex. 2 at 6-8, 16-17). Air emissions from Power Block 4 were principally analyzed for emissions from fuel oil firing as representing the maximum air quality impact. The air quality impact analysis was performed using approved air quality models and five years of historical hourly meteorological data. This analysis indicated that Power Block 4 will not cause any violations of federal or state AAQS and will comply with applicable PSD Class II and Class I increments. The maximum impact of the Project was estimated to be well below the applicable PSD Class II increments. Maximum ambient air impacts were also estimated to be well below the applicable AAQS. Using worst case air emissions during oil firing, it was shown that the Project impacts would be less than the PSD Class I increments, as well as less than the Class I significant impact levels, and therefore were concluded not to be significant in the PSD Class I area. (PEF Ex. 6, Osbourn at 8-14, Exs. SO-3 and SO-4; FDEP Ex. 2 at 7-8, 16-17). Air emissions from Power Block 4 are not expected to have any impact on vegetation or to cause any growth-related air quality impacts. The results of the visibility impact analysis of the Project’s emissions in the nearest PSD Class I area demonstrated no adverse impact on visibility at that location due to Power Block 4. (PEF Ex. 6, Osbourn at 14-15; FDEP Ex. 2 at 6-7, 17). Noise Noise impacts during operation of Power Block 4 were shown not to be significant. Noise monitoring was originally conducted at various locations around the Hines Energy Complex site prior to construction and operation of Power Block 1. Additional noise monitoring was conducted at these locations in 2000 and 2004 during the permitting of Power Blocks 2 and 4, to determine any changes since the original permitting. There are only a few isolated rural residences in the land area surrounding the site. The nearest residence is about 2.5 miles from the proposed Power Block 4. Industrial activities in the surrounding area result in considerable traffic on nearby roads, causing noise levels to exceed the EPA guideline of 55 dBA. Without the area traffic, ambient noise levels meet the EPA guidelines. (PEF Ex. 1 at 2-65 to 2-72). Using a conservative approach which tends to overstate the Project impacts, noise impacts due to operation of Power Block 4 would increase by less than 2 dBA at the nearest receptor and will not be significant. Therefore, the Project will meet applicable noise criteria and no significant noise impacts will occur as a result of the Project. (PEF Ex. 6, Osbourn at 15-16; PEF Ex. 10, Slide 23; PEF Ex. 1 at 5-9 to 5-12). Land Use and Socioeconomic Impacts The Plant Island, where Power Block 1 is in operation and where Power Block 4 will be constructed, is located near the southern end of the site. The northern boundary of the Plant Island is about two miles south of CR 640. The western limit of the City of Fort Meade is about 3.9 miles east of the Plant Island, and the unincorporated community of Homeland is more than 3.5 miles northeast of the Plant Island. The nearest residential use is three homes located approximately 2.5 miles from the southern boundary of the Plant Island. Otherwise, the entire area surrounding the proposed power plant site consists of existing or former phosphate mines. The site is buffered from surrounding populations at Homeland and Fort Meade by an extensive buffer area on the eastern perimeter of the site. There has been almost no change in land use and very little change in the landscape in the area of the Hines Energy Complex since the original site certification. (PEF Ex. 6, Zwolak at 5- 6). There have not been any changes in the area surrounding the Hines Energy Complex that would change the land use and socio-economic conclusions reached in the Final Order of Certification issued for the site by the Siting Board on January 27, 1994. The most significant change has been the completion of another nearby power plant approximately three miles southeast of the Hines site. (PEF Ex. 6, Zwolak at 6). No land use or socio-economic impacts will be associated with construction of Power Block 4 that were not previously addressed in the Final Order of Certification for the Hines Energy Complex in 1994. (PEF Ex. 6, Zwolak at 6-8). The land use impacts from development and construction of Power Block 4 will be quite minimal, and the economic benefits will be substantial. Current operating employment at the Hines Energy Complex is 29. The staffing level at the plant is expected to increase by six employees with the addition of Power Block 4. Annual payroll was $2.7 million in 2002. The annual payroll will increase by about $493,000 when Power Block 4 becomes operational in 2007. (PEF Ex. 6, Zwolak at 8). The estimated increase in property taxes for Power Block 4 is $5.0 million. Over one-half of this revenue goes to support the Polk County school system. (PEF Ex. 6, Zwolak at 8; PEF Ex. 1 at 7-1). Agency Positions and Stipulations The FDEP, the Florida Department of Community Affairs, the FDOT, and the SWFWMD each prepared written reports on the Project. (FDEP Ex. 2). Each of these agencies either recommended approval of Hines Power Block 4 or otherwise did not object to certification of the proposed power plant. The FDEP has proposed a series of Conditions of Certification for the Project that incorporate the recommendations of the various reviewing agencies. At hearing, the FDEP added one additional condition related to air emissions monitoring. (Tr. 54-55). PEF states that it can comply with these Conditions of Certification in the design, construction, and operation of the Hines Power Block 4. (Tr. 21, 56). No state, regional, or local agency has recommended denial of certification of the Project or has otherwise objected to certification of the Project. (PEF Ex. 4). Subject to compliance with the proposed conditions of certification, the proposed design of Hines Power Block 4 offers reasonable assurance that the standards of the FDEP and other affected regulatory agencies will be met and that the operation safeguards are technically sufficient for the protection of the citizens of the state. The Hines Power Block 4, as proposed, minimizes through reasonable and available methods the 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. (FDEP Ex. 1 at 28; Tr. 57-59).
Conclusions For Progress Energy Florida: Douglas S. Roberts, Esquire Hopping Green & Sams, P.A. Post Office Box 6526 Tallahassee, Florida 32314-6526 For the Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 For the Southwest Florida Water Management District: Martha A. Moore, Esquire Southwest Florida Water Management District 2379 Broad Street Brooksville, Florida 34604-6899
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order granting certification to PEF to construct and operate a new 530 MW natural gas-fired electrical power plant (Hines Power Block 4 Project) in Polk County, Florida, in accordance with the Conditions of Certification, FDEP Exhibit 2. DONE AND ENTERED this 5th day of April, 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 5th day of April, 2005. COPIES FURNISHED: Douglas S. Roberts, Esquire Hopping Green & Sams, P.A. Post Office Box 6526 Tallahassee, Florida 32314-6526 Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 Martha A. Moore, Esquire Southwest Florida Water Management District 2379 Broad Street Brooksville, Florida 34604-6899 Michael Duclos, Esquire Polk County Attorney’s Office Post Office Box 9005 Bartow, Florida 33831-9005 James V. Antista, Esquire Fish and Wildlife Conservation Commission 620 South Meridian Street Tallahassee, Florida 32399-1600 Sheauching Yu, Esquire Department of Transportation Haydon Burns Building 605 Suwannee Street, Mail Station 58 Tallahassee, Florida 32399-0450 Craig Varn, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Wm. Cochran Keating IV, Esquire Florida Public Service Commission 2450 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Norman White, Esquire Central Florida Regional Planning Council 555 East Church Street Bartow, Florida 33830 Steven Palmer Siting Coordination Office Department of Environmental Protection 2600 Blair Stone Road Tallahassee, Florida 32399 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
Findings Of Fact The County is a political subdivision of the State of Florida, and the Hillsborough County Sheriff's Office is a department of the County government. On or about January 18, 1989, a site evaluation for the County's application, on behalf of the Hillsborough County Sheriff's Department, for an onsite sewage disposal system (septic tank and drainfield) at Vandenberg Airport was conducted. A soil profile was prepared showing brown sand from the ground surface down 14 inches, a gray sand down another 2 inches, and a gray clay from 16 inches to 7 feet below the surface. The United States Department of Agriculture Soils Survey Book classifies the soils found at Vandenberg Airport as Manatee fine sandy loam, which is now called Chobee 10, and characterizes its permeability as "severe" with a seasonal high water table of from 0 inches at ground surface to 10 inches below the ground surface. By letter dated April 13, 1989, the Department formally denied the County's application due to the poor texture of the Chobee 10 soil and high water table found in the site evaluation, as well as the zoning of the property. This denial letter recognized the applicant's right to apply for a variance. Since the County anticipated denial of its application due to verbal indications from Departmental representatives, the County filed an application for variance with the Department on or about March 29, 1989. A Variance Review Board met and considered the County's variance application, and then recommended approval. However, the variance application was denied by the Department on June 1, 1989, due to the nature of the activities to be conducted on the site, as well as the severe soil conditions on site. The denial of the County's variance request effectively denied its application for this permit. The County has timely sought this review of the Department's denial of its application for a permit for a septic tank and drainfield system at Vandenberg Airport for use by the Sheriff's Department. The parties stipulated that the County's application included the redesign plans and report of its consulting engineers. They further stipulated that the location for which this permit is sought is imperative to the duties of the Sheriff's Department, and there is no alternative to this location without greatly increasing the response time of the Sheriff's Department to emergencies and other calls for service. The Hillsborough County Sheriff's Department has been operating its aviation unit out of a hangar at Vandenberg Airport for several years, and in March, 1989, the County entered into a ten year lease with the Hillsborough County Aviation Authority for approximately 103,126 square feet of land (2.37 acres) located at the Vandenberg Airport for a new hangar for storage and maintenance of aircraft used in conjunction with the services provided by the Sheriff's aviation unit. The site was formerly used for three residences which were served by septic tanks. This lease specifically provides that the County is responsible for obtaining all necessary permits and for securing necessary utility services for the use of this Sheriff's hangar. Thus, the Aviation Authority is not responsible for providing sewage treatment facilities for this site. The Hillsborough County Aviation Authority is not a unit within Hillsborough County government, but is an independent entity established by Special Act. The County has no control or authority over the Aviation Authority's creation of development plans, but the County may approve or disapprove these plans after they have been created by the Aviation Authority and submitted to the County. The Authority's development plans for expansion of Vandenberg Airport provide for runway expansion, taxiways, aprons and parking for aircraft and hangar expansion. As part of this expansion, the Aviation Authority has removed 51 individual septic tanks from homes located on lands which have been acquired, and which now comprise part of Vandenberg Airport. There is no record of any problems with the three residential septic tanks formerly located on this site for 25 to 30 years. The Aviation Authority's plans do not include construction of a sewage treatment plant or providing sewage treatment services in any manner other than with septic tanks, the permits for which must be obtained by its lessees. No centralized wastewater service is available to the proposed Sheriff's hangar at the Vandenberg Airport, and the closest sewer main will be more than 10,000 feet away upon its completion in 1990. The County's five year capital improvement plan does not include extension of this sewer line to the Airport. The location for the Sheriff's hangar is currently zoned SPI-AP-V, which is a special airport district zoning classification created in September, 1989, for Vandenberg Airport. In this zoning district, manufacturing, processing and assembly activities are prohibited. Retail activities are also prohibited, as well as hotels, motels, repair services, physician and dental offices, bus and train terminals, lumberyards, warehouses, publishing and printing, and rental and leasing activities. This district is to be used for public use facilities, wastewater treatment plants and lift stations, aircraft landing fields, airport and airport related activities. "Airport" activities are defined to include fuel storage and transmission facilities, hangars, aircraft service, repair and maintenance facilities. "Airport related" activities are defined as: Uses which are dependent upon proximity to the airport for effective performance, or which provide services to the airport..., including but not limited to airport maintenance facilities and associated administrative offices; sales of new and used aircraft and aircraft parts; sales of aircraft fuels, lubricants, and other aircraft supplies; ... and other airport-related uses compatible with the operation of airports for public and private use. Based upon five soil borings taken at the boundaries of, as well as within, the proposed hangar site, Darrell Hanecki, a geotechnical engineer who was accepted as an expert in engineering, found that the groundwater table was 3 to 4 feet below the existing ground surface in October and November, 1988. The seasonal high groundwater table was estimated to be approximately 12 inches above the existing ground water table at that time, but significant fluctuations in the groundwater level were anticipated due to seasonal variations in rainfall, runoff, and other site specific factors. The borings upon which Hanecki's findings are based were performed in general compliance with accepted procedures for standard field penetration tests. Hanecki concluded that the soil conditions are suitable for the proposed hangar if constructed on a shallow footing foundation with special site preparations. William Fernandez, who was accepted as an expert in civil engineering, developed a redesign of the County's septic tank and drainfield in support of its variance request in order to address concerns expressed by the Department's representatives concerning soil conditions on site. It is proposed that the septic tank and drainfield site will be excavated to a depth of 6 feet, and all clays will be removed. The site will then be backfilled with clean materials in order to allow the drainfield to percolate through these clean materials from three mounded drains which will be located in a two foot high mound constructed above the original grade. A pump will be used to lift the effluent from the tank to the drainfield. The septic tank will have a 750 gallon capacity. It is projected that 8 people will use this septic tank each day, and that each person will cause 25 gallons of sewage per day to be deposited in the system, or a total of 160 gallons of sewage per day. Only domestic wastes from the hangar restrooms will go into the system. Oils, greases and other substances used in aircraft maintenance and repair will be separated and carried to a retention pond through a system of trenches. After hearing the testimony of the County's expert witnesses about the surface water management system to be constructed on site, the Department's environmental specialist, Gary Schneider, testified that he was no longer as concerned about the possibility of oils, greases and other hazardous materials getting into the septic tank system. The County has also applied to the Southwest Florida Water Management District for a surface water management permit, and must receive that permit for this proposed hangar at Vandenberg Airport. The Department seeks to rebut the expert testimony offered by the county primarily with the testimony of Robert Blanco, supervisor of the county health department's septic tank permit program, who was neither tendered nor accepted as an expert, as well as a letter from Richard Ford, resource soil scientist with the Soil Conservation Service, dated September 18, 1989, who took one soil boring and concluded that the soil identified was poorly drained to very poorly drained Chobee loamy sand. Ford was not present to testify. Blanco agreed with Ford's conclusion, expressed in his letter, that the seasonal high water table on this site will come to the surface, or within 10 inches of the surface, for 2 to 6 months each year, causing ponding to occur. Based upon the demeanor and qualifications of the witnesses who testified at hearing, it is specifically found that the testimony offered in support of the County's application, and in particular the expert testimony of Hanecki and Fernandez, is more credible and is given greater weight than the testimony offered on behalf of the Department, particularly the testimony of Blanco. Blanco was not qualified or tendered as an expert in any field, and therefore, he was only competent to offer fact testimony. He speculated, without any supporting evidence in the record, that the septic tanks formerly on this site were not built to Code specifications and probably did not work, although there is no evidence of any complaints about these septic tanks during the 25 to 30 years they were in operation. Blanco also insisted that standardized texts describing soil types over large geographic areas are more reliable than actual soil borings on site, although he could not render an expert opinion in this regard. The letter from Ford offered by the Department was not supported by other competent, substantial, credible evidence, and in any event was based upon only one soil boring as opposed to five borings conducted by Hanecki in accordance with generally accepted practices. Therefore, it is found that the groundwater table on this site is 3 to 4 feet below the existing ground surface, and the seasonal high groundwater table is approximately 12 inches above the existing groundwater table, although it does fluctuate. It was undisputed at hearing that the soils on site are Chobee 10, which is poorly to very poorly drained soil, but the County's redesign of the proposed septic tank and drainfield reasonably and adequately accounts for, and accommodates, this condition by excavating to a depth of 6 feet and backfilling with clean materials, and by placing three drains in a mounded drainfield built two feet above the existing ground level. This redesign complies with the requirements and provisions of Chapter 10D-6, Florida Administrative Code.
Recommendation Based upon the foregoing, it is recommended that the Department enter a Final Order granting the application of Hillsborough County for a permit for an onsite sewage disposal system (septic tank and drainfield) for the Sheriff's Department hangar at Vandenberg Airport. DONE AND ENTERED this 24th day of October, 1989 in Tallahassee, Florida. DONALD D. CONN 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 24th day of October, 1989. APPENDIX TO RECOMMENDED ORDER, CASE NO. 89-3776 Rulings on the County's Proposed Findings of Fact: 1. Adopted in Finding 1. 2-7. Adopted in Findings 6, 7. Adopted in Finding 8. Adopted in Finding 7. Adopted in Finding 10. Adopted in Findings 9, 12. 12-13. Adopted in Findings 2, 3. Adopted in Findings 10, 12. Adopted in Findings 3, 5, 10. Adopted in Findings 3, 4. Rulings on the Department's Proposed Findings of Fact: Adopted in Finding 6. Adopted in Finding 8. 3-4. Adopted in Finding 2. Adopted in Finding 11; Rejected in Finding 12. Rejected in Finding 12 as irrelevant and immaterial since the classification of the soils on site was not disputed at hearing. Adopted in Finding 5. Adopted and Rejected in part in Finding 12. COPIES FURNISHED: Michael J. Morrison, Esquire Assistant County Attorney 725 East Kennedy Boulevard Tampa, Florida 33602 Raymond R. Deckert, Esquire W. T. Edwards Facility 4000 West Buffalo Avenue Room 500 Tampa, Florida 33614 John Miller, General Counsel 1323 Winewood Boulevard Tallahassee, Florida 32399-0700 Sam Power, Agency Clerk 1323 Winewood Boulevard Tallahassee, Florida 32399-0700 Gregory Coler, Secretary 1323 Winewood Boulevard Tallahassee, Florida 32399-0700
Findings Of Fact On or about December 28, 1987 Hy Kom filed with the Department an application for a permit to construct a .0126 MGD Advanced Waste Water Treatment Plant on Emerson Point, Snead Island in Manatee County. The proposed waste water treatment plant would discharge effluent into the waters of Terra Ceia Bay in Manatee County. The proposed waste water treatment plant would discharge effluent into the waters of Tampa Bay in Manatee County. The proposed waste water treatment plant would discharge effluent into the waters of Manatee River in Manatee County. The waters of Terra Ceia Bay have been designated Outstanding Florida Waters (OFW) by the Department. On or about April 27, 1989 the Department issued a Notice of Permit Denial concerning Hy Kom's permit application. The parties stipulate the Intervenor, Manasota-88, has standing to intervene as a party Respondent and to object to the issuance of the permit. Petitioner's evidence can best be summarized by what was not submitted. First, the expert witness called to identify the application had not prepared any part of the application or verified any of the studies presented therein. Similarly Petitioner's expert on the proposed treatment plant did not testify that Petitioner was committed to using this plant, or that the construction of the plant and the operation of the plant would comply with statutory and rule requirements. The only witness called by Petitioner to testify to the effect the discharge from the proposed advanced waste water treatment plant would have on the receiving waters was also Respondent's expert; and this witness testified that the effluent discharge from this proposed plant would have an adverse effect on the receiving waters, would seriously degrade the receiving waters as a nursery habitat for both crustacea and fishes endemic to the area, and that no reasonable assurances that this would not happen were ever presented by the Petitioner. This witness further testified that no discharge into these receiving waters would be acceptable not only because of the nitrogen level (which was the most significant reason for denying the permit) but also because even a discharge of absolutely pure water would upset the salinity of the receiving waters at the critical time the receiving waters act as a marine nursery.
Recommendation It is RECOMMENDED that a Final Order be entered denying the application of Hy Kom Development Company, for a permit to construct and operate an advanced waste water treatment facility at Emerson Point, Snead Island, Manatee County, Florida. DONE and ORDERED this _15th_ day of September, 1992 in Tallahassee, Leon County, Florida. COPIES FURNISHED: JAMES W. STARNS ESQ 501 GOODLETTE RD SUITE D-100-24 NAPLES FL 33940 W DOUGLAS BEASON ESQ ASST GENERAL COUNSEL K. N. AYERS 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 _15th_ day of September, 1992. DEPT OF ENVIRONMENTAL REGULATION 2600 BLAIRSTONE RD TALLAHASSEE FL 32399 2400 THOMAS W REESE ESQ 123 EIGHTH ST N ST PETERSBURG FL 33701 DANIEL H THOMPSON ESQ GENERAL COUNSEL DEPT OF ENVIRONMENTAL REGULATION 2600 BLAIRSTONE RD TALLAHASSEE FL 32399 2400 CAROL BROWNER SECRETARY DEPT OF ENVIRONMENTAL REGULATION 2600 BLAIRSTONE RD TALLAHASSEE FL 32399 2400
The Issue The issue is whether Palm Beach County's application for a permit to construct a domestic wastewater collection/transmission system in Palm Beach County should be approved.
Findings Of Fact Based upon all of the evidence, the following findings of fact are determined: Parties The County is a political subdivision of the State of Florida and is the permittee in this matter. The County Water Utilities Department currently serves approximately 425,000 persons, making it the largest utility provider in Palm Beach County and the third largest in the State of Florida. ITID is an independent water control special district created by special act of the legislature in 1957 and whose boundaries lie within the County. Portions of the transmission line to be constructed by the County will cross easements and roads, and pass under canals, owned by ITID. Petitioners Joseph Acqualotta, Michael D'Ordine, Ann Hawkins, and Lisa Lander all live in areas in close proximity to the proposed transmission line. Lander lives adjacent to the proposed route of the line along 40th Street North, while Acqualotta, D'Ordine, and Hawkins live adjacent to the proposed route along 140th Avenue North. Acqualotta, Hawkins (but not D'Ordine, who resides with Hawkins), and Lander own the property where they reside. Petitioners Troy and Tracey Lee (Case No. 05-2979), Lisa Gabler (Case No. 05- 2980), and Anthony and Veronica Daly (Case No. 05-2982) did not appear at the final hearing. The Department is an agency of the State of Florida authorized to administer the provisions of Part I of Chapter 403, Florida Statutes, and is the state agency charged with the responsibility of issuing domestic wastewater collection/ transmission permits under Section 403.087, Florida Statutes (2004).1 Background On December 15, 2004, the County filed its application with the Department for an individual permit to construct a domestic wastewater collection/transmission system (Transmission Line). The Transmission Line is one element of the County's Northern Region Utilities Improvement Project (Project) and will be approximately 41,050 feet long and comprised of approximately 32,350 linear feet of 20-inch force main and 18,700 linear feet of 30-inch force main (or nearly ten miles in length). A primary purpose of the Project is to provide water and wastewater service to the Village, a 1,900 acre parcel located in the unincorporated part of the County several miles west of the Florida Turnpike, south of State Road 710, and north of the Villages of Wellington and Royal Palm Beach. The Village will be the home of the Scripps Project and Campus. The Transmission Line will run from the southeastern corner of the Village south to Northlake Boulevard, then east to 140th Avenue North, then south along that roadway to 40th Street North, where it turns east until it interconnects with existing facilities. The wastewater will be collected in a regional pump station on the Scripps Project site, where it will be pumped through the Transmission Line to the East Central Plant, which will be the primary treatment facility. The East Central Plant is owned and operated by the City of West Palm Beach (City), but the County owns between forty and forty-five percent of the treatment capacity. Because the wastewater system is interconnected, the wastewater could also be treated at the County's Southern Regional Plant. Ultimately, the flow from the Scripps Project will be one or two million gallons per day. The Transmission Line is the only way that wastewater can be handled at the Scripps Project. A preliminary analysis by the Department and the South Florida Water Management District determined that on-site treatment was not feasible because of the environmentally sensitive nature of the area. The Scripps Project will include residential units, commercial entities, and institutional uses, such as medical clinics. Besides serving these customers, the Transmission Line will also serve other customers in the area. The County has already signed agreements with the Beeline Community Development District (which lies a few miles northwest of the Village) and the Village of Royal Palm Beach (which lies several miles south-southeast of the Village). At the time of the hearing, the County anticipated that it would also sign an agreement with Seacoast Utility Authority (whose service area is located just southeast of the Village) to transport wastewater through the Transmission Line. All of the treatment facilities have sufficient existing capacity to treat the estimated amount of domestic wastewater that will be generated by the Scripps Project and the other users that will discharge to the Line. The County commenced construction of the Transmission Line in May 2005 when the Department issued the Permit. On August 2, 2005, the County published the Department's Notice to issue the Permit, and once the Petitions were filed, the County stopped construction pending the outcome of this hearing. Approximately seventy percent of the Transmission Line is now completed. The Permit does not allow the Transmission Line to be used until it is pressure tested and certified complete. Upon completion, the County must receive an Approval to Place a Domestic Wastewater Collection/Transmission System into Operation from the Department. Such approval is given only after the County has given reasonable assurance that adequate transmission, treatment, and disposal is available in accordance with Department standards. See Fla. Admin. Code R. 62-604.700. On August 15, 2005, Petitions challenging the issuance of the Permit were filed by ITID and the individual Petitioners. ITID contends that the Transmission Line will convey not only domestic wastewater, but also industrial waste; that the County did not comply with all applicable technical standards and criteria required under the Department's rules; that the Project will be located on ITID's right-of-way, on which the County has no right to occupy; that the Project will be located within seventy-five feet from private drinking wells and does not provide an equivalent level of reliability and public health protection; and that the pipe material and pressure design is inappropriate for the Transmission Line's requirements. The individual Petitioners (who filed identical Petitions) are mainly concerned about the location of the Transmission Line in relation to their private drinking wells and property, the possibility of the pipe bursting or leaking once it becomes operational, and the restoration of their property to its original condition after construction is completed. As to the property claims by all Petitioners, the County plans to place the Transmission Line in property that it either owns or has an easement, in property that it is in the process of condemning, or in a public right of way. While the County acknowledges that it has already placed, and intends to place other portions of, the Transmission Line in easements that ITID says it has the exclusive right to use and for which a permit from ITID is required, the County alleges that it also has the right to use those easements without an ITID permit. The dispute between the County and ITID is the subject of a circuit court proceeding in Palm Beach County, and neither the Department nor DOAH has the authority to decide property interests. Petitioners' Objections Domestic wastewater and pretreatment The wastewater that will be generated by the Scripps Project is considered domestic wastewater; it will not include industrial wastewater. Waste that is industrial or non- domestic must be pretreated to protect the wastewater plant, collection system, and the health of system workers and the general public. The Department administers a pretreatment program through which it requires a public wastewater utility to police the entities that discharge to their wastewater plants. A central part of the pretreatment program is the local ordinance that gives legal authority to the utility to permit, inspect, and take enforcement action against industrial users who are part of the pretreatment program. The utility files an annual report with an industrial user survey, and the Department periodically inspects and audits local pretreatment programs to ensure they are being operated as intended. The system is not failsafe but is designed to ensure that potentially harmful wastes are rendered harmless before discharge. For example, the utility has the authority to immediately shut water off if a harmful discharge is occurring. Both the County and the City have pretreatment programs approved by the Department. The City has an ordinance that allows it to enforce the pretreatment standards for all entities that discharge to its wastewater system. The County Water Utilities Department has a written pretreatment manual, and the County has zoning restrictions on the discharge of harmful material to the wastewater system. It has also entered into an interlocal agreement under which it agrees to enforce the City ordinance. The County provides wastewater treatment to industrial, educational, and medical facilities, and it has never experienced a discharge from any of these facilities that has caused adverse health or environmental impacts. The County pretreatment program for the Southern Regional Facility was approved in 1997. The City pretreatment program for the East Central Regional Facility was approved in 1980. The Scripps Project must apply for a permit from the County and provide a baseline monitoring report, data on its flow, and information on the flow frequency and raw materials. Medical waste from the Scripps Project will be pretreated to render it safe before it is discharged into the Transmission Line. Transmission Line Design The Transmission Line was designed in accordance with the technical standards and criteria for wastewater transmission lines in Florida Administrative Code Rule 62- 604.300(5). That rule incorporates by reference a set of standards commonly known as the Ten State Standards, which contain several of the standards used in the design of this project. These standards are recommended, but are not mandatory, and a professional engineer should exercise his or her professional judgment in applying them in any particular case. The Transmission Line also meets the design standards promulgated by the America Water Works Association (AWWA). Specifically, the County used the AWWA C-905 design standard for sizing the polyvinyl chloride, or PVC, pipe used in the project. The County has received written certification from the manufacturer that the PVC pipe meets the standards in AWWA C-905. The Transmission Line is designed with stub-outs, which will allow for future connections without an interruption of service, and inline isolation valves, which allow the line to be shut down for maintenance. The Use of PVC Pipe There is no standard regulating the selection of PVC pipe material in the Department's rules. Instead, the Department relies on the certification of the applicant and the engineer's seal that the force main will be constructed to accepted engineering standards. The only specification applicable to the Transmission Line is the Ten State Standard, adopted and incorporated by reference in Florida Administrative Code Rule 62-604.300(5)(g). That document contains a general requirement that the material selected have a pressure rating sufficient to handle anticipated pressures in wastewater transmission lines. The Transmission Line will be constructed with PVC piping with a thickness of Dimension Ratio (DR) 32.5, which is the ratio of the outside diameter of the pipe to its thickness. Higher ratios mean thinner-walled pipes. This is not the first time the County has used 32.5 PVC piping for one of its projects, and other local governments in the State have used 32.5 or thinner pipe. The County is typically conservative in requiring thicker-walled pipe, because most transmission lines are built by developers, and the County is unable to design the entire line or control or inspect its installation. The specifications for wastewater transmission lines built in the County call for the use of DR 25 pipe. On this project, however, the County determined that thicker- walled pipe would have been an over-design of the system because the County controls the pump stations and oversees the installation; therefore, the Director of the Water Utilities Department has waived that requirement. The County considers the use of DR 32.5 PVC to be conservative. Although this pipe will be thinner than what is typically used in the County, it satisfies the Department's requirements. The Department has permitted many miles of similar PVC force mains in South Florida, and none have failed. PVC has benefits over other transmission line material, such as ductile iron. For example, PVC is more corrosion resistant. Wastewater generates hydrogen sulfide as it decomposes, which can form highly corrosive sulfuric acid. Some of the older transmission lines in the County that were made of ductile iron have corroded. PVC also has a superior ability to absorb surges, such as cyclical surges, than ductile iron. It is easier to install, and its interior flow characteristics are smoother than ductile iron or pre-stressed concrete pipe. Mr. Farabee, a professional engineer who testified on behalf of ITID, recommended a DR 14 pipe, which is thicker- walled than the DR 32.5 pipe used by the County. While he opined that the DR 32.5 pipe was too thin for the project, he could not definitively state that it would not pass the 150 per square inch (psi) pressure test. He also opined that the pipe is undersized because it will be unable to withstand the surge pressures during cleaning. The witness further testified that the pipe would be subject to much higher pressures than 150 psi, and therefore it was impossible to know whether the pipe would fail. In his opinion, this means the Department did not have reasonable assurance for the project. The County consulted with the Unibell PVC Pipe Association (Unibell) in the planning of this project. Unibell is a trade association that provides technical support for PVC pipe manufacturers. Robert Walker, a registered professional engineer and Unibell's executive director who testified on behalf of the County, disagreed with Mr. Farabee's conclusions concerning the adequacy of the PVC pipe in this project. The AWWA C-905 standard uses a safety factor of two, which means the pipes are tested at pressures that are at least twice their stated design strength. Mr. Walker explained the different standards that apply to PVC pipe. DR 32.5 pipe, which is used in this project, has a minimum interior pressure rating of 125 pounds per square psi. Each pipe section is tested before it is shipped at 250 psi, and the minimum burst pressure for the material is in excess of 400 psi. The pipe also meets a 1000- hour test at 270 psi. In light of these standards and testing, the pipe will pass the two-hour 150 psi test required by the Department. Mr. Farabee expressed some concern that the PVC pipe would be more prone to breakage than ductile iron or thicker PVC. However, the PVC pipe standards provide that the pipe can be flattened at sixty percent without splitting, cracking, or breaking. At shallow depths on dirt roads, ovalation, which occurs when PVC is flattened through pressure, will initially occur, but over time the soil around the pipe will become compacted and result in re-rounding of the pipe. The joints are three times stiffer than the body of the pipe, which will protect the joint from excessive ovalation and leaking, and the use of mechanical restrained joints will further strengthen the joints. There has been no joint leakage in Florida due to deflection of the joints. Finally, there have been no failures of PVC pipe caused by three-feet of fill, which is the depth to which the Transmission Line pipe will be buried. To further protect the pipe, the County optimized its pumping system to avoid cyclical surges by using variable frequency drive pumps that gradually increase and decrease speed rather than just turning on or off. In addition, the pump stations are fed by two power lines that come from different directions and emergency generators, which should lessen the chances of harmful surging. Testing the Installation The anticipated pressures in the Transmission Line will likely be about 50 psi. After installation, the Line will be pressure tested at 150 psi for two hours, which is sufficient to provide the Department with reasonable assurance that the Line will hold pressure and will not leak. Also, the County contract inspectors are on the construction site daily. If problems with the installation arise later, the County has committed to promptly fix the problem, even if it means digging up the line. During the hearing, ITID asserted that the Uniform Policies and Procedure Manual standards, which the County has adopted for use by developers when constructing wastewater transmission lines, should be applied to the County as well. This standard, which requires pressure testing to 200 psi for PVC pipes larger than 24 inches, has not been adopted by the Department and is not an applicable Department permitting standard. Even if it did apply, the Transmission Line would meet this criterion because it is designed to withstand 270 psi for at least 1,000 hours. Mr. Farabee believed that the entire Transmission Line would be pressure tested after the construction was complete, which would require digging up sections of the pipe to install bulkheads. However, this assessment of the County's testing program is incorrect. Leisha Pica, Deputy Director of the Water Utilities Department, developed the schedule for the project, helped develop the phasing of the work and budget, and oversaw the technical aspects. She stated that the County has successfully tested approximately fifty percent of the line that was already installed at 150 psi for two hours and not a single section of the line failed the test. Compaction The County has stringent backfilling and compaction requirements, which are sufficient to ensure the pipe will be properly installed and that there will be adequate compaction of the fill material. The County plans and specifications provide that compaction must be to ninety-five percent of the American Association of State Highway and Transportation Officials (AASHTO) standards for non-paved surfaces and one hundred percent of AASHTO standards for paved surfaces. Even ITID's expert agreed that the compaction specifications are sufficient. Mr. Farabee contended, however, that even though the standards are stringent, the County cannot properly test the installation for compliance with the standards. Mr. Farabee believed that testing of the backfill would be done after all of the construction was complete. In that case, he did not see how the testing could be done without digging many holes to check for the density of the backfill. These assumptions, however, are incorrect. The evidence shows that a total of two hundred sixty-four compaction tests have already been done on the portion of the Transmission Line that was completed. No part of the installation failed the tests. The County has an inspector who observes the installation and pressure tests. The compaction was tested at every driveway and major roadway, as well as every five hundred feet along the route. While Lander and D'Ordine pointed out at hearing that no compaction tests have been performed on the dirt roads which run adjacent to their property and on which construction has taken place, the Department requires that, before the work is certified as complete, non-paved roads must be compacted in accordance with AASHTO standards in order to assure that there is adequate compaction of the fill material. The Sufficiency of the Application When an application for an individual transmission/ collection line permit is filed with the Department, the applicant certifies that the design of the pipeline complies with the Department's standards. However, not all of the details of the construction will be included in the permit application. The Department relies on the design engineer to certify that the materials used are appropriate. The application form is also signed and sealed by a professional engineer registered in the State of Florida. All plans submitted by the County, including the original, modifications, and final version, were certified by professional engineers registered in the State of Florida. After receiving the application, the Department requested additional information before issuing the permit, and the County provided all requested information. The original construction plans that were submitted with the application were changed in response to the Department's requests for additional information. The Permit issued by the Department indicates the Transmission Line would be constructed with ductile iron pipe, but this was a typographical error. ITID maintains that all of the technical specifications for the project must be included in the application, and because no separate engineering report was prepared by the County with the application, the County did not meet that standard. While the County did not submit an engineering report, it did submit sufficient data to provide reasonable assurance that the project will comply will all applicable rules of the Department. As a part of its application package, the County submitted construction plans, which contain the specifications required by the Department. Also, the general notes included in the construction drawings specify the use of restrained joints where appropriate, the selection of pipe material, the pressure testing of the Transmission Line, and other engineering requirements. In addition, the plans contain numerous other conditions, which are also specifications sufficient to fulfill the Department's requirements. Finally, further explanation and clarification of the technical aspects of the application was given by the County at the final hearing. At the same time, the Department engineer who oversaw the permitting of this project, testified that a detailed engineering report was not necessary. This engineer has extensive experience in permitting transmission lines for the Department and has worked on over five hundred permits for wastewater transmission and collection systems. The undersigned has accepted his testimony that in a relatively straightforward permit such as this, the application and attachments themselves can function as a sufficient engineering evaluation. This is especially true here since the County is seeking only approval of a pipeline project, which would not authorize the receipt of wastewater flow unless other wastewater facilities are permitted. Impacts on Public and Private Drinking Water Wells As part of the design of the Transmission Line, the County located public and private drinking water wells in the area of the line. County personnel walked the route of the Transmission Line and looked for private wells and researched the site plans for all of the properties along the route. No public wells were found within one-hundred feet of the Transmission Line route, but they did find seventeen private wells that are within seventy-five feet of the line. None of the Petitioners have private wells that are within seventy- five feet of the line. While Petitioners D'Ordine and Hawkins initially contended that the well on Hawkins' property was within seventy-five feet of the Transmission Line, at hearing Mr. D'Ordine admitted that he "misread the plans and referred to the wrong property." In order to protect the private drinking water wells, Florida Administrative Code Rule 62-604.400(1)(b) requires that the County provide an extra level of protection for the wells that are within seventy-five feet of the Transmission Line. The County will provide that extra level of protection by installing restrained joints that will restrain the joints between the pipe sections. The restrained joints are epoxy-coated mechanical devices that reduce the tendency for the pipes to separate under pressure. The County has used these restrained joints on its potable water and wastewater lines in other areas of the County and has never experienced problems with the devices. The restrained joints will provide reliable protection of the private wells within seventy-five feet of the Transmission Line. The Department is unaware of any instances where restrained joints have failed in South Florida. If more wells are discovered that are within seventy-five feet of the Transmission Line, then the County will excavate the Line and install restrained joints. Minimum Separation Distances The County has complied with all applicable pipe separation requirements in the installation of the Transmission Line. More specifically, it is not closer than six feet horizontally from any water main and does not intersect or cross any reclaimed water lines. See Fla. Admin. Code R. 62-555.314(1)(a). It will be at least twelve inches below any water main or culvert that it crosses. See Fla. Admin. Code R. 62-555.314(2)(a). Finally, it will be a minimum of twelve inches below any culverts that it crosses. (However, the Department has no separation requirement for culverts crossed by the Transmission Line.) h. The M-Canal Crossing The Transmission Line must cross the M-canal, which runs in an east-west direction approximately midway between 40th Street North and Northlake Boulevard. The original design called for the Transmission Line to cross above the water, but the City and the Department suggested that it be located below the canal to eliminate the chance that the pipe could leak wastewater into the canal. In response to that suggestion, the County redesigned the crossing so that a 24- inch high density polyethylene pipe in a 48-inch casing will be installed fifteen feet below the design bottom of the canal. The polyethylene is fusion-welded, which eliminates joints, and is isolated with a valve on either side of the canal. Appropriate warning signs will be installed. See Fla. Admin. Code R. 62-604.400(2)(k)2.-5. The depth of the subaqueous line and the use of the slip line, or casing, exceeds the Department's minimum standards. See Fla. Admin. Code R. 62-604.400(2)(k)1. i. Flushing Protocol Section 48.1 of the Ten State Standard recommends that wastewater transmission lines maintain a velocity of two feet per second. When the Transmission Line becomes operational, it will not have sufficient flow to flush (or clean) accumulated solids from the lines at the recommended two feet per second velocities. (Sufficient flow will not occur until other customers connect to the Transmission Line during the first one to three years of operation.) Accumulated solids produce gases and odors that could create a problem at the treatment plant and might leak out of the manhole covers. To address this potential problem, Specific Condition 9 of the Permit requires the County to flush the lines periodically. Pursuant to that Condition, the County plans to flush the Transmission Line with additional water which will raise the velocity to three or four feet per second, so that the accumulated solids will be flushed. The water will be supplied by large portable tanks that will be temporarily set up at several locations along the Line. During the purging of the Line, sewage will collect in the pump stations until the purge is finished. There is sufficient capacity in the pump stations to contain the wastewater. In addition, the County will use a cleansing tool known as a pig, which is like a foam bullet that scrapes the sides of the pipe as it is pushed through the line. This protocol will be sufficient to keep the Line clean. ITID asserts that the County's plan for flushing is inadequate, because it does not provide enough water for long enough to flush both the 20-inch and 30-inch lines. Mr. Farabee calculated that the County would need almost twice the proposed volume, or almost six million gallons, to adequately flush the lines. ITID's analysis of the flushing protocol is flawed, however, because it assumes a constant flow in all segments of the pipe, which is not practical. In order to maintain the flushing velocity of three feet per second, the County will introduce water into the Transmission Line at three separate locations, resulting in a more constant flow velocity throughout the Transmission Line. In this way, it can maintain the proper velocity as the lines transition from a 20-inch to 30-inch to 36-inch pipe. The County has flushed other lines in the past using this protocol and has had no problems. This flushing protocol would only be in effect from one to three years. The County estimates that the necessary volumes to maintain a two-feet-per-second velocity in the 20- inch line would be reached in about one year. The 30-inch line should have sufficient flows sometime in 2008. These estimates are based on the signed agreements the County has with other utilities in the area to take their flows into the Transmission Line. Because of these safeguards, the Transmission Line will not accumulate solids that will cause undesirable impacts while flow is less than two feet per second. Other Requirements The construction and operation of the Transmission Line will not result in the release or disposal of sewage or residuals without providing proper treatment. It will not violate the odor prohibition in Florida Administrative Code Rule 62-600.400(2)(a). It will not result in a cross- connection as defined in Florida Administrative Code Rule 62- 550.200. The construction or operation of the Transmission Line will not result in the introduction of stormwater into the Line, and its operation will not result in the acceptance of non-domestic wastewater that has not been properly pretreated. If constructed and permitted, the Transmission Line will be operated so as to provide uninterrupted service and will be maintained so as to function as intended. The record drawings will be available at the Department's district office and to the County operation and maintenance personnel. Finally, concerns by the individual Petitioners that the County may not restore their property to its original condition after construction is completed are beyond the scope of this proceeding. At the hearing, however, the Deputy Director of the Water Utilities Department represented that the County would cooperate with the individual property owners to assure that these concerns are fully addressed. Reasonable Assurance The County has provided the Department with reasonable assurance, based on plans, test results, installation of equipment, and other information that the construction and installation of the Transmission Line will not discharge, emit, or cause pollution in contravention of the Department's standards.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department of Environmental Protection enter a final order denying all Petitions and issuing Permit No. 0048923-017-DWC. DONE AND ENTERED this 18th day of October, 2005, in Tallahassee, Leon County, Florida. S DONALD R. ALEXANDER 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 18th day of October, 2005.
