The Issue The principal issues to be resolved in this proceeding concern whether certification should be issued to the City of Lakeland, Department of Electric Utilities (Lakeland or Lakeland Electric) to construct and operate the steam electric equipment needed to create a nominal 350-megawatt combined-cycle generating unit located at Lakeland’s McIntosh Power Plant site in Lakeland, Florida in accordance with the provisions of Section 403.502, et seq., Florida Statutes. The related issues concern whether the site for the McIntosh Unit 5 Steam Cycle Project is consistent and in compliance with the applicable land use plans and zoning ordinances of the City of Lakeland, pursuant to Section 403.508(2), Florida Statutes.
Findings Of Fact Project Operations and Impacts Project Overview The City of Lakeland, Department of Electric Utilities is a municipal utility that supplies electric service to approximately 106,000 customers, which represents approximately 200,000 residents in its service area within Polk County. Lakeland’s electric utility commenced operation in 1891, making Lakeland one of only three Florida cities with electricity at that time. Lakeland currently operates power plants at two locations in the City of Lakeland with a combined generating capacity of 785 megawatts (MW). The McIntosh Power Plant site is the larger power plant site and contains six electrical generating units. McIntosh Unit 3 is a 365-megawatt, coal-fired electrical generating unit, which was originally certified under the Florida Electrical Power Plant Siting Act in 1978. In 1998, Lakeland obtained approvals to construct a new 250-megawatt, simple-cycle combustion turbine (CT) at the McIntosh site. These approvals consisted of a modification of the site certification for McIntosh Unit 3 and a separate Prevention of Significant Deterioration (PSD) Permit, both issued by FDEP. That modification of the site certification for the new Unit 5 CT was required because the new CT was to be located within the site certified for McIntosh Unit 3. Pursuant to FDEP rules, the approval for that new unit was required to be obtained under the PPSA’s modification rules. The new McIntosh Unit 5 CT is completing construction and will be placed into service in the near future. The original permits for the Unit 5 CT anticipated that the CT would later be converted to a combined cycle configuration. The City of Lakeland considered a number of generating options before selecting the Unit 5 project to meet the City’s required 15 percent reserve margin. Siemens Westinghouse submitted a proposal to the City that Lakeland be the host site for the first 501G simple-cycle combustion turbine. The City concluded that this proposal was the best alternative available to meet the City’s needs for additional electricity. The conversion of Unit 5 to combined cycle operation will expand Lakeland’s natural gas-fired generating capacity to 76 percent of Lakeland’s total electrical generating capacity. No energy conservation measures exist that would affect the need for the plant. The 250-megawatt CT in Unit 5 is one of the most efficient generating units currently operating. In the CT, compressed air is introduced into a combustion zone and fuel, typically natural gas, is combusted within the forward portion of the CT. The resulting hot gases expand in the turbine and turn an electrical generator. For Unit 5, this electrical generator produces approximately 250 MW of electricity. The hot exhaust gases then are exhausted out the existing stack. Under the proposed Unit 5 Steam Cycle Project, the combined cycle configuration for Unit 5 involves the construction of a heat recovery steam generator (HRSG), which captures the exhaust gas from the CT and produces steam by extracting the heat from the flue gases. In the HRSG, the hot gases are used to convert water into steam in a closed system of piping. The steam is then used to turn a new steam turbine, which then turns an electrical generator. Other equipment required for the steam cycle project includes: a new, taller exhaust stack; a new cooling tower; and other plant equipment. The addition of the new HRSG steam turbine and electrical generator to McIntosh Unit 5 will produce an incremental 100 MW of electricity produced through the use of steam. The PPSA requires an increase of steam-generating capacity at the McIntosh site to undergo the full permitting proceedings of the PPSA. Therefore, Lakeland was required to submit its application for site certification to add the steam cycle to Unit 5. The McIntosh Unit 5 will be located on a 3-acre tract of land within the larger 530-acre McIntosh Power Plant site. The site is located in the eastern portion of the City of Lakeland, along the northern shore of Lake Parker. The McIntosh plant site is generally surrounded by undeveloped lands, including reclaimed and vacant phosphate lands used, in part, as a recreational and fishing area managed by the Florida Fish and Wildlife Conservation Commission (FWCC). There are no residential or commercial properties adjacent to the project site. The nearest residence to the project site is over one mile away. The site for the McIntosh Unit 5 contains no significant environmental features. No wetlands are found within the site. The Unit 5 site is an open field, containing grasses and low-quality, weedy vegetation. Further, no archaeological, or historical resources were found on the site. No sensitive local, regional, state or federal parks, wilderness areas, forests, or areas of critical concern are located within 5 miles of the site. No threatened, endangered, or protected plant or animal species are known to be present at or near the project site. The combined cycle unit will be fired primarily with natural gas, with fuel oil as a backup fuel. Natural gas is supplied by a 10-mile long pipeline owned by the City of Lakeland, which connects to the Florida Gas Transmission gas pipeline system. No alterations to those pipelines are required for the project. Fuel oil for the unit will be delivered by truck and stored in an existing on-site fuel storage tank. The capture and utilization of waste heat from the CT exhaust in the new heat recovery steam generator will significantly increase the efficiency of the electrical generation process for Unit 5. Use of the waste heat will not require any increase in fuel use and will not result in any increase in air emissions from the power plant. When considered on the basis of electrical output, the amount of emissions per megawatt hour of electricity will actually decrease by approximately 30 percent. All of the air emissions from Unit 5 are associated with the operation of the combustion turbine; and the addition of the heat recovery steam generator does not result in any increase in those emissions. Water Use, Wastewaters and Other Impacts The addition of the HRSG requires the use of a cooling tower to remove the heat from the circulating steam. Once the steam exits the steam turbine, it passes through a condenser in which the heat from the steam is transferred to circulating cooling water. The steam is condensed back to water and then recycled into the HRSG in a closed loop system. The heated cooling water is then routed to the cooling tower where forced air evaporation removes the heat. Periodically, a portion of the cooling water in the cooling tower system is removed to prevent the buildup of solids and other constituents which could impair the performance of the cooling tower. Replacement of this "blowdown water" and of the water lost through evaporation will be achieved through the use of treated domestic waste water (reuse water) supplied from the City of Lakeland’s wastewater treatment plants, including a plant adjacent to the McIntosh plant site. The cooling tower will require approximately 3.24 million gallons per day (mgd) to replace water lost in the cooling process. FDEP adopted Rule 62-610, Florida Administrative Code, to encourage the beneficial use of reuse water from domestic wastewater systems as a means of water conservation. The rule sets out certain treatment and design criteria that must be met when reuse water is used, including water used in cooling towers. The Lakeland Unit 5 cooling tower meets these rule requirements because the cooling tower is located more than 300 feet from the nearest property boundary, and the reuse water receives secondary treatment by the City of Lakeland. In the event reuse water is not available because of supply or quality problems, groundwater from on-site wells will be used as a backup source of cooling water makeup until reuse water is available again. The needed quantity of groundwater, up to 3.24 mgd, has been approved by the Southwest Florida Water Management District (SWFWMD) under the existing consumptive use permit issued by SWFWMD for the McIntosh plant site. That quantity of water has been shown to not have adverse effects on area users of groundwater. In addition to cooling water, the plant requires high quality service water to replace water lost in the operation of the HRSG and for other plant processes, including control of nitrogen oxide (NOx) emissions during oil firing. This water is obtained from groundwater wells and is treated in on-site water treatment facilities. Conversion of Unit 5 to combined cycle operation will reduce the use of groundwater by approximately 250,000 gallons per day during normal operations due to increased recycling of water within the unit. Wastewater from the plant is generated from the cooling tower, as a result of the periodic blowdown of the water in the cooling tower. This blowdown water is routed to an on-site collection sump and then routed to the City of Lakeland wastewater treatment system. Industrial-related wastewaters from plant operations, including wastewaters from plant water treatment, are also collected and routed to the City of Lakeland Wastewater Treatment system. There is no direct discharge of wastewater from McIntosh Unit 5 to adjacent surface waters. The project will not have any effect on area surface waters. There will be no increase in the need for potable water or domestic wastewater treatment. The addition of the new HRSG and related equipment for the steam-cycle project will not require an increase in permanent employment at the project site. The on-site stormwater management system is already sized to accommodate the addition of the steam-cycle equipment Minor amounts of solid and hazardous wastes will be generated by the project, mainly during construction. Any hazardous wastes will consist mainly of small amounts of spent solvent. Systems are already in place to dispose of these wastes in an approved manner. Electricity generated at the site is distributed from an on-site switchyard into the City of Lakeland transmission system. This system is interconnected to other Florida utilities. The addition of the Unit 5 Steam Cycle Project will not require any changes to the existing electrical transmission system. The McIntosh Unit 5 will be compatible with the other surrounding land uses in the vicinity of the project site. The project represents a logical expansion of the existing power plant site. It is well buffered from residential land uses. Noise from Plant construction and operation will not adversely impact nearby residents. Existing noise levels in the residential areas near the plant are low, even with the existing generating units at the McIntosh site in operation. Noise levels during construction and operation will comply with the applicable local noise ordinance, as well as the existing noise limitations in the McIntosh site certification conditions. Construction will generally occur during daylight hours, and construction equipment has to comply with noise limits set by the manufacturers. Addition of the new HRSG and other equipment will act to buffer noise from the existing CT. Operation of the plant will not be noticeable at the nearest residence, which is almost one mile away. Air Quality Analyses Required Polk County has not been designated by the U.S. Environmental Protection Agency (EPA) or FDEP as a nonattainment area for any federal or Florida ambient air quality standards. Federal and state Prevention of Significant Deterioration (PSD) program requirements applied to the simple cycle portion of McIntosh Unit 5. Because it was a major source of air pollution Because there were no significant net emission increases of any regulated air pollutants due to the conversion of McIntosh Unit 5 to combined-cycle operation, the PSD requirements did not apply to the addition of the steam cycle to Unit 5. Under the PPSA, air quality impacts associated with the new, taller stack and the new cooling tower associated with the combined-cycle operation of Unit 5 were required to be evaluated. However, no changes to the PSD permit itself were necessary to address the addition of the steam cycle to Unit 5, although some updated information reflecting the increased stack height and the addition of the cooling tower was provided to FDEP. Emission Impacts Under FDEP’s rules, air emissions from McIntosh Unit 5 must not cause or contribute to a violation of federal and state ambient air quality standards or PSD increments. Polk County is classified as a Class II area for PSD purposes. The nearest Class I area to the McIntosh Power Plant is the Chassahowitska National Wilderness Area, located approximately 90 kilometers (60 miles) from the Plant. The ambient air quality analysis demonstrated that McIntosh Unit 5's emissions, including operations in combined- cycle mode with the taller stack and cooling tower, will not have a significant impact on air quality near the McIntosh Plant or in the Chassahowitska Class I area. The maximum predicted impacts from Unit 5 in combined-cycle mode are below the EPA and FDEP significant impact levels. Unit 5's emissions will not cause or contribute to an exceedance of any state or federal ambient air quality standards. The 250-foot stack height for McIntosh Unit 5 in combined-cycle mode represents "good engineering practice" (GEP), calculated in accordance with FDEP and EPA rules. McIntosh Unit 5's air emissions are not expected to cause any adverse impacts on vegetation, soils, or visibility in the McIntosh Power Plant site vicinity or in the Chassahowitska National Wilderness Area, the nearest PSD Class I area. Air emission impacts of McIntosh Unit 5 on water bodies in the vicinity of the McIntosh Power Plant will be insignificant. No adverse air emission impacts are expected to result off-site during the construction of the steam cycle portion of Unit 5, and appropriate control methods will be used to minimize emissions during construction activities. The cooling tower plume could cause temporary and localized ground-level fog on occasion. The majority of these relatively rare instances will be of short duration and occur when fog is already naturally occurring. BACT and Emission Rates A Best Available Control Technology (BACT) analysis, required under the PSD program, is intended to ensure that the air emissions control systems selected for a new project reflect the latest in control technologies used in a particular industry based on a cost-benefit approach, taking into account technical, economic, energy, and environmental considerations. A BACT determination was made for emissions from Unit 5, including operation of the unit in combined-cycle mode, as part of the PSD permit previously issued for the simple-cycle operation on the Unit 5 CT. High efficiency drift eliminators are being installed on the McIntosh Unit 5 cooling tower to minimize particulate matter emissions from solids contained in the water released from the cooling tower. While the NOx emission limits in the PSD permit will not change due to the addition of the steam cycle portion of Unit 5, the projected emission rate in terms of pound-per-megawatt- hour (lb/mwhr) are actually lower when in combined-cycle mode because of the increase in electricity generated with no additional emissions being created. Compliance McIntosh Unit 5 in the combined-cycle mode will comply with all applicable federal and state air quality standards, including the conditions contained in the PSD Permit for Unit 5 and in FDEP is proposed conditions of certification. Consistency with Local Land Use Plan and Zoning Ordinances The Lakeland McIntosh Unit 5 project site, as well as the entire McIntosh Plant Site, is located in a future land use map designation of "Industrial" on the City of Lakeland’s Future Land Use Map. That map is part of the locally-adopted Comprehensive Plan for the City of Lakeland. Electrical power plants are a permitted use in that Industrial land use category. McIntosh Unit 5 meets the locational criteria in the future land use element, in that it is well buffered and served by adequate, available public facilities. The McIntosh Unit 5 Steam Cycle project site is zoned I-3, or Heavy Industrial under the City of Lakeland’s zoning regulations. That zoning district allows electrical power plants, subject to further review under the City’s zoning requirements. This additional zoning review consists of a conditional use permit, which is intended to provide an additional layer of review for these types of facilities. On September 7, 1999, the City of Lakeland City Council issued a conditional use permit for the entire McIntosh plant site, which includes the site for McIntosh Unit 5. McIntosh Unit 5, when converted to combined-cycle operation, will be consistent and in compliance with the City of Lakeland’s land use plans and zoning designations for the project. Further, the project will be consistent with the conditional use permit issued for the project site. McIntosh Unit 5 will also be consistent with the other provisions of the City of Lakeland Comprehensive Plan. The project meets the local Plan’s concurrency requirements, promotes the use of treated wastewater for cooling of power plants, and meets the provisions for protection of local air quality. Agency Positions and Stipulations The FDEP, the Florida Department of Community Affairs, the Southwest Florida Water Management District, the Florida Department of Transportation and the Fish and Wildlife Conservation Commission each prepared written reports on the project, and all recommended approval of the City of Lakeland McIntosh Unit 5 Steam Cycle Project. (Amended FDEP Exhibit 3). FDEP has proposed Conditions of Certification for the project, which Lakeland agrees to accept and comply with in plant construction and operation. The Department of Community Affairs determined that the project, if certified, would be consistent with the State Comprehensive Plan. The Central Florida Regional Planning Council (CFRPC) did not submit a report to FDEP as part of its review of the project. However, CFRPC entered into a prehearing stipulation with the City of Lakeland in which it stated that the project would be consistent with the CFRPC’s Strategic Regional Policy Plan. DCA entered a similar stipulation indicating its agreement that the project was consistent with the State Comprehensive Plan. The Department of Transportation entered into a prehearing stipulations indicating it did not object to certification of the project. No state, regional, or local agency has recommended denial of certification of the project.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that The City of Lakeland, Department of Electric Utilities be granted certification, pursuant to Chapter 403, Part II, Florida Statutes, for the location and operation of the McIntosh Unit 5 Steam Cycle Project, representing an expansion of the electrical generating capacity of the existing McIntosh Unit 5, as proposed in the Site Certification Application and the evidence presented at hearing, and subject to the Conditions of Certification contained in Amended FDEP Exhibit 3, and subject to the Conditions of Certification attached hereto; The Siting Board find that the site of the McIntosh Unit 5 Steam Cycle Project, as described in the Site Certification Application and the evidence presented at the hearing, is consistent and in compliance with the existing land use plans and zoning ordinances of the City of Lakeland as they apply to the site, pursuant to Section 403.508(2), Florida Statutes. DONE and ENTERED this 2nd day of March, 2000, in Tallahassee, Leon County, Florida. J. LAWRENCE JOHNSTON Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 2nd day of March, 2000. COPIES FURNISHED: Mark Carpanini, Esquire Polk County Attorney’s Office Drawer AT01 Post Office Box 9005 Bartow, Florida 33831-9005 Douglas S. Roberts, Esquire Hopping Green Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314 Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Sheauching Yu, Esquire Department of Transportation Haydon Burns Building 605 Suwannee Street, Mail Station 58 Tallahassee, Florida 32399-0450 James V. Antista, Esquire Fish and Wildlife Conservation Commission 620 South Meridian Street Tallahassee, Florida 32399-1600 Andrew S. Grayson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Robert V. Elias, Esquire Florida Public Service Commission Gerald Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Frank Anderson, Esquire Southwest Florida Water Management District 2379 Broad Street Brooksville, Florida 34609-6899 Thomas B. Tart, Esquire Orlando Utilities Commission 500 South Orange Street Orlando, Florida 32801 Andrew R. Reilly, Esquire East Lake Parker Residents Post Office Box 2039 Haines City, Florida 33845-2039 Norman White, Esquire Central Florida Regional Planning Council 555 East Church Street Bartow, Florida 33830 Kathy Carter, Agency Clerk Office of the General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000 Teri Donaldson, General Counsel Office of the General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000
Findings Of Fact On December 17, 1973, Henry Botwinick acknowledged having received from Mrs. Kane $4,000 on account for addition on the house at Northeast 11th Place, North Miami, Florida (Exhibit 8). Exhibit 3 is an application for building permit and building permit issued by the City of North Miami for the construction at the Kane residence. Attached thereto are the plans for the construction. Exhibits 4, 5, and 6 show pollution control authority for the construction, the plumbing permit, and electrical inspection permit. Subsequent thereto construction was commenced on this project. Mrs. Kane was advised that the project would be completed in 4 to 6 weeks, however, the contract was never completed. In April Mr. Botwinick came to Mrs. Kane and asked for an additional $500 to get the electrical work started and the cement foundation poured. Approximately two weeks later he again obtained from Mrs. Kane $1500 with which to pay the roofer. He advised Mrs. Kane that he had used the money, previously advanced by her for materials, on another job. Exhibit 8 indicates that payments of $500 were made on April 1, another $500 was made on April 12, and $1,500 was made on April 25, 1974. Subsequent inaction by the contractor on this project resulted in a letter (Exhibit 7) dated May 6, 1975 from Bertil Lindblad, a building official for the City of North Miami, in which he advised Mr. Botwinick that the building permit issued to him had expired for lack of progress or abandonment of the work for a period exceeding ninety days. Mrs. Kane last saw work performed by Botwinick on February 25, 1975. She made numerous telephone calls, but was unable to contact him. Subsequent to the payments made to Botwinick, Mrs. Kane has had to pay nearly $3,000 to another contractor to perform work and the project is still not completed. As of the date of hearing she requires approximately $3,000 additional work to complete this project.
Recommendation RECOMMENDED that Building Contractor's License #CBC001839 issued to Henry Botwinick, 11321 Rexmere Boulevard, Ft. Lauderdale, Florida, be revoked. DONE AND ENTERED this 18th day of March 1976 in Tallahassee, Florida. K. N. AYERS Hearing Officer Division of Administrative Hearings Room 530 Carlton Building Tallahassee, Florida
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 The Respondent is a certified building contractor, having been issued license number CB C011621 as an individual contractor. The Petitioner is an agency of the State of Florida, having responsibility and authority to license building contractors and to regulate their licensure status and their standards of practice pursuant to Chapter 489, Florida Statutes. Sometime in December, 1979, the Respondent, doing business as Economy Steel Buildings, Inc., entered into a contract with Digital Machine and Tool Company to construct a steel building for that firm. The Respondent subsequently commenced the construction on land owned by Digital Machine and Tool Company and obtained a permit from Seminole County on December 6, 1979, authorizing the installation of a septic tank. On the face of the permit appeared language containing the specification that the "stub-out" or pipe exiting the septic tank be installed 12 inches above the original grade level. The Respondent observed that language on the face of the building permit and knew and understood its import, as his own testimony reveals. The Respondent subsequently subcontracted the installation of the septic tank to a company known as Al's Septic Tanks, which installed the tank and drain field during the early part of February, 1980. On February 10, 1980, an inspector for the Seminole County Health Department, Don Gross, inspected the septic tank installation and informed the subcontractor and the Respondent that it was not in conformance with Section 10D-6.25(2)(e), Florida Administrative Code, in that the subcontractor had not followed the instructions on the face of the building permit (12 inches above grade level), which were designed to satisfy that Administrative Code section. Sometime between February 10, 1980, and the end of April, 1980, the Respondent received a "Notice of Violation" from the Seminole County Health Department regarding the alleged improper installation of the septic tank. The Respondent admitted that sometime soon after installation of the septic tank he became aware that it did not pass the Seminole County Health Department inspection. The Respondent maintained that he made three attempts to contact the Health Department regarding the Notice of Violation during the month of April, 1980, but he introduced no competent, substantial evidence to show what efforts, if any, he made to correct the installation of the septic tank. There were ongoing disputes between Digital Machine and Tool Company, its representative, Galon Lyell, and the Respondent during this period, and on May 21, 1980, the Respondent was told to stay off the premises and perform no further construction on the site. There arose at about this time a civil dispute between the Respondent and Digital Machine and Tool Company which is outside the scope of this proceeding. In any event, the Respondent did not correct the installation of the septic tank and there is no question that the septic tank was not installed with the "stub-out" pipe 12 inches above the original grade level. Digital Machine and Tool Company later obtained a corrected installation of the septic tank so that it would be "stubbed-out 12 inches above original grade" from a different subcontractor, at its own additional expense, in the amount of $855. From the period of December, 1979, through the completion of the building for Digital Machine and Tool Company, the Respondent was performing contracting under the name of Economy Steel Buildings, Inc. The Respondent admitted that he was fully aware, as of November 19, 1979, that he could not properly perform contracting work under the name, Economy Steel Buildings, Inc., without properly qualifying that company. After a Notice of Violation (Respondent's Exhibit 6) was issued by the Construction Industry Licensing Board through Investigator Hunter, the Respondent was aware that contracting under an unqualified company name was improper. After that Notice of Violation, the Respondent made some attempts to separate his personal contracting business from that of his material supply company, Economy Steel Buildings, Inc. The Respondent, however, accepted payment for contracting and materials from his client, Digital Machine and Tool Company, for the subject project in the name of Economy Steel Buildings, Inc. The Respondent also paid Myron Roseland, a subcontractor, from Economy Steel Buildings, Inc.'s account for work attributable to the Digital Machine and Tool project. Finally, Petitioner's Exhibit 5 establishes that the Respondent attempted to discharge personal liability as a contractor, which attached to him through the Digital Machine and Tool Company project and other projects, by declaring bankruptcy pursuant to Chapter 11 of the Federal Bankruptcy Act as Economy Steel Buildings, Inc., since in that petition he listed numerous subcontractors, including Myron Roseland, who performed work on the Digital Machine and Tool Company job, as creditors of that corporation to be discharged. In summary, during the period of December, 1979, through the completion of the building for Digital Machine and Tool Company, the Respondent was performing contracting work as Economy Steel Buildings, Inc. During that time period, Economy Steel Buildings, Inc., was not properly qualified or registered with the Construction Industry Licensing Board by the Respondent, who was the owner and sole stockholder of Economy Steel Buildings, Inc.
Recommendation Having considered the foregoing Findings of Fact and Conclusions of Law, the evidence in the record, the candor and demeanor of the witnesses, and the pleadings and arguments of the parties, it is, therefore, RECOMMENDED: That a Final Order be entered by the Petitioner finding the Respondent guilty of the violations alleged in Counts III and IV of the Amended Administrative Complaint and imposing an administrative fine of $1,000. The administrative fine should be suspended in part, provided the Respondent provides proof within sixty (60) days from the date thereof that he has made restitution to Digital Machine and Tool Company for the $855 it had to expend to obtain correction of the improper septic tank installation, as well as restitution of monies owed to Mr. Myron Roseland attributable to the Digital Machine and Tool Company project, in which event the Respondent's fine should be reduced to $250. DONE AND ENTERED this 10th day of February, 1983, at Tallahassee, Florida. P. MICHAEL RUFF, 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 10th day of February, 1983. COPIES FURNISHED: John O. Williams, Esquire 547 North Monroe Street Suite 204 Tallahassee, Florida 32301 James R. Lavigne, Esquire 1971 Lee Road Winter Park, Florida 32789 James Linnan, Executive Director Construction Industry Licensing Board Department of Professional Regulation Post Office Box 2 Jacksonville, Florida 32202 Fred Roche, Secretary Department of Professional Regulation 130 North Monroe Street Tallahassee, Florida 32301
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 issue to be resolved in this proceeding concerns whether the Governor and Cabinet, sitting as the Siting Board, should issue certification to Gulf Power Company (Gulf or Gulf Power) to construct and operate a 574 megawatts (MW) combined cycle electrical generating unit to be located at Gulf's existing Lansing Smith Plant in Bay County, Florida, in accordance with the provisions of Section 403.501, et seq., Florida Statutes.
Findings Of Fact Gulf Power is an investor-owned electric utility that supplies electric service in northwest Florida. Gulf currently serves approximately 350,000 customers in its service area, which extends westward from the Apalachicola River to the western border of Florida. Gulf Power has been supplying electricity within this area since 1926. Gulf is a subsidiary of the Southern Company. Gulf Power currently operates power plants at three locations in the Florida Panhandle, with a combined generating capacity of 2,284 MW. Gulf Power's Lansing Smith power plant (Smith Plant) is located in the central portion of Bay County, Florida, approximately 2.5 miles west of the unincorporated community of Southport, Florida, and 2.5 miles northwest of the City of Lynn Haven, Florida. The City of Panama City lies due south, across the open waters of North Bay. The Smith Plant is in the unincorporated area of the County. Access is via County Road 2300 which connects to State Road 77. Within the approximate 1,384 acres, which comprise, the Smith Plant, are two existing coal-fired electrical generating units along with their supporting facilities, including a coal unloading and storage facility, wastewater treatment and disposal facilities, intake and discharge canals which handle cooling water, and electrical substations and transmission lines. Smith Unit 1 has a generating capacity of 162 MW and Smith Unit 2 has 192 MW of generating capacity. The two existing units have been in operation since 1965 and 1967 respectively. An existing 31.6 MW oil-fired simple cycle combustion turbine is also located at Smith Plant. The balance of Smith Plant is largely undeveloped, and is comprised mainly of planted pines, forested areas and wetlands. Immediately adjacent off-site lands are used for silviculture (planted pines) or are otherwise undeveloped. The nearest residence is more than two miles away, located to the northeast of Smith Plant. Project Description The proposed Smith Unit 3 consists of a natural gas- fired combined cycle plant capable of generating up to 574 MW of electricity. The new unit will more than double the generating capacity at Smith Plant. Smith Unit 3 will be located upon a 50.1-acre site (Project site) within the existing boundaries of Smith Plant. Smith Unit 3 will utilize state-of-the-art combined cycle design concepts and equipment to achieve a high level of efficiency in electrical power production. The Project will employ two General Electric combustion turbine units which have a proven operating record around the world. Each combustion turbine will generate approximately 170 MW of electricity. The hot exhaust gases from the two combustion turbines will be captured in two heat recovery steam generators (HRSGs) which will produce additional steam-generated electricity of 200 MW. Hot exhaust gases from the combustion turbine/HRSGs will then be vented to the atmosphere by the main stack. In addition, the HRSGs will contain duct burners which will fire additional fuel in the boilers, adding additional generating capacity to the HRSG portion of the Project. Smith Unit 3 will also employ power augmentation in which a portion of the steam in the HRSGs is routed back to the combustion turbine to increase the mass flow through the combustion turbine, increasing its ability to generate electricity. After the energy is removed from the steam in the steam turbine, the steam is condensed back into water in the condenser. Cooling for the Project will feature a creative and environmentally sound combination, utilizing the existing cooling water discharge from Smith Units 1 and 2 within a new cooling tower for Smith Unit 3. This means the Project will actually use hot water from the existing cooling system for Units 1 and 2 and then discharge cooler water from Unit 3 back into the existing discharge canal. Smith Unit 3 will use the existing Smith Plant access road, also the existing electrical switch yard will provide the interconnection for Smith Unit 3, and electrical power from the Project will be transmitted via the existing transmission lines to existing off-site electrical substations. Three of these existing electrical transmission lines, which run south and east into the Panama City area, will be reconductored. Reconductoring involves replacement of the existing conductors or wires with higher capacity conductors. This reconductoring is necessary to maintain the reliability of the Gulf Power transmission system. The reconductoring will involve removal of the existing wires, installation of new wires, and possible repair and maintenance of the existing structures. However, no new electrical transmission structures will be required as part of the reconductoring. No other expansions or other alterations to the Gulf Power transmission system are required as part of this project. A new 28 mile gas pipeline will be constructed to provide natural gas fuel for Smith Unit 3. This gas pipeline lateral will connect to an existing Florida Gas Transmission pipeline running through Washington County. The new gas lateral to serve the Project will be permitted, constructed, owned and operated solely by Florida Gas Transmission Company. The new lateral will interconnect with the existing gas pipeline and then follow a southerly route paralleling State Road 77 and an existing Gulf Power transmission right-of-way before entering the Smith Plant. A new gas metering station will be constructed within the Project site. Existing groundwater wells at the Smith Plant site will supply the groundwater needs for Smith Unit 3, as well as continue to supply the existing units. New facilities to be constructed within the approximate 50-acre Project site will include the two combustion turbines, the two HRSGs, steam turbines, three electrical generators, a cooling tower, an administration building, and other ancillary facilities. A new electrical switchyard will also be built within the Project site, which will then be interconnected to the existing main electrical switchyard at the Smith Plant. Need for Smith Unit 3 The Florida Public Service Commission (Commission) issued an affirmative need determination for Smith Unit 3 on August 2, 1999. The Commission concluded that Smith Unit 3 was necessary to ensure the future reliability and integrity of Gulf Power’s electrical system. The Commission found that there existed a generation/load imbalance in the Panama City area due to growth and electrical demand on Gulf Power’s existing system. In finding that no cost-effective energy conservation measures existed that could offset the need for electricity from the Gulf Power Smith Unit 3, the Commission concluded that Smith Unit 3 is necessary to provide adequate electricity at a reasonable cost to Gulf Power’s customers, as contemplated under Section 403.519, Florida Statutes. The Commission, therefore, found that the Project is the "most cost effective alternative available to Gulf to meet its needs for adequate electricity at a reasonable price." Gulf Power needs to add new generating capacity by the year 2002 to maintain an appropriate level of generating reserves on its system. Gulf Power has been able to obtain short-term purchases of electricity that meet its capacity needs until 2002. In evaluating its need for additional power, Gulf Power evaluated both a self-build option and conducted a request for proposal (RFP) process to consider outside offers to supply electricity. In the RFP process, Gulf Power evaluated nine different offers from outside interests, which were compared to the Gulf Power Smith Unit 3 option. After evaluating all of the options and their associated costs, Gulf Power concluded that Smith Unit 3 was clearly the most cost-effective choice. Project Schedule and Construction Construction of Smith Unit 3 is scheduled to begin in August 2000, or as soon as the final approvals are obtained. In addition to the site certification, Gulf Power is required to obtain a Prevention of Significant Deterioration (PSD) permit, a modified National Pollutant Discharge Elimination (NPDES) Permit issued by FDEP, and a dredge and fill permit from the U.S. Army Corps of Engineers. The new unit is projected to be in service in June 2002. Construction will require approximately 250 employees, with a peak of 325 employees. Construction activities will involve clearing of a portion of the Project site, removal of muck and placement of backfill, setting of pilings and foundations, followed by assembly of equipment. Installation of boilers and metal buildings will then follow, with the gas turbines and steam turbines being put into place last. These construction activities will require approximately 32.7 acres of the approximate 50-acre Project site. This includes the power block, construction laydown area, ancillary facilities, and stormwater ponds. The remainder of the Project site will remain principally as planted pine. During construction, heavy equipment will be delivered by barge, while small and medium sized items will be delivered by truck over County Road 2300. Road wetting and project maintenance will be used to control dust during construction. The site is relatively flat and is not expected to create any significant runoff during Project construction. Erosion during construction will be managed with an erosion control plan. This will include planting of exposed areas, collection of runoff and use of detention ponds to collect sediments in runoff. Project construction will have little impact on open waters. The only construction activity in open waters will be the placement of the cooling tower intake and discharge pipes within the existing Smith Plant cooling water discharge housing. This will cause minor turbidity during construction with approved construction techniques taken to minimize these impacts with no long term effect. Surface Water Management System The existing Project site is currently undeveloped although the upland areas have been modified by silviculture practices. The site currently drains to existing natural wetland systems. During construction, a portion of the Project site will be filled and graded to provide a finished surface for various Project components. Stormwater basins will also be installed during construction and grading will provide drainage for building and working areas through gravity flow. Runoff will be conveyed to two on-site wet detention stormwater ponds to be located within the east and west portions of the Project site. These stormwater ponds will ultimately discharge to adjacent wetland systems, following natural drainage patterns. The stormwater management system, including the stormwater ponds, will be constructed to comply with the requirements of local, state and federal regulations. Project Water Use The major water uses during operation of Smith Unit 3 will involve cooling tower blowdown and cooling tower evaporation, representing approximately 7.4 million gallons per day (mgd). The cooling water system has the greatest water need of all of the systems for the Project. Other water uses will involve blowdown from the HRSGs to maintain water quality in that system, and water losses due to gas turbine evaporative cooling and wash water. The Smith Unit 3 cooling system will utilize a closed- loop cooling circuit. This circulates cooled water from the mechanical draft cooling tower to the Unit 3 heat exchangers. Heated water resulting from the steam cycle of the plant is returned to the cooling tower where it is cooled by an evaporative cooling process. During this process, a certain amount of water is lost through evaporation and drift. In addition, it is necessary to "blow down" or remove a portion of the water from the cooling tower periodically to control suspended and dissolved solids in the cooling water. Without this blowdown, sedimentation and deposits in the tower will reduce the heat transfer there and damage the cooling equipment. The water loss in the cooling tower must be replaced with water from an outside source. The source of cooling water makeup for the Smith Unit 3 cooling tower will be from the existing thermal discharge flow from Smith Plant. The existing Units 1 and 2 use a once-through cooling system in which water withdrawn from North Bay passes directly through a condenser and discharges into the existing discharge canal. The makeup water from Smith Unit 3 will be taken from this hot water exiting Smith Plant Units 1 and 2. The cooling tower blowdown from Smith Unit 3 will be discharged back into the discharge canal from the cool water side of its cooling tower. As a result, the Project will actually act to reduce the amount of heat currently discharged from Smith Plant into the cooling water discharge canal and then into West Bay. The calculated quantity of water needed for cooling tower makeup is 7.4 mgd. This represents approximately 2.5 percent of the current daily water flow through Smith Plant Units 1 and 2. On a daily basis, approximately 3.7 mgd will be discharged back into the cooling water discharge canal as blowdown from the Unit 3 cooling tower. The other 3.7 mgd will be lost through evaporation in the cooling tower. Smith Unit 3 process water needs include water used to cool and wash the gas turbines and other facilities, to make up HRSG blowdown, and to satisfy other water uses. These process water needs will be supplied from groundwater taken from the existing Smith Plant well system. The raw water will be treated in both a filtered water production system and a demineralized water system. This water will then be used for the various processes identified. During hot months of the year, evaporative coolers will be provided for the combustion turbines, providing denser intake air for combustion and improving the electrical output of the combustion turbines. In addition, the gas turbines must be washed periodically, both during plant operation and when the unit is offline. During operation, wash water is lost through evaporation in the combustion turbine exhaust. When Smith Unit 3 is offline, wastewater from this process is collected in an on- site tank and trucked off-site for appropriate disposal. During the power augmentation mode of operation, steam is introduced into the combustion turbine, again to increase mass flow through the combustion turbine. This steam is produced in the HRSG, using high quality demineralized water. These water treatment and water uses in Smith Unit 3 will generate various process wastewaters. Wastewaters resulting from process water treatment will be routed to an existing Smith Plant on-site collection sump. HRSG blowdown will also be routed to this on-site sump. The process wastewaters then will be routed to an existing Smith Plant on-site ash pond, which has adequate, permitted capacity to accommodate these additional wastewater flows. There will be no direct discharge of these Project-related process waters to area surface waters of the State. Impacts to Groundwater In September 1998, a site investigation was undertaken to sample and characterize the subsurface system at Smith Plant. The groundwater regime and its subsurface system underlying Smith Plant consists of a surficial aquifer system, overlying an intermediate aquifer system that in turn overlays the Floridan aquifer which is found throughout this area. The existing Project site lies at an elevation of approximately 7 to 8 feet above mean sea level. Subsurface sediments in the area are primarily marine and estuarine and represent ancient coastal environments or marine terraces. After these marine terraces were deposited, they were mixed with underlying sediments, consisting of a permeable sand, clay, silt and shell mixture. The underlying intermediate aquifer system consists of sandy clay and is approximately 80 feet thick. The Floridan aquifer is found at a depth of approximately 100 feet below land surface, typically consists of limestone with macrofossils, and is approximately 300 feet thick in the area of the Project site. Impacts to groundwater from the Project would occur principally from the withdrawal of groundwater for Smith Unit 3 use and from dewatering activities, if necessary, during construction. The existing Smith Plant is presently served by four groundwater wells that are permitted under a Consumptive Use Permit issued in September 1999 by the Northwest Florida Water Management District. That permit authorizes a maximum groundwater use of 1.2 million gallons per day (mgd) for the entire Smith Plant, which would include Units 1 and 2, as well as the proposed Smith Unit 3. These wells are sufficient to satisfy the groundwater withdrawal needs for Smith Unit 3, which amounts to an average of 209,000 gallons per day (gpd). By comparison, the existing Units 1 and 2 average a combined groundwater withdrawal rate of 647,000 gpd. During the recent renewal of the Consumptive Use Permit, Gulf Power conducted groundwater modeling to determine if any significant impacts to water resources or water users would occur as a result of the projected water use increase due to Smith Unit 3 operations. That modeling indicated that no adverse or irreversible impacts will occur to the Floridan aquifer system, or to its users in the vicinity of the Smith Plant site. The use of groundwater for process water is a reasonable and beneficial use of that resource. In addition, Gulf Power evaluated other potential sources of water. The factors of reliability and distance to the source were the primary factors considered by Gulf Power in the selection of groundwater use for Smith Unit 3. The Northwest Florida Water Management District agreed with this conclusion and issued the renewed Consumptive Use Permit for Smith Plant, including the proposed addition of Smith Unit 3. In fact, groundwater use for Smith Unit 3 represents less than 3 percent of the total 7.6 mgd Project water need. Project construction may require dewatering during construction activities, including placement of pilings at the Project site. If dewatering occurs, any impact will be very localized, and limited to a small area immediately adjacent to the dewatering activities. Dewatering effluent would be routed to the drainage system and then to the new detention basins. This effluent will then be allowed to infiltrate back into the surficial aquifer, and thereby offset the dewatering volumes. Wastewaters from Smith Unit 3 will be routed to the existing ash pond at Smith Plant. That ash pond operates under an existing NPDES permit and discharges infrequently, during extreme rainfall events, to a ditch which connects to the existing discharge canal only during extreme rainfall events. Any such pond discharge is sampled and reported to the Department. Any wastewaters that do not evaporate instead percolate into the underlying groundwater. The pond is subject to an FDEP-approved groundwater monitoring program, which has been in operation since the early 1980s. Seven compliance monitor wells are periodically sampled and analyzed for 21 separate parameters to ensure compliance with applicable state groundwater quality standards. This ash pond operates in compliance with the approved requirements of the groundwater monitoring plan and monitoring data indicate that Smith Plant has been and continues to be in compliance with all applicable Florida groundwater standards and criteria. Impacts to Surface Water Gulf’s Smith Plant is located on the northern end of a peninsula between the North and West Bays of St. Andrews Bay in Panama City, Florida. Thus, surface water runoff at this location generally flows from the northeast to the southwest and discharges to the existing cooling water canal. Four adjacent existing Smith Plant Units 1 and 2 intake water from Alligator Bayou, which is connected to North Bay, and the discharge canal Andrews Bay. Alligator Bayou is a Class III marine water, while waterbodies. The Class III designation is primarily to protect recreation and maintain a healthy propagation in population of waterbody standards provide additional protections for shellfish propagation and harvesting Operation of the cooling system for the existing generating units at Smith Plant may have impacts on area surface entrainment and impingement from cooling water intake structures and thermal stresses from cooling water Entrainment is an impact to organisms that are entrapped in the cooling water and drawn through plant water crabs, which may be trapped on water intake screens. Thermal impacts are heat-related stresses that result if excess Warren Bayou. These potential impacts have been studied extensively at the Smith Plant for the past 25 years. Studies in 1977 concluded that impacts of the cooling water intake system were acceptable and that Smith Plant was using the best available technology for that system. The thermal plume in West Bay from the existing units was also studied over the past 25 years. These studies delineated the extent of the thermal plume from Smith Plant in the open waters, and included specific sampling of biological communities to determine any adverse thermal plume impact. These studies were used to set the present thermal discharge limits for Smith Plant, and further demonstrated there would be no unacceptable impacts from its operation. Recent ongoing studies, including findings and conclusions contained in a 1998 report, confirmed that there are minimal thermal impacts in West Bay from the existing Smith Plant’s cooling water discharge. As discussed above, cooling water for Smith Unit 3 will be taken from the warm water discharge from the existing two Smith Plant units; cooling water blowdown will be discharged from the cool side of the new cooling tower. Thus, the temperature of the Smith Unit 3 discharge will actually be less than the temperature of the water withdrawn from the cooling canal. Further, since half the water withdrawn for Smith Unit 3 will be lost through evaporation in the cooling tower, approximately one- half of the heat that is removed from the existing canal will not be returned to the canal. Thus, there will be a slight reduction in the total heat contribution to area surface waters from Smith Plant as it presently exists. This will reduce the overall heat rejection from the Smith Plant by 1.4 percent. The existing thermal plume will therefore be reduced slightly and the water temperature in the discharge canal will not increase over existing conditions as a result of the addition of Smith Unit 3. This will not cause any exceedance in the existing permitted thermal limits for Smith Plant. Since Smith Unit 3 will withdraw cooling water from the existing discharge canal, there will be no change in entrainment or impingement impacts from the once-through cooling system because no additional water will be withdrawn from North Bay for this Project. The Smith Unit 3 cooling tower will operate under two cycles, meaning that one-half the water withdrawn will be evaporated in the cooling tower. The remaining constituents within the water in the cooling tower will be concentrated two- fold prior to discharge as blowdown, due solely to water being evaporated. However, this blowdown of approximately 2,600 gallons per minute will be immediately mixed in the discharge canal with the 185,000 gallons per minute of water discharged from Smith Plant Units 1 and 2. Therefore, the discharge from the Smith Unit 3 cooling tower will be diluted at a ratio of 71:1. Constituent concentrations within the discharge from Smith Plant will only increase approximately 1.4 percent over existing values. The existing discharge is in compliance with both Class II and Class III water quality standards, and it is not anticipated that the slight increase in concentrations due to the Project will cause any violations of applicable FDEP water quality standards. Two constituents will be added to the cooling water to facilitate its use in the cooling tower. Biofouling or the growth of unwanted organisms, such as algae and bacteria, within the cooling tower will be treated with chlorination. However, the discharge valve will be closed during this process and the chlorine will be allowed to dissipate prior to any release. Chemicals will also be added to the cooling tower water to prevent scaling. These chemicals will be nontoxic in nature when discharged and will be approved for use by FDEP under the existing NPDES permit. The Project also will have no measurable effect on adjacent aquatic communities from atmospheric deposition of air emissions from Smith Unit 3. The two primary emissions of concern are nitrogen oxides, which could reach the surrounding water as nitrogen and stimulate growth of algae, and sulfur dioxide, which could contribute to acid rain. With the addition of Smith Unit 3, there will be no increase in nitrogen oxide emissions over existing conditions and, therefore, no additional impact from nitrogen deposition in area waters. Further, sulfur constitute 1/1000th of the current Smith Plant sulfur dioxide emission levels. Therefore, sulfur dioxide emissions from the its aquatic community. Wetlands, Impacts and Mitigation Plan wetlands. These wetlands are composed of 15.4 acres of wet pine plantation, 10.2 acres of cypress- and 0.4 acres of ditch habitats. The remaining upland areas are mostly planted pines. Construction of Smith Unit 3 will impact Gulf Power has prepared a Mitigation Plan (Plan) to provide compensation for the loss of these wetlands. This Plan within a larger neighboring 232 acre parcel of land. This parcel is located approximately one mile north of the Project site. The The Plan will involve removing the existing planted pines and replanting native hardwood and cypress trees. The trees will be trees per acre. Tree species to be planted include Bald Cypress, Red Maple, naturally in hardwood and cypress swamps in the vicinity. The Plan is based upon a ratio of 12 wetland acres of enhancements for each acre impacted of the 6.4 acres of cypress-titi swamp and a 6:1 ratio of wetland enhancement to wetland loss for impacts to the wet pine plantation on the Project site. Thus, the overall mitigation ratio represents an average of 9:1 enhancement, which means for every acre of wetland impact at the Project site, there will be 9 acres of high quality wetlands produced in the mitigation/enhancement area. This Plan is more than adequate to compensate for the wetland impacts on the Project site. The Plan also provides that after planting of the wetland tree species, there will be an ongoing monitoring and maintenance program to determine the overall success of the wetland mitigation efforts. Survival of planted trees and hydrological data will be collected for up to five years, or until the goals of the Plan are otherwise achieved. The mitigation parcel will also be placed under a Conservation Easement, which will preserve the property in perpetuity. Plant and wildlife species surveys of the Project site identified the presence of four protected plant species. Two of these are relatively common ferns, which are protected from commercial exploitation. One threatened species, Chapman’s Crownbeard, is found in a transmission corridor that will not be disturbed by Project construction. The fourth plant, the Panhandle Spiderlily, is a rare species in the region and is considered endangered. Gulf Power will relocate these plants out of the construction area to nearby wetlands that will not be disturbed by construction. No listed animal wildlife species were found on the Project site, although the Bald Eagle and Brown the Project will not impact either of these two species of birds. Air Quality The Prevention of Significant Deterioration (PSD) air construction permit program applies to new major facilities and attaining the federal and state ambient air quality standards. When a new electrical generating unit is added at an existing the addition of the unit results in a significant net emissions increase above recent past actual emission levels for certain Neither Bay County nor any area in Florida is currently designated as " Protection Agency (EPA) or FDEP for any federal or Florida ambient air quality standard. facility for PSD applicability purposes. Smith Unit 3 will add two new combustion turbines and two new duct burners, which will pollutants: carbon monoxide (CO), nitrogen oxides (NOX), particulate matter (PM), particulate matter of ten microns or less (PM10), sulfur dioxide (SO2), sulfuric acid mist, and volatile organic compounds (VOCs), and will also add one new cooling tower, which will have the potential to emit PM/PM10 The recent actual NOX emissions from Smith Plant’s existing Units 1 and 2 were 6,666 tons per year. As part of this Project, a facility-wide cap on NOX emissions will apply to existing Units 1 and 2, Smith Unit 3, and the existing gas turbine to ensure that the addition of Unit 3 will not result in an increase above these recent actual annual NOX emissions. PSD review was therefore not required for NOX emissions from the Project. Because there were no creditable contemporaneous increases or decreases (within the last five years) in any pollutant emissions other than for NOX, the future potential emissions from Smith Unit 3 were compared to the PSD applicability thresholds for all emissions except NOX. Based on these thresholds and conservative estimates of the future potential emissions from the new Smith Unit 3 combustion turbines, duct burners, and cooling tower, PSD review was required for CO, PM/PM10, SO2, sulfuric acid mist, and VOCs. Operation in the steam power augmentation mode is limited to 1,000 hours per year of operation. For those pollutants triggering PSD review, the PSD program requires a demonstration that the Project’s emissions will not cause or contribute to any violation of state or federal further requires an analysis for these pollutants to demonstrate as well as impacts induced by residential, commercial, and that Best Available Control Technology (BACT) be applied to Emission Impacts contribute to a violation of federal or state ambient air quality classified as a Class II area for PSD. The nearest Class I area Bradwell Bay National Wilderness Area, An air quality analysis, undertaken in accordance with Smith Unit 3 would not cause or contribute to an state and federal ambient air quality standards for CO, PM , or 2 10 2 Smith Unit 3 is also not expected to cause an increase not increase and VOC emissions will increase only negligibly. In new combustion turbines and duct burners. The projected impacts of the sulfuric acid mist emissions from Smith Unit 3 combustion turbines and duct burners were compared to the draft Florida Ambient Reference Concentrations (FARCs). The modeling analysis demonstrated that projected impacts of sulfuric acid mist from Smith Unit 3 will be well below the corresponding draft FARCs and will not impose a health risk. Further, the Project's air emissions are not expected to cause any adverse impacts on visibility and vegetation in the Smith Plant vicinity or in the Bradwell Bay National Wilderness Area, the nearest PSD Class I area. Only temporary and very small residential and no significant industrial or commercial growth is expected from the construction phase of Smith Unit 3. Any resulting air emissions will be very small, well-distributed, and have no measurable impact on ambient air quality. The operation of Smith Unit 3 will not cause odor impacts and will have no significant effect on acid rain because NOX emissions are not being increased and sulfur dioxide emissions are being increased by only a small amount. Consequently, taking into account all of the above factors and considerations, no significant air emission impacts are expected to result from the construction and operation of Smith Unit 3. BACT and Emission Rates A BACT analysis determines the most stringent, allowable emissions rule for each emissions unit and pollutant subject to PSD review on a case-by-case basis, considering available and technically feasible control technologies, methods, systems, and technologies, as well as economic, energy, and environmental impacts and other costs. A BACT review for the Smith Unit 3 combustion turbines and duct burners was required for CO, PM and PM10, SO2, sulfuric acid mist, and VOCs. For the new cooling tower, BACT was required for PM and PM10 emissions. For the Project’s combustion turbines and duct burners, FDEP determined that BACT for PM and PM10 emissions is the fuel quality of natural gas, good combustion practices and a ten percent opacity limitation. For the new cooling tower, BACT was established by FDEP for PM and PM10 emissions to be the use of high-efficiency drift eliminators. For the Smith Unit 3 combustion turbines and duct burners, FDEP’s BACT determination for CO and VOC emissions consists of good combustion practices. The cost per ton of controlling CO emissions through the use of an add-on emission control device known as an oxidation catalyst was found to be excessive. Further, in FDEP’s BACT analysis, the use of an oxidation catalyst would provide no air quality benefits or serve an environmental purpose. BACT for CO and VOCs was, therefore, determined by FDEP to be good operating practices. For the Project’s combustion turbines and duct burners, BACT for SO2 and sulfuric acid mist was determined by FDEP to be the use of low-sulfur natural gas. For the Smith Unit 3 combustion turbines and duct burners, BACT for NOX emissions was not required since Gulf Power will use dry low-NOX burners on Unit 3 to control NOX emissions, and short-term NOX emissions limits will apply on a 30-day rolling average basis. A separate NOX limit of 0.1 pounds per million British thermal units applies to the duct burners, which is more stringent than the applicable federal New Source Performance Standard (NSPS) limit. Furthermore, Smith Unit 3 combustion turbines and duct burners will have emission limits well below the applicable NSPS requirements, and no NSPS requirements apply to cooling towers. No National Emissions Standards for Hazardous Air Pollutants (NESHAPs) apply to Smith Unit 3, and a case-by-case determination of Maximum Achievable Control Technology (MACT) for hazardous air pollutants was not required. Compliance The Smith Plant air emission units and activities, both new and existing, will comply with all applicable federal, state, and local air quality standards, including the conditions conditions of certification for Smith Unit 3. for NOX as well as the unit-specific emission limiting standards certification and the proposed PSD permit. Compliance with the emissions monitoring and fuel use data for existing Smith Plant emission factors for the existing gas turbine. 70. The adjacent land use to Smith Plant is The Bay County Land Use Code defines the maximum noise level for dBA). The Code dBA during dBA at night. of Smith Unit 3 will be 63 lower than the applicable noise standard for the adjacent where noise levels from construction would not be excessive. steam and air blowing, which should occur infrequently during the will notify the nearby residents prior to commencement of the 72. During normal operation of Smith Plant following the 3, the highest predicted continuous dBA at the property adjacent property. Thus, the operation of Smith Plant will Socioeconomic Impacts and Benefits beneficial economic and social effects. The main regional reliable energy source. Also, during construction, employment with a peak of 325 workers for approximately six months. $23.7 million. It is expected that most of the construction subcontractors and vendors will be used to provide labor and include concrete, lumber, and other construction materials. construction costs will result in indirect benefits to the local 74. The operation of Smith Unit 3 will result in employment day schedule. It is expected that these new employees will be million. These new employees are expected to pay taxes and the local economy. Using accepted economic multipliers, the over $1.8 million. Gulf Power also expects to make annual equipment related to Smith Unit 3 operations. short term traffic impacts due to construction. These impacts traffic flow should conditions warrant. Residential areas are from the site and screening by existing forested vegetation. 76. Impacts from Smith Unit 3 operations are expected to be recreational areas, parks or scenic aesthetic quality of the vicinity will be negligible. Smith Unit services or facilities. The Smith Plant is equipped with its own guards. The number of new employees are not expected to roadways. Project site from agricultural to industrial uses is appropriate 600-acre portion of Smith Plant site used for electrical an economic loss as a result of Smith Unit 3 construction. County Comprehensive Plan, the State Comprehensive Plan, and the Planning Council. The FDEP, the Florida Department of Community Affairs, Wildlife Conservation Commission, the Northwest Florida Water Council each prepared written reports on the Project. Each of otherwise, did not object to certification of the proposed power for the Project, incorporating the recommendations of the various and comply with these Conditions of Certification in the construction and operation of Smith Unit 3. In its report, the Florida Department of Community Affairs determined that, if certified, the Project would be consistent with the State Comprehensive Plan, as contained in Chapter 187, Florida Statutes. The West Florida Regional Planning Council stated in its agency report that the Project would not conflict with the strategic Regional Policy Plan for West Florida. No state, regional, or local agency has recommended denial of certification of the Project or has otherwise objected to certification of the Project.
Conclusions For Gulf Power Company: Douglas S. Roberts, Esquire William D. Preston, Esquire Angela R. Morrison, Esquire Hopping Green Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314 For Florida Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building Mail Station 35 3900 Commonwealth Boulevard. Tallahassee, Florida 32399
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Siting Board grant full and final certification to Gulf Power Company, under Section 403, Part II, Florida Statutes, for the location, construction, and operation of Smith Unit 3, representing a 575 MW combined cycle unit, as described in the Site Certification Application and the evidence presented at the certification hearing, and subject to the Conditions of Certification contained in FDEP Exhibit 4. DONE AND ENTERED this 19th day of June, 2000, in Tallahassee, Leon County, Florida. P. MICHAEL RUFF 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) 921-68847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 19th day June, 2000 COPIES FURNISHED: Douglas S. Roberts, Esquire William D. Preston, Esquire Hoping, Green, Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314-6526 Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 James V. Antista, Esquire Fish and Wildlife Conservation Commission 620 Meridian Street Tallahassee, Florida 32399-1600 Andrew S. Grayson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Sheauching Yu, Esquire Department of Transportation Mail Station 35 Haydon Burns Building 605 Suwannee Street Tallahassee, Florida 32399-0450 Robert V. Elias, Esquire Florida Public Service Commission Gerald Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Daniel F. Kurmel, Executive Director West Florida Regional Planning Council Post Office Box 486 Pensacola, Florida 32593-0486 Douglas Barr, Executive Director Douglas L. Stowell, Esquire Northwest Florida Water Management District 81 Water Management Drive Havana, Florida 32333 Johnathan Mantay, County Manager Bay County Post Office Box 1818 Panama City, Florida 32402-1818 Teri Donaldson, General Counsel Department of Environmental Protection Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000
The Issue The issue to be resolved in this portion of this power plant site certification proceeding is whether the site for the proposed Florida Power & Light Company (FPL) Martin Unit 8 Expansion Project (Project) is consistent and in compliance with the existing land use plans and zoning ordinances of Martin County, Florida, pursuant to Section 403.508(2), Florida Statutes.
Findings Of Fact FPL provides electricity in its service area that stretches from the Florida/Georgia border in the north to the Florida Keys in the south, and along Florida's west coast to just south of Tampa. FPL has been providing electricity to customers in Florida since 1926. FPL currently serves about 7 million residents of Florida. FPL operates 14 power plants in the State of Florida, including its Martin Plant located near Lake Okeechobee. The existing FPL Martin Plant site is located approximately 7 miles west of the community of Indiantown, Florida, and approximately 20 miles west of Stuart, Florida. The plant site is located in the unincorporated area of Martin County, Florida. The site is bounded along its northern and eastern edges by State Road (S.R.) 710, which provides the principal access to the plant site. The Martin Plant site comprises approximately 11,300 acres, and contains an approximately 6,800-acre cooling pond. The site also contains existing transmission line corridors located to the east of the plant. The Martin site presently contains several existing electrical generating units. Martin Units 1 and 2 are large conventional steam-electric units, each with generating capacity of approximately 800 megawatts (MW). These two units burn natural gas and/or residual oil. They have been in service since 1980 and 1981, respectively. Units 3 and 4 are combined cycle units, each with a generating capacity of approximately 450 MW. They burn natural gas and are permitted to burn light oil as well. These two units have been in service since 1994. Units 8A and 8B are simple cycle, advanced combustion turbines, each with generating capacity of approximately 170 MW. They burn natural gas and light oil and have been in operation since 2001. Units 1 and 2 were constructed prior to the implementation of the Florida Electrical Power Plant Siting Act. Units 3 and 4 were originally certified under the PPSA. The new Unit 8 will be located in that portion of the Martin Plant Site, which was previously certified under the PPSA. The Unit 8 Project area is approximately 110 acres, with approximately 15 acres to be occupied by actual power plant facilities. The Project area is a previously-graded flat area with scrub grass on the surface. No substantial clearing will be required for the Unit 8 Project, "[j]ust grading for the foundations." The proposed Martin Unit 8 would incorporate the two existing combustion turbines (Units 8A and 8B), and add two additional combustion turbines, four heat recovery steam generators (one for each combustion turbine), and a single new steam turbine generator. The two new combustion turbines and the new steam turbine will be placed to the east of the existing Units 8A and 8B. A new cooling tower may potentially be built to serve the new unit as an alternative to connecting the new unit directly to the cooling pond. In any event, the existing cooling pond will supply cooling water for Unit 8. The two existing combustion turbines each have a capacity of approximately 170 MW. The new Unit 8 generating equipment will provide approximately 800 MW of additional generating capacity. Therefore, the total capacity of Martin Unit 8 will be approximately 1,140 MW. The new Unit 8 will be supplied with natural gas by an existing natural gas lateral serving the Martin Plant site, or possibly by a new gas pipeline. Light oil will be delivered by truck and stored in two on-site fuel tanks, one of which will be a new tank. The maximum height of any of the new structures for Martin Unit 8 will be 150 feet. The new Unit 8 will share several existing facilities located at the Martin site. These include use of the existing: cooling pond, plant electrical substation, water tanks, light oil tank, electrical transmission facilities, and control building. The new Unit 8 will connect to FPL's electrical transmission system at the on-site substation at the Martin Plant where the voltage of the electricity from the new Unit will be increased for transmission over FPL's transmission system. In addition to the new power plant facilities, FPL plans to construct two new 230 kilovolt transmission lines, which are integration facilities which will maintain the reliability of the transmission system. A portion of the transmission lines will be located within existing FPL electrical transmission line rights-of-way. However, one segment of the new transmission facilities will be located within a new right-of-way, approximately eight and one-half miles long. FPL seeks certification of this new eight and one-half mile portion of the proposed Indiantown - Martin No. 2 line (the new offsite transmission line) as part of its Martin Unit 8 Site Certification Application. The new offsite transmission line follows S.R. 76 and County Road (C.R.) 726 as those roadways pass west to east near the community of Indiantown. FPL distribution lines already occupy the existing route. The proposed route of the new ROW segment consists mainly of a mix of citrus, pasture lands and some multi-acre residential lots. The new offsite transmission line will be constructed on single-pole concrete structures, which are embedded into the ground. These structures will be unguyed, except where they make right turns to cross the St. Lucie Canal. The remaining portion of the approximately 21-mile transmission line project will be located in rights-of-way already occupied by FPL's 230 and 500 kilovolt transmission lines. The Unit 8 Project will be located within the 2,192- acre portion of the Martin Plant site which was certified under the Power Plant Siting Act in 1991. In 1990, the Siting Board entered a Final Order on land use for the original development of Units 3 and 4 determining that the site was consistent and in compliance with the land use plans and zoning ordinances of Martin County, Florida. The Martin Unit 8 Project will be located in an area designated under the Future Land Use Map of the Martin County Comprehensive Plan as "major power generation facilities." That designation is specifically for uses such as proposed Martin Unit 8. In 1989, the Martin County Board of County Commissioners rezoned the 2,192-acre parcel at the Martin Plant site to industrial planned unit development (PUD(i)) zoning, and entered into a Planned Unit Development Zoning Agreement with FPL. PUD zoning is intended to provide flexibility from the strict zoning regulations and development standards. It is designed to encourage a more creative approach to land use planning with specific regulations established to control the development pursuant to the PUD zoning approval. The PUD Zoning Agreement establishes the zoning criteria for the FPL Martin Unit 8 site. The Martin Unit 8 Project has been designed and will otherwise be consistent with the PUD Zoning Agreement approved by Martin County. Specifically, the Martin Unit 8 Project will be located within the area designated as "power block" under the preliminary development plan contained in the PUD Zoning Agreement. The proposed Unit 8 facilities are among the listed permitted uses under the PUD Zoning Agreement. Further, the Martin Unit 8 Project complies with all other applicable provisions of the PUD Zoning Agreement, including those special conditions set forth in the Zoning Agreement to control development within the area subject to the PUD zoning. These include compliance with the size and dimensional criteria; preservation of upland preserve and wetland restoration areas within the site; compliance with specific performance standards and with provisions related to wetlands preservation; hazardous waste management; excavation and fill; noise; protection of archaeological artifacts and threatened or endangered species or species of special concern that may be discovered on the site; and public availability of employment applications during periods of substantial hiring. The Martin County Commission has also granted a special exception to allow heights of structures in excess of 60 feet at the Unit 8 Project site. This special exception for heights applies to the Unit 8 Project Area. The Unit 8 Project will comply with this height exception. Martin County defines utilities to include electrical transmission systems. Such utility facilities are allowed as permitted uses in all the zoning districts which the proposed new offsite transmission line will cross. The PUD Zoning Agreement for the Project site includes approval of a preliminary development plan contained within the Zoning Agreement. The Zoning Agreement further provides that the application for site certification under the PPSA will constitute formal application for a final development plan approval for the PUD. The PUD Zoning Agreement also provides that the site certification order issued under the PPSA will constitute the final development plan approval. Thus, if the Siting Board issues a certification order for the Martin Unit 8 Project, it will also constitute approval of the amendment to the existing final development plan under the terms of the PUD Zoning Agreement. The PUD Agreement is not specific as to the amount of generating capacity in the area subject to the PUD Zoning Agreement. FPL published Notice of Land Use Hearing for a Power Plant Siting Application to be located in Martin County, Florida, in The Stuart News on March 15, 2002 and also in the Indiantown News on both March 21 and March 28, 2002. Notice of the land use hearing was published in the Florida Administrative Weekly on March 22, 2002.
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is, therefore, RECOMMENDED that the Siting Board determine that the site of the FPL Martin Unit 8 Project, as described by the evidence presented at the final hearing, and including the offsite transmission line, is consistent and in compliance with existing land use plans and zoning ordinances of Martin County, pursuant to Section 403.508(2), Florida Statutes. DONE AND ENTERED this 10th day of June, 2002, in Tallahassee, Leon County, Florida. ___________________________________ CHARLES A. STAMPELOS Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 10th day of June, 2002. COPIES FURNISHED: Peter C. Cunningham, Esquire Douglas S. Roberts, Esquire Hopping Green & Sams, P.A. Post Office Box 6526 Tallahassee, Florida 32314 Scott A. Goorland, Esquire Senior Assistant General Counsel Department of Environmental Protection 3900 Commonwealth Blvd., Mail Station 35 Tallahassee, Florida 32399-3000 Tyson Waters, Esquire Krista Storey, Esquire Martin County Attorney's Office 2401 Southeast Monterey Road Stuart, Florida 34996 Ross Stafford Burnaman, 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 Colin Roopnarine, Esquire Assistant General Counsel Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Robert V. Elias, Esquire Florida Public Service Commission Gerald Gunter Building 2450 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Roger Saberson, Esquire Treasure Coast Regional Planning Council 70 Southeast Fourth Avenue Delray Beach, Florida 33483-4514 Susan Roeder Martin, Esquire Assistant General Counsel South Florida Water Management District Post Office Box 24680 West Palm Beach, Florida 33416 Teri L. Donaldson, General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000 Kathy C. Carter, Agency Clerk Office of the General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000
Findings Of Fact On or about May 24, 1976, Petitioner and Respondent entered into a contract for State Project No. HRS-7525-A (hereinafter "Phase 1") for improvements to the utility system at Chattahoochee, Florida. The Phase I contract involved conversion of boilers located at that facility to fuel oil firing; additions to the system's cooling tower capacity; and repair of condenser shell and boiler stacks at the hospital. Petitioner was to be paid ;525,927 for work performed under the Phase I contract. Although Respondent was referred to as the "owner" in the Phase I contract documents, it was responsible only for contracts and the work performed thereunder. The Florida Department of Health and Rehabilitative Services is the state agency responsible for operating Florida State Hospital and is referred to in the contract documents as the "using agency". The using agency's only responsibility under the Phase I contract was to coordinate periodic utility outages with Petitioner. The firm of Tidewater Engineers, Inc. ("architect' or Tidewater") was referred to in the Phase I contract document as the Architect and/or Engineer. Tidewater engineered the Phase I contract, prepared the contract specifications, and provided general administration of the work performed under the contract. Pursuant to the provisions of the Phase I contract, Petitioner received from Respondent a Notice to Proceed with construction dated June 28, 1976. In accordance with the contract documents, Petitioner was given 210 days, or until January 23, 1977, to complete construction on the project. Petitioner actually commenced work on Phase I on June 28, 1976. During the course of construction, Petitioner was granted a 23-day extension of time by change order, with a resulting extension of the tine for completion of the project through February 15, 1977. The architect certified that Petitioner attained "substantial completion" of work, as that term is defined in the contract documents, on the project on February 23, 1977. Accordingly, "substantial completion" was accomplished eight-days beyond the date provided for in the contract, as modified by change orders approved by the architect. The Phase I contract allowed Petitioner a period of 60 days between "substantial completion" and "final completion" of construction on the project. Thus, Petitioner was scheduled to conclude work on the project no later than April 24, 1977 However, "final completion" was certified by the architect to have been accomplished by Petitioner on July 21, 1977, or 88 day's beyond the period provided in the Phase I contract. The Phase I Contract contained the following provision concerning liquidated damages for failure to attain "substantial completion" and "final completion" within the time limit agreed upon by the parties: . . . it is hereby agreed that if the project is not substantially completed, according to the definition of "sub- stantial completion" in Article 8.3 hereof, or within such further time, if any, as in accordance with the provisions of the contract documents shall be allowed for such substantial completion, the Contractor shall pay to the Owner as liquidated damages for such delay, and not as a penalty, Two Hundred dollars ($200) for each and every calendar day elapsing between the date fixed for sub- stantial completion in Article 4 hereof and the date such substantial completion shall have been fully accomplished. It is also hereby agreed that if this project is not finally completed, in accordance with the requirements of the contract documents, the Contractor shall pay to the Owner as liquidated damages for such delay, and not as a penalty, one-fourth of the rate indicated above. . . . In accordance with the foregoing provisions of the Phase I contract, and in light of the 8-day overrun in attaining "substantial completion" and the 88-day overrun in attaining "final completion", the architect, by certificate dated December 12, 1978, assessed against Petitioner $1,600 in liquidated damages for failure to timely accomplish "substantial completion", and $4,400 for overruns on "final completion" of the project, for total liquidated damages of $6,000. Petitioner contends that it should have been granted extensions of time by the architect sufficient to offset the amounts assessed as liquidated damages by virtue of its failure to-attain "substantial completion" and "final completion" within the time limits contained in the Phase I contract documents, as modified by change orders issued by the architect. The record in this proceeding establishes that additional delays in completion of construction of Phase I were attributable to an insufficient number of welders on the job site to complete construction as contemplated. Petitioner additionally asserts that adverse weather conditions and problems encountered by its subcontractors in interfacing the contract work with existing facilities caused unavoidable delay. In this regard, Section 8.3.1 of the General Conditions of the Contract for Construction provides that: If the Contractor is delayed at any time in the progress of the Work by any act or neglect of the Owner or the Archi- tect, or by any employee of either, or by any separate contractor employed by the Owner, or by changes ordered in the Work, or by labor disputes, fire, unusual delay in transportation, unavoidable casualties or any causes beyond the Contractor's con- trol or by delay authorized by the Owner pending arbitration, or by any cause which the Architect determines may justify the delay, then the Contract Time shall be extended by Change Order for such reason- able time as the Architect may determine. Further, Section 8.3.2 of the General Conditions provides that: [a]ll claims for extension of time shall be made in writing to the Architect no more than twenty days after the occurrence of the delay; otherwise they shall be waived Petitioner did not timely submit a request for extension of time to reach "substantial completion" or "final completion" of construction on Phase I, nor is there any competent evidence in this proceeding to indicate that either Respondent or the architect agreed explicitly or by implication to waive the requirement of the contract documents that requests for extension of time be made in writing within twenty days of the occurrence giving rise to the request. On or about October 19, 1976, after receipt and evaluation of competitive bids, Petitioner and Respondent entered into a contract for State Project Number HRS-7525-B (hereinafter "Phase II") . The Phase II contract involved demolition and removal of Boiler Number 5, installation of Boiler Number 9 and accessories, and other modifications to the steam distribution system at Florida State Hospital. Petitioner was paid a total of $276,322.44 for work performed under the Phase II contract. In addition, Tidewater also served as the architect on the Phase II contract. Among the specifications contained in the Phase II contract documents as the following: Bidders are required, before submitting their proposals, to visit the site of the proposed work and completely familiar- ize themselves with the nature and extent of the work and any local conditions that may in any manner-affect the work to be performed, and the equipment, materials, and labor required. They are also required to examine carefully the drawings, speci- fications and other bidding documents, to inform themselves thoroughly regarding any and all conditions and requirements that may in any manner affect the work. [Original emphasis]. (Joint Exhibit number 2, p. B-4). The specifications governing Phase II required Petitioner to attend a pre-construction conference before beginning work at the site, the purpose of which conference was to discuss the project under contract and prepare a program of procedure in keeping with requirements of the drawing and specifications." (Joint Exhibit number 2, p. H-1) . In addition, the Phase II specifications provided that it was Petitioner's responsibility " . . . to verify all conditions relating to the work in the field prior to proceeding with the installation." [Original emphasis]. (Joint Exhibit number 2, p. 1-1). The specifications further provided that where the work under the contract " . . . ties into existing facilities [Petitioner] shall coordinate his work with the Owner so that a minimum of downtime and disruption will occur." (Joint Exhibit number 2, p. 1-1). The section of the Phase II specifications dealing with demolition and installation of the various boilers provided that: It is imperative that the Contractor visit the jobsite prior to submitting his bid for the work. He shall carefully inspect the premises and shall include in his pro- posal such necessary contingencies as might be required by conditions at the site. Failure of the Contractor to visit the jobsite and include necessary contin- gencies shall not relieve him from complete and correct prosecution of the work. (Joint Exhibit number 2, p. 6-1). Finally, the Phase II specifications also provides that: The plant will be in operation during construction. Any outages shall be scheduled at the convenience of the Owner and at a time designated by him. When required by Owner, temporary feeds will be provided by this Contractor to keep existing equipment in operation while installing new equipment. On October 25, 1976, a conference was held at the construction site with representatives of Petitioner, Respondent, Florida State Hospital and the architect present. By letter dated October 26, 1976, Petitioner's president memorialized the discussions which occurred at this meeting as they applied to work under both Phase I and Phase 11. With respect to Phase II, this letter indicated that Petitioner's president: . . . was advised by both [the architect] and [the hospital's representative] that the hospital must have the capability to fire three boilers at anytime during this time of the year. [The architect] further advised that [Petitioner] could not start demolition of Boiler number 5 until all existing boilers are converted and checked out. [Petitioner's president] advised [the architect] that it would take [Petitioner] the minimum of six months to complete Phase II of this contract after [Petitioner] is allowed to go to work. [The architect] advised that he would grant [Petitioner] this additional time from when [Petitioner is] allowed to proceed. The evidence in this proceeding establishes that the demolition of Boiler Number 5 and the installation of Boiler Number 9 constituted the vast majority of work to be performed in Phase II. Accordingly, at all times following the meeting of October 25, 1976, Petitioner was aware that no date had been established for commencement of the major portion of the Phase II contract work, but that it would be allowed an extension of time of six months to complete Phase II of the contract after receiving notice from Respondent to proceed with demolition of Boiler Number 5. The Phase II contract provided that work to be performed thereunder would be commenced within ten calendar days after receipt of a Notice to Proceed, and that work under that section of the contract was required to be "substantially completed" within 180 calendar days of receipt of the Notice to Proceed. However, as indicated above, Petitioner was advised at the October 25, 1976 meeting that it would receive, in addition to the time periods contained in the original Phase II documents, a 180-day period of time to complete the contract work after receipt of a Notice to Proceed with demolition of Boiler Number 5. Petitioner received from Respondent a Notice to Proceed, dated November 4, 1976, establishing the starting date for the Phase II contract time as November 15, 1976. In accordance with the Phase II contract documents, the Notice to Proceed also established a "substantial completion" date of May 13, 1977. These dates were established subject to change consistent with the agreement between the parties reached at the October 25, 1976 pre-construction conference. The record clearly establishes that this Notice to Proceed was intended to allow Petitioner to begin that portion of the Phase II work not associated with demolition of Boiler Number 5 and installation of Boiler Number 9. A second conference was held at the job site on November 15, 1976, which resulted in a pre-construction conference report signed by representatives of Respondent, Florida State Hospital, the architect and Petitioner. This report indicated that work on Phase II of the project was ". . . being delayed because of work on Phase I that the " . . . engineer agrees with delay on Phase II and suggests [Change Order] to extend time . .", and that a " . . . Change Order [is] to be issued when boiler is received and project starts." (Respondent's Exhibit number 1). In reliance on the Notice to Proceed dated November 15, 1976, Petitioner apparently proceeded with some of the work called for under the contract, with the exception of work connected with the demolition of Boiler Number 5 and the installation of Boiler Number 9. The understanding between the parties concerning the starting date for work on the two boilers was again memorialized in a letter from the architect to Petitioner dated December 7, 1976. That letter provided that: Due to the circumstances involved while converting the existing boilers No. 6, 7 & 8 the institution has requested the use of boiler No. 5 during the conversion shut down. This boiler will remain in use until the new fuel oil pumping system is in operation serving the existing boilers No. 6, 7 and 3. Since you have been notified to proceed with the Phase II contract and your con- strution time has begun, we will give you 180 calendar days from the time you are allowed to begin demolition of No. 5 boiler. Please advise your subcontractors and suppliers of this change so they can arrange their schedules accordingly. It appears that the work inside the boiler room can begin about January 15, 1977. The January 15, 1977 anticipated starting date referred to in the aforementioned letter apparently resulted from an estimate of the anticipated date of substantial completion of work on Phase I, which was scheduled for January 2.3, 1977. However, as a result of Change Orders issued on the Phase I project and construction overruns by Petitioner on the Phase I work, substantial completion was not reached on Phase I until February 23, 1977. As a result, Respondent did not issue a Notice to Proceed with demolition of Boiler Number 5 until March 28, 1977. This Notice to Proceed established March 28, 1977 as the contract commencement time, and further established September 23, 1977 as the required date for substantial completion. This second Notice to Proceed also contained a notation that these new dates were being established because " . . . Project HRS-7525-A, Improvements to Utilities System, Phase I, was behind schedule, therefore the Using Agency could not shut dawn the existing boiler which is to be renovated under the contract." (Petitioner's Exhibit number 22). In accordance with the earlier understanding by the parties reached on October 25, 1976, Petitioner was given a period of 180 days from March 28, 1977, in which to reach "substantial completion" of work on the project. In addition, the architect granted a 32-day extension by Change Order during the course of construction work. As a result, the date on which substantial completion was to have been reached by Petitioner was October 25, 1977. However, the architect certified that Petitioner attained substantial completion of work on the project on November 11, 1977, which constituted a 17-day overrun of the required substantial completion date. The Phase II contract documents allowed Petitioner a period of sixty days from the date established for substantial completion to reach final completion of construction on the project. Accordingly, final completion of the project was scheduled to occur no later than January 10, 1978. However, final completion of work on the Phase II contract was certified by the architect to have been accomplished by Petitioner on February 16, 1978, 37 days beyond the date required by the contract documents. The Phase II contract documents contained a provision that for each day of overrun in reaching substantial completion, the Petitioner would be assessed one hundred dollars as liquidated damages. In addition, the contract provided far a twenty-five dollar per day assessment of liquidated damages for each day of overrun in reaching final completion of the project. Accordingly, Petitioner was assessed $1,700 in liquidated damages for overruns on reaching substantial completion, and $925 for overruns in obtaining final completion. Petitioner did not request an extension of time in accordance with the Phase II contract documents to offset the time overruns for which it was assessed liquidated damages. In addition, as with the Phase I contract, nothing in the record of this proceeding establishes that Respondent or its representatives in any way waived the notice provisions of the Phase II contract documents with regard to requests for extensions of time. Finally, the coordination problems encountered by Petitioner with materialmen which Petitioner asserts as justification for the overruns on the Phase II contract, were among the matters which the contract documents required Petitioner to take into account in formulating its bid and cannot, at this late date, constitute an excuse for failure to comply with the time limits contained in the contract. Periodic payments under both the Phase I and the Phase II contracts were scheduled to be made to Petitioner on a monthly basis depending upon progress in construction. The contract allowed Respondent to withhold 10 percent from the amount of each of the monthly progress payments as retainage. The contract documents also provided that upon substantial completion of the contract work, the 10 percent retainage figure could be reduced to 5 percent, in the discretion of the architect, with the remaining 5 percent constituting the final payment to be made upon final completion. All periodic payments were to be made to Petitioner upon approval by the architect. Payment in the amount of $32,169.39 reducing Phase I retention from 10 percent to 5 percent was made on February 9, 1978, almost one year after the February 23, 1977, date certified by the architect for substantial completion on Phase I. Payment reducing retention on Phase II from 10 percent to 5 percent, in the amount of $34,730.70, was made on February 3, 1978, approximately three months after the November 11, 1977, certified date for substantial completion of construction on Phase II. Final payment of all retention on Phase I, which payment amounted to $20,451.50, was made on March 19, 1979, approximately 20 months after the July 21, 1977 certificate of final completion Issued by the architect. Final payment of all retention on Phase II, in the amount of $11,389.14, was made on May 29, 1979, approximately 15 months after the February 16, 1978, final completion date certified by the architect. Petitioner claims that it is entitled to an award of interest on those parts of the contract sums remaining unpaid from the respective dates of substantial and final completion of the two projects until retainage payments were actually received. In this regard, the General Conditions of the contract documents contained a clause that provided that " . . [a]ny monies not paid when due to either party under this Contract shall bear interest at the legal rate in force at the place of the Project." (Joint Exhibit number 5 p. 12) However, in the specifications for both the Phase I and Phase II contracts there appears a clause which deletes the above-quoted interest provision in its entirety. It is, therefore, specifically found that the intent of the parties in deleting that portion of the contract documents providing for the payment of interest on past-due monies owing under the contracts was to relieve either- party from any liability for interest on such past-due amounts. Accordingly, Petitioner's claim for an award of interest on late payments is precluded by virtue of the provisions of both the Phase I and Phase II contract documents. Finally, Petitioner claims entitlement to an increase in the contract sum on the Phase II contract because of its inability to proceed with demolition of Boiler Number 5 and installation of Boiler Number 9 until March 28, 1977. Petitioner calculates its claim for an increase in the contract sum based upon additional overhead expenses attributable to the lapse of time between the initial Notice to Proceed issued on November 15, 1976 and the second Notice to Proceed of March 28, 1977. In essence, Petitioner argues that there was nothing in any of the Phase II contract documents which would have put it on notice that construction on Phase II could not have commenced shortly after the award of the contract, and that it prepared its bid in reasonable reliance on its ability to begin construction shortly after the letting of the contract. Because of the using agency's need to keep Boiler Number 5 operating until completion of work on Phase I, and the additional requirement that a coal chute at the hospital be left unblocked to facilitate unloading of fuel, Petitioner was not allowed to begin demolition of Boiler Number 5 until 134 days after issuance of the initial Notice to Proceed. As indicated earlier in this Recommended Order, the Phase II contract documents required Petitioner to visit the site of the proposed work and completely familiarize [itself] with the nature and extent of the work and any local conditions that may in any manner affect the work to be performed, and the equipment, materials, and labor required . . . [Original emphasis]. (Joint Exhibit number 2, p. B-4). The Phase II contract documents also required that "[w]here [Petitioner] ties into existing facilities, [it] shall coordinate its work with the Owner, so that a minimum of downtime and disruption will occur." (Joint Exhibit number 2, p. 1-1). Finally, the contract documents contained a provision that: . . . If [Petitioner] is delayed at any time in the progress of the Work . . . by any cause which the Architect determines may justify the delay, then the Contract Time shall be extended by Change Order for such reasonable time as the architect may deter- mine. [Emphasis added]. (Joint Exhibit number 5, p. 12). There is no provision in any of the Phase II contract documents setting a specific starting time for work on the project. Instead, the contract documents simply provide that "[t]he date of commencement of the Work is the date established in a notice to proceed (Joint Exhibit number 5, p. 12). In this regard, Petitioner knew at all times on and after October 25, 1976, that there would be a substantial delay in commencement of work on the demolition of Boiler Number 5. In accordance with the terms of the contract documents, Petitioner was advised on October 25, 1976, and at numerous times thereafter, that it would be granted the full 180-day time period to complete the Phase II work after receipt of a notice to proceed with demolition of Boiler Number 5. The record establishes that Petitioner acquiesced in this arrangement, and that it did not request an increase in the contract sum within twenty days of the October 25, 1976, meeting as it was required to do in the contract documents. (Joint Exhibit number 5, p. 17). Finally, delays in commencement of work under the Phase II contract, unlike changes in or stoppage of the work once it has been started, cannot form the basis for an award of delay damages. Under the Phase II contract, delays in initial commencement of the work arising prior to the issuance of a notice to proceed can be redressed only by extension of the contract time. Accordingly, expenses incurred in preparation to perform work under the contract prior to the issuance of a notice to proceed, absent some contrary agreement, are undertaken at the contractor's risk. This is especially so under the facts of this case where Petitioner knew of the likelihood of delay on work on Phase II well in advance of the issuance of either of the notices to proceed, and where Petitioner itself, by virtue of its delinquencies in performing work under the Phase I contract, thereby contributed to the delay in commencing work on Phase II. Both Petitioner and Respondent have submitted proposed findings of fact in this proceeding. To the extent that those proposed findings have not been adopted herein, they have been rejected as either being irrelevant to the issues presented or as not having been supported by the evidence.
The Issue Pursuant to Section 403.508(2), Florida Statutes, the sole issue for determination in this case is whether the site for the Petitioner’s proposed electrical power plant “is consistent and in compliance with existing land use plans and zoning ordinances.” (All statutory references are to the 2000 codification of the Florida Statutes.)
Findings Of Fact The Petitioner Calpine intends to license, construct, own, and operate a new electrical power plant in the City of Auburndale, Florida. Calpine filed an application with DEP under the PPSA for the proposed electrical power plant, which is known as the Osprey Energy Center or the Osprey Project. The Site for the Osprey Energy Center The site (“Site”) for the Osprey Energy Center is located within the municipal limits of the City of Auburndale, which is in the north-central portion of Polk County, Florida. The Site is approximately 1.5 miles from downtown Auburndale. The Site is approximately 19.5 acres in size. The Site currently consists of an abandoned orange grove, which is overgrown and neglected. The Site has excellent characteristics for its planned use because the Site contains no environmentally sensitive areas, surface water bodies, wetlands, floodplains, threatened or endangered species of plants or wildlife, or historic or archaeological resources. Adjacent to the east side of the Site is the Auburndale Power Plant, a 150 MW natural gas and oil-fired cogeneration facility. The eastern boundary of the Site also is adjacent to Tampa Electric Company’s Recker Substation. Derby Avenue (CR 544A, a two-lane, paved collector road) is adjacent to the north side of the Site. The City of Auburndale’s Memorial Park Cemetery is adjacent to the west side of the Site. The southern boundary of the Site is adjacent to Recker Highway (SR 655, a two-lane, paved collector road). There are several commercial operations on the south side of Recker Highway, including a sand/cement plant, an automobile parts shop, and a storage center. Cutrale Citrus Juices USA, Inc. and Florida Distillers have large industrial facilities located east of the Site. The City of Auburndale’s Allred wastewater treatment plant (“WWTP”) also is located east of the Site. Historically, the area surrounding the Site has been comprised of a mixture of residential, commercial, industrial, and utility uses. However, the general area surrounding the Site is now dominated by industrial and commercial land uses and this land use trend is becoming more homogeneous. Although there are some homes across Derby Avenue and Recker Highway from the Site, they already are impacted by existing development in the area. Polk County planners have recognized this trend in land development patterns and have designated the homes located north of the Site as areas for future development as Business Park Centers. The Site has excellent characteristics for its planned use. The Site is adjacent to an existing electrical power plant that uses the same combined cycle generating technology as the Osprey Project. The Site also is located adjacent to an existing electrical substation. Thus, the proposed use of the Site is nearly identical to the closest adjacent land uses. Potable water, reclaimed water, and wastewater services will be available at the Site from the City of Auburndale. The City’s Allred WWTP is located near the Site. The Recker Substation is adjacent to the Site, so no new electrical transmission lines will need to be built. Description of the Proposed Osprey Project The Osprey Energy Center will involve the construction and operation of a combined cycle, natural gas-fired, electrical power plant. The Osprey Energy Center will generate approximately 527 (nominal) MW under annual average ambient conditions. The Project will include two combustion turbines, two heat recovery steam generators, a steam turbine, exhaust stacks, cooling towers, a treatment and storage system for process water, a treatment system and two retention basins for stormwater, an operations control center, transformers and related switching gear, and other ancillary structures and features. Minimization of Project Impacts The Osprey Project will utilize highly efficient, state-of-the-art design concepts and equipment for the production of electrical power. Every aspect of the construction and operation of the Project has been designed to ensure compliance with all of the applicable land use regulations and to minimize impacts on nearby land uses. Many of the major components of the Project will be located inside an environmental enclosure. The two combustion turbines, the steam turbine, certain water treatment equipment, and some maintenance and operations facilities will be inside a fully-enclosed area. The environmental enclosure will help minimize the impacts of the Project on the surrounding area by reducing ambient sound levels, reducing the amount of contact stormwater generated on the Site, and improving Site aesthetics. In compliance with the City of Auburndale’s landscape regulations, Calpine has prepared and will implement a landscape plan for the Site. The landscape plan will utilize long leaf pine, shumard oak, bald cypress and live oak trees to provide significant visual screening of the Project from adjacent roads and surrounding areas. The landscape plan will include shrubs and ground cover to supplement the proposed arrangement of trees. The Osprey Project will use only natural gas to produce electricity. Natural gas is the cleanest-burning fossil fuel available to generate electricity. A natural gas pipeline will be developed independently and brought to the Site, thus supplementing the natural gas pipelines that are presently available to the Auburndale Power Plant and other nearby industry and businesses. The Osprey Project will not discharge any industrial or domestic wastewater to any surface water or groundwater. Instead, all of the wastewater from the power plant will be discharged to the City’s nearby Allred WWTP for treatment. Treated effluent (reuse water) from the City’s Allred WWTP will be pumped to the Osprey Energy Center for reuse. By using treated effluent, the Project will reduce its use of groundwater. Compatibility With Other Land Uses Because the Osprey Project will use combustion turbines and combined cycle technology to generate electricity, the Project will be more compatible with less intense types of adjacent land uses than a traditional power plant would be. The Project will be more compatible with other land uses because: the Project’s footprint is much smaller than older plants and the entire facility will occupy much less land; (b) the structures used to generate steam and electricity are much smaller and less bulky than older facilities; (c) the Project’s stacks are much smaller than the stacks used at older facilities; (d) the smaller size of the Project allows for the use of an environmental enclosure to minimize sound and other impacts; and (e) the Project is more highly automated than older facilities, thus requiring fewer employees and, as a result, minimizing highway traffic impacts. There are approximately two dozen electrical power plants presently using combustion turbines in combined cycle configuration in Florida. Combustion turbines in combined cycle configuration are currently operated: (a) on the University of Florida’s campus, approximately 800 feet from Shands Hospital; in Walt Disney World, approximately 1400 feet from Cinderella’s Castle in the Magic Kingdom; (c) in Lake Worth, Florida, next to the local high school and within 1/4 mile of downtown Lake Worth; (d) in Umatilla, Florida, between a citrus processing plant and a residential neighborhood; and (e) at the Auburndale Power Plant, immediately adjacent to the Site. These existing facilities demonstrate that a combined cycle power plant can be compatible with less intensive land uses. Existing Land Use Plans and Zoning Ordinances The City of Auburndale fully supports and welcomes the construction of the Project. The City annexed the Site, amended its comprehensive land use plan (“Comprehensive Plan”), and rezoned the Site for the express purpose of allowing the Project to be developed. On February 7, 2000, the City Commission adopted Ordinance No. 995, which annexed the Site into the City from Polk County. The City annexed the Site so that the City could better control the Site’s development. On July 10, 2000, the City Commission adopted Ordinance 999, which amended the future land use designation of the Site under the City’s Comprehensive Plan and future land use map to “Business Park Centers.” On August 28, 2000, the Florida Department of Community Affairs found the City’s designation of the Site for Business Park Centers to be “in compliance” with the requirements of Chapter 163, Part II, Florida Statutes. The City designated the Site for Business Park Centers because, prior to annexation, the Site and the adjacent Auburndale Power Plant were designated “Business Park Center” under Polk County’s comprehensive land use plan. The City’s Comprehensive Plan provides that the City will utilize future land use classifications that are similar to and consistent with the land use designations used by Polk County. Consequently, after the City annexed the Site, the City designated the Site in a manner that was consistent with the County’s prior designation. Further, the City’s designation of the Site as Business Park Centers is consistent with the County’s designation of Business Park Center for the lands located north and east of the Site. For all of these reasons, the Business Park Centers designation for the Site under the City’s Comprehensive Plan is appropriate. Under the City’s Comprehensive Plan, the Business Park Centers designation authorizes light assembly plants as well as warehousing. The activities conducted at the proposed Osprey Energy Center will be consistent and compatible with these types of land uses. Indeed, the existing Auburndale Power Plant operates in a Business Park Center under Polk County’s comprehensive land use plan, thus demonstrating that activities like the ones proposed for the Osprey Project are compatible with the City’s Business Park Centers designation. The City has adopted land development regulations (“LDRs”) that implement the City’s Comprehensive Plan. The City’s LDRs include zoning regulations applicable to this case. On July 10, 2000, the City Commission adopted Ordinance 1000, which changed the zoning classification for the Site to “Light Industrial.” The City’s Light Industrial zoning classification permits light manufacturing, processing, fabricating, storage and warehousing, wholesaling and distribution facilities. The impacts and intensity of land uses associated with the Osprey Project will be comparable to the impacts associated with light manufacturing or processing facilities. Indeed, the Auburndale Power Plant is zoned Light Industrial by Polk County. In contrast to the Light Industrial zoning classification, the City has a Heavy Industrial zoning classification, which allows such uses as chemical plants, pulp and paper mills, and steel mills. A combined cycle, natural gas-fired power plant is smaller and has fewer adverse impacts than the types of uses included in the Heavy Industrial classification. For these reasons, the City’s Light Industrial zoning classification is appropriate for the Osprey Project. The City’s LDRs allow “essential services” to be located in any zoning category if the project is reviewed and approved by the City Commission, and the project is not otherwise prohibited in the applicable zoning category. The City’s definition of “essential services” expressly includes both “structures and uses” for electric facilities. If the City’s LDRs are applied to this case, it is clear that the Osprey Energy Center will provide essential electrical services. The Auburndale City Commission approved the annexation, future land use designation and zoning classification for the Osprey Project. Electrical power plants are not one of the uses prohibited in the City’s Light Industrial zoning category. Thus, the Osprey Project is an allowed and appropriate use in the City’s Business Park Centers land use classification and in the City’s Light Industrial zoning district as an “essential service.” In early 2000, the City of Auburndale’s LDRs included rigorous noise standards that would have been difficult to achieve at the Site for sounds in the high octave ranges. Indeed, the existing ambient noise levels at the Site were not in compliance with the City’s noise regulations. Accordingly, on or about March 31, 2000, a petition for a variance from the City’s noise regulations was filed with the City’s Board of Adjustment. On April 19, 2000, the City’s Board of Adjustment granted a variance for the Osprey Project. The City subsequently repealed its noise standards and replaced them with the Standard Southern Building Code, which the Project can meet. Consequently, a variance for sound is no longer required. Consistency With Land Use Plans and Zoning Ordinances The Site is consistent and in compliance with the City of Auburndale’s comprehensive land use plan. The Site is consistent and in compliance with the City of Auburndale’s LDRs and the applicable zoning classification. Indeed, the City amended its Comprehensive Plan and rezoned the Site specifically to ensure that the Osprey Project would have the appropriate land use designations. The Site is consistent and in compliance with the Central Florida Regional Planning Council’s Regional Plan. The Site also is consistent and in compliance with the State Comprehensive Plan. In the Prehearing Stipulation, the City of Auburndale, Polk County, the Florida Department of Community Affairs, the Central Florida Regional Planning Council, the Florida Department of Environmental Protection, the Florida Department of Transportation, the Florida Public Service Commission, the Florida Fish and Wildlife Conservation Commission and the Southwest Florida Water Management District either agreed with, did not object to, or took no position concerning Calpine’s assertion that the Site is consistent and in compliance with existing land use plans and zoning ordinances. Public Notice of the Land Use Hearing On April 12, 2000, Calpine published a “Notice of Filing of Application for Electrical Power Plant Site Certification” in The Ledger, which is a newspaper of general circulation published in Lakeland, Florida. On April 21, 2000, the Department published a “Notice of Receipt of Application for Power Plant Certification” in the Florida Administrative Weekly. On September 28, 2000, the Administrative Law Judge issued an “Order Granting Continuance and Re-Scheduling Hearing” and served a copy of this Order on all of the parties to this proceeding. The Judge’s Order stated that the Land Use Hearing would be conducted on January 23, 2001. On November 29, 2000, Calpine published a “Notice of Land Use and Zoning Hearing on Proposed Power Plant Facility” in The Ledger. On December 8, 2000, the Department published notice of the Land Use Hearing in the Florida Administrative Weekly. The public notices for the Land Use Hearing satisfy the informational and other requirements set forth in Section 403.5115 and Rules 62-17.280 and 62-17.281(4), Florida Administrative Code. No party to this proceeding or member of the public has alleged that the public notices for the Land Use Hearing were not timely or sufficient.
Conclusions For Petitioner Calpine Construction Finance Company, L.P.: David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 For the Florida Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Tallahassee, Florida 32399
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Land Use Final Order in this case finding that the Site of the Osprey Energy Center is consistent and in compliance with the existing land use plans and zoning ordinances. DONE AND ORDERED this 28th day of February, 2001, in Tallahassee, Leon County, Florida. J. LAWRENCE JOHNSTON Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 28th day of February, 2001. COPIES FURNISHED: David S. Dee, Esquire Landers & Parsons 310 West College Avenue Tallahassee, Florida 32301 Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard The Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 Steven Palmer, P.E. Department of Environmental Protection Office of Siting Coordination 2600 Blairstone Road, Mail Station 48 Tallahassee, Florida 32399 Cari L. Roth, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Suite 315 Tallahassee, Florida 32399-2100 Sheauching Yu, Esquire Department of Transportation 605 Suwannee Street Haydon Burns Building, Mail Station 58 Tallahassee, Florida 32399-0458
Findings Of Fact Upon consideration of the oral and documentary evidence adduced at the hearing, as well as the stipulations of fact entered into by the parties prior to the hearing, the following relevant facts are found: Petitioner Manasota-88, Inc., is a nonprofit corporation organized for the protection of the environment and has members who are residents of Manatee County. This organization filed a timely petition for hearing on the subject November 19, 1980, and January 1981 permit revisions. The intervenor Manatee Energy Company is the owner and operator of a crude oil splitter located in Port Manatee, Manatee County, Florida. This facility is a potential source of air pollutants, received a construction permit in 1978, and is permitted to operate under Permit Number A041-26555 issued by the DER in March of 1980. The intervenor's application to obtain a construction permit indicated a total process input rate of 15,000 to 22,000 barrels per day of crude oil. The splitter was to be fueled by either liquid petroleum gas or fuel oil with a sulfur content of 0.7 percent weight or less. The type of crude oil to be processed was not specified. The application further specified that the maximum heat input rate would be 70 million BTU/hr, and that the normal operating time would be 350 days per year, seven days per week and 24 hours per day. DER's Permit Number A041-26555, which authorized the operation of the crude oil splitter, described the facility as follows: ". . .a Crude Oil Splitter (15,000 BPSD) to separate crude oil by distillation into jet fuel (JP4 and/or Jet A), diesel fuel, and Bunker C. This permit includes the furnaces, boiler, burnoff flare, and storage tanks under the supervision of Manatee Energy. Combustion devices to be fired with LPG or fuel oil with a sulfur content of 0.7 percent or less. Facility located at Port Manatee." This permit also included specific conditions limiting particulate and sulfur dioxide emissions in terms of an amount of emissions per unit of heat input into the furnace and boiler. Because the crude oil splitter operates as a closed system, the heat input to the combustion units--the furnace and boiler-- determines the level of emissions from those sources. During the application and original permit process, Manatee Energy Company did not know the precise quality or grade of crude oil which would be utilized. In the early course of operations, it was discovered that considerably larger volumes of input (as much as 28,000 barrels per day), if processed at the normal design heat input rate, would not result in atmospheric emissions which violated the original permit conditions. For this reason, Manatee Energy Company, by letter dated October 22, 1980, and supplemented by letter dated October 29, 1980, sought a "clarification" in the conditions pertaining to its operating permit. In effect, Manatee Energy Company wanted to know if the original permit allowed a product input of greater than 15,000 barrels per day if other limitations on emissions from the furnace and boiler would not be violated. In support of its request for clarification, Manatee Energy Company submitted data regarding results from emission tests. The information submitted was not on a DER application form and did not include the certification of a professional engineer registered in the State of Florida, DER has subsequently received a letter dated November 22, 1982, from a Florida registered engineer certifying that the data submitted by Manatee Energy Company on October 22 and 29, 1980, was in conformity with sound engineering principles and offering the opinion that current permit conditions would not be violated by the facts submitted. DER responded to the October 22 and 29, 1980, letters from Manatee Energy Company by issuing a revised operating permit on November 10, 1980. This revised permit deleted the prior restriction on product input rate (15,000 barrels per day) contained in the project description and added a specific condition restricting the maximum heat input to the crude oil furnace to 55 million BTU per hour and to the boiler to 15 million BTU per hour. The permit revision issued by DER on November 10, 1980, did not allow a change in the physical premises of the plant, a change in the sulfur content of the fuel, or a change in the amount of heat input to the plant. Consequently, Manatee Energy Company did not request, and the revision did not allow, any additional atmospheric emissions, nor did it allow any increase in emissions which would exceed the limitations imposed in the original operating permit. An increase in the rate at which raw material is processed does not result in an increase in emissions. A cap on the amount of heat input also caps the amounts of emission. Stated differently, if the combustion of the fuel is being held constant by a limitation on the amount of allowable heat input, there will be no increase in emission regardless of the product input rate. The main effect of an increase in product input is on storage. The furnace and the boiler burn the same fuel. Further operating experience revealed that the boiler did not require 15 million BTU of heat input to perform its function, but only required 5 or 6 million BTU depending on the type of oil or other circumstances, such as wind. Manatee Energy Company therefore sought another clarification of the conditions of its operating permit as to the need to have separate allocations of heat input to the furnace and the boiler. In response to this request, DER, by letter dated January 19, 1981, changed the permit conditions by restricting the combined heat input to the furnace and boiler to 70 million BTU per hour, and removing the separate allocations of 55 million BTU/hr for the furnace and 15 million BTU/hr for the boiler. No changes were made to the emissions or the quality of fuel authorized under the original permit. This revision was not preceded by a permit application on a DER form certified by a professional engineer registered in the State of Florida. The level of emission from the furnace and boiler at the heat input capacity of 55 million BTU per hour and 15 million BTU per hour, respectively, would be the same as the level of emission from the furnace and boiler at the combined heat input capacity of 70 million BTU per hour. Therefore, the January 1981 permit revision did not allow emissions in excess of that allowed by the November 1980 permit revision. The 70 million BTU per hour heat input rate to the furnace and boiler specified in the two challenged revisions is the same as that indicated in the construction application submitted by Manatee Energy Company for the crude oil splitter. There being no increases in allowable heat input to the furnace and boiler, there is no increase in pollutant emissions from the two sources. By letter dated July 1, 1982, Manatee Energy Company requested that the storage tanks be deleted from Permit Number A041-26555 for the reason that it no longer contemplated using this previously leased tankage in connection with further refinery operations. By letter dated September 14, 1982, DER informed Manatee Energy Company that its permit was being changed by deleting reference to the storage tanks in the project description and by replacing a condition concerning the storage tanks with the following language: "6. The crude oil splitter cannot be operated unless the necessary storage tanks are in the possession and control of Manatee Energy Company, the tanks meet all Department regulations, and Manatee Energy Company obtains the required permit(s)." This permit revision or modification is not the subject of challenge in the instant proceeding. It is relevant only to illustrate that any issue as to an increase in hydrocarbon discharges resulting from increased production is now mooted, since the storage tanks were the only source of hydrocarbon and volatile organic compound emissions associated with the crude oil splitter.
Recommendation Based upon the findings of fact and conclusions of law recited herein, it is RECOMMENDED that the Intervenor's request for revisions to its Permit Number A041-26555 be GRANTED as proposed by the Department of Environmental Regulation on November 10, 1980, and January 19, 1981. Respectfully submitted and entered this 17th day of March, 1983, in Tallahassee, Leon County, Florida. DIANE D. TREMOR, 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 17th day of March, 1983. COPIES FURNISHED: Thomas W. Reese 123 Eighth Street, North St. Petersburg, Florida 33701 Martha Harrell Hall Assistant General Counsel 2600 Blair Stone Road Tallahassee, Florida 32301 W. Guy McKenzie McKenzie & Panebianco Post Office Box 1200 Tallahassee, Florida 32302 Victoria Tschinkel, Secretary Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32301
