Findings Of Fact On September 12, 1995, Petitioner became a Florida Power customer. He received electricity service in his name at an apartment located at 2950 N. Pinehill Road #31, Orlando, Florida. From September 1994, through December, 1994, Petitioner occupied the apartment at 2950 N. Pinehill Road #31, Orlando, Florida. Petitioner's meter indicated he used 827 Kwh from September 12, 1994, through October 4, 1994. Petitioner's meter indicated he used 1525 Kwh from October 4, 1994, through November 2, 1994. Petitioner's meter indicated he used 1548 Kwh from November 2, 1994, through December 5, 1994. Petitioner's final bill was for December 5, 1994, through December 28, 1994. The meter indicated he used 221 Kwh for this final period. Respondent's tariff sheet 8.05 filed with the Commission sets forth the length of time within which Respondent must disconnect a customer's service after receiving a disconnect order. Respondent must disconnect service within 3 days of receiving the disconnect order. On December 26, 1994, Petitioner requested that his service be disconnected on December 27, 1994. Respondent disconnected Petitioner's service on December 28, 1994. On January 12, 1995, Petitioner's meter was tested in St. Petersburg, Florida. Petitioner's meter registered 99.96 percent accuracy.
Recommendation Based on the foregoing findings of fact and conclusions of law, it is, RECOMMENDED that the Commission enter a Final Order finding that Respondent acted in compliance with applicable law and did not overbill Petitioner. RECOMMENDED in Tallahassee, Leon County, Florida, this 2nd day of January, 1995. DANIEL S. MANRY, Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 2nd day of January, 1995. COPIES FURNISHED: Rodney Gaddy, Esquire Florida Power Corporation 3201 34th Street, South St. Petersburg, Florida 33711-3828 Thomas Fuller Post Office Box 617217 Orlando, Florida 32861 Robert D. Vandiver, General Counsel Florida Public Service Commission Gerald L. Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Noreen S. Davis, Director Division of Legal Services Florida Public Service Commission Gerald L. Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850
The Issue The issues are (1) whether engaging in air conditioning contracting regulated by the Florida Electrical Contractors Licensing Board pursuant to Section 489.500 et seq. Part II, Florida Statutes, constitutes exceeding the scope of one's license as an electrical contractor, (2) whether performing air conditioning contracting in the name of "Dixon's Heating and Air Conditioning" constitutes operating in a name other than the name his electrical contracting license is issued in, contrary to Subsection 489.533(1)(l), and (3) whether Respondent willfully violated the building codes by venting the heater improperly, failing to get a permit and get work inspected.
Findings Of Fact Notice of hearing was given to Respondent at Route 2, Box 595, Yulee, Florida 32097. Arnold Dixon is and has been at all times material to this case a registered electrical contractor, license number ER0004417. (Pet. Ex. 1 & 2) He has maintained his address of record as Route 2, Box 595, Yulee, Florida 32097. (T-Pg. 6) He has held such license since 1976. (Pet. Ex. 1 & 2) Arnold Dixon does not hold a license, a state registration or certification to engage in contracting as a heating or air conditioning contractor. (Pet. Ex. 4 & 6) Arnold Dixon does hold a Nassau County Occupational License as an electrical contractor and as a heating and air conditioning contractor. No check of local records was conducted to see if he had a local license as an air conditioning contractor. (T-Pg. 22) On or about June 1985, the Respondent's company, Dixon's Heating and Air Conditioning, contracted to install an air conditioning and heating unit at the home of John Williams for a contract price of $1985. (Pet. Ex. 5 and T-Pgs. 10 & 11) The work on this contract was done by David Everett, who negotiated the contract. The Respondent's company, Dixon's Heating and Air Conditioning, did not obtain a permit to perform the work at the Williams' residence. Inspections on the Williams' job were not called for by Dixon's Heating and Air Conditioning. Permits and inspections were required by the applicable building code. (T-Pgs. 25 & 26) Entering into a contract to perform air conditioning and heating work and performing such work is air conditioning contracting, which is regulated under Part I, Chapter 489, Florida Statutes. After installation by Dixon's Hearing and Air Conditioning, the Williams' heating system generated carbon monoxide when operating because there was insufficient fresh air being provided to the unit. Because the air intake was in a closet which restricted the air supply to the hot air handling system, the air handling unit sucked fumes from the exhaust side of the unit back through the unit's combustion chamber and circulated it through the house. The longer the unit ran, the more debris was trapped in the louvered door of the closet and the more combustion gases were pulled through the combustion chamber and distributed through the house by the air handling unit. (T-Pg. 34) According to the manufacturer's representative, the hot air return is required to be ducted into the unit. In this case, the return air was pulled from inside a closet which had louvered doors. No duct was used and this installation was not in accordance with the manufacturer's instructions. Although the unit as installed was unsafe and had the potential to kill, no evidence was received that failure to install the unit in accordance with the manufacturer's instructions was a violation of local building code. (T-Pgs. 34- 38) Dixon's Heating and Air Conditioning did not hold itself out to be and was not engaged in electrical contracting in fulfilling the Williams' contract. Dixon's Heating and Air Conditioning did hold itself out to be an air conditioning contractor and the work performed in fulfilling the Williams' contract was air conditioning contracting.
The Issue Whether the Respondent's decision to reject the bid submitted by the Petitioner in response to Invitation to Bid # 03-DC-7514, Maintenance and Repair of Emergency Generators, was contrary to the Respondent's governing statutes, the Respondent's rules or policies, or the specifications in the Invitation to Bid.
Findings Of Fact Based on the oral and documentary evidence presented at the final hearing and on the entire record of this proceeding, the following findings of fact are made: On June 23, 2003, the Invitation to Bid ("ITB") for Bid No. 03-DC-7514 was advertised and also mailed to prospective bidders on the bidding list maintained by the Department. The ITB solicited bids for the maintenance and repair of emergency generators in correctional facilities, and separate bids were to be submitted for Regions I through IV. All Power Generators submitted its bid by the deadline of 2:00 p.m. September 15, 2003, together with four other bidders, including Pantropic. Both All Power Generators and Pantropic bid only on the part of the ITB relating to work in Region IV. When the bids were opened, the annual costs stated by the bidders for each region covered by the ITB were read and recorded. All Power Generators' cost total was lower than that of Pantropic, and All Power Generators was the apparent lowest responsive bidder. After the bids were opened, Department personnel reviewed the cost tabulations to confirm their accuracy and reviewed the other documentation required by the ITB, including the Certification/Attestation for Mandatory Statements, the Certification/Attestation of Executive Summary Statements, and the Bidder's Background Summary, to ensure the bidders' responsiveness to the requirements of the ITB. As a result of this review, the Department's Procurement Manager determined that All Power Generators did not meet the three years' business/corporate experience requirement of the ITB. The Procurement Manager recommended that the contract be awarded to Pantropic, the next lowest bidder. This recommendation was accepted, and the Department noted on the Bid Tabulation form its intent to award the contract for Region IV to Pantropic and its determination that All Power Generators did "not meet required experience criteria." In Section 1.3 of the ITB, "mandatory responsiveness requirements" are defined in pertinent part as follows: "Terms, conditions or requirements that must be met by the bidder to be responsive to this ITB. These responsiveness requirements are mandatory. Failure to meet these responsiveness requirements will cause rejection of a bid. . . ." (Emphasis in original.) Section 4.3.6 of the ITB provides in pertinent part: The Department shall reject any and all bids not meeting mandatory responsiveness requirements. In addition, the Department shall also reject any or all bids containing material deviations. The following definitions are to be utilized in making these determinations: Mandatory Responsiveness Requirements: Terms, conditions or requirements that must be met by the bidder to be responsive to this ITB. These responsiveness requirements are mandatory. Failure to meet these responsiveness requirements will cause rejection of a bid. Material Deviations: The Department has established certain requirements with respect to bids to be submitted by bidders. The use of shall, must or will (except to indicate simple futurity) in this ITB indicates a requirement or condition which may not be waived by the Department. A deviation is material if, in the Department's sole discretion, the deficient response is not in substantial accord with this ITB's requirements, provides an advantage to one bidder over other bidders, has a potentially significant effect on the quantity or quality of items or services bid, or on the cost to the Department. Material deviations cannot be waived and shall be the basis for rejection of a bid. (Emphasis in original.) The Mandatory Responsiveness Requirements are set forth in Section 5.1 of the ITB, which provides in pertinent part: The following terms, conditions, or requirements must be met by the bidder to be judged responsive to this ITB. These responsiveness requirements are mandatory. Failure to meet these responsiveness requirements shall cause rejection of a bid. Any bid rejected for failure to meet responsiveness requirements will not be reviewed. * * * It is mandatory that the bidder sign, have certified by a notary public and return, under Tab 1, the "Certification/Attestation for Mandatory Statements" (ATTACHMENT 1), which includes the following statements: Business/Corporate Experience: A statement certifying that the bidder/contractor has business/corporate experience of at least three (3) years relevant to the provision of generator maintenance and repair, within the last five (5) years. Authority to Legally Bind the Bidder: A statement certifying that the person signing form PUR 7031 [the Bidder Acknowledgment] and all other forms is the person in the bidder/contractor's organization responsible for, or authorized to make, binding decisions as to the prices bid. Juan R. Garcia signed the form PUR 7031 and the Certification/Attestation for Mandatory Statements as President and owner of All Power Generators, and these documents were duly notarized. The Certification/Attestation for Mandatory Statements form signed by Mr. Garcia contains the following statement: "This is to certify that the bidder/contractor has business/corporate experience of at least three (3) years relevant to the provision of generator maintenance and repair, within the last five (5) years." Mr. Garcia also signed the Certification/Attestation of Executive Summary Statements, wherein he certified that "the bidder is a corporation" that is "registered to do business in Florida." Finally, Mr. Garcia completed the Bidder's Background Summary for All Power Generators in which he stated that All Power Generators was established in 2001 as a corporation whose primary business was to service and repair generators. All Power Generators has been doing business for approximately two and one-half years. Mr. Garcia has worked for 21 years repairing and maintaining generators. Prior to organizing All Power Generators, Mr. Garcia was the service manager for a company called Power Depot. His primary job at Power Depot was repairing and maintaining generators, and, among other technical qualifications, he is certified by Kohler to work on the generators it manufacturers. All Power Generators has five employees, including Mr. Garcia, who have between 8 and 22 years' experience maintaining and repairing generators. It is of critical importance that the Department's emergency generators be properly maintained and promptly repaired. When there is a power outage in one of the Department's correctional facilities, emergency generators automatically start and provide emergency power to operate security systems, food service operations, water wells, wastewater plants, and emergency lighting. Under the ITB, response time is 24 hours for non-emergency repairs and four hours for emergency repairs. The bidder/contractor who is awarded the contract to maintain and repair emergency generators used in the correctional facilities must have employees who are technically proficient in maintaining and repairing generators, but, because of the short response time for repairs and the numerous correctional facilities covered by the contract, especially in Region IV,1 the Department requires that the bidder/contractor also have business/corporate experience in managing contracts and coordinating the necessary maintenance, routine repairs, and emergency repairs of the generator systems. The evidence presented by All Power Generators is not sufficient to establish that its bid satisfied the mandatory requirement that the bidder/contractor have a minimum of three years' business/corporate experience. All Power Generators was organized in 2001 and has been in business only two and one-half years. Even though Mr. Garcia has many years of technical experience in the repair and maintenance of generators, All Power Generators does not have the business/corporate experience required by the ITB.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department of Corrections enter a final order denying the bid protest of All Power Generators Corporation and dismissing the Petition filed by All Power Generators Corporation. DONE AND ENTERED this 13th day of January, 2004, in Tallahassee, Leon County, Florida. S PATRICIA HART MALONO 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 13th day of January, 2004.
The Issue The issue to be determined in this case is whether a supplemental site certification should be issued to Lee County for the construction and operation of Unit No. 3 at Lee County's Solid Waste Energy Recovery Facility (Facility), in accordance with the provisions of the Florida Electrical Power Plant Siting Act (PPSA), Sections 403.501 - .518, Florida Statutes. (All statutory references are to the 2002 codification of the Florida Statutes.)
Findings Of Fact The Applicant The Applicant, Lee County, is a political subdivision of the State of Florida. Lee County owns the existing Facility and will own Unit No. 3. The Facility was designed, built and is operated by a private company, Covanta Lee, Inc. (Covanta), pursuant to a long-term contract with Lee County. It is anticipated that Covanta or another private company will design, construct and operate Unit No. 3 for the County. History of the Project In 1985, the Florida Legislature enacted the Lee County Solid Waste Disposal and Resource Recovery Act (the Act), which authorized Lee County to construct, operate, and maintain a solid waste disposal and resource recovery system for the benefit of Lee County's residents. In 1989, pursuant to the Act, Lee County adopted an Integrated Solid Waste Management Master Plan (Plan), which established a comprehensive plan for the management, reuse, recycling and/or disposal of the solid waste generated in Lee County. Lee County's Plan was based on the development of: (a) an aggressive recycling program to reduce the quantity of materials requiring disposal; (b) a waste-to-energy facility for waste reduction and energy recovery from those materials that are not recycled; and (c) a landfill for the disposal of ash and by- pass waste (i.e., materials that are not recycled or processed in the waste-to-energy facility). Lee County has implemented its Integrated Solid Waste Management Plan with innovative approaches and state of the art technology. Lee County has a comprehensive recycling program that handles a wide array of materials, including: (a) waste from residential, commercial, governmental, and institutional facilities; (b) household hazardous waste; (c) yard waste; (d) recovered materials; (e) construction and demolition debris; and (f) electronic waste. Lee County established a recycling and materials separation goal of 40 percent for its residents, even though the State of Florida's goal is 30 percent. From 1993 through 2000, Lee County exceeded the State's 30 percent goal. In 1998, Lee County's recycling rate was approximately 38 percent, which was higher than that of any other county in Florida. Consistent with its Plan, Lee County built a modern landfill, which is equipped with two synthetic liners, two leachate collection systems, and a network of groundwater monitoring wells to ensure the protection of the environment. Lee County's landfill is located in Hendry County, pursuant to an interlocal agreement between Lee County and Hendry County. Under this agreement, the solid waste from both counties is taken to Lee County's Facility for processing and then the ash and by-pass waste are taken to the landfill for disposal. This cooperative, regional approach to solid waste management issues has enabled Lee County and Hendry County to provide environmentally sound, cost-effective programs for the residents of both counties. In 1992, the Governor and Cabinet, sitting as the Siting Board, approved the construction and operation of Units No. 1 and No. 2 at the Facility, and certified an ultimate site capacity of 60 megawatts (MW), based on the operation of three municipal waste combustor (MWC) units. Units No. 1 and No. 2 have been in commercial operation since 1994. Despite Lee County's comprehensive recycling program, the amount of solid waste delivered to the Facility has increased each year since the Facility began operation, primarily due to population growth. In 1999, Lee County's solid waste deliveries were equal to the Facility's guaranteed processing capacity (372,300 tons). In 2000, the Facility processed more than 392,000 tons of solid waste, but the County still had to dispose of nearly 44,000 tons of processible waste in its landfill. Current population projections for Lee and Hendry Counties suggest that the amount of processible solid waste will continue to increase, reaching almost 550,000 tons by 2010. Lee County has decided that it should expand the Facility, consistent with Lee County's long-standing Plan, rather than discard processible waste in a landfill. The Facility was designed to readily accommodate the construction of a third MWC unit. If approved and built, the third unit (Unit No. 3) will be operating at or near its design capacity by 2010 (i.e., within five years after it commences commercial operations). For these reasons, on November 18, 2002, Lee County filed its Supplemental Application with DEP for the construction and operation of Unit No. 3. The Site The Facility is located east of the City of Fort Myers, in unincorporated Lee County. The Facility is approximately 2.5 miles east of the intersection of Interstate-75 and State Road 82, on the north side of Buckingham Road. The County owns approximately 300 acres of land at this location, but only 155 acres (which constitutes the Site) was certified under the PPSA for the Facility. The Site currently includes the Facility, a household hazardous waste drop-off area, a waste tire storage facility, a horticultural waste processing area, and a recovered materials processing facility. A solid waste transfer station is under construction at the Site. Even after the Facility is expanded to accommodate Unit No. 3, approximately 63 percent of the Site will be used solely as buffer and conservation areas. The Surrounding Area There are large buffer areas around the Site. A Florida Power & Light Company (FPL) transmission corridor, containing electric transmission lines, is located along the western boundary of the Site. Approximately three-quarters of a mile to the west of the Site is a limerock, fill, and topsoil mining operation. Immediately north of the Site is approximately 145 acres of undeveloped land owned by the County. A 135-acre County-owned park is adjacent to the Site's eastern property line. Scattered single-family homes are located northeast and farther east of the Site. An adjacent parcel southeast of the Site was previously used as a sanitary landfill (which has been closed and covered), and is now owned by the City of Fort Myers and private individuals who use it for livestock grazing. The land immediately south of the Site is undeveloped. The Gulf Coast Sanitary Landfill is located three miles directly south of the Site. Site Suitability The Site is well-suited for the addition of Unit No. 3. The Site has sizable buffer areas on all sides. Potable water, reclaimed water, and wastewater services are already provided to the Site through existing pipelines. The Facility is near an existing electrical substation (Florida Power & Light Company's Buckingham Substation). An existing electrical transmission line connects the Facility to the substation. Zoning and Land Use In 1991, the Siting Board determined that the Site and Facility are consistent and in compliance with the applicable land use plans and zoning ordinances, based on the construction and operation of three MWC units at the Facility. The Site was zoned for an Industrial Planned Development, and was designated as Public Facilities in the future land use map of Lee County's comprehensive land use plan, specifically to allow the Facility to be built and operated on the Site. The Existing Facility The Facility currently consists of Units No. 1 and No. 2, which have been in commercial operation since 1994. Each MWC unit has a nominal capacity of 600 tons per day (tpd) of solid waste (660 tpd using a reference fuel with a higher heating value of 5000 British thermal units per pound (Btu/lb)). The two MWC units generate steam that is used to drive an electric turbine generator, which generates approximately 39 MW of electricity. The Facility also includes an ash management building, cooling tower, stack, stormwater management ponds, water treatment system, electrical switchyard, electrical transmission lines, and related facilities. Solid waste collection trucks enter the Site from Buckingham Road. They follow an access road to the County's scale house, where the trucks are weighed, and then the trucks are directed to the Facility. The trucks drive inside the Facility and dump the garbage into a refuse pit. A crane mixes the garbage in the pit. The crane then places the garbage in a hopper, which feeds into the combustion chamber where the garbage is burned. The air in the combustion chamber passes through the Facility's air pollution control equipment, and then out the stack. Ash from the combustion process is quenched and then is deposited onto an enclosed conveyor, which takes the ash to an ash management building. The ash then is loaded into trucks and taken to the County's existing landfill in Hendry County. As a result of this process, the amount of fill being taken to the existing landfill is reduced by approximately 90 percent. The New Project-MWC Unit No. 3 The Project involves the construction and operation of a new MWC unit (Unit No. 3) at the Facility. The new unit will be substantially the same as the two existing MWC units. The new unit will have the capacity to process 600 tpd (nominal) of solid waste (660 tpd at 5000 Btu/lb). A new electric turbine generator will be installed and it will generate approximately 20 MW of additional electricity. In addition, the cooling tower will be expanded, the ash management building will be expanded, a lime and carbon silo will be installed, and the new unit may be connected with the two existing units. Construction of Unit No. 3 The Facility was originally designed and built to accommodate the addition of a third MWC unit, thus making the construction of Unit No. 3 relatively simple, without disrupting large areas of the Site. Unit No. 3 will be located adjacent to the two existing MWC units. The expansion of the cooling tower will be adjacent to the existing cooling tower. Construction of Unit No. 3 will occur in previously disturbed upland areas on the Site. Construction of Unit No. 3 will not impact any wetlands or environmentally sensitive areas on the Site. No new electrical transmission lines or improvements will need to be built to accommodate the additional electrical power generated by Unit No. 3. No new pipelines or other linear facilities will need to be built for the Project. Operation of Unit No. 3 The basic operation of the Facility will not change when Unit No. 3 becomes operational. Solid waste will be processed at the Facility in the same way it is currently processed. The Facility has been in continuous operation since 1994, and has an excellent record for compliance with all applicable regulations, including regulations concerning noise, dust, and odors. All of the activities involving solid waste or ash occur inside enclosed buildings. The refuse pit is maintained under negative air pressure, thus ensuring that dust and odors are controlled within the building. Because the operations at the Facility will remain the same after Unit No. 3 becomes operational, no problems are anticipated due to noise, dust or odors. The Facility's basic water supply and management system will remain the same after Unit No. 3 becomes operational. Treated wastewater from the City of Ft. Myers' wastewater treatment plan (WWTP) will be used to satisfy the Facility's need for cooling water. Potable water will be provided to the Facility from the City's water supply plant. On-site wells will be available for emergency water supply purposes; however, the wells have not been regularly used as a source of back-up cooling water since the Facility became operational. The County's water supply plan maximizes the use of reclaimed water and minimizes the use of groundwater. To the extent feasible, the Project uses all of the reclaimed water that is available before it relies on groundwater. The Facility also recycles and reuses water to the greatest extent practicable. Unit No. 3 will not discharge any industrial or domestic wastewater to any surface water or groundwater. Most of the wastewater from the cooling tower will be recycled and reused in the Facility. Any excess wastewater will be discharged to the City of Fort Myers' WWTP. Stormwater runoff from the Project will be collected and treated in the existing system of swales and detention/ retention ponds on the Site. Ultimate Site Capacity The construction of Unit No. 3 will not expand the Facility beyond the boundaries of the Site certified by the Siting Board in 1992. The operation of Unit No. 3, together with the operation of Units No. 1 and No. 2, will not increase the electrical generating capacity of the Site beyond the 60 MW certified by the Siting Board in 1992. Air Quality Regulations The County must comply with federal and state New Source Performance Standards (NSPS) and Best Available Control Technology (BACT) requirements, both of which impose strict limits on the Facility's airborne emissions. The County also must comply with Ambient Air Quality Standards (AAQS) and Prevention of Significant Deterioration (PSD) standards, which establish criteria for the protection of ambient air quality. The addition of Unit No. 3 must undergo PSD review because the Project is a new source of air pollution that will emit some air pollutants at rates exceeding the threshold levels established under the PSD program. PSD review for the Project is required for airborne emissions of particulate matter less than 10 microns in diameter (PM10), MWC metals, MWC organic compounds, MWC acid gasses, sulfur dioxide (SO2), nitrogen oxides (Nox), carbon monoxide, mercury, fluorides, and sulfuric acid mist (SAM). Best Available Control Technology A BACT determination is required for each pollutant for which PSD review is required. BACT is a pollutant-specific emission limit that provides the maximum degree of emission reduction, after taking into account the energy, environmental, and economic impacts and other costs. As part of the BACT determination, all available and feasible pollution control technologies being used worldwide are evaluated. As part of its BACT analyses, DEP determined that a fabric filter baghouse will control the Facility's emissions of particulate matter, a scrubber will control acid gases, a selective non-catalytic reduction system (SNCR) will control NOx, an activated carbon injection system (ACI) will control mercury emissions, and proper facility design and operating methods will control other pollutants. These air pollution control technologies are currently used in Units No. 1 and No. 2, and they have performed extremely well. Units No. 1 and No. 2 are among the best operated and controlled MWC units currently operating in the United States. Unit No. 3 will have better, more modern, and more sophisticated air pollution control systems than Units No. 1 and No. 2. In its PSD analysis for the Project, DEP determined the emission limits for the Project that represent BACT. All of the BACT emission limits determined by DEP for Unit No. 3 are as low as the limits established by the United States Environmental Protection Agency (EPA) in the NSPS (40 CFR 60, Subpart Eb) for new MWC units, based on the use of Maximum Achievable Control Technology (MACT). Indeed, DEP's BACT emission limits for Unit No. 3 are lower than EPA's MACT emissions limits for: (a) particulate matter; (b) sulfur dioxide; (c) carbon monoxide; (d) nitrogen oxides; and (e) mercury. The BACT emission limits, as determined by DEP, are included in the proposed Conditions of Certification for Unit No. 3. The Facility's proposed air pollution control systems are proven technologies that can achieve the proposed BACT emission limits. The Facility will use an array of continuous emissions monitors to help ensure that the Facility is continuously in compliance with the BACT emission limits. Protection of Ambient Air Quality The EPA has adopted "primary" and "secondary" National Ambient Air Quality Standards (NAAQS). The primary NAAQS were promulgated to protect the health of the general public, including the most susceptible groups (e.g., children, the elderly, and those with respiratory ailments), with an adequate margin of safety. The secondary NAAQS were promulgated to protect the public welfare, including vegetation, soils, visibility, and other factors, from any known or anticipated adverse effects associated with the presence of pollutants in the ambient air. Florida has adopted EPA's primary and secondary NAAQS, and has adopted some Florida AAQS (FAAQS) that are more stringent than EPA's NAAQS. Lee County and DEP analyzed the Project's potential impacts on ambient air quality, using conservative assumptions that were intended to over-estimate the Project's impacts by a wide margin. These analyses demonstrate that the maximum impacts from Unit No. 3 will be less than one percent of the amount allowed by the ambient air quality standards. The maximum impact from the Facility (i.e., all three units) will be less than or equal to 1.2 percent of the amount allowed by the FAAQS and NAAQS. Unit No. 3 and the Facility will not cause or contribute to any violations of the FAAQS or NAAQS. The maximum impacts of Unit No. 3 and the Facility, when operating under worst case conditions, will be less than the regulatory levels that are deemed "significant" (i.e., less than the numerical thresholds set by EPA as "significant impact levels"). The Facility's impacts on ambient air quality will be immeasurably small and will be indistinguishable from ambient background conditions. Non-criteria pollutants are substances for which there are no AAQS. The Department's Air Toxics Group has established non-enforceable guidelines known as ambient reference concentrations (ARCs) (also known as "No Threat Levels") for the non-criteria pollutants. DEP believes there is no health or environmental threat associated with ambient air impacts less than the ARCs. In this case, the maximum impacts of the Facility (3 MWC units) will be less than 50 percent of any of DEP's ARCs. For most parameters, the Facility's maximum impacts are less than 10 percent of the applicable ARCs. Other PSD Analyses The PSD program provides protection for those areas that have good air quality. Different areas of Florida have been designated as PSD "Class I" or "Class II" areas, depending upon the level of protection that is to be provided under the PSD program. In this case, the Project is located in a PSD Class II area. The nearest PSD Class I area is the Everglades National Park (Everglades), which is approximately 90 kilometers (km) south-southeast of the Site. The analyses performed by Lee County and DEP demonstrate that the Project's impacts on the ambient air quality in the vicinity of the Site will be insignificant. The analyses performed by Lee County and DEP also demonstrate that the Project's impacts on the ambient air quality in the PSD Class I area at the Everglades will be insignificant. The Project will not significantly affect visibility in the Class I area, regional haze, or other air quality-related values. Compliance With Air Standards Lee County has provided reasonable assurance that the Project will comply with all of the applicable state and federal air quality standards and requirements. Among other things, Lee County has provided reasonable assurance that the airborne emissions from the Project, alone and when operating with the two existing MWC units at the Facility, will not: (a) cause or contribute to the violation of any state or federal ambient air quality standard; (b) cause or contribute to a violation of any PSD increment for any PSD Class I or Class II area; (c) cause any adverse impacts on human health or the environment; (d) exceed any ARC guideline established by DEP for non-criteria pollutants; or (e) cause any adverse impacts to soils, vegetation or wildlife. Lee County also has provided reasonable assurance that Unit No. 3 and the Facility will be able to comply with the Conditions of Certification involving air issues. Human Health and Ecological Risk Assessments As indicated above, the County has performed extensive analyses of the Facility's emissions and impacts to demonstrate compliance with the requirements of state and federal air quality regulations. In addition, the County has taken other measures to address public concerns about the potential impacts associated with the Facility's airborne emissions. In 1992, the County's expert consultants conducted a human health and ecological risk assessment, which evaluated the potential impacts associated with the airborne emissions of mercury and dioxin from the County's Facility. The assessment demonstrated that the operation of the Facility would not adversely affect humans or threatened or endangered species. At the request of the United States Fish and Wildlife Service, the County conducted a supplementary risk assessment in 1992, to more thoroughly evaluate the potential impact of the Facility's mercury emissions on the Florida panther. Among other things, the supplementary assessment evaluated the panther's exposure to mercury through a complex food chain. The County's supplementary assessment confirmed that the Facility would not cause adverse impacts to the panther. The County also initiated a biomonitoring program, which was designed in conjunction with the U.S. Fish and Wildlife Service to identify background concentrations and trends for mercury in key indicator species within the local aquatic environment (i.e., largemouth bass, oysters, and mosquitofish). The County's biomonitoring program was started in 1993, and continued after the County's Facility commenced operations in 1994. The data collected in the biomonitoring program indicate that the mercury concentrations in these key species have not increased as a result of the operation of the Facility. In 2002, the County's consultants completed a new, large-scale, evaluation of the human health and ecological risks associated with the Facility's airborne emissions. The County's 2002 risk assessment evaluated the cumulative impacts of the entire Facility, with all three MWC units in operation. The County's 2002 risk assessment was conducted in compliance with current EPA guidance. The risk assessment considered hypothetical human receptors (e.g., infants, children, and adults) that were engaged in different types of behavior (e.g., a typical resident; a beef farmer; a subsistence fisherman) and were exposed through multiple pathways (e.g., inhalation; ingestion of soil; ingestion of local produce, beef and/or fish) to both acute short-term and chronic long-term impacts from the Facility. The risk assessment was designed to overestimate the potential impacts of the Project, and thus be protective of human health and the environment. The risk assessment relied upon the latest EPA data for mercury, dioxin, and the other chemicals of concern, as set forth in EPA's 1997 Mercury Report to Congress, EPA's 2000 Dioxin Reassessment, and other relevant documents. The County's 2002 risk assessment demonstrates that the Facility's airborne emissions will not measurably increase the typical concentrations of chemicals in the environment. For example, even at the point of maximum impact, the maximum environmental mercury and dioxin concentrations associated with the operation of the Facility will be far below the levels that are typically found in the environment and they will be immeasurably small. The County's 2002 risk assessment also demonstrates that the potential risks associated with the Facility's emissions will not exceed, and in most cases will be much less than, the risks that are deemed acceptable by the EPA and DEP for the protection of human health and the environment. The County's findings are consistent with the findings in environmental monitoring studies and risk assessments that have been performed for other modern waste-to-energy (WTE) facilities in the United States. Indeed, the environmental monitoring studies conducted at similar WTE facilities have shown that risk assessments, like the ones performed for Lee County, overestimate the actual impacts. In light of the evidence presented by the County in this case, the Facility should not have any measurable effect on human health or the environment, even when all three MWC units are operational. Other Potential Environmental Impacts The County's 2002 risk assessment primarily focused on the Facility's maximum impacts under worst case operating conditions. The maximum concentrations in the ambient air and the maximum deposition rates resulting from the Facility's mercury emissions will occur within 2.5 km (approximately 1.5 miles) of the Site. The ambient air concentrations and deposition rates at all other locations beyond the Site will be even lower. EPA studies of similar facilities have shown that mercury deposition rates decrease at least 100 times (i.e., by a factor of 100) within the first 10 km. In this case, the nearest portions of the Everglades are approximately 90 km from the Site. Moreover, the generally prevailing winds at the Site blow toward the Gulf of Mexico, not toward the Everglades. Approximately 90 percent of the time, the wind does not blow from the Site toward the Everglades. For these and other reasons, the Facility's mercury emissions will have an insignificant impact on the Everglades. The Facility's emissions of nitrogen oxides (i.e., NOx) will not cause or contribute to violations of any water quality standards in any surface waterbody. Environmental Benefits of the Project The addition of Unit No. 3 will provide significant environmental benefits to Lee County and Hendry County. The solid waste processed by Unit No. 3 will reduce the volume of processible solid waste by approximately 90 percent. By reducing the volume of processible waste, the Facility will significantly extend the useful life of the Lee County/Hendry County regional landfill, effectively postponing the need to build a new landfill in Lee County or Hendry County. The Project will also provide environmental benefits to the State of Florida. For example, the Facility will produce approximately 1.88 billion kilowatt-hours of electricity from discarded materials during the next 20 years. In this manner, Unit No. 3 will reduce the need to use fossil fuels to generate electricity at traditional power plants. Unit No. 3 will eliminate the need to use approximately 5.54 million barrels of oil, and thus will save approximately $150 million in oil purchases over the next 20 years. In addition, the County will recover ferrous and non-ferrous metals from the Facility's ash, thus recycling resources that otherwise would be buried with the County's solid waste in a landfill. Socioeconomic Benefits of the Project The local economy and labor market will benefit from approximately $70 million that Lee County will spend to construct the Project. A significant amount of construction supplies, such as concrete, structural steel, glass, piping, fittings, and landscape materials, are anticipated to be purchased from local businesses. The Project will provide jobs for over 125 construction workers during the peak of construction activities. The addition of Unit No. 3 will also provide approximately nine new permanent jobs at the Facility, with an increase in the Facility's annual payroll of approximately $400,000. WTE Criteria in Section 403.7061 Section 403.7061, Florida Statutes, establishes several criteria that must be satisfied before an existing waste-to- energy facility may be expanded. Lee County has provided reasonable assurance that the Project will satisfy all of the standards and criteria in Section 403.7061, Florida Statutes. Among other things, the County has demonstrated that Lee County's waste reduction rate will exceed 30 percent when Unit No. 3 begins operation. Compliance with Environmental Standards Lee County has provided reasonable assurance that the Project will comply with all of the nonprocedural land use and environmental statutes, rules, policies, and requirements that apply to the Project, including but not limited to those requirements governing the Project's impacts on air quality, water consumption, stormwater, and wetlands. The location, construction, and operation of the Project will have minimal adverse effects on human health, the environment, the ecology of the State's lands and wildlife, and the ecology of the State's waters and aquatic life. The Project will not unduly conflict with any of the goals or other provisions of any applicable local, regional or state comprehensive plan. The Conditions of Certification establish operational safeguards for the Project that are technically sufficient for the protection of the public health and welfare, with a wide margin of safety. Agency Positions and Conditions of Certification On December 11, 2001, the PSC issued an order concluding that the Project was exempt from the PSC's "determination of need" process, pursuant to Section 377.709(6), Florida Statutes. DEP, DOT, DCA, and SFWMD all recommend certification of the Project, subject to the Conditions of Certification. The SWFRPC determined that the Project is "Regionally Significant and Consistent with the Regional Strategy Plan," but did not recommend any conditions of certification for the Project. Lee County has accepted, and has provided reasonable assurance that it will comply with, the Conditions of Certification.
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order granting a supplemental site certification for the construction and operation of Unit No. 3 at the Lee County Solid Waste Energy Recovery Facility, in accordance with the Conditions of Certification contained in Appendix 1 to DEP Exhibit 2. DONE AND ENTERED this 19th day of August, 2003, in Tallahassee, Leon County, Florida. S _________________________________ RICHARD A. HIXSON 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 19th day of August, 2003.
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 determined is whether the Governor and Cabinet, sitting as the Siting Board, should approve the Site Certification Application ("Application") submitted by Florida Power & Light Company ("FPL"), pursuant to the Florida Power Plant Siting Act ("PPSA"), sections 403.501 through 403.518, for the construction and operation of a new electrical power generation facility, Dania Beach Energy Center ("DBEC") at FPL's existing Lauderdale Site in Broward County, Florida; and, if so, the Conditions of Certification that should be imposed.
Findings Of Fact The Parties FPL is the applicant for site certification for the DBEC electrical power plant5/ at issue in this proceeding. FPL is the largest electric utility in Florida, serving approximately 4.9 million customer accounts. Its service territory covers approximately 28,000 square miles, in all or part of 35 counties in Florida, and in Georgia. Its 53 existing electrical power generating units are located at power plants throughout its service territory, and consist of diverse generation technologies, including nuclear units, coal-burning units, combined cycle units, oil/gas steam units, combustion turbines, gas turbines, and solar facilities. As of December 2016, FPL had a total system electrical power generation capacity of 26,267 megawatts ("MW"). DEP is the state agency charged with administering the PPSA, which is codified at chapter 403, part II. Specifically, the SCO administers the PPSA and coordinates the site certification process, including receiving comments from the affected agencies and preparing the PAR, which contains the proposed Conditions of Certification.6/ Sierra is a national non-profit environmental advocacy organization. A key component of Sierra's mission is to advocate for the use of clean energy sources. As discussed below, Sierra was granted intervenor status pursuant to section 403.508(3)(e), subject to proving that its substantial interests are affected in this proceeding. The DBEC Electrical Power Plant FPL's Lauderdale Site FPL owns and operates the Lauderdale Site, an existing electrical power generating facility site located on approximately 392 acres in the City of Dania Beach and the City of Hollywood, in Broward County, Florida. The Site is approximately one mile west of Interstate 95 and approximately 1/4 mile south of Interstate 595. It has served as an operating power plant site for more than 90 years, and has existing infrastructure consisting of a transmission switch yard, a gas yard, an existing gas transmission pipeline, an existing electrical transmission system, water lines, fuel storage tanks, and a sewer line. Currently, the Lauderdale Site features five electrical power generation units: Units 4 and 5, which consist of four combined cycle units comprised of four 1990s-vintage combustion turbines ("CTs"), four heat recovery steam generators ("HRSGs"), and two 1950s-vintage steam turbines; Unit 6, which consists of five 200-MW single cycle CTs used as "peakers" to generate additional electrical power during periods of peak demand; and two 35 MW units. Location of DBEC DBEC is proposed to be constructed on the portion of the Lauderdale Site that is located within the City of Dania Beach. The City of Dania Beach recently amended its Comprehensive Plan to add the Electrical Generation Facilities use category to the Future Land Use Element and to so designate, on its Future Land Use Map, the portion of the Lauderdale Site on which DBEC will be constructed. DBEC is proposed to be constructed and operated on the portion of the Lauderdale Site on which Units 4 and 5 currently are located. These units will be completely dismantled and removed before construction of DBEC commences.7/ DBEC will use much of the existing infrastructure that currently serves Units 4 and 5. This infrastructure includes existing fuel and storage tanks, an existing gas transmission pipeline, existing electrical transmission lines, existing cooling water intake at the Dania Cutoff Canal, and existing cooling water discharge structures. The major new components of DBEC will be constructed at an elevation of 11.5 feet above mean sea level. The existing infrastructure that will be used by DBEC will not be raised above its current elevation above mean sea level. Unit 7 Technology Unit 7, as proposed, will consist of a new two-on-one combined cycle electrical power generation unit with a nominal rating of 1,200 MW. A combined cycle electrical generation system generates electrical power in two cycles. In the first cycle, ambient air is drawn into the multistage compressor, where it is compressed, then directed to the combustor section, where fuel——in this case, natural gas——is introduced, ignited, and burned. The hot combustion gases are diluted with additional cool air and directed to the turbine section, where they expand, causing the CT, which is connected to a generator, to rotate, producing electricity. The captured gases are then routed to a HRSG, which begins the second cycle. In this cycle, the heat from the captured gases is used to convert water to steam, which drives a steam turbine generator ("STG"), producing additional electricity. Each CT/HRSG combination is termed a "train." Unit 7 will have two CT/HRSG trains, each having a gross generation capacity of 400 MW at an inlet air temperature of 75 degrees Fahrenheit. These two CT/HRSG trains will be connected to one STG having a generation capacity of 400 MW. The combination of the two CT/HRSG trains with one STG gives rise to the "two-on-one combined cycle" label for this type of power generation unit. Combined cycle systems, such as the one that will constitute Unit 7, are significantly more efficient than single cycle units that involve only combustion turbines. This increased efficiency is due to the addition of the second cycle, which uses captured exhaust heat from the first cycle to create steam, which is then used to turn a steam turbine, thereby generating an additional 400 MW of electricity per total amount of fuel burned. Operating efficiency for combined cycle units is measured in terms of "heat rate," which is an expression of how efficiently the fuel is converted to electrical energy. The lower the heat rate, the more efficient the electrical power generation unit. Unit 7 is a modern combined cycle plant and is expected to achieve a heat rate of approximately 6,119 British Thermal Units ("BTUs") per kilowatt hour. By contrast, Units 4 and 5——which are also combined cycle units but use older, less efficient equipment——have an average heat rate of approximately 7,800 BTUs per kilowatt hour. As noted above, Unit 7 will use natural gas as its primary fuel. The natural gas will be delivered to the DBEC site through an existing natural gas pipeline, which originates offsite and is not part of this site certification proceeding.8/ Ultra-low sulfur distillate ("ULSD") oil will be used as the back-up fuel. Unit 7 Effect on FPL System-wide Natural Gas Consumption As noted above, Unit 7 will use the most modern combined cycle technology. Dr. Steven Sim, FPL's director of Integrated Resource Planning, prepared a projection of the effect Unit 7 will have on natural gas consumption by FPL's electrical power generation units on a system-wide basis. Using a model that simulates the operation of all electrical generating units on FPL's system, FPL compared, for natural gas fuel consumption on a system-wide basis, two scenarios: one in which Units 4 and 5 continue to operate indefinitely and Unit 7 is not constructed and operated; and one in which Units 4 and 5 are retired in the fourth quarter of 2018, and Unit 7 is constructed and commences operation in mid-2022. The inputs to the model included a range of information, including the electrical load that FPL will serve in the future, on an hourly, monthly, and yearly basis, for a period of 30 years; information, for each of FPL's 53 electrical power generation units regarding individual generating capacity, fuel use efficiency, scheduled maintenance outages, and forced outages; fuel costs; environmental compliance costs; and the addition of other power-generation resources to meet future forecasted demand. The model was used to determine which of FPL's generating units operate during each hour, in order to determine how to most economically generate electrical power. The model projected a significant reduction in natural gas consumption by FPL on a system-wide basis over a 30-year horizon if Units 4 and 5 are retired in late 2018 and Unit 7 commences operation in 2022. Conversely, if Units 4 and 5 are not retired and continue to operate9/——which will be the case if Unit 7 is not certified——the model showed that FPL will consume substantially more natural gas on a system-wide basis over a 30- year horizon, from 2018 through 2047, than if Unit 7 is certified, constructed, and begins operating in 2022. Assuming Units 4 and 5 are retired in 2018 and Unit 7 commences operation in 2022, the model-generated comparative natural gas consumption amounts shows a consistent system-wide decrease in natural gas consumption in amounts ranging from slightly over two million cubic feet per year to slightly over six million cubic feet per year, for a projected total decrease in system-wide natural gas consumption of nearly 134 million cubic feet over the 30-year horizon. This is because the operation of Unit 7 will displace less-efficient gas burning units that otherwise would be used if Unit 7 does not operate. Further, because the model-generated projected natural gas consumption amounts simply compared the "with Units 4 and 5 and without Unit 7" scenario to the "without Units 4 and 5 and with Unit 7" scenario, with all other variables being held constant, the projected natural gas consumption differential between the two scenarios would not change, regardless of whether, and which, additional types of energy-generation resources were added to FPL's system. Dr. Sim acknowledged that the social costs of carbon were not considered as part of the modeling of FPL's system-wide projected natural gas consumption. However, he noted that as a practical matter, because Unit 7 will operate more efficiently, FPL will demand less natural gas on a system-wide basis to fuel its electrical power generating units. As a result of reduced demand, less natural gas will need to be produced and transported by pipeline to fuel FPL's electrical power plant generating system. Public Service Commission Need Determination Pursuant to section 403.519, FPL filed a petition for determination of need for DBEC with the PSC in October 2017. Sierra intervened into the need determination proceeding. The final hearing was held on January 17, 2018. The PSC issued the Need Determination for DBEC Unit 7 on March 19, 2018. This Order, which constitutes final agency action, was not appealed. During the need determination proceeding, Sierra contended, and presented evidence in an effort to show, that renewal energy sources and technologies, such as solar facilities, could be deployed incrementally to delay or potentially entirely forestall the need for Unit 7. Thus, as part of the need analysis, the PSC specifically considered the feasibility of using renewable generation options and sources, including solar facilities. The PSC specifically determined that the use of such generation options and sources, including solar facilities, was less cost-effective than DBEC. The PSC found that: "[n]o additional cost-effective renewable resource has been identified in this proceeding that can mitigate the need for new generation. Similarly, no additional cost-effective [Demand Side Management] has been identified in this proceeding that can mitigate the need for new generation." Based on the evidence and argument presented in the need determination proceeding, the PSC granted the Need Determination for DBEC Unit 7, specifically finding and concluding that "the Dania Beach Clean Energy Center Unit 7 is the most cost-effective alternative that maintains Florida Power & Light Company's system and Southeastern Florida area reliability compared to other alternatives[.]" Section 403.519(3) states: The commission shall be the sole forum for the determination of [need], which accordingly shall not be raised in any other forum or in the review of proceedings in such other forum. In making its determination, the commission shall take into account the need for electric system reliability and integrity, the need for adequate electricity at a reasonable cost, the need for fuel diversity and supply reliability, whether the proposed plant is the most cost-effective alternative available, and whether renewable energy sources and technologies, as well as conservation measures, are utilized to the extent reasonably available. The commission shall also expressly consider the conservation measures taken by or reasonably available to the applicant or its members which might mitigate the need for the proposed plant and other matters within its jurisdiction which it deems relevant. The commission's determination of need for an electrical power plant shall create a presumption of public need and necessity and shall serve as the commission's report required by s. 403.507(4). An order entered pursuant to this section constitutes final agency action. § 403.519, Fla. Stat. (emphasis added). Pursuant to this statute, the PSC is the only entity authorized to determine whether an electrical power plant is needed, and whether, given the need for the power plant, the applicant should be required to implement renewable energy sources and technologies, including the use of solar generation facilities. Here, the PSC determined that DBEC is needed, and further determined that the use of renewable energy sources and technologies, such as solar technology, was not cost-effective, and, therefore, was not reasonably available. Pursuant to the plain language of section 403.519(3), it is beyond the scope of this proceeding for the undersigned or the Siting Board to require, as a condition of site certification for DBEC, the use of alternative energy sources or technologies, such as solar or other forms of renewable energy, or to deny DBEC's site certification on the basis that such technologies are not proposed as part of the project. DBEC Emissions and Air Construction/Prevention of Significant Deterioration Permit Florida's Air Quality Regulatory Program In Florida, DEP implements the federal air regulatory programs under the Clean Air Act, subject to approval and oversight by the United States Environmental Protection Agency ("EPA"). Under this system, DEP is the permitting authority, while EPA retains commenting authority. DEP rules implementing the Clean Air Act consist of several air quality regulatory programs. Pertinent to this proceeding are the National Ambient Air Quality Standards ("NAAQS") and Prevention of Significant Deterioration ("PSD") programs. Under the Clean Air Act, EPA is required to promulgate NAAQS for certain air pollutants called "criteria" pollutants. The primary NAAQS establish levels of air quality that are necessary to protect the public health, with an adequate margin of safety to protect sensitive populations. Secondary NAAQS also may be established to protect the public welfare, which can include environmental impacts. 40 C.F.R. § 50.2(b). NAAQS have been developed for six air pollutants: sulfur dioxide, nitrogen dioxide, carbon monoxide, ozone, certain sizes of particulate matter, and lead. NAAQS have not been established for greenhouse gases ("GHGs"). For each of the six criteria air pollutants for which NAAQS have been developed, EPA has designated areas within each state that either meet or do not meet the NAAQS for that specific pollutant. Areas in which the NAAQS for a specific criteria air pollutant is met are termed "attainment" areas for that pollutant, while areas in which the NAAQS is not met for a specific criteria pollutant are termed "nonattainment" areas for that pollutant. Attainment areas are classified as Class I, which need special air quality protection; or Class II, which do not need special air quality protection. Everglades National Park and designated national wilderness areas are the only Class I attainment areas in Florida. All other attainment areas in Florida are designated as Class II. Broward County, including the DBEC site, is in a Class II attainment area for all NAAQS. The PSD program applies in attainment areas to limit the air quality impacts that may result from new or modified major sources of air pollution. Its purpose is to assure that the air quality in areas meeting the NAAQS does not significantly deteriorate below an established baseline. Under the PSD program, all major new sources of air pollution are subject to preconstruction review to determine whether significant air quality deterioration will result from the facility. As part of the PSD review, the new source is required to demonstrate compliance with PSD increments, which effectively constitute small amounts of air quality impacts that new or modified major sources of air pollution cannot exceed. PSD increments are more stringent than NAAQS, and, as such, they protect against air quality degradation in attainment areas. If an area meets the NAAQS for a specific criteria pollutant, PSD increments prevent the addition of that pollutant in greater than that incremental amount over an established baseline concentration for that pollutant. No PSD increments have been established for GHGs. The PSD program also requires demonstration that the air pollution source will use the Best Available Control Technology ("BACT"). BACT is defined, in pertinent part, as: an emission limitation based on the maximum degree of reduction of each pollutant subject to regulation under this chapter emitted from or which results from any major emitting facility, which the permitting authority, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant. 40 U.S.C. § 7479(3). More simply stated, BACT is the maximum degree of emission reduction that is available and feasible for the source, taking into account environmental, energy, economic impacts, and other costs. BACT requires a "top-down" analysis, which starts with the most stringent emission limits demonstrated feasible for a specific air pollution source category, as applied throughout the country. EPA has created a software tool accessible on its website, that enables a review of different source categories to determine the most stringent applicable control technology that meets the definition of BACT for that particular source type. BACT also must be at least as stringent as new source performance standards ("NSPS"), which are EPA-developed emissions limits for specific pollutants emitted by new or modified air pollution sources within a particular source category. The NSPS applicable to combined cycle combustion turbines, such as those that will comprise Unit 7, are nitrogen oxides, sulfur dioxide, and GHGs. DBEC Emissions DBEC will have several sources of air emissions. These consist of the two CTs that are part of the CT/HRSG trains discussed above; an auxiliary boiler; two emergency diesel generators, two natural gas heaters; a fire water pump diesel engine; a 14-cell auxiliary cooling system; and circuit breakers containing sulfur hexafluoride located in the Unit 7 power block. Of these, the CTs constitute the most significant air emissions source. DBEC's air emissions sources will emit nitrogen oxides, carbon monoxide, volatile organic compounds, sulfur dioxide, sulfuric acid, particulate matter ("PM") 10 and PM2.5, and GHGs. The GHGs emitted by DBEC will consist primarily10/ of carbon dioxide, with small amounts of methane.11/ DBEC's Air Construction/PSD Permit FPL applied to DEP for an air construction/PSD permit for DBEC in July 2017. DEP issued the air construction/PSD permit for DBEC ("Air Permit") in December 2017. The Air Permit was not challenged and became final agency action on December 24, 2017. It is valid through December 31, 2027. Pursuant to section 403.509(5), the Air Permit is not subject to revision or modification in this proceeding.12/ Because DBEC will emit 100 tons per year or more of regulated pollutants and is included in a source category to which the 100-tons-per-year threshold applies, it constitutes a major stationary source of air pollution. See Fla. Admin. Code R. 62-210.200(154)(a)1. Therefore, under Florida and federal law, FPL was required to obtain an air construction/PSD permit for DBEC. As part of the PSD review, FPL was required to perform a control technology review; to demonstrate that all applicable state and federal emission limiting standards would be met; and to determine and implement BACT to control the emissions. Projected emissions of carbon monoxide, volatile organic compounds, sulfur dioxide, sulfuric acid, PM10 and PM2.5, and GHGs underwent PSD review. Initial PSD modeling for projected carbon monoxide and sulfur dioxide emissions showed that these emissions would not exceed "significant impact levels," so no further review beyond the modeling was required. Initial modeling showed that PM10 and PM2.5 emissions would exceed the "significant impact level," so the modeling results were compared to the Class I and Class II PSD increments. This comparison showed that neither PM10 emissions nor PM2.5 emissions would exceed the increments for these pollutants. Accordingly, FPL demonstrated that DBEC would comply with the incremental standards for these pollutants. DBEC also meets BACT for volatile organic compounds emissions. The primary BACT for GHG emissions for Unit 7, as a combined cycle unit, is the efficiency of the unit itself in producing electrical power using low-GHG emitting fuels, such as natural gas. As previously discussed, Unit 7 will be an extremely efficient combined cycle unit that will use natural gas as its primary fuel. The Air Permit limits the emissions rates for, and amounts of, GHG emissions. These are consistent with BACT, as determined comparing DBEC's control technology to all other types of GHG control technology for CTs throughout the country. The Air Permit also imposes an extremely stringent methane monitoring requirement. Pursuant to these measures, DBEC was determined to meet the BACT requirement applicable to GHGs.13/ Additionally, DBEC will meet the NSPS applicable to CTs.14/ Specifically, DBEC emissions of nitrogen oxides will be 7.5 times lower than the NSPS limit for that pollutant, and DBEC emissions of sulfur dioxide will be ten times lower than the NSPS standard for that pollutant. Accordingly, DBEC will meet the NSPS for these pollutants. DBEC also will meet the applicable NSPS for GHGs.15/ The NSPS for GHG emissions applicable to combined cycle CTs is 1,000 pounds per MW hour ("lbs/MWh"). DBEC is projected to produce 727 lbs/MWh of GHGs when burning natural gas——well below the 1,000 lbs/MWh NSPS limit. The Air Permit also imposes emissions standards for carbon monoxide, PM10 and PM2.5, sulfur dioxide, sulfuric acid mist, volatile organic compounds, and GHGs. The competent, credible evidence established that replacing Units 4 and 5 with Unit 7 will reduce the emissions of nitrogen oxides, PM10 and PM2.5, volatile organic compounds, sulfur dioxide, and carbon monoxide by approximately 6.6 million pounds for the period from 2018 to 2047. The evidence also established that replacing Units 4 and 5 with Unit 7 is projected to result in an approximately 22-percent reduction in GHGs generated, measured in lbs/MWh, assuming Unit 7 is operated at the same frequency as Units 4 and 5. This comparative reduction in GHG emissions on a lbs/MWh basis underscores the efficiency of Unit 7 compared to Units 4 and 5. Additionally, the credible evidence established that the operation Unit 7 will result in a system-wide reduction of GHG emissions for the period from 2018 to 2047.16/ The retirement of Units 4 and 5 in 2018 and commencement of operation of Unit 7 in 2022 may not result in reduced total amounts of GHG emissions generated at the Lauderdale Site. This is because even though Unit 7 is substantially more efficient than Units 4 and 5——so will burn substantially less natural gas——it may operate more often because it will be the most efficient electrical power generating unit in FPL's electrical power generation system. However, the competent, credible evidence showed that the operation of Unit 7 will reduce GHG emissions across FPL's electrical power generating system because it will be operated more often than other, less efficient units, thereby displacing the use of those units across FPL's electrical power generation system. Stated another way, because Unit 7 will be a significantly more efficient electrical power generating unit—— meaning that it will produce more electricity per cubic foot of natural gas than FPL's less efficient units——it will be operated more frequently than FPL's less efficient units, resulting in reduced consumption of natural gas on a system-wide basis. Reduced natural gas consumption on a system-wide basis will result in a reduced total amount of GHGs generated on a system-wide basis from FPL's electrical power generating plants. The competent, credible evidence establishes that the retirement of Units 4 and 5 in 2018 and the addition of Unit 7 in 2022 will result in a total reduction of approximately 8.1 million tons17/ of GHG emissions in the form of carbon dioxide18/ across FPL's electrical power generation system for the period from 2018 to 2047.19/ Sierra contends that DBEC will "[e]mit millions of tons more [GHGs] every year than the units it replaces." As discussed above, the evidence shows that the operation of Unit 7 in conjunction with the retirement of Units 4 and 5 in 2018 may not result in reduced GHG emissions at the Lauderdale Site because, due to its efficiency, Unit 7 may be operated more frequently and at higher capacity. However, the competent, credible, and persuasive evidence establishes that the total GHG emissions from FPL's electrical power plant generating units will be reduced on a system-wide basis by approximately 8,123,624 tons over the period between 2018 and 2047. Further, Sierra's position that retiring Units 4 and 5 in 2018 and operating Unit 7 beginning in 2022 will result in a greater total amount of GHGs being emitted appears grounded in the assumption that if Unit 7 does not go into operation, FPL will retire Units 4 and 5 by 2033. However, this assumption is not supported by any competent substantial evidence in the record,20/ and was directly contradicted by Dr. Sim, who testified that Units 4 and 5 realistically could operate indefinitely. In sum, the competent, credible, and persuasive evidence shows that if DBEC does not commence operation in 2022, and Units 4 and 5 continue to operate indefinitely, FPL's GHG emissions on a system-wide basis will be approximately 8,123,624 tons more for the period between 2018 and 2047 than if Units 4 and 5 are retired in 2018 and Unit 7 commences operation in 2022. In sum, FPL demonstrated that DBEC meets all applicable state and federal air regulatory and permitting requirements for DBEC and, specifically, for Unit 7. As discussed above, FPL demonstrated that DBEC will meet the applicable BACT requirement——which literally means the best available control technology——for GHG emissions, as well as other emissions from Unit 7 and other emissions sources. Additionally, the air construction/PSD permit establishes emissions limits for DBEC, and, specifically, for Unit 7, and FPL demonstrated, to DEP's satisfaction, that its emissions control technology will meet the applicable standards, which are more stringent than applicable NSPS limits. Thus, FPL demonstrated that DBEC will meet state and federal law regarding emissions limitations for GHGs and other pollutants emitted by DBEC. Sierra's Contentions Regarding GHG Emissions from DBEC Notwithstanding that FPL demonstrated that DBEC meet all applicable air rules and regulations, Sierra contends that the Siting Board should either deny the site certification for DBEC or approve it with conditions (addressed below) because, it alleges, FPL and/or DEP failed to consider or address numerous environmental issues regarding projected GHG emissions for DBEC. These alleged deficiencies are: failure of FPL and/or DEP to perform modeling of the "the environmental impact" of DBEC's GHG emissions; failure of FPL and/or DEP to analyze the "social costs of carbon" emitted by DBEC; failure of FPL and/or DEP to perform a "life-cycle analysis" to analyze DBEC's GHG emissions "from start to finish, . . . from gas generation to gas burn"; failure of FPL and/or DEP to consider the cumulative impacts of DBEC's emissions combined with GHG emissions "from other existing and foreseeable permitted sources in Florida and elsewhere"; and failure of FPL and/or DEP to consider the use of solar electrical power generation.21/ Each of these challenges is addressed below. Failure to Model Endpoint Environmental Impact With respect to FPL's and/or DEP's alleged failure to perform modeling of "the environmental impact" of DBEC's GHG emissions, the evidence establishes that FPL and DEP complied with the applicable state rules and federal regulatory requirements in addressing GHG emissions from DBEC. To that point, Syed Arif, who performed the air construction/PSD permit application review, testified that modeling of the environmental impacts of DBEC's projected GHG emissions offsite was not performed because it is not required by the applicable state rules and federal regulations. Indeed, EPA's PSD Guidance document22/ specifically states that "[w]hen conducting a BACT analysis for GHG's, the environmental impact analysis should continue to concentrate on impacts other than direct impacts due to emissions of the regulated pollutant in question." This document further states, in pertinent part: When weighing any trade-offs between emissions of GHGs and emissions of other regulated NSR pollutants, EPA recommends that permitting authorities focus on the relative levels of GHG emissions rather than the endpoint impacts of GHGs. As a general matter, GHG emissions contribute to global warming and other climate changes that result in impacts on 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. EPA PSD Guidance, at pp. 41-42 (emphasis added). In sum, state and federal PSD permitting law does not require an analysis of endpoint impacts of GHGs, and, further, expressly recognizes that due to the global scope of GHG emissions' contribution to climate change, climate change modeling and risk/impact evaluation of GHG emissions is conducted on a scale orders of magnitude larger than the emissions from individual projects. Additionally, the guidance expressly recognizes that determining the exact climate change impacts due to GHGs emitted on a source-specific basis is not currently possible with climate change modeling. Sierra's contention that the site certification for DBEC should be denied or additional GHG-related conditions imposed due to project-specific environmental endpoint impacts is not persuasive, because it is not grounded in applicable law and, as discussed above, is not possible using current climate change modeling. Failure to Consider and Address Social Costs of Carbon Sierra also contends that the site certification for DBEC should be denied or additional GHG-related conditions imposed because FPL and/or DEP failed to analyze the social costs of carbon emitted by DBEC, particularly by Unit 7, and failed to mitigate or minimize those costs. The social cost of carbon is defined as the present monetary value of the additional damages caused by emitting one more ton of carbon dioxide. In general terms, the social cost of carbon is the economic cost per ton of emissions. For each incremental ton of carbon emissions, there is an incremental amount of harm. There are different methods, or models, for determining the social cost of carbon. They vary depending on the types of data used in the model, as well as how the models address issues such as the rate of climate change; whether the models adequately and accurately address catastrophic risk; and whether the models address "tipping points" at which climate change becomes abruptly and irreversibly worse. Sierra's expert on the social cost of carbon, Dr. Frank Ackerman,23/ presented the results of integrated assessment models used to estimate the social cost of carbon.24/ These types of models have been applied in various studies to estimate, in 2017 dollars, the cost per metric ton of carbon dioxide. These studies generated estimates of the social cost of carbon ranging from as low as $39 per metric ton in 2020 to as high as $1,821 in 2050, with each study generating a range of projected values for the first year modeled——either 2020 or 2025——through the last year modeled——either 2050 or 2055. These widely-ranging values for the modeled years over these 30-year periods are due to the substantial uncertainty and disagreement regarding the rate and extent of climate change, and whether there are tipping points that must be taken into consideration. Ackerman estimated the social cost of carbon, as of 2012, as ranging from $33 to $1,048 per metric ton of carbon dioxide in 2020, to $75 to $1,821 per metric ton of carbon dioxide in 2050. Ackerman prepared a report analyzing the social cost of carbon from DBEC's projected GHG emissions. He attempted to compare the costs of DBEC's emissions with the benefits of DBEC's operation. In assessing the social cost of carbon emitted by DBEC, Ackerman considered the damage to tourism; human health; unique wildlife and ecosystems, including the Everglades; and property loss due to sea level rise and exacerbated king tides. He acknowledged that while it can be very difficult to estimate the true monetary value of the social cost of carbon for a project due to the aforementioned uncertainties, it is possible to arrive at estimates that represent a "floor," or minimum value, of damage due to GHG emissions from a specific project. Ackerman used the federal government's estimated social cost of carbon of $70 per ton of carbon dioxide25/——which, in Ackerman's view, underestimates the value of damages due to carbon dioxide emissions——and multiplied it by the GHG emissions, in tons, for each year of the DBEC project's projected life. Using two different annual GHGs emissions projections for DBEC—— 4.13 million metric tons or 3.04 million metric tons——he determined that the value of damages due to carbon dioxide emitted by DBEC would range from $213 million to $289 million on an annual basis.26/ Ackerman testified that, according to a research project conducted by Columbia University and the Rhodium Group, out of the 48 contiguous states, Florida will experience the greatest damage from climate change——which is projected to negatively impact the state's gross domestic product ("GDP") by between 10 and 24 percent by 2100. Using this study's projected GDP impacts and assuming that Florida experiences, to the year 2100, the same growth rate it has experienced over the past 20 years, Ackerman estimated that the monetary impact to Florida's economy from climate change may be between $500 million to $1.1 trillion annually by 2100. Ackerman also attempted to quantify DBEC's proportion of that impact on Florida. Using the two values of projected carbon dioxide emissions from DBEC and comparing them to global carbon dioxide emissions projections, Ackerman estimated that DBEC accounts for approximately 1/115,000th to 1/120,000th of total global carbon dioxide emissions on an annual basis. Using those proportions and the valued damage of global climate change to Florida, he estimated that the present value of the damages resulting from DBEC's annual carbon dioxide emissions would range from $8.4 million and $27 million per year. Ackerman also compared these annual projected social costs of carbon dioxide to the assumed $8.29 million annual benefits of the DBEC project to FPL's ratepayers. Based on this comparison, he concluded that the damages from DBEC's carbon emissions greatly outweigh DBEC's benefits to FPL ratepayers. Ackerman did not perform any analysis of DBEC's economic effects on the local community. He also did not take in account the effect that the increased efficiency of Unit 7 would have on FPL's system-wide emissions of GHGs through 2040. He acknowledged that if greenhouse gas emissions are reduced as a result of Unit 7, then the overall harm and damage from the social costs of carbon would also be reduced. As he put it: "[t]he social cost is a per ton harm, so if fewer tons, smaller harm. . . . A reduction in emissions is a reduction in harm." Ackerman testified that emitting any amount of GHGs has a social cost, but that "[a] smaller amount of emission is better. A smaller amount of emissions represents a smaller harm." While the evidence shows that GHG emissions from DBEC will result in increased social costs of carbon on a per-ton basis compared to a zero emissions baseline, the competent, substantial, and persuasive evidence establishes that the operation of Unit 7 will reduce FPL's GHG emissions on a system- wide basis by approximately 8.1 million tons by 2047, due to the retirement of older, less-efficient Units 4 and 5 and the reduced use of older, less-efficient generating units that produce greater quantities of GHG emissions.27/ Based on the foregoing, it is determined that retiring Units 4 and 5 in 2018 and operating Unit 7 commencing in 2022 will result in a net total reduction in the amount of GHG emissions from FPL's electrical power generating units on a system-wide basis——which, in turn, will result in lower social costs of carbon than if Unit 7 is not operated and Units 4 and 5 continue to operate indefinitely into the future.28/ Failure to Perform Life-Cycle Analysis Additionally, Sierra contends that the site certification for DBEC should be denied or additional conditional GHG-related conditions imposed because FPL and/or DEP failed to perform a "life-cycle analysis" to analyze DBEC's GHG emissions "from start to finish, . . . from gas generation to gas burn," which would include GHGs emitted by natural gas production and transport by pipeline to the DBEC site. This contention disregards that such an analysis is beyond the scope of this proceeding. This proceeding specifically applies only to "electrical power plants" as that term is defined in section 403.503(14). Pursuant to that definition, the scope of this proceeding is limited only to considering the impacts of, and imposing conditions on, facilities that fall within that definition. By this statute's plain terms, associated facilities that are directly or indirectly connected to the electrical power plant are to be considered only if they are owned by the applicant. As discussed above, the evidence establishes that Florida Gas Transmission Company owns the pipeline that transports natural gas to the DBEC site. No evidence was presented showing that FPL has any ownership interest in this pipeline, or that FPL has any ownership in sources which may produce gas that is ultimately transported to DBEC for use as fuel for Unit 7. Therefore, any GHG impacts associated with the operation of the pipeline to transport natural gas to DBEC are beyond the scope of this proceeding.29/ Failure to Consider Cumulative Impact of GHG Emissions Sierra also contends that the site certification for DBEC should be denied or additional GHG-related conditions imposed because FPL and/or DEP did not consider the cumulative impacts of DBEC's GHG emissions combined with those from "other existing and foreseeable permitted sources in Florida and elsewhere." As previously discussed, Florida and federal air statutes and rules do not impose cumulative impacts assessment in the PSD permitting process. Further, EPA's PSD Guidance expressly recognizes that climate change modeling and impacts evaluation of GHG emissions is conducted for changes in GHG emissions that are orders of magnitude larger than those from individual projects, and that determining the exact impacts attributable to a specific GHG source is not possible under current climate change modeling. Failure to Consider Using Solar Power Generation Technology Sierra also contends that the site certification for DBEC should be denied or additional conditions imposed because FPL and/or DEP "did not consider using solar generation." As discussed above, the PSC's Need Determination for Unit 7 considered and specifically rejected the use of photovoltaic (solar) facilities as a cost-effective alternative to Unit 7 as proposed. As discussed above, the PSC is the sole forum for determining need for electrical power plants subject to the PPSA. § 403.519, Fla. Stat. The PSC's need determination considers, among other things, the need for electric system reliability, the need for fuel diversity, whether the proposed plant is the most cost-effective alternative, and whether renewable energy resources may mitigate the need for the proposed electrical power plant. Thus, section 403.519 vests sole jurisdiction in the PSC to determine, as part of the need determination process, whether solar facilities should be required to be implemented as part of an electrical power plant's need determination. Therefore, the decision whether to impose a requirement for DBEC to implement solar facilities is beyond the scope of this proceeding. DBEC Stormwater Management System and Flooding Issues The stormwater management system for DBEC was designed to ensure that stormwater received onsite does not flood onsite facilities and to ensure that stormwater leaving the site does not cause offsite flooding or pollution. The stormwater management system for DBEC consists of a system of culverts, catch basins, ditches, storm sewer inlets, an underground storm sewer system, and ponds. The collection and conveyance structures collect the stormwater onsite and convey it to the ponds, which collect and store the water, then release it offsite at a controlled rate. Compliance with Applicable Stormwater Management Requirements The DBEC stormwater management system is designed in accordance with, and meets, all applicable stormwater management requirements of the City of Dania Beach, the City of Hollywood, Broward County, and the South Florida Water Management District ("SFWMD"), including regulations specifically directed toward protecting land uses against flooding. Broward County's land development code regulations require the floor elevation of the power plant facilities to be elevated to at least 5.5 feet North American Vertical Datum of 1988 ("NAVD88"), or approximately 6.5 feet above mean sea level, to withstand flooding from a 100-year, 72-hour storm event. The City of Dania Beach requires new or substantially improved power generation structures to be elevated three feet above the Federal Emergency Management Agency's ("FEMA") 100-year Base Flood Elevation established on the FEMA Flood Insurance Rate Map ("FEMA Map"). FEMA's 100-year Base Flood Elevation is three feet NAVD88; thus, the City of Dania Beach requires DBEC's power generation structures to be elevated to six feet NAVD88, which is approximately seven feet above mean sea level. To be conservative, FPL proposes to elevate the minimum floor elevation of DBEC's power generation structures to 10.5 feet NAVD88, or 11.5 feet above mean sea level——an additional five feet above Broward County's flood elevation requirement. This far exceeds both Broward County's and the City of Dania Beach's minimum flood elevation requirements. Broward County also required FPL to compare the base elevation of the stormwater management ponds to future groundwater elevation established on the Broward County Future Conditions Average Wet Season Groundwater Map ("Groundwater Map"), to ensure that the ponds would be sufficiently elevated to hold enough water to prevent flooding during storm events. The Groundwater Map depicts a projected future average wet season groundwater elevation of 2.5 feet above mean sea level——i.e., 1.5 feet NAVD88——in the year 2060. The base of the onsite stormwater storage ponds will be constructed one to two feet above this elevation. Additionally, the stormwater management system ponds have been designed to provide adequate storage to accommodate a 100-year, 72-hour storm event, so that the project does not have stormwater offsite impacts. Projected Sea Level Rise and DBEC Design The design elevation of DBEC's power block and stormwater management ponds adequately accounts for sea level rise. At Broward County's request, FPL compared the base flood elevation of the DBEC power block to the 2015 Unified Sea Level Rise Projection for Southeast Florida ("USLRP") document. This document, which was prepared by a technical working group on behalf of Palm Beach, Broward, Miami-Dade and Monroe counties, projects future sea level rise in South Florida, including Broward County. The USLRP contains a graph30/ consisting of four curves31/ depicting projected sea level rise from 1992 (the baseline year) to 2100 for the southeast Florida region.32/ The table below summarizes the projected sea level rise corresponding to each curve on the USLRP graph for the year 206033/. Name of Sea Level Rise Projection Predicted Sea Level Rise by 2060 (inches) NOAA High Curve 34 USACE High Curve 26 IPCC AR5 Curve 14 NOAA Intermediate/Low Curve 10.5 The area between the IPCC AR5 Curve and the USACE High Curve is recommended in planning design elevation for most projects that fall within a short-term planning horizon, and applies to "most infrastructure projects, especially those with a design life expectancy of less than 50 years."34/ Additionally, the USLRP states that "[p]rojects in need of a greater factor of safety related to potential inundation should consider designing for the [USACE High Curve]. Examples of such projects may include evacuation routes planned for reconstruction, communications and energy infrastructure, and critical government and financial facilities."35/ DBEC has a design life of 40 years and constitutes energy infrastructure. Therefore, the USACE High Curve is appropriate to use in designing the DBEC project to account for projected sea level rise by 2060. By contrast, the NOAA High Curve is used to plan high- risk projects that will be constructed after 2060; projects that are not easily replaceable or removable, have a long design life— —i.e., more than 50 years; or are critically interdependent with other infrastructure of services. Examples of infrastructure expressly identified in the USLRP document to which the NOAA High Curve is appropriately applied include nuclear power plants,36/ wastewater treatment facilities, levees or impoundments, bridges along major evacuation routes, airports, seaports, railroads, and major highways. DBEC does not fall within any of these categories; accordingly, the NOAA High Curve is not recommended for use in designing the DBEC project to account for projected sea level rise by 2060. Nonetheless, FPL took a conservative approach in determining the appropriate design elevation for the project over its projected design-life. Specifically, FPL added one inch to the USACE High Curve projection to account for two additional years of sea level rise beyond the end of DBEC's design-life in 2060. This resulted in a projected 27 inches of sea level rise by 2062. FPL then added this projection to the Broward County existing flood level requirement of 6.5 feet above mean sea level to determine potential flood levels in 2062. This calculation showed that an elevation of 8.75 feet above mean sea level is necessary to protect against sea level rise by 2062, using the USACE High Curve as the design benchmark. Because the minimum concrete base on which the power block will be elevated to 11.5 feet above mean sea level, it will be sufficiently elevated to protect against projected sea level rise by 2062. To further ensure that the design elevation of 11.5 feet above mean sea level is adequate to protect against a realistic, reasonably-projected "worst case" scenario, FPL compared the design elevation of 11.5 feet above mean sea level to the 34-inch sea level rise projected by the NOAA High Curve by 2060. Adding the 34 inches to Broward County's existing flood level requirement of 6.5 feet above mean sea level results in a design elevation of approximately 9.5 feet above mean sea level needed to address the NOAA High Curve projection by 2062. Thus, DBEC's minimum floor elevation of 11.5 feet above mean sea level exceeds the recommended design elevation, even when compared to sea level rise projected by the NOAA High Curve in 2062. FPL also used the NOAA Sea, Lake, and Overland Surges from Hurricanes ("SLOSH") model to address potential storm surge in determining the design elevation for DBEC's power block. This model projects storm surges for different categories of hurricanes and tidal events. FPL applied the SLOSH model to sea level rise projected by the USACE High Curve to predict storm surge height at the DBEC site by 2060, and then compared those results to the FEMA Map. The SLOSH model indicated lower elevations than the FEMA Map, which takes storm surge into account in determining the 100-year flood elevation. Accordingly, the 11.5 foot above mean sea level design elevation on which the DBEC power block will be constructed is more conservative than, and, thus, more protective than, a design based on the SLOSH model. As discussed above, FPL used the Groundwater Map to establish the bottom elevation of DBEC's stormwater ponds. The Groundwater Map, which relies on the USACE High Curve, projects groundwater levels at the DBEC site will be at approximately 1.5 feet NAVD88 by 2060. Because the bottom elevation of the stormwater ponds will be one to two feet above this projected level, they will adequately account for projected sea level rise by 2060. As noted above, certain existing infrastructure is not being replaced, so will not be elevated. These structures, which were constructed in compliance with the regulatory requirements in effect at the time they were approved, are constructed at six to seven feet NAVD88 above mean sea level. The highest flood elevation on the FEMA Map is at elevation 5.5 feet NAVD88 in 2060. Thus, it is unlikely that these structures will be subject to flooding by 2060. In designing DBEC, FPL reasonably relied on the sea level rise projections in the USLRP. That document, which was developed specifically for use in structural design and land use planning to address projected sea level rise, was created by the local governments in south Florida and provides the best scientific consensus view of future sea level rise.37/ FPL's expert, Dr. George Maul,38/ concurred that FPL reasonably relied on the USACE High Curve in designing the floor of DBEC's power block at 11.5 feet above mean sea level. In Maul's opinion, the USACE High Curve's projection for sea level rise is reasonable and appropriate for use in southeast Florida over the next 60 years.39/ Maul questioned the reliability of the NOAA High Curve, which predicts a rate of sea level rise twice as high as that experienced exiting the last Ice Age. He further noted that, in any event, the USACE High Curve and the NOAA High Curve differ by only a few inches in projected sea level rise by 2060. Dr. Harold Wanless40/ testified on behalf of Sierra regarding the relationship between climate change and sea level rise, hurricanes, and their effects on coastal marine environments. Specifically, Wanless testified regarding a range of factors that may cause the rate of sea level rise to accelerate. According to Wanless, research shows that sea level rise began to accelerate in approximately 1993 due to melting of the Greenland and Antarctic ice sheets.41/ Based on this research, Wanless disputes the accuracy of government predictions that do not take this phenomenon into account. In his testimony regarding the projected rate and extent of sea level rise over time, Wanless presented a graphic adapted from a January 2017 NOAA publication showing three global sea level curves——the "intermediate/high," "high," and "extreme" curves——projecting sea level rise through the year 2100. All of these curves on Wanless' adapted graphic assume Greenland and Antarctic ice sheet loss. Based on the extreme curve, Wanless projected that global sea level rise "could be" three feet by 2059. Notably, no evidence was presented regarding the probability of this projected sea level rise scenario. To depict local sea level rise in southeast Florida through 2100, Wanless added "local influences" to the 2017 NOAA curves, which consisted of higher water levels on the western side of the Gulf Stream due to its deceleration, and the gravitational redistribution of water due to decreasing ice sheet mass in Antarctica and Greenland. Specifically, Wanless added to the 2017 NOAA extreme curve sea level rise projection of three feet by 2062, 15 percent additional sea level rise to account for deceleration of the Gulf Stream, and 52 percent additional sea level rise to account for redistribution of water due to decreased gravitational pull by Greenland and Antarctica. Applying these local influences, Wanless projected that there "could be" an approximate 5.2 feet of local sea level rise by 2062. Again, no evidence was presented regarding the probability with which this projected local sea level rise scenario may occur. Upon full consideration of the testimony by Maul and Wanless, the undersigned concludes, based on the competent, substantial, and persuasive evidence, that the USACE High Curve, rather than Wanless's local influence sea level projection curve, is the more reasonable benchmark to apply in determining the appropriate design elevation for the DBEC power block. Wanless's local sea level rise projection is substantially based on the assumption that redistribution of the Earth's mass will significantly contribute to local sea level rise; however, Wanless himself noted that this phenomenon only recently has become the focus of research, and that "we're still learning."42/ Maul counseled against attempting to project long-term sea level rise using short periods of record data. To that point, he testified that trends derived from short records are less reliable as projections because they are affected by inter- annual and decadal climate and oceanographic patterns that are superimposed on the long-term rise of global sea level. Maul's research of historical 19-year periods43/ over which sea level rise rates have been observed by use of tidal gauges shows significant variability between 19-year periods. He testified, credibly, that in his recent review of tidal and sea level records for Key West, "I found we can pick a 19-year period where that particular 19 years is twice the long-term [sea level] range and other times where it's half the long-term range." He also testified that in looking at 19-year records a year at a time, "I find times when that short time scale is much, much higher than a long-term average and other times when it's much less than the long-term average. So you can either overestimate or underestimate what's happening when choosing short records." On that basis, Maul disputes that "since the year 2000, there has been a rapid acceleration in sea level rise." He testified, credibly, that he has not observed any statistically significant increase in sea level at Key West since 2000. Maul also opined, based on his own research, that there is no statistically significant slowing of the Gulf Stream. Sierra did not present persuasive evidence specifically refuting Maul's conclusion regarding slowing of the Gulf Stream.44/ In any event, the DBEC power block minimum floor elevation has been set at 11.5 feet above minimum sea level—— well above the 34- to 37-inch global sea level rise projected by the 2015 NOAA High Curve and the 2017 NOAA Extreme Curve, and also well above Wanless' projected local 5.2-foot local sea level rise by 2060. Sierra also contends that the minimum design elevation for the DBEC power block does not adequately consider storm surges associated with hurricanes. In support, Wanless presented graphics generated using LiDar, a light-detection and ranging technology, showing the elevation above mean sea level of Broward County, including the DBEC site. One graphic shows the current elevation of the DBEC site as approximately two feet above mean sea level. Other graphics assume a two-foot global mean sea level rise by 2060; a four-foot rise by 2089; a six-foot rise by 2110; an 8-foot rise by 2127; and a ten-foot rise in 2142. Each of these graphics shows the DBEC site as being inundated by sea level rise by 2060. Wanless also presented graphics for the period from 2018 to 2060, depicting the effect of adding storm surges of four feet and nine feet to regional sea level influences, king tides, and global mean sea level. According to these graphics, adding a four-foot storm surge may result in water heights of as much as 11 feet above present global mean sea level on the DBEC site by 2060, and adding a storm surge of nine feet may result in water heights of as much as 15 feet above present global mean sea level on the DBEC site by 2060. Wanless's storm surge scenarios entail layering contingencies on top of contingencies——each contingency fraught with uncertainty. Stated another way, each assumed condition on which Wanless relies to project storm surge heights of 11 and 15 feet has its own inherent uncertainty. To that point, the evidence showed that while it is well-accepted that climate change is occurring and that, as a result, global sea levels are rising, there is substantial lack of consensus in the scientific community and regulatory agencies regarding the extent and rate of global sea level rise in the future. Further, as discussed above, currently there is not a consensus that the Gulf Stream is slowing or that water mass is being redistributed due to the melting of the Greenland and Antarctic ice sheets——two contingencies that substantially contributed to Wanless' projection of a 5.2-foot local sea level rise by 2060. Additionally, as with Wanless's other projections, no evidence was presented regarding the probability that his projected water height scenarios on the DBEC site, assuming four- and nine-foot storm surges, would occur. Based on the foregoing, it is determined that the 11.5 foot above mean sea level design elevation for DBEC adequately addresses future storm surges. As previously discussed, certain existing infrastructure will be used for DBEC. These components were built years ago, complied with code requirements for elevation at the time they were constructed, and currently comply with those code requirements.45/ In sum, the competent substantial evidence establishes that the DBEC site design, as currently proposed, complies with all applicable state and local regulatory requirements. The competent, substantial, and persuasive evidence further establishes that DBEC site design elevation, which exceeds all applicable regulatory requirements, will adequately protect against flooding and inundation due to global and local sea level rise and storm surges. Other Impacts Water Resource Impacts The construction and operation of DBEC will not adversely impact water resources. The primary water uses for DBEC consist of cooling water, process water, service water, irrigation, and potable water. The cooling system for DBEC will use cooling water withdrawn from the Dania Cutoff Canal, which currently serves, and since 1927 has served, as the cooling water source for the electrical power generating facilities on the Lauderdale Site. DBEC will not require an increase in the rate or amount of cooling water withdrawn from the canal. Because the withdrawal rate will not increase, the through-screen velocity through the cooling water intake structure will not increase. This helps ensure that the project will not adversely impact fish or shellfish by impingement or entrainment. Additionally, no increase in the authorized quantity of industrial wastewater discharge will be required. The cooling system has been designed to ensure that DBEC will meet existing permitted National Pollutant Discharge Elimination System ("NPDES") thermal discharge limits. The average amount of process water used is anticipated to decrease. DBEC will continue to receive potable water from the City of Hollywood, and potable water use is not anticipated to increase. Sanitary Waste Disposal and Solid and Hazardous Waste The City of Hollywood will provide sanitary waste disposal services to DBEC. The operation of DBEC will generate small amounts of solid waste, which will be recycled, reused, disposed onsite, disposed in licensed offsite landfills, or otherwise appropriately disposed via approved disposal methods. The Lauderdale Site is a conditionally-exempt small quantity generator of hazardous waste and is anticipated to remain so during the construction and operation of DBEC. Hazardous waste generation by DBEC is anticipated to be less than 100 kilograms per month. FPL will contract with an approved and licensed hazardous waste disposal entity to handle and dispose of any hazardous waste generated by DBEC in a manner that complies with all federal, state, and local environmental regulations. Terrestrial Impacts The DBEC project will affect approximately 134 acres of the 392-acre Lauderdale site, which has continuously been used for industrial activities for the past 90 years. As such, the Lauderdale site is disturbed and does not constitute prime wildlife habitat for unique wildlife species. The upland and wetland habitat onsite is low-quality, and consists of a mixture of nuisance exotic and native species. Due to the disturbed nature of the site and the lack of significant wildlife habitat, no change in floral or faunal populations, including commercially- or recreationally-important species, is anticipated due to DBEC. Additionally, the site does not contain significant areas of preferred habitat for nesting, roosting, or foraging by state and/or federal endangered, threatened, or candidate species. Approximately 18.67 acres of low-quality wetlands, 0.12 acres of disturbed exotic and native hardwood systems, and a small area of low-quality isolated freshwater marsh will be impacted by dredging and filling. These wetland impacts will be mitigated through purchase of mitigation credits from the Everglades Mitigation Bank. Impacts on Aquatic Species DBEC project will continue to withdraw water from the existing Dania Cutoff Canal and to discharge cooling water into ponds and, ultimately, offsite. Proximate aquatic systems are subject to tidal influences and fresh water discharges through SFWMD canals. The waters in the vicinity of the DBEC site are designated Class III marine waters. Existing stresses on aquatic systems in the vicinity of DBEC include altered hydrology, altered salinity, elevated nutrient and organic loads, power plant intake/discharge, physical alterations, and pressures from fishing and boating. DBEC will address impacts to these aquatic systems, as appropriate, through obtaining an NPDES permit for the cooling water discharge. Additionally, FPL will use best management practices during construction to control erosion, sedimentation, and runoff to prevent water quality degradation. Significant impacts to aquatic resources and biological communities are not anticipated. During DBEC construction, FPL will continue to discharge warm water consistent with the Manatee Protection Plan established under the NPDES permit for the existing electrical power plant facility. The Lauderdale Site will continue to provide a warm water refuge for manatees during and after DBEC is constructed. Transportation Impacts A traffic analysis for construction and operation of DBEC was performed and provided in the site certification application. During peak construction, approximately 500 vehicles per day are anticipated to enter and exit the DBEC site. A traffic impact analysis showed that additional construction-related traffic will not degrade roadway system operating conditions. FPL will develop a traffic management plan to minimize level of service deficiencies due to construction traffic. FPL has agreed, pursuant to the Conditions of Certification, to work with the City of Hollywood to improve roadway operations at site access locations. No adverse impacts to traffic flow are anticipated from DBEC operation. Archaeological and Historical Site Impacts A cultural resource assessment of the DBEC site determined that no archaeological or historical structures that are listed, eligible, or potentially eligible for listing in the National Register of Historic Places, are present. Noise A computer program predicted environmental noise impacts from DBEC. Most of the noise sources, which consist of the steam turbine, the gas turbines, the electric generators, and the compressors, are located in enclosed structures, which helps mitigate impacts. The DBEC sound profile will not be significantly different than that for Units 4 and 5. The Lauderdale Site is in a highly-developed area having other proximate industrial and urban uses, including a waste-to-energy center, a shipping center, a recycling center, the Fort Lauderdale-Hollywood International Airport, and several major highways. DBEC is projected to comply with the Broward County and City of Hollywood noise ordinances. DBEC's normal operation is not anticipated to exceed the City of Dania Beach's maximum permissible noise levels. However, as part of the site certification application, FPL has requested a variance from the City of Dania Beach noise ordinance, chapter 17, article IV, sections 17-79 through 17-90, for noise levels that may occur on an infrequent and short-term basis during startup, shutdown, and upset conditions. The City of Dania Beach does not object to FPL's request for the variance. The undersigned recommends approval of FPL's request for a variance from the City of Dania Beach noise ordinance, chapter 17, article IV, sections 17-79 through 17-90. Climate Change "Climate change" is a term used to describe changes in global temperature, global sea level rise, and other conditions associated with those effects, including changes in precipitation, winds, waves, and climates. Climate change is occurring globally and locally, including in southeast Florida. Climate change is caused, in substantial part, by the emission of GHGs. Water vapor, carbon dioxide, and methane are the most significant GHG contributors to climate change. Atmospheric concentrations of gaseous carbon dioxide and methane are increasing. Since the Industrial Revolution, the global atmospheric concentration of carbon dioxide has dramatically increased, from 280 parts per million ("ppm") to 410 ppm at present——almost 100 times faster than historical increases in atmospheric carbon dioxide concentration during previous interglacial periods. Most of the increase in atmospheric carbon dioxide concentration has occurred since World War II and is primarily due to human population increase, global industrialization, and increased burning of fossil fuels on a global basis. GHGs cause climate change by trapping solar radiation in the Earth's atmosphere, thereby warming the atmosphere. Once carbon dioxide is emitted, it persists in the atmosphere for approximately 4,000 years. Climate change is responsible for causing sea level to rise on a global and local basis. The main drivers of sea level rise are atmospheric and ocean warming, which increase the ocean's mass through melting land and sea ice and increase the ocean's volume through thermal expansion. Increasing the concentration of carbon dioxide in the atmosphere increases the rate of climate change, which, in turn, accelerates sea level rise. The last time atmospheric concentrations of carbon dioxide were at or above 400 ppm, sea level was approximately 20 meters, or 70 feet, higher than current level. At that level, a substantial portion of the land mass that constitutes the state of Florida was inundated. The evidence shows that global sea level does not rise in a gradual linear manner, but instead rises in rapid pulses followed by pauses. Although it is well-established that sea level is rising on a global and local basis, there currently is little consensus regarding the rate of sea level rise. Due to its low elevation, southeast Florida is particularly vulnerable to sea level rise. Many urban areas in southeast Florida experience substantial flooding during rainfall events. The evidence shows that sea level rise is likely a contributing cause. Sea level rise causes substantial coastal hazards, including inundation of land, higher storm surges, higher king tides, increased flood height and frequency, coastal erosion and destruction of coastal mangroves and other ecosystems, erosion and destruction of coastal barrier islands, and saltwater intrusion into freshwater aquifers and ecosystems. These impacts will worsen or accelerate with sea level rise. The cumulative addition of carbon dioxide to the atmosphere is warming the atmosphere, which, in turn, is causing ocean temperatures to rise on a global basis. In particular, the upper ocean has warmed substantially on a global basis since 1997, due to increasing human population and the corresponding increased burning of fossil fuels. Increased carbon dioxide in the atmosphere is being transferred to the oceans, causing them to acidify. Some scientific studies indicate that climate change will cause more severe storm and weather events. Some scientific studies indicate that climate change will result in threats to human health, native wildlife and ecosystems, agriculture, and the tourism industry. In sum, the competent, persuasive evidence establishes that climate change is occurring, that it is primarily caused by GHGs emissions, and that every ton of GHGs emitted into the atmosphere contributes to climate change. The competent, persuasive evidence also establishes that as a result of climate change, sea level is rising globally, and, to a certain extent, locally,46/ and that sea level rise already is causing environmental adverse impacts.47/ SCO and Affected Agencies' Review of Application The PPSA establishes a centralized, coordinated process for licensing electrical power plants that generate 75 MW or more of electrical power. §§ 403.502, 403.503(14), Fla. Stat. Site certification for an electrical power plant constitutes a license that addresses and encompasses the regulatory requirements of the agencies that are involved in the site certification application review process. The SCO is an office within DEP's Division of Air Resource Management. It is responsible for coordinating and overseeing the electrical power plant site certification application review process. The SCO also serves as administrative staff for the Siting Board. The SCO's responsibilities include receiving site certification applications, preparing a schedule of deadlines and milestones applicable to the site certification application review process, determining completeness48/ of the application based on the recommendations of affected agencies,49/ receiving each affected agency's preliminary statement of issues, receiving each affected agency's report, and preparing the PAR.50/ §§ 403.5064, 403.5066, and 403.507, Fla. Stat. The PAR addresses the proposed electrical power plant's compliance with all applicable non-procedural requirements of the affected agencies51/ and contains copies of the affected agencies' reports; comments from other agencies or persons; any variances and waivers from applicable regulatory requirements that have been requested and the SCO's recommendation regarding the request; the SCO's recommendation regarding whether site certification should be approved, denied, or approved with conditions; and proposed conditions of certification. § 403.507(5)(a), Fla. Stat. The affected agencies' reports provide the agencies' specialized knowledge on matters within their jurisdiction and expertise, so are a crucial component of the PAR. Each affected agency conducts a substantive review of the site certification application to determine whether the electrical power plant complies with that particular agency's applicable substantive rules, regulations, ordinances, standards, and criteria. The affected agency's report must specifically address these topics and must state whether, based on its substantive review, the agency recommends that the electrical power plant be approved, denied, or approved with conditions. The report also must include any conditions of certification that the agency recommends be imposed regarding matters within that agency's jurisdiction. § 403.507(3), Fla. Stat. Conditions of certification are regulatory requirements imposed to minimize and mitigate the potential adverse effects of the construction and operation of the electrical power plant with respect to the environment and public health. Because the conditions of certification are regulatory requirements, each affected agency that recommends a specific condition of certification must possess the legal authority to impose that condition. § 403.507(3)(c), Fla. Stat. To that end, the affected agency is required to cite the specific statute, rule, or ordinance that authorizes the imposition of that specific condition. Because each affected agency possesses legislatively or constitutionally delegated regulatory authority over specific matters, the SCO does not conduct an independent review as to whether the proposed electrical power plant meets those affected agencies' nonprocedural requirements, and instead relies on each affected agency's specific regulatory knowledge and expertise regarding matters that are within its substantive regulatory jurisdiction. FPL submitted the Application for DBEC to the SCO on July 27, 2017. The Application was referred to DOAH and was distributed to the affected agencies for review and comment regarding completeness of the Application. The affected agencies needed additional information, so the Application was determined incomplete. After FPL provided the requested information, the Application was deemed complete on October 27, 2017. Pursuant to section 403.507(3), the SFWMD; Florida Fish and Wildlife Conservation Commission ("FFWC"); Florida Department of Transportation ("DOT"); Florida Department of Economic Opportunity ("DEO"); Florida Department of State, Division of Historical Resources ("DHR"); DEP; Broward County; the City of Dania Beach; and the City of Hollywood reviewed the Application and submitted agency reports to the SCO. Each of these affected agencies submitted recommended conditions of certification to be included in the site certification as conditions specifically designed to address matters within that particular agency's regulatory jurisdiction. Each agency concluded that if DBEC complies with the conditions of certification recommended by that agency, it will meet all applicable non-procedural requirements, rules, and ordinances within that agency's jurisdiction. Each affected agency recommended that DBEC be approved, subject to the conditions of certification recommended by that agency. Each agency report is briefly discussed below. PSC Need Determination As previously noted, the PSC issued the Need Determination for DBEC on March 19, 2018. Pursuant to section 403.507(4)(a), the Need Determination constitutes the PSC's agency report for DBEC. In determining the need for DBEC, the PSC considered critical components of need, including forecasted load, necessary reserve margin, projected load generation and imbalance, and area reliability margin. The PSC determined that FPL demonstrated the need for DBEC Unit 7 in the 2024-to-2026 timeframe, in order to maintain its electrical system reliability and integrity. The PSC found that: No cost-effective [Demand Side Management] or renewable resources have been identified that could mitigate the need for DBEC Unit 7. DBEC Unit 7 is expected to provide adequate electricity at a reasonable cost to FPL's customers. DBEC Unit 7 is projected to reduce overall natural gas consumption and reduce emissions compared to maintaining the existing Lauderdale units. DBEC Unit 7 is the most cost-effective alternative that maintains FPL's system and Southeastern Florida area reliability compared to other alternatives. South Florida Water Management District SFWMD determined that there will be no increase in water use for DBEC, and that the cooling water, potable water, and process water sources will remain the same as for the units currently existing at the Lauderdale Site. SFWMD determined that if DBEC complies with SFWMD's recommended conditions of certification, it can be constructed and operated in compliance with the applicable statutes and rules within SFWMD's jurisdiction. Florida Fish and Wildlife Conservation Commission FFWCC's report noted that several listed wildlife species were observed onsite or have a moderate to high likelihood of occurrence onsite. Additionally, the West Indian Manatee will be affected by ceasing operation of Units 4 and 5 before the construction of DBEC. FFWCC recommended conditions of certification requiring biological surveys, monitoring for impacts to listed species, and also recommended a condition of certification to require temporary heaters to be used during DBEC construction to maintain a warm water refuge for manatees. Department of Transportation DOT determined that, with the exception of construction-related traffic, DBEC is not anticipated to adversely affect the State Highway System in the vicinity of the plant. DOT recommended certification of DBEC, contingent on DBEC's compliance with its recommended conditions of certification. Department of Economic Opportunity DEO anticipates that DBEC will provide economic and fiscal benefits to the City of Dania Beach, Broward County, and the surrounding area. DEO recommended approval without any recommended conditions of certification. Division of Historical Resources DHR did not object to DBEC, noting that all current matters pertaining to historical resources were addressed. Department of Environmental Protection DEP reviewed solid waste and hazardous waste, environmental resource permitting, industrial wastewater, and stormwater management issues within its jurisdiction and determined that DBEC will meet all applicable regulatory requirements, provided it complies with the proposed conditions of certification. DEP recommended conditions of certification to address solid waste and hazardous waste, environmental resource permitting, industrial wastewater, and stormwater management issues within its jurisdiction. Local Governments Broward County, the City of Dania Beach, and the City of Hollywood each recommended approval of DBEC, subject to recommended conditions of certification regarding matters within its regulatory jurisdiction. The City of Dania Beach did not object to the variance sought by FPL related to noise limits in the City of Dania Beach's Code of Ordinances for transient and infrequent noises associated with unit startup, shutdown, and upset conditions. Preliminary Analysis Report and Recommended Approval with Conditions of Certification On April 2, 2018, the SCO issued the PAR for DBEC. The PAR describes the project and summarizes the affected agencies' substantive review of DBEC. Based on the agencies' reports, recommended conditions of certification, and unanimous approval recommendation, the SCO determined that FPL has provided reasonable assurance that, considering and balancing the factors in section 403.509(3)(a) through (g), DBEC can be certified. The PAR recommends approval of the site certification for DBEC, subject to the proposed Conditions of Certification ("COC") attached thereto, which were compiled from the affected agencies' recommended conditions of certification submitted as part of their agency reports. Sierra contends that because the SCO did not conduct an independent review of whether DBEC meets the nonprocedural requirements of the affected agencies, it was not able to determine whether FPL provided reasonable assurance that the site certification complies with the agencies' applicable statutes, rules, regulations, and other requirements. This contention is rejected. The purpose of the affected agency's review and report submittal requirement in section 403.507 is to ensure that the agency legally and factually vested with the substantive jurisdiction and expertise over a specific regulated area is an integral part of the site application review process. To that end, each agency is charged with submitting recommended conditions of certification that are specifically keyed to addressing issues within that agency's substantive jurisdiction and expertise. The purpose of affected agency involvement in the site certification process would be defeated if the SCO——which is not an expert over the matters within the various affected agencies' substantive jurisdiction—— was authorized to second-guess these agencies' determinations and to modify or reject their recommended conditions of certification. Further, and fundamentally, the SCO is not statutorily authorized to conduct such an independent review. Notably, Sierra has not cited any statutory, rule, or case law authority to support its position.52/ Notice, Public Outreach, and Public Hearing All public notices required by the PPSA were provided. FPL timely published the notice of filing of the Application, as required by section 430.5115(1)(a), and notice of the certification hearing, as required by section 403.5115(1)(e). DEP published notice of the filing of the Application and the certification hearing in the Florida Administrative Register, as required by section 403.5115(4). Additionally, FPL provided direct written notice that the Application had been filed to property owners and residents within three miles of the project area, as required by section 403.5115(6)(a). FPL also engaged in public outreach for the project, including providing a toll-free phone number at which information regarding the project could be obtained, a website containing information about the project, and electronic mail contact information. Additionally, FPL sent 310 letters to residents of the neighborhood closest to the project and sent 1,600 mailers to residents and property owners in the vicinity of the site, inviting them to an open house that was held on May 24, 2017. FPL hosted another open house in June 2017 for residents of the neighborhood immediately south of the project site. A public hearing was held on May 15, 2018, from 6:00 p.m. until 8:03 p.m. Many members of the public provided comments on the DBEC project,53/ and were able to ask questions of representatives from FPL and DEP. The public hearing comments were recorded and transcribed as part of the Transcript of the certification hearing.54/ Federal Permits As discussed above, an air construction/PSD permit has been issued for DBEC. FPL has applied for an NPDES permit and a permit from the United States Army Corps of Engineers under section 404 of the Clean Water Act. These permits and approvals are not part of, or subject to revision, modification, or revocation in, this proceeding. Variance As discussed above, FPL has requested a variance from the City of Dania Beach noise ordinance in Chapter 17-86 of the City's Code of Ordinances, which establishes the permissible sound levels for receiving land use categories. Specifically, FPL requested a variance from the City's maximum permissible sound levels for: Noise due to emergency or upset conditions for all time periods and all receiving land use categories; Noise due to transient conditions associated with unit startup and shutdown shall be limited to 70 dB(A) for all time periods and all receiving land use categories, except for Industrial land use which shall retain a limit of 75 dB(A). Currently, the area in which the Lauderdale Site is located experiences significant noise from the combined effect of a range of industrial and urban activities, including the operation of Units 4 and 5 at the Lauderdale Site. DBEC's projected noise profile is not materially different than that of the existing power plant operation at the Lauderdale Site. Transient and infrequent conditions at the Lauderdale Site, including unit startup, shutdown, and upset conditions occasionally occur for short periods of time. These conditions also are expected to occasionally occur at DBEC. The variance is limited in nature, and the noise levels necessitating a variance are expected to be infrequent and short-lived during unit startup, shutdown, or upset conditions. The City of Dania Beach does not oppose the variance. Given the limited nature of the variance, lack of opposition, and that similar noise levels currently occur at the Lauderdale Site, it is determined that the requested variance is reasonable, and, therefore, should be granted. The Siting Board's Role and Authority Section 403.509(3) sets forth the Siting Board's authority and duty under the PPSA. In considering whether to approve, approve with conditions, or deny a power plant site certification license, the Siting Board must consider all factors in section 403.509(3)(a) through (g). The Siting Board possesses broad authority under the PPSA in considering whether to certify an electrical power plant. With the exception of the need determination and federal permits, the Siting Board is not bound by the conditions of certification proposed by the SCO or the affected agencies, and may modify, remove, or add conditions of certification, as authorized, to protect the broad interests of the public and minimize adverse impacts of the electrical power plant on the environment and human health. See § 403.502(2), Fla. Stat. Comparative Impacts and Benefits of DBEC As discussed above, DBEC will emit GHGs into the atmosphere. Therefore, DBEC's emissions will increase the amount of carbon dioxide in the atmosphere when compared to a zero emissions scenario——i.e., no GHG emissions at all. However, the alternatives in this proceeding do not entail a zero GHG emissions alternative to DBEC. As discussed above, the PSC found and concluded, in the Need Determination, that with the retirement of Units 4 and 5, DBEC is needed to meet a projected future electrical power demand. As part of the Need Determination, the PSC concluded that no additional cost-effective renewal resource——such as solar or wind generation technology——could mitigate the need for DBEC. The PSC also concluded that no new demand side management——i.e., conservation——could mitigate the need for DBEC. In so determining, the PSC established, as a baseline condition to this proceeding, that DBEC, a natural gas-fueled facility, is the most cost-effective means of meeting projected future electrical power demands if Units 4 and 5 are retired. Thus, given the Need Determination, the only alternative available to constructing DBEC is to continue operating Units 4 and 5 indefinitely.55/ As previously discussed, Units 4 and 5 are less efficient units that burn substantially more natural gas than will Unit 7. Therefore, if Units 4 and 5 continue to operate indefinitely——as will be the case if DBEC is not certified——they will burn more natural gas, resulting in the emission of greater amounts of GHGs over their operation life than would the construction and operation of Unit 7, combined with FPL's reduction of the use of less-efficient units in its system. The competent, substantial, and persuasive evidence establishes that the retirement of Units 4 and 5 in 2018, along with the construction and operation of DBEC in 2022 and FPL's concomitant reduction in the use of other less-efficient, more- polluting units in its system, will result in the emission of approximately 8.1 million tons less GHGs into the atmosphere over a 30-year period than if DBEC is not approved and Units 4 and 5 continue to operate indefinitely. Because DBEC will, through system-wide reduced GHG emissions, result in a net environmental benefit as compared to the alternative of continuing to operate Units 4 and 5 indefinitely into the future, DBEC should be weighed as a net positive in considering and balancing the site certification criteria in section 403.509(3). Other measures, discussed above, that DBEC will include and implement to minimize offsite impacts include using the existing transmission line system, existing natural gas pipeline, existing site access, and using a previously-developed power generation site. DBEC will not require new water sources, will not result in a new or expanded surface water discharge, and will reduce the use of processed water by approximately 22 percent. Additionally, upon its operation, DBEC will provide a warm water refuge for manatees.56/ In sum, the undersigned finds that DBEC's benefits, discussed at length above, outweigh its adverse impacts. This determination is more fully addressed in the Conclusions of Law, below. Sierra's Standing Sierra has intervened in this proceeding pursuant to section 403.508(3)(e), which confers party status on persons or entities who demonstrate that their substantial interests will be affected by this proceeding. Sierra is a national non-profit organization. Sierra and its members are committed to protecting the environment. Sierra focuses extensive effort and resources toward combating climate change through advocating the displacement of fossil-fuel energy sources, which emit GHGs, in favor of renewable energy sources and energy sources, such as solar power, wind power, and energy storage and batteries. Consistent with that mission, Sierra's members are concerned about climate change resulting from GHG emissions and the adverse impacts of climate change on human health, property, wildlife, and sensitive ecological systems, and many are actively involved in efforts aimed at reducing GHG emissions on a global and local basis. Several Sierra members testified at the certification hearing regarding the environmental and personal harms they allege they will suffer due to climate change——to which, Sierra alleges, DBEC will contribute. These alleged harms include rising sea level, saltwater intrusion, contamination of drinking water aquifers, property damage due to flooding and increased storm intensity, adverse impacts on recreational activities due to degradation of coral reef and mangrove ecosystems, algal blooms, and human health impacts. Sierra has nearly 38,000 members who live in Florida. Approximately 18,000 Sierra members live in FPL's service territory.57/ The relief Sierra requests in this proceeding is set forth below. Generally, Sierra requests either that the site certification for DBEC be approved, subject to additional conditions that Sierra proposes, or be denied. Relief Requested by Sierra On May 2, 2018, Sierra filed Sierra's Statement on Relief ("Statement on Relief"), identifying the relief it seeks in this proceeding. That relief was set forth in nine sequentially-numbered paragraphs. On May 8, 2018, FPL filed Florida Power & Light Company's Motion to Strike paragraphs 1 through 7 of the Statement on Relief. On May 11, 2018, Sierra filed Sierra Club's Opposition to Florida Power & Light Company's Motion to Strike. At the commencement of the certification hearing, the undersigned struck paragraphs 6 and 7 of the Statement on Relief and reserved ruling on the other forms of relief requested in paragraphs 1 through 5, 8 and 9, pending development of the evidentiary record in this proceeding. The undersigned has ruled on these paragraphs in the Conclusions of Law, below. Sierra requests the following relief in paragraphs 1 through 5, 8, and 9 of its Statement on Relief, which remain at issue in this proceeding: Paragraph 1 of Sierra's Statement of Relief requests the Siting Board to require FPL to limit the annual emission of GHGs from DBEC to the existing annual GHG emission levels from Units 4 and 5, and require FPL to terminate GHG emissions from DBEC at the same date that FPL planned to retire Units 4 and 5, in 2033, subject to any required operation to meet electric reliability needs. Paragraph 2 of Sierra's Statement of Relief requests the Siting Board to require FPL to comply with FPL's stated system- wide GHG commitment to DEP and the PSC, and upon which FPL relies in seeking approval for DBEC——specifically, that DBEC's operation reduces FPL's system-wide annual emissions of GHGs from its current baseline by at least the amount committed to by FPL. As part of this requirement, approval of DBEC should be conditioned on FPL's system-wide annual emissions of GHGs being lower than its current baseline by at least the amount committed to by FPL, and never exceeding that reduced level of GHGs during each year of the lifespan of DBEC. Paragraph 3 of Sierra's Statement of Relief requests the Siting Board to require FPL to develop a locally-sited public stakeholder process that provides municipalities and other governmental entities that have adopted, or that in the future adopt, carbon reduction or clean energy commitments, a means to work with FPL to develop a binding plan to meet the commitments of the municipalities and other governmental entities, subject to any governmental approvals required by law, and that such processes allow interested persons, including non-governmental organizations, a meaningful opportunity to participate. Paragraph 4 of Sierra's Statement of Relief requests the Siting Board to require FPL to evaluate, every five years, in a detailed, transparent process with opportunity for meaningful public participation, the Climate Change Damages resulting from 40 years of GHG pollution from building and operating DBEC as proposed, and approve DBEC subject to the opportunity for the Siting Board to reevaluate the approval of DBEC, including whether there are additional reasonable and available methods that should be adopted to minimize the Climate Change Damages caused by DBEC, and to impose further conditions, including future emissions reductions of DBEC. The impacts of DBEC must be evaluated individually, as well as in the context of cumulative impacts from other GHG emissions. In this evaluation, FPL must examine reasonable and alternative methods to minimize the adverse effects of DBEC's emissions, including sequestration of GHGs and the ability to avoid the emissions. Paragraph 5 of Sierra's Statement of Relief requests the Siting Board to require FPL and DEP to reevaluate, on a five-year basis, and in a detailed, transparent process with opportunity for meaningful public participation, the Climate Change Damages which pose a risk to the DBEC facility specifically, and approve DBEC subject to the opportunity for the Siting Board to reevaluate the approval of DBEC, including whether there are additional reasonable and available methods that should be adopted to minimize the Climate Change Damages to the DBEC facility, and to impose further conditions, including future emissions reductions of DBEC. Paragraph 8 of Sierra's Statement of Relief requests the Siting Board to deny DBEC's site certification. Paragraph 9 of Sierra's Statement of Relief requests that the ALJ and the Siting Board provide such relief as is just and reasonable.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law it is RECOMMENDED that the State of Florida Siting Board enter a final order approving DBEC, subject to the Conditions of Certification contained in the PAR, and approving the variance to the City of Dania Beach Code of Ordinances, Chapter 17, Article IV, Noise, Section 17-86, as set forth in the PAR. DONE AND ENTERED this 30th day of July, 2018, in Tallahassee, Leon County, Florida. S CATHY M. SELLERS 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 July, 2018.
The Issue The issue for determination in this case is whether the affiliated facilities and proposed site of the Hardee Unit 3, a fifty acre parcel in the unincorporated area of Hardee County within the site of the Hardee Power Station encompassing 1300 acres in Hardee and Polk Counties, is consistent and in compliance with existing land use plans and zoning ordinances of Hardee and Polk Counties, pursuant to Section 403.508(2), Florida Statutes.
Findings Of Fact The site for the proposed Hardee Unit 3 electric generating plant is a 50 acre parcel within the larger 1,300 acre Hardee Power Station Site which is located in both Polk and Hardee Counties. The Hardee Unit 3 site is approximately 9 miles northwest of the City of Wauchula, which is located in Hardee County. The Hardee Unit 3 electrical generating structures will be located in the unincorporated area of Hardee County. The Hardee Unit 3 will utilize the existing cooling reservoir, the existing site access road and the existing natural gas pipeline, all of which are located in both Hardee County and Polk County. A new gas pipeline lateral may be constructed within both the Hardee County and Polk County portions of the Hardee Power Station Site if a fuel supply contract is successfully negotiated with Sunshine Pipeline Company. The Public Service Commission in its Order Granting Petition for Determination of Need, (the "need order,") found that Seminole Electric had provided adequate assurances that sufficient natural gas pipeline capacity will be available to transport natural gas to the proposed combined cycle unit. The Hardee Power Station Site was originally certified in November 1990 for an ultimate site capacity of 660 megawatts (MW) of natural gas and oil fired generating capacity. In a final order entered in August 1990, the Siting Board determined the Hardee Power Station Site was consistent and in compliance with the land use plans and zoning ordinances of Hardee and Polk Counties. In this proceeding, Seminole proposes to increase the ultimate site capacity determination for the Hardee Power Station Site by an additional 220 MW of capacity and to seek certification of the electric generating equipment for the 440 MW Hardee Unit 3 as described below. If finally certified, the ultimate site capacity determination for the Hardee Power Station Site would be increased to a total of 880 MW. With the addition of proposed Hardee Unit 3, the Hardee Power Station will consist of combined cycle electric generating facilities with an ultimate nominal capacity of 880 MW to be constructed in two phases. In the first phase, TECO Power Services (TPS) constructed 295 MW of generating capacity, which began commercial operation in January 1993, and will construct an additional 145 MW combined cycle facility, which is scheduled to be in service in January 2003. Phase 2 of the project is the addition of Seminole's proposed separate 440 MW (nominal) combined cycle facility, to be in service in January 1999. On June 21, 1994, the Florida Public Service Commission ("PSC") issued a need order based on Seminole Electric's application for a need determination for construction of a 440 MW combined cycle facility. The PSC order granted the application. The Hardee Unit 3 will utilize the existing 570 acre cooling reservoir to supply condenser cooling water for all existing and planned combined cycle units at the site. The Hardee Unit 3 also will have associated onsite oil storage and handling facilities and an onsite electrical switch yard which will connect to the existing TPS switch yard onsite for transmission access. Power generated from the Hardee Unit 3 power plant and the full build out capacity of 880 MW will be distributed via three existing transmission lines. These transmission lines were authorized and constructed pursuant to the November 1990 certification. The existing pipeline connecting to the Florida Gas Transmission system also can supply natural gas to the Hardee Unit3. No changes to these electrical and gas transmission lines will be required for the Hardee Unit 3. The new gas pipeline lateral may also supply natural gas to the site, if constructed. The Applicant published notice of the September 7, 1994 land use hearing in The Herald-Advocate (Wauchula) on July 21, 1994, The Ledger (Lakeland) on July 20, 1994, and The Tampa Tribune on July 20, 1994. Notice of the September 7, 1994 hearing also was published in the Florida Administrative Weekly on July 22, 1994. (Exhibit 20; Bachor T. 16-17) Hardee County Aspects of the Hardee Unit 3 to be located in Hardee County include: (a) the power plant facility; (b) a portion of a possible future natural gas pipeline lateral extending to Sunshine Gas Pipeline Company's main gas line which may be constructed to serve the site; and (c) miscellaneous accessory facilities. The land use plan that governs the Hardee Unit 3 site in Hardee County for purposes of this hearing is the future land use plan element of the Hardee County Comprehensive Plan, originally adopted in April 1991. The applicable zoning regulation is Hardee County Zoning Ordinance No. 82-2 as codified in the Hardee County Land Development Code. The Hardee County future land use map designates the Hardee Power Station Site as A-I, Agricultural. Power plants are identified as a permitted land use within the Agricultural land use category. The zoning category for the site of the Hardee Unit 3 generating facility located within Hardee County is 1-1 (Light Industrial). The Light Industrial district, as described in the Hardee County zoning ordinance, includes "public and semi-public plants" in an enumeration of authorized "principle uses and structures," and authorizes the proposed power plant. The Hardee County Board of County Commissioners rezoned the Hardee Power Station Site to 1-1, effective December 31, 1989, to authorize construction of a power generation plant. Expert testimony was presented demonstrating that the proposed Hardee Unit 3 is consistent and in compliance with Hardee County's land use plan and zoning ordinance. On August 31, 1991, the Applicant and Hardee County entered into a stipulation in which the County confirmed that the proposed site of the Hardee Unit 3 is consistent and in compliance with Hardee County's existing land use plan and zoning ordinance. Polk County The only new aspect of the Hardee Unit 3 which may be constructed within Polk County is a portion of a gas lateral within the Hardee Power Station Site to connect to a future natural gas pipeline that may serve the site. The existing cooling reservoir, the site access road and an existing gas pipeline all located partially within Polk County will continue to be used by the new unit. The land use plan that governs the Hardee Unit 3 pipeline facilities located in Polk County is the Polk County Comprehensive Plan, as adopted by the Board of County Commissioners on November18, 1992. The applicable zoning regulation is the 1983 Polk County zoning ordinance, as amended. The future land use map for Polk County designates the portion of the Hardee Power Station Site within Polk County as Phosphate Mining ("PM"). Electrical generating facilities and natural gas pipelines that support existing or proposed development are allowed uses within that land use category. The Polk County zoning category for the portion of the Hardee Power Station Site within Polk County is Rural Conservation, ("RC"). Natural gas pipelines are an allowed use within this zoning district as a Class I Essential Use. Expert testimony also demonstrated that the power plant site and associated linear facilities are in compliance and consistent with Polk County's land use plan and zoning ordinance. The Applicant has entered into a stipulation with Polk County, dated September2, 1994, in which the County confirms that the site of those facilities for the Hardee Unit 3 power plant which may be located in Polk County is consistent and in compliance within Polk County's existing land use plan and zoning ordinance.
Recommendation Based upon the foregoing findings of fact and conclusions of law, it is recommended that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order finding that the site of the Hardee Unit 3 electric generating facility, as proposed in the Site Certification Application and representing an incremental increase of 220 MW in the ultimate site capacity for the entire Hardee Power Station Site, is consistent and in compliance with the existing land use plans and zoning ordinances of Hardee and Polk Counties. DONE AND ENTERED this 14th day of October, 1994, in Tallahassee, Florida. DAVID M. MALONEY 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 14th day of October, 1994. APPENDIX Findings of Fact Nos. 1 - 20, proposed by the applicant and Hardee County in their Joint Proposed Findings of Fact, in substance, and insofar as material, are adopted. COPIES FURNISHED: Doug Roberts Attorney at Law Hopping, Boyd, Geen & Sams P. O. Box 6526 Tallahassee, Florida 32314 Richard Donelan Assistant General Counsel 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Hamilton S. Oven, Jr. Department of Environmental Protection 3900 Commonwealth Blvd. Tallahassee, Florida 32399-3000 David Russ Assistant General Counsel Department of Community Affairs 2740 Centerview Drive Tallahassee, Florida 32399-2100 Representing DCA Michael Palecki, Chief Bureau of Electric & Gas Florida Public Service Commission 101 East Gaines Street Tallahassee, Florida 32399-0850 Representing PSC Dorothy Johnson, Chief Department of Transportation 605 Suwannee Street, M.S. 58 Tallahassee, Florida 32399-0458 Mark F. Lapp James A. Robinson Assistant General Counsels Southwest Florida Water Management District 2379 Broad Street Brooksville, Florida 34609-6899 Representing SWFWMD James Antista, General Counsel Florida Game and Fresh Water Fish Commission Bryant Building 630 South Meridian Street Tallahassee, Florida 32399-1600 Representing GFWFC Gary Alan Vorbeck Hardee County Attorney Vorbeck & Vorbeck, P.A. 207 East Magnolia Street Arcadia, Florida 33821 Representing Hardee County Timothy F. Campbell Assistant County Attorney Post Office Box 60 Bartow, Florida 33830 Representing Polk County Brian Sodt Central Florida Regional Planning Council P. O. Box 2089 Bartow, Florida 33830 Lawrence N. Curtin Attorney at Law Holland & Knight P. O. Drawer 810 Tallahassee, Florida 32302-0810 Honorable Lawton Chiles Governor State of Florida The Capitol Tallahassee, Florida 32399 Honorable Robert A. Butterworth Attorney General State of Florida The Capitol Tallahassee, Florida 32399-1050 Honorable Bob Crawford Commissioner of Agriculture State of Florida The Capitol Tallahassee, Florida 32399-0810 Honorable Douglas L. "Tim" Jamerson Commissioner of Education State of Florida The Capitol Tallahassee, Florida 32399 Honorable Jim Smith Secretary of State State of Florida The Capitol, PL-02 Tallahassee, Florida 32399-0250 Honorable Tom Gallagher Treasurer and Insurance Commissioner State of Florida The Capitol Tallahassee, Florida 32399-0300 Honorable Gerald A. Lewis Comptroller State of Florida The Capitol, Plaza Level Tallahassee, Florida 32399-0350
The Issue The issue to be determined in this case is whether a site certification should be issued to Hillsborough County for the construction and operation of a fourth municipal waste combustor unit (“Unit No. 4”) at Hillsborough County’s Resource Recovery Facility, in accordance with the provisions of the Florida Electrical Power Plant Siting Act.
Findings Of Fact The Applicant The Applicant, Hillsborough County, is a political subdivision of the State of Florida. The County owns the existing Facility and will own the proposed Project. The Facility was designed, built, and is operated by a private company pursuant to a long-term contract with the County. It is anticipated that a private company will design, construct, and operate the Project for the County. Hillsborough County’s Existing Solid Waste System The County has adopted a solid waste Comprehensive Master Plan (the “Master Plan”) in conjunction with the Cities of Tampa, Temple Terrace, and Plant City. The Master Plan provides for state-of-the-art technology and innovative approaches to recycling, waste reduction, and waste disposal. In accordance with the Master Plan, the County has developed: (a) an aggressive recycling program that significantly reduces the quantity of materials requiring disposal; (b) a resource recovery facility for waste reduction and energy recovery from those materials that are not recycled; and (c) a landfill for the disposal of ash and by-pass waste (i.e., materials that are not recycled or processed in the Facility). Hillsborough County and the three cities have used a cooperative, regional approach to solid waste management issues, while providing environmentally protective, cost-efficient programs for local residents. Despite the County’s comprehensive recycling program, the amount of solid waste generated in the County has increased each year since the Facility began operation, primarily due to population growth. The amount of solid waste generated in the County now significantly exceeds the Facility’s design capacity. Consequently, large quantities of solid waste currently are being diverted from the Facility to the County landfill. In 2005, the Board of County Commissioners decided to expand the Facility, consistent with the County’s long-standing Master Plan, rather than dispose of ever-increasing amounts of solid waste in a landfill. The Board’s decision was based on a thorough evaluation of the County’s solid waste disposal options. For these reasons, on November 21, 2005, the County filed an application with DEP for the construction and operation of Unit No. 4. The Site The Facility is located next to Falkenburg Road in an unincorporated area in the County. The Facility is southeast of the City of Tampa, west of Interstate 75 (“I-75"), and north of the Crosstown Expressway and State Road 60. The Facility was built on a 50.4-acre site (“Site”), which is in the southern portion of a 353-acre tract of land owned by Hillsborough County. The Surrounding Area The Facility is surrounded by a variety of governmental and industrial land uses. The Facility is bounded: on the south by the County’s Falkenburg Road Wastewater Treatment Plant and a railroad track that is owned by the CSX railroad company; on the west by a 230 kilovolt transmission line corridor and easement owned by Tampa Electric Company (“TECO”); on the north by vacant improved pasture land, the Falkenburg Road Jail, the Hillsborough County Department of Animal Services, and the Hillsborough County Sheriff’s Office (District 2); and on the east by Falkenburg Road and vacant land. The Facility is compatible with the adjacent and surrounding land uses. The nearest residential area is approximately 1 mile away from the Facility. It is located on the opposite (east) side of I-75. Zoning and Land Use In 1984, the Siting Board determined that the Site and Facility were consistent and in compliance with the applicable land use plans and zoning ordinances. The Siting Board’s determination was based on the County’s plans for the construction and operation of four MWC units at the Facility. The Site is currently zoned “Planned Development”, and is designated “Public/Quasi-Public” under the County’s comprehensive land use plan, specifically to allow the Facility and the Project to be built and operated on the Site. The Existing Facility The Facility currently has three MWC units. Each MWC unit has a nominal design capacity of 400 tons per day (“tpd”) of municipal solid waste (440 tpd when burning a reference fuel with a higher heating value of 4500 British thermal units (“Btu”) per pound). The three MWC units are located inside a fully enclosed building, which also contains the air pollution control systems for the MWC units, the “tipping floor,” the refuse storage pit, and a turbine generator. The Facility also includes an ash management building, cooling tower, stack, stormwater management ponds, water treatment system, transformer yard, electrical transmission lines, and ancillary equipment and facilities. Municipal solid waste (e.g., household and commercial garbage) is delivered to the Site in trucks, which drive inside the refuse storage building to the tipping floor, where the trucks dump the MSW into the refuse storage pit. Two overhead cranes mix the waste in the refuse storage pit and then load the waste into the charging hoppers that feed the three MWC units. The combustion of the municipal solid waste produces heat, which is used to produce steam. The steam is used in a turbine generator to produce approximately 29.5 megawatts (“MW”) of electricity. The Project The Project involves the construction and operation of a fourth MWC unit at the Facility. The new unit will be substantially the same as the three existing MWC units, but larger. The new unit will be designed to process approximately 600 tpd of municipal solid waste (660 tpd @ 5000 Btu/lb). A new turbine generator also will be installed, which will increase the Facility’s electrical generating capacity by approximately 18 MW, thus increasing the Facility’s total net generating capacity to approximately 47 MW. In addition, the Facility’s cooling tower will be expanded, the refuse and ash management buildings will be expanded, two lime silos and a carbon silo will be installed, a new settling basin will be installed, and other related improvements will be made. Construction of Unit No. 4 The Facility was designed and built to accommodate the addition of a fourth MWC unit, thus making the construction of Unit No. 4 relatively simple, without disrupting large areas of the Site. Unit No. 4 will be located adjacent to the three existing MWC units. The construction of the other Facility improvements also will occur adjacent to the existing components of the Facility. Only about 0.3 acres of the Site will be converted from open space to a building or similar use. Construction of Unit No. 4 will occur in previously disturbed upland areas on the Site that are already used for industrial operations. Construction of Unit No. 4 will not affect any wetlands or environmentally sensitive areas. No new electrical transmission lines will need to be built to accommodate the additional electrical power generated by Unit No. 4. No new pipelines or other linear facilities will need to be built for the Project. The construction of Unit No. 4 will not expand the Facility beyond the boundaries of the Site that was certified by the Siting Board in 1984. Operation of Unit No. 4 The basic operation of the Facility will not change when Unit No. 4 becomes operational. Municipal solid waste will be processed at the Facility in the same way it is currently processed. The Facility has operated since 1987 and has an excellent track record for compliance with all applicable regulations, including regulations concerning noise, dust, and odors. All of the activities involving solid waste and ash occur inside enclosed buildings. The tipping floor and refuse storage pit are maintained under negative air pressure, thus ensuring that dust and odors are controlled within the building. Since the operations at the Facility will remain the same after Unit No. 4 becomes operational, no problems are anticipated in the future due to noise, dust, or odors. The Facility’s basic water supply and management system will remain the same after Unit No. 4 becomes operational. Treated wastewater from the County’s co-located Falkenburg Road Wastewater Treatment Plant (“WWTP”) will be provided via an existing pipeline to satisfy the Facility’s need for cooling water. Potable water will be provided to the Facility via an existing pipeline from the City of Tampa’s water supply plant. The Facility does not use groundwater or surface water for any of its operations. The Facility will not discharge any industrial or domestic wastewater to any surface water or groundwater. Most of the Facility’s wastewater will be recycled and reused in the Facility. Any excess wastewater will be discharged to the Falkenburg Road WWTP. Stormwater runoff from the Project will be collected and treated in the existing system of swales and ponds on the Site. The County will modify two existing outfall weirs to provide improved treatment of stormwater and to ensure compliance with water quality standards. A traffic analysis was performed to evaluate the potential traffic impacts associated with the operation of the Facility, after the Project is completed. The analysis demonstrated the Facility will not have any significant impacts on the surrounding roadway network, even when Unit No. 4 is operational. Air Quality Regulations The County must comply with federal and state New Source Performance Standards (“NSPS”) and Best Available Control Technology (“BACT”) requirements, both of which impose strict limits on the Facility’s airborne emissions. The County also must comply with Ambient Air Quality Standards (“AAQS”) and Prevention of Significant Deterioration (“PSD”) standards, which establish criteria for the protection of ambient air quality. Best Available Control Technology BACT is a pollutant-specific emission limit that provides the maximum degree of emission reduction, after taking into account the energy, environmental, and economic impacts and other costs. As part of the BACT determination, all available and feasible pollution control technologies being used worldwide are evaluated. The Department performed a BACT determination for the Project. As part of its BACT analyses, DEP determined that (a) a flue gas recirculation system and a selective non-catalytic reduction system (“SNCR”) will control NOx; (b) a spray dryer with lime injection will control MWC acid gas; (c) an activated carbon injection system (“ACI”) will control MWC organic compounds; (d) a fabric filter baghouse will control particulate matter and MWC metals; and (e) proper facility design and operating methods will control other pollutants. These air pollution control technologies (except flue gas recirculation) and methods are currently used in the three existing MWC units and they have performed extremely well. Unit No. 4 will have better, more modern, and more sophisticated versions of these air pollution control systems, plus a flue gas recirculation system. In its analysis of the Project, DEP determined the emission limits for the Project that represent BACT. All of the emission limits determined by DEP for Unit No. 4 are as low as or lower than the emission limits established in 2006 by the U.S. Environmental Protection Agency (“EPA”) in the NSPS (40 CFR 60, Subpart Eb) for new MWC units. The NSPS are based on the use of Maximum Achievable Control Technology (“MACT”). Unit No. 4 will be subject to the lowest NOx emission limits imposed on any MWC unit in the United States. The Facility will use an array of continuous emissions monitors to help ensure that the Facility is continuously in compliance with the DEP’s emission limits. Indeed, Unit No. 4 will be the first MWC unit in the United States to be equipped with a continuous emissions monitor for mercury. Protection of Ambient Air Quality The EPA has adopted “primary” and “secondary” National Ambient Air Quality Standards ("NAAQS"). The primary NAAQS were promulgated to protect the health of the general public, including the most susceptible groups (e.g., children, the elderly, and those with respiratory ailments), with an adequate margin of safety. The secondary NAAQS were promulgated to protect the public welfare, including vegetation, soils, visibility, and other factors, from any known or anticipated adverse effects associated with the presence of pollutants in the ambient air. Florida has adopted EPA’s primary and secondary NAAQS, and has adopted some Florida AAQS (“FAAQS”) that are more stringent than EPA’s NAAQS. The County analyzed the Project’s potential impacts on ambient air quality, using conservative assumptions that were intended to over-estimate the Project’s impacts by a wide margin. These analyses demonstrate that the maximum impacts from Unit No. 4 will be less than one percent of the amount allowed by the ambient air quality standards. The maximum impact from the Facility (i.e., all four units) will be less than 2.5 percent of the amount allowed by the FAAQS and NAAQS. For these reasons, the emissions from Unit No. 4 and the Facility are not expected to cause adverse impacts on human health or the environment. The maximum impacts of Unit No. 4 and the Facility, when operating under worst case conditions, will be immeasurably small and will be indistinguishable from ambient background conditions. Human Health and Ecological Risk Assessments The County performed a human health and ecological impact assessment of the risks associated with the Facility’s airborne emissions. The County’s risk assessment evaluated the impacts of the entire Facility, with all four MWC units in operation. The risk assessment was designed to over-estimate the potential impacts of the Facility. The County’s risk assessment was conducted in compliance with current EPA guidance. The risk assessment considered hypothetical human receptors (e.g., infants, children, and adults) that were engaged in different types of behavior (e.g., a typical resident; a beef farmer; a subsistence fisherman) and were exposed through multiple pathways (e.g., inhalation; ingestion of soil; ingestion of local produce, beef, and/or fish) to chronic long term impacts from the Facility. The risk assessment also considered the Facility’s potential impacts on sensitive environmental receptors, including aquatic life (benthic dwelling aquatic organisms), wood storks, and river otters. The County’s risk assessment demonstrates that the potential risks associated with the Facility’s emissions will not exceed, and in most cases will be much less than, the risks that are deemed acceptable by the EPA and DEP for the protection of human health and the environment. The County’s assessment is consistent with the findings in environmental monitoring studies, epidemiological studies, and risk assessments that have been performed for other modern waste-to-energy ("WTE") facilities in the United States. The County’s findings also are consistent with the determinations made by the EPA, which has concluded that WTE facilities equipped with modern pollution control systems are a “clean, reliable, renewable source of energy.” The evidence presented by the County in this case demonstrates that the Facility is not likely to have any adverse effect on human health or the environment, even when all four MWC units are operational, if the Facility is built and operated in compliance with the Conditions of Certification. Potential Impacts on Water Quality The Facility’s emissions of nitrogen oxides (i.e., NOx) will not cause or contribute to violations of any water quality standards in any surface waterbody. Environmental Benefits of the Project The addition of Unit No. 4 will provide significant environmental benefits to the County. Unit No. 4 will reduce the volume of processible solid waste by approximately 90 percent. By reducing the volume of processible waste, Unit No. 4 and the Facility will greatly extend the useful life of the County’s landfill, thus postponing the need to build a new landfill. The Facility also will convert putrescible waste into a relatively inert ash, which poses less threat to groundwater resources. The Project will also provide environmental benefits to the State of Florida. For example, the Facility will produce electricity from discarded materials. In this manner, Unit No. 4 will reduce the need to use fossil fuels to generate electricity at traditional power plants. Unit No. 4 will eliminate the need to use approximately 4 million barrels of oil and thus will save approximately $200 million in oil purchases over the next 20 years. Socioeconomic Benefits of the Project The local economy and labor market will benefit from approximately $100 million that the County will spend to construct the Project. A significant amount of construction supplies, goods, and services are anticipated to be purchased from local businesses. The Project will provide jobs for construction workers. The daily workforce is expected to average between 25 and 75 people over a period of approximately 21 months. The addition of Unit No. 4 will also provide approximately 8 new permanent jobs at the Facility. WTE Criteria in Section 403.7061 Section 403.7061, Florida Statutes, establishes several criteria that must be satisfied before an existing waste-to-energy facility may be expanded. The County has provided reasonable assurance that the Project will satisfy all of the standards and criteria in Section 403.7061, Florida Statutes. Among other things, the County has demonstrated that the County’s waste reduction rate has consistently exceeded the State’s 30 percent recycling goal. Consistency With Land Use Plans and Zoning Ordinances As required by Section 403.508(2), Florida Statutes, the County demonstrated that the Site is consistent and in compliance with the Hillsborough County comprehensive land use plan and Hillsborough County’s applicable zoning ordinances. Compliance with Environmental Standards The Department has concluded and the evidence demonstrates that the County has provided reasonable assurance the Project will comply with all of the nonprocedural land use and environmental statutes, rules, policies, and requirements that apply to the Project, including but not limited to those requirements governing the Project’s impacts on air quality, water consumption, stormwater, and wetlands. The County has used all reasonable and available methods to minimize the impacts associated with the construction and operation of the Facility. The location, construction, and operation of the Project will have minimal adverse effects on human health, the environment, the ecology of the State’s lands and wildlife, and the ecology of the State’s waters and aquatic life. The Project will not unduly conflict with any of the goals or other provisions of any applicable local, regional, or state comprehensive plan. The Conditions of Certification establish operational safeguards for the Project that are technically sufficient for the protection of the public health and welfare, with a wide margin of safety. Agency Positions Concerning Certification of the Project On May 4, 2006, the PSC issued a report concluding that the Project was exempt from the PSC’s need determination process, pursuant to Section 377.709(6), Florida Statutes. The DEP, DOT, and SWFWMD recommend certification of the Project, subject to the Conditions of Certification. The other agencies involved in this proceeding did not object to the certification of the Project. The County has accepted, and has provided reasonable assurance that it will comply with, the Conditions of Certification. Public Notice of the Certification Hearing On December 19, 2005, the County published a “Notice of Filing of Application for Electrical Power Plant Site Certification” in the Tampa Tribune, which is a newspaper of general circulation published in Hillsborough County, Florida. On May 25, 2006, the County published notice of the Certification Hearing in the Tampa Tribune. On December 23 and December 30, 2005, the Department electronically published “Notice of Filing of Application for Power Plant Certification.” On May 26, 2006, the Department electronically published notice of the Certification Hearing. The public notices for the Certification Hearing satisfy the informational and other requirements set forth in Section 403.5115, Florida Statutes, and Florida Administrative Code Rules 62-17.280 and 62-17.281(4).
Conclusions For Petitioner Hillsborough County (the “County”) David S. Dee, Esquire Young van Assenderp, P.A. 225 South Adams Street, Suite 200 Tallahassee, Florida 32301-1720 For the Florida Department of Environmental Protection (“Department” or “DEP”) Scott A. Goorland, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard, M.S. 35 Tallahassee, Florida 32399-300
Recommendation Based on the foregoing Findings of Facts and Conclusions of Law, it is RECOMMENDED that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order granting a site certification for the construction and operation of Unit No. 4 at the Hillsborough County Resource Recovery Facility, in accordance with the Conditions of Certification contained in DEP Exhibit 2. DONE AND ENTERED this 2nd day of August, 2006, in Tallahassee, Leon County, Florida. S J. LAWRENCE JOHNSTON Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 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 August, 2006.
