The Issue The issue in this case is whether Petitioner should be issued an air construction permit authorizing its Crystal River steam generating plant Units 1 and 2 to co-fire a five to seven percent blend of petroleum coke with coal.
Findings Of Fact Based upon all of the evidence, the following findings of fact are determined: Background Petitioner, Florida Power Corporation (FPC), is an investor-owned public utility engaged in the sale of electricity to approximately 1.2 million customers. Among others, it operates the Crystal River Power Plant consisting of five electric-generating units in Citrus County, Florida. Units 1, 2, 4, and 5 are coal-fired, while Unit 3 is a nuclear unit. Respondent, Department of Environmental Regulation (DEP), is a state agency charged with the statutory responsibility of regulating the construction and operation of business enterprises in a manner to prevent air pollution in excess of specified limits. Among other things, DEP issues air construction permits for a limited period of time to undertake and evaluate initial operations of a business enterprise; long- term approval subsequently is available under an air operation permit. As a part of this process, and pursuant to federal law, DEP engages in a Prevention of Significant Deterioration (PSD) review to determine if non-exempt alterations to major facilities result in net emission increases greater than specified amounts. Under certain conditions, however, the use of alternative fuels or raw materials are exempted from PSD review. Intervenor, Legal Environmental Assistance Foundation, Inc. (LEAF), is a non-profit Alabama corporation licensed to do business in the State of Florida. It is a public interest advocacy organization whose corporate purposes include securing environmental and health benefits from clean air and water. Intervenor, Sierra Club, Inc. (Sierra Club), is a public interest advocacy organization incorporated in California and doing business in Florida. Its corporate purposes include securing the environmental and health benefits of clean air and water. On December 26, 1995, FPC filed an application with DEP for an air construction permit authorizing it to burn a blend of petroleum coke and coal in its existing coal-fired Units 1 and 2 at the Crystal River Power Plant in Citrus County, Florida. In the application, FPC did not address PSD review since it believed it qualified for an exemption from PSD permitting under Rule 62- 212.400(2)(c)4., Florida Administrative Code. That rule exempts from PSD review the [u]se of an alternative fuel or raw material which the facility was capable of accommodating before January 6, 1975, unless such change would be prohibited under any federally enforceable permit condition which was established after January 6, 1975. After reviewing the application, DEP issued an Intent to Deny on June 25, 1996. In that document, DEP stated that [a]ccording to information in Department files, both Units 1 and 2 operated on liquid fuel prior to January 6, 1975. Very substantial modifications of the boilers and pollution control equipment were implemented thereafter by [FPC] to convert the units to coal-firing mode. Therefore the project does not qualify for the exemption from PSD review claimed by the company. Contending that it was entitled to an exemption from PSD review and therefore a permit, FPC filed a Petition for Administrative Hearing on October 4, 1996. In its Petition, FPC generally alleged that petroleum coke is a product with characteristics very similar to coal; Units 1 and 2 were capable of accommodating coal and petroleum coke as of January 6, 1975; and contrary to the statements in the Intent to Deny, any boiler modifications and pollution control improvements to those units were minor and not substantial. The Permitting Program The PSD program is based on similar PSD requirements found in the federal Clean Air Act of 1970, as amended (the Act). The permitting program is a federally required element of DEP's State Implementation Plan (SIP) under Section 110 of the Act. DEP has fulfilled the requirement of administering the federal PSD program by obtaining approval from the Environmental Protection Agency (EPA) of state PSD regulations that meet the requirements of federal law. The requirements of the SIP are found in Chapters 62-204, 62-210, 62-212, 62-296, and 62-297, Florida Administrative Code. Chapter 62-212 contains the preconstruction review requirements for proposed new facilities and modifications to existing facilities. Rule 62-212.400, Florida Administrative Code, establishes the general preconstruction review requirements and specific requirements for emission units subject to PSD review. The provisions of the rule generally apply to the construction or modification of a major stationary source located in an area in which the state ambient air quality standards are being met. Paragraph (2)(c) of the rule identifies certain exemptions from those requirements. More specifically, subparagraph (2)(c)4. provides that a modification that occurs for the following reason shall not be subject to the requirements of the rule: 4. Use of an alternative fuel or raw material which the facility was capable of accommodating before January 6, 1975, unless such change would be prohibited under any federally enforceable permit condition which was established after January 6, 1975. The rule essentially tracks verbatim the EPA regulation found at 40 CFR 52.21(b)(2)(iii)(e)1. Therefore, in order to qualify for an exemption from PSD review, FPC must use "an alternative fuel . . . which [Units and 2 were] capable of accommodating before January 6, 1975." In addition, FPC must show that "such change would [not] be prohibited under any federally enforceable permit condition which was established after January 6, 1975." Contrary to assertions by Respondent and Intervenors, in making this showing, there is no implied or explicit requirement in the rule that FPC demonstrate that it had a subjective intent to utilize petroleum coke prior to January 6, 1975. The Application and DEP's Response In its application, FPC proposes to co-fire a five percent (plus or minus two percent) blend of petroleum coke with coal, by weight. It does not propose to make any physical changes to Units 1 and 2 to utilize petroleum coke. Also, it does not request an increase in any permitted air emission rates for the units because it can meet its current limits while burning the proposed blend rate of petroleum coke with coal. The application included extensive fuel analysis and air emissions data obtained from a DEP-authorized petroleum coke trial burn conducted from March 8 until April 4, 1995. Although it is not proposing to make physical changes to the plant, FPC applied for the air construction permit in deference to DEP's interpretation that such a permit is required when a permittee utilizes an alternative fuel. After completing his initial review, the DEP supervisor of the New Source Review program acknowledged in a memorandum to his supervisor that FPC was "entitled to a permit" but suggested that FPC be asked to "change their minds." Before the permit was issued, however, DEP changed its mind and issued an Intent to Deny on the ground that prior to January 6, 1975, Units 1 and 2 were not capable of accommodating coal or a blend of petroleum coke with coal. The Units Unit 1 has a generating capacity of 400 MW and commenced operation as a coal-fired plant in October 1966. It fired coal until March 1970, fuel oil until October 1978, and then again fired coal from June 1979 to the present. Unit 2 has a generating capacity of 500 MW and commenced operations as a coal-fired plant in November 1969. It fired coal until September 1971, fired fuel oil from December 1971 until October 1976, and then again fired coal from December 1976 to the present. Original equipment installed during the initial construction of Units 1 and 2 included the following: the barge unloader, which removes coal from barges that deliver coal from New Orleans; the stacker/reclaimer, which stacks the coal into piles and then reclaims the coal by directing it from the coal piles to conveyors that deliver it to the units; the crusher house, which has two crushers that crush the coal on the way to units down to nuggets no larger than three-quarters of an inch in diameter; the silos, which store the crushed coal; the feeders, located below the silos, which regulate the flow of coal from the silos to the pulverizers; the pulverizers, which grind the coal in preparation for combustion and then direct the pulverized coal to the burners, which are located on the corners of each unit's boiler; and the boilers, where the fuel is combusted, imparting heat to water contained in the waterwalls and thereby producing steam for electrical generation. The foregoing equipment was reflected in the plant's construction specifications and remains in operation, on site, at the plant. Components and parts of this equipment have been maintained, replaced, and repaired periodically. The original operations manual for the barge unloader, stacker/reclaimer, crushers, and conveyor systems are still kept and utilized on site. The primary fuel utilized in Units 1 and 2 is coal, although these units also co-fire from one to five percent number fuel oil and used oil. The combustion of fuel in Units 1 and 2 results in air emissions. As a result of changing regulatory requirements, there have been substantial improvements to the units' air pollution control capabilities since original construction. Existing Air Permits Unit 1 currently operates under Air Operation Permit Number A009-169341. Unit 2 operates under Air Operation Permit Number A-009-191820. Both permits were amended by DEP on October 8, 1996. Although each air operation permit contains an expiration date that has been surpassed, the permits remain in effect under DEP's regulations during the pendency of the agency's review of FPC's applications for air operation permits under the new Title V program found in Chapter 62-213, Florida Administrative Code. The air operation permits governing Units 1 and 2 contain mass emission rate limitations of 0.1 pounds/million (mm) British thermal units (Btu) or particulate matter (PM), and 2.1 pounds/mmBtu for sulfur dioxide. These mass emission rate limitations restrict the amount of each pollutant (measured in pounds) that is to be released into the atmosphere per million Btu of heat energy by burning fuel. The PM limitation is applicable to Units 1 and 2 under state regulations originally promulgated in 1972. The sulfur dioxide limitation was established in 1978 as a result of a PSD air quality analysis performed in conjunction with the permitting of Units 4 and 5. Prior to 1978, sulfur dioxide limits promulgated early in 1975 imposed a limit of 6.17 pounds/mmBtu on coal-fired operations at Units 1 and 2. Because Units 1 and 2 were subjected to a PSD air quality impact analysis along with Units 4 and 5, the units' sulfur dioxide emission limits were reduced from 6.17 to 2.1 pounds/mmBtu. The 2.1 pounds/mmBtu sulfur dioxide emission limitation applicable to Units 1 and 2 was set with the intention of assuring no adverse air quality impacts. The sulfur dioxide impacts associated with Units 1, 2, 4, and 5, after collectively being subjected to PSD air quality review, were much lower than the sulfur dioxide impacts previously associated with only Units 1 and 2. Is Petroleum Coke an Alternative Fuel? Petroleum coke is a by-product of the oil refining process and is produced by many major oil companies. The oil refineries refine the light ends and liquid products of oil to produce gasoline and kerosene, resulting in a solid material that resembles and has the fuel characteristics of coal. Both historically and presently, it has been common- place for electric utilities to rely on petroleum coke as fuel. For example, during the period 1969 through 1974, regular shipments of petroleum coke were sent to various electric utility companies throughout the United States to be co-fired with coal. In addition, DEP has issued permits for Tampa Electric Company to co-fire petroleum coke with coal. In 1987 and again in 1990, the EPA promulgated air- emission regulations which specifically define "coal" as including "petroleum coke." DEP has incorporated these regulations by reference at Rule 62-204.800(7)(b) 3. and 4., Florida Administrative Code. Given these considerations, it is found that petroleum coke constitutes an alternative fuel within the meaning of Rule 62-212.400(4)(c)4., Florida Administrative Code. Were the Units Capable of Accommodating the Fuel? Petroleum coke and coal are operationally equivalent. Petroleum coke can be handled, stored, and burned with the existing coal handling equipment at Units 1 and 2. The barge unloader, stacker/reclaimer, storage areas, conveyors, silos, crusher house, pulverizers, and burners, all installed prior to 1975, can handle petroleum coke. The equipment comprising Units 1 and 2 does not require any modification in order to burn a blend of petroleum coke with coal. Also, there will be no net impact on steam generator design or operation, and there will be no decline in performance or adverse impacts to the boilers. FPC could have co-fired petroleum coke with coal historically without making physical alterations or derating the units. Similarly, petroleum coke can be fired in Units 1 and 2 now without alterations or derating. These findings are further supported by Petitioner's Exhibits 35 and 36, which are reference books published in 1948 and 1967 by the manufacturer of the equipment installed at Units 1 and 2. They confirm that prior to 1975, petroleum coke was suitable for the manufacturer's boilers and pulverizers. Unrebutted testimony demonstrated that Units 1 and 2 could have co-fired petroleum coke with oil during the oil-firing period. Even when Units 1 and 2 fired oil instead of coal for a period of time in the 1970s, the coal-handling equipment remained in existence on-site and available for use, and both units remained readily convertible to their original, coal-firing modes. Because the plant remained capable of accommodating coal, it also remained capable of accommodating petroleum coke. In light of the foregoing, it is found that co-firing petroleum coke with coal at Units 1 and 2 could have been accomplished prior to January 6, 1975. Are there Post-January 6, 1975, Prohibitions? There is no evidence to support a finding that a federally enforceable permit condition was establshed after January 6, 1975, that prohibits co-firing petroleum coke with coal. I. Miscellaneous By letters dated February 14 and June 2, 1997, the EPA Region IV office replied to inquiries from DEP regarding the instant application. The conclusions reached in those letters, however, were based on a misapprehension of the facts in this case. Therefore, the undersigned has not credited these letters. To prove up its standing, LEAF introduced into evidence a copy of its articles of incorporation and a brochure describing the organization. In addition, it asserted that the air quality for its members would be "at risk" if Units 1 and 2 did not meet PSD standards and air emissions were "increased." Intervenor Sierra Club proffered that a substantial number of members "live, work, or recreate in the vicinity of the Crystal River Units 1 and 2, and in the area subject to the air emissions by those units," and that those members "would be substantially affected by the proposed exemption."
Recommendation Based on the foregoing findings of fact and conclusions of law, it is RECOMMENDED that the Department of Environmental Protection enter a final order granting the application of Florida Power Corporation and issuing the requested air construction permit. DONE AND ORDERED this 23rd day of September, 1997, in Tallahassee, Leon County, Florida. DONALD R. ALEXANDER Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1560 (904) 488-9675 SUNCOM 278-9675 Fax Filing (904) 921-6847 Filed with the Clerk of the Division of Administrative Hearings this 23rd day of September, 1997. COPIES FURNISHED: Kathy Carter, Agency Clerk Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 James S. Alves, Esquire Post Office Box 6526 Tallahassee, Florida 32314-6526 W. Douglas Beason, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Mail Station 35 Tallahassee, Florida 32399-3000 Gail Kamaras, Esquire 1115 North Gadsden Street Tallahassee, Florida 32303-6327 Jaime Austrich, Esquire Post Office Box 1029 Lake City, Florida 32056-1029 F. Perry Odom, Esquire Department of Environmental Protection 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000
The Issue The issue is whether certain provisions within proposed rule 62-296.470 are an invalid exercise of delegated legislative authority, as alleged in the Petition for Administrative Determination of Invalidity of Specific Provisions of a Proposed Rule (Petition) filed by Petitioner, Florida Power and Light Company (FPL), on August 16, 2006.
Findings Of Fact Based on the evidence presented by the parties, the following findings of fact are made: The Parties FPL is Florida's largest electric utility, serving over four million residential, commercial, and industrial accounts in thirty-five counties throughout southern and eastern Florida, or approximately forty percent of the state population. Its business address is 700 Universe Boulevard, Juno Beach, Florida. It owns and operates over 20,000 megawatts (MW) of electric generating capacity. Approximately seventy-seven percent of FPL's self-generated energy comes from fossil fuels, primarily oil and natural gas. The remaining twenty-three percent of self-generation comes from nuclear power or is produced from non-polluting renewable sources. Approximately sixty-six percent of the fossil fuel self-generation relies on clean- burning natural gas, with oil making up another twenty-seven percent. About seven percent comes from coal, with two-thirds of that generated from the Southern Company's Scherer Unit 4, which is located in Georgia. Only 232 MW, or 1.1 percent of FPL's total capacity comes from coal plants in Florida. FPL has an additional 1,144 MW generating unit set to come on-line in 2007, which also relies on natural gas generation. FPL participated in the rulemaking process before the Department and ERC and objected to the use of fuel adjustment factors in the rule. FPL also informed the Department and ERC of the economic impact to its customers of the proposed rule, and the Department addressed FPL's comments in its SERC. The Department is the state agency charged with the responsibility of regulating discharges from the EGUs, including those of FPL. It must also implement the programs required under the federal Clean Air Act. See § 403.061(35), Fla. Stat. ("The Department of Environmental Protection shall implement the programs required under the federal Clean Air Act"). Among other things, that Act requires the Department to develop rules to implement the CAIR, including reductions in emissions of SO2 and NOx from EGUs in the State. Gulf is an investor-owned electric utility with a service territory that is bounded on the Alabama border on the west and runs to the Apalachicola River on the east, and from the Alabama border on the north to the Gulf of Mexico to the south. It serves approximately 394,722 retail customers directly and an additional 14,128 customers through the wholesale delivery of electricity to one investor-owned electric utility and one municipality. Gulf serves customers in seventy- one towns and communities. Its total generating capacity is 2,711,900 kilowatts (KW) and its thirteen units are fueled by coal and natural gas. Gulf participated in the proceedings which culminated in the proposed rule and supports the Department's position. FPC is an investor-owned electric utility with coal- fired, gas-fired, and oil-fired generating units whose service area is in central and northern peninsular Florida. It presently serves 1,583,000 customers and has a total generating capacity of 9,365 MW. FPC also supports the proposed rule. TECO is an investor-owned electric utility with 4,400 MW of generating capacity serving over 645,000 residential, commercial, and industrial customers in the Tampa Bay area. Its plants use coal, natural gas, and oil for the generation of electric power. TECO has intervened in support of the proposed rule. Seminole is a generation and transmission cooperative. It operates the Seminole Generating Station and the Payne Creek Generating Station with capacities of 1,300 and 500 MW, respectively. In addition, construction is nearing completion on 310 MW of combustion turbine peaking units at the Payne Creek Generating Station site. The Seminole Generating Station is fired by coal, while the Payne Creek Generating Station is fired by natural gas and Number 2 fuel oil. Seminole provides service to an estimated 1,600,000 customers in forty-six counties. It supports the proposed rule. JEA owns, operates, and manages the electric system established by the City of Jacksonville and is the largest community-owned utility in the State. JEA serves in excess of 366,000 customers in Jacksonville and parts of three adjacent counties. The generating plants are fueled by coal, petroleum coke, oil, and natural gas. JEA supports the proposed rule. Cedar Bay owns and operates a cogeneration facility located in Jacksonville, Florida. The facility burns crushed coal to generate approximately 258 MW (net output) of electricity and provides steam to a kraft paper recycling mill. Cedar Bay will be regulated by the proposed rule and supports its adoption. Indiantown owns and operates a cogeneration facility located near the community of Indiantown in the southwestern portion of Martin County, Florida. The facility burns pulverized coal to generate approximately 330 MW (net output) of electricity and provides steam to a citrus processing facility. Indiantown is also regulated by the rule and supports the proposed rule. The Department is unwilling to stipulate to the facts that would form the basis for FPL's standing to challenge the rule. (If FPL lacks standing to challenge the rule under the theory posited by the Department, then Intervenors likewise lack standing to support the rule.) The record shows, however, that FPL and Intervenors own EGUs or cogeneration facilities, those facilities will be regulated by the proposed rule, and their substantial interests will accordingly be affected by the implementation of the rule. Background The underlying history which prompted the adoption of the proposed rule in issue is lengthy and somewhat complex. The federal Clean Air Act (42 U.S.C. §§ 7401 et seq.) was enacted in 1970 and forms the primary legal basis for air pollution programs in the United States. Section 110 of the Clean Air Act (42 U.S.C. § 7410) requires every state to adopt a state implementation plan (SIP) for implementing the requirements of the Clean Air Act. Among other things, the SIP must describe how each state will achieve compliance with National Ambient Air Quality Standards (NAAQS) promulgated by the EPA. One provision of the Clean Air Act, commonly referred to as the "Good Neighbor Provision," provides that emissions from one state shall not significantly interfere with another state's attainment of compliance with the NAAQS. See 42 U.S.C. § 7410(a)(2)(D)(i). In 2004, the EPA began rulemaking to address the non- attainment of NAAQS in a number of states where non-attainment was caused or contributed to by airborne emissions from upwind states. Among other things, the EPA determined that Florida EGUs contribute significantly to non-attainment of NAAQS in a small number of counties in Georgia and Alabama, including those counties in which the cities of Birmingham, Alabama, and Atlanta and Macon, Georgia, are located. On May 12, 2005, CAIR was promulgated by the EPA and generally requires (through implementation in two phases, the first of which begins in 2009) reductions in emissions of SO2 and/or NOx from EGUs in twenty-eight eastern states, including the State of Florida, and the District of Columbia, all of whom are considered upwind states. In adopting CAIR, the EPA determined that Florida, and other upwind states, contribute significantly to the non- attainment by downwind states of NAAQS for fine particles and/or 8-hour ozone, and they interfere with the maintenance of those standards. The CAIR requires Florida (and other affected states) to revise its SIP to include control measures to reduce emissions of SO2 and NOx so as to enable the downwind states to achieve and maintain the required standards. CAIR provides that in the event a state does not timely file a SIP modification satisfactory to EPA by September 2006, a federal implementation plan will apply within the state until proper modifications are filed. (Presumably, the Department complied with this requirement by adopting a rule before September 2006, even though the rule is now subject to a challenge which may not be concluded, after court appeals, until 2007 or even 2008. In addition, and probably in late 2005, FPL filed suit in the United States Court of Appeals for the District of Columbia challenging EPA's CAIR. That matter still remains pending as of this time.) Under CAIR, EPA determined "budgets" (or numerical limitations) for the pollutants that each state could emit consistent with its goal of avoiding significant contributions to downwind non-attainment. With respect to NOx emissions, which are at issue here, the CAIR states were allocated a share of the region-wide pool of available NOx allowances based on the heat input of the fuel burned by EGUs within the state, with fuel adjustment factors applied to adjust the heat input based on the type of fuel burned. In other words, EPA based its distribution scheme on heat input, subject to fuel adjustment factors. This is referred to as the fuel-adjusted heat input allocation method. The specific fuel adjustment factors used by EPA for allocation to the states were 100 percent for coal, 60 percent for oil, and 40 percent for gas. These factors, when multiplied by heat input, determine the proportion of available allowances to each utility. As the numbers imply, under this methodology more emission credits are allocated to coal-fired units than to EGUs that rely on gas and oil generation. In choosing these percentage factors, the EPA concluded that they take into account the relatively greater burden on coal-fired units to control emissions, that the allocation methodology will have little effect on overall compliance costs or environmental outcome, and that the fuel adjustment factors provide a more equitable budget distribution methodology for allocation credits. See Joint Exhibit 5. Thus, under the EPA distribution scheme, utilities with a higher proportion of coal-fired EGUs (such as Intervenors) would receive a higher proportion of allowances to continue operating and provide fuel diversity, while FPL, which has very little coal-fired electric generation, will receive fewer pollution allowances. Indeed, FPL claims that due to its heavy reliance on oil and gas, the redirection of credits to coal plants under the challenged provisions will cause it to "lose" 7,000 pollution credits to other utilities, and its regulatory costs will rise around $13 million per year. Although states are encouraged by the EPA to use the above fuel adjustment factors, a state is allowed to allocate NOx allowances to EGUs on whatever basis it chooses so long as it substantially complies with CAIR. For example, it may use other allowance methodologies, such as one which allocates allowances based on the electricity generated by EGUs rather than the heat used for generation (as found in EPA's Model Rule). For the State of Florida, EPA allocated 99,445 NOx allowances for the years 2009-2014 (phase 1) and 82,871 allowances for 2015 and subsequent years (phase 2). EPA's allocation of NOx allowances establishes the state cap, that is, the total amount of NOx that may be emitted by all of the EGUs in Florida combined, unless allowances are acquired from out-of- state sources in a cap and trade system. Florida's cap is less than the current annual NOx emissions from the EGUs in Florida. In a cap and trade system, which the Department has chosen to use, the regulator (EPA) sets a cap on emissions in a geographic area and then allocates allowances to the facilities in the State that is subject to the cap. Both FPL and Intervenors (and other entities operating EGUs or cogeneration facilities) are subject to the cap and are required to have at least one allowance for each ton of emissions. The proposed rule acts as an absolute bar to any emissions of NOx for Florida EGUs which do not have sufficient allowances. If a regulated facility does not receive enough allowances from the state, the facility may reduce its emissions by reducing operations or installing air pollution control systems. The facility may also purchase allowances from anyone that has a surplus of allowances. If a regulated facility has a surplus of allowances, the facility may sell its allowances or a facility may save, or bank, its allowances and then use or sell the allowances in a subsequent year. Although EPA has not mandated that states use a cap and trade system for the CAIR, as noted above, it has encouraged states to do so and has prepared a Model Rule that states may adopt to implement a CAIR cap and trade system. States adopting EPA's Model Rule will be deemed to be in compliance with the CAIR. To opt into the federal cap and trade system, the Department was required to either adopt the EPA Model Rule or adopt other regulations substantially identical to the Model Rule. On May 26, 2006, the Department published a Notice of Proposed Rulemaking (Notice) in the Florida Administrative Weekly advising that it intended to create a new rule 62-296.470 which implements the CAIR, that it would opt into the cap and trade system, and that it would use the fuel adjustment factors found in EPA's Model Rule. The proposed rule was approved for adoption by the ERC on June 29, 2006, subject to certain minor modifications. The ERC exercises the standard-setting authority of the Department under Chapter 403, Florida Statutes. See § 403.804(1), Fla. Stat. On July 21, 2006, the Department published in the Florida Administrative Weekly a Notice of Change, which reflected minor revisions to the proposed rule not relevant here and set out its final language. The Notice of Change indicates that the Department relied upon Sections 403.061 and 403.087, Florida Statutes, as the specific authority for adopting the rule and Sections 403.031, 403.061, and 403.087, Florida Statutes, as the laws being implemented. In the Joint Proposed Final Order, as well as various exhibits, the Department has more precisely identified Section 403.061(35), Florida Statutes, as the statute which grants it specific authority to adopt the rule in question and the statute which is being implemented. That provision states that the Department must "[e]xercise the duties, powers, and responsibilities required of the state under the federal Clean Air Act, 42 U.S.C. ss. 7401 et seq. The department shall implement the programs required under that act in conjunction with its other powers and duties." The Challenged Provisions The entire proposed rule is lengthy and need not be repeated in full here. Relevant to this controversy are subparagraphs (B) through (D) of paragraph (3)(d)3.(i), which contain the challenged fuel adjustment factors. The latter paragraph, including the challenged provisions, reads as follows: (3) * * * * The baseline heat input (in mmBtu) used with respect to CAIR NOx allowance allocations under paragraph (b) of this section for each CAIR NOx unit will be: For units commencing operation before January 1, 2000: the average of the 3 highest amounts of the unit's adjusted control period heat input for 2000 through 2004; for units commencing operation on or after January 1, 2000, and before January 1, 2007: the average of the 3 highest amounts of the unit's adjusted control period heat input over the first 5 calendar years following the year in which the unit commenced operation, or the average of the 2 highest amounts of the of the unit's adjusted control period heat input over the first 4 calendar years following the year in which the unit commenced operation, or the maximum adjusted control period heat input over the first 1 to 3 calendar years following the year in which the unit commenced operation, depending on the maximum number (1 to 5) of such calendar years of data available to the permitting authority for determination of allowance allocations pursuant to sections 96.141(a) or 96.141(b); with the adjusted control period heat input for each year calculated as follows: If the unit is 85 percent or more (on a BTU basis) biomass-fired during the year and is subject to best available control technology (BACT) for NOx emissions, the unit's control period heat input for such year is multiplied by 150 percent; If the unit is coal-fired during the year, and not subject to paragraph (a)(1)(i)(A) of this section for the year, the unit's control period heat input for such year is multiplied by 100 percent; If the unit is oil-fired during the year, the unit's control period heat input for such year is multiplied by 60 percent; and If the unit is not subject to paragraph (a)(1)(i)(A), (B), or (C) of this section, the unit's control period heat input for such year is multiplied by 40 percent. Identical language regarding the challenged fuel adjustment factors is also found in subparagraphs (B) through of paragraph (5)(d)3.(i), which reads as follows: (5) * * * * The baseline heat input (in mmBtu) used with respect to CAIR NOx Ozone Season allowance allocations under paragraph (b) of this section for each CAIR NOx Ozone Season unit will be: For units commencing operation before January 1, 2000: the average of the 3 highest amounts of the unit's adjusted control period heat input for 2000 through 2004; for units commencing operation on or after January 1, 2000, and before January 1, 2007: the average of the 3 highest amounts of the unit's adjusted control period heat input over the first 5 calendar years following the year in which the unit commenced operation, or the average of the 2 highest amounts of the of the unit's adjusted control period heat input over the first 4 calendar years following the year in which the unit commenced operation, or the maximum adjusted control period heat input over the first 1 to 3 calendar years following the year in which the unit commenced operation, depending on the maximum number (1 to 5) of such calendar years of data available to the permitting authority for determination of allowance allocations pursuant to sections 96.141(a) or 96.141(b); with the adjusted control period heat input for each year calculated as follows: If the unit is 85 percent or more (on a BTU basis) biomass-fired during the year and is subject to best available control technology (BACT) for NOx emissions, the unit's control period heat input for such year is multiplied by 150 percent; If the unit is coal-fired during the year, and not subject to paragraph (a)(1)(i)(A) of this section for the year, the unit's control period heat input for such year is multiplied by 100 percent; If the unit is oil-fired during the year, the unit's control period heat input for such year is multiplied by 60 percent; and If the unit is not subject to paragraph (a)(1)(i)(A), (B), or (C) of this section, the unit's control period heat input for such year is multiplied by 40 percent. On August 10, 2006, FPL filed its Petition challenging subparagraphs (B) through (D) of paragraphs (3) and (5) on the ground they constitute an invalid exercise of delegated legislative authority. More specifically, the Petition alleged in relevant part that for the following reasons, the challenged provisions constitute an invalid exercise of delegated authority: The agency exceeded its grant of rulemaking authority in including fuel adjustment factors set out in the Challenged Provisions. The Challenged Provisions enlarge, modify, or contravene the specific provisions of law implemented, have no basis in any explicit power or duty identified in the statutory language and go beyond the particular powers and duties conferred to DEP. The Challenged Provisions are arbitrary and capricious, are unsupported by necessary facts or logic and without thought or reason or irrational, and are therefore an invalid exercise of delegated legislative authority. See Fla. Stat. § 120.52(8)(e). In employing fuel-biased allocation factors to adjust the allocation of compliance costs in a manner divorced from any incremental environmental benefit and, inter alia, lessening compliance costs for certain fuel types at the expense of others, creating economic incentives for certain fuels, creating disincentives for fuels that are already at a cost advantage, and setting up a system of cross subsidies among fuel types, DEP went beyond the particular powers and duties conferred upon it, and also impinged in the statutory jurisdiction of the Florida Public Service Commission set out in sections 366.04 and 366.05, Florida Statutes. The Challenged Provisions impose excess regulatory costs upon FPL and the public as a whole that are not justified by any incremental environmental benefit. The inclusion of the Challenged Provisions in the proposed rule fails to adhere to the agency's duty to consider economic impacts and weigh the relative risks and benefits to the public and the environment pursuant to section 403.804(1), Florida Statutes, and imposes excess regulatory costs in violation of section 120.541(1)(d), Florida Statutes. Petition, paragraphs 45-49. In short, FPL contended in its initial pleading that the inclusion of the fuel adjustment factors that EPA encourages states to use is outside the rulemaking authority of the Department, is arbitrary and capricious, contravenes the legislative purpose, and imposes excess regulatory costs that could otherwise be avoided. In addition, the Petition alleged that the SERC was improperly prepared by the Department in several respects. Besides Section 120.52(8), Florida Statutes2, the Petition also cited Sections 120.54, 120.541, 120.56(1) and (2), 120.57, 366.04, 366.05, 403.021, 403.031, 403.061, 403.087, and 403.804, Florida Statutes, as the provisions which require that the proposed rule be invalidated. Does the rule exceed the statutory grant of authority? FPL has alleged that the rule goes beyond the specific powers and duties conferred upon the Department by Chapter 403, Florida Statutes, to promulgate regulations implementing CAIR. As noted above, the Department has cited Section 403.061(35), Florida Statutes, as the underlying grant of authority for adopting the rule. That statute requires the Department to "[e]xercise the duties, powers, and responsibilities required of the state under the federal Clean Air Act, 42 U.S.C. ss. 7401 et seq. The department shall implement the programs required under that act in conjunction with the other powers and duties." The Clean Air Act gives EPA authority to require submission of an appropriate SIP from any state that contributes to a violation of NAAQS in any other state. Using this authority, EPA promulgated CAIR. Florida is considered an upwind state and is therefore subject to these new standards. Thus, the Department must "implement the programs required under that act." CAIR provides Florida with the option of achieving compliance with the new standards by either mandating reductions of NOx at each source by requiring each EGU to alter production or operations, or to participate in an interstate cap and trade program. Florida has opted to participate in the cap and trade program, and the rule was tailored to do so. Under CAIR, EPA requires states participating in the cap and trade program to allocate a fixed number of allowances to the state EGUs. FPL concedes that the proposed rule, including the challenged provisions, will comply with this federal requirement because the Department essentially adopted the federal Model Rules. Although the Department could have complied with the federal requirement in a way more favorable to FPL, the rule, as written, is clearly within the grant of authority given under Section 403.061(35), Florida Statutes, since it does nothing more than "implement the programs required under the [Clean Air Act]." Does the rule enlarge, modify, or contravene the specific provisions of the law implemented? FPL further contends that because the proposed rule uses a fuel-biased allocation method not required under the statute, and it does not serve an environmental purpose, the challenged provisions enlarge the specific provisions of the law being implemented. As noted above, Section 403.061(35), Florida Statutes, requires that the Department adopt rules to implement the requirements of the Clean Air Act. While FPL may quarrel with the fuel adjustment factors in the rule which favor coal-fired units, the Department's decision to adopt the EPA's Model Rule is consistent with its statutory authority to implement EPA's programs under the Clean Air Act. Is the rule arbitrary and capricious? FPL next contends that coal EGUs do not need a subsidy; there are significant defects in the Department's economic analysis; the Department incorrectly concluded that FPL would not bear any net compliance costs; the Department's proposal will be more costly than estimated; and these erroneous considerations collectively led to an arbitrary and capricious decision to utilize the fuel adjustment factors in violation of Section 120.52(8)(e), Florida Statutes. To overcome this claim, there must be evidence in the record showing that the rule is supported by facts and logic, and that the Department's decision was reached after giving thought or reason to the matter. After EPA adopted CAIR in May 2005, the Department began its rule development process by meeting with utilities and other interested parties interested in the implementation of CAIR. It also conducted three public meetings or workshops and encouraged the utilities to reach a consensus on how to distribute the CAIR allowances. Early on, the Department decided to participate in the cap and trade program, a decision supported by all parties, including FPL. No consensus was reached on how to distribute the pollution allowances, as the parties aligned themselves in the manner in which they are in this case: the utilities that primarily burn coal versus the utilities that primarily burn natural gas. After concluding that a consensus would probably not be reached, the Department hired a consultant, Dr. Paul M. Sotkiewicz, to assist it in analyzing the implementation options for CAIR and the Clean Air Mercury Rule (CAMR), which is not in issue here. Although the Department considered using a number of variations of the proposed rule during the rule adoption process, and relied on several different bases for doing so, it finally concluded that, with some minor changes, the EPA's Model Rule should be adopted. (For example, the Department considered using a heat input approach with fuel adjustment factors adopted by EPA; a heat input approach with no fuel adjustment factors; and an output approach, based upon the amount of fuel required to produce a unit of electricity.) During the entire process, the Department carefully considered the information presented by FPL and other parties and as well as a number of policy issues, including energy efficiency, fuel diversity, economic impacts, and environmental impacts. It also relied upon Dr. Sotkiewicz's conclusion, accepted by the undersigned as being credible, that the overall cost of compliance with CAIR in Florida would be the same under each of the proposed allocation schemes being evaluated by the Department and that the overall effect on ratepayers would be same. As to FPL, if the proposed rule becomes effective, the impact on its customers will be de minimus, that is, it will add approximately $0.33 per month for a customer using 1,000 killowatt hours of electricity. On the other hand, if FPL's proposal were accepted, there would be a financial impact on the customers of the utilities that utilize large percentages of coal-fired electric generation. In choosing to adopt the rule as finally proposed, the Department was guided by five broad principles: protecting the state's status as an attainment area for air quality standards; accommodating the state's future growth in demand for electricity; promoting new, more efficient power production technologies; maintaining fuel diversification across the fleet of EGUs in the State; and minimizing the impact of CAIR on the utility customers. These principles constitute rational and valid concerns to consider when adopting a rule such as this. The greater weight of evidence supports a finding that air quality will be protected because EGUs will comply with the cap on the state's NOx emissions; the environmental benefits of CAIR will be achieved in accordance with EPA's plan; the rule's approach to allocation of allowances encourages the use of more efficient power production technologies in new EGUs; the rule will not materially affect fuel diversification in the state's existing fleet of EGUs; the rule will not likely affect a utility's decision regarding the type of EGU to build in the future; and it protects the state's ratepayers because it allows the EGUs to participate in a cap and trade program. The proposed rule is very similar to the EPA Model Rule, except for certain exceptions which address issues unique to a high growth state such as Florida. In addition, the evidence shows that coal-fired EGUs will bear the greatest costs when complying with CAIR. This is true no matter which allocation scheme is selected by the Department. It was not illogical for the Department to adopt a distribution system for NOx allowances that places more NOx allowances with the utilities who will need them the most. Based on sound public policy, this same approach was taken by the EPA when distributing NOx allowances to the States, when creating the Model Rule, and when adopting the federal implementation plan. The fact that fuel costs for coal-fired EGUs are currently lower than the fuel costs for gas and oil-fired EGUs does not require the adoption of a different system for distributing NOx allowances. Indeed, fuel costs are only one component of the total cost of generating electricity. Although FPL generates electricity primarily by using oil and natural gas-fired units, its customers enjoy some of the lowest costs for electricity in the State. Placing NOx allowances with the other utilities is not irrational. FPL contends that the Department should have adopted the system advocated by FPL for the distribution of NOx allowances. However, this proposal was considered and rejected by the EPA, ERC, and Department. Even if the challenged provisions are applied to FPL, it will receive NOx allowances, as a percentage of emissions, at a level that is above the average for all utilities. On average, each utility will receive NOx allowances under the proposed rule equal to 44.4 percent of their NOx emissions in 2004. FPL will receive 45.8 percent, or more than the average utility. If FPL's proposed allocation had been adopted, it would receive allowances equal to 64.4 percent of its emissions, while Intervenors and others would continue to receive 44.4 percent. The evidence supports a finding that there are facts and logic which support the Department's decision to adopt the proposed rule, and that its decision was made with thought and reason. Issues Surrounding the SERC FPL has raised two arguments related to the SERC: that the use of the Department's fuel adjustment factors in the rule imposes regulatory costs on FPL that could be reduced by adopting FPL's own proposal (allowances based upon an unadjusted heat input approach); and that the Department's SERC does not comply with the requirements of Section 120.541(1)(b) and (2)(c), Florida Statutes, because the Department failed to adopt FPL's alternative proposal or provide a statement of the reasons for its rejection, and it failed to include an estimate of the transactional costs to be incurred by affected individuals and entities in complying with the rule. Because the Department and Intervenors contend that FPL has waived its right to raise either argument by failing to request a SERC or timely filing a LCRA, and omitting at least one of the issues from the Pre- Hearing Stipulation, a brief history of the preparation of the SERC, the issues raised in the Petition, and the issues recited in the parties' Pre-Hearing Stipulation is appropriate. The Preparation of the SERC Following the publication of CAIR in May 2005, the Department began the process to adopt a rule which would modify Florida's SIP, as required by federal law. A public workshop was held on November 29, 2005, at which time the Department presented a rule proposal using a transitional basis to allocate NOx allowances, that is, the allowances would be initially allocated using the fuel adjustment heat input method, but would switch to an output method in 2012. At the end of the workshop, the Department invited written comments from all interested parties. FPL submitted comments on January 6, 2006, objecting to the initial part of the proposal, but supporting the switch that would occur in 2012. After further study regarding the issues, on March 2, 2006, the Department conducted another workshop, at which it announced that it intended to use the fuel adjusted heat input method on a permanent, rather than a transitional, basis. The Department again invited comments from interested parties. In response to that invitation, on March 20, 2006, the Florida Electric Power Coordinating Group (FCG), an organization representing major electric utilities in the State, including FPL, submitted a two and one-half page letter in which it offered comments regarding the implementation of CAIR and CAMR. Among other things, the letter noted that it expected the Department to adopt a rule implementing CAIR that would be consistent with EPA's rule. Also, it specifically requested that the Department prepare a "[SERC] for its proposals to implement both CAIR and CAMR, in accordance with Sections 120.54(3)(b)[1.] and 120.541." Department Exhibit 29, page 2. The letter went on to say that its "prior comments [contained in letters dated October 7, 2005, January 6, 2006, and February 7, 2006], as well as this letter, constitute a 'good faith written proposal for a lower cost regulatory alternative' which accomplishes the objectives of CAIR and CAMR." Id. On March 17, 2006, or three days earlier, FPL also submitted a four and one-half page letter which reiterated in part its earlier comments contained in a letter of January 6, 2006, and which "endorses and incorporates by reference the comments submitted on behalf of . . . FCG pertaining to both the CAIR and CAMR." FPL Exhibit 22, page 1. (Obviously, FPL was anticipating that FCG would be filing comments within a few days.) FPL's letter made no specific reference to a SERC, and those portions of the letter objecting to the Department's use of fuel adjustment factors and the associated economic impact on the utility were not labeled or otherwise identified as a LCRA. Even so, FPL takes the position that by "endorsing" FCG's comments, it was likewise requesting that a SERC be prepared. It also takes the position that its comments regarding the cost effect of the challenged provisions constituted a bona fide LCRA within the meaning of the law. Among other things, FPL's letter specifically objected to the Department's decision to retain the EPA's fuel adjustment factors in the rule and pointed out that this would cost FPL "tens of millions of dollars each year"; that the Department's proposal was "inequitable" to its customers; that it required FPL's customers to pay a disproportionate share of the implementation of CAIR; and that many of the assumptions made by the EPA when it adopted the Model Rule were erroneous. (By now, FPL had filed suit in federal court seeking to overturn the EPA rule; FPL reminded the Department that this litigation was ongoing.) The Department conducted another workshop on April 13, 2006, at which time it announced that it intended to propose fuel adjustment factors in the rule. Following that workshop, on April 28, 2006, the FCG submitted comments similar to the ones contained in its letter of March 20, 2006, and again requested that a SERC be prepared. Joint Exhibit 3, page 23. On the same day, FPL filed a four and one-half page letter containing comments relating to both CAIR and CAMR, although most of the letter focused on CAIR. Among other things, FPL stated that it continued to oppose the Department's decision to utilize fuel adjustment factors for the allocation of allowances; that it should include language in the rule that would require a modification of the rule if FPL prevailed in its federal suit against the EPA; that the fuel adjustment factors were "inequitable" to its customers and allocated a disproportionate share of allowances to the coal-fired units; that neither the Department nor the EPA had ever presented a rational justification for the methodology being used; that the proposed rule would result in "an annual cost to our customers of approximately $15 million"; that compliance with CAIR would not reverse the competitive advantage of coal; and that as a compromise, the Department should increase the fuel adjustment factors for oil and gas units from 60 and 40 percent, respectively, to 80 percent for each. FPL Exhibit 23. The letter made no reference to a SERC, and while it referred to lower regulatory costs that it would experience if its proposal was adopted, it did not characterize the comments as a LCRA that would substantially accomplish the statutory objectives. On May 26, 2006, the Department published its Notice in the Florida Administrative Weekly to satisfy the requirements of Section 120.54(3)(a)1., Florida Statutes. (That provision requires an agency to publish such a notice prior to the adoption, amendment, or repeal of a rule.) No relevant changes to the proposed rule were made as a result of FPL's comments. The Notice stated that the ERC would hold a rule adoption hearing on June 29, 2006. The Notice also stated that the Department had "begun preparation of a [SERC] as outlined in section 120.541 of the Florida Statutes . . . ." By making this statement, it is fair to infer that the Department had treated FCG's earlier request for preparation of a SERC as a valid request and that it intended to prepare one to satisfy the statutory requirement. In addition, because of the complexity of the subject matter and the widely differing views presented by the parties on how to comply with CAIR, the Department, as a matter of good regulatory practice, believed that a complex rule such as this warranted a companion SERC for the benefit of the ERC and interested parties even if one had not been formally requested. (The Department has continued to take the position that the SERC was prepared voluntarily and that no appropriate request for one was ever made.) The Notice also borrowed language from Section 120.541(1)(a), Florida Statutes, by stating that "[a]ny person who wishes to provide information regarding the estimated regulatory costs, or to provide a proposal for a lower cost regulatory alternative must do so in writing within 21 days of this notice." At hearing, FPL conceded that it never formally requested that a SERC be prepared in any document filed during the rule development phase or in accordance with the instruction in the Notice. Also, while not conceding this point, it failed to specifically characterize any comments in its letters of March 17 or April 28, 2006, as a LCRA within the meaning of Section 120.541(1)(a), Florida Statutes. However, it is fair to infer that the Department considered FPL's comments as a LCRA since it summarized those comments in its draft SERC prepared shortly thereafter, and it later gave reasons for rejecting the proposal in a revised SERC. See Findings of Fact 55 and 57, infra. Here, the undersigned rejects the contention by FPL that its "endorsement" of FCG's letter of March 20, 2006, was equivalent to a formal request by FPL for a SERC. Had FPL desired to request one, it could have easily included that request in any of its written submissions to the Department during the lengthy rule development process, or even after the Notice was issued. Section 120.541(1)(a), Florida Statutes, provides that "a substantially affected person, within 21 days after publication of the notice provided under s. 120.54(3)(a), may submit to an agency a good faith written proposal for a [LCRA] to a proposed rule which substantially accomplishes the objectives of the law being implemented." Subsection (1)(b) goes on to provide that if a LCRA is filed within that time limitation, the agency must prepare a SERC (assuming one has not yet been prepared) "or shall revise its prior [SERC], and either adopt the alternative or give a statement of the reasons for rejecting the alternative in favor of the proposed rule." No substantially affected party in this proceeding submitted to the Department a good faith written proposal for a LCRA within the time limitation described in the statute. As noted elsewhere, however, the Department treated FCG's letter of March 20, 2006, as a request to prepare a SERC, and it obviously construed the comments submitted by FPL as a LCRA. On June 21, 2006, the Department submitted to the ERC a memorandum summarizing its rationale for the proposed rule. Attached to the memorandum was its initial SERC, which the Department refers to as a "draft" SERC, and which has been received in evidence as Joint Exhibit 3. The SERC was prepared by the Department's in-house economist, Dr. Nicholas Stratis, and represented a good faith effort by the Department to estimate the economic impacts associated with the adoption of the rule. Beginning on page 23 of the draft SERC and continuing through page 25, the report included a section which was intended to comply with the requirement that, with respect to LRCAs submitted by other persons, the agency must either adopt the alternative proposal or state the reasons for its rejection. Since no alternative proposals were submitted after the Notice was published on May 26, 2006, this portion of the SERC was directed to the comments filed by interested parties during the rule development phase of the process. The SERC noted that only FCG had requested a SERC in its letter dated March 20, 2006, and then went on to summarize the comments contained in FCG's letter, as well as additional comments made by FCG in a letter dated April 28, 2006. Also, the report noted comments submitted by another organization, the Florida Municipal Electric Association, on behalf of its 33 members, as well comments submitted by other utilities. Finally, the Department summarized the concerns raised by FPL in its comments dated March 17 and April 28, 2006, which opposed the Department's adjusted heat input proposal. While the Department gave its rationale for adopting the proposed rule, the SERC did not state the reasons for rejecting FPL's LCRA. In the parties' Pre-Hearing Stipulation filed on November 13, 2006, FPL admits without dispute that the Department "addressed FPL's comments in its Statement of Estimated Regulatory Costs" submitted to the ERC prior to the adoption of the rule. See Pre-Hearing Stipulation, page 10, paragraph E.14.d. See also Finding of Fact 2, supra. On the first day of the final hearing, the Department submitted a revised SERC for the purpose of correcting what it considered to be "minor" errors contained in the draft SERC, which surfaced when FPL deposed Dr. Stratis during preparation for the final hearing. That document has been received in evidence as Joint Exhibit 7. (According to counsel, preparation of the revised SERC was completed on November 9, 2006.) While the SERC again summarized the arguments of FPL at length, it also responded to FPL's LCRA by concluding that "DEP's modeling shows that the total cost of the proposed regulation for 2009- 2021 for all utilities is the same under DEP's proposal and under the unadjusted heat input allocation proposal. While the unadjusted heat input approach would result in lower costs for FP&L, it would not result in lower costs for the entire regulation, and DEP rejects the alternative proposed by FP&L." It is fair to assume that the SERC was revised as a matter of caution in the event FPL's comments in its two letters were deemed to be a LCRA, and that it was filed on a timely basis. The Petition and Pre-Hearing Stipulation In its Petition filed on August 10, 2006, FPL identified as disputed issues of material fact "[w]hether DEP's [SERC] complied with the requirements of section 120.541, Florida Statutes," and "[w]hether FPL's proposal for a fuel- neutral system without the fuel adjustment factors in the Challenged Provisions constitutes a lower cost alternative that would substantially accomplish the statutory objectives[.]" See paragraphs 19k. and m., Petition. Therefore, both issues were clearly raised in the initial Petition. On November 13, 2006, or just before the final hearing, the parties filed a Pre-Hearing Stipulation, a document which controls the issues to be adjudicated at final hearing. See, e.g., Heartland Environmental Council, Inc. v. Department of Community Affairs et al., DOAH Case No. 94-2095GM (DOAH Oct. 15, 1996, DCA Nov. 25, 1996), 1996 Fla. Div. Adm. Hear. LEXIS 3152 at *49 ("[a party] is bound by the allegations in its Petition for Hearing as to the alleged deficiencies in the [rule], as further limited by the Prehearing Stipulation filed in [the] case")(Emphasis added). Among other things, the stipulation contains a concise statement of the nature of the controversy, a brief statement of each party's position, a list of each party's exhibits and witnesses, facts admitted or requiring no proof at hearing, issues of law upon which there is agreement, issues of fact which remain to be litigated, and issues of law which remain for determination. The issues of fact which remained for determination included "[w]hether FPL's proposal for an allocation system without the fuel adjustment factors in the Challenged Provisions constitutes a lower cost alternative that will substantially accomplish the statutory objectives." The parties likewise stipulated that under Section 120.54(1)(d), Florida Statutes, the Department "is required to adopt the least-cost regulatory alternative that substantially accomplishes the statutory objectives." Pre- Hearing Stipulation, paragraphs 15.c. and 16.c. Whether intentionally or through oversight, the document fails to include, explicitly or otherwise, the issue of whether the SERC was prepared in accordance with the requirements of Section 120.541, Florida Statutes. Therefore, the original allegation in the Petition was limited by the parties' Pre-Hearing Stipulation, and the issue was not preserved. Whether FPL's proposal constitutes a lower cost alternative that will substantially accomplish the statutory objectives? FPL contends the challenged provisions are invalid under Section 120.52(8)(f), Florida Statutes, because its alternative proposal imposes lower regulatory costs on FPL and substantially accomplishes the statutory objectives. Accepting the premise that FPL's two letters filed during the rule development process constituted timely-filed LCRAs within the meaning of the law, this contention must still be rejected since it is not supported by the more credible evidence. As noted earlier, the Department considered several alternative methodologies for allocating NOx allowances under CAIR, including: (a) using the heat input approach with the fuel adjustment factors adopted by EPA; (b) using a heat input approach with no fuel adjustment factors or differentiation between fuels; and (c) using an output approach, based upon the amount of fuel required to produce a unit of electricity. During this process, the Department's rationale for using the fuel adjustment factors changed. For example, it initially took the position that a lack of agreement among the parties on an alternative proposal justified the use of the EPA model. The Department finally concluded that the fuel adjustment factors allocated the pollution allowances in a more equitable manner. As is common with cap and trade programs, there are a variety of ways in which an individual utility or an individual EGU may meet the requirements of CAIR and the proposed rule. These options include the installation of control technology, the purchasing or banking of allowances, repowering or fuel switching, or a combination of these approaches. The decision on how best to comply will be made by each individual utility or facility owner, and depends on many factors. These factors include such things as cost, equipment availability, operational difficulty, unit dispatch, and the overall philosophy of the entity making the decisions regarding compliance strategy. Although some of the regulated entities in Florida have preliminary plans on how they intend to comply with CAIR, FPL has not yet settled on a definitive compliance strategy. During the course of the rulemaking, the Department was aware of some of the proposals and methods by which individual EGUs would achieve compliance. However, the Department did not have a final compliance plan for each company and EGU, and this information was not provided to the Department by all of the regulated interests. Even if the Department had requested such information, the compilation of the information would have been exceedingly time-consuming and expensive. Moreover, because the method of compliance is left up to the individual utility or regulated entity, even if this information had been provided, the Department would not have any way of ensuring that the proposed methodology ultimately would be implemented. As noted earlier, to assist with its economic analysis of the proposed rule, the Department retained Dr. Paul M. Sotkiewicz, an expert in economics and economic modeling, electric utility regulation, and emission trading in electricity markets. Dr. Sotkiewicz's primary role was to provide advice to the agency on the various schemes that were under consideration for allocating NOx allowances. During the rule development process, the Department concluded that some economic modeling should be performed to assist in the analysis. Dr. Sotkiewicz developed computer model programs to confirm that the allocation methodologies under consideration by the Department would not lead to a different overall compliance cost for the state, and to determine how the cost burdens among the affected utilities would change with the different allowance allocation schemes. Models do not provide a literal depiction of the real world and its attendant complexities, but models are nevertheless useful analytical tools. Factors to be considered when constructing a model include the availability of data to input into the model and the amount of computational complexity necessary to capture the issues being examined. Any modeling effort involves certain assumptions. Among the primary assumptions for the models in this case are that the utilities will follow optimizing behavior and act to minimize the cost of compliance with CAIR. For the models created by Dr. Sotkiewicz, pollution control technologies are assumed to be installed only when they become cost effective over the remaining time horizon of the models. As a result, some sources do not install pollution control technology immediately upon the effective date of the proposed rule, but rather at some future date. The models also assume no uncertainty and, as such, are perfect foresight models. Finally, the models assume no banking of allowances because of the computational complexity that banking would add and the limited time available to perform the modeling. Dr. Sotkiewicz testified that, even if the model accounted for banking, this issue would not have changed the outcome of his analysis. Dr. Sotkiewicz assumed a NOx allowance price of $2,500.00 in the models. He did not have the data, or the time to collect the data, from all affected sources in the 28 states subject to the CAIR program, which would have been necessary to construct an equilibrium model that determines the price of the allowances. However, this analysis had already been completed by EPA in its model. The $2,500.00 figure used by Dr. Sotkiewicz was a conservative estimate because it is high enough to represent a reasonable "worst case" scenario for the allowance price. This amount also is the midpoint of the range of $1,500.00 to $3,500.00 used by FPL in its analyses. Dr. Sotkiewicz's models assumed that oil and gas steam generating units would only install selective catalytic reduction technology or selective non-catalytic reduction technology to reduce NOx emissions. This approach is consistent with the approach taken by EPA in its analyses. Natural gas combustion turbines could install selective catalytic reduction, selective non-catalytic reduction, dry low NOx burners, water injection technology, or a combination of these emission controls. Control efficiency information was derived from the data published by the United States Energy Information Administration, publications from the United States Department of Energy, and EPA modeling data. The models required input on future utility demand growth. This information was obtained from the Department and the ten-year site plans submitted to the Florida Public Service Commission (PSC) by the electric utilities. Dr. Sotkiewicz assigned a certain generation rate for each of the EGUs using historical data from the year 2004 as a base for existing units and using information from the Department for new units not yet in service. Fuel usage for each EGU was assumed to be in the same proportion as it was during the years from 2000 to 2004. The same time period was used to estimate EGU efficiencies. The models compared a number of different scenarios, including the allocation methodology in the challenged provisions and the methodology proposed by FPL (heat input without fuel adjustment factors). The model showed that when optimizing behavior is present, that is, allowing EGUs to install pollution control technologies as well as engaging in transactions in the emission trading market, the emissions will be the same under both allocation schemes. This result is also supported by general economic theory without the models. Based on his experience with emissions trading markets and his modeling, Dr. Sotkiewicz established that the method of allocating NOx allowances "will have no effect on the ultimate emissions outcome, will have no effect on which [pollution control] technologies will be installed by particular generating units, and will not lead to any differences in overall compliance costs." Dr. Sotkiewicz's model demonstrates that the overall cost of compliance with CAIR will be the same under either allocation methodology for distributing NOx allowances. This conclusion is consistent with EPA's determination that the method of distributing NOx allowances will not affect the environmental impact of the CAIR program or the economic cost of compliance. There will be variations in the costs to individual utilities, depending upon what scheme is adopted and what assumptions are made as to the compliance methodology. The overall cost of compliance, however, will not be reduced by FPL's proposal. FPL criticized the models because they do not account for all of the site-specific information held by FPL and other utilities. One advantage of emissions trading, however, is that the Department and other regulators do not need to know the specific costs of controls for individual utilities. FPL complained that the cost of pollution control equipment will be greater than the values used in Dr. Sotkiewicz's models. Even if this assertion is true, however, it does not change the "overall qualitative results [of the model] that the allocation scheme will not affect overall costs." In its Petition, FPL also raised the issue of whether certain transaction costs associated with the compliance decisions for utilities had been taken into account in the Department's modeling. The transaction costs include such things as broker fees for allowances and trades, and costs associated with planning, engineering, and construction in cases in which control technology is to be installed. Dr. Sotkiewicz explained that these transaction costs will not affect the overall cost of compliance in this case. Utilities preparing to comply with the proposed rule will undertake many of these costs, regardless of the allocation scheme, and by the time the program is in effect, those costs will have already been expended. Brokerage fees and the like are generally incurred per allowance transaction. The empirical evidence gathered from the sulfur dioxide trading program administered by EPA suggests that transaction costs have not been a factor at all in the decisions made by utilities to participate in the market or in their trading activity in the market. FPL's expert (Dr. Landon) testified that the method of compliance could be affected by the treatment a utility could expect to receive from the PSC for the costs expended. He testified that one could not assume the PSC would approve such expenditures as being "prudent" and provided examples of several types of transactions in which the utility's prudence may be called into question. However, the testimony from other FPL witnesses made it clear that the cost recovery process at the PSC is ongoing, that the PSC is kept informed of the decisions as they are made by FPL, and that those costs are pre-approved by the PSC. FPL acknowledged that it did not know of any instance in which costs expended in this manner were not authorized to be recovered. Moreover, the Department met with PSC staff during the rulemaking process to reassure them that the cost recovery information that was then being submitted was legitimate, even though the rule was not yet adopted, and the time to comply would be short. The testimony of FPL's other witnesses discredits Dr. Landon's concerns about this issue. Dr. Landon further opined there will be an increase in the total CAIR compliance costs if, hypothetically, there is no trading of NOx allowances. Dr. Landon admitted his hypothetical involved an "extreme" scenario because it is undisputed that trading will occur under CAIR, as it does under the existing trading programs for NOx and SO2. FPL witness LaBauve confirmed that FPL favors the CAIR cap and trade program, and FPL has observed that other such systems have worked effectively. On cross-examination, Dr. Landon conceded that he had not quantified the actual CAIR compliance costs that will be incurred under realistic conditions. Further, Dr. Sotkiewicz explained that Landon's "no trading" hypothetical was based on assumptions reflecting a "command and control" regulatory regime, which would be expected to have higher compliance costs than the cap and trading system proposed by the Department. Although Dr. Landon was critical of the Sotkiewicz models, he did not perform any modeling himself because it would be time-consuming and expensive. He further questioned the assumptions used by Dr. Sotkiewicz concerning perfect foresight, perfect competition, and no transaction costs. The record demonstrates, however, that the assumptions used by Dr. Sotkiewicz are reasonable and appropriate. Dr. Sotkiewicz used the same assumptions that EPA used in its model. Even Dr. Landon acknowledged that the EPA model is an appropriate model for use in this case. The purpose of CAIR is to reduce the emissions of certain pollutants by imposing a statewide cap on those emissions. The EPA's cap operates as an allocation of NOx allowances to the individual states. Each state must distribute the allowances among the affected utilities and entities in accordance with one of the allocation methodologies available. The individual regulated entities are then free to decide for themselves how best to comply with the cap on each EGU, in accordance with their own goals, objectives, and decision-making processes. Each individual entity may approach the decision- making process differently, but the factors that generally are considered in this process appear to be the kinds of factors that would be considered by all such entities. Nevertheless, each entity will make voluntary decisions on what is best for it and its customers. These voluntary decisions are generally unaffected by the allocation scheme for allowances because the decisions are based on multiple considerations, such as the regulated entity's individual projections about the cost and availability of NOx allowances in the market, the cost of construction and the availability of construction workers and materials for pollution control systems, and the general philosophy of the entity with regard to its tolerance for risk. A utility with a high tolerance for risk may choose a path that is more uncertain and perhaps less costly, while one with a lower tolerance for risk would opt for more certainty. These voluntary decisions may well affect the cost of compliance for each individual utility. Although FPL criticized the assumptions used by Dr. Sotkiewicz in his model, it represents a good faith estimate by the Department of the economic impacts associated with the proposed rule. Even if the model results are not precisely accurate, the results provided useful information to the Department. Moreover, even if the model results are disregarded entirely, thirty years of experience with emission trading programs and general economic theory demonstrates that the allocation of allowances in a fixed baseline trading system, like the one proposed by the Department, will not affect the overall cost of compliance with the proposed rule. For all of these reasons, FPL's proposed allocation methodology does not constitute a lower cost alternative in this case. g. Whether the SERC Complies with the Law? For the reasons stated above, the issue of whether the SERC complies with the law has not been preserved. That issue, as originally framed by FPL, is whether the Department's SERC fails to satisfy the requirements of Section 120.541(1)(b) and (2)(c), Florida Statutes, because the Department failed to adopt FPL's alternative method or include a statement of the reasons for rejecting that alternative in favor of the proposed rule, and it failed to provide a good faith estimate of the transactional costs that would be incurred by regulated persons or entities in complying with the rule's requirements. Assuming arguendo that the issue is viable, in both the initial and revised SERCs, the Department summarized all of FPL's objections to the use of fuel adjustment factors for allocating allowances, and in the revised SERC gave a statement of the reasons for rejecting FPL's proposal. While the reasons for rejecting that proposal are admittedly brief, and they differ with the views advocated by FPL throughout the rule development process, the SERC concludes that the Department's modeling supports its allocation method by demonstrating that "the total cost of the proposed regulation for 2009-2021 for all utilities is the same under DEP's proposal and under the unadjusted heat input allocation proposal [of FPL]." It goes on to state that while FPL's proposal would obviously reduce FPL's overall costs or financial burden to comply with CAIR, the Department (and EPA) method of allocation "would not result in lower costs for the entire regulation, and DEP rejects the alternative propos[al] by FP&L." Accordingly, the evidence supports a finding that the SERC considered FPL's LCRA and stated the reasons for its rejection. Finally, both the initial and revised SERCs include a section which contains a good faith estimate of the transactional costs likely to be incurred by individuals and entities who must comply with the rule. See Joint Exhibit 3, pages 15-18; Joint Exhibit 7, pages 15 and 16.
The Issue The issue for determination in this case is whether Florida Administrative Code Rule 62-302.300(6) is an invalid exercise of delegated legislative authority because the rule is vague, fails to establish adequate standards for agency decisions, or vests unbridled discretion in the agency.
Findings Of Fact The Parties The Department is the state agency authorized under Chapter 403, Florida Statutes, to regulate discharges of industrial wastewater to waters of the state. Under a delegation from the United States Environmental Protection Agency, the Department administers the National Pollution Discharge Elimination (NPDES) permitting program in Florida. The Department promulgated the rules in Florida Administrative Code Title 62 that are applicable to the permitting of wastewater discharges. FOPB is a non-profit Alabama corporation established in 1988 whose members are interested in protecting the water quality and natural resources of Perdido Bay. FOPB has approximately 450 members. About 90 percent of the members own property adjacent to Perdido Bay. James Lane is the president of FOPB. Jacqueline Lane and James Lane live on property adjacent to Perdido Bay. IP owns and operates a paper mill in Cantonment, Escambia County, Florida. IP is the applicant for the Department authorizations that are the subject of DOAH Case Nos. 08-3922 and 08-3923. Background When this rule challenge was filed, DOAH Cases Nos. 08-3922 and 08-3923 (the permit cases) involved challenges by these same Petitioners to four Department authorizations for IP: an NPDES permit, a Consent Order, an approved exemption for the experimental use of wetlands pursuant to Florida Administrative Code Rule 62-660.300, and a waiver related to the experimental use of wetlands. IP later withdrew its request for the experimental use of wetlands exemption and the related waiver. Petitioners were ordered to show cause why their claim regarding the invalidity of Florida Administrative Code Rule 62- 660.300 was not rendered moot by IP’s withdrawal of its request for the exemption. Subsequently, the challenge to the validity of Florida Administrative Code Rule 62-660.300 was dismissed as moot. At the commencement of the final hearing on June 22, 2009, FOPB and James Lane announced that they were withdrawing their rule challenges except with respect to Florida Administrative Code Rule 62-302.300(6), and that the only legal ground being asserted for the invalidity of the rule is that it is vague and vests unbridled authority in the Department. Petitioners’Standing Jacqueline Lane, James Lane and a substantial number of the members of FOPB swim, boat, and make other uses of Perdido Bay. Perdido Bay would be affected by IP's wastewater effluent. The challenged rule was applied by the Department to determine that IP's proposed industrial wastewater discharge was in the public interest. The Challenged Rule Florida Administrative Code Rule 62-302.300, is entitled "Findings, Intent, and Antidegradation Policy for Surface Water Quality." Subsection (6) of the rule states: Public interest shall not be construed to mean only those activities conducted solely to provide facilities or benefits to the general public. Private activities conducted for private purposes may also be in the public interest. Most of the permits that are issued by the Department are issued to private entities whose primary purposes are personal uses or the production of private incomes and profits, rather than solely to provide facilities or benefits to the general public.
Findings Of Fact Respondent issued an Invitation To Bid (ITB) for Bid No. 91-04, entitled "Granular Activated Carbon (GAC) Filter Installations and Exchanges" in September, 1990. The purpose of the ITB was to continue a project begun around 1985 for the removal of the pesticide ethylene dibromide (EDB) from private drinking water wells. The EDB project began with a field test involving wells installed by Intervenor working with Respondent. The equipment and material in those wells were the basis for specifications developed by Respondent. Glenn Dykes, an employee of Respondent was responsible for developing the specifications. When the project began, the state legislature intended the Department of Agriculture and Consumer Services (DACS) to manage the EDB removal contracts since EDB had been applied to citrus groves by the state in some affected areas. Removal of EDB from the drinking water in these areas is accomplished by installation and regular maintenance of filter systems at the wells. The heart of each filter system is a tank of granular activated carbon (GAC) which absorbs EDB. The carbon is replaced every six months. The project was administered by )ACS through contract with Respondent. Funds were transferred from Respondent to DACS, subject to the approval of Dykes, contract manager on the project for Respondent. Dykes' office also had monitoring responsibilities for the project. From 1986 to 1989, Intervenor received contracts to perform the work, even though there were lower bidders. Several times all bids were rejected, but Intervenor received the contract. Intervenor has other contracts with Respondent and its relationship with Respondent was such that it listed Dykes and an another Respondent employee, John Kraynak, as references in the bid later submitted in response to the ITB which forms the basis of this proceeding. Dykes and Kraynak exercised responsibility for preparation of ITB NO. 91-04. In 1989, DACS issued an invitation to bid containing the identical carbon filter specifications as those contained in Respondent's Bid No. 91-04. Petitioner in the instant proceeding was awarded the DACS' bid. A bid protest, initiated by Intervenor, resulted. During the pendency of that protest proceeding, DACS issued emergency purchase orders to the intended bid awardee. Petitioner and DACS were in general agreement that specifications contained in the DACS' bid were applicable to the emergency purchase orders and operated on that basis until October 15, 1990. Contract management for EDB filter installation and maintenance was returned from DACS to Respondent, effective October 15, 1990. Because of the pending return of management of the EDB removal project, Respondent advertised its invitation to bid for EDB removal and gasoline contamination removal under ITB 91- 04. Two bids were received in response to Respondent's ITB 91-04; one from Petitioner for a composite total price of $748,355.00 and one from Intervenor for a total composite price of $904.475.00. An intended contract award was not immediately posted, rather the bids were evaluated before announce:nent of an intended decision. Three Respondent employees were mainly involved in the writing and processing of ITB NO. 91-04. Those persons were Kraynak, Dykes, and an individual named James Den Bleyker. Kraynak, in charge of the bid for Respondent's water supply section of the Bureau of Drinking Watr and Ground Water Resources, wrote the bid specification based upon the previous DACS bid and discussions with John Folks, a DACS employee involved in the previous emergency purchase orders to Petitioner. 1(raynak, who had no prior experience with the state bid process nor any training in that area, was assisted by his supervisor, Glenn Dykes. Den Bleyker, a Respondent purchasing agent overseeing the bid preparation for Respondent's purchasing section to insure compliance with bidding requirements, knew nothing about the technical aspects of the bid. He instructed Kraynak that each bid "is supposed to stand on its own." He also instructed Kraynak to check anything on the bid submittal that appeared questionable. Kraynak had the responsibility for determining whether the bids were responsive. He was also instructed by Den Bleyker to check both bids if a point in one bid raised a question. Apparently, this is the usual procedure for Respondent's ITB process. One of the specifications included in ITB NO. 91-04 was a requirement for a carbon filter (GAC 30) with a minimum iodine number of 950. This number reflects the milligrams of iodine adsorbed per gram of carbon; a higher numbr, the more adsorptive the carbon. Manufacture of GAC is not an exact science. The carbon is produced in lots. A lot is a quantity of carbon that has gone through the manufacturing process together. Each lot may have some variation from another lot because the processing entails adjustment of oxygen, temperature, and steam of the furnace. After removal from the furnace, the lot is taken for analysis of physical and activity properties. This is a lot analysis and is done by the manufacturer. Some lots will have iodine numbers of 950 or greater. Lots can be hand selected to meet all Respondent's ITB 91-04 specifications. However, absent such a selection process, no manufacturer in this country produces a standard carbon which meets Respondent's bid specifications. Sensitized through a review of the previous DACS' bid and the resultant administrative litigation, Kraynak was aware that the carbon specification was the most important aspect of the bid package. Kraynak attempted to treat this aspect of the two bid packages carefully. Vendors were required by the ITB to provide "full documentation and specification on all equipment and components to be used in providing the GAC filter systems and maintenance." This last point was reiterated in the specifications section of the bid with the following: Specifications for the individual equipment components MUST BE PROVIDED WITH YOUR BID OR THE BID WILL BE DECLARED INCOMPLETE AND INELIGIBLE FOR CONSIDERATION! While the ITB required bidders to submit specifications for products, it did not require submission of manufacturer's specifications. Included iii. Petitioner's bid submittal was the manufacturer's specification sheet for a product known as GAC 30. The name of the company on the specification sheet submitted by Petitioner is Atochem. On the specification sheet, the number 950 appeared as the minimum iodine number. An asterisk appeared next to the minimum iodine number. At the bottom of the page was the following typed note: * Lots will be specifically selected to meet or exceed all bid requirements. In reviewing Petitioner's bid, Dykes and Kraynak were aware from a previous conference with John Folks, contract manager for DACS, that Petitioner had been using selected lots of Atochem GAC 30 which met the specified iodine numbei of 950 and that lot analyses were provided to Folks. As a result, the provision of an analysis for each lot was included in ITB NO. 91- 04. Kraynak understood that carbon came in "lots', and that lots varied in analysis. Nonetheless, he determined to verify the contents of the bids. On October 9, 1990, 1(raynak called Atochem, the manufacturer whose specification sheet was submitted b Petitioner. He learned that the specification sheet lists 900 as the minimum iodine number. Atochem does not make a standard GAC 30 filter with a minimum iodine number of 950 and was unaware of the alteration or the inclusion of an altered specification sheet in Petitioner's bid submitta1. However, Atochem also confirmed during that telephone conversation and later, per Kraynak's request for written confirmation, by facsimile letter to Kraynak dated October 10, 1990, that the actual iodine number for GAC 30 is often above 950 and that lot selections of carbon could be made meeting or exceeding 950. Intervenor's bid submittal contained a typewritten specification sheet which was originally hand written by Intervenor's carbon supplier, a company named Alamo. While Alamo does not manufacture carbon, the specifications on the sheet were accurate for the lots of carbon that Alamo would supply to Intervenor. Alamo brand ABG-CWF with a minimum iodine number of 950. In the course of verification of the bid specification of the carbon intended to be supplied by Intervenor, Kraynak was told ABG-CWF met specifications, was manufactured by a company named Calgon and also had a minimum iodine number of 900. Interestingly, as established at the final hearing and contrary to the results of Kraynak's verification, Alamo will obtain the carbon to be supplied to Intervenor from Atochem, the same manufacturer intended to be used by Petitioner. Under Alamo's arrangement with Atochem, lots of Atochem's GAC 30, a standard available product, will be selected by Alamo meeting the bid specification of an iodine number of 950. After selection, Alamo will mark those lots with the brand ABG-CWF, a brand specifically prepared for Intervenor. This is not a standard available product and, in fact, "CWF" stands for "Continental Water Florida", intervenor in this proceeding. The ITB requires that isotherms be provided in a bid response for the carbon proposed to be used. An isotherm is a graphic depiction of the adsorptive capabilities of Larbon. The bid responses of both Petitioner and Intervenor included isotherms for Atochem GAC 30. The ITB also requires that lot analyses confirming compliance with bid specifications be provided in the course of any subsequent contract on all carbon filters to be used by the successful bidder. The carbon specification sheet submitted by Petitioner in its bid response did not purport to be from the manufacturer. The asterisk and footnote are clearly typed separately and clearly describe how specifications aide to be met. While Kraynak determined it appropriate to consider information from Atochem that its specifications were different from those submitted by Petitioner, he chose to reject Atochem's confirmation of Petitioner's explanation that lots would be selected to meet bid requirements. Kraynak documented in a memorandum to Respondent's purchasing office his reasons for rejecting Petitioner's bid. In that memorandum, he explained that the bid specifications differed from those of the manufacturer. Notably, he omitted any reference to Petitioner's footnote on the bid submission or the October 10 letter from Atochem. By letter dated October 12, 1990, Respondent informed Petitioner of the intended award of the bid to Intervenor as a "Single Bidder Award. " The letter contained no statement regarding deficiencies in Petitioner's bid. Two other areas of Petitioner's bid response were reviewed by Respondent's personne1. These areas involved Petitioner's lack of qualified personnel residing in the State of Florida, and Petitioner's failure to specify the type of a particular transformer being proposed as part of equipment to be supplied. Neither the matter of personnel or the transformer description was considered by Respondent to constitute a sufficient basis to deem Petitioner's bid non-responsive. Furthers testimony at the final hearing on these points establishes that these variances in Petitioner's bid response did not constitute material deficiencies. 40 Respondent determined Petitioner's bid non- responsive totally on the basis of the carbon iodine number which had been changed from 900 to 950 in the course of Petitioner's customizing the Atochem GAC 30 specification sheet. Following rejection of Petitioner's bid, Respondent issued purchase orders to Intervenor in amounts exceeding $200,000. Petitioner was responsive in all material respects to Respondent's ITB NO. 91-04.
Recommendation Based on the foregoing, it is hereby RECOMMENDED that a Final Order be entered granting the award of the bid in Respondent's ITB NO. 91-04 to Petitioner as the lowest and best bid. DONE AND ENTERED this 19th day of December, 1990, in Tallahassee, Leon County, Florida. DON W. DAVIS 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 19th day of December, 1990. APPENDIX The following constitutes my specific rulings, in accordance with Section 120.59, Florida Statutes, on findings of fact submitted by the parties. Petitioner's Proposed Findings. 1.-2. Adopted in substance. 3. Rejected, unnecessary. 4.-17. Adopted in substance. l8.-19. Adopted by reference. 20.-34. Adopted in substance. Intervenor's Proposed Findings. 1.-3. Rejected, unnecessary. 4.-14 Adopted in substance, though not verbatim. Rejected, not supported by the weight of the evidence. Adopted in substance. 17.-18. Rejected, not supported by weight of the evidence. 19.-20. Adopted in substance, though not verbatim. 21.-26. Rejected, relevance, argumentative. Rejected, not relevance in the face of Respondent determination that these matters werE not material to responsiveness of the bid. Rejected, argument. Adopted by reference. 30.-33. Rejected, not relevance, argument. Respondent's Proposed Findings. 1.-2I. Adopted in substance. 22. Rejected, not supported by weight of the evi6ence. 23.-40. Adopted in substance, though not verbatim. 41. Rejected. COPIES FURNISHED: Donna H. Stinson, Esquire Suite 100, The Perkins House 118 North Gadsden Street Tallahassee,Florida 32301 Cynthia K. Christen, Esquire Department of Environmental Regulation 2600 Blairstone Road, Room 654 Tallahassee, Florida 32399-2400 M. Christopher Bryant, Esquire 2700 Blairstone Road, Suite C Tallahassee, FL 32301 Dale H. Twachtmann, Secretary Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Daniel H. Thompson, Esquire General Counsel Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32399-2400
Findings Of Fact Upon consideration of the oral and documentary evidence in the record, as well as the pleadings and joint prehearing stipulation, the following relevant facts are found: Cast-Crete owns and operates a concrete batch plant in Hillsborough County, Florida, and manufactures concrete products such as reinforced beams, lintels, seals and drainage structures on the property. The plant is located on the west side of State Road 579, 3/4 mile north of Interstate 4, Section 28, Township 28 South, Range 20 East. The concrete products are manufactured in various forms which are laid out over a large portion of Cast-Crete's property. Lubricating oils are utilized to facilitate the removal of the product from the confining forms. During this process some of the lubricating oil is spilled onto the ground. Also, cleaning solutions containing degreasers are utilized to wash the concrete trucks eight to ten times per day. This solution ends up on the ground. Aggregate limerock (crushed limestone) is used in the concrete formulation process and is stored in large piles on the property. In order to contain the dust, water is sprayed on the aggregate piles 24 hours a day. The wash water from the continuous process of wetting the aggregate, other waste water and some stormwater is channeled through the property and into a settling pond in the northwest corner of Cast-Crete's property. This pond discharges continuously off the property by way of a concrete flume into a county maintained ditch. Water in the ditch travels in a westerly direction approximately 200 to 300 yards before it passes under Black Dairy Road, where the watercourse deepens and widens. The ditch discharges into a marshy area which drains into Six Mile Creek and other water bodies. The pond at the northwest corner of Cast-Crete's property is equipped with a metal skimming device to remove oils and greases floating on the surface of the pond. Nevertheless, it is estimated that approximately 100 gallons of oil per year are discharged by Cast-Crete. Oil and grease in the outflow water is occasionally above 5 mg/L. Oil and grease layers have been observed on water at both Black Dairy Road and Six Mile Creek, probably resulting from road run- off. Approximately 90 percent of the water discharged from the property is a result of the wetting or washdown of the aggregate piles. The excess water which comes from the aggregate piles is laden with dissolved limestone, lime and limestone particles. This limestone dust raises the pH level of the water. Because of the continued wetting of the aggregate, water flows through the settling ponds and off of Cast-Crete's property at a rate of approximately 4.8 gallons per minute, or 7,200 gallons per day or 2.5 million gallons per year. During a rain event, the flow increases markedly. Except during times of heavy rainfall, water flowing from the respondent's property provides a thin stream of water in the drainage ditch approximately six inches wide and several inches deep. The pH of the wastewater from Cast-Crete's discharge flume is between 10 and 11 units. During high volume flows, the pH remains at or above 11 units. An increase of one unit of pH in the wastewater means that the wastewater has become 10 times more basic, since pH is measured on a logarithmic scale. The natural background of unaffected streams in the area of and in the same watershed as the Cast-Crete property is less than 8.5 units. Specific conductance or conductivity is the measure of free ions in the water. Typical conductivity readings from other water bodies in Hillsborough County range between 50 and 330 micromhos per centimeter. The specific conductance of Cast-Crete's wastewater ranges from 898 to 2000 micromhos per centimeter. This is due to the presence of calcium carbonate and calcium hydroxide in the water. Blue-green algae is the dominant plant species in the ditch between the Cast-Crete discharge flume and the first 150 meters of the ditch. A biological survey of the ditch system indicates that the diversity of species east of Black Dairy Road is low. This is attributable in part to the high pH of the wastewater. The low diversity can also be attributed to the fact that the County maintains the ditch by use of a dragline on an annual basis. Background samples from a site within one mile to the northwest of the Cast-Crete property were taken. The site (a stream passing under Williams Road) is an appropriate place to take background samples because the water there is unaffected by Cast-Crete's discharge or other man-induced conditions. The pH background sample ranged from 4.6 units to 5.1 units. The specific conductance background samples ranged from 70 to 100 micromhos per centimeter. Samples taken from a site potentially impacted by Cast-Crete's discharge showed a pH level of from 6.35 to 7.37 units and specific conductance of from 592 to 670 micromhos per centimeter. Cast-Crete discharges water from its concrete plants operation without a permit from the DER.
Recommendation Based upon the findings of fact and conclusions of law recited herein, it is RECOMMENDED that a Final Order be entered requiring respondent to submit a complete application for an industrial wastewater permit within thirty (30) days, and that, if it fails to do so, it cease discharging wastewater from its property until such time as an appropriately valid permit is issued by the DER. Respectfully submitted and entered this 3rd day of May, 1985, in Tallahassee, Florida. DIANE D. TREMOR Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32301 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 3rd day of May, 1985. COPIES FURNISHED: David K. Thulman Assistant General Counsel Department of Environmental Regulation Twin Towers Office Building Blairstone Road Tallahassee, FL 32301 W. DeHart Ayala, Jr. 501 E. Jackson Street Suite 200 Tampa, FL 33602 Victoria Tschinkel Secretary Department of Environmental Regulation Twin Towers Office Building 2600 Blairstone Road Tallahassee, FL 32301 ================================================================= AGENCY FINAL ORDER ================================================================= STATE OF FLORIDA DEPARTMENT OF ENVIRONMENTAL REGULATION DEPARTMENT OF ENVIRONMENTAL REGULATION, STATE OF FLORIDA, Petitioner, vs. CASE NO. 84-1647 CAST-CRETE CORPORATION OF FLORIDA Respondent. /
Findings Of Fact Petitioner Jerry L. Seymour owns lot 220A in Pine Tree Estates, a parcel of slightly over one acre, approximately 140 feet by 330 feet, situated in Broward County, Florida. Petitioner's lot is substantially overgrown with vegetation, including swamp cabbage, myrtle, sawgrass, ferns, palmetto and cypress. The soil consists of cap rock, muck, sandy loam, humus and sand. On June 13, 1977, the day before the final hearing, standing water a few inches deep covered major portions of lot 220A, including the southern one-third and eastern edge of the lot. In short, lot 220A lies in a low, swampy area. The ground water level varies directly with rainfall. On June 13, 1977, the ground water was not quite as high as the crown of the road adjoining the lot. Rainfall in the area on June 12 or 13, 1977, if any, was not extraordinary. Historically, annual rainfall in Broward County has averaged 60 inches, but annual rainfall since 1970 has been below this average. According to petitioner's testimony, the water table has dropped a foot in the past year. After Petitioner's initial application for a permit for installation of a septic tank on lot 220A had been turned down, he filed an amended application in which he proposed to remove impervious materials from an area approximately 130 feet by 140 feet and to refill the excavation, to a height of 42 inches above the adjacent road, with soil of a kind that would facilitate drainage. In his letter denying petitioner's amended application, Mr. Hillyer, on behalf of respondent, wrote: Inasmuch as the lot in question does not comply with the above referenced code requirements we can not issue a septic tank permit at this time. However, if Mr. Seymour wishes to remove the muck in the area of the drainfield and fill the property as outlined on the survey submitted to the 42" above the crown of the road mentioned in your letter, this department will be in a position to re-evaluate this property as to whether or not a septic tank permit can be issued. Petitioner's amended application also indicated that a "Chromaglass Model CA-900 Aerobic Treatment Unit" together with a chlorinator and chlorine contact chamber would be installed, instead of a conventional septic tank; and that the installation would be in an absorption field of at least 300 square fee, and at a distance of at least 125 feet from the well petitioner proposed to drill on the lot. In addition, petitioner proposed to dredge a swale as a means of draining lot 220A. Petitioner also owns lot 220B in Pine Tree Estates, which lies immediately west of lot 220A, and shares a north-south boundary with lot 220A. The lots are about the same size and about equally swampy, although the soil in lot 220B is slightly less sandy. When petitioner's application for a permit to place a similar aerobic treatment unit on lot 220B was denied, he petitioned for an administrative hearing. The recommended order which resulted was accepted in evidence at the final hearing in this matter. That recommended order concludes: Wherefore, the Hearing Officer finds that if the planned drain field is installed on a 100' x 140' pad filled an additional 23 inches above its current pad level it will be 42 inches from the October, 1974 high water table measure, meeting the criteria established by law and I would recommend its approval. Jerry Seymour v. Broward County Health Department, State of Florida, No. 75-1059 (DOAH; October 10, 1975) No final order in Case No. 75-1059 was offered in evidence at the hearing in the present case.
Recommendation Upon consideration of the foregoing, it is RECOMMENDED: That respondent deny petitioner's application for a permit for construction of a septic tank, with leave to petitioner to refile an application if changed circumstances warrant. DONE and ENTERED this 2nd day of August, 1977, in Tallahassee, Florida. ROBERT T. BENTON, II Hearing Officer Division of Administrative Hearings Room 530, Carlton Building Tallahassee, Florida 32304 (904) 488-9675 COPIES FURNISHED: Mr. Christopher B. Knox, Esquire Suite 302A, Medical Towers 303 Southeast 17th Street Ft. Lauderdale, Florida 33316 Mr. Howard L. Braynon, Esquire 5920 Arlington Expressway Post Office Box 241F Jacksonville, Florida 32231
Findings Of Fact Petitioner did not identify a particular part of Rule 62-4.244 that he claims is unconstitutional. Rule 62-4.244 is a lengthy rule and is not set forth here in its entirety. The gist of the rule is explained in subsection (1)(a): The Department may allow the water quality adjacent to a point of discharge to be degraded to the extent that only the minimum conditions described in subsection 62- 302.500(1), F.A.C., apply within a limited, defined region known as the mixing zone. Under the circumstances defined elsewhere in this section, a mixing zone may be allowed to provide an opportunity for mixing and thus to reduce the costs of treatment. However, no mixing zone or combination of mixing zones shall be allowed to significantly impair any of the designated uses of the receiving body of water.
The Issue Whether the Department should grant a permit to IMCF to mine and ultimately reclaim 145 acres of wetlands located primarily in Section 14, Township 31S, Range 23E, Polk County, Florida ("Section 14 Area") on the western edge of a larger wetlands system known as "Hookers Prairie."
Findings Of Fact Background and Procedural History On July 9, 1987, IMCF filed an application with the Department for a permit to mine phosphate rock from and then reclaim the Section 14 Area. The Section 14 Area is owned by IMCF. On December 2, 1987, in response to a determination of incompleteness issued by the Department, IMCF supplied additional information which supplemented and modified the original application. The application as augmented and modified was determined to be complete by the Department on December 7, 1987. Department representatives carried out onsite inspections of the Section 14 Area on September 22 and October 9, 14, and 19, 1987, and issued a written permit application appraisal. Based upon the information contained in the application and on the site visits, the Department determined to issue the requested permit to IMCF subject to certain draft permit conditions. The Department directed IMCF to publish notice of the Department's intent to issue the permit. The Department's notice of intent to issue was published in the Lakeland Ledger, a newspaper of general circulation in the location of the Section 14 Area on March 15, 1988. Petitioners objected to the Department's proposed issuance of the permit by filing their Petition to Intervene and Request for Formal Hearing with the Department on April 7, 1988. Petitioners have standing to intervene in this proceeding and participate as parties for the purpose of objecting to the issuance of the subject permit. Description of Proposed Mining Project The wetlands that make up the Section 14 Area are part of a larger 162 acre project area proposed to be mined and reclaimed by IMCF. This mining area is located to the south of the eastern portion of Bradley Junction, a small residential community. The Section 14 Area wetlands make up 131 acres of the overall project area. The remaining 31 acres of uplands involved in the proposed mining project are not subject to Department permitting requirements. IMCF has all necessary permits and approvals to gain access to the upland areas to carry out mining operations. These uplands areas are located primarily in the northernmost part of the project area directly abutting the location of certain residences and churches in eastern Bradley Junction. The jurisdictional wetlands in the Section 14 Area are located no closer than 450 feet from a residential structure in Bradley Junction. Most of the wetlands in the Section 14 Area are substantially farther away from the Bradley Junction residences. The initial step in the mining process will be to construct a ditch and berm system around the Section 14 Area. This ditch and berm system will effectively segregate the mining area from adjacent wetland areas that are to remain undisturbed. Approximately 99 acres of the Section 14 Area wetlands will actually be mined; the remaining 32 acres will be disturbed by the construction of the ditch and berm system. Following the construction of the ditch and berm, land clearing will take place. Once land clearing is completed, mining operations will commence. In phosphate mining operations, large, electrically-powered draglines are used. The dragline first removes and casts aside the "overburden" which is the earthen material that over lies the "matrix." The matrix is the geologic deposit that contains phosphate rock. The dragline extracts the matrix and places it into nearby pits where high- pressure waterguns are used to create a slurry of the matrix material. This slurry is then pumped to the beneficiation facility several miles distant from the mining operations where the matrix slurry is processed to extract the phosphate rock. The matrix is composed primarily of three major components: phosphate rock, sand, and clay. In the beneficiation process, the phosphate rock is separated from the other two components. Residual clays are then pumped to large settling areas where the clays are allowed to settle and consolidate prior to reclamation. No clay settling area is proposed to be located in the Section 14 Area. The sand "tailings" that are generated in the beneficiation process are pumped back to mined areas for use in reclamation programs. Sand tailings will be used in the reclamation proposed for the Section 14 Area. IMCF proposes to initially carry out ditching and berming activities in the Section 14 Area. The central and southern portion of the project area is planned to be mined during the period from July 1989 and June 1990. The dragline will then mine an area to the west outside of the project area. The dragline will return to mine the northern portion of the project area in May 1991. Actual mining operations in the northern portions of the Section 14 Area wetlands and the uplands near Bradley Junction residences will occur over approximately a seven-month period and the dragline will depart the area in December 1991. There are approximately 800,000 tons of phosphate rock underlying the Section 14 Area wetlands. After extraction and beneficiation, this rock will be used for the production of phosphate fertilizer or other phosphate-based products. Project Modifications IMCF has agreed to the following modifications to the Section 14 Area mining and reclamation project as originally proposed in July 1987: The southern boundary of the Section 14 Area has been moved to avoid encroachment on a small stream channel in the upper reaches of the South Prong of the Alafia River, the outlet from Hookers Prairie. The project has been modified to conform to setback requirements recently adopted by the Board of County Commissioners of Polk County. Under the revised setback requirements, the edge of a mine cut may come no closer than 100 feet from the IMCF property boundary or 250 feet from an occupied residence, whichever distance is greater. In response to concerns about noise and lights associated with mining operations, IMCF has agreed to restrict the hours of mining operations. Mining operations will not take place during the period from 11:00 p.m. to 7:00 a.m. when the dragline cab is located within 700 feet of a residence. In addition, mining operations will be suspended on Sundays during the period from 7:00 a.m. through 3:00 p.m. when a dragline cab is located within 700 feet of any place of worship in the Bradley Junction community. The Polk County Mining Ordinance requires that either a berm or a wire fence be constructed on the perimeter operations to limit unauthorized access. IMCF has agreed to construct both a berm and a solid wooden fence, at least six feet high, along the IMCF property boundaries adjacent to residences located in the Bradley Junction community. IMCF has agreed to expedite the reclamation of areas mined adjacent to residences in the Bradley Junction community. The area encompassing the first mine cut closest to the residences (a distance of 250 to 300 feet) will be recontoured and revegetated within 90 days following completion of mining in the area. The area encompassing the first two mine cuts (a distance of 500 to 600 feet) will be recontoured and revegetated within six (6) months following completion of mining in the area. Type, Nature and Function of Section 14 Area Wetlands The Section 14 Area is composed of approximately 127 acres of herbaceous (shrubby) wetlands and approximately 4 acres of young hardwood (forested) wetlands. Western Hookers Prairie, including the Section 14 Area, has been adversely impacted by land use activities over the last several decades. Parts of the area have been drained and cleared to accommodate agricultural uses. The resulting widely fluctuating water levels have induced the extensive growth of what the Department considers to be undesirable "nuisance species" such as cattails and primrose willow, in these areas. Other areas, especially in the southern portion of the Section 14 Area, contain some relatively diverse herbaceous wetland systems. The Section 14 Area also has been adversely impacted to some extent by emergency releases of phosphogypsum and acidic process wastewater generated by the chemical manufacture of phosphate-based fertilizer. Such spills occurred in the 1950s and 1960s and resulted in the deposition of high levels of phosphorous and fluoride in western Hookers Prairie. However, the Section 14 area is less affected than eastern parts of the Western Prairie due to a natural slight rise in elevation along the eastern edge of Section 14, causing a natural flow of water containing the contaminants generally south around Section 14. Wetland systems, in general, can perform certain valuable ecological functions. These functions include: nutrient retention/removal, sediment trapping, flood storage desynchronization, groundwater recharge, food chain support, wildlife habitat, and recreation. Certain wetland systems also serve a shoreline protective/wave dissipation function but that function is not relevant to herbaceous wetland systems like the Section 14 Area that are not adjacent to open water. Because of the nature of the Section 14 Area and the stresses previously imposed upon it, its ability to perform wetland functions has been reduced. The nutrient retention/removal function refers to the ability of the vegetation in wetland systems to remove excess nutrients from water. The Section 14 Area does not perform a significant nutrient retention/removal function. The available data indicate that waters leaving western Hookers Prairie at its outlet to the South Prong of the Alafia River contain more nutrients on balance than do waters entering the system. It is not uncommon for wetlands that are in headwaters of a water system to be net exporters of nutrients. In addition, in this particular area, the historical spills of phosphogypsum and acidic process wastewater have overloaded the sediments in the area with nutrients. The sediment trapping function refers to the ability of wetland systems to filter sediment (suspended particulate matter) from water as it travels through the wetland area. The Section 14 Area performs a reduced sediment trapping function. Although some of the water entering the Section 14 Area comes from Whiskey Store Creek to the north, some of the water entering Section 14 has already traveled relatively long distances through the rest of western Hookers Prairie so that most of the water entering the Section 14 Area does not contain high levels of sediments. As more and more parts are excised for phosphate mining, the importance of the sediment trapping function of the remaining portions, even Section 14, increases, at least until reclamation projects succeed. See "J. Cumulative Impact," below. The flood storage/desynchronization function refers to the ability of a wetland system to store rain water generated during storm events and then to release this water gradually, thus reducing the likelihood of downstream flooding. Hookers Prairie, as a whole, does serve a valuable flood storage/desynchronization function. The approximately 130 acres involved in the Section 14 project area only amount to three to four percent of the overall water storage capacity in the affected area. But the Hookers Prairie wetlands have an approximately two foot thick layer of peat that acts as a sponge to absorb water during inundation and slowly release the stored water over time. It could be misleading to compare the storage of wetland to other water storage acreage on an acre for acre basis. Again, as more and more parts of the Prairie are excised for mining, the importance of the remaining areas increases, at least until reclamation projects succeed. IMCF did not give reasonable assurances as to the cumulative impact of the loss of Section 14 and the other areas under permit on the water storage capacity of the catchment area. See "J. Cumulative Impact," below. The ground water recharge function of wetlands refers to those situations in which a wetland is connected to an underlying groundwater aquifer system in such a way that surface water flows into the wetland system and then down into the underlying aquifer system. The underlying aquifer system is thus "recharged" by the infusion of surface water through the wetland system. The Section 14 Area does not perform any significant groundwater recharge function. Hookers Prairie, including the Section 14 Area, is a topographic depression. Therefore, water can flow out of the uppermost aquifer system (known as the surficial aquifer) into the wetlands, but the reverse is not true. Furthermore, the water in the wetland area cannot move down into lower aquifer systems (such as the intermediate aquifer or the Floridian aquifer) because of the existence of geologic confining layers that underly the Section 14 Area and inhibit vertical groundwater flow. The food chain support function refers to the ability of a wetland to produce organisms or biological material that is used as food by other organisms either in the wetland itself or in surface water areas downstream of the wetland system. The Section 14 Area performs some food chain support functions. Food chain support can be performed in three ways. First, dissolved nutrients, such as phosphorous and nitrogen, can be released into the water. Because of the prior spills into Hookers Prairie, the area is already discharging nutrients in amounts that are normally considered to be high. The second mechanism for performing food chain support is the physical flushing of small aquatic organisms downstream to feed the fish or other larger aquatic organisms. Studies carried out by the United States Environmental Protection Agency indicate that the small organisms found in the downstream reaches of the South Prong of the Alafia River do not appear to be similar to those found at the point of discharge from Hookers Prairie. These data indicate that Hookers Prairie produces and releases this type of food chain support but that its direct impact does not extend significantly into the southern reaches of the South Prong of the Alafia River, as compared to the total production from other tributaries of the river. The third type of food chain support is the release of detrital material (partially decomposed vegetation). Detrital material generated in much of Hookers Prairie is likely to be retained in the Prairie because of the sediment/trapping filtration function discussed above in Finding No. 17(b). However, being adjacent to the outflow from the Prairie to the South Prong, Section 14 could be expected to deliver a larger share of detrital material than the portions of the Prairie further east. The Section 14 Area provides a wildlife habitat function although it does not appear to serve as diverse a group of wildlife as is served by the eastern portion of Hookers Prairie. The Section 14 Area is not utilized for recreational purposes. It is densely vegetated so that access by man is difficult. There are no open water areas that could be used for hunting or fishing. Mitigation IMCF proposes to mitigate the temporary loss of function caused by the mining of the Section 14 Area by reclaiming the area following the completion of mining operations. The first step in reclamation will be the pumping of sand tailings back into the project area to create a land surface at approximately the original grade. The previously moved overburden material will then be spread and recontoured. Stockpiled organic muck material will then be spread over the reclamation area to provide a nutrient source to support plant growth. Department representatives will review and approve the final contours to assure that they are similar to those found in the original natural environment. Following completion of the contouring, the portion of the project area that will be reclaimed as a wetland will be inundated with water and then revegetated with desirable wetland species. The reclamation of the Section 14 Area will be subject to extensive monitoring by IMCF. This monitoring will involve short- and long-term vegetation monitoring and water quality monitoring. The results of this monitoring will be submitted to the Department, and the project will not be released from regulatory scrutiny until certain success criteria are met. During the period of recontouring, revegetation, and monitoring, the berm around the Section 14 Area will remain in place to isolate the area from the adjacent Hookers Prairie system. Once the Department determines that the vegetation in the Section 14 Area has been successfully reestablished, the Department will authorize IMCF to install culverts in the berm to allow for the gradual introduction of exchange of waters between the reclaimed area and the natural Hookers Prairie system. Following this process, after approval by the Department, IMCF will remove the berm area by pushing it back into the ditch and will replant the disturbed area in the previous location of the berm with desirable herbaceous wetland species. At that point, the reclaimed area will be totally reconnected to the rest of the western Hookers Prairie. The reclamation of the Section 14 Area will involve the recreation of approximately 121 acres of herbaceous wetlands. This is approximately the same amount of herbeceous wetlands that were mined or disturbed in the Section 14 Area. In addition, 24 acres of forested wetlands will be created. This is approximately six times the number of area of forested wetlands that were in the Section 14 Area prior to mining operations. IMCF has had extensive experience in the reclamation of wetland systems in Florida. The company has reclaimed over 3,000 acres of wetlands over the last ten years. The company's experience includes the reclamation of both herbaceous wetland systems and forested wetland systems. With regard to the proposed mitigation, the primary issue at dispute in the hearing was whether IMCF can control the growth of nuisance species, such as cattail and primrose willow, in accordance with the Department's current policy. This policy, which will be implemented as a condition of any permit issued in this matter, is that nuisance species shall be limited to ten percent or less of the total cover or, if these species exceed ten percent of the total cover, their density must be declining over several years. IMCF would use several methods to limit the growth of nuisance species in the reclamation area. The company will flood the reclamation area immediately following recontouring. In addition, the company will assure that water levels are maintained in the project area throughout the vegetation period. These hydrological controls are designed to preclude seeds from nuisance species growing nearby from blowing into the area and propagating. These seeds will not propagate under water. In addition, the project area would be covered by a two-inch to six- inch layer of organic mulch material. The use of such organic material inhibits the growth of nuisance species. Finally, IMCF will plant desirable wetland species on a relatively dense basis; i.e., on three- to five-foot centers. When established, these desirable species are expected to quickly grow and outcompete any nuisance species that may enter the area. There is legitimate concern about the growth of nuisance species in the reclamation area and about the company's ability to eradicate or remove nuisance species if in fact the area does become invaded. There also is legitimate concern that the disturbance caused by the construction of the perimeter berm might induce the growth of a five to fifteen foot band of nuisance species outside of the Section 14 Area. Even if this occurred, it would not have a significant impact on the Hookers Prairie system, which already contains a large amount of "nuisance species." Finally, there is a concern whether nuisance species can be kept out of the ditch and berm area after the berm is leveled since there no longer would be hydrological controls in place. I am persuaded by the weight of the evidence presented in this matter that, with the following additional special permit conditions, IMCF has provided sufficient reasonable assurances to the Department that it will be able to successfully reclaim the Section 14 Area and to control nuisance species growth in accordance with applicable Department policy: that, in accordance with existing Department policy, the plant material used for revegetation for the reclamation project be plants that grew naturally within 50 miles of the reclamation site; that the elevations in the reclamation site be "fine-tuned" after recontouring but before removal of the ditch and berm to approximate existing elevations as closely as possible except when deviations from existing elevations might be desirable to better accomplish the goals of the reclamation project and reduce nuisance species; that, upon removal of the ditch and berm, all nuisance species (cattails and primrose willow) that may have invaded the perimeter band along the berm (see Finding 25, above) be removed and revegetation over the ditch and berm area be on two to four foot centers to aid competition with any invading nuisance species. Evaluation of Project Impacts Extensive testimonial and documentary evidence was presented at the hearing concerning a wide variety of potential impacts associated with the mining of the Section 14 Area. Potential impacts addressed included the impacts of mining and reclamation upon surface water and ground water quality, upon surface water flow conditions, and upon the availability of ground water for use as a portable water supply by the Bradley Junction residents. In addition, evidence was presented concerning potential impacts upon the Bradley Junction community in the form of fugitive dust, physical damage to structures in the community, and impacts associated with machinery noise generate during the mining and reclamation process. Surface Water Quality The perimeter berm and ditch system around the Section 14 Area will completely segregate the mining operations from the adjacent Hookers Prairie wetland system and the South Prong of the Alafia River. Therefore, the mining operations will not have a direct adverse impact upon the quality of surface water outside of the Section 14 Area. As noted in Findings Nos. 17(a) and 17(b), the temporary exclusion of just the Section 14 Area from the Western Hookers Prairie wetlands system will not have a significant adverse water quality impact. But, see "J. Cumulative Impact", below. Construction of the berm will not significantly affect dissolved oxygen levels in Hookers Prairie even in the areas immediately adjacent to the berm. Natural dissolved oxygen levels in the Hookers Prairie system are relatively low, and its waters are normally in a static or stagnated condition. (Construction of the berm probably will elevate dissolved oxygen levels in some areas near the berm by creation of small open water areas and lower levels in other areas where discarded plant material accumulates.) The weight of the evidence indicates that the construction of the berm will not cause a violation of state water quality standards outside of the Section 14 Area. During the reclamation process, water quality monitoring will take place and the resulting data will be presented to the Department. Upon Department approval, the reclaimed wetland system will be gradually reconnected to the natural Hookers Prairie system. The water quality in the Section 14 Area after reclamation will comply with applicable State water quality standards. Ground Water Quality Several residents of the Bradley Junction community have raised concerns about the quality of the water withdrawn from their portable water supply wells. While it does appear that water from certain of these wells may be of substandard quality, this condition is not a result of phosphate mining operations and will not be affected by the mining and reclamation of the Section 14 Area. The basis for this finding is: Mining in the Section 14 Area will take place in the surficial aquifer system. Portable water supply wells in the Bradley Junction community area draw water from the intermediate aquifer system. The intermediate aquifer system is separated from the surficial aquifer system by a thick, relatively impervious clay layer that significantly impedes the vertical flow of ground water. The Section 14 Area is located hydrologically downgradient from the Bradley Junction community. Any seepage from mining operations will move away from Bradley Junction, not toward that location. The quality of the water that will be found in the mine cuts and ditches in the Section 14 Area is very good and probably would not significantly adversely impact the quality of the portable water drawn from Bradley Junction water supply wells even if it were physically possible for the mining-related waters to reach the wells. The Polk County Public Health Unit of the Department of Health and Rehabilitative Services carried out a study of the quality of portable water in the Bradley Junction community. The study indicates that water from certain of the wells exhibit elevated levels of fecal coliform. The probable source of this contamination is improper sanitary conditions in the area near the well locations. There is no evidence to indicate that phosphate mining operations have any impact on the quality of the water in these wells. Surface Water Flow Conditions At this time, the construction of the berm and ditch system and the mining in the Section 14 Area will have only a minor impact on surface water flow conditions outside of the Section 14 Area. The proposed mining and reclamation project itself will not cause an increased likelihood of flooding in downstream areas nor will it cause increased erosion in the South Prong of the Alafia River. IMCF has applied for and received a "Works of the District" permit for the Section 14 Area from the Southwest Florida Water Management District, the state agency primarily responsible for evaluating the impact of construction activities on surface water flow conditions. But see "J. Cumulative Impact," below. Ground Water Availability The digging of mine cuts in the surficial aquifer can result in a drawdown or lowering of the water table in the surficial aquifer system. If controls were not employed by IMCF in connection with the mining of the Section 14 Area, the surficial aquifer in the area of the Bradley Junction community could be drawn down by as much as five feet below natural levels. IMCF has applied for and received a consumptive use permit from the Southwest Florida Water Management District, the state agency primarily responsible for regulating the use of ground water in the State of Florida. The consumptive use permit requires IMCF to maintain the water level in the surficial aquifer at historic levels taking into account the natural variations in the water table that occur during the year. IMCF will comply with the conditions of the consumptive use permit by the use of two positive control methods. The perimeter ditch surrounding the project site will serve as a hydrological barrier or recharge ditch that will maintain the surficial aquifer water levels at historic levels. In addition, during mining operations, the dragline will cast the removed overburden material against the face of the mine cut. This procedure will have the effect of sealing the face of the mine cut and inhibiting the flow of ground water from contiguous areas into the mine cut. In accordance with the consumptive use permit, IMCF will monitor water levels adjacent to the Section 14 Area to assure compliance with the drawdown restrictions. 1/ As noted in Finding No. 32(a), the portable water supply wells in the Bradley Junction community draw water from the intermediate aquifer system. Water levels in the intermediate aquifer system are not significantly affected by the water levels in the surficial aquifer. The two systems operate independently by virtue of the thick confining layer that separates them. Mining operations in the surficial aquifer in the Section 14 Area will have no effect on the water levels in the intermediate aquifer system underlying the Bradley Junction community. Therefore, the proposed mining operations will have no effect upon the availability of water in the Bradley Junction portable water supply wells. Dust Dragline operations and slurry pit operations are wet process activities that do not generally result in the emission of dust. Dust can be emitted as a result of vehicle travel on access roadways, by land clearing operations, and during reclamation activities especially in the dry season under high wind conditions. IMCF will control dust emissions from the Section 14 Area by use of water trucks to keep access roads moist. In addition, IMCF will curtail land clearing and reclamation operations during periods when high winds are prevailing in the direction of the Bradley Junction community. Physical Impact on Structures Certain residents of the Bradley Junction community have complained that nearby mining operations have caused physical damage to their homes. The evidence presented at the hearing, however, demonstrates that neither vibration caused by the equipment used in mining operations nor the construction of mine cuts will cause any adverse physical effects on nearby structures. The basis for this finding are as follows: Vibration measurements taken in the vicinity of the type of equipment that will be used in the Section 14 Area demonstrates that the vibration levels that will be experienced at the residences closest to the mining operations are far below the level that would cause any structural damage. These worse case conditions would be experienced at a point approximately 250 feet from the mining operations. It should be noted that these conditions will only occur when mining operations are taking place in upland areas outside of the Department's jurisdiction. Vibration impacts resulting from mining activities in the more distant jurisdictional wetland areas are even less significant. A slope stability analysis carried out by Dr. John Garlanger demonstrated that the construction of a mint cut at a distance no closer than 250 feet from a residence will cause no adverse impact on the structural integrity of the residence. This conclusion is underscored by the fact that the dragline, which is larger and heavier than the typical Bradley Junction home, will safely operate very near the edge of the mine cut without significant risk of slope collapse. Any current physical damage to structures in the Bradley Junction community is probably the result of age, water damage, improper site preparation, and other improper construction techniques. Noise Draglines, pumps, and other pieces of heavy equipment to be used in the mining and reclamation of the Section 14 Area will produce noise that is audible to, and will be annoying to, the people living near the project. None of the expected noise levels will exceed the guidelines established by the Federal Highway Administration ("FHA") for construction of highway projects near residential communities. The FHA guidelines require that noise levels may not exceed 70 decibels more than 10 percent of the time. Even in the worst case situation, which involves mining in the upland areas no closer than 250 feet from a residential structure, the expected noise levels will not exceed the FHA guidelines. When mining operations occur at more distant locations, the noise experienced in the Bradley Junction community will be proportionately reduced. The suggested United States Environmental Protection Agency noise level limitation is 55 decibels. At the 55-decibel level, there was scientific evidence that noise exposure resulted in irritability and sleep loss, but no actual hearing loss would occur. The 55 decibel EPA guideline is calculated differently than the FHA guidelines. The maximum levels expected to occur near the Section 14 Area based on the data collected by Mr. Nelson were essentially in compliance with the EPA recommendations. Furthermore, the predicted noise levels reflect outside noise levels. The noise levels inside the structures in the Bradley Junction community would be below the recommended EPA levels because of noise attenuation by the structure. The mining operations would have a reduced impact upon sleep because the company will not operate between the hours of 11 p.m. and 7 a.m. when close to the residences. Mining operations in the northernmost portion of the project will occur over a period of seven months. Reclamation in the immediate vicinity of the Bradley Junction community will be completed within six months following mining operations. The predicted worst case conditions during mining and reclamation will occur only over a few weeks with regard to any particular residence. These worst case conditions will occur in upland areas outside the Department's jurisdiction. Noise resulting from activities taking place within jurisdictional wetlands is at even lower levels. Polk County Ordinance. The governmental body primarily responsible for public health concerns such as dust, noise and vibration impact or structures is the local government, Polk County. Polk County has enacted a mining setback ordinance which is less restrictive than other nearby counties - - only 250' from the nearest residence versus 500' in Hillsborough County and 1000' in Manatee County. Under the Polk County ordinance, IMCF is able to mine as close to Bradley Junction residents as it proposes. Archeological Resources There are no significant historical or archeological resources in the Section 14 Area. Cumulative Impact Hooker's Prairie is a wetlands marsh system which comprises the headwaters of the South Prong of the Alafia River. The Section 14 project area is an integral part of the Prairie. Although IMCF's case thoroughly addressed all other issues raised by the opponents of the Section 14 project-- including noise, dust and even damage to structures from vibration-- its case conspicuously failed to as clearly address the question of cumulative impacts. It is not clear from the evidence if Hookers Prairie historically was 3000 acres, 3500 acres or some other size. Likewise, the current size of the Prairie, unmined and unsevered, also is unclear from the evidence. DER has issued five previous permits for phosphate mining in Hooker's Prairie. These permits are to W. R. Grace for approximately 1000 acres in the Eastern Prairie and IMCF for approximately 120 acres in the Western Prairie, including the recent IMCF Section 12 project involving mining and filling approximately 100 acres of Hooker's Prairie. It is not clear from the evidence how much of the 1000 acres already has been mined. DER's appraisal report, dated November 4, 1987, states that there has been recent mining in Section 18 in the Western Prairie. It points out that, as a result, cattails have intruded into Section 13 of the Prairie from the east. The report states that, aside from the Section 14 project area, there were then only 720 acres of wetland left in the Western Prairie, which has been almost blocked from the Eastern Prairie by mining activities, 620 in Section 13 and 100 in the west side of Section 7. It also states that almost 700 acres "in [the Section 14 project) area alone" were then permitted for mining. Although it is not clear, this appears to consist of 96 acres IMCF had under permit "in this immediate vicinity" and 580 acres of the Prairie to the east. It is not clear whether this acreage is in addition to, or part of, the acreage referred to in Finding 48, above. To date, no one has successfully restored mined wetlands in Hooker's Prairie. IMCF has restored a small, approximately 20 acre tract of wetland in the Western Prairie, but no success determination has yet been made. IMCF's approximately 100 acre restoration in Section 12 is underway. Efforts by Grace to restore mined wetland in the Eastern Prairie were delayed while Grace and DER negotiated an alternative to the original "land and lakes" restoration concept approved under the DER permits. A wetlands restoration concept finally having been agreed to, restoration now is underway. W. R. Grace has plans to mine the entire remaining wetlands of Hookers Prairie in the foreseeable future. Wetland restoration takes approximately two to four years. IMCF plans to mine in Section 14 from July, 1989, through December, 1991. Restoration is planned to take place through December, 1994. It may take longer. During part of this time period, IMCF's 120 acres of restoration in the Western Prairie still will not be functional. There was no evidence to suggest that the Grace wetlands restoration would be completed before IMCF plans to complete its Section 14 restoration project. There was no evidence as to when Grace is expected to complete any restoration of the 1000 acres it has under permit in the Eastern Prairie. The same would be true of any other parts of the wetlands that may be under permit. In light of the substantial, though undeterminable, reduction of the size of Hooker's Prairie from its historical size, the cumulative impact of removing an additional 131 acres of wetland from the system for approximately five or more years is significant. During this time, the size of functional wetland in the Prairie may be close to just half its historical size or even less. IMCF has not given reasonable assurances that the cumulative impact of the loss of another 131 acres of Hooker's Prairie for five or more years, combined with the recent reduction in the size of the functional wetland, will not be contrary to the public interest. Further phosphate mining in Hooker's Prairie should await successful restoration of wetlands in areas already under permit for mining operations.
Recommendation Based on the foregoing Findings Of Fact and Conclusions Of Law, it is recommended that the Department of Environmental Regulation deny the application of IMC Fertilizer, Inc., to mine for phosphate in Section 14, Hooker's Prairie, at this time. RECOMMENDED in Tallahassee, Florida this 14th day of February, 1989. J. LAWRENCE JOHNSTON Hearing Officer Division of Administrative Hearings The Oakland 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 February, 1989.
The Issue Whether the alleged violation exists and, if so, whether orders for corrective action should be made final against respondents or either of them?
Findings Of Fact On October 17, 1984, Sunshine acquired from R & F what had been a filling station at the corner of U.S. Highway 98 and Laurie Avenue in Bay County, Florida. The old gas pumps had been moved some time before October 17, 1984. Only loose pipe connections leading to the underground storage tanks remained. The deed K & F executed in favor of Sunshine made no mention of these tanks. Respondent's Exhibit No. 1. Sunshine later contracted with Jake Walters, who began construction the following April to convert the site into a convenience store with gas pumps. On January 25, 1985, long before bringing any petroleum product onto the property, Jake Walters' construction foreman, John Kenneth Barnes, began taking up the two-foot slab of concrete that overlay K & F's underground storage tanks. The ground underneath the concrete smelled of gasoline. James Guris, who was overseeing the job for Sunshine, ordered work stopped and told Harold Millis, Sunshine's vice-president for real estate and construction, about the feel and smell of the soil. When Mr. Millis learned of the situation, he decided that DER should be notified. Because by then it was too late in the day to reach DER, Jim Guris called DER's office in Panama City on the following Monday, January 28, 1985. He spoke to DER's Grady Swann, who told him to file a discharge notification form with DER. Mr. Swann said removal of the underground tanks could go forward. Before removing the storage tanks, Mr. Barnes, or somebody at his direction, measured the depth of the tanks with a stick to determine how deep to dig. In this way two or three inches of gasoline were discovered in the bottom of each tank. Even though workmen secured a pump and pumped gasoline from each underground tank (into a 500-gallon tank mounted on a truck), they were unable to pump the tanks completely dry. In each of the three underground tanks, about a half inch of gasoline remained. With a crane and lifting rigs, they raised the tanks in an upright position, without spilling any gasoline. Except inside where the half inch of gasoline stood, the tanks and appurtenant pipes and tubing were dry. Mr. Guris ordered pressure tests done on the tanks, each a cylinder some five feet in diameter. Two of the tanks passed this test, but the third failed. That tank had a hole approximately one quarter inch in diameter a little left of center, about half way up one end of the tank. Groundwater on the site came within four and a half or five feet of the surface in early February of 1985. Because it contains less than 10,000 parts per million total dissolved solids, it is properly classified as G-II. A marine clay separates the surficial aquifer from the Floridan, but the surficial aquifer recharges the Floridan. Northeast of where the storage tanks were dug up and 300 to 350 feet way a two-inch well 390 feet deep supplies water from the Floridan aquifer to three households. Nobody has detected any odor or taste of gasoline in water from those wells. Grady Swann took soil samples on site on February 8 and again on February 26, 1985. On his first visit, he noticed no sheen on the surface of the water standing in the area excavated around the old tanks, smelled no odor emanating from the standing water and did not take a sample. On his second visit, he did notice evidence of groundwater contamination and took water as well as soil samples. Mr. Swann returned on March 11, 1986, with Kenneth L. Busen and Mike Wilson of DER's Operation Response Team and used a power augur to put in temporary wells from which additional water samples were taken. These tests confirmed suspicions that the old gas tanks had leaked and revealed groundwater contamination attributable to gasoline including, in some samples, more than 1,000 times the allowable concentration of benzene. Gasoline seeping through soil leaves residual hydrocarbons which contaminate percolating rain or other groundwater moving through the same soil. Petitioner's Exhibit No. 6 depicts the probable initial configuration of the plume of hydrocarbons in the vicinity of the old tanks. Contamination is moving down gradient to the northeast, spreading out but growing more dilute. The steps called for by the proposed corrective orders are a reasonable way to mitigate environmental damage.
