The Issue The issues in this case are whether Respondents engaged in the unlicensed practice of contracting, and, if so, what penalty should be imposed.
Findings Of Fact The Department is the state agency responsible for, inter alia, licensing and monitoring general contractors. The Department headquarters are in Tallahassee, Florida. Part and parcel of the Department's duties is the sanctioning of persons who practice general contracting without a license. Morin is an individual living in Orlando, Florida. At all times relevant hereto, Morin was the registered agent and managing member of the LLC. As of the date of the final hearing, the LLC was no longer an active entity in Florida. No other members of the now-inactive LLC appeared at the final hearing. The Administrative Complaint filed by the Department makes the following allegations: Morin was not registered or certified to engage in the practice of contracting. The LLC was not registered or certified to engage in the practice of contracting. Respondents contracted with Scott Ghivizzani to construct a deck and boat dock in Lake County, Florida. Ghivizzani made a down payment to Respondent, but the deck and boat dock were never constructed. The down payment was never returned to Ghivizzani.1 The LLC is essentially a subsidiary of an entity also known as Barefoot Docks, but which operates in the state of Georgia. The Georgia entity advertises itself as a company which will construct, among other things, floating docks. At some point in time, the Georgia entity decided to create a limited liability company in Florida to handle its sales in this state. Morin, the company's primary salesman in Florida, became registered agent of the Florida entity, known and previously identified as Barefoot Docks of Florida, LLC. Morin resides in Florida and became a salesman for the LLC's products (primarily floating docks) in this state. Ghivizzani had contacted the LLC's representatives in Georgia concerning a floating dock. The Georgia representatives had referred Ghivizzani to Morin as their Florida contact. Thereafter, Ghivizzani dealt solely with Morin concerning the purchase. Ghivizzani ultimately signed a contract on June 14, 2005. The contract is entitled "Barefoot Docks Contract" and is signed by Ghivizzani. The total price of the contract was $49,500, with a deposit of $29,350 paid at the time of signing. The contract sets forth a general list of the component parts of the dock. Included in the contract was a provision in Section 5 saying, "All appropriate permitting will be handled by Barefoot Docks and no construction will begin until all permits are in effect. Owner will be charged all local and state permitting fees at final billing." The tone of the contract is a sufficient basis for Ghivizzani to believe that (1) there would be construction involved; and (2) Barefoot Docks was a licensed contractor. The contract did not, however, distinguish between the Georgia and Florida entities. The contract is not signed by the LLC or the Georgia entity. Morin does not dispute the general allegations in the Administrative Complaint except that the subject contract was between the LLC and Ghivizzani, i.e., that Morin was not individually bound by the contract. Further, Morin claims he was the agent of the LLC but did not individually contract with Ghivizzani. Also, Morin maintains that the LLC, of which he was a partial owner, merely sold Ghivizzani a prefabricated dock "kit" and agreed to assemble it for Ghivizzani, i.e., that it was not construction per se. The normal turnaround time for the LLC to put together a dock kit was about one month from the date it was ordered. In fact, another project completed by the LLC just across the lake from the Ghivizzani project took only about a month. The Ghivizzani project took six to eight months just to obtain a permit from the St. John's Water Management District. By the time this permit was issued, the LLC had essentially stopped doing business. The requisite city and/or county permits for this project were never obtained. The floating dock project necessarily required some electrical components. The electrical wiring component was not part of the original contract, but could be done at an additional cost to the owner. In that case, the LLC would have contacted an electrician to do the work. Ghivizzani's down payment was deposited by Morin into the LLC operating account. Morin at that time had access to the account as a member of the LLC and used a portion of the down payment to order component parts for the dock structure and to seek the necessary permits. Morin estimates that $9,000 to $10,000 of the deposit was used, leaving $19,000 to $20,000 of the deposit available. At some point in time, Ghivizzani decided to terminate the contract and asked Morin to return his deposit. Morin contacted the LLC's other members (who were both in Georgia) and was told that they would attempt to take money from another pending project in order to repay Ghivizzani. Morin attempted for several months to obtain the deposit as promised. After months of efforts by Morin to obtain Ghivizzani's down payment, the Georgia partners stopped returning Morin's calls. Morin realized at some point that the business had closed; at that time, there was no money in the LLC's bank accounts. None of the deposit was ever repaid to Ghivizzani. The materials and component parts of his dock were allegedly being held in the Georgia warehouse, but nothing was ever delivered to Ghivizzani. Ghivizzani had also paid the LLC to demolish an existing dock on the site. That work was done and paid for separately from the new dock purchase. Neither Morin nor the LLC has ever been licensed in the State of Florida to perform general contracting or electrical contracting.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that a final order be entered by the Department of Business and Professional Regulation finding that Respondent, Barefoot Docks of Florida, LLC, is guilty of the unlicensed practice of contracting. Inasmuch as the LLC is no longer active, imposition of a fine or other sanctions against it would be meaningless. However, its principals (Jim Peterson and Dennis Shaw) should be denied certification should they ever apply in this state. As for Respondent, Chad Morin, the mitigating facts support an administrative fine of $500. DONE AND ENTERED this 26th day of February, 2008, in Tallahassee, Leon County, Florida. S R. BRUCE MCKIBBEN Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 26th day of February, 2008.
Findings Of Fact Petitioner, Edward W. Horsman, filed an application August 14, 1984, pursuant to Chapter 489, Florida Statutes, for certification by examination as an electrical contractor. On October 12, 1984 Respondent denied Petitioner's application on the basis that he lacked sufficient experience in the trade to qualify for the licensure examination. Section 489.521, Fla. Stat., and Rule 21GG-5.02(1), F.A.C. Petitioner filed a timely request for a hearing pursuant to Section 120.57, Fla. Stat. Petitioner has 20 years experience in the electrical construction industry. From 1965-1980 Petitioner was employed by Spaulding Electric Company, an electrical contractor in Detroit, Michigan. While employed by Spaulding, Petitioner worked as a wireman for one and one-half years, a foreman for one and one- half years, a field superintendent for four years, an estimator for one and one-half years, chief estimator for one and one-half years, and as manager of electrical construction for five years. Petitioner's managerial and supervisory experience included supervision of draftsmen in plan preparation, bid estimates, negotiation of contracts, overall supervision of construction, scheduling and purchasing. From 1980-1982 Petitioner was employed by Lastar Electric Company, an electrical contractor in Madison Heights, Michigan. Petitioner's managerial and supervisory experience at Lastar comported with his duties at Spaulding. In December 1982 Petitioner was laid off by Lastar, due to an economic recession which plagued Detroit, Michigan. From December 1982 until February 1984, Petitioner operated his own consulting firm in Rochester, Michigan, providing estimating and project management services for electrical contractors. Business was poor, and few contracts were acquired. In February 1984 Respondent relocated to Englewood, Florida, and undertook his current employment with Baldwin Electric, Inc. Respondent seeks to be licensed as the qualifying agent for Larry's Electric, Inc., a wholly owned subsidiary of Baldwin Electric, Inc.
Findings Of Fact Application No. 76-00336 is a request by the City of Plant City, Florida, for a new use from a single well at a location approximately 31 miles east of downtown Plant City. The well would be located in the Hillsborough Basin. The average annual daily withdrawal sought is 2.0 million gallons with a maximum daily withdrawal sought being 3.5 million gallons. The amount requested is consonant with the needs of the city and contains provision for some growth. The Plant City service area encompasses 8,600 acres. The sought for consumptive use will not significantly induce salt water intrusion. The consumptive use sought may interfere with existing legal uses. There are a number of private wells, perhaps 50-60, in the area. Most of these wells are in a subdivision known as Pleasant Acres. These wells will experience drawdowns of up to 4.3 feet which may cause the pump to break suction during the dry season or line pressure to drop. Further, the average drawdown at the property boundary created by the sought for consumptive use will be approximately 6.3 feet. The boundary of the well site is approximately 150 feet from the well. The well could have been located so that the average drawdown at the property boundary would not have been in excess of 5 feet. The well is already in existence, having been constructed over one year ago. The primary purpose of the well is for better fire protection and additional capacity for domestic use and growth in Plant City. The residents of Pleasant Acres are very concerned about the effect of the proposed well on their existing wells. The Southwest Florida Water Management District's staff recommends granting of the permit with the following conditions: That the City of Plant City shall install a totalizing flowmeter on the well. That the City of Plant City shall submit monthly pumpages on a quarterly basis to the following address: Chief, Technical Information Service, SWFWMD, 50560 U.S. 41 South, Brooksville, Florida. That upon completion of construction of all pumping facilities the City of Plant City will pump the permitted facility during the third week of the following May at the maximum rate of 3.5 million gallons per day for at least three days. Private well owners within a radius of mile will be notified prior to the initiation of the tests. Complaints will be handled by the city according to stipulation D. The City of Plant City shall investigate under the direction of the city engineer, all complaints by owners of private wells which are within a mile radius of the permitted facility and which relate to loss of water. Further, the city shall repair or replace at no cost to the owner, those private wells and/or the associated pumping facilities which are substantially affected by the city's with- drawals and which can be attributed to 10 feet or less of drawdown. With the exception of those matters set forth above pertaining to Subsection 16J-2.11(4)(b), F.A.C., none of the matters set forth in Subsection 16J-2.11(2), (3) or (4), F.A.C., exist, with regard to this application so as to require its denial.
Recommendation It is recommended that Application No. 76-00336, submitted by the City of Plant City, Florida, be granted in the amount of 2 million gallons per day average annual withdrawal and 3.5 million gallons per day maximum daily withdrawal, provided that the four conditions listed in paragraph 8, above, be placed upon the permit. ENTERED this 26th day of May, 1976, in Tallahassee, Florida. CHRIS H. BENTLEY, Hearing Officer Division of Administrative Hearings Room 530, Carlton Building Tallahassee, Florida 32304 (904) 488-9675 COPIES FURNISHED: Jay T. Ahern, Esquire Staff Attorney Southwest Florida Water Management District P. O. Box 457 Brooksville, Florida 33512 Salvador D. Nabong City Engineer City of Plant City P. O. Drawer C Plant City, Florida 33566 Paul Buckman, Esquire City Attorney City of Plant City City Hall Plant City, Florida 33566
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.
Findings Of Fact DOT has been engaged for some years in a program to improve U.S. Highway 1, which runs through the Florida Keys. The program has involved highway paving, and reconstruction of most of the bridges. The roadway and bridge construction projects require large amounts of fill material. DOT has experienced an increase in the cost of obtaining fill material in the Florida Keys. To lessen the cost of the fill material DOT is seeking to open a borrow pit on Dudjoe Key. The pit, and an adjoining roadway would cover approximately fourteen acres. DOT initially filed a permit application with DER, seeking approval to construct the pit. DER ultimately issued a notice of intent to deny the application on the grounds that reasonable assurances had not been given that the short-term and long-term effects of the proposed project would not violate water quality standards set out in DER's rules and regulations. DOT thereafter filed a request for variance from the water quality standards so that the pit could be permitted. This proceeding ensued. Petitioner is a Florida corporation which does business in Monroe County, Florida. Petitioner has engaged in numerous public road and bridge construction projects in the Florida Keys and in the selling of fill material for road and bridge construction projects. Petitioner currently owns and operates a "borrow pit" on Cudjoe Key. Petitioner's pit is located within one- half mile of DOT's proposed pit. The purpose of the DOT pit would be to provide fill material which the Petitioner currently provides from its Cudjoe Key pit. DOT originally asserted that operation of a state borrow pit would result in savings of nine million dollars. This assertion has been scaled down to three million dollars, and more recently to 1.5 million dollars. Basically, DOT asserts that fill from a state-owned pit would be cheaper because the operation costs would be approximately the same, but no royalty would need to be paid for the material. DOT sought to establish the amount of potential savings at the hearing through two kinds of analysis: First, DOT offered the testimony of its former cost estimator as to the costs per cubic yard of fill from a state-owned pit as opposed to fill from a private contractor pit; and second, DOT offered bid submissions that have been made by contractors in recently bid projects in the Keys, and which had alternative bids for state-owned and private contractor supplied fill material. DOT's estimator calculated that the State would save approximately 1.5 million dollars through operation of a state-owned borrow pit. The testimony, however, is not of probative value, and cannot serve as the basis for a finding to that effect. In the first place, many of the estimator's figures were determined through private conversations that he had with various unnamed contractors. This hearsay evidence is not cumulative nor corroborative of other evidence, and cannot therefore serve as the basis for a finding of fact (See discussion at Paragraph 2 of the Conclusions of Law, infra.). Furthermore, the estimator underestimated the heavy equipment that would be required to operate the borrow pit; underestimated the cost of the equipment; did not include insurance, social security, and overtime in labor costs; overestimated by twice the number of swings that a dragline would be able to make; and underestimated the cost of moving equipment to the site. Methodology used by the State's estimator would appear to be the best that is available to the State in making initial estimates as to the cost of proposed road-building projects. The State does not have the detailed cost information available to it that private contractors have. While useful for the purpose of making preliminary estimates of the cost of proposed projects, the methodology is not adequate to support a finding of fact based as it is upon hearsay, and containing numerous miscalculations. The second line of analysis offered by DOT to establish the amount of possible savings was a comparison of recent bids submitted by contractors. Special provisions drafted by DOT for the Park and Bow bridge projects using two alternatives for embankment or fill material. Alternate "A" in the bid called for state-furnished material. The low bidder on the project was Atlantic Foundation Company, Inc. Under Alternate "A", Atlantic bid a price of $9.35 per cubic yard for embankment material, and $12.00 under Alternate "B". This would have resulted in a total of $222,574.00 lest using the Alternate "A" bid on the Park and Bow projects. The second low bidder, MCC of Florida, Inc., bid $11.13 for material under Alternate "A", and $14.02 under Alternate "B". Alternate "A" would have been $247,752.00 cheaper under the MCC bid. Petitioner was the next low bidder, and it bid $10.05 per cubic yard under Alternate "A", and $10.25 under Alternate "B". Hardaway Constructors, Inc., was the only other bidder, and it offered $10.00 under Alternate "A", and $10.25 under Alternate "B". The potential savings in favor of Alternate "A" under all of these bids is reduced somewhat by clearing and grubbing costs which were bid separately by the contractors. Clearing and grubbing costs would actually have made Alternate "B" cheaper under the bids submitted by Petitioner and Hardaway. Clearing and grubbing costs would not, however, continue as a cost item in subsequent projects, because once clearing and grubbing is accomplished, it would not need to be done again. DOT seeks to apply bid differentials submitted for the Park and Bow Channel jobs to determine the potential saving the State could realize by using a state-owned landfill for the remaining road and bridge projects in the Keys. Approximately 402,039 cubic yards of embankment material will be needed to complete the remaining projects. Using the high differential between Alternates "A" and "B" submitted for the Park and Bow Channels (that submitted by MCC), which was $2.89 per cubic yard, the potential saving would be $1,161,892.00. Using the low differential (twenty cents per cubic yard as submitted by Petitioner), savings would be $80,407.00. Subsequent to the hearing, DOT awarded the Park and Bow Channel construction to the low bidder, Atlantic Foundation, Inc. The Alternate "B" proposal was accepted. DOT did not accept that proposal because of a preference to do that, but rather so that the otherwise advantageous bid could be accepted despite the pendance of this proceeding. During the hearing, bids were opened for two new road and bridge projects in the Keys: the Kemp and Torch-Ramrod Channel Projects. The apparent low bidder on these projects was the Petitioner. Petitioner bided a price of $11.00 for embankment material if provided by a private contractor, and $10.80 if provided from a state-owned pit for the Kemp project, and $10.40 and $10.20 respectively for the Torch-Ramrod Project. The differences between the two reflect differences in hauling distance. The price differentials for contractor versus state provided embankment material in projects that have already been let cannot be used to determine with any precision the amount of saving that would inure to the State through opening its own borrow pits. Potential savings depend upon many factors. The primary of these factors is which contractor happens to make the lowest bid for the project, and this in turn depends upon the contractor's cost figures for many items other than embankment material will receive the bid only if the total bid is lower than that submitted by other contractors. It is clear that opening a state-owned borrow pit would result in some savings. It appears that $10.00 per cubic yard is the lowest possible price that could be expected for contractor- provided fill material. It appears that state-furnished material could reach a price as low as $7.00 per cubic yard, although none of the bids submitted up to the time of the hearing reflected such a price. It appears that the highest potential saving would be less than the approximately one million dollars that would have been saved if the price differential reflected in the Atlantic Foundation bid on the Park and Bow Channel projects became the differential in all subsequent projects. It also appears that the saving would be somewhat more than the eighty thousand dollar saving that would inure if the price differential reflected in the Petitioner's bid on the Park and Bow projects remained consistent. Beyond these parameters, the evidence would not support a finding as to the amount of savings. The fourteen-acre site of the proposed borrow pit is presently comprised entirely of tidally inundated wetland areas. Approximately two-thirds of the area has average water depths up to six inches. The southeastern portion of the site is dominated by buttonwood, and red, black and white mangrove. All of these species are wetland indicator species under DER's rules and regulations. A large number of mollusks inhabit the area, and it is a feeding area for birds, and for deer. The area of the proposed borrow pit is within the Key Deer Refuge, which is managed by the Refuse Division of the United States Fish and Wildlife Service. There is now a stable herd from 350 to 400 Key deer, an endangered species, and they feed primarily on mangrove. There are 15 to 20 deer in the Cudjoe Key area. The deer do presently feed in the area of the proposed borrow pit. The proposed pit, including the access roads, would comprise approximately fourteen acres. It would be located landward of a berm so that there would not be a constant exchange of waters between the pit and surrounding areas. There would be an initial two-foot drop form the edge of the pit, and then a slope of five-to-one extending into the pit. A ten-to-one slope would be preferable because ultimately vegetation would be ore easily established in such a slope area. The term "Borrow pit" is actually a euphemism for a mining operation. Material would be extracted from the pit to be used as embankment material on the Keys road and bridge projects. The pit would ultimately reach a depth of more than thirty feet. Construction of the borrow pit would result in obliteration of approximately fourteen acres of a natural wetland environment in the Keys. All the flora and fauna presently on the site would be destroyed. During the time that the pit is being constructed and actively operated, violations of DER's standards for turbidity, lead, oils and greases, and transparency would be likely. Once the mining operation terminates, these short-term impacts would lessen; however, violations of the Department's dissolved oxygen standards would be likely as long as the pit exists. A viable biologic community could be established along the fringes of the pit, but in the deeper areas, low dissolved oxygen levels would be a limiting factor. Other mining operations in the Keys and elsewhere in Florida confirm the likelihood of dissolved oxygen violations. Loss of the fourteen acres of feeding ground for the Florida Key deer would be a significant loss in terms of preservation of that species. The proposed borrow pit is located adjacent to U.S. Highway 1. On the other side of the highway, there is a housing development. Operation of the borrow pit, especially blasting activities would inevitably prove a nuisance to residents of that area. One witness testified that blasting would likely cause damage to the residences, but this was not confirmed by competent, scientific evidence.
The Issue The issue is whether the Department of Environmental Protection's (Department's) proposed award of a contract to Intervenor, CDM Constructors, Inc. (CDM), is contrary to the Department's governing statutes, rules or policies, or the solicitation's specifications.
Findings Of Fact Based on all of the evidence, the following findings of fact are made: Background Piney Point is an abandoned fertilizer manufacturing plant adjacent to Port Manatee in Manatee County. In the fertilizer manufacturing process, phosphate rock is converted into soluble phosphorus by adding sulfuric acid to the phosphate rock to produce phosphoric acid. A by-product of this activity is phosphogypsum. For every ton of phosphoric acid produced, approximately five tons of phosphogypsum are produced. The phosphogypsum is stored in stacks like the ones at Piney Point. Federal and state regulations require that the phosphogypsum be managed in stack systems. (Stack systems are large impoundments containing contaminated water that has come into contact with the phosphogypsum.) This is accomplished by using process water to "slurry" the phosphogypsum to the stacks where the phosphogypsum settles out. The process water becomes extremely polluted as a result of the manufacturing activities and is typically very acidic. It contains heavy metals, such as arsenic, cadmium, chromium, and fluoride, in addition to high levels of nutrients, nitrogen, and total dissolved solids. It is also slightly radioactive. The process water is stored in impoundments surrounded by the phosphogypsum stacks, in cooling ponds, and in the seepage ditches around the stacks. The Piney Point site is located south of Tampa, approximately one mile inland from Bishops Harbor, which is a portion of Tampa Bay. The site encompasses a total of approximately six hundred acres. There are two phosphogypsum stacks located at Piney Point; each of these is divided into two compartments or ponds. Today, the old gypsum stack rises to a height of eighty feet. The site previously held around 1.4 billion gallons of process water with 800 million gallons stored in the various ponds and 600 million gallons stored in the pores of the gypsum stacks as pore water. The site is currently estimated to have 500 to 550 million gallons of process water of which about 350 million gallons is pore water. All of this water must be treated and removed in order to close and remediate the site. To close one of these phosphogypsum stack systems, all of the water must be removed from the ponds. The surface is allowed to dry and is then graded. A polyethylene liner is placed over the surface and than a soil cover is placed on top of the liner. The liner prevents any additional rainfall from infiltrating into the gypsum stack and creating additional process water. The pore water underneath the liner is then allowed to drain from the stack and is collected in seepage ditches, where the water will ultimately be treated. A thick layer of grass is grown on the steep slopes of the gypsum stacks to help prevent infiltration of rainwater back into the stacks. The ultimate goal is to convert this site into a freshwater reservoir for the residents of Manatee County. Until early 2001, Piney Point Phosphates, Inc., which was a subsidiary of Mulberry Phosphate Company (Mulberry), owned and operated a fertilizer manufacturing complex at Piney Point. (Mulberry also operated another fertilizer manufacturing complex in Mulberry, Florida). In February 2001, Mulberry filed a petition for protection from creditors in the United States Bankruptcy Court in Tampa, Florida. At the same time, Mulberry notified the Department that it did not have the resources to maintain the site. (The Department was also advised by Mulberry that it did not have the resources to maintain the stack system at the Mulberry site.) Because there existed the potential for release of the contaminated waters from Piney Point into Tampa Bay, the Department immediately assumed financial responsibility for Piney Point and in May 2001, a state court appointed a Receiver for Piney Point to take "all reasonable steps and action to preserve the Property's environmental integrity and its compliance with environmental regulations." To execute these duties, the Receiver entered into a contract with the Department. Pursuant to that contract, it retained the services of Ardaman, an international engineering consulting firm in Orlando, Florida, as its engineer of record to design a plan to close Piney Point and to ensure that the plan was properly implemented. At about the same time, the Receiver contracted with IT Corporation, the predecessor to Shaw, to begin some of the site closure work on an emergency basis. Since that time, the Department has spent $63 million at Piney Point, with Shaw receiving a majority of that amount. Based on the Department’s experience at the Mulberry site, it believed that it could realize a significant savings to the State through the Invitation to Negotiate (ITN) process and the use of a lump sum contract, rather than continuing to contract out the work for Piney Point on a time and materials basis. Further, the Department's Inspector General had recommended a lump sum contract as an incentive to the contractor selected to conduct the closure work. The ITN Under Section 403.4154(3)(a), Florida Statutes (2004),1 "[t]he department may take action to abate or substantially reduce any imminent hazard caused by the physical condition, maintenance, operation, or closure of a phosphogypsum stack system." Pursuant to this provision, on July 16, 2004, the Department issued ITN No. 2005002C (the ITN) entitled "Closure of the Piney Point Phosphogypsum Stack System." The contract called for a contractor to provide services at the Piney Point site in three primary areas: continued operation and maintenance of the site; water consumption; and closure of the phosphogypsum stack system. Water consumption consists of treating the process water and pore water and removing it from the site by evaporation, irrigation, discharge, or other methods. Closure of the stacks includes draining water from the stacks, grading the banks, and installing liners, clean soil, and sod. The contract is estimated to be worth approximately $51.2 million to the successful vendor. The contract was intended to replace the Receiver's existing contract with Shaw, although Shaw was free to compete for the new contract. A number of individuals were involved with developing the ITN. First, Gwenn D. Godfrey, who is the Department's Procurement Administrator, assisted with the original ITN. Also, Phil Coram, who is the Department's Chief of the Bureau of Mine Reclamation, was heavily involved with the ITN and assumed a major role on technical issues such as operation and maintenance as well as water management planning. Although the Department does not normally use private consultants in the procurement process, due to the complex technical issues involved, it retained Ardaman to assist with the procurement process. Ardaman, who was then serving as engineer of record on the project, does approximately 90 to 95 percent of all work performed in Florida in the area of phosphogypsum stack systems and has special expertise in that area. (As noted above, Ardaman designed the complex closure plan for the facility.) One of its employees, Dr. Nadim Fuleihan, a senior vice president and principal engineer, has served as the chief engineer for the Piney Point project since 2001 and has worked closely with Mr. Coram, who has been the Department's coordinator on the project since 2002. According to Mr. Coram, Dr. Fuleihan "knew more about that site, especially the closure aspects, . . . than anyone." This observation was undisputed. For that reason, Dr. Fuleihan was requested to assist in the procurement process. Mr. Coram was asked by Department management to identify individuals to serve as evaluators for the ITN process. Besides Dr. Fuleihan, management wanted the evaluators to consist of Department employees within the Bureau of Mine Reclamation, the Division of Waste Management, the Office of General Counsel, and representatives from other agencies that had been involved with Piney Point. The seven ITN evaluators consisted of Mr. Coram; Dr. Fuleihan; Sam Zamani, Administrator for the Department's Phosphate Management Program; John Wright, a professional engineer in the Department's Division of Waste Management; Jon Alden, a Department attorney who has represented the Department in the Mulberry bankruptcy case; Robert Brown, a Senior Environmental Administrator for Manatee County; and Richard Eckenrod, Executive Director of the Tampa Bay Estuary Program (TBEP). Before the evaluation process began, the Department required all members of the evaluation team to sign a certification that if "at any time during [their] participation on the contractor selection committee, that a potential conflict of interest exists," they agreed to notify the Department's Procurement Section of the circumstances surrounding the potential conflict of interest. By doing so, the Department complied with Section 287.057(20), Florida Statutes, which requires that if the procurement costs more than $25,000.00, "the individuals taking part in the development or selection of criteria for evaluation, the evaluation process, and the award process shall attest in writing that they are independent of, and have no conflict of interest in, the entities evaluated and selected." A requirement that the certification form be executed by each team member is also found in the solicitation instructions. Significantly, the certification form imposed a continuing obligation on the evaluators to notify the Department should any "potential conflict of interest arise." Prior to submitting responses, three potential vendors, Shaw, Compass, and CDM, contacted Dr. Fuleihan and asked him to participate on their respective teams in the ITN process. Dr. Fuleihan declined to work with any of them on an exclusive basis. Tetra Tech, Inc., which is Ardaman's parent company, also considered preparing a response to the ITN but Dr. Fuleihan advised it not to do so since Ardaman's status as engineer of record could raise a conflict of interest. On September 10, 2004, CDM, Compass, Shaw, and Coburn Construction (Coburn) submitted replies to the ITN. The Department subsequently deemed the reply by Coburn to be non- responsive for its failure to comply with the requirements of the ITN. Coburn did not challenge this determination. The other proposals were independently reviewed, scored, and ranked. The results were given to Mr. Coram, who computed an average rank for each of the firms. The final average rankings were very close with Shaw being ranked first, followed by Compass and CDM, who were tied. After the initial replies were filed, Mr. Eckenrod became concerned that he had a potential conflict of interest with Craig A. Kovach, President of QuietEarth Consultants, Inc., which was identified as a CDM subcontractor and team member. Mr. Kovach's wife served on the TBEP Board of Directors and had hiring and firing authority over Mr. Eckenrod. Accordingly, Mr. Eckenrod emailed the Department's Office of General Counsel for a determination of whether a conflict existed. Under the Department's Code of Ethics, which is also known as Administrative Directive DEP 202 (DEP 202), "[e]mployees should avoid any conduct . . . which might undermine the public trust, whether that conduct is unethical or may give the appearance of ethical impropriety." See Compass Exhibit 32, DEP 202, paragraph 7.a. In addition, another document known as DEP 315 establishes Department policy for the purchase of contractual and professional services. See Compass Exhibit 61. Paragraph 26 of DEP 315 adopts the standards of conduct for public officers and employees which are codified in Section 112.313(3) and (7)(a), Florida Statutes. While not specifically applicable to Mr. Eckenrod's situation, among other things, that paragraph prohibits Department employees from having an "employment or contractual relationship with any business entity . . . which is . . . doing business with" the Department. Teresa L. Mussetto, a Department attorney who then served as a Department Ethics Officer on behalf of the General Counsel, issued an opinion on September 29, 2004, stating in part that even though Mr. and Mrs. Kovach had never sought to influence Mr. Eckenrod, his professional association with a member of the CDM team "may be perceived as a conflict of interest," and that if the contract were ultimately awarded to CDM, the transaction might "reasonably give rise to the 'appearance of impropriety.'" See Shaw Exhibit 21. Ms. Mussetto also determined that even though Mr. Eckenrod was not a Department employee, he acted as an integral part of the procurement team and that DEP 202 was applicable to him. (It follows that DEP 315 would likewise apply.) Because DEP 202 requires that every aspect of the procurement process be conducted in a manner which would not undermine the public trust or lead a reasonable person to question its fairness and impartiality, Mr. Eckenrod's potential conflict with CDM's subcontractor was a sufficient basis for his removal from the evaluation team, and he did not participate further in the process. On October 12, 2004, the Department gave notice of its rankings of the vendors and informed them that it intended to exercise its right to conduct oral discussions with all three vendors. The firms would then be asked to submit Best and Final Offers (BAFOs) which would be scored anew. This was consistent with the ITN, which provided that the Department "reserves the right to short list respondents deemed to be in the competitive range to conduct oral discussions prior to the final determination of contract award." The decision to conduct oral discussions was made by senior management in the Department at the time scores were posted for the replies to the ITN. The Secretary of the Department, along with other senior management, determined oral discussions would be conducted with all three vendors to assist in formulating the BAFO Instructions (Instructions) and then the Department would proceed to score the BAFOs. No one has challenged this process. Development of the BAFO Instructions Before drafting the Instructions, the Secretary of the Department met with Earl Black, a Department of Revenue attorney, and Barbara F. Phillips, a Purchasing Analyst with the same agency. Both individuals had substantial experience with procurements and were asked to participate in the BAFO process. They agreed and were added to the evaluation team. As finally formed, the team consisted of two attorneys, four engineers, and two persons with significant procurement experience. Six of the eight had considerable prior knowledge of the Piney Point site. In an effort to refine the Instructions, CDM, Compass, and Shaw each made oral presentations to the Department's evaluators and other Department staff on November 3, 2004. All of the evaluators, including Mr. Black and Ms. Phillips, attended the oral presentation. As part of this process, the vendors were able to ask questions of the evaluators, and the evaluators were able to ask questions of the vendors. Following the oral discussions, another round of discussions was held with each vendor. These discussions were referred to as "negotiation sessions." The purpose of these discussions was to better understand the cost elements and facts of each vendor’s initial proposal in order to develop the Instructions. Mr. Alden, Dr. Fuleihan, Mr. Black, and Ms. Phillips conducted these discussions with each vendor. The Instructions were drafted by a group of individuals including Dr. Fuleihan, Mr. Black, Ms. Phillips, Ms. Godfrey, Mr. Alden, and Mr. Coram. Dr. Fuleihan gave input on the sections relating to technical issues primarily in the scope of work, which included the process water consumption section. He was also involved in revising the pricing summary and developing the evaluation criteria. Neither Shaw nor Compass challenged any part of the Instructions. After the Instructions were completed, but before the BAFOs were submitted by the three vendors, the Department again required each evaluator to complete a second conflict of interest certification. The form was similar to the earlier certification in the procurement process and required that the members certify that they had "no conflict of interest" with the "entities being considered for the contract award." Like the earlier form, it imposed a continuing obligation on the evaluators to notify the Department should any potential conflict of interest arise. The form listed CDM, Compass, and Shaw as the relevant entities. Each member, including Dr. Fuleihan, executed the certification. At that time, Dr. Fuleihan was not aware of any projects that Ardaman was doing for Shaw or Compass, and he did not believe that Ardaman was doing any work for CDM because of a past disagreement with one of the CDM entities that resulted in no work between the companies for many years. Section 1.19 of the Instructions provides that the Department reserves the right to waive minor informalities or irregularities in the offers received where such are merely a matter of form and not substance and the correction of which are not prejudicial to other vendors. Evaluation of the BAFOs On November 15, 2004, the Department issued the Instructions, which required that responses be filed by the three vendors no later than Wednesday, December 1, 2004. The Instructions also informed the vendors that negotiations with the top-ranked vendor would begin immediately after the posting of the scoring results. CDM, Compass, and Shaw timely submitted their BAFOs on December 1, 2004. CDM's response indicated that it proposed to use a specific water treatment process relying on The Mosaic Company (Mosaic) as its subcontractor. This company was formed when the phosphate operations of the Cargill Companies and IMC Global, Inc. were combined in October 2004, or shortly before the BAFOs were filed. The evaluators located in Tallahassee were individually given the responses submitted by CDM, Compass, and Shaw on Thursday, December 2, 2004. For those evaluators located outside of Tallahassee, the responses were given on Friday, December 3, 2004. Pursuant to a specific set of instructions provided by the Department, each evaluator, acting independently, then individually ranked the BAFO responses. In order to determine the responsiveness of the BAFOs, Ms. Godfrey used a checklist to review the individual submittals and found that all three were complete. Also, Dr. Fuleihan, who served as the subject matter expert, reviewed each proposal to ensure that the qualifications of the persons identified in the responses met the minimum qualifications listed in the Instructions. He determined that all three vendors met the minimum qualifications. Therefore, the Department considered all three vendors responsive to the Instructions and qualified to perform the work. (If an evaluator considered a particular item in the response to be incomplete or defective, the evaluator could reflect that by assigning a lower score to that response.) The BAFO Scoring Process For scoring purposes, each BAFO response was divided into approximately fifteen identified subcategories. A one-to- five scale (with five being the highest score) was used to evaluate each subcategory of the vendor’s response. The raw scores for a given subcategory would be multiplied by a weight factor that corresponded to that subcategory to arrive at a weighted score for each subcategory. To obtain a total score for each vendor, the weighted scores for each subcategory would then be added together. The total weighted scores could range between 0 and 220. Each vendor was then assigned a ranking based on its weighted total score. The vendor with the highest score received a rank of one, the second highest score received a rank of two, and the third highest score received a rank of three. If two or more vendors had identical weighted total scores the ranks were added together and divided by two. (For example, if Vendor A received a 175 and Vendors B and C each received a 170, the vendors would be ranked as follows: Vendor A - 1.0, Vendor B - 2.5, and Vendor C - 2.5.) After all the scores had been submitted, the ranks of each vendor were averaged to determine the best proposal for the State. Average ranks were used in order to normalize the evaluations so that an especially generous or especially hard grader would not skew the outcome. Each of the eight evaluators conducted an individual, objective, and impartial review of the three responses to the Instructions. They all spent four to five days, including a weekend, reviewing each of the responses. (There is some confusion regarding the actual amount of time that Mr. Zamani spent reviewing the BAFOs. Documents offered by Shaw reflect that he received the BAFOs on December 3 and returned his rankings the following day, December 4. Testimony offered by the Department reflects that he spent several days reviewing the filings. Even if Shaw's time frame is correct, there is no evidence that Mr. Zamani evaluated the BAFOs in an improper or arbitrary manner.) The evaluators did not have any discussions during the evaluation process about their evaluations. Outside one phone call from Mr. Brown to Mr. Coram to clarify what the vendors had received with the Instructions, the evaluators had no contact with one another. Mr. Alden ranked CDM first with a score of 177, Compass second with a score of 174, and Shaw third with a score of 172. Mr. Black ranked CDM first with a score of 140, Compass second with a score of 137 and Shaw third with a score of 106. Mr. Brown ranked CDM first with a score of 205, Compass second with a score of 183 and Shaw third with a score of 182. Mr. Coram ranked Compass first with a score of 180, Shaw second with a score of 175 and CDM third with a score of 170. Dr. Fuleihan ranked CDM first with a score of 192, while Compass and Shaw tied with scores of 189. Ms. Phillips originally submitted her evaluations with Compass ranked first with a score of 144, and Shaw and CDM tied with a score of 141. Due to an error when she transposed her scores from her notes to her score sheet, she corrected her evaluations at the hearing. With the corrected scores Compass was still ranked first with a score of 144, but CDM was now second with a score of 143, and Shaw third with a score of 139. However, this correction did not change the final results of the evaluation process. Mr. Wright ranked Shaw first with a score of 183, Compass second with a score of 181, and CDM third with a score of 166. Mr. Zamani ranked CDM first with a score of 218, Compass second with a score of 210, and Shaw third with a score of 191. After the evaluators submitted their score sheets, the ranks were added up and averaged to obtain a final ranking for each vendor. The final ranking was as follows: CDM was ranked first with an average rank of 1.688, Compass second with an average rank of 1.813, and Shaw third with an average rank of 2.500. (If Dr. Fuleihan's scores were removed from the final tabulation, as requested by Compass, then Compass would be the highest ranked vendor.) On December 7, 2004, the Department electronically posted a recommended award to CDM as the best- ranked vendor. As predetermined in the Instructions, the announcement also stated that negotiations would immediately begin with CDM, and if those negotiations failed, it would then negotiate with Compass, the second ranked vendor, and if those failed, with Shaw, who was ranked last. Compass and Shaw timely filed their Notices of Protest on December 9, 2004. On December 20, 2004, they timely filed their Formal Written Protests. Both Petitioners have contended that the process was flawed because Mosaic (a listed subcontractor on CDM's proposal) was a client of Ardaman; that Dr. Fuleihan had a conflict of interest which should have been disclosed; and he should have recused himself from the process. Shaw also contends (for the first time in its Proposed Recommended Order) that at least two of the evaluators (Mr. Black and Ms. Phillips) had little, if any, knowledge or experience concerning the scientific and technical requirements sought in the ITN and Instructions and were not qualified to evaluate the responses. It also alleged that a Sunshine Law violation may have occurred; that Mr. Zamani did not have a sufficient amount of time to evaluate the proposals;2 and that the proposals of CDM and Compass were non-responsive in various respects. The other contentions raised in Shaw's formal protest and the Pre-Hearing Stipulation have not been addressed in its Proposed Recommended Order and are deemed to have been abandoned. The remaining contentions are discussed below. Sunshine Law Violation There is no evidence that the evaluators met in closed meetings. Rather than scoring as a group, each of the evaluators scored the BAFOs separately and independently. Therefore, there was no meeting of the evaluators that was required to be conducted in the sunshine. No vendor attended the oral discussion meetings between another vendor and the evaluation team. However, there is no evidence that any of the vendors asked to attend those meetings or that the Department denied the vendors the ability to attend. Qualifications of the Evaluators There was no allegation in the Pre-Hearing Stipulation that any of the evaluators were unqualified. Although Shaw elicited testimony on that issue at hearing, especially regarding the qualifications of Mr. Black and Ms. Phillips, the issue was not timely raised. Even if it was, the evidence does not show that those two individuals, or any other member of the team, were not qualified. Mr. Black and Ms. Phillips were chosen for the team because of their extensive experience in state procurement, and not for their technical or scientific background. Mr. Black, who has been an attorney for thirty-two years, is an Assistant General Counsel and Section Chief for the Department of Revenue (DOR). In this position, he has handled numerous procurement cases for that agency. His duties include handling procurement matters, leasing matters and administrative functions for DOR. Prior to assuming his position at DOR, he worked for fourteen years for the Department of Management Services (DMS) as its primary attorney responsible for contracts dealing with environmental issues. Ms. Phillips is a Purchasing Analyst for DOR with over 28 years of procurement experience with the vast majority involving solicitation evaluations. Her responsibilities involve ensuring proper administration of complex contracts and specifications, Invitations to Bid (ITB), Requests for Proposals (RFP), ITNs, and advertisements. She develops guidelines and procedures to facilitate the ITB/RFP/ITN process and has evaluated procurement policies and procedures for DOR. Conflict of Interest Issue In its response to the ITN, CDM identified IMC Global, Inc., as a subcontractor for water treatment. After CDM's initial reply was submitted, IMC Global, Inc. and a subsidiary of Cargill merged to form a new company known as The Mosaic Company. To conform its BAFO with this corporate merger, CDM changed its response to reflect the new company as a subcontractor for water treatment and consumption. Because Ardaman had a contractual relationship with Mosaic at the time the BAFOs were submitted, Petitioners have contended that Dr. Fuleihan had a conflict of interest, that he should have disclosed this fact, and that he should have withdrawn from the ITN process. They also contend that the Department dismissed another non-employee evaluator, Richard Eckenrod, when it learned that he had a potential conflict of interest and that Dr. Fuleihan's circumstances are no different. When Mr. Coram suggested that Dr. Fuleihan participate as an evaluator, he knew that it would be likely that Ardaman would have contractual relationships with most or all of the phosphate companies over time. He expected Ardaman to continue to have such contractual relationships in the future simply because Ardaman does excellent work. However, he did not hesitate to recommend Dr. Fuleihan because he had worked with him on a daily basis for over the past three years and had known him for at least ten years. Mr. Coram testified that he always found Dr. Fuleihan's actions to be ethical and in the best interests of the State. Dr. Ardaman is a Senior Vice President of Ardaman, a member of its management team, and head of the firm's corporate engineering group. He receives a salary, bonus, and stock options; the bonus and stock options are tied to performance and profitability of Ardaman and its parent company, Tetra Tech, Inc. IMC, The Cargill Companies, and Mosaic have been clients of Ardaman. This is not surprising, however, because Ardaman's clients include "the whole phosphate industry." Indeed, Ardaman does approximately 90 to 95 percent of the engineering work performed in Florida involving phosphogypsum stack systems, a fact well known by virtually all of the players in the phosphate industry, including Petitioners. Over the last five years, Ardaman has represented such clients as Agrico Chemical Company, CF Industries, Inc., the United States Army Corps of Engineers, the Florida Department of Community Affairs, PCS Phosphate, Comanco Environmental Corporation, Moretrench Environmental Services, Inc., Shaw Environmental, Inc. (and its predecessor, IT Corporation), PENN PRO, Inc., and the Florida Department of Transportation. The Department itself is among Ardaman's most significant clients. When the ITN was first posted it was well known that Dr. Fuleihan knew all of the principals of CDM, Compass, and Shaw, including those who testified at the final hearing. In fact, Dr. Fuleihan has worked on numerous occasions with most, if not all, of the subcontractors and the consultants listed by all three vendors in their BAFOs. All three vendors also knew that Dr. Fuleihan had assisted with the ITN and BAFO processes and was serving as an evaluator for the BAFOs. Prior to the issuance of the Instructions, Dr. Fuleihan was present during the oral discussions along with the other evaluators. He also led the "negotiation sessions" where the Department was gathering information to develop the Instructions. Only after the Department proposed to award the contract to CDM on December 7, 2004, did Petitioners challenge Dr. Fuleihan's participation in the solicitation process and express a fear that the process might be tainted. Mosaic is considered an important client for Ardaman. However, there was no evidence that Ardaman would stand to gain anything from Mosaic by it serving as a subcontractor. Under the terms of the ITN, Ardaman will continue working for the Department at Piney Point as the engineer of record regardless of which vendor ultimately contracts with the Department. Ardaman did not receive any additional work from IMC Global, Inc., when it was conducting work at Piney Point in 2003, and Ardaman does not expect to receive any additional work if Mosaic returns to the site to assist with the operation of water treatment equipment. Although it is characterized as an important team member, Mosaic at most will have a limited role on CDM's team and would receive very little financial benefit from this work. Specifically, Mosaic will receive a nominal fee for allowing CDM to use the patents on its reverse osmosis equipment and roughly $50,000.00 for technical support in years three through five of the project, or a total of less than one-tenth of one percent of the estimated $52 million contract. (There is no guarantee that Mosaic will even be used by CDM since the vendor has the right to substitute subcontractors during the post-award negotiation process. In fact, CDM approached Mosaic because, at that time, Dr. Vaughn Astley worked for Mosaic, and CDM wanted his expertise and experience as part of CDM's team. Dr. Astley subsequently retired from Mosaic, as planned.) There is no evidence that, as a result of Mosaic being retained as a subcontractor for CDM, Ardaman or Dr. Fuleihan would be given extra business over and above what they already provide. There is also no evidence that as a result of CDM's being awarded the contract that Dr. Fuleihan would have his salary increased, obtain some sort of bonus, increase his stock options, or be enriched in any way. There is no evidence that Dr. Fuleihan attempted to influence the BAFO process to the advantage of any particular vendor. There is no evidence that he favored one vendor over another when he assisted in the preparation of the Instructions, determined whether the responses to the Instructions satisfied the minimum qualifications, and reviewed the BAFOs. To the contrary, the evidence supports a finding that Dr. Fuleihan scored and ranked the individual BAFOs in a fair and objective manner. Notwithstanding the lack of any evidence to show that Dr. Fuliehan exhibited bias or favoritism during the solicitation process, the facts surrounding the removal of Mr. Eckenrod are essentially the same as those of Dr. Fuleihan. In the case of Mr. Eckenrod, a non-employee, he alerted the Department that he feared that there might be an appearance of impropriety due to the fact that one of the individuals listed in CDM's proposal and his wife held positions on boards of the organization where he worked. Because the boards had the ability to hire or fire him, and determine the program's budget, Mr. Eckenrod was under the impression that this relationship might be perceived as potentially influencing his evaluation of the proposals. Given this impression, it was determined that a reasonable person might come to the same conclusion and therefore Mr. Eckenrod was excused from service. In the case of Dr. Fuleihan, also a non-employee, he had a professional relationship with a subcontractor (Mosaic), which relationship might reasonably give rise to an appearance of ethical impropriety in the event the contract was ultimately awarded to CDM. Therefore, even though there is no evidence that Dr. Fuleihan acted improperly in evaluating the proposals, a reasonable person might question his perceived impartiality. Under the precedent established in Mr. Eckenrod's case, DEP 202 and DEP 315 apply to Dr. Fuleihan's conduct, and he is obligated "to avoid any conduct . . . which might undermine the public trust . . . or give the appearance of ethical impropriety," and to not have a "contractual relationship with any business entity . . . doing business with" the Department. Given these standards, at a minimum, disclosure of this conflict was necessary as soon as the BAFOs were filed. By failing to make such a disclosure, the requirements in Section 287.057(20), Florida Statutes, the corresponding Instructions, and DEP 202 and 315 were contravened. The Department's contention that DEP 202 and DEP 315 do not apply to non-employees has been rejected, especially since the Department applied the same provisions to Mr. Eckenrod. During the course of discovery in this case (and after the solicitation process was over), Dr. Fuleihan learned that Ardaman does have one small contract (valued at $57,000) with CDM's parent company, Camp, Dresser & McKee (located in St. Louis, Missouri), that was entered into in April 2004. That contract calls for Ardaman to serve as a specialty consultant/ subcontractor to Monsanto Company (Monsanto) in providing waste disposal services for Monsanto's elemental phosphorus plant located in Idaho. When Dr. Fuleihan reviewed the BAFOs, he was unaware of this contract. He acknowledged, however, that had he known, he would have disclosed this fact to the Department. Even so, it is fair to infer that a reasonable search of Ardaman's records prior to the commencement of the process would have revealed this conflict, and the Department's Ethics Officer could have then made a determination as to whether Dr. Fuleihan could serve as a team member. Dr. Fuleihan signed two conflict of interest forms certifying that he had no conflict. He did not disclose any conflict with Mosaic because he did not believe that the form applied to subcontractors (as opposed to prime contractors), and because his firm's relationship with a potential subcontractor would not impede his ability to carry out his responsibilities in evaluating the proposals. (If Mosaic had been a prime contractor, Dr. Fuleihan acknowledged that he would have recused himself from the process.) Other Department witnesses (Godfrey and Coram) conceded, however, that the conflict of interest form applies to subcontractors as well as the prime contractor, and that if a conflict with a subcontractor arose, it should be disclosed to the Department. In summary, while there is no evidence that Ardaman's professional relationship with both a prime contractor and a subcontractor caused the evaluator to exhibit bias or favoritism towards any particular vendor, the relationships give rise to an appearance of ethical impropriety so that a reasonable person might question the impartiality of Dr. Fuleihan. By not having those relationships disclosed, the Department's governing statutes, policies, and Instructions were contravened. g. Were the CDM and Compass Proposals Responsive? Shaw also contends that there were "many areas" in which the proposals made by CDM and Compass did not materially comply with the Instructions, and that they should be considered non-responsive. Although Shaw's Formal Written Protest identified a wide range of purported deficiencies, only those items which are discussed in Shaw's Proposed Recommended Order are addressed here. Shaw first contends that even though the vendors were required by the Instructions to demonstrate the reliability of their chosen methods of water treatment, Compass elected to treat half of all water it would treat through an unproven technology that was not demonstrated to be reliable. Compass proposed a water treatment and consumption method consisting of double-liming and air stripping or aeration, followed by reverse osmosis. (Double-liming is a chemical treatment process involving the addition of lime to process water, while reverse osmosis is a physical treatment where process water is forced through a semi-permeable membrane at high pressure to separate the clean and contaminated water.) This was consistent with the Instructions, which specifically allowed a vendor to use double-lime, air-stripping, and reverse osmosis for water treatment. See Joint Exhibit 4, Attachment 3 at pages 20-21. There is no requirement in Attachment 3 that vendors use "proven technology" or demonstrate the reliability and viability of their proposed water treatment methods. There is no credible evidence in the record that the water treatment method proposed by Compass would not work. Shaw also alleged that Compass failed to adequately bid utility services, because on line A2 of its BAFO, Compass bid only $36,200.00 for all five years of electric utility services. In its proposal, Compass also included an assumed prevailing rate for power of $100,922.00 per month. Although only $36,200.00 is shown on line A2, Compass spread the rest of the utility costs (approximately $2.3 million) throughout the lines in Section B of Attachment 4. While this amount was lower than the other vendors, the Department believed that Compass' overall operation and maintenance expenses were reasonable, and if any mistake had been made by Compass by understating the power cost, it was to Compass' detriment and would not adversely affect the interests of the State. Shaw also argues that Compass submitted a drawing that included reinforced geotextile but omitted the cost for that item in that portion of its BAFO entitled "clarifications." (Geotextiles allow for drainage of fluids and provide a basis for bridging over soft, unstable materials). Compass indicated in the clarifications section of its BAFO that "reinforced geotextile would be (as needed). The cost for this reinforced geotextile is not included." Under the terms of the Instructions, there was no requirement that a vendor estimate quantities that are not listed on the Pricing Summary Sheet, so long as it submits a fixed price bid. Here, the Pricing Summary Sheet in the Instructions does not have a line for the "as needed" geotextiles, and Compass submitted a fixed price bid. Therefore, the omission of the cost for that item did not render the BAFO non-responsive. Finally, Shaw has alleged that in its BAFO, Compass limited its exposure for the cost of normal repairs and replacements of pumps and piping and was therefore non- responsive. This argument is based on the fact that Compass included $1.1 million in its cost estimate for normal repairs and replacement of pumps and piping. Shaw asserts, however, that because the plant is very old, the contractor will have to take responsibility for failing equipment in order to keep the plant running, and Compass has essentially capped its replacement costs for transformers, switch gears, and other necessary equipment. Shaw did not present evidence that Compass had actually capped its pump maintenance costs or that the amount shown was inadequate. In fact, Shaw's estimated pump maintenance was between $660,000.00 and $900,000.00, or less than the amount proposed by Compass. Even if the amount shown was underestimated, the Department has made it clear that it wanted a lump sum contract and would hold the vendors to the price stated in the BAFOs. (Like the other vendors, Compass submitted a fixed price bid.) Shaw next contends that CDM's proposal was non- responsive in the areas of spray evaporation, the closure construction schedule, water balance, and spray irrigation. These items will be discussed separately below. Shaw first asserts that CDM overestimated the amount of process water it can treat with spray equipment during the first two years of the contract since the spray equipment CDM proposes to use will not be available until the fifth month of the first year of the contract. During the first two years of the contract, CDM proposes to dispose of 175 million gallons of process water through spray evaporation, which involves spraying water into the air to form a mist of small droplets and enhancing the natural evaporation through various techniques. In doing so, CDM intends to use a new spray system developed by CF Industries, which has achieved a rate of 200 million gallons per year, or twice as much as the amount CDM proposes over a two year period. Therefore, even if the equipment can only be used for twenty months during the first two years, it is reasonable to assume that CDM can evaporate 175 million gallons of process water during the first two years, as projected in its BAFO. Shaw also points out that the Instructions require each vendor to supply a closure schedule including eight "milestones" that must be completed within certain time frames. The eighth milestone is the closure and placement of grass on all lined reservoir slopes at least one year prior to the end of the contract. See Joint Exhibit 4, Attachment 3, page 4, § IV. While it concedes that CDM included a closure schedule for the site, Shaw asserts that CDM failed to indicate when, if ever, it would place grass-protected soil cover on all lined reservoir slopes. While the Department acknowledged that CDM's BAFO was not as detailed as those of the other two vendors, it points out there is "a lot of flexibility in the BAFO," and that "the covers were not critical for the closure schedule." Because CDM clearly intends to place the soil cover on the lined areas in conformance with the closure schedule, the omission was not material and does not render the BAFO non-responsive. Shaw next contends that even though the Instructions require that a vendor prepare an independent water balance, it is not apparent in the BAFO whether CDM prepared one. See Joint Exhibit 4, page 14, § B. (A water balance is a professional estimate of the volume of water on site, coupled with a projection of how it will fluctuate over time considering rainfall and groundwater inputs, surface and spray system evaporation, groundwater seepage, and other factors.) The Instructions required that CDM independently estimate the water balance for the five-year contract period. Nothing in the Instructions, though, requires that the actual calculation or spreadsheets that support the estimated water balance be shown. With the assistance of its consultants, CDM estimated the total quantity of process water as slightly in excess of one billion gallons, which it rounded off to one billion. This amount was responsive to the Instructions and was similar to the amounts estimated by Shaw and Compass. Accordingly, the estimate by CDM was responsive to the Instructions. Finally, Shaw argues that while "CDM also mentioned the use of spray irrigation," CDM "did not estimate any volume of water to be treated with this method." The contention has been considered and found to be without merit. In summary, the BAFOs submitted by CDM and Compass conformed in all material respects to the solicitation. To the extent that there were any minor deviations, they did not give Compass or CDM an advantage or benefit not enjoyed by Shaw, and under Section 1.19 of the Instructions they could be waived by the Department.
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 determining that its proposed award of the contract to CDM Constructors, Inc., which was based upon a review, grading, and ranking of the vendors by an evaluation team that included Dr. Fuleihan, is contrary to its governing statutes, policies, and specifications. DONE AND ENTERED this 21st day of March, 2005, in Tallahassee, Leon County, Florida. S DONALD R. ALEXANDER Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 21st day of March, 2005.
The Issue The issue to be resolved in this proceeding concerns whether the Governor and Cabinet, sitting as the Siting Board, should issue certification to Gulf Power Company (Gulf or Gulf Power) to construct and operate a 574 megawatts (MW) combined cycle electrical generating unit to be located at Gulf's existing Lansing Smith Plant in Bay County, Florida, in accordance with the provisions of Section 403.501, et seq., Florida Statutes.
Findings Of Fact Gulf Power is an investor-owned electric utility that supplies electric service in northwest Florida. Gulf currently serves approximately 350,000 customers in its service area, which extends westward from the Apalachicola River to the western border of Florida. Gulf Power has been supplying electricity within this area since 1926. Gulf is a subsidiary of the Southern Company. Gulf Power currently operates power plants at three locations in the Florida Panhandle, with a combined generating capacity of 2,284 MW. Gulf Power's Lansing Smith power plant (Smith Plant) is located in the central portion of Bay County, Florida, approximately 2.5 miles west of the unincorporated community of Southport, Florida, and 2.5 miles northwest of the City of Lynn Haven, Florida. The City of Panama City lies due south, across the open waters of North Bay. The Smith Plant is in the unincorporated area of the County. Access is via County Road 2300 which connects to State Road 77. Within the approximate 1,384 acres, which comprise, the Smith Plant, are two existing coal-fired electrical generating units along with their supporting facilities, including a coal unloading and storage facility, wastewater treatment and disposal facilities, intake and discharge canals which handle cooling water, and electrical substations and transmission lines. Smith Unit 1 has a generating capacity of 162 MW and Smith Unit 2 has 192 MW of generating capacity. The two existing units have been in operation since 1965 and 1967 respectively. An existing 31.6 MW oil-fired simple cycle combustion turbine is also located at Smith Plant. The balance of Smith Plant is largely undeveloped, and is comprised mainly of planted pines, forested areas and wetlands. Immediately adjacent off-site lands are used for silviculture (planted pines) or are otherwise undeveloped. The nearest residence is more than two miles away, located to the northeast of Smith Plant. Project Description The proposed Smith Unit 3 consists of a natural gas- fired combined cycle plant capable of generating up to 574 MW of electricity. The new unit will more than double the generating capacity at Smith Plant. Smith Unit 3 will be located upon a 50.1-acre site (Project site) within the existing boundaries of Smith Plant. Smith Unit 3 will utilize state-of-the-art combined cycle design concepts and equipment to achieve a high level of efficiency in electrical power production. The Project will employ two General Electric combustion turbine units which have a proven operating record around the world. Each combustion turbine will generate approximately 170 MW of electricity. The hot exhaust gases from the two combustion turbines will be captured in two heat recovery steam generators (HRSGs) which will produce additional steam-generated electricity of 200 MW. Hot exhaust gases from the combustion turbine/HRSGs will then be vented to the atmosphere by the main stack. In addition, the HRSGs will contain duct burners which will fire additional fuel in the boilers, adding additional generating capacity to the HRSG portion of the Project. Smith Unit 3 will also employ power augmentation in which a portion of the steam in the HRSGs is routed back to the combustion turbine to increase the mass flow through the combustion turbine, increasing its ability to generate electricity. After the energy is removed from the steam in the steam turbine, the steam is condensed back into water in the condenser. Cooling for the Project will feature a creative and environmentally sound combination, utilizing the existing cooling water discharge from Smith Units 1 and 2 within a new cooling tower for Smith Unit 3. This means the Project will actually use hot water from the existing cooling system for Units 1 and 2 and then discharge cooler water from Unit 3 back into the existing discharge canal. Smith Unit 3 will use the existing Smith Plant access road, also the existing electrical switch yard will provide the interconnection for Smith Unit 3, and electrical power from the Project will be transmitted via the existing transmission lines to existing off-site electrical substations. Three of these existing electrical transmission lines, which run south and east into the Panama City area, will be reconductored. Reconductoring involves replacement of the existing conductors or wires with higher capacity conductors. This reconductoring is necessary to maintain the reliability of the Gulf Power transmission system. The reconductoring will involve removal of the existing wires, installation of new wires, and possible repair and maintenance of the existing structures. However, no new electrical transmission structures will be required as part of the reconductoring. No other expansions or other alterations to the Gulf Power transmission system are required as part of this project. A new 28 mile gas pipeline will be constructed to provide natural gas fuel for Smith Unit 3. This gas pipeline lateral will connect to an existing Florida Gas Transmission pipeline running through Washington County. The new gas lateral to serve the Project will be permitted, constructed, owned and operated solely by Florida Gas Transmission Company. The new lateral will interconnect with the existing gas pipeline and then follow a southerly route paralleling State Road 77 and an existing Gulf Power transmission right-of-way before entering the Smith Plant. A new gas metering station will be constructed within the Project site. Existing groundwater wells at the Smith Plant site will supply the groundwater needs for Smith Unit 3, as well as continue to supply the existing units. New facilities to be constructed within the approximate 50-acre Project site will include the two combustion turbines, the two HRSGs, steam turbines, three electrical generators, a cooling tower, an administration building, and other ancillary facilities. A new electrical switchyard will also be built within the Project site, which will then be interconnected to the existing main electrical switchyard at the Smith Plant. Need for Smith Unit 3 The Florida Public Service Commission (Commission) issued an affirmative need determination for Smith Unit 3 on August 2, 1999. The Commission concluded that Smith Unit 3 was necessary to ensure the future reliability and integrity of Gulf Power’s electrical system. The Commission found that there existed a generation/load imbalance in the Panama City area due to growth and electrical demand on Gulf Power’s existing system. In finding that no cost-effective energy conservation measures existed that could offset the need for electricity from the Gulf Power Smith Unit 3, the Commission concluded that Smith Unit 3 is necessary to provide adequate electricity at a reasonable cost to Gulf Power’s customers, as contemplated under Section 403.519, Florida Statutes. The Commission, therefore, found that the Project is the "most cost effective alternative available to Gulf to meet its needs for adequate electricity at a reasonable price." Gulf Power needs to add new generating capacity by the year 2002 to maintain an appropriate level of generating reserves on its system. Gulf Power has been able to obtain short-term purchases of electricity that meet its capacity needs until 2002. In evaluating its need for additional power, Gulf Power evaluated both a self-build option and conducted a request for proposal (RFP) process to consider outside offers to supply electricity. In the RFP process, Gulf Power evaluated nine different offers from outside interests, which were compared to the Gulf Power Smith Unit 3 option. After evaluating all of the options and their associated costs, Gulf Power concluded that Smith Unit 3 was clearly the most cost-effective choice. Project Schedule and Construction Construction of Smith Unit 3 is scheduled to begin in August 2000, or as soon as the final approvals are obtained. In addition to the site certification, Gulf Power is required to obtain a Prevention of Significant Deterioration (PSD) permit, a modified National Pollutant Discharge Elimination (NPDES) Permit issued by FDEP, and a dredge and fill permit from the U.S. Army Corps of Engineers. The new unit is projected to be in service in June 2002. Construction will require approximately 250 employees, with a peak of 325 employees. Construction activities will involve clearing of a portion of the Project site, removal of muck and placement of backfill, setting of pilings and foundations, followed by assembly of equipment. Installation of boilers and metal buildings will then follow, with the gas turbines and steam turbines being put into place last. These construction activities will require approximately 32.7 acres of the approximate 50-acre Project site. This includes the power block, construction laydown area, ancillary facilities, and stormwater ponds. The remainder of the Project site will remain principally as planted pine. During construction, heavy equipment will be delivered by barge, while small and medium sized items will be delivered by truck over County Road 2300. Road wetting and project maintenance will be used to control dust during construction. The site is relatively flat and is not expected to create any significant runoff during Project construction. Erosion during construction will be managed with an erosion control plan. This will include planting of exposed areas, collection of runoff and use of detention ponds to collect sediments in runoff. Project construction will have little impact on open waters. The only construction activity in open waters will be the placement of the cooling tower intake and discharge pipes within the existing Smith Plant cooling water discharge housing. This will cause minor turbidity during construction with approved construction techniques taken to minimize these impacts with no long term effect. Surface Water Management System The existing Project site is currently undeveloped although the upland areas have been modified by silviculture practices. The site currently drains to existing natural wetland systems. During construction, a portion of the Project site will be filled and graded to provide a finished surface for various Project components. Stormwater basins will also be installed during construction and grading will provide drainage for building and working areas through gravity flow. Runoff will be conveyed to two on-site wet detention stormwater ponds to be located within the east and west portions of the Project site. These stormwater ponds will ultimately discharge to adjacent wetland systems, following natural drainage patterns. The stormwater management system, including the stormwater ponds, will be constructed to comply with the requirements of local, state and federal regulations. Project Water Use The major water uses during operation of Smith Unit 3 will involve cooling tower blowdown and cooling tower evaporation, representing approximately 7.4 million gallons per day (mgd). The cooling water system has the greatest water need of all of the systems for the Project. Other water uses will involve blowdown from the HRSGs to maintain water quality in that system, and water losses due to gas turbine evaporative cooling and wash water. The Smith Unit 3 cooling system will utilize a closed- loop cooling circuit. This circulates cooled water from the mechanical draft cooling tower to the Unit 3 heat exchangers. Heated water resulting from the steam cycle of the plant is returned to the cooling tower where it is cooled by an evaporative cooling process. During this process, a certain amount of water is lost through evaporation and drift. In addition, it is necessary to "blow down" or remove a portion of the water from the cooling tower periodically to control suspended and dissolved solids in the cooling water. Without this blowdown, sedimentation and deposits in the tower will reduce the heat transfer there and damage the cooling equipment. The water loss in the cooling tower must be replaced with water from an outside source. The source of cooling water makeup for the Smith Unit 3 cooling tower will be from the existing thermal discharge flow from Smith Plant. The existing Units 1 and 2 use a once-through cooling system in which water withdrawn from North Bay passes directly through a condenser and discharges into the existing discharge canal. The makeup water from Smith Unit 3 will be taken from this hot water exiting Smith Plant Units 1 and 2. The cooling tower blowdown from Smith Unit 3 will be discharged back into the discharge canal from the cool water side of its cooling tower. As a result, the Project will actually act to reduce the amount of heat currently discharged from Smith Plant into the cooling water discharge canal and then into West Bay. The calculated quantity of water needed for cooling tower makeup is 7.4 mgd. This represents approximately 2.5 percent of the current daily water flow through Smith Plant Units 1 and 2. On a daily basis, approximately 3.7 mgd will be discharged back into the cooling water discharge canal as blowdown from the Unit 3 cooling tower. The other 3.7 mgd will be lost through evaporation in the cooling tower. Smith Unit 3 process water needs include water used to cool and wash the gas turbines and other facilities, to make up HRSG blowdown, and to satisfy other water uses. These process water needs will be supplied from groundwater taken from the existing Smith Plant well system. The raw water will be treated in both a filtered water production system and a demineralized water system. This water will then be used for the various processes identified. During hot months of the year, evaporative coolers will be provided for the combustion turbines, providing denser intake air for combustion and improving the electrical output of the combustion turbines. In addition, the gas turbines must be washed periodically, both during plant operation and when the unit is offline. During operation, wash water is lost through evaporation in the combustion turbine exhaust. When Smith Unit 3 is offline, wastewater from this process is collected in an on- site tank and trucked off-site for appropriate disposal. During the power augmentation mode of operation, steam is introduced into the combustion turbine, again to increase mass flow through the combustion turbine. This steam is produced in the HRSG, using high quality demineralized water. These water treatment and water uses in Smith Unit 3 will generate various process wastewaters. Wastewaters resulting from process water treatment will be routed to an existing Smith Plant on-site collection sump. HRSG blowdown will also be routed to this on-site sump. The process wastewaters then will be routed to an existing Smith Plant on-site ash pond, which has adequate, permitted capacity to accommodate these additional wastewater flows. There will be no direct discharge of these Project-related process waters to area surface waters of the State. Impacts to Groundwater In September 1998, a site investigation was undertaken to sample and characterize the subsurface system at Smith Plant. The groundwater regime and its subsurface system underlying Smith Plant consists of a surficial aquifer system, overlying an intermediate aquifer system that in turn overlays the Floridan aquifer which is found throughout this area. The existing Project site lies at an elevation of approximately 7 to 8 feet above mean sea level. Subsurface sediments in the area are primarily marine and estuarine and represent ancient coastal environments or marine terraces. After these marine terraces were deposited, they were mixed with underlying sediments, consisting of a permeable sand, clay, silt and shell mixture. The underlying intermediate aquifer system consists of sandy clay and is approximately 80 feet thick. The Floridan aquifer is found at a depth of approximately 100 feet below land surface, typically consists of limestone with macrofossils, and is approximately 300 feet thick in the area of the Project site. Impacts to groundwater from the Project would occur principally from the withdrawal of groundwater for Smith Unit 3 use and from dewatering activities, if necessary, during construction. The existing Smith Plant is presently served by four groundwater wells that are permitted under a Consumptive Use Permit issued in September 1999 by the Northwest Florida Water Management District. That permit authorizes a maximum groundwater use of 1.2 million gallons per day (mgd) for the entire Smith Plant, which would include Units 1 and 2, as well as the proposed Smith Unit 3. These wells are sufficient to satisfy the groundwater withdrawal needs for Smith Unit 3, which amounts to an average of 209,000 gallons per day (gpd). By comparison, the existing Units 1 and 2 average a combined groundwater withdrawal rate of 647,000 gpd. During the recent renewal of the Consumptive Use Permit, Gulf Power conducted groundwater modeling to determine if any significant impacts to water resources or water users would occur as a result of the projected water use increase due to Smith Unit 3 operations. That modeling indicated that no adverse or irreversible impacts will occur to the Floridan aquifer system, or to its users in the vicinity of the Smith Plant site. The use of groundwater for process water is a reasonable and beneficial use of that resource. In addition, Gulf Power evaluated other potential sources of water. The factors of reliability and distance to the source were the primary factors considered by Gulf Power in the selection of groundwater use for Smith Unit 3. The Northwest Florida Water Management District agreed with this conclusion and issued the renewed Consumptive Use Permit for Smith Plant, including the proposed addition of Smith Unit 3. In fact, groundwater use for Smith Unit 3 represents less than 3 percent of the total 7.6 mgd Project water need. Project construction may require dewatering during construction activities, including placement of pilings at the Project site. If dewatering occurs, any impact will be very localized, and limited to a small area immediately adjacent to the dewatering activities. Dewatering effluent would be routed to the drainage system and then to the new detention basins. This effluent will then be allowed to infiltrate back into the surficial aquifer, and thereby offset the dewatering volumes. Wastewaters from Smith Unit 3 will be routed to the existing ash pond at Smith Plant. That ash pond operates under an existing NPDES permit and discharges infrequently, during extreme rainfall events, to a ditch which connects to the existing discharge canal only during extreme rainfall events. Any such pond discharge is sampled and reported to the Department. Any wastewaters that do not evaporate instead percolate into the underlying groundwater. The pond is subject to an FDEP-approved groundwater monitoring program, which has been in operation since the early 1980s. Seven compliance monitor wells are periodically sampled and analyzed for 21 separate parameters to ensure compliance with applicable state groundwater quality standards. This ash pond operates in compliance with the approved requirements of the groundwater monitoring plan and monitoring data indicate that Smith Plant has been and continues to be in compliance with all applicable Florida groundwater standards and criteria. Impacts to Surface Water Gulf’s Smith Plant is located on the northern end of a peninsula between the North and West Bays of St. Andrews Bay in Panama City, Florida. Thus, surface water runoff at this location generally flows from the northeast to the southwest and discharges to the existing cooling water canal. Four adjacent existing Smith Plant Units 1 and 2 intake water from Alligator Bayou, which is connected to North Bay, and the discharge canal Andrews Bay. Alligator Bayou is a Class III marine water, while waterbodies. The Class III designation is primarily to protect recreation and maintain a healthy propagation in population of waterbody standards provide additional protections for shellfish propagation and harvesting Operation of the cooling system for the existing generating units at Smith Plant may have impacts on area surface entrainment and impingement from cooling water intake structures and thermal stresses from cooling water Entrainment is an impact to organisms that are entrapped in the cooling water and drawn through plant water crabs, which may be trapped on water intake screens. Thermal impacts are heat-related stresses that result if excess Warren Bayou. These potential impacts have been studied extensively at the Smith Plant for the past 25 years. Studies in 1977 concluded that impacts of the cooling water intake system were acceptable and that Smith Plant was using the best available technology for that system. The thermal plume in West Bay from the existing units was also studied over the past 25 years. These studies delineated the extent of the thermal plume from Smith Plant in the open waters, and included specific sampling of biological communities to determine any adverse thermal plume impact. These studies were used to set the present thermal discharge limits for Smith Plant, and further demonstrated there would be no unacceptable impacts from its operation. Recent ongoing studies, including findings and conclusions contained in a 1998 report, confirmed that there are minimal thermal impacts in West Bay from the existing Smith Plant’s cooling water discharge. As discussed above, cooling water for Smith Unit 3 will be taken from the warm water discharge from the existing two Smith Plant units; cooling water blowdown will be discharged from the cool side of the new cooling tower. Thus, the temperature of the Smith Unit 3 discharge will actually be less than the temperature of the water withdrawn from the cooling canal. Further, since half the water withdrawn for Smith Unit 3 will be lost through evaporation in the cooling tower, approximately one- half of the heat that is removed from the existing canal will not be returned to the canal. Thus, there will be a slight reduction in the total heat contribution to area surface waters from Smith Plant as it presently exists. This will reduce the overall heat rejection from the Smith Plant by 1.4 percent. The existing thermal plume will therefore be reduced slightly and the water temperature in the discharge canal will not increase over existing conditions as a result of the addition of Smith Unit 3. This will not cause any exceedance in the existing permitted thermal limits for Smith Plant. Since Smith Unit 3 will withdraw cooling water from the existing discharge canal, there will be no change in entrainment or impingement impacts from the once-through cooling system because no additional water will be withdrawn from North Bay for this Project. The Smith Unit 3 cooling tower will operate under two cycles, meaning that one-half the water withdrawn will be evaporated in the cooling tower. The remaining constituents within the water in the cooling tower will be concentrated two- fold prior to discharge as blowdown, due solely to water being evaporated. However, this blowdown of approximately 2,600 gallons per minute will be immediately mixed in the discharge canal with the 185,000 gallons per minute of water discharged from Smith Plant Units 1 and 2. Therefore, the discharge from the Smith Unit 3 cooling tower will be diluted at a ratio of 71:1. Constituent concentrations within the discharge from Smith Plant will only increase approximately 1.4 percent over existing values. The existing discharge is in compliance with both Class II and Class III water quality standards, and it is not anticipated that the slight increase in concentrations due to the Project will cause any violations of applicable FDEP water quality standards. Two constituents will be added to the cooling water to facilitate its use in the cooling tower. Biofouling or the growth of unwanted organisms, such as algae and bacteria, within the cooling tower will be treated with chlorination. However, the discharge valve will be closed during this process and the chlorine will be allowed to dissipate prior to any release. Chemicals will also be added to the cooling tower water to prevent scaling. These chemicals will be nontoxic in nature when discharged and will be approved for use by FDEP under the existing NPDES permit. The Project also will have no measurable effect on adjacent aquatic communities from atmospheric deposition of air emissions from Smith Unit 3. The two primary emissions of concern are nitrogen oxides, which could reach the surrounding water as nitrogen and stimulate growth of algae, and sulfur dioxide, which could contribute to acid rain. With the addition of Smith Unit 3, there will be no increase in nitrogen oxide emissions over existing conditions and, therefore, no additional impact from nitrogen deposition in area waters. Further, sulfur constitute 1/1000th of the current Smith Plant sulfur dioxide emission levels. Therefore, sulfur dioxide emissions from the its aquatic community. Wetlands, Impacts and Mitigation Plan wetlands. These wetlands are composed of 15.4 acres of wet pine plantation, 10.2 acres of cypress- and 0.4 acres of ditch habitats. The remaining upland areas are mostly planted pines. Construction of Smith Unit 3 will impact Gulf Power has prepared a Mitigation Plan (Plan) to provide compensation for the loss of these wetlands. This Plan within a larger neighboring 232 acre parcel of land. This parcel is located approximately one mile north of the Project site. The The Plan will involve removing the existing planted pines and replanting native hardwood and cypress trees. The trees will be trees per acre. Tree species to be planted include Bald Cypress, Red Maple, naturally in hardwood and cypress swamps in the vicinity. The Plan is based upon a ratio of 12 wetland acres of enhancements for each acre impacted of the 6.4 acres of cypress-titi swamp and a 6:1 ratio of wetland enhancement to wetland loss for impacts to the wet pine plantation on the Project site. Thus, the overall mitigation ratio represents an average of 9:1 enhancement, which means for every acre of wetland impact at the Project site, there will be 9 acres of high quality wetlands produced in the mitigation/enhancement area. This Plan is more than adequate to compensate for the wetland impacts on the Project site. The Plan also provides that after planting of the wetland tree species, there will be an ongoing monitoring and maintenance program to determine the overall success of the wetland mitigation efforts. Survival of planted trees and hydrological data will be collected for up to five years, or until the goals of the Plan are otherwise achieved. The mitigation parcel will also be placed under a Conservation Easement, which will preserve the property in perpetuity. Plant and wildlife species surveys of the Project site identified the presence of four protected plant species. Two of these are relatively common ferns, which are protected from commercial exploitation. One threatened species, Chapman’s Crownbeard, is found in a transmission corridor that will not be disturbed by Project construction. The fourth plant, the Panhandle Spiderlily, is a rare species in the region and is considered endangered. Gulf Power will relocate these plants out of the construction area to nearby wetlands that will not be disturbed by construction. No listed animal wildlife species were found on the Project site, although the Bald Eagle and Brown the Project will not impact either of these two species of birds. Air Quality The Prevention of Significant Deterioration (PSD) air construction permit program applies to new major facilities and attaining the federal and state ambient air quality standards. When a new electrical generating unit is added at an existing the addition of the unit results in a significant net emissions increase above recent past actual emission levels for certain Neither Bay County nor any area in Florida is currently designated as " Protection Agency (EPA) or FDEP for any federal or Florida ambient air quality standard. facility for PSD applicability purposes. Smith Unit 3 will add two new combustion turbines and two new duct burners, which will pollutants: carbon monoxide (CO), nitrogen oxides (NOX), particulate matter (PM), particulate matter of ten microns or less (PM10), sulfur dioxide (SO2), sulfuric acid mist, and volatile organic compounds (VOCs), and will also add one new cooling tower, which will have the potential to emit PM/PM10 The recent actual NOX emissions from Smith Plant’s existing Units 1 and 2 were 6,666 tons per year. As part of this Project, a facility-wide cap on NOX emissions will apply to existing Units 1 and 2, Smith Unit 3, and the existing gas turbine to ensure that the addition of Unit 3 will not result in an increase above these recent actual annual NOX emissions. PSD review was therefore not required for NOX emissions from the Project. Because there were no creditable contemporaneous increases or decreases (within the last five years) in any pollutant emissions other than for NOX, the future potential emissions from Smith Unit 3 were compared to the PSD applicability thresholds for all emissions except NOX. Based on these thresholds and conservative estimates of the future potential emissions from the new Smith Unit 3 combustion turbines, duct burners, and cooling tower, PSD review was required for CO, PM/PM10, SO2, sulfuric acid mist, and VOCs. Operation in the steam power augmentation mode is limited to 1,000 hours per year of operation. For those pollutants triggering PSD review, the PSD program requires a demonstration that the Project’s emissions will not cause or contribute to any violation of state or federal further requires an analysis for these pollutants to demonstrate as well as impacts induced by residential, commercial, and that Best Available Control Technology (BACT) be applied to Emission Impacts contribute to a violation of federal or state ambient air quality classified as a Class II area for PSD. The nearest Class I area Bradwell Bay National Wilderness Area, An air quality analysis, undertaken in accordance with Smith Unit 3 would not cause or contribute to an state and federal ambient air quality standards for CO, PM , or 2 10 2 Smith Unit 3 is also not expected to cause an increase not increase and VOC emissions will increase only negligibly. In new combustion turbines and duct burners. The projected impacts of the sulfuric acid mist emissions from Smith Unit 3 combustion turbines and duct burners were compared to the draft Florida Ambient Reference Concentrations (FARCs). The modeling analysis demonstrated that projected impacts of sulfuric acid mist from Smith Unit 3 will be well below the corresponding draft FARCs and will not impose a health risk. Further, the Project's air emissions are not expected to cause any adverse impacts on visibility and vegetation in the Smith Plant vicinity or in the Bradwell Bay National Wilderness Area, the nearest PSD Class I area. Only temporary and very small residential and no significant industrial or commercial growth is expected from the construction phase of Smith Unit 3. Any resulting air emissions will be very small, well-distributed, and have no measurable impact on ambient air quality. The operation of Smith Unit 3 will not cause odor impacts and will have no significant effect on acid rain because NOX emissions are not being increased and sulfur dioxide emissions are being increased by only a small amount. Consequently, taking into account all of the above factors and considerations, no significant air emission impacts are expected to result from the construction and operation of Smith Unit 3. BACT and Emission Rates A BACT analysis determines the most stringent, allowable emissions rule for each emissions unit and pollutant subject to PSD review on a case-by-case basis, considering available and technically feasible control technologies, methods, systems, and technologies, as well as economic, energy, and environmental impacts and other costs. A BACT review for the Smith Unit 3 combustion turbines and duct burners was required for CO, PM and PM10, SO2, sulfuric acid mist, and VOCs. For the new cooling tower, BACT was required for PM and PM10 emissions. For the Project’s combustion turbines and duct burners, FDEP determined that BACT for PM and PM10 emissions is the fuel quality of natural gas, good combustion practices and a ten percent opacity limitation. For the new cooling tower, BACT was established by FDEP for PM and PM10 emissions to be the use of high-efficiency drift eliminators. For the Smith Unit 3 combustion turbines and duct burners, FDEP’s BACT determination for CO and VOC emissions consists of good combustion practices. The cost per ton of controlling CO emissions through the use of an add-on emission control device known as an oxidation catalyst was found to be excessive. Further, in FDEP’s BACT analysis, the use of an oxidation catalyst would provide no air quality benefits or serve an environmental purpose. BACT for CO and VOCs was, therefore, determined by FDEP to be good operating practices. For the Project’s combustion turbines and duct burners, BACT for SO2 and sulfuric acid mist was determined by FDEP to be the use of low-sulfur natural gas. For the Smith Unit 3 combustion turbines and duct burners, BACT for NOX emissions was not required since Gulf Power will use dry low-NOX burners on Unit 3 to control NOX emissions, and short-term NOX emissions limits will apply on a 30-day rolling average basis. A separate NOX limit of 0.1 pounds per million British thermal units applies to the duct burners, which is more stringent than the applicable federal New Source Performance Standard (NSPS) limit. Furthermore, Smith Unit 3 combustion turbines and duct burners will have emission limits well below the applicable NSPS requirements, and no NSPS requirements apply to cooling towers. No National Emissions Standards for Hazardous Air Pollutants (NESHAPs) apply to Smith Unit 3, and a case-by-case determination of Maximum Achievable Control Technology (MACT) for hazardous air pollutants was not required. Compliance The Smith Plant air emission units and activities, both new and existing, will comply with all applicable federal, state, and local air quality standards, including the conditions conditions of certification for Smith Unit 3. for NOX as well as the unit-specific emission limiting standards certification and the proposed PSD permit. Compliance with the emissions monitoring and fuel use data for existing Smith Plant emission factors for the existing gas turbine. 70. The adjacent land use to Smith Plant is The Bay County Land Use Code defines the maximum noise level for dBA). The Code dBA during dBA at night. of Smith Unit 3 will be 63 lower than the applicable noise standard for the adjacent where noise levels from construction would not be excessive. steam and air blowing, which should occur infrequently during the will notify the nearby residents prior to commencement of the 72. During normal operation of Smith Plant following the 3, the highest predicted continuous dBA at the property adjacent property. Thus, the operation of Smith Plant will Socioeconomic Impacts and Benefits beneficial economic and social effects. The main regional reliable energy source. Also, during construction, employment with a peak of 325 workers for approximately six months. $23.7 million. It is expected that most of the construction subcontractors and vendors will be used to provide labor and include concrete, lumber, and other construction materials. construction costs will result in indirect benefits to the local 74. The operation of Smith Unit 3 will result in employment day schedule. It is expected that these new employees will be million. These new employees are expected to pay taxes and the local economy. Using accepted economic multipliers, the over $1.8 million. Gulf Power also expects to make annual equipment related to Smith Unit 3 operations. short term traffic impacts due to construction. These impacts traffic flow should conditions warrant. Residential areas are from the site and screening by existing forested vegetation. 76. Impacts from Smith Unit 3 operations are expected to be recreational areas, parks or scenic aesthetic quality of the vicinity will be negligible. Smith Unit services or facilities. The Smith Plant is equipped with its own guards. The number of new employees are not expected to roadways. Project site from agricultural to industrial uses is appropriate 600-acre portion of Smith Plant site used for electrical an economic loss as a result of Smith Unit 3 construction. County Comprehensive Plan, the State Comprehensive Plan, and the Planning Council. The FDEP, the Florida Department of Community Affairs, Wildlife Conservation Commission, the Northwest Florida Water Council each prepared written reports on the Project. Each of otherwise, did not object to certification of the proposed power for the Project, incorporating the recommendations of the various and comply with these Conditions of Certification in the construction and operation of Smith Unit 3. In its report, the Florida Department of Community Affairs determined that, if certified, the Project would be consistent with the State Comprehensive Plan, as contained in Chapter 187, Florida Statutes. The West Florida Regional Planning Council stated in its agency report that the Project would not conflict with the strategic Regional Policy Plan for West Florida. No state, regional, or local agency has recommended denial of certification of the Project or has otherwise objected to certification of the Project.
Conclusions For Gulf Power Company: Douglas S. Roberts, Esquire William D. Preston, Esquire Angela R. Morrison, Esquire Hopping Green Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314 For Florida Department of Environmental Protection: Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building Mail Station 35 3900 Commonwealth Boulevard. Tallahassee, Florida 32399
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Siting Board grant full and final certification to Gulf Power Company, under Section 403, Part II, Florida Statutes, for the location, construction, and operation of Smith Unit 3, representing a 575 MW combined cycle unit, as described in the Site Certification Application and the evidence presented at the certification hearing, and subject to the Conditions of Certification contained in FDEP Exhibit 4. DONE AND ENTERED this 19th day of June, 2000, in Tallahassee, Leon County, Florida. P. MICHAEL RUFF Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-68847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 19th day June, 2000 COPIES FURNISHED: Douglas S. Roberts, Esquire William D. Preston, Esquire Hoping, Green, Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314-6526 Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000 James V. Antista, Esquire Fish and Wildlife Conservation Commission 620 Meridian Street Tallahassee, Florida 32399-1600 Andrew S. Grayson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Sheauching Yu, Esquire Department of Transportation Mail Station 35 Haydon Burns Building 605 Suwannee Street Tallahassee, Florida 32399-0450 Robert V. Elias, Esquire Florida Public Service Commission Gerald Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Daniel F. Kurmel, Executive Director West Florida Regional Planning Council Post Office Box 486 Pensacola, Florida 32593-0486 Douglas Barr, Executive Director Douglas L. Stowell, Esquire Northwest Florida Water Management District 81 Water Management Drive Havana, Florida 32333 Johnathan Mantay, County Manager Bay County Post Office Box 1818 Panama City, Florida 32402-1818 Teri Donaldson, General Counsel Department of Environmental Protection Douglas Building, Mail Station 35 Tallahassee, Florida 32399-3000
The Issue The principal issues to be resolved in this proceeding concern whether certification should be issued to the City of Lakeland, Department of Electric Utilities (Lakeland or Lakeland Electric) to construct and operate the steam electric equipment needed to create a nominal 350-megawatt combined-cycle generating unit located at Lakeland’s McIntosh Power Plant site in Lakeland, Florida in accordance with the provisions of Section 403.502, et seq., Florida Statutes. The related issues concern whether the site for the McIntosh Unit 5 Steam Cycle Project is consistent and in compliance with the applicable land use plans and zoning ordinances of the City of Lakeland, pursuant to Section 403.508(2), Florida Statutes.
Findings Of Fact Project Operations and Impacts Project Overview The City of Lakeland, Department of Electric Utilities is a municipal utility that supplies electric service to approximately 106,000 customers, which represents approximately 200,000 residents in its service area within Polk County. Lakeland’s electric utility commenced operation in 1891, making Lakeland one of only three Florida cities with electricity at that time. Lakeland currently operates power plants at two locations in the City of Lakeland with a combined generating capacity of 785 megawatts (MW). The McIntosh Power Plant site is the larger power plant site and contains six electrical generating units. McIntosh Unit 3 is a 365-megawatt, coal-fired electrical generating unit, which was originally certified under the Florida Electrical Power Plant Siting Act in 1978. In 1998, Lakeland obtained approvals to construct a new 250-megawatt, simple-cycle combustion turbine (CT) at the McIntosh site. These approvals consisted of a modification of the site certification for McIntosh Unit 3 and a separate Prevention of Significant Deterioration (PSD) Permit, both issued by FDEP. That modification of the site certification for the new Unit 5 CT was required because the new CT was to be located within the site certified for McIntosh Unit 3. Pursuant to FDEP rules, the approval for that new unit was required to be obtained under the PPSA’s modification rules. The new McIntosh Unit 5 CT is completing construction and will be placed into service in the near future. The original permits for the Unit 5 CT anticipated that the CT would later be converted to a combined cycle configuration. The City of Lakeland considered a number of generating options before selecting the Unit 5 project to meet the City’s required 15 percent reserve margin. Siemens Westinghouse submitted a proposal to the City that Lakeland be the host site for the first 501G simple-cycle combustion turbine. The City concluded that this proposal was the best alternative available to meet the City’s needs for additional electricity. The conversion of Unit 5 to combined cycle operation will expand Lakeland’s natural gas-fired generating capacity to 76 percent of Lakeland’s total electrical generating capacity. No energy conservation measures exist that would affect the need for the plant. The 250-megawatt CT in Unit 5 is one of the most efficient generating units currently operating. In the CT, compressed air is introduced into a combustion zone and fuel, typically natural gas, is combusted within the forward portion of the CT. The resulting hot gases expand in the turbine and turn an electrical generator. For Unit 5, this electrical generator produces approximately 250 MW of electricity. The hot exhaust gases then are exhausted out the existing stack. Under the proposed Unit 5 Steam Cycle Project, the combined cycle configuration for Unit 5 involves the construction of a heat recovery steam generator (HRSG), which captures the exhaust gas from the CT and produces steam by extracting the heat from the flue gases. In the HRSG, the hot gases are used to convert water into steam in a closed system of piping. The steam is then used to turn a new steam turbine, which then turns an electrical generator. Other equipment required for the steam cycle project includes: a new, taller exhaust stack; a new cooling tower; and other plant equipment. The addition of the new HRSG steam turbine and electrical generator to McIntosh Unit 5 will produce an incremental 100 MW of electricity produced through the use of steam. The PPSA requires an increase of steam-generating capacity at the McIntosh site to undergo the full permitting proceedings of the PPSA. Therefore, Lakeland was required to submit its application for site certification to add the steam cycle to Unit 5. The McIntosh Unit 5 will be located on a 3-acre tract of land within the larger 530-acre McIntosh Power Plant site. The site is located in the eastern portion of the City of Lakeland, along the northern shore of Lake Parker. The McIntosh plant site is generally surrounded by undeveloped lands, including reclaimed and vacant phosphate lands used, in part, as a recreational and fishing area managed by the Florida Fish and Wildlife Conservation Commission (FWCC). There are no residential or commercial properties adjacent to the project site. The nearest residence to the project site is over one mile away. The site for the McIntosh Unit 5 contains no significant environmental features. No wetlands are found within the site. The Unit 5 site is an open field, containing grasses and low-quality, weedy vegetation. Further, no archaeological, or historical resources were found on the site. No sensitive local, regional, state or federal parks, wilderness areas, forests, or areas of critical concern are located within 5 miles of the site. No threatened, endangered, or protected plant or animal species are known to be present at or near the project site. The combined cycle unit will be fired primarily with natural gas, with fuel oil as a backup fuel. Natural gas is supplied by a 10-mile long pipeline owned by the City of Lakeland, which connects to the Florida Gas Transmission gas pipeline system. No alterations to those pipelines are required for the project. Fuel oil for the unit will be delivered by truck and stored in an existing on-site fuel storage tank. The capture and utilization of waste heat from the CT exhaust in the new heat recovery steam generator will significantly increase the efficiency of the electrical generation process for Unit 5. Use of the waste heat will not require any increase in fuel use and will not result in any increase in air emissions from the power plant. When considered on the basis of electrical output, the amount of emissions per megawatt hour of electricity will actually decrease by approximately 30 percent. All of the air emissions from Unit 5 are associated with the operation of the combustion turbine; and the addition of the heat recovery steam generator does not result in any increase in those emissions. Water Use, Wastewaters and Other Impacts The addition of the HRSG requires the use of a cooling tower to remove the heat from the circulating steam. Once the steam exits the steam turbine, it passes through a condenser in which the heat from the steam is transferred to circulating cooling water. The steam is condensed back to water and then recycled into the HRSG in a closed loop system. The heated cooling water is then routed to the cooling tower where forced air evaporation removes the heat. Periodically, a portion of the cooling water in the cooling tower system is removed to prevent the buildup of solids and other constituents which could impair the performance of the cooling tower. Replacement of this "blowdown water" and of the water lost through evaporation will be achieved through the use of treated domestic waste water (reuse water) supplied from the City of Lakeland’s wastewater treatment plants, including a plant adjacent to the McIntosh plant site. The cooling tower will require approximately 3.24 million gallons per day (mgd) to replace water lost in the cooling process. FDEP adopted Rule 62-610, Florida Administrative Code, to encourage the beneficial use of reuse water from domestic wastewater systems as a means of water conservation. The rule sets out certain treatment and design criteria that must be met when reuse water is used, including water used in cooling towers. The Lakeland Unit 5 cooling tower meets these rule requirements because the cooling tower is located more than 300 feet from the nearest property boundary, and the reuse water receives secondary treatment by the City of Lakeland. In the event reuse water is not available because of supply or quality problems, groundwater from on-site wells will be used as a backup source of cooling water makeup until reuse water is available again. The needed quantity of groundwater, up to 3.24 mgd, has been approved by the Southwest Florida Water Management District (SWFWMD) under the existing consumptive use permit issued by SWFWMD for the McIntosh plant site. That quantity of water has been shown to not have adverse effects on area users of groundwater. In addition to cooling water, the plant requires high quality service water to replace water lost in the operation of the HRSG and for other plant processes, including control of nitrogen oxide (NOx) emissions during oil firing. This water is obtained from groundwater wells and is treated in on-site water treatment facilities. Conversion of Unit 5 to combined cycle operation will reduce the use of groundwater by approximately 250,000 gallons per day during normal operations due to increased recycling of water within the unit. Wastewater from the plant is generated from the cooling tower, as a result of the periodic blowdown of the water in the cooling tower. This blowdown water is routed to an on-site collection sump and then routed to the City of Lakeland wastewater treatment system. Industrial-related wastewaters from plant operations, including wastewaters from plant water treatment, are also collected and routed to the City of Lakeland Wastewater Treatment system. There is no direct discharge of wastewater from McIntosh Unit 5 to adjacent surface waters. The project will not have any effect on area surface waters. There will be no increase in the need for potable water or domestic wastewater treatment. The addition of the new HRSG and related equipment for the steam-cycle project will not require an increase in permanent employment at the project site. The on-site stormwater management system is already sized to accommodate the addition of the steam-cycle equipment Minor amounts of solid and hazardous wastes will be generated by the project, mainly during construction. Any hazardous wastes will consist mainly of small amounts of spent solvent. Systems are already in place to dispose of these wastes in an approved manner. Electricity generated at the site is distributed from an on-site switchyard into the City of Lakeland transmission system. This system is interconnected to other Florida utilities. The addition of the Unit 5 Steam Cycle Project will not require any changes to the existing electrical transmission system. The McIntosh Unit 5 will be compatible with the other surrounding land uses in the vicinity of the project site. The project represents a logical expansion of the existing power plant site. It is well buffered from residential land uses. Noise from Plant construction and operation will not adversely impact nearby residents. Existing noise levels in the residential areas near the plant are low, even with the existing generating units at the McIntosh site in operation. Noise levels during construction and operation will comply with the applicable local noise ordinance, as well as the existing noise limitations in the McIntosh site certification conditions. Construction will generally occur during daylight hours, and construction equipment has to comply with noise limits set by the manufacturers. Addition of the new HRSG and other equipment will act to buffer noise from the existing CT. Operation of the plant will not be noticeable at the nearest residence, which is almost one mile away. Air Quality Analyses Required Polk County has not been designated by the U.S. Environmental Protection Agency (EPA) or FDEP as a nonattainment area for any federal or Florida ambient air quality standards. Federal and state Prevention of Significant Deterioration (PSD) program requirements applied to the simple cycle portion of McIntosh Unit 5. Because it was a major source of air pollution Because there were no significant net emission increases of any regulated air pollutants due to the conversion of McIntosh Unit 5 to combined-cycle operation, the PSD requirements did not apply to the addition of the steam cycle to Unit 5. Under the PPSA, air quality impacts associated with the new, taller stack and the new cooling tower associated with the combined-cycle operation of Unit 5 were required to be evaluated. However, no changes to the PSD permit itself were necessary to address the addition of the steam cycle to Unit 5, although some updated information reflecting the increased stack height and the addition of the cooling tower was provided to FDEP. Emission Impacts Under FDEP’s rules, air emissions from McIntosh Unit 5 must not cause or contribute to a violation of federal and state ambient air quality standards or PSD increments. Polk County is classified as a Class II area for PSD purposes. The nearest Class I area to the McIntosh Power Plant is the Chassahowitska National Wilderness Area, located approximately 90 kilometers (60 miles) from the Plant. The ambient air quality analysis demonstrated that McIntosh Unit 5's emissions, including operations in combined- cycle mode with the taller stack and cooling tower, will not have a significant impact on air quality near the McIntosh Plant or in the Chassahowitska Class I area. The maximum predicted impacts from Unit 5 in combined-cycle mode are below the EPA and FDEP significant impact levels. Unit 5's emissions will not cause or contribute to an exceedance of any state or federal ambient air quality standards. The 250-foot stack height for McIntosh Unit 5 in combined-cycle mode represents "good engineering practice" (GEP), calculated in accordance with FDEP and EPA rules. McIntosh Unit 5's air emissions are not expected to cause any adverse impacts on vegetation, soils, or visibility in the McIntosh Power Plant site vicinity or in the Chassahowitska National Wilderness Area, the nearest PSD Class I area. Air emission impacts of McIntosh Unit 5 on water bodies in the vicinity of the McIntosh Power Plant will be insignificant. No adverse air emission impacts are expected to result off-site during the construction of the steam cycle portion of Unit 5, and appropriate control methods will be used to minimize emissions during construction activities. The cooling tower plume could cause temporary and localized ground-level fog on occasion. The majority of these relatively rare instances will be of short duration and occur when fog is already naturally occurring. BACT and Emission Rates A Best Available Control Technology (BACT) analysis, required under the PSD program, is intended to ensure that the air emissions control systems selected for a new project reflect the latest in control technologies used in a particular industry based on a cost-benefit approach, taking into account technical, economic, energy, and environmental considerations. A BACT determination was made for emissions from Unit 5, including operation of the unit in combined-cycle mode, as part of the PSD permit previously issued for the simple-cycle operation on the Unit 5 CT. High efficiency drift eliminators are being installed on the McIntosh Unit 5 cooling tower to minimize particulate matter emissions from solids contained in the water released from the cooling tower. While the NOx emission limits in the PSD permit will not change due to the addition of the steam cycle portion of Unit 5, the projected emission rate in terms of pound-per-megawatt- hour (lb/mwhr) are actually lower when in combined-cycle mode because of the increase in electricity generated with no additional emissions being created. Compliance McIntosh Unit 5 in the combined-cycle mode will comply with all applicable federal and state air quality standards, including the conditions contained in the PSD Permit for Unit 5 and in FDEP is proposed conditions of certification. Consistency with Local Land Use Plan and Zoning Ordinances The Lakeland McIntosh Unit 5 project site, as well as the entire McIntosh Plant Site, is located in a future land use map designation of "Industrial" on the City of Lakeland’s Future Land Use Map. That map is part of the locally-adopted Comprehensive Plan for the City of Lakeland. Electrical power plants are a permitted use in that Industrial land use category. McIntosh Unit 5 meets the locational criteria in the future land use element, in that it is well buffered and served by adequate, available public facilities. The McIntosh Unit 5 Steam Cycle project site is zoned I-3, or Heavy Industrial under the City of Lakeland’s zoning regulations. That zoning district allows electrical power plants, subject to further review under the City’s zoning requirements. This additional zoning review consists of a conditional use permit, which is intended to provide an additional layer of review for these types of facilities. On September 7, 1999, the City of Lakeland City Council issued a conditional use permit for the entire McIntosh plant site, which includes the site for McIntosh Unit 5. McIntosh Unit 5, when converted to combined-cycle operation, will be consistent and in compliance with the City of Lakeland’s land use plans and zoning designations for the project. Further, the project will be consistent with the conditional use permit issued for the project site. McIntosh Unit 5 will also be consistent with the other provisions of the City of Lakeland Comprehensive Plan. The project meets the local Plan’s concurrency requirements, promotes the use of treated wastewater for cooling of power plants, and meets the provisions for protection of local air quality. Agency Positions and Stipulations The FDEP, the Florida Department of Community Affairs, the Southwest Florida Water Management District, the Florida Department of Transportation and the Fish and Wildlife Conservation Commission each prepared written reports on the project, and all recommended approval of the City of Lakeland McIntosh Unit 5 Steam Cycle Project. (Amended FDEP Exhibit 3). FDEP has proposed Conditions of Certification for the project, which Lakeland agrees to accept and comply with in plant construction and operation. The Department of Community Affairs determined that the project, if certified, would be consistent with the State Comprehensive Plan. The Central Florida Regional Planning Council (CFRPC) did not submit a report to FDEP as part of its review of the project. However, CFRPC entered into a prehearing stipulation with the City of Lakeland in which it stated that the project would be consistent with the CFRPC’s Strategic Regional Policy Plan. DCA entered a similar stipulation indicating its agreement that the project was consistent with the State Comprehensive Plan. The Department of Transportation entered into a prehearing stipulations indicating it did not object to certification of the project. No state, regional, or local agency has recommended denial of certification of the project.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that The City of Lakeland, Department of Electric Utilities be granted certification, pursuant to Chapter 403, Part II, Florida Statutes, for the location and operation of the McIntosh Unit 5 Steam Cycle Project, representing an expansion of the electrical generating capacity of the existing McIntosh Unit 5, as proposed in the Site Certification Application and the evidence presented at hearing, and subject to the Conditions of Certification contained in Amended FDEP Exhibit 3, and subject to the Conditions of Certification attached hereto; The Siting Board find that the site of the McIntosh Unit 5 Steam Cycle Project, as described in the Site Certification Application and the evidence presented at the hearing, is consistent and in compliance with the existing land use plans and zoning ordinances of the City of Lakeland as they apply to the site, pursuant to Section 403.508(2), Florida Statutes. DONE and ENTERED this 2nd day of March, 2000, in Tallahassee, Leon County, Florida. J. LAWRENCE JOHNSTON Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 SUNCOM 278-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 2nd day of March, 2000. COPIES FURNISHED: Mark Carpanini, Esquire Polk County Attorney’s Office Drawer AT01 Post Office Box 9005 Bartow, Florida 33831-9005 Douglas S. Roberts, Esquire Hopping Green Sams & Smith Post Office Box 6526 Tallahassee, Florida 32314 Scott A. Goorland, Esquire Department of Environmental Protection Douglas Building, Mail Station 35 3900 Commonwealth Boulevard Tallahassee, Florida 32399-3000 Sheauching Yu, Esquire Department of Transportation Haydon Burns Building 605 Suwannee Street, Mail Station 58 Tallahassee, Florida 32399-0450 James V. Antista, Esquire Fish and Wildlife Conservation Commission 620 South Meridian Street Tallahassee, Florida 32399-1600 Andrew S. Grayson, Esquire Department of Community Affairs 2555 Shumard Oak Boulevard Tallahassee, Florida 32399-2100 Robert V. Elias, Esquire Florida Public Service Commission Gerald Gunter Building 2540 Shumard Oak Boulevard Tallahassee, Florida 32399-0850 Frank Anderson, Esquire Southwest Florida Water Management District 2379 Broad Street Brooksville, Florida 34609-6899 Thomas B. Tart, Esquire Orlando Utilities Commission 500 South Orange Street Orlando, Florida 32801 Andrew R. Reilly, Esquire East Lake Parker Residents Post Office Box 2039 Haines City, Florida 33845-2039 Norman White, Esquire Central Florida Regional Planning Council 555 East Church Street Bartow, Florida 33830 Kathy Carter, Agency Clerk Office of the General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000 Teri Donaldson, General Counsel Office of the General Counsel Department of Environmental Protection 3900 Commonwealth Boulevard, Mail Station 35 Tallahassee, Florida 32399-3000
