Findings Of Fact At all times material to this proceeding, the Respondent, Joseph Davidow, was licensed as a general contractor with the Florida Construction Industry Licensing Board. On August 3, 1978, the Respondent entered into an agreement with Rubin Zimmerman, Vice-president of Gilbert's Fish Camp, Inc., located in Monroe County, to construct an addition and make alterations to an existing motel. The contract specified the work to be done, for which the Respondent was to receive $190,000 with a completion date within 90 days of the contract. The Respondent was recommended to Mr. Zimmerman, the complainant in this case, by Mr. Zimmerman's architect on the project, Seymore Drexler, AIA. The Respondent originally bid the project at $210,000 of which $19,000 was allocated for electrical work to be performed by a qualified sub-contractor. The complainant believed that the original bid for electrical work was too high and suggested that the Respondent contact Mr. Charles Katzman of Kay Electric, a long-time friend of the complainant. Mr. Katzman was able to obtain his permits on the project despite being unlicensed in Monroe County, a fact which was not known by either the Respondent or the complainant at the time. Mr. Katzman bid $13,500 on the project which was $5,500 under the lowest bid received by the Respondent and was, therefore, awarded the project. During the course of the construction, numerous problems arose which affected the progress on the site. The complainant and his business partner, Harry Gilbert, made numerous requests for changes in the original plans and specifications. The "extras" requested by the complainant and/or his business partner were generally done orally on the site and at times through direct negotiations between the complainant and the Respondent's sub-contractors or workmen. The changes in the specifications included modifications to the flooring, patio, laundry and storage room, grade beams, pilings, walkways, stairs, patio wall, diningroom walls, linen closet, bathroom windows and walls, outside planter, doors and support system for electrical cooling. A dispute arose between the Respondent and the complainant and Mr. Gilbert over the cost and the extent of the change orders. Additionally, the Respondent was concerned because the extras requested by the complainant diverted his sub-contractors and/or workmen from the basic project to areas not contemplated by the contract. Certain of the electrical work performed by Mr. Katzman was negotiated separately from the original contract. Romex an illegal electrical wire was used on the project, but this was not known by the Respondent nor was Romex used in any of the electrical work specified in the original plans. Due to the continuing dispute over the cost of the extras and the diversion of workers for additional "extras," the Respondent sent the Monroe County Building and Zoning Department on April 12, 1979, a notice of withdrawal as general contractor on the subject project. Since that time liens have been filed against the project by suppliers of materials and/or labor which have been satisfied by the corporation. Civil litigation involving Kay Electric also has been instituted. The building inspection reports maintained by Monroe County concerning this project are incomplete.
Recommendation Upon consideration of the foregoing, it is RECOMMENDED: That the Department dismiss the complaint filed against the Respondent, Joseph Davidow. DONE and ORDERED this 26th day of November, 1980, in Tallahassee, Leon County, Florida. SHARYN L. SMITH Hearing Officer Division of Administrative Hearings Room 101, Collins Building Tallahassee, Florida 32301 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 26th day of November, 1980. COPIES FURNISHED: Barry S. Sinoff, Esquire 2400 Independent Square One Independent Drive Jacksonville, Florida 32202 Arthur W. Karlick, Esquire 1454 NW 17th Avenue Miami, Florida 33125 Nancy Kelley Wittenberg, Secretary Department of Professional Regulation 2009 Apalachee Parkway Tallahassee, Florida 32301 ================================================================= AGENCY FINAL ORDER ================================================================= BEFORE THE FLORIDA CONSTRUCTION INDUSTRY LICENSING BOARD DEPARTMENT OF PROFESSIONAL REGULATION, Petitioner, vs. Case No. 80-382 JOSEPH DAVIDOW, CG C007463 Respondent. /
Findings Of Fact The Petitioner, John Michael Hatcher, is an electrician by training and was employed at times pertinent hereto by the City of Gainesville. His job as an electrician spanned the years 1979 to 1992. He first worked at the Deer Haven Power Plant operated by the City of Gainesville. In 1987, he was transferred to a position as a substation electrician with the City utility entity. His primary duties as a substation electrician involved performing maintenance and repair to high-voltage circuit breakers and other equipment involved in the transmission and distribution of electrical power. Substation electricians perform their work by employing two crews of three members each. On each crew, there were two electricians and one crew leader. The work of substation crews is performed on 90-day schedules. In September of 1992, the Petitioner was suspended from his position for "inability to perform the essential functions of his job" and was ultimately terminated on October 7, 1992. That termination was upheld by the City of Gainesville through its grievance process on November 10, 1992, after exhaustion of the three-step grievance process provided for in the City's collective bargaining agreement. Sometime in 1987, the Petitioner experienced breathing difficulties or respiratory irritation, when in the presence of electric power circuit breaker vapors, related to petroleum products used to cool the circuit breakers. The Respondent installed high-volume ventilation fans at the substation and encouraged the Petitioner to use the fans to remove the noxious vapors from the power circuit breaker area prior to the fume exposure which he states caused his injury. The Respondent also advised the Petitioner to use breathing masks. The ventilation fans proved to be effective in removing the vapors which the Petitioner found irritating in the electric substation environment. The masks were also effective in allowing him to work in that environment without being bothered by the fumes, as he admitted. These steps solved the Petitioner's problem in his main working environment but still left a problem for him when he drove the vehicle he used to get from job site to job site. The Petitioner maintained that he was bothered by exhaust fumes when traveling through downtown traffic in the open van-type vehicle. The Respondent recommended that he wear the breathing mask during this time, as well, and he acknowledged that it was effective in preventing the respiratory irritation that had bothered him when driving or riding in the van. The Petitioner, however, advised that he could not wear the protective mask for very long periods. This was purportedly because the heat and humidity gave him problems wearing the mask for an extended period, although traveling across a town the size of Gainesville did not take a very extended period of time. The protective mask was shown to be effective at his regular work station and in the van. The irritation problem was caused by the Petitioner not timely donning the mask before he became symptomatic. It is not clear exactly when, after mid-1987, the Respondent learned that the Petitioner was purportedly having breathing difficulties in association with his work environment. In any event, during mid-1989, the Respondent, after hearing that the Petitioner had experienced breathing difficulties when in the presence of power circuit breaker vapors, began an independent study of the causes of his complaint. This was in addition to its recommendation that he use the high-volume ventilation fans and the protective masks the Respondent provided. The Respondent's risk management division hired Lipsey & Associates to conduct a toxicology evaluation of the areas in which the Petitioner worked. The air quality in the Petitioner's work environment, tested by this independent firm, was found to be within appropriate air-quality standards or "OSHA" standards. None of the Petitioner's co-workers suffered the symptoms the Petitioner complains of. The Petitioner did not always wear the breathing mask in the work areas where fumes occur nor does he always wear it when driving the van through downtown Gainesville. Because of the Petitioner's health complaints, he was referred to the Family Practice Medical Group and examined by Dr. Marvin Dewar on June 8, 1992. Previously, the Petitioner was examined by Dr. Pravda on April 23, 1991 and diagnosed with sinusitis and asthma. He was examined by Dr. Stringer, an ear, nose and throat specialist, on August 27, 1991, with no physical abnormalities being found. He was also examined by Dr. Gonzalez-Rothi on October 10, 1991, with no significant pulmonary disease being found. He was then diagnosed with a "sinobronchial syndrome". During this period of time, beginning in 1989, the Petitioner's attendance for his various evaluation periods was rated "conditional" and "below average" (in 1990-1991). In 1992, he received a score of "2" (out of 10) for below-average attendance. His absences in the 1992 evaluation period increased both in number of hours used and number of incidents. The Petitioner attributed his absences during his 1992 evaluation period to a recurring illness caused by his exposure to irritants in the work place. He acknowledged in his testimony, however, that the breathing mask and ventilation fans had helped prevent the problem but that he did not always avail himself of the protective devices on a timely basis to prevent symptoms. Rather, he only wore the masks intermittently after he felt symptomatic with respiratory irritation. Because of his continuing absences, the Respondent finally notified the Petitioner that he was being terminated, due to an inability to perform the essential functions of his job, rather than because of an unwillingness to do so. At the time the Petitioner was notified that his employment would be terminated, he had not ever informed the Respondent, or filed any claim, for an alleged disability. The Respondent was aware that he had a sensitivity to petroleum and automotive fumes, but with the ventilation fans and masks that it had provided, and with the air quality report stemming from the study, the Respondent was of the belief that the Petitioner was able to perform all of the duties of his job as an electrician. It only became convinced that he was unable to perform the essential functions of his job because of the frequency of absences, which failed to improve. An informal conference related to the termination was scheduled for September 17, 1992 and held on September 21, 1992. At this time, the Petitioner had not yet informed the Respondent of any alleged disability, as shown by Mr. Holder's testimony. Although the Petitioner claimed in his testimony that he informed the Respondent of his diagnosis of "chronic fatigue immune system dysfunction" and "idiosyncratic reaction to petroleum vapors" by purportedly giving Mr. Holder, his supervisor, a copy of Dr. Itzkowitz's diagnosis on one of the prescription forms, the credible testimony and evidence is that those diagnoses were not known to the Respondent nor discussed at the September 21, 1992 informal conference. The credible evidence and testimony shows that the Petitioner informed the Respondent that he had found a doctor who had diagnosed his problem and could cure him, but did not mention any handicap or the need for any accommodation at the time of that informal conference. In fact, the Petitioner's testimony in this regard is contradicted in a document he himself wrote, in evidence as Respondent's Exhibit 3. In this self-authored "termination summary," the Petitioner himself states that prior to that September 21, 1992 meeting with management, management personnel did not know he had found a doctor who had diagnosed his condition. The Petitioner attempts to correct this contradiction by testifying that his statement to that effect referred to "upper management" not knowing. This attempted correction is itself contradicted by the Petitioner's statement on direct examination that he believed Mr. Holder would give the prescription form document, supposedly containing his diagnosis, to Mr. Holder's superior, Mr. Williams. Therefore, if, indeed, he had given the diagnosis on the prescription form to Mr. Holder, and if his statement that he believed Mr. Holder would convey it to Mr. Williams and "upper management" is his true belief, how could he then testify that management did not know (unless he really knew he had never informed the Respondent at or before the September 21, 1992 meeting at all)? Indeed, that is found to be the case. The Respondent did not learn of Dr. Itzkowitz's diagnosis until after that conference. In testifying at hearing, the Petitioner presented a "diagnosis" of "chronic fatigue syndrome" and "hypertriglecemia" by presenting a prescription form of Dr. Itzkowitz as Petitioner's Exhibit 2. That form is dated August 24th. The Petitioner stated that he presented it to his supervisor, Mr. Holder, in August or early September of 1992, before his September 14, 1992 suspension. He stated that he believed Mr. Holder would give the document to his superior, Mr. Randy Williams. In contrast, the Respondent presented its Exhibit R-1, which is a copy of the same document on Dr. Itzkowitz's prescription form. This copy is undated. It had been included in a packet of medical information from the Petitioner to the Commission, which contained copies of all the medical information previously submitted to the Respondent by the Petitioner. When asked how the same document could be dated in one version and undated in another, the Petitioner stated that he had received an undated version from Dr. Itzkowitz and had returned it to her for signature, whereupon the date was put on it. Dr. Itzkowitz, in her testimony, however, contradicts this and stated that she "absolutely" dated the document when she originally wrote it. The Petitioner and Dr. Itzkowitz cannot both be right. One of the two is either giving untrue testimony or has a very faulty memory in this regard. In any event, the authenticity of the document containing the purported diagnosis and by which the Petitioner maintains he informed the Respondent of his diagnosis and handicap before his suspension, the September 21, 1992 meeting, and his termination, is called into serious question, as are the motives of the document originators, particularly the Petitioner. It is thus found that the Respondent was not informed of the Petitioner's diagnosis and handicap before the termination and that Mr. Holder's testimony in this regard to the effect that he did not know of any handicap, or the diagnosis upon which the Petitioner relies, before the termination, is accepted as more credible and worthy of belief under these circumstances. The Petitioner's Exhibit 2 is not deemed a credible document. Subsequent to the Petitioner's September 21, 1992 informal conference with the Respondent, Petitioner's physician, Dr. Itzkowitz, sent the Respondent a letter dated September 29, 1992, stating her diagnosis of fibromyalgia and idiosyncratic reaction to petroleum vapors. Dr. Itzkowitz's letter to the Respondent does not state that the Petitioner was able to perform the duties as a substation electrician. The doctor states that he would do well at his previous assignment (power plant electrician). The doctor's September 29, 1992 letter finds "significant, reversible respiratory illness" even though prior medical examinations found no physical abnormalities. The doctor also supplied a "certificate of examining physician", for purposes of the Petitioner's unemployment compensation claim, stating that the Petitioner was unable to work from August 14, 1992 through September 14, 1992. In fact, that was an inaccurate statement because the Petitioner worked all but about four of the days between those two dates. The Petitioner submitted this document to the Department of Labor, Division of Unemployment Compensation, without advising that entity that the information was incorrect and that, indeed, he had been working during most of that period of time. When Dr. Itzkowitz was questioned by the Respondent about the Petitioner's ability to work during that period, following exchange occurred: Do you have any recollection as to whether or not Mr. Hatcher was actually not working during all that period? When Mr. Hatcher came to me, he told me he was not allowed to work. Whether that meant that he was given time off, he was suspended, or what, I have no clue. 2. So, when you say unable to work, you are going from what Mr. Hatcher told you? a. Or what other information was given to me, and again this is only a partial record. I mean I don't have the full record here, and what I do have I can't read. (See Petitioner's Exhibit 1 in evidence) However, according to the information on Respondent's Exhibit 4, the Petitioner became Dr. Itzkowitz's patient on August 14, 1992; and on that same day, the doctor wrote the Petitioner a doctor's excuse to be off work indefinitely. The Petitioner, however, only stayed off work for four days. The Petitioner was asked in this regard: Q. Whose idea was it for you to go back to work, yours or hers? Dr. Itzkowitz being the her. A. Mine, I believe. Q. Did you check with her to see if that was approved? A. Yes. Consequently, when Dr. Itzkowitz filled out the form represented in Respondent's Exhibit 4 in evidence, she must have known that it was not really accurate that the Petitioner was unable to work from August 14, 1992 through September 14, 1992. She authorized the Petitioner to be off work and approved the Petitioner returning to work, if the Petitioner's testimony quoted last above is true, that is. In any event, it has not been credibly demonstrated that the Petitioner had to be off work due to any disability or illness from August 14, 1992 through September 14, 1992. Up to the date of his termination on October 7, 1992, the Petitioner had not actually alleged a disability nor had he requested accommodations for such. He was terminated based upon his inability to perform the essential functions of his job and not because of his handicap. He could not perform the essential functions of his job because he was not there often enough, due to his pattern of frequent absences. He is able to perform the duties of his electrician job without accommodation, aside from the presence of irritating fumes. The problem of the irritating fumes was already alleviated by the voluntary provision of ventilation fans and face masks provided to him by his employer. After his termination on October 7, 1992, the Petitioner appealed to the third level or step of the Respondent's internal grievance procedure and alleged there for the first time that he was handicapped by "chronic fatigue syndrome". He requested accommodations for that alleged disability. The accommodations he requested involved a proposed return to his previous position as a power plant electrician at the Deer Haven Power Plant or the setting up of a rotating assignment, as a full-time position, as well as the allowance of an air-conditioned truck to perform this new position. None of the accommodations requested involved the Petitioner performing the same job and position from which he was terminated. During the period of time the Petitioner was experiencing high absenteeism from 1989 through 1992, purportedly because of his aversion to the fumes, he was encouraged to apply for other positions with the City that would take him away from fumes. The Petitioner stated to the Respondent during his "step 3" grievance conference, after his initial termination, that he considered job openings in the Human Resources Department but had not talked to anyone with that entity or filed an application. Subsequent to his termination, he applied two or three times for a position as a power plant electrician, the position he held before becoming a substation electrician. He falsified his application, where he stated that he had never been discharged or terminated but he was still allowed to take the test for the open position. Instead of testing for the position, however, he called the Respondent before the day of the test and advised the Respondent that he could not take the test due to illness. This is somewhat curious. Since the test was scheduled for the afternoon, it would seem if he wanted to avoid the test due to illness on the day of the test, he would have called on the morning of the test, rather than the day before it was administered to state that he could not take the test due to illness. The Petitioner could have consulted a physician to find out if something could be done to allow him to take the test at a different time and he could have called and requested some accommodation in taking the test, if he believed he was an applicant with a handicap. However, The Petitioner did neither of these things. He simply said he could not take the test due to illness and apparently never sought any alternative time or means of taking the test to become qualified for the position. This calls into question whether the Petitioner genuinely has any interest in returning to work at the power plant. Moreover, in his Petition for Relief, the Petitioner requested that he be reinstated to his former position. Subsequent to his termination, however, he filed a claim for social security benefits. In order to be considered disabled for purposes of social security benefits, a person must be "unable to do any substantial, gainful work due to a medical condition which has lasted or is expected to last for at least 12 months in a row. The condition must be severe enough to keep a person from working not only in his or her usual job but in any other substantial, gainful work." See Respondent's Exhibit 8, in evidence. The Petitioner's testimony at hearing conflicts with his representation of his condition in Respohndent's Exhibit 8. It reveals, in effect, that he did not meet this definition for disability when he unsuccessfully applied for those benefits. He was, and is, not in accord with that definition of disability, is able to work as stated above and seeks reinstatement to his former position with the power plant. The Petitioner stated in his Petition for Relief that his handicap is not hypersensitivity to petroleum vapors but, rather, is a chronic fatigue illness of his immune system, causing immune dysfunction and resulting sensitivity to drugs, allergies, odors, and chemicals. The Petitioner also alleges that the chronic fatigue causes the sensitivity to vapors. At the hearing, he could not point out any single incident of chronic fatigue suffered by him, but which preceded his sensitivity to petroleum vapors, which occurred back in 1987. The medical evidence indicates that prior to his sensitivity to vapors, his health had been good. Fibromyalgia is a chronic condition causing people who suffer from it to have chronic aches most of the time. It is a syndrome, and sufferers often also have associated chronic fatigue. The two terms are synonomous for the same condition. The Petitioner's medical history does not reflect any history of severe or chronic aches. Nothing in his medical records reflects any history of the fatigue syndrome preceding his vapor sensitivity. His allegation that his vapor sensitivity is a symptom of two separate conditions, chronic fatigue and fibromyalgia, is not credible.
Recommendation Based on the foregoing Findings of Fact, Conclusions of Law, the evidence of record, the candor and demeanor of the witnesses, and the pleadings and arguments of the parties, it is RECOMMENDED that a Final Order be entered dismissing the Petitioner's Petition for Relief in its entirety. DONE AND ENTERED this 31st day of August, 1995, in Tallahassee, Florida. P. MICHAEL RUFF, Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 1st day of September, 1995. APPENDIX TO RECOMMENDED ORDER, CASE NO. 94-264 Petitioner's Proposed Findings of Fact 1-4. Accepted. Rejected, as contrary to the preponderant weight of the evidence and subordinate to the findings of fact of the Hearing Officer. Rejected, as irrelevant. Rejected, as immaterial. Accepted, but not materially dispositive. 9-11. Accepted, but not itself materially dispositive. 12. Accepted, in terms of describing Dr. Itzkowitz's testimony but not as to its purported material import. 13-15. Accepted, but not itself materially dispositive. 16. Rejected, as subordinate to the Hearing Officer's findings of fact on this subject matter and not entirely in accord with the preponderant weight of the evidence. 17-19. Accepted, but not materially dispositive. Respondent's Proposed Findings of Fact The Respondent's proposed findings of fact are accepted to the extent that they are not inconsistent with the findings of fact made by the Hearing Officer. To the extent that they differ from the Hearing Officer's findings of fact, they are rejected. Certain of the Respondent's proposed findings of fact are omitted as being irrelevant or unnecessary. COPIES FURNISHED: John M. Crotty, Esq. Post Office Drawer 2759 Gainesville, FL 32602 Ronald D. Combs, Esq. Assistant City Attorney II City of Gainesville-Law Department Post Office Box 1110 Gainesville, FL 32602 Sharon Moultry, Clerk Human Relations Commission Building F, Suite 240 325 John Knox Road Tallahassee, FL 32303-4149 Dana C. Baird, Esq. General Counsel Human Relations Commission Building F, Suite 240 325 John Knox Road Tallahassee, FL 32303-4149
The Issue The issues to be determined in this proceeding are whether OUC should receive supplemental certification from the Siting Board for its proposed Unit 2 electrical power plant and associated facilities, including a transmission line and alternate access road, and what conditions, if any, should be incorporated within such supplemental certification to assure that minimal adverse consequences result from the new electrical power plant and associated facilities. The parties have reached substantial agreement on issues of fact and upon conditions of certification necessary to assure compliance with applicable nonprocedural requirements of the agencies having jurisdiction over the project. No party opposes the issuance of the supplemental certification sought by OUC, leaving a single dispute between OUC and SJRWMD as to SJRWMD's proposed condition of certification which would limit OUC's consumptive water use authorization to a ten-year period commencing on the date of certification and would essentially require OUC to reapply for subsequent consumptive use permits for water use thereafter.
Findings Of Fact The Co-applicants. Orlando Utilities Commission (OUC) is a statutory commission of the State of Florida and is part of the government of the City of Orlando. OUC generates and distributes electric power and water to persons within its service area. OUC owns the Stanton Energy Center site and will have a 75% ownership interest in Stanton 2. The Florida Municipal Power Agency (FMPA) is a joint agency formed under the Interlocal Cooperation Act and exercises power under the Joint Power Act. FMPA has authority to undertake and finance electric projects and to plan, finance, acquire, construct, own, operate, maintain or otherwise participate jointly in Stanton 2 and other projects. FMPA members Fort Pierce, Homestead, Key West, Lake Worth, Starke and Vero Beach will be participants in Stanton 2; FMPA members Bushnell, Clewiston, Green Cove Springs, Jacksonville Beach, Leesburg and Ocala will be participants through FMPA's All Requirements Project. The FMPA will have an approximate 21% ownership interest in Stanton 2. Kissimmee Utility Authority (KUA) is a public body, organized and existing as part of the government of the City of Kissimmee. KUA generates, transmits and distributes electric power. KUA will have an approximate 4% ownership interest in Stanton Unit 2. The Stanton Site and the proposed project. OUC owns the Curtis H. Stanton Energy Center, a 3280-acre site, with associated railroad, utility and transmission corridors located in Orange County, approximately twelve miles east-southeast of the City of Orlando, Florida. On December 14, 1982, the Governor and Cabinet of the State of Florida, sitting as the Siting Board, certified the Stanton Energy Center site for an ultimate generating capacity of approximately 2000 megawatts. On July 1, 1987, Stanton Energy Center Unit 1, a 465 megawatt gross, 440 megawatt net, coal-fired electrical generating plant, went into commercial operation. The certified facilities associated with the Stanton site include a railroad corridor containing a railroad spur for coal train access to the site, a cooling water pipeline for the treated sewage effluent used for cooling water obtained from the Orange County Easterly Subregional Wastewater Treatment Plant, a plant access road, and associated transmission lines. The associated facilities are sized to accommodate the ultimate 2000 megawatt site development; additional associated transmission lines will be required for the ultimate site development. Certain facilities constructed with Stanton Unit 1 were sized to accommodate Stanton 2. These include the following: cooling water storage pond, coal handling and storage areas, two potable water wells, wastewater treatment systems and a landfill for disposable wastes and flue gas sulfur sludge. Development of the site for Stanton 1 and its associated facilities directly affected approximately 960 acres. The construction of the Stanton 2 power block will affect approximately nine additional acres which were originally graded and prepared during Stanton 1 construction. The proposed Unit 2 is a 465 megawatt gross (440 megawatt net) coal- fueled, steam electric generating plant which is intended by OUC to be virtually identical to the existing Unit 1. New plant facilities to be constructed with Unit 2 include electrostatic precipitators, sulfur-dioxide removal equipment, a chimney and a cooling tower. Unit 2 will have a Babcock and Wilcox natural circulation steam generator with a maximum continuous rating of 3,305,000 lb. hr. of steam at 2,640 psig and 1005/1005 degree F. The unit will have a Westinghouse Turbine Generator with a 516,200 KVA generator nameplate rating. The boiler will be equipped with low NOx burners. The unit will have an electrostatic precipitator and wet limestone scrubber, consisting of two scrubber modules and one spare module. Treated sewage effluent provided by Orange County's Easterly Subregional Wastewater Treatment Plant will be used for cooling water. No cooling water or wastewater will be discharged from the Stanton site. A natural draft cooling tower will be used for cooling and evaporation of water. New linear facilities to be constructed for Unit 2 consist of a 14- mile 230 kV transmission line (which includes a new unpaved access road) and a new 1.4-mile alternate access road. The existing certified transmission line corridor, which is 220 feet wide, extends approximately 32 miles east and west from a point one-fourth mile north of the SEC site boundary. This corridor contains two sets of transmission lines and structures which connect Unit 1 to OUC's Indian River Power Plant, near Titusville, Florida, and to OUC's Pershing Substation located at Orlando, Florida. One set of lines comprises two 115 kV lines on wooden structures, while the other set is a 230 kV line on steel structures. In order to integrate the power generated by Unit 2 into OUC's transmission system, a new 230 kV transmission line is required. This proposed Stanton-Mud Lake 230 kV transmission line will originate at the existing Stanton Energy Center 230 kV Substation and will interconnect with the existing OUC Transmission Line 7-0615 after its relocation near Mud Lake. The new Stanton- Mud Lake Transmission Line, approximately 14.0 miles in length, is to be constructed within OUC's existing OUC coal-haul railroad corridor, which runs from the Stanton Energy Center to its interconnection with existing transmission line 7-0615. This corridor, which varies in width along its route, from 260 feet to 400 feet, was certified along with Unit 1 in 1982. The 1.4-mile alternate access road will be paved. It will provide a second access to the Stanton site during construction. It will also provide access from the Bee Line Expressway for OUC personnel, and for fire, ambulance or other emergency vehicles. Approximately 60 OUC employees will use the alternate access road on a daily basis. The daily use of this alternate access road will increase during plant outages. Secondary access to the SEC site was previously provided by a road across the adjacent Orange County landfill during the construction of Unit 1. However, expansion of the landfill has resulted in this particular road not being available for Unit 2. Stanton's solid waste management and disposal area was placed along the western boundary of the SEC site because existing upland surface elevations allowed the use of the area as a source of fill material and because an existing sanitary landfill was located on adjacent property to the west. The railroad track loop for coal trains is placed along the south side of the complex because the railroad spur from Orlando approaches the site from the south. All coal is received by rail. Rail service to the site is provided by the CSX railroad system from its main line connecting Jacksonville to Orlando and Tampa. A rail spur branches from the CSX main line at a point about three miles south of Taft and runs easterly, skirting the south boundary of Orlando International Airport and associated residential-commercial development. The spur turns due north just before it crosses the Bee Line Expressway, enters the SEC site and terminates in the site's rail loop, utilized for unloading coal. The headwaters of the Hart, Cowpen, Green and Turkey Creek tributaries of the Econlockhatchee River are located on the eastern part of the site which includes the power block, transmission line and associated proposed access roads. The location and arrangement of the Unit 2 power block does not encroach upon these tributaries. Wetlands on site consist of both isolated wetlands and those connected to other wetland systems or bodies of water. No wetlands will be cleared for the construction of the Unit 2 power block. Colonies of the endangered red-cockaded woodpecker (RCW) inhabit portions of the SEC site. When Unit 1 was built there were 63 RCW cavity trees on site, of which five had to be removed for construction. One of these was an active cavity tree. No existing cavity trees will be removed for construction of Unit 2. The approximately 2000 undeveloped acres of the site are being managed currently by OUC, pursuant to condition number XXXI of the site certification to provide foraging habitat for red-cockaded woodpeckers. The construction of Unit 2 should not have any significant adverse impact upon red- cockaded woodpeckers or their habitat on the Stanton site. Land use planning considerations. Originally, the site, including the corridor certified for railroad use, consisted predominantly of sandy areas of little topographical relief, supporting native forest vegetation or improved pasture and pine forest. These terrain conditions are referred to as flatwoods. Prior to OUC's acquisition of the site, it was logged and used for the grazing of livestock. There are scattered wooded and wet areas on the site. The east half of Sections 13 and 14 and the northeast quarter of Section 23 were under lease for hunting purposes. There were no residences on the site. The site is located four and three-fourths miles south of Highway 50 and one mile north of Bee Line Highway in eastern Orange County, Florida. The Econlockhatchee River is about three-fourths mile east of the northeast corner of the site boundary; four tributaries cross the site. The Orange County landfill, or solid waste disposal facility, is adjacent to the site along the west boundary. There are no incorporated areas within five miles of the plant. The community of Bithlo, at the periphery of a five-mile radius, was incorporated from about 1895 to 1977. In 1977, the incorporation was dissolved and the area reverted as part of unincorporated Orange County, which now determines zoning and provides services for the area. Some residential development has occurred north and east of the site. Existing development in the Bithlo region begins about three and one-half miles north-northeast of the plant. To the south of the plant, near the Bee Line Expressway, International Corporate Park is attempting to develop an office/industrial complex. A state prison is located south of the site immediately north of the Bee Line and east of the railroad spur. Some zoning of the plant site and area within a five-mile radius of the plant is classified as "A-2," which is defined as a Ranch and Farmland Rural District with a minimum one-half acre lot size. Exceptions are the Bithlo area northeast of the plant and the proposed development area northwest of the plant. The Bithlo and Cape Orlando areas are predominantly classified at "R-1A," which is defined as a Single Family Residential District with a minimum 7500 square feet lot size. A portion of the Cape Orlando area is zoned "R-1AA," which is Single Family Residential with 10,000 square feet lot size. The area of proposed development to the northwest of the plant is classified as "P-D," which is defined as a Planned Development District. Citrus groves occur between the four and five mile radii to the northeast, southeast, and northwest of the plant site. No citrus groves are located within four miles of the plant location. There are no prime or unique farmlands, as identified by the U.S. Department of Agriculture Soil Conservation Service, within five miles of the plant site. There are no state or federally owned lands within five miles of the plant site. Water resources in the site vicinity (five mile radius) which could be affected include four tributaries of the Econlockhatchee River, isolated wetlands and the surficial and Floridan aquifer. These surface water resources are east and west of the developed portions of the site, respectively, while the surficial and Floridan aquifers underlie all of Orange County. The Floridan aquifer will supply plant service and potable water, and the Orange County Easterly Subregional Wastewater Treatment Facility supplies cooling tower make- up water. No municipal water supply or wastewater facilities are located on- site or are proposed. No natural lakes are on-site or within the five-mile site vicinity. Numerous small lakes to the west and south of the site are used for recreation and irrigation water supply. The cooling water reservoir occupying 93 acres was constructed on site to serve the existing and proposed units. Proximity to and impacts on transportation system. One alternate access road for vehicular access to the site will be constructed. This alternate access road will extend southward for 1.4 miles along the rail spur to the Bee Line Expressway. The existing access to the site is by Alafaya Trail, a two lane road which ends at the existing plant site. This road was constructed contemporaneously with Stanton 1 and was subsequently conveyed to Orange County. The maximum traffic generated by Stanton 2 will occur during a period in 1995 when up to an estimated 983 construction workers will be employed on site. Most of these construction workers will travel eastward from Orlando to work during the morning, with the reverse being true in the evening hours. There will be no substantial adverse effects on traffic congestion as a result of construction or operation of Stanton Unit 2, except at some intersection movements during construction. Traffic would use the East-West Expressway to bypass the more congested State Road 50, therefore not adding substantially to existing conditions at the State Road 50 and Alafaya Trail intersection. During construction, truck traffic to the plant will be scattered throughout the day and will not pose major problems other than some added wear and tear on roadways. However, the substantial portion of heavy equipment and material needed for Unit 2 is expected to arrive by rail, entering the plant site via the existing rail spur. Unit 2 is expected to employ only 85 additional personnel spread between three shifts. These employees will have minimal impact upon the transportation system during Unit 2 operation. Soil and foundation conditions. The soil and foundation conditions at the Stanton Energy Center Site were described in the original site certification application. There have been no significant changes in these conditions since the site certification. There will be no impact upon or changes to these conditions or factors as a result of the construction and operation of Stanton Unit 2. The soils underlying Unit 2 and its associated facilities have sufficient strength to support Unit 2 and its associated facilities with conventional foundation systems. The foundation systems will have no detrimental impact on the environment on site. The strata beneath the site to a depth of 209 feet are divided into five stratigraphic layers: a surficial sand layer, an intermediate cohesive layer, a lower sand layer, a lower cohesive layer and limestone bedrock. The soil and foundation conditions were extensively described in the original site certification application. These conditions are suitable for the construction and operation of Stanton Unit 2. Impact on archaeological sites and historic preservation areas. There are no recorded historic, scenic, cultural or natural landmarks located on the plant site. The National Registry of Natural Landmarks does not include any sites for Orange County, Florida. An archaeological and historic survey was conducted on accessible portions of the Stanton Energy Center site. The site survey was conducted by personnel from the Florida Secretary of State, Division of Archives, History and Records Management. Four sites were found during the survey. Three were prehistoric archaeological sites and one was a historic hunting lodge from the early 20th century. This lodge is located just off the site near the southwest corner of the property line. The Division of Archives, History and Records Management concluded that the sites did not represent significant archaeological or historical resources. No known landmarks or scenic areas will be affected by the proposed transmission line. During Stanton 1 construction, the railroad spur was realigned to miss a historical site that would have required salvaging. There are no historically, culturally or archaeologically significant areas within or along the new transmission line right-of-way that will be affected. Although archaeological site #8-OR-2208 is located along the new transmission line right-of-way, as first identified in the 1989 Lake Hart DRI review, the upper 30 cm. of soil in the area had previously been disturbed. Since the transmission line will span the 100 meter site, this project will have no impact on that site. Impacts to wetland and riparian habitat regulation zone resources. Installation of the proposed transmission line corridor and access roads will require clearing and filling of wetlands. Impacts to these wetlands are regulated by DER, SFWMD and SJRWMD. Those portions of the site which are located in the SJRWMD jurisdiction lie within a regulatory basin known as the Econlockhatchee River Hydrologic Basin (Econ Basin). Within the Econ Basin is a special area known as the Riparian Habitat Regulation Zone (RHRZ), regulated to provide additional habitat protection for certain contiguous wetlands and uplands. Of the total acres of wetland to be cleared, 13.19 acres are DER jurisdictional wetlands and 21.18 acres are regulated as isolated or connected by the SFWMD. Of the total wetland acres to be filled during construction of the transmission line and access roads, fill impacts include 4.12 acres of DER jurisdictional wetlands and 1.87 acres of SFWMD wetlands. The SJRWMD and SFWMD wetland acreage totals include the DER wetland acreages. As a result of construction of the transmission line and access roads, approximately a total of 8.9 acres of SJRWMD wetlands, and 6.6 acres of uplands within the Riparian Habitat Regulation Zone and 1.1 acre of isolated SJRWMD wetlands will be impacted. Construction of the access roads will result in the filling of 2.7 acres of herbaceous wetlands, and 0.1 acre of forested wetlands, and 0.9 acre of an isolated wetland. Approximately 0.1 acre of forested and 0.1 acre of herbaceous uplands within the RHRZ will be filled. Clearing impacts associated with the transmission line will result in the loss of 5.5 acres of forested wetlands and 6.4 acres of uplands within the RHRZ and 0.2 of an acre of isolated SJRWMD wetland. OUC's mitigation plan, as approved by SJRWMD, provides 67.75 acres of wetlands mitigation (compared to SJRWMD jurisdiction impacts of 4.3 acres filled and 5.7 acres cleared) and 81.95 acres of upland mitigation, including 32.55 acres of RHRZ (compared to SJRWMD jurisdiction RHRZ uplands impact of 6.6 acres). Surface water management considerations. The surface water management system and stormwater management system (the system) which OUC proposes to construct and operate includes the Unit 2 power block facilities, transmission line, structure pads and support structures, unpaved access road and paved alternate access road. Surface and stormwater runoff from the power block facility will be conveyed by new ditches and piping systems connecting to existing drainage systems to the Recycle Basin and Make-up Water Supply Storage Pond which is part of the power block facilities. The basin and pond are designed to retain runoff from the ultimate build-out (four units) of the power block area. The transmission line will be maintained through the use of the unpaved access road and the paved alternate access road. The unpaved access road consists solely of intermittent fill segments. No excavation or filling will occur for the unpaved access road in upland areas; however, fill will be placed in wetland areas which exist in the proposed unpaved access road alignment. These areas of fill will be contained with erosion and sediment control practices during construction and stabilized with vegetation upon final grading so as to prevent erosion and sediment transport into the Econlockhatchee RHRZ. The unpaved access road will allow passage of maintenance vehicles during normal climatic conditions for maintenance and repair of the transmission line and structures; maintenance is expected to occur approximately twice per year. Due primarily to its infrequent use and low impervious nature, the operation of this unpaved, stabilized access road is not expected to be a concern regarding stormwater pollution or to increase peak runoff rates. Placement of fill will occur for the length of the proposed paved alternate access road. Runoff from this road will be directed to proposed swales with ditch blocks and overflow structures. The proposed system meets SJRWMD's peak discharge criteria because plans and calculations demonstrate that: Runoff from the Unit 2 power block is directed to an adequately sized existing facility which attenuates peak discharge from the 25-year and 2.3-year, 24-hour regulatory storm events; The transmission line with its unpaved access road has a very low impervious nature; therefore, only an insignificant increase in runoff is expected; and Runoff from the paved alternate access road will be directed to the proposed roadside swale system which will attenuate peak discharge from the SJRWMD regulatory storm events. The proposed system meets SJRWMD's post-development volume criterion because there is no discharge from the proposed system to a landlocked basin. The proposed system meets the floodway conveyance and floodplain storage criteria of SJRWMD because plans and calculations show that: Existing culverts under the railroad track bed will be extended underneath both access roads and an additional bridge adjacent to the existing bridge will be constructed, such that floodway conveyance capabilities will not be impaired. The proposed extended culverts and bridge will be the same sizes as the existing culverts and bridges; and Necessary compensating storage for fill placed within the 100-year floodplain due to construction of the unpaved access road south of the Bee Line Expressway will be provided by excavating uplands adjacent to the floodplain. The proposed system will not decrease the flows of adjacent streams, impoundments or other watercourses so as to cause adverse impacts because: The applicants propose no new impoundments which might impair low flow discharges; and The applicants propose no deep excavations which might impair base flow. Anticipated construction dewatering will be temporary and will not unacceptably reduce water tables. The proposed system meets the SJRWMD's water quality criteria and standards because plans and calculations demonstrate that: Runoff from the Unit 2 power block will be directed to an adequately designed retention facility sized to treat a volume in excess of 1/2 inch of runoff from the contributing site; The transmission line with its unpaved access road will be stabilized, has a low impervious nature and will be used only to access the transmission line and poles. The operation of this road is not expected to increase pollutant loading to receiving waters; therefore, no additional stormwater management controls are proposed since they are not needed and would only result in additional impact to the RHRZ adjacent to the proposed road; Runoff from the paved alternate access road will be treated in roadside swales designed to provide storage and recovery of the required pollution abatement volume; and Adequate temporary and permanent erosion and sediment control measures will be implemented to protect the quality of receiving waters. The proposed system is a gravity flow system. It has no high maintenance pumps or filter drain systems which can be difficult to operate and maintain. The system will be easily maintained through mowing, as necessary, and through inspection of culverts to ensure no obstruction at least twice per month from June through October and once per month from November through May. There are no Works of the District (SJRWMD) in the vicinity of the plant site, proposed transmission line or proposed roads. There have been no minimum flows or levels yet established in the SJRWMD pursuant to Section 373.042, Florida Statutes. The area of influence of any dewatering associated with the proposed system will not extend to any area where the surficial aquifer is used by others. The operation of the proposed system will not induce saltwater intrusion. The proposed system has been designed to provide attenuation of peak runoff rates, to maintain floodway conveyance and floodplain storage, and to provide treatment of the required pollution abatement volume. No damage to property of the public is likely to be caused by operation of the system. Plant communities. Plant communities at the SEC site at the time of the original site certification application were described in that certification application. The plant communities existing on site are typical of those in the region, predominated by nearly level flatwoods with scattered wetlands and low ridges on the western portion and in the center of the already certified site. Construction and operation of Unit 2 will not affect any endangered or threatened plant species. No additional protected state listed species pursuant to 581.185(5)(a), Florida Statutes, have been identified on site within the plan proposed for alteration for Unit 2. Spoonflower (Peltandra sagittifolia), a listed species, was observed in a hardwood bay stand in summer 1981; however, this stand is not proposed for development as a result of the construction of Stanton Unit 2. Animal communities. The animal species found on or utilizing the SEC site were described in the original site certification application. The red-cockaded woodpeckers are restricted primarily to the scrub oak and pine flatwoods habitats. However, they are known to also utilize the wetlands on site as foraging habitat. Habitat improvements to the longleaf pine flatwoods have resulted from the Habitat Management Plan which has been implemented since construction of Unit 1. The distribution of animal communities on site reflects the variety of site conditions. Primarily upland species may utilize a variety of habitat types. The cypress strand wetlands on site provide habitat requirements for a wide array of wildlife species. Animal species found on the Stanton site include game animals and resident fur-producing species. Common small game species of wildlife consist of bobwhite quail, mourning dove, cottontail rabbit, marsh rabbit and gray squirrel. Populations of white-tailed deer and feral swine are present in much of the area and some adjoining lands. The land seasonally attracts a few migratory species. A wide selection of fur-bearing mammal species occur on the site. The endangered wood stork (Mycteria americana), the only American representative of the stork family, is a large white bird locally common in southern swamps, freshwater marshes and ponds. Its primary foods are fish, frog, young alligators and other aquatic animals. Wood storks have been observed on site. Red-cockaded woodpeckers (Picoides borealis) are characterized as inhabiting mature, open pine forest. Several trees on site have nest cavities of the red-cockaded woodpeckers. Prior to construction of Unit 1, surveys of the Stanton site revealed a total of 45 active cavity trees and 35 red-cockaded woodpeckers in the vicinity of the proposed project. Once the presence of the birds was known, the plant site layout was revised to preserve as many cavity trees and as much foraging habitat as possible, although two clans left the area following the construction of Unit 1. Nine clans occurred on the site in 1981 and six clans now live on the site, with others located nearby. One active cavity tree was to be removed for Unit 1 development. No other active trees are destined to be removed for ultimate site development. A management/study plan was developed for the purpose of minimizing and assessing impacts on woodpeckers. OUC has implemented the management plan for the red-cockaded woodpecker. The threatened Florida scrub jay (Aphelocoma c. cocrulescens) is characteristic of oak scrub communities and is confined mainly to such habitats. The range of this subspecies is restricted to peninsular Florida, primarily along the east coast with scattered populations in the central portion and western coastline of Florida. The Florida scrub jay has been observed on the southwest portion of the property. No activities are proposed in this area and no impact to this species is anticipated. Scrub habitat found along the southern portion of the transmission corridor south of the Bee Line was surveyed and no scrub jays were found. The threatened eastern indigo snake (Drymarchon corais) occurs in peninsular Florida, in a few widely scattered areas of the Georgia Coastal Plain, and in parts of the Florida panhandle. This snake occupies a wide variety of habitat types. Indigo snakes have been observed on site. The gopher tortoise (Gopherus polyphemus), a species of special concern, is commonly encountered in central Florida. On-site populations of gopher tortoise are centered mainly on the higher elevation in the western and south-central portion of the property. No impacts to the gopher tortoise are anticipated as a result of the construction, including the clearing, of the transmission line corridor. No tortoises occur within the alternate access road corridor. The proposed transmission line corridor follows the existing railroad corridor from the site to the existing OUC transmission line 7-0615 near Mud Lake southeast of Orlando International Airport. The corridor was surveyed in 1982 and in the summer of 1991 for the presence of threatened and endangered species. One sandhill crane nest was observed within the corridor. Construction activities in the vicinity of the known sandhill crane nest will be arranged and scheduled to avoid any adverse impacts to this nest. Air Quality Issues. The only new air emission point for Unit 2 will be the 550-foot chimney. This source was previously evaluated with regard to its effect on air quality and is included as an approved source in a Prevention of Significant Deterioration (PSD) permit issued by the U.S. Environmental Protection Agency for the project (Units 1 and 2) during the initial permitting process that commenced in 1981. However, because combustion parameters and emissions rates for Unit 2 have been revised, an additional review has verified that air quality impacts remain below all applicable PSD increments and ambient air quality standards. The air quality impact analysis required by the PSD regulations include: an analysis of existing air quality; a PSD increment analysis (NOx, PM and SO2 only); an Ambient Air Quality Standards (AAQS) analysis; an analysis of impacts on soils, vegeta- tion, and visibility and of growth-related air quality impacts; a "Good Engineering Practice" (GEP) stack height determination. The analysis of existing air quality generally relies on pre- construction monitoring data collected with EPA-approved methods. The AAQS analysis depends on the air quality dispersion modeling carried out in accordance with EPA guidelines. Based on these required analyses, there is reasonable assurance that the proposed facility, as subject to the applicable conditions of certification, will not cause or contribute to violation of any PSD increment or ambient air quality standard. The PSD increment represents the amount that new sources in an area may increase ambient ground-level concentrations of a given pollutant. The purpose of these increment limitations is to prevent areas which currently have good air quality from being significantly degraded. If an area currently has ambient concentrations near the ambient air quality standards for NO2, PM or SO2, the increased emissions from new sources must not cause or contribute to a violation of the ambient air quality standard and the allowed increments would be reduced to prevent such exceedances. The Stanton site is located in a Class II area and must meet the increments defined for this class. The nearest Class I area (Chassahowitzka National Wilderness Area) is about 130 kilometers west of the site. Stanton is not expected to influence this Class I area. All of the emissions of NO2, PM and SO2 at Stanton will consume Class II increments. No other sources near Stanton have been identified which would be expected to significantly affect increment consumption in the area of the Stanton Site. Air modeling results indicate that Stanton does not contribute to a violation of the PSD Class II increments. Of the pollutants subject to review, only CO, NO2, PM, SO2 and ozone have AAQS with which to compare. In general, the total ambient air quality impact for each pollutant is obtained by adding the estimated background concentration to the maximum predicted modeled concentrations of the proposed facility and other modeled background sources. Ozone is a photochemically formed pollutant resulting mainly from motor vehicle emissions. The regulated pollutant for ozone formation is volatile organic compounds (VOC) which cannot be modeled for source-specific applications. Ozone, by way of VOC's, is regulated through BACT. Given existing air quality in the area of the proposed facility, emissions from Stanton are not expected to cause or contribute to a violation of any AAQS. Impacts on soils, vegetation, visibility and growth-related air quality impacts are not expected to change from the original OUC's proposal. This project does not change the original GEP stack height. BACT Determination Considerations. DER's BACT determination is based on the maximum degree of reduction of each pollutant emitted which the Department, on a case-by-case basis, taking into account energy, environmental and economic impacts and other costs, determines is achievable through application of production processes and available methods, systems, and techniques. In addition, Department BACT regulations require the Department to give consideration to any Environmental Protection Agency determination of Best Available Control Technology pursuant to Section 169, and any emission limitation contained in 40 CFR Part 60 (Standards of Performance for New Stationary Sources) or 40 CFR Part 61 (National Emission Standards for Hazardous Air Pollutants), and to: All scientific, engineering and technical material and other information available to the Department; The emission limiting standards or BACT determinations of any other state; and The social and economic impact of the application of such technology. The EPA currently stresses that BACT should be determined using the "top-down" approach. The first step in this approach is to determine for the emission source in question the most stringent control available for a similar or identical source or source category. If it is shown that this level of control is technically or economically infeasible for the source in question, the next most stringent level of control is determined and similarly evaluated. This process continues until the BACT level under consideration cannot be eliminated by any substantial or unique technical, environmental or economic objections. The air pollutant emissions from coal-fired power plants can be grouped into categories based upon what control equipment and techniques are available to control emissions from these facilities. Using this approach, the emissions can be classified as follows: Combustion Products (e.g., Particulates). Controlled generally by good combustion of clean fuels and baghouse filters or electrostatic precipitators (ESP); Products of Incomplete Combustion (e.g., CO). Controlled generally by proper combustion techniques; and Acid Gases (e.g., NOx). Controlled generally by gaseous control devices. Grouping the pollutants in this manner facilitates the BACT analysis because it enables the equipment available to control the type or group of pollutants emitted and the corresponding energy, economic and environmental impacts to be examined on a common basis. Although all of the pollutants addressed in the BACT analysis may be subject to a specific emission limiting standard as a result of PSD review, the control of "nonregulated" (noncriteria) air pollutants is considered in imposing a more stringent BACT limit on a "regulated" (criteria) pollutant (i.e., particulates, sulfur dioxide, fluorides, sulfuric acid mist, etc.), if a reduction in "nonregulated" air pollutants can be directly attributed to the control device selected as BACT for the abatement of the "regulated" pollutants. Unit 2's major combustion equipment will consist of a pulverized coal (PC) boiler. The PC boiler will be started on No. 6 fuel oil and use No. 6 fuel oil for flame stabilization during low load operation. The PC boiler is rated at 3,305 MMBTU/hr. and has a maximum heat input of 4,286 MMBTU/hr. OUC has indicated the maximum annual tonnage of regulated air pollutants expected to be emitted from the facility based in 100 percent capacity to be as follows: PSD Significant Emissions Potential Emissions (tons/yr.) PC Boiler (tons/yr.) NOx 5943 40 SO2 6008 40 PM 375 25 PM10 375 15 CO 2816 100 VOC 282 40 H2SO4 653 7 BE 0.039 0.0004 Hg 0.041 0.1 Pb 0.701 0.6 Fluorides 1.58 3 Florida Administrative Code Rule 17-2.500(5)(c) requires a BACT review for all regulated pollutants emitted in an amount equal to or greater than the significant emission rates listed in the previous table. The BACT requirements are intended to ensure that a proposed facility will incorporate air pollution control systems that reflect the latest techniques (including fuel cleaning or treatment or innovative fuel combustion) used in the particular industry. An evaluation of the air pollution control techniques and systems is required, including a consideration for energy requirements, environmental and economic impact. The appropriate best available control technology (BACT) emission rates for criteria pollutants for Stanton Unit 2 are shown on the following table: Sulfur Dioxide, lb/MBtu 30-day rolling average 0.25 24-hour emission rate 0.67 3-hour emission rate 0.85 Nitrogen Oxides lb/MBtu 30-day rolling average 0.17 Particulate Matter, lb/MBtu TSP 0.02 PM10 0.02 VOC, lb/MBtu 0.015 Carbon Monoxide, lb/MBtu 0.15 The BACT emission rates for non-criteria pollutants are shown on the following table: H2SO4, lb/MBtu 3.3 x 10-2 Be, lb/MBtu 5.2 x 10-6 Hg, lb/MBtu 1.1 x 10-5 Pb, lb/MBtu 1.5 x 10-4 Fluoride, lb/MBtu 4.2 x 10-4 Air emission considerations. The cause-effect-control relationship concerning air and pollutant emissions and the entire phenomenon of acid deposition or "acid rain" is extremely complex. Stanton Unit 2 will have less adverse impact upon air quality than other coal fueled units in the state which do not employ sulfur- dioxide (SO2) and nitrogen-oxides (NOx) emission controls that are as stringent as those required for Stanton Unit 2 to meet BACT emission limits. Stanton Unit 2 will utilize a flue-gas desulfurization system which includes wet limestone scrubber for control of sulfur dioxide emissions. Use of scrubbers and NOx control technologies represent practical and effective means of minimizing the contribution from Unit 2 to rain fall acidification. Given the location of the plant and the advanced air emission controls that will be utilized at Stanton Unit 2, this plant will not significantly contribute to acid rain or acid deposition in Florida. Potential adverse health effects of the criteria air pollutants expected to be emitted by Unit 2 have been analyzed utilizing the total expected concentrations of sulfur dioxide, nitrogen oxides, particulates and carbon monoxide. These concentrations were determined by adding together the maximum predicted impacts for both Stanton plants with measured, historical background concentrations. The resulting air levels are all below the Florida Ambient Air Quality Standard values and are not expected to adversely affect human health. The maximum levels of SO2 in the ambient air are predicted to be 17.2, 106.8, and 642.4 ug/m3 for annual, 24-hour and 3-hour averaging periods, respectively. These are total expected concentrations determined by adding the modeled Stanton impacts with the existing background concentrations. These levels are below the Florida AAQS of 60, 260, and 1,300 ug/m3 for annual, 24- hour and 3-hour values. These concentrations are also below levels at which any clinically evident health effects, such as shortness of breath or wheezing, have been demonstrated in laboratory tests in normal individuals or in sensitive individuals, including asthmatics, during exercise. The annual and 24-hour concentrations are less than those levels shown to have deleterious health effects during longer term epidemiology studies that are relevant to those averaging period. The annual and 24-hour total expected PM10 concentrations are 42 and 128 ug/m3. These levels are below the Florida AAQS values for annual and 24- hour averaging periods of 50 and 150 ug/m3. The annual total expected PM10 concentration of 42 ug/m3 is below the level associated with health effects in epidemiology studies comparing different annual particulate levels in different cities. The 24-hour total expected particulate level of 128.0 ug/m3 is below the level resulting in clinically significant symptoms, such as shortness of breath or wheezing in asthmatics during exercise. The 24-hour level of 128.0 ug/m3 is also below levels at which most studies on sensitive asthmatics have found changes in laboratory measures of lung function. 90 The annual total expected concentration of NOx is 26.0 ug/m3, which is well below the Florida AAQS of 100 ug/m3. The maximum predicted impact only contributes 2 ug/m3, and background contributes 24 ug/m3 to this value. This total expected concentration has not been found to produce health effects in epidemiology studies of long term NO2 exposures in children. A level of 26 ug/m3 is also well below the lowest dose at which minimal effects have been found in short term studies in sensitive subjects with asthma, chronic bronchitis and chronic obstructive pulmonary disease (emphysema). The total expected concentrations of carbon monoxide are 31.0 and 106.4 ug/m3 for eight- and one-hour average periods, respectively, and are well below the Florida AAQS of 10,000 and 40,000 ug/m3. These values are also well below the level expected to cause any significant health effects. Carbon monoxide causes the production of carboxyhemoglobin, which is normally in the blood at 0.5% as a result of metabolism. Exposure to these maximum expected levels of CO would yield an insignificant increase in the normally present amount of carboxyhemoglobin. Certain trace elements exist in coal which can be released when the coal is burned. Those trace elements that remain in particulate form will be effectively removed from the flue gas by the electrostatic precipitator. Those trace elements that are volatilized in the boiler will be largely removed by the cooling of the flue gas in the scrubber and the subsequent of these elements after they have condensed on the fly ash particles. Other toxic air emissions are primarily prevented from forming by the complete combustion of the fuel. Water use considerations. Water used at the Stanton Energy Center will come from three sources: the Orange County Easterly Subregional Wastewater Treatment Plant, wells and rain. The majority of the water will be used as make-up to the cooling towers. Cooling tower make-up will be primarily treated sewage effluent, up to 10.19 million gallons per day (MGD) for both units from the Orange County treatment plant, plus collected reuse water, site runoff and direct precipitation on the make-up water supply storage pond. A maximum of 2 MGD of well water from the Floridan aquifer is used for potable water, general plant uses and steam cycle make-up. Yearly use of the aquifer may not exceed 321 million gallons. The well water comes from two 850 gallons per minute (gpm) capacity on-site wells that pump from the Floridan aquifer. The well water is pumped directly to a solids contact unit for treatment by aeration, lime softening, filtration and chlorination. Unit 1 operations require withdrawal of 305 gpm from two existing Floridan aquifer wells. The construction of Unit 2 will require the pumping of those wells at the rate of 611 gpm for a daily average consumption of 879,840 gallons. The proposed consumptive uses represent quantities of water which are necessary for economic and efficient utilization because: The water will be used for household (or potable) dewatering and power production purposes, which are recognized classes of water use; Under current technology and economics, the proposed consumptive use amounts are reasonable for the purposes intended; and The plant, a "zero discharge" facility, employs many current water- saving technologies, in that once water enters the facility, it is recirculated and recycled in a number of processes to reduce quantities used; and the water is needed in order to meet electric power demands. The proposed consumptive uses are for a purpose that is both reasonable and consistent with the public interest because: The water will be put to a variety of purposes, all of which fit into accepted classes of use; Lower quality water in the form of treated sewage effluent, reuse water and stormwater will be employed for cooling purposes; and Water will be supplied to generate needed power. The known characteristics of the aquifer, the results of the 48-hour constant rate discharge pump test performed on each of the two existing Floridan aquifer wells with a withdrawal rate greater than the proposed consumptive use, as well as the fact that these wells have been supplying water for years without experiencing production problems, establish that the Floridan aquifer here is capable of producing the proposed consumptive use amounts. The projected effluent quantities from the Orange County Easterly Subregional Wastewater Treatment Plant, stormwater runoff and on-site reuse water are sufficient to supply the facility's cooling water needs. The proposed consumptive uses of water will not seriously harm the sources of the water and will not cause significant saline water intrusion or encroachment, will not result in any unacceptable amount of economic or environmental harm and will not interfere with any presently existing legal use of water because: The drawdown effects due to the proposed consumptive use withdrawals on the Floridan aquifer were predicted utilizing the U.S. Geological Survey MODFLOW model. The proposed reduction in the surficial aquifer due to construction dewatering on the plant site was also analyzed. These analyses of the proposed groundwater consumptive use withdrawals showed limited drawdowns and that the radius of influence of these withdrawals will not extend beyond the boundaries of the facility. Based on currently available data, the proposed consumptive uses are not predicted to cause interference with other water users or result in other adverse economic impacts; and There is no known water quality or saline water intrusion or encroachment problem in the aquifers on-site. Based on current water quality data and the above-referenced hydrologic modeling, the proposed consumptive uses are not predicted to cause a water quality or saline water intrusion problem. OUC has submitted and will implement a water conservation plan. The Stanton facility now utilizes currently available conservation, recycling and reuse measures which are economically, environmentally and technologically feasible. OUC will utilize available treated sewage effluent in an average annual allocated amount of 10.19 million gallons/day for cooling tower make-up water needed for Stanton Units 1 and 2 from the Orange County Easterly Wastewater Treatment Facility. Effluent from the on-site treatment facility will also be used for this cooling purpose. The proposed consumptive uses of water utilize the lowest acceptable quality water source which is currently available and currently economically, environmentally and technologically feasible. No flooding damage will result from or be contributed to by the proposed consumptive uses because no wastewater from the plant use or dewatering will be discharged from the site. The proposed consumptive uses will cause no serious harm to any receiving body of water. The applicants will monitor withdrawals of water through metering devices. The SJRWMD Governing Board has not reserved water from use pursuant to Section 373.223(3), Florida Statutes. The SJRWMD and OUC entered into a Stipulation agreeing, with one exception, to the imposition of conditions of certification that will ensure that OUC's water withdrawal will be in compliance with Chapter 373, Florida Statutes, and Chapter 40C-2 F.A.C. SJRWMD proposed the following condition which is opposed by OUC: Condition 7: During the tenth year following issuance of this certification order, OUC, et al., shall submit a report to SJRWMD and DER demonstrating compliance with these conditions of certification, Chapter 373, Florida Statutes, and the rules of SJRWMD and DER, applicable to the consumptive use of water. Compliance shall be demonstrated with rules and statutory provisions in effect at that time. SJRWMD shall evaluate the report and notify DER in a report of any issues regarding compliance with this certification and applicable rules and statutory provisions, including whether the consumptive use of water complies with those provisions of Chapter 373, Florida Statutes, and DER's and SJRWMD's rules applicable to consumptive use and whether any conditions of certification must be amended, added, or deleted in order to insure compliance with the referenced rules and statutory provisions. SJRWMD shall respond within 30 days of receipt of OUC, et al.'s report as to whether or not it contains information sufficient to make a determination as to compliance with the referenced rules and statutory provisions. Thereafter, DER shall notify OUC, et al., and SJRWMD as to its determination concerning sufficiency. SJRWMD shall file its report within ninety (90) days after DER's determination that OUC, et al.'s report is sufficient. Section 40C-1.610, Florida Administrative Code, shall apply. An opportunity for hearing pursuant to Section 120.57, Florida Statutes, shall be afforded any party. In any hearing requested pursuant to this condition of certification, the burden of demonstrating compliance shall be on OUC, et al. The continued consumptive use of water for the Stanton Energy Center Unit 2, shall be dependent upon OUC, et al., demonstrating and presenting sufficient data to establish that its consumptive use meets the referenced rules and statutory provisions. The Board hereby delegates to the Secretary the authority to enter final orders regarding this condition in the event an administrative hearing is requested. SJRWMD asserts that its proposed condition is based on the regulatory standards found in Section 6.5.1, Applicants Handbook: Consumptive Uses of Water (A.H.) and Section 373.236, Florida Statutes. SJRWMD believes that the proposed condition 7 is necessary for the following reasons: Section 6.5.1, A.H., sets forth a 10-year duration for consumptive use allocations where the applicant derives 50% or more of their total allocation from reclaimed water or stormwater. Water technology is constantly changing and improving. Water which is no longer needed by the applicant as a result of such changes and improvements could be allocated to other uses. Economic conditions change over time. As water becomes increasingly scarce and the demand for it increases, it is possible that even lower quality waters may be required to be used for this power plant. Knowledge about the water resource is continually improving. Knowledge gained in the future may change SJRWMD's ability to predict and allocate water. In order to allocate the water resource consistently with the public interest, the allocating agency needs to have the capability to require a user to periodically re-establish that its uses are not harming the water source or receiving water, are utilizing the must efficient and water-conserving technology, and are not impacting other users or land uses. The wording of condition 7 and the testimony of Mr. Jeffrey Elledge, Director of the SJRWMD's Department of Resource Management, makes it clear that under the proposed condition, after ten years the burden would be upon OUC to file a report with DER and SJRWMD demonstrating that OUC's continued consumptive use of water is still consistent with the criteria in Chapter 373, Florida Statutes, and the District's rules in effect at that time. The District maintained that a review of the consumptive use of water by OUC after ten years is needed "to reevaluate the use periodically . . . to make sure that they are still efficient and still in the public interest." SJRWMD has issued water allocations and consumptive use permits to approximately 4000 consumptive water users. These allocations include public water supply, agricultural, industrial, and commercial uses. Each allocation has been for a specific duration. Since the passage of the Power Plant Siting Act in 1973, at least thirty power plants have been certified. Of these, only one, Cedar Bay, has had a time limitation on its consumptive water use allocation. Cedar Bay is a private company and it voluntarily accepted a condition of certification similar to condition 7. There is no consumptive use time limitation which was approved through the certification process for Unit 1. The other certified power plants in SJRWMD's jurisdiction do not have time limitations on their consumptive use of water. In fact, other than in Cedar Bay, the issue of duration for a consumptive use allocation has never been raised and contested in any other power plant certification proceeding. Mr. Elledge acknowledged that SJRWMD's interpretation of and intention in condition 7 is that OUC's ten year water allocation would be reviewed, with the burden being on OUC to convince the District and DER that the rule criteria would be met for the duration of the next allocation. If the burden was not satisfied, the allocation for Unit 2 could be totally rescinded. Although the condition uses the term "report" for the documentation which OUC would have to file, in fact the "report" is the procedural equivalent of a permit renewal application. Without the granting of that renewal, OUC would not have the authorization for further water use. The parties have agreed to conditions of certification which adequately protect other current and future water users in the event of water shortages and unforeseen impacts to existing users, adjacent land uses, and water quality. These conditions are adequate to address the nonprocedural requirements and the concerns of SJRWMD which are summarized above in Finding of Fact 107. Solid waste considerations. Solid waste is generated from a number of sources at the Stanton power plant. The largest quantity of solid wastes produced by the operation of the plant is sludge generated by the flue gas desulfurization (FGD) system. Coal combustion ash, in the form of fly ash and bottom ash, is the other major solid waste. Collectively, FGD waste and coal ash are referred to as "high volume solid wastes." Other comparatively small quantities of solid wastes, generated on an infrequent basis by the operation of the plant, include sludge from the sedimentation pond, retention basin, cooling towers and wastewater treatment facilities. Ash is the residue produced by the combustion of coal. It consists of the unburned organic matter and inorganic mineral constituents present in the coal. The quantity and chemical characteristics of ash depend on the coal, boiler operating conditions and air pollution control devices, among others. Two types of ash are produced during combustion - fly ash and bottom ash. Fly ash consists of the finer particles that are entrained in the flue gas stream. Bottom ash is the courser, heavier material that accumulates in the furnace bottom in the form of a loose ash or slag. Approximately 447,000 tons of bottom ash are expected to be generated over the life of the plant. Maximum rate of production of bottom ash is expected to be about 17 tons/hour for each unit. Fly ash and boiler hopper ash will be generated at a maximum rate of about 48,400 tons/year for each unit. Approximately 1.45 million tons of fly ash will be generated over the life of the plant. For the proposed Unit 2 wet limestone FGD scrubber, the sulfur dioxide in the flue gas reacts with the limestone slurry producing a waste which must be removed. The maximum rate of production of FGD sludge for the unit is estimated at about 201,000 tons/year. Total wastes produced over the life of the plant will be approximately 6.03 million tons. Periodic removal of sediments from the sedimentation pond also generates a solid waste. Due to the number of variables involved, such as rainfall frequency and duration, concentration of suspended solids in the influent, etc., quantities are difficult to predict. Frequency of sediment removal is approximately once per year. Solids removed are mainly coal dust and ash. Cooling towers are expected to be drained approximately once per year and the accumulated solids removed. The solids will contain suspended solids from the make-up water and particulates from the atmosphere. Based on ground water monitoring data, the concentrations of dissolved constituents in groundwater from the waste disposal area beyond all site boundaries does not exceed Florida Class I-B water quality standards for the inorganic constituents and does not exceed U.S. EPA secondary drinking water standards within the unconfined Hawthorn and Floridan aquifer systems beyond the site boundary. The construction and operation of Unit 2 will not adversely change these existing conditions beyond the site boundaries. Construction impacts. Site clearing necessary for the construction of Unit 2 power block was done in connection with Unit 1. The Alafaya Trail, which provides access from State Road 50, was paved during construction of Unit 1. No impacts along Alafaya Trail will result from construction of Unit 2. Construction waste materials will be disposed of in accordance with applicable Conditions of Certification, rules and regulations. General waste materials will be disposed of in dumpsters for collection and disposal at the county landfill adjacent to the site or other suitable and approved local landfill areas. Impacts are expected from the construction of the transmission line with an unpaved access road and alternate access road. These include the filling of wetlands and the clearing of uplands and wetlands on the plant site and within the existing certified corridor for the access roads and transmission line. The construction of the existing rail spur from the plant site to the CSX mainline converted land from its original use along its 18-mile length. This corridor will be used for the new 230 kV transmission line and access roads. Wetland impacts include the filling of wetlands (regulated by SJRWMD, SFWMD and DER) and the clearing of wetlands, 13.19 acres of which are DER jurisdictional. These wetlands vary in quality from cattail (Typha spp.) monocultural areas, swales and ditches adjacent to the existing cooling water reservoir, to cypress domes and mixed hardwood forests. Mitigation for these projected impacts has been proposed by OUC in the form of enhancement of wetlands located on the site through planting of forested wetland species and proposed reestablishment of "natural" hydroperiod to selected wetland stands, proposed creation of herbaceous wetlands and the proposed enhancement of upland buffers and upland habitats through the planting of longleaf pine forests. Mitigation for the projected impacts from the transmission line and the transmission line access road within the South Florida Water Management District (SFWMD) jurisdiction has been proposed by OUC in the form of wetlands creation within the transmission line right-of-way, enhancement of wetlands located on the OUC plant site through the planting of forested wetland species, the reestablishment of "natural" hydroperiod to selected wetland stands, creation of herbaceous wetlands and the enhancement of upland buffers and sensitive upland buffers and sensitive upland habitats through the planting of longleaf pine forests. Neither DER nor the SFWMD has reviewed or approved final construction plans for this proposed mitigation; both agree that the plan is feasible, appropriate in concept and capable of being approved after certification with the submission to DER and SFWMD by OUC of sufficient additional details and plans following certification. The primary construction effects on upland areas will be clearing of some forested areas to accommodate the transmission line installation and construction of the access roads. Following clearing, the land under the transmission line can continue to be used for wildlife habitat or agricultural uses where such uses currently exist. A small segment of an orange grove will be crossed, but no clearing will be done there and fruit production will not be affected. The new transmission facilities should cause little inconvenience to the adjacent landowners since the land may continue to be used as it has in the past. The planned facilities also will not change traffic patterns from those already existing. Right-of-way clearing will affect existing vegetation. Upland habitat provided by trees and other vegetation will be reduced along the six miles of expanded transmission corridor. Of course, the cleared areas will continue to be utilized by some wildlife. Deer, birds and small mammals are often seen in these areas. Growth retardants, chemicals, biocides, sprays, etc., will not be used during construction. If recommended conditions are followed, no significant erosion is anticipated because of the construction of the new transmission line facilities. The construction techniques used will be similar to those utilized previously in Florida to construct transmission facilities. As outlined in the application, construction procedures, including runoff control facilities and practices to avoid contamination of state waters, will be implemented. The construction site is isolated from the general public by appropriate means which include fences and guards. Compliance with OSHA standards and the provisions of Section 440.56, Florida Statutes, should adequately protect construction workers and operating personnel. Comprehensive plan considerations. The Department of Community Affairs concluded as a result of its overall evaluation of the consistency of the Stanton Energy Center Unit 2 with the state comprehensive plan that the power plant was consistent with the state comprehensive plan and should be certified with appropriate conditions of certification. The construction and operation of Stanton Unit 2 will be consistent with the state comprehensive plan (Chapter 187, Florida Statutes), the Orange County Plan and the East Central Florida Regional Policy Plan. Noise impacts. There are no applicable federal, state or local laws, regulations or ordinances that govern the permittable noise levels in the vicinity of the Stanton Energy Center that will be caused by the proposed construction and operation of Stanton Unit 2. Both the State of Florida and the U.S. Environmental Protection Agency have recommended noise guidelines, both of which recommend a 24-hour equivalent noise level of 55 DBA or less in outdoor areas where people spend varying amounts of time. This recommended community noise level should ensure that there is no annoyance or interference with outdoor activities. Because the majority of site clearing and preparation for Stanton Unit 2 was completed during construction of Unit 1, the noise impacts of Unit 2 construction will be lower than the noise impacts caused during construction of Unit 1. The estimated average construction noise impacts for Unit 2 are below the 55 DBA level at the site boundaries. Therefore, the estimated construction noise impacts will not be significant to the closest residential land uses, which are well beyond the Stanton Energy Center site boundaries. The off-site noise impacts from the operation of Unit 2 equipment will result in an increase to the existing ambient noise level of approximately 2 DBA. A 2 DBA increase in noise is not noticeable to the average person. No area outside of the Stanton Energy Center site boundary will have noise impacts that exceed 55 DBA. Therefore, the expected noise impacts resulting from the operation of Stanton Unit 2 will be insignificant. Regional economic impacts. The local Orlando economy (defined as Orange County, Lake County, Osceola County, and Seminole County) will realize significant and positive, direct regional economic benefits due to the construction and operation of Stanton 2. Direct economic benefits realized by the local Orlando economy due to the construction of Unit 2 include approximately 1,863 man-years of employment, $25.1 million in local supply and material purchases, and $91.8 million (1991 dollars) of construction expenditures. Direct annual economic benefits realized by the local Orlando economy due to the operation of Stanton 2 include approximately $7.0 million (1990 dollars) in fixed operation and maintenance (O&M) expenditures and capital addition expenditures, and a Stanton 2 work force of 85 persons. In addition to the direct economic benefits, the local Orlando economy will also realize indirect economic benefits through output, employment and earnings multiplier effects. Total (direct and indirect) Stanton 2 construction economic impacts include approximately 3,878 man-years of employment, $181.6 million (1991 dollars) in earnings and $49.5 million (1991 dollars) in output. Total annual Stanton 2 operational (arising from fixed O&M and capital additions) economic impacts include approximately 263 man-years of employment, $7.7 million (1990 dollars) in earnings, and $9.7 (1990 dollars) in local output.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is hereby recommended that the Governor and Cabinet, sitting as the Siting Board, enter a Final Order granting a supplemental site certification for Unit 2 and the associated facilities of the Curtis H. Stanton Energy Center, subject to the Conditions of Certification contained in Appendix A. RECOMMENDED this 15th day of November, 1991, at Tallahassee, Florida. DIANE K. KIESLING, Hearing Officer Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 SC 278-9675 Filed with the Clerk of the Division of Administrative Hearings this 15th day of November, 1991. APPENDIX A TO RECOMMENDED ORDER, CASE NO. 91-1813EPP STATE OF FLORIDA DEPARTMENT OF ENVIRONMENTAL REGULATION ORLANDO UTILITIES COMMISSION CURTIS H. STANTON ENERGY CENTER UNIT 2 PA 81-14/SA1 SUPPLEMENTAL CONDITIONS OF CERTIFICATION TABLE OF CONTENTS PART I I/I ENTITLEMENT . . . . . . . . . . . . . . . . . . . . 1 I/II SCOPE OF LICENSE . . . . . . . . . . . . . . . . . . 1 I/III JURISDICTIONAL AGENCIES . . . . . . . . . . . . . . 1 I/IV DEFINITIONS . . . . . . . . . . . . . . . . . . . . 2 I/V TRANSFER OF CERTIFICATION . . . . . . . . . . . . . 2 I/VI SEVERABILITY . . . . . . . . . . . . . . . . . . . . 2 I/VII PROFESSIONAL CERTIFICATION . . . . . . . . . . . . . 3 I/VIII RIGHT OF ENTRY . . . . . . . . . . . . . . . . . . . 3 I/IX DESIGN STANDARDS . . . . . . . . . . . . . . . . . . 3 I/X LIABILITY . . . . . . . . . . . . . . . . . . . . . 3 I/XI PROPERTY RIGHTS . . . . . . . . . . . . . . . . . . 4 I/XII COMPLIANCE . . . . . . . . . . . . . . . . . . . . . 4 I/XIII POST-CERTIFICATION REVIEW . . . . . . . . . . . . . 5 I/XIV COMMENCEMENT OF CONSTRUCTION . . . . . . . . . . . . 6 I/XV COMMENCEMENT OF OPERATION . . . . . . . . . . . . . 6 I/XVI OPERATIONAL CONTINGENCY PLANS . . . . . . . . . . . 6 I/XVII REVOCATION OR SUSPENSION . . . . . . . . . . . . . . 7 I/XVIII CIVIL AND CRIMINAL LIABILITY . . . . . . . . . . . . 7 I/XIX ENFORCEMENT . . . . . . . . . . . . . . . . . . . . 7 I/XX FIVE YEAR REVIEW . . . . . . . . . . . . . . . . . . 7 I/XXI MODIFICATION OF CONDITIONS . . . . . . . . . . . . . 7 PART II II/I AIR . . . . . . . . . . . . . . . . . . . . . . . . 9 II/II WETLANDS RESOURCE MANAGEMENT . . . . . . . . . . . . 17 II/III ELECTRIC AND MAGNETIC FIELDS . . . . . . . . . . . . 19 II/IV OTHER . . . . . . . . . . . . . . . . . . . . . . . 19 PART III III/I WILDLIFE SURVEY . . . . . . . . . . . . . . . . . . 20 III/II NESTING SANDHILL CRANES . . . . . . . . . . . . . . 20 III/III MANAGEMENT PLAN . . . . . . . . . . . . . . . . . . 20 PART IV IV/I LEGAL/ADMINISTRATIVE CONDITIONS . . . . . . . . . . 21 IV/II SURFACE WATER MANAGEMENT CONDITIONS . . . . . . . . 23 IV/III ENVIRONMENTAL CONDITIONS . . . . . . . . . . . . . . 26 PART V V/I WATER SHORTAGES . . . . . . . . . . . . . . . . . . 30 V/II WELL CONSTRUCTION, MODIFICATION, OR ABANDONMENT . . 30 V/III WELL MAINTENANCE . . . . . . . . . . . . . . . . . . 30 V/IV MITIGATION OF WITHDRAWAL IMPACTS ON EXISTING LEGAL USERS . . . . . . . . . . . . . . . . . . . . 30 V/V MITIGATION OF IMPACTS ON ADJACENT LAND USES . . . . 31 V/VI IDENTIFICATION TAGS . . . . . . . . . . . . . . . . 31 V/VII MAXIMUM ANNUAL WITHDRAWALS . . . . . . . . . . . . . 31 V/VIII MAXIMUM DAILY WITHDRAWALS . . . . . . . . . . . . . 31 V/IX LIMITATION ON USE OF WATER . . . . . . . . . . . . . 31 V/X DEWATERING . . . . . . . . . . . . . . . . . . . . . 32 V/XI OFF-SITE DISCHARGES . . . . . . . . . . . . . . . . 32 V/XII DISCHARGES FROM MAKE-UP WATER SUPPLY POND . . . . . 32 V/XIII WELL WATER QUALITY SAMPLING . . . . . . . . . . . . 32 V/XIV WATER TREATMENT PLANT REPORTS . . . . . . . . . . . 33 V/XV WELL WATER FLOW MONITORING . . . . . . . . . . . . . 33 V/XVI CONSERVATION PLAN . . . . . . . . . . . . . . . . . 33 V/XVII WELL WATER FLOW METERS . . . . . . . . . . . . . . . 33 V/XVIII CALIBRATION OF FLOW METERS . . . . . . . . . . . . . 33 V/XIX MAINTENANCE OF FLOW METERS . . . . . . . . . . . . . 33 V/XX DELINEATION OF LIMITS OF CONSTRUCTION . . . . . . . 33 V/XXI BACKGROUND ASSESSMENT PLAN . . . . . . . . . . . . . 34 V/XXII COMPLETION OF BACKGROUND ASSESSMENT . . . . . . . . 34 V/XXIII INITIATION AND COMPLETION OF ENHANCEMENT MITIGATION PLAN . . . . . . . . . . . . . . . . . . .34 V/XXIV CRITERIA FOR SUCCESS OF ENHANCEMENT AND MITIGATION . . . . . . . . . . . . . . . . . . . . . 34 V/XXV MONITORING PLAN FOR ENHANCEMENT AND MITIGATION . . . 34 V/XXVI SURVEY OF ENHANCEMENT AREAS . . . . . . . . . . . . .35 V/XXVII MONITORING REPORTS FOR THE ENHANCEMENT AND MITIGATION AREAS . . . . . . . . . . . . . . . . . . 35 V/XXVIII REVISIONS TO ENHANCEMENT AND MITIGATION . . . . . . 35 V/XXIX EROSION AND SEDIMENT CONTROL DURING CONSTRUCTION . . 36 V/XXX EROSION AND SEDIMENT CONTROL DURING OPERATION . . . 36 V/XXXI INCORPORATION OF MITIGATION PLAN . . . . . . . . . . 36 V/XXXII COMPLETION OF SURFACE WATER MANAGEMENT SYSTEM . . . 36 V/XXXIII RETENTION/DETENTION STORAGE AREAS . . . . . . . . . 36 V/XXXIV ACCESS ROAD AND TRANSMISSION LINE CONSTRUCTION PLANS . . . . . . . . . . . . . . . . . 37 V/XXXV ACCESS ROAD FILL . . . . . . . . . . . . . . . . . . 37 V/XXXVI CONTRACTOR REVIEW AND POSTING OF CONDITIONS OF CERTIFICATION . . . . . . . . . . . . . . . . . . . 37 VI/I PART VI CONSTRUCTION IMPACT MITIGATION PROGRAM . . . . . . . 38 PART VII VII/I RED-COCKADED WOODPECKER MANAGEMENT AREA IDENTIFICATION . . . . . . . . . . . . . . . . . . 39 VII/II USE AND LIMITATIONS OF THE RCW AREA . . . . . . . . 39 SUPPLEMENTAL CONDITIONS OF CERTIFICATION (COCs) PART I Administrative Conditions I/I. ENTITLEMENT Pursuant to s. 403.501-519, F.S., the Florida Electrical Power Plant Siting Act, this certification is issued to Orlando Utilities Commission, Florida Municipal Power Agency, and Kissimmee Utility Authority as joint owner/operators of Curtis H. Stanton Unit 2. I/II. SCOPE OF LICENSE Certification has previously been issued by the Governor & Cabinet on 12/14/82 for the Stanton site, including associated transmission and rail spur lines, with subsequent modifications thereto. These Conditions of Certification address the supplementary changes related to the construction and operation of Unit 2 and associated transmission line and alternate access road (shown on Attachment I). Where these conditions supersede the original COC and modifications thereto, such COC are rendered void; otherwise, the original COC and modifications thereto remain in effect. Unit 2 certification is limited to 516,200 KVA (465 MW at a 0.9 power factor) nameplate capacity. I/III. JURISDICTIONAL AGENCIES The following agencies are deemed to have jurisdictional interest in the certification, and thus regulatory authority over the development, construction, operation, and maintenance of the facility: Department of Environmental Regulation (& Central District Office) [DER or DER/CDO] South Florida Water Management District [SFWMD] St. Johns River Water Management District [SJRWMD] Game & Fresh Water Fish Commission [GFWFC] Department of Natural Resources [DNR] Department of Community Affairs [DCA] Department of Transportation [DOT] Orange County [OC] I/IV. DEFINITIONS Licensee: References herein to the "Licensee" apply to Orlando Utilities Commission, Florida Municipal Power Agency, and Kissimmee Utility Authority as joint owners of Stanton Unit 2, or to their successors or assigns. (See COC-I/V regarding transfer of certification). Completeness/sufficiency: The term "complete" as used herein shall have the same meaning as contained in Chapter 120, F.S., not Chapter 403, F.S., i.e., a complete application shall also provide sufficient information for an agency to perform an analysis of compliance with the conditions of certification and applicable regulations. Where agency-recommended COCs have used the Ch. 403 FS term of "sufficient", that shall have the same meaning as the term "complete" as used herein. Affected agencies: References to the "affected agencies" apply to the jurisdictional agencies listed in COC-I/III. Other terms: The meaning of terms not otherwise specified in A-C, as used herein, shall be governed by the definitions contained in Chapter 403, Florida Statutes, and any regulations adopted pursuant thereto. In the event of any dispute over the meaning of a term in these conditions which is not defined in such statutes or regulations, such dispute shall be resolved by reference to the most relevant definitions contained in any other state or federal statute or regulation. I/V. TRANSFER OF CERTIFICATION If contractual rights, duties, or obligations are transferred under this Certification, notice of such transfer or assignment shall immediately be submitted to the Florida Department of Environmental Regulation and the Affected Agencies by the previous certification holder (Licensee) and the Assignee. Included in the notice shall be the identification of the entity responsible for compliance with the Certification. Any assignment or transfer shall carry with it the full responsibility for the limitations and conditions of this Certification. I/VI. SEVERABILITY The provisions of this certification are severable, and if any provision of this certification or the application of any provision of this certification to any circumstances, is held invalid, the application of such provisions to other circumstances and the remainder of the certification shall not be affected thereby. I/VII. PROFESSIONAL CERTIFICATION Where post-certification submittals are required by these conditions, drawings shall be signed and sealed by a Professional Engineer, or Professional Geologist, as applicable, registered in the State of Florida. I/VIII. RIGHT OF ENTRY The Licensee shall allow during operational or business hours the Secretary of the Florida Department of Environmental Regulation and/or authorized representatives, including personnel of the Affected Agencies, upon the presentation of appropriate credentials: To have access during normal business hours (Mon.-Fri., 9:00 a.m. to 5:00 pm.) to any records required to be kept under the conditions of this certification for examination and copying; and To inspect and test any monitoring equipment or monitoring method required in this certification and to sample any discharge or pollutants; and To assess any damage to the environment or violation of ambient standards; and To have reasonable escorted access to the power plant site and any associated linear facilities to inspect and observe any activities associated with the construction, operation, maintenance, or monitoring of the proposed project in order to determine compliance with the conditions of this Certification. The Licensee shall not refuse immediate entry or access upon reasonable notice to any Affected Agency representative who requests entry for the purpose of the above noted inspections and presents appropriate credentials. I/IX. DESIGN STANDARDS The facility shall be constructed pursuant to the design standards presented in the application and any approved post-certification submittals, and shall be considered the minimum design standards for compliance. I/X. LIABILITY The Licensee shall hold and save the Affected Agencies harmless from any and all damages, claims, or liabilities which may arise by reason of the construction, operation, maintenance and/or use of any facility authorized by this Certification, to the extent allowed under Florida law. I/XI. PROPERTY RIGHTS The issuance of this certification does not convey any property rights in either real or personal property, nor any exclusive privileges, nor does it authorize any injury to public or private property or any invasion of personal rights nor any infringement of Federal, State or local laws or regulations. I/XII. COMPLIANCE Compliance with Conditions The Licensee shall at all times maintain in good working order and operate all treatment or control facilities or systems installed or used by the Licensee so as to achieve compliance with the terms and conditions of this certification. All discharges or emissions authorized herein shall be consistent with the terms and conditions of this certification. The discharge of any regulated pollutant not identified in the application, or more frequent than, or at a level in excess of that authorized herein, shall constitute a violation of the certification. An environmental control program shall be established under the supervision of a qualified Environmental Engineer/Specialist to assure that all construction activities conform to applicable environmental regulations and the applicable Conditions of Certification. If a violation of standards, harmful effects or irreversible environmental damage not anticipated by the application or the evidence presented at the certification hearing are detected during construction, the Licensee shall notify the DER Central District Office and Siting Coordination office, as required in I/XII.B. Any anticipated facility expansions beyond the certified initial nameplate capacity, production increases, or process modifications which may result in new, different, or increased discharges of pollutants, change in type of fuel, or expansion in steam generation capacity shall be reported by submission of a modification petition pursuant to Chapter 403, Florida Statutes. In the event of a malfunction of Unit 2's pollution control system, that the Licensee shall comply with 40 CFR 60.46a. Non-compliance Notification If, for any reason, the Licensee does not comply with or will be unable to comply with any limitation specified in this certification, the Licensee shall notify the Central District office of the Department of Environmental Regulation by telephone within a working day that said noncompliance occurs and shall confirm this in writing within seventy-two (72) hours of becoming aware of such conditions, and shall supply the following information: A description of the discharge and cause of noncompliance; and The period of noncompliance, including exact dates and times; or if not corrected, the anticipated time the noncompliance is expected to continue, and steps being taken to reduce, eliminate and prevent recurrence of the noncomplying event. Adverse Impact The Licensee shall take all reasonable steps to minimize any adverse impact resulting from noncompliance with any limitation specified in this certification, including such accelerated or additional monitoring as necessary to determine the nature and impact of the noncomplying discharge. I/XIII. POST-CERTIFICATION REVIEW Further information may be required by these conditions for site-specific or more detailed review and approval to determine compliance with the conditions of certification. Compliance determinations of the Department and other reviewing agencies are subject to review pursuant to chapter 120, Florida Statutes. In order to provide adequate lead time for review, such information, as developed, must be submitted for post-certification review at least 120 days prior to the intended commencement date of construction or operation of the feature undergoing review. Notification of the submittal of the information, and any determinations made pursuant to these COC, shall be provided to the DER Siting Coordination Office for record-keeping purposes. Where such information is required, it shall be submitted to the agency(ies) named in the condition, which shall then have 30 days in which to determine the completeness (sufficiency) of the information. If a written request for additional information is not issued within the 30 day time period, the information will be presumed to be complete (sufficient). Once the information has been determined complete (sufficient), the agency(ies) shall have 90 days, unless another time period has been specified herein, in which to make the determination regarding compliance. I/XIV. COMMENCEMENT OF CONSTRUCTION At least 30 days prior to the commencement of construction, the Licensee or Project Engineer shall notify the DER Siting Coordination Office, the DER Central District Office, and Affected Agencies of theconstruction start date. Quarterly construction status reports shall similarly be submitted by the Licensee beginning with the initial construction start date. The report shall be a short narrative describing the progress of construction. I/XV. COMMENCEMENT OF OPERATION At least 30 days prior to the commencement of operation, the Licensee or Project Engineer shall notify the DER Siting Coordination Office and Affected Agencies of the operation start date. I/XVI. OPERATIONAL CONTINGENCY PLANS Operating Procedures The Licensee shall develop and make available for viewing at the Stanton site by the DER operating instructions for all aspects of the operations which are critical to keeping the facility's pollution control equipment working properly and to keep the facility in compliance with air and water quality criteria. Contingency Plans The Licensee shall develop and make available for viewing at the Stanton site by the DER written contingency plans or procedures for the continued operation of the unit in event of pollution control equipment breakdown. Stoppages which compromise the integrity of the operations must have appropriate contingency plans. Such contingency plans shall identify critical spare parts to be readily available. Current Engineering Plans For all pollution control and monitoring systems, the Licensee shall maintain a complete current set of as installed engineering plans, equipment data books, catalogs and documents in order to facilitate the smooth acquisition or fabrication of spare parts or mechanical modifications. Application Modifications The Licensee shall furnish appropriate modifications to drawings and plot plans submitted as part of the application. I/XVII. REVOCATION OR SUSPENSION This certification may be suspended or revoked for violations of any of its conditions pursuant to Section 403.512, Florida Statutes. I/XVIII. CIVIL AND CRIMINAL LIABILITY This certification does not relieve the Licensee from civil or criminal penalties for noncompliance with any conditions of this certification, applicable rules or regulations of the Department or Chapter 403, Florida Statutes, or regulations thereunder. Subject to Section 403.511, Florida Statutes, this certification shall not preclude the institution of any legal action or relieve the Licensee from any responsibilities or penalties established pursuant to any other applicable state statutes, or regulations. I/XIX. ENFORCEMENT The Department of Environmental Regulation, as supported by the applicable Affected Agency, may take any and all lawful actions to enforce any condition of this Certification. Any agency which deems enforcement to be necessary shall notify the Secretary of DER of the proposed actions. The agency may seek modification of this Certification for any change in any activity resulting from enforcement of this Certification which change will have a duration longer than 60 days. I/XX. FIVE YEAR REVIEW The certification shall be final unless revised, revoked, or suspended pursuant to law. At least every five years from the date of issuance of certification the Department shall review the project and these conditions of certification and propose any needed modifications. I/XXI. MODIFICATION OF CONDITIONS Pursuant to Subsection 403.516(1), F.S., the Board hereby delegates the authority to the Secretary to modify any condition of this certification not in conflict with Condition of Certification Part VII dealing with sampling, monitoring, reporting, specification of control equipment, related time schedules, emission limitations, variances or exceptions to water quality standards, transmission line, access road or pipeline construction, source of treated effluent cooling water, mitigation, transfer or assignment of the Certification or related federally delegated permits, or any special studies conducted, as necessary to attain the objectives of Chapter 403, Florida Statutes. All other modifications to these conditions shall be made in accordance with Section 403.516, Florida Statutes. II/I. AIR Part II Conditions Recommended by the Department of Environmental Regulation The construction and operation of Unit 2 at Orlando Utilities Commission, Curtis H. Stanton Energy Center (CHSEC) steam electric power plant site shall be in accordance with all applicable provisions of Chapters 17-2, 17-4, and 17-5, Florida Administrative Code except for NOx, and SO2 which shall be governed by 40 CFR Part 60 regarding startup, shutdown, and malfunction. In addition to the foregoing, the permittee shall comply with the following conditions of certification: A. Emissions Limitations The proposed steam generating station shall be constructed and operated in accordance with the capabilities and specifications of the application including the proposed 465 (gross) megawatt generating capacity and the 4286 MMBtu/hr heat input rate for each steam generator. Based on a maximum heat input of 4286 million Btu per hour, stack emissions from CHSEC Unit 2 shall not exceed the following when burning coal: SO2 - lb/million Btu heat input 30 - day rolling average 0.25 24 - hour emission rate 0.67 3 - hour emission rate 0.85 NOx - lb/million Btu heat input 30-day rolling average 0.17 PM/PM10 - lb/million Btu heat input lb/MBtu lb/hr PM 0.02 85.7 PM10 0.02 85.7 CO - 0.15 lb/million Btu heat input, 643 lb/hour. VOC - 0.015 lb/million Btu heat input, 64 lb/hour. H2SO4 - 0.033 lb/million Btu heat input 140 lb/hour. Be - 5.2 x 10-6 lb/million Btu heat input, 0.022 lb/hour. Hg - 1.1 x 10-5 lb/million Btu heat input, 0.046 lb/hour. Pb - 1.5 x 10-4 lbs/million Btu heat input, 0.64 lb/hour. Fluorides - 4.2 x 10-4 lb/million Btu heat input, 1.8 lb/hour. The height of the boiler exhaust stack for CHSEC Unit 2 shall not be less than 550 ft. above grade. Particulate emissions from the coal, lime and limestone handling facilities: All conveyors and conveyor transfer points will be enclosed to preclude PM emissions (except those directly associated with the coal stacker/reclaimer or emergency stockout, and the limestone stockout for which enclosure is operationally infeasible). Inactive coal storage piles will be shaped, compacted and oriented to minimize wind erosion. Water sprays or chemical wetting agents and stabilizers will be applied to storage piles, handling equipment, etc. during dry periods and as necessary to all facilities to maintain an opacity of less than or equal to 5 percent, except when adding, moving or removing coal from the coal pile, which would be allowed no more than 20%. Limestone day silos and associated transfer points will be maintained at negative pressures during filling operations with the exhaust vented to a control system. Lime will be handled with a totally enclosed pneumatic system. Exhaust from the lime silos during filling will be vented to a collector system. The fly ash handling system (including transfer and silo storage) will be totally enclosed and vented (including pneumatic system exhaust) through fabric filters; and Any additional coal, lime, and limestone handling facilities for Stanton Unit 2 will be equipped with particulate control systems equivalent to those for Stanton Unit 1 Particulate emissions from bag filter exhausts from the following facilities shall be limited to 0.02 gr/acf: coal, lime, limestone and flyash handling systems excluding those facilities covered by II/I.A.3.c above. A visible emission reading of 5% opacity or less may be used to establish compliance with this emission limit. A visible emission reading greater than 5% opacity will not create a presumption that the 0.02 gr/acf emission limit is being violated. However, a visible emission reading greater than 5% opacity will require the permittee to perform a stack test for particulate emissions, as set forth in Condition II/I.C. Compliance with opacity limits of the facilities listed in Condition II/I.A. will be determined by EPA referenced method 9 (Appendix A, 40 CFR 60). Construction shall reasonably conform to the plans and schedule given in the supplemental application. The permittee shall report any delays in construction and completion of the project which would delay commercial operation by more than 90 days to the DER Central District office in Orlando. Reasonable precautions to prevent fugitive particulate emissions during construction shall be to coat the roads and construction sites used by contractors, regrass or water areas of disturbed soils. Coal shall not be burned in the unit unless the electrostatic precipitator and limestone scrubber and other air pollution control devices are operating as designed except as provided under 40 CFR Part 60, Subpart Da. The fuel oil to be fired in Stanton Unit 2 and the auxiliary boiler shall be "new oil" which means an oil which has been refined from crude oil and has not been used. On-site generated lubricating oil and used fuel oil which meets the requirements of 40 CFR 266.40 may also be burned. The quality of the No. 2 fuel oil used by the auxiliary boiler shall not contain more than 0.5% sulfur by weight and cause the allowable emission limits listed in the following table to be exceeded. Such emissions may be calculated in accordance with AP-42. Allowable Emission Limits Pollutant lb/MMBtu PM 0.015 S02 0.51 NOx 0.16 Visible emissions Maximum 20% Opacity The flue gas scrubber shall be put into service during normal operational startup, and shut down when No. 6 fuel oil is being burned. The No. 6 fuel oil shall not contain more than 1.5% sulfur by weight. No fraction of flue gas shall be allowed to bypass the FGD system to reheat the gases exiting from the FGD system, except that bypass shall be allowed during startup and shutdown. All fuel oil and coal shipments received shall have an analysis for sulfur content, ash content, and heating value either documented by the supplier or determined by analysis. Coal sulfur content shall be determined and recorded on a daily basis. Records of all the analysis shall be kept for public inspection for a minimum of two years after the data is recorded. Within 90 days of commencement of operations, the applicant will determine and submit to FDER the pH level range in the scrubber reaction tank that correlates with the specified limits for SO2 in the flue gas. Moreover, the applicant is required to operate a continuous pH meter equipped with an upset alarm to ensure that the operator becomes aware when the pH level of the scrubber reaction tank falls out of this range. The pH monitor can also act as a backup in the event of malfunction of the continuous SO2 monitor. The value of the scrubber pH may be revised at a later date provided notification to FDER is made demonstrating the emission limit is met. Further, if compliance data show that higher FGD performance is necessary to maintain the emission limit, a different pH value will be determined and maintained. The applicant will comply with all requirements andprovisions of the New Source Performance standard for electric utility steam generating units (40 CFR 60 Part Da). The Licensee shall submit to the Department at least 120 days prior to start of construction of the NOx control system, copies of technical data pertaining to the selected Nox control system. These data, if applicable to the technology chosen by the Licensee, should include but not be limited to design efficiency, guaranteed efficiency, emission rates, flow rates, reagent injection rates, or types of catalysts. The Department may, upon review of these data, disapprove the use of any such device or system if the Department determines the selected control device or system to be inadequate to meet the emission limits specified in l.b. above. Such disapproval shall be issued within 90 days of receipt of the technical data. B.Air Monitoring Program A flue gas oxygen meter shall be installed for Stanton Unit 2 to continuously monitor a representative sample of the flue gas. The oxygen monitor shall be used with automatic feedback or manual controls to continuously maintain air/fuel ratio parameters at an optimum. The flue gas manufacturing oxygen monitor shall be calibrated and operated according to established procedures as approved by DER. The document "Use of Flue Gas Oxygen Meter as BACT for Combustion Controls" may be used as a guide. The permittee shall install and operate continuous monitoring devices for Stanton Unit 2 main boiler exhaust for sulfur dioxide, nitrogen oxides, oxygen, and opacity. The monitoring devices shall meet the applicable requirements of Section 17-2.710, FAC., and 40 CFR 60.47a. The opacity monitor may be placed in the duct work between the electrostatic precipitator and the FGD scrubber. The permittee shall operate one continuous ambient monitoring device for sulfur dioxide in accordance with DER quality control procedures and EPA reference methods in 40 CFR, Part 53, and one ambient monitoring device for PM10, and one continuous NOx monitor. The monitoring devices shall be specifically located at a location approved by the Department. The frequency of operation of the particulate monitor shall be every six days commencing as specified by the Department. During construction and operation the existing meteorological station will be operated and data reported with the ambient data. The permittee shall maintain a daily log of the amounts and types of fuel used. The log shall be kept for inspection for at least two years after the data is recorded. Fuel analysis data including sulfur content, ash content, and heating values shall be determined on an as received basis and kept for two years. The permittee shall provide stack sampling facilities as required by Rule 17-2.700(4) F.A.C. The ambient monitoring program shall begin at least one year prior to initial start up of Unit 2 and shall continue for at least one year of commercial operation. The Department and the permittee shall review the results of the monitoring program annually and determine the necessity for the continuation of or modifications to the monitoring program. Stack Testing Within 60 calendar days after achieving the maximum capacity at which Unit 2 will be operated, but no later than 180 operating days after initial startup, the permittee shall conduct performance tests for particulates, SO2, NOx, and visible emissions during normal operations near (+ _ 10%) 4286 MMBtu/hr heat input and furnish the Department a written report of the results of such performance tests within 45 days of completion of the tests. The performance tests will be conducted in accordance with the provisions of 40 CFR 60.46a and 48a. Compliance with emission limitation standards mentioned in specific Condition No. II/I.A. shall be demonstrated during the initial performance test using appropriate EPA Methods, as contained in 40 CFR Part 60 (Standards of Performance for New Stationary Sources), or 40 CFR Part 61 (National Emission Standards for Hazardous Air Pollutants), or any method as proposed by the Applicant and approved by the Department, in accordance with F.A.C. Rule 17- 2.700. EPA Method For Determination of Selection of sample site and velocity traverses. Stack gas flow rate when converting concentrations to or from mass emission limits. Gas analysis when needed for calculation of molecular weight or percent 02. Moisture content when converting stack velocity to dry volumetric flow rate for use in converting concentrations in dry gases to or from mass emission limits. Particulate matter concentration and mass emissions. 201 or 201A PM10 emissions. 6, 6C, or 19 Sulfur dioxide emissions from stationary sources. 7, 7C, or 19 Nitrogen oxide emissions from stationary sources. 9 Visible emission determination of opacity. At least three one hour runs to be conducted simultaneously with particulate testing for the emissions from dry scrubber/baghouse, and ash handling building baghouse. At least one lime truck unloading into the lime silo (from start to finish). 10 Carbon monoxide emissions from stationary sources. 12 or 101A Lead concentration from stationary sources. 13A or 13B Fluoride emissions from stationary sources. 18, 25, 25A Volatile organic compounds concentration. or 25B 101A or 108 Mercury emissions. 104 Beryllium emission rate and associated moisture content: The permittee shall provide 30 days written notice of the performance tests for continuous emission monitors or 10 working days written notice for stack tests in order to afford the Department the opportunity to have an observer present. Stack tests for particulates, NOx and SO2 and visible emissions shall be performed annually in accordance with Conditions C.2 and .3 above. Reporting For Stanton Unit 2, a summary in the EPA format of stack continuous monitoring data, fuel usage and fuel analysis data shall be reported to the Department's Central District Office and to the Orange County Environmental Protection Department on a quarterly basis commencing with the start of commercial operation in accordance with 40 CFR, Part 60, Section 60.7, and 60.49a and in accordance with Section 17-2.710(2), F.A.C. Utilizing the SAROAD or other format approved in writing by the Department, ambient air monitoring data shall be reported to the Bureau of Air Quality Management of the Department quarterly. Such reports shall be due within 45 days following the quarterly reporting period. Reporting and monitoring shall be in conformance with 40 CFR Parts 53 and 58. Beginning one month after certification, the permittee shall submit to the Department a quarterly status report briefly outlining progress made on engineering design and purchase of major pieces of air pollution control equipment. All reports and information required to be submitted under this condition shall be submitted to the Siting Coordination Office, Department of Environmental Regulation, 2600 Blair Stone Road, Tallahassee Florida, 32301. Malfunction or Shutdown In the event of a prolonged (thirty days or more) equipment malfunction or shutdown of air pollution control equipment, operation may be allowed to resume or continue to take place under appropriate Department order, provided that the Licensee demonstrates such operation will be in compliance with all applicable ambient air quality standards and PSD increments. During such malfunction or shutdown, the operation of Stanton Unit 2 shall comply with all other requirements of this certification and all applicable state and federal emission standards not affected by the malfunction or shutdown which is the subject of the Department's order. Exceedances produced by operational conditions for more than two hours due to upsets in air pollution control systems as a result of start-up, shutdown, or malfunctions as defined by 40 CFR 60 need not be reported as specified in Condition I/XII. Identified operational malfunctions which do not stop operation but prevent compliance with emission limitations shall be reported to DER as specified in Condition I/XII. Open Burning Open burning in connection with initial land clearing shall be in accordance with Chapter 17-256, F.A.C., Chapter 5I-2, F.A.C., Uniform Fire Code Section 33.101 Addendum, and any other applicable County regulation. Any burning of construction generated material, after initial land clearing that is allowed to be burned in accordance with Chapter 17-256, F.A.C., shall be approved by the DER Central District Office in conjunction with the Division of Forestry and any other County regulations that may apply. Burning shall not occur unless approved by the jurisdictional agency or if the Department or the Division of Forestry has issued a ban on burning due to fire safety conditions or due to air pollution conditions. Federal Annual Operating Permits and Fees DER Responsibilities The Department of Environmental Regulation shall implement the provisions of Title V of the 1990 Clean Air Act for Stanton 2 developing Conditions of Certification requiring submission of annual operating permit information and annual pollutant emission fees in accordance with Federal Law and Federal regulations. OUC Responsibilities OUC shall submit the appropriate annual operating permit application information as well as the appropriate annual pollutant emission fees as required by Federal Law to the Department as specified in Condition 3. below. Annual Operating "Permit" Application and Fee (Reserved) II/II. WETLANDS RESOURCE MANAGEMENT The proposed transmission line from the Stanton Energy Center to the Mud Lake transmission line and the proposed alternate access road to the Stanton Energy Center from the south shall be routed as shown in the supplemental application. Prior to construction, the permittee shall submit drawings on 8.5" by 11" paper, showing the final design, including plan views and cross-sections for each area of filling or clearing in wetlands. The drawings shall show the existing and proposed ground elevations and all existing and proposed structure locations, sizes and invert elevations. All clearing and construction activities shall be confined to the limits of the clear zone necessary for the transmission line as shown on Figures 6.1-5 and 6.1-6 of the application drawings. Within 30 days of the completion of construction, the permittee shall arrange a site visit by DER District personnel from the Central District office in Orlando to verify that no wetland damage has occurred outside the transmission line clear zone. If wetland damage occurs outside the transmission line clear zone during construction, the permittee shall submit to the Bureau of Wetland Resource Management for review a plan to restore the wetland area which was damaged and to provide mitigation for the damage. The plan shall be implemented with 30 days of the Department approving the restoration and mitigation plan. This condition does not preclude the Department from taking enforcement action if unauthorized activities occur. Prior to initiating construction, the permittee shall submit a map and aerial photographs showing the location of all staging areas for the transmission line and alternate access road construction to the Bureau of Wetland Resource Management for review and written approval. These areas shall be upland areas which are not currently providing red-cockaded woodpecker nesting or foraging habitat. The staging areas shall not be used prior to receiving DER approval. Drainage structures shall be placed in the transmission line ROW and under the alternate access road at the same locations where drainage structures currently exist under the CSX Railroad berm. The drainage structures shall provide at least the same efficiency as the corresponding drainage structure currently existing in the CSX Railroad berm. The forested areas to be cleared shall be cleared using low-impact equipment so as to minimize soil disturbance. The rootmats and tree stumps shall be left in place to provide soil stabilization. During construction, best management practices, including but not limited to staked hay bales and filter cloth, shall be utilized to control erosion and turbidity. All side slopes shall be seeded and mulched within 72 hours of the final grading. Construction of the transmission line and alternate access road will result in the filling of 4.12 ac. of herbaceous wetlands the permanent clearing of 13.19 ac. of forested wetlands. The permittee shall provide mitigation to offset the wetland loss and habitat degradation resulting from the construction of this project. Prior to construction, the permittee shall propose a mitigation plan and shall provide the following information to the Bureau of Wetland Resource Management to allow the Department to review the proposed mitigation plan: detailed description of each wetland impact area; acreage of the type and quality of wetland being impacted at each site; narrative, drawings and aerial photographs showing and explaining the proposed mitigation; detailed description of the existing conditions at the mitigation area; acreage of the proposed mitigation by mitigation and wetland type; documentation providing reasonable assurance that the proposed mitigation will be successful. If the mitigation submittal is deemed by the Department to provide insufficient information for review, additional information requested by the Department shall be submitted. Upon receiving complete information, the Department will assess the mitigation plan within 90 days. If the Department, upon review of the proposed mitigation, determines that the proposed mitigation is inadequate to offset the wetland loss and habitat degradation from this project, the permittee shall propose additional mitigation. II/III. ELECTRIC AND MAGNETIC FIELDS The associated transmission line shall comply with the requirements of Ch. 17- 274, F.A.C. II/IV. OTHER For wastewater treatment, sanitary waste treatment, public water supply, surface water monitoring, and ground water monitoring see Unit 1's Conditions of Certification. For air and water monitoring programs, quality assurance plans shall be submitted by OUC within 90 days of certification. Such QA plans shall be submitted in conformance with Chapter 17-160, F.A.C. Part III Conditions Recommended by the Game and Fresh Water Fish Commission III/I. WILDLIFE SURVEY Prior to the construction of the proposed facility, a wildlife survey, consistent with methodology prescribed by the FGFWFC, shall be conducted for the presence of listed species (endangered, threatened, or species of special concern) and suitable habitat for same within the site. The results of said survey shall be submitted to the DER, the FGFWFC, and the United States Fish and Wildlife Service. If construction of the proposed facility will impact any listed species, other than the previously identified impact on the foraging habitat of the red-cockaded woodpecker resulting from the clearing of the transmission line right-of-way, the Permittee shall consult with the DER and the FGFWFC to determine the appropriate steps to avoid, minimize, mitigate, or otherwise appropriately address any adverse impacts within each agency's respective jurisdiction. III/II. NESTING SANDHILL CRANES Nesting sandhill cranes shall be avoided by limiting installation of transmission lines over wetlands utilized by nesting cranes to periods outside of the nesting season, which runs from January through June. III/III. MANAGEMENT PLAN Before construction, a management plan for the preserved areas shall be presented to the FGFWFC for review and approval. At a minimum, this plan shall include a statement of what habitat function the preserve is expected to provide; a schedule of fire management through a certified burn specialist and including, but not limited to, burn conditions, burn frequency, and measures taken to avoid spread of wildfire; measures taken to remove exotic vegetation from both wetlands and uplands; and the responsible entity. Part IV Conditions Recommended by the South Florida Water Management District IV/I. LEGAL/ADMINISTRATIVE CONDITIONS These conditions also incorporate by reference the conditions contained in Part I, Administrative Conditions, of the Recommended Supplemental Conditions of Certification. GENERAL Compliance Requirements This project must be constructed, operated and maintained in compliance with and meet all non-procedural requirements set forth in Chapter 373, F.S., and Chapter 40E-4 (Surface Water Management), F.A.C. Off-Site Impacts It is the responsibility of the Permittee to ensure based on information provided that adverse off-site water resource related impacts do not occur during the construction, operation, and maintenance of the transmission line and associated transmission line access roads within SFWMD. Post Certification Information Submittals Information submitted to the SFWMD subsequent to Certification, in compliance with the conditions of this Certification, shall be for the purpose of the SFWMD determining the Permittee's compliance with the Certification conditions and the non-procedural criteria contained in Chapter 40E-4, F.A.C., as applicable, prior to the commencement of the subject construction, operation and/or maintenance activity covered thereunder. PROCESSING OF INFORMATIONAL REQUESTS Right-of-way Modifications At least ninety (90) days prior to the commencement of construction of any portion of the transmission line, the Permittee shall submit any proposed modifications to the transmission line right-of-way, identified on Exhibits 2, 3 and 4 (Figures 6.1-2, 6.1-3, and 6.1-4), to the SFWMD staff for review and approval. If the SFWMD staff does not issue a written request for additional information and/or an objection to the proposed right-of-waymodification within thirty (30) days, the modification shall be presumed to be complete and acceptable. Completeness and Review At least ninety (90) days prior to the commencement of construction of any portion of the linear facilities located in the SFWMD, the Permittee shall submit to SFWMD staff, for a completeness and sufficiency review, any pertinent additional information required under the SFWMD's Conditions of Certification for that portion proposed for construction. If SFWMD staff does not issue a written request for additional information within thirty (30) days, the information shall be presumed to be complete and sufficient. Compliance Review and Confirmation Within sixty (60) days of the determination by SFWMD staff that the submitted information is complete and sufficient, the SFWMD shall determine and notify the Permittee in writing whether the proposed activities conform to SFWMD criteria, as required by Chapter 40E-4, F.A.C., and the Conditions of Certification. If necessary, the SFWMD shall identify what items remain to be addressed. No construction activities shall begin until the SFWMD has determined either in writing, or by failure to notify the Permittee in writing, that the activities are in compliance with the applicable SFWMD criteria. Revisions to Site Specific Design Authorizations The Permittee shall submit, consistent with the provisions of Condition IV/I.B, any proposed revisions to the site specific design authorizations specified in this Certification to the SFWMD for review and approval prior to implementation. The submittal shall include all the information necessary to support the proposed request, including detailed drawings, topographic maps, average wet season water table elevations, calculations and/or any other applicable data. Such requests may be included as part of the appropriate additional information submittals required by this Certification provided they are clearly identified as a requested modification to the previously authorized design. Dispute Resolution Since this Certification is the only form of permit required from any agency, it is understood that the Permittee and the SFWMD shall strive to resolve disputes by mutual agreement. Objections Objections to modifications of the terms and conditions of this Certification shall be resolved through the process established in Section 403.516, F.S. Changes to Information Requirements The SFWMD and the Permittee may jointly agree to vary the informational requirements. IV/II. SURFACE WATER MANAGEMENT CONDITIONS GENERAL CONDITIONS Professional Engineer Certificate The operation of the surface water management system authorized under this certification shall not become effective until a Florida Registered Professional Engineer certifies, upon completion of each phase, that these facilities have been constructed in accordance with the design approved by the SFWMD. Within 30 days after completion of construction of the surface water management system, the Permittee or authorized agent shall submit the engineer's certification and notify the SFWMD Field Engineering Division that the facilities are ready for inspection and approval. Such notification shall include as-built drawings of the site which shall include elevations, locations, and dimensions of components of the surface water management system. Impacts on Fish, Wildlife, Natural Environment Values and Water Quality The Permittee shall prosecute the work authorized under this Certification in a manner so as to minimize any adverse impacts of the authorized works on fish, wildlife, natural environment values, and water quality. The Permittee shall institute necessary measures during the construction period, including necessary compaction of any fill materials placed around newly installed structures and/or the use of silt screens, hay bales, seeding and mulching, and/or other similar techniques, to reduce erosion, turbidity, nutrient loading and sedimentation in the receiving waters. Correction of Water Quality Problems The Permittee shall be responsible for the correction of any sedimentation, turbidity, erosion, shoaling and/or maintenance of the works authorized under this Certification. Off-site Conveyances All off-site conveyances during construction and development of the transmission line and associated access roads shall be made only through the conveyance facilities authorized by this Certification. No roadway or structure pad construction shall commence on-site unless in conjunction with the construction of the permitted conveyance facilities and any associated detention areas. Water conveyed from the project shall be through facilities having a mechanism suitable for regulating upstream water stages. Stages may be subject to operating schedules satisfactory to the SFWMD. Additional Water Quality Requirements The Permittee may be required to incorporate additional water quality treatment methods into the surface water management system if such measures are shown to be necessary. Access Roads The Permittee shall, whenever available, utilize adjacent existing roads for access to the transmission line right of way for construction, operation and/or maintenance purposes. Finger roads connecting the existing roads to the structure pads and access roads which must be constructed in areas where an existing road is not available shall be constructed in a manner which does not impede natural drainage flows and minimizes impacts to on-site and adjacent wetlands. Correction of Drainage Problems The Permittee shall be responsible for the correction of any adverse on-site, upstream, and/or downstream drainage and/or wetland impacts which may occur as a result of the construction of the proposed access road and/or structure pads. These may include the placement and/or removal of culverts and/or other structures to remedy the impact. Modifications Subsequent modifications to the drawings and supporting calculation submitted to the SFWMD which may alter the quantity and/or quality of waters discharged off- site shall be made pursuant to Section 403.516, F.S., and Rule 17-17.211, F.A.C. They shall also be submitted to the SFWMD for a determination that the modifications are In compliance with the non-procedural requirements of Chapters 40E-2 and 40E-4, F.A.C., prior to the commencement of construction. SITE SPECIFIC DESIGN AUTHORIZATIONS Access/Maintenance Road and Structure Pads The Permittee is authorized to construct an access/maintenance road and associated conveyance facilities for the transmission line in the areas specifically identified on Exhibits 2, 3, and 4 (Figures 6.1-2, 6.1-3, and 6.1- 4). Areas where an access/maintenance road is not proposed will be accessed from existing roads. Authorized Receiving Water (Transmission Line Access Maintenance Roads only) Adjacent Wetlands ADDITIONAL INFORMATION REQUIREMENTS Access/Maintenance Road and Structure Pad Construction Plans Prior to the commencement of construction of any portion of the transmission line which affects the movement of waters, the Permittee shall submit plans for any construction activities for that portion of the transmission line which may obstruct, divert, control, impound or cross waters of the state, either temporarily or permanently, to the SFWMD, consistent with the provisions of Condition IV/I.B, for a determination of compliance with the non-procedural requirements of Chapter 40E-4, F.A.C., in effect at the time of submittal. "Construction activities" in this situation shall include the placement of access/ maintenance roads, culverts, and/or fill materials, excavation activities, and any related activities. All plans, detail sheets and calculations shall be signed and sealed by a Florida Registered Professional Engineer. For all construction activities, the following information, referenced to NGVD, shall be submitted: A centerline profile of existing topographic features along the proposed access/maintenance road(s); A design of the proposed access/maintenance and finger road(s) with finished elevations marked; A typical cross-section of the proposed access/maintenance and finger road(s), including relative dimensions and elevations; A cross-section of each stream or creek at the point(s) to be crossed by the proposed access/maintenance and finger road, and/or other facility; Identification of wet season water table elevations for each basin in which facilities will be located; Specifications, including supporting assumptions and calculations, showing the type and size of water control structures (pipe, culvert, equalizer, etc.) to be used, with proposed flowline elevations marked, drainage areas identified, and design capacity verified; A cross-section of any proposed excavation areas showing the proposed depth of excavation; Calculations and supporting documentation which demonstrate that the proposed construction and/or excavation activities associated with the transmission line will not have an adverse water quantity and/or water quality impact on adjacent wetlands and/or permitted surface water management systems; If construction of the transmission line contributes to the necessity for future modifications to adjacent/existing roads, water quality treatment requirements of the requested road modifications must be addressed in the surface water management system design for the transmission line. IV/III. ENVIRONMENTAL CONDITIONS GENERAL Wetland Avoidance The Permittee shall avoid impacting wetlands within the transmission line corridor wherever practicable. Where necessary and feasible, the location of the structure pads, other related facilities and/or the transmission line alignment shall be varied to eliminate or reduce wetland impacts. The Permittee shall work in accordance with the submitted plans in the supplemental site certification application as supplemented by final approved construction plans. Clearing and construction activities shall be confined to the limits of the clearing zone. Fill Materials No fill materials shall be obtained from excavated wetlands or within 200 feet of functional wetlands, unless in accordance with a mitigation plan submitted in compliance with the conditions of this Certification. Additional Wetlands Mitigation The Permittee may be required to provide additional mitigation and/or other measures if wetland monitoring and/or other information demonstrates that adverse impacts to protected, restored, incorporated, and/or mitigated wetlands have occurred as a result of project-related activities. Additional Environmental Review The Permittee shall submit any proposed changes in land use, project design, and/or the treatment of on-site wetlands to the SFWMD for additional environmental review in order to determine whether any additional mitigation activities will be required. Mitigation Areas Mitigation credits shall be given for mitigation areas within both the SFWMD and the SJRWMD. Mitigation credits shall be given for acreages and activities which have also been accepted by the DER as mitigation for impacts in areas of joint jurisdiction. Any acreages or activities proposed by the mitigation plan and its addendum which exceed the mitigation requirements of the SJRWMD, and meet the non- procedural requirements for wetland mitigation of the SFWMD, shall be credited as mitigation for impacts within the SFWMD. If required by SFWMD, OUC agrees to provide additional acreages and activities to offset impacts within SFWMD not credited by the Mitigation Plan (June 1991) and its addendum (Sept 1991). SITE SPECIFIC DESIGN AUTHORIZATIONS Authorized Wetland Impacts The Permittee is authorized to construct an access/maintenance road and associated conveyance facilities for the transmission line and structure pads in the wetland areas specifically identified on Exhibits 2, 3, and 4 (Figures 6.1- 2, 6.1-3, and 6.1-4). Sandhill Crane Nest Protection The Permittee shall protect the active sandhill crane nest located in the 0.58 acre marsh situated between stations 125 and 126 in accordance with the following requirements: The transmission line poles and structure pads shall be positioned so that the transmission line spans the marsh; Construction shall be scheduled to avoid the nesting season for sandhill cranes; The marsh shall not be disturbed in any way; The access road shall be located in the swale adjacent to the railroad rather than in the marsh. ADDITIONAL INFORMATION REQUIREMENTS Wetlands Protection Prior to the commencement of construction of any portion of the transmission line which will be located adjacent to the wetlands identified for preservation, the Permittee shall: Stake and rope off the protected wetlands and buffer zones to prevent encroachment during construction. The stakes and ropes shall remain in place until all adjacent construction activities have been completed. Verification of staked areas by SFWMD staff shall be required prior to the commencement of and upon completion of any construction activities. Install silt screens, turbidity barriers and/or hay bales prior to any construction in or alteration of any wetlands within the project site in order to prevent adverse water quality impacts to wetlands. These barriers shall remain in place until fill material is stabilized and turbidity has returned to background levels. Mitigation Plan Prior to the commencement of construction of any portion of the transmission line which may affect wetlands, the Permittee shall submit a mitigation and monitoring plan to the SFWMD for a determination of compliance with the non- procedural requirements of Chapter 40E-4, F.A.C., including Appendix 7 (Isolated Wetlands Rule) of the Basis of Review for Surface Water Management Permit Applications in the SFWMD, in effect at the time of submittal. At a minimum, the plan shall include the following information: Locations and sizes of all proposed mitigation areas, species to be planted, planting densities, details of the proposed hydrologic regime, cross- sections showing the proposed elevations and water depths, and an estimated time schedule for completion of the construction of the mitigation areas. A wetland mitigation and/or restoration work schedule which details each specific mitigation task (e.g. grading to proper elevation, mulching, planting, regularly scheduled maintenance and monitoring, etc.) and the calendar dates for the start and completion of each task. Provisions for both quantitative and qualitative observations of wildlife utilization and the vegetative community, monthly water level readings, panoramic photographs documenting the condition of the mitigation areas, and evaluation of the success of the mitigation effort, and an annual report incorporating this information and any other relevant information. The water level readings will be taken weekly for sampling points that are accessable until demonstrated to the appropriate agency that less frequent water level readings are sufficient to demonstrate compliance. Documentation that sufficient areas have appropriately worded conditions of certification within the SFWMD and/or the SJRWMD to compensate for the proposed wetland impacts with both the water management districts. Part V Conditions Recommended by the St. Johns River Water Management District V/I. WATER SHORTAGES Nothing in this certification shall be construed to limit the authority of the SJRWMD to declare a water shortage and issue orders pursuant to Section 373.175, Florida Statues or to formulate a plan for implementation during periods of water shortage, pursuant to Section 373.246, Florida Statutes. Pursuant to Section 403.516, Florida Statutes, in the event of a water shortage as declared by the SJRWMD, DER may seek a modification of the terms and conditions of this certification to implement the water shortage declaration. V/II. WELL CONSTRUCTION, MODIFICATION, OR ABANDONMENT Prior to the construction, modification, or abandonment of a well, OUC, et al., must obtain approval from the SJRWMD and meet the requirements of Chapter 40C-3, Florida Administrative Code. V/III. WELL MAINTENANCE Leaking or inoperative well casings, valves, or controls must be repaired or replaced as required to put the system back in an operative condition acceptable to the SJRWMD. Failure to make such repairs will be cause for deeming the well abandoned in accordance with Subsection 17-532.200(1), Florida Administrative Code and Section 373.309, Florida Statutes. V/IV. MITIGATION OF WITHDRAWAL IMPACTS ON EXISTING LEGAL USERS OUC, et al., must mitigate any adverse impact caused by withdrawals permitted herein on legal uses of water existing at the time of the Supplemental Site Certification Application for Stanton 2. If unanticipated significant adverse impacts occur, the DER has the right to curtail permitted withdrawal rates or water allocations unless the impacts can be mitigated by OUC, et al. Adverse impacts are exemplified by, but not limited to: Reduction of well water levels resulting in a reduction of 10% in the ability of an adjacent well (other than one owned by OUC) to produce water; Reduction of water levels in an adjacent surface water body resulting in a significant impairment of the use of water (other than a use by OUC) in that water body; Saline water intrusion or introduction of pollutants into the water supply of an adjacent water use (other than a use by OUC) resulting in a significant reduction of water quality; or Change in water quality resulting in either impairment or loss of use of a well or water body (other than a use by OUC). V/V. MITIGATION OF IMPACTS ON ADJACENT LAND USES OUC, et al., must mitigate any adverse impact caused by withdrawals permitted herein on an adjacent land use which existed at the time of Supplemental Site Certification Application for Stanton 2. If unanticipated significant adverse impacts occur, the DER has the right to curtail permitted withdrawal rates or water allocations unless the impacts can be mitigated by OUC, et al. Adverse impacts are exemplified by, but not limited to: Significant reduction in water levels in an adjacent surface water body; Land collapse or subsidence off-site caused by a reduction in water levels; or Damage to crops and other types of off-site vegetation. V/VI. IDENTIFICATION TAGS A SJRWMD-issued identification tag must be prominently displayed at each withdrawal site by permanently affixing such tag to the pump, headgate, valve or other withdrawal facility as provided by Section 40C-2.401, Florida Administrative Code. OUC, et al., must notify the SJRWMD in the event that a replacement tag is needed. V/VII. MAXIMUM ANNUAL WITHDRAWALS Maximum annual withdrawals from the Floridan aquifer must not exceed 321.20 million gallons. V/VIII. MAXIMUM DAILY WITHDRAWALS Maximum daily withdrawals from the Floridan aquifer must not exceed 2.00 million gallons. V/IX. LIMITATION ON USE OF WATER Withdrawals from the Floridan aquifer wells must not be used directly for cooling tower make-up water. Reclaimed wastewater in an allocated amount of 10.19 million gallons/day on an annual average basis from the Orange County Easterly Wastewater Treatment Facility, stormwater runoff, on-site reuse water and direct precipitation shall be the source of cooling tower make-up water. V/X. DEWATERING All withdrawals from the surficial aquifer for dewatering to facilitate construction must be retained on-site within the recycle basin or the make-up water supply pond (#20 and #22, respectively, OUC, et al.'s Figure 3.2-1). V/XI. OFF-SITE DISCHARGES No off-site discharges are approved from this facility, except as provided for by the overflow structure in the make-up water supply pond (#20, OUC, et al.'s Figure 3.2-1), and the natural drainage patterns indicated on SCA Figure 3.10-1 for the duration of this certification. V/XII. DISCHARGES FROM MAKE-UP WATER SUPPLY POND All off-site discharges, as provided for by the overflow structure in the make- up water supply pond (#20, OUC, et al.'s Figure 3.2-1), must be in compliance with water quality standards as set forth in Chapters 17-4, and 17-302, F.A.C., or such standards as issued through a variance by DER. V/XIII. WELL WATER QUALITY SAMPLING Water quality samples must be taken in April and October of each year from each production well. The samples must be analyzed for the following parameters: Calcium Chloride Magnesium Sulfate Sodium Carbonate Potassium Bi-Carbonate (or alkalinity if pH is 6.9 or lower) All major ion analyses must be checked for anion-cation balance and must balance within 5% prior to submission. It is recommended that duplicates be taken to allow for laboratory problems or loss. The sample analyses must be submitted to the SJRWMD by May 15 and November 15 of each year. Prior to sample collection, a minimum of 3-5 casing volumes must be removed from each well. All sampling and water quality analyses shall be performed by organizations with approved comprehensive or generic quality assurance plans on file with the DER or a laboratory having HRS certification. V/XIV. WATER TREATMENT PLANT REPORTS By January 31 of each year, OUC, et al., must submit to the SJRWMD copies of the previous year (12 months) DER monthly water treatment plant operating report data showing total flow from the 2 Floridan wells going to the potable water treatment plant on-site. The project name and certification number must be attached to all reports. V/XV. WELL WATER FLOW MONITORING OUC, et al., must maintain the continuous recorder on the Floridan aquifer monitor well. Copies of the previous year (12 months) recorder charts must be forwarded to the SJRWMD on a yearly basis. The charts must be submitted by January 31 of each year. V/XVI. CONSERVATION PLAN OUC, et al., must implement the conservation plan submitted to the SJRWMD in accordance with the schedule contained therein. V/XVII. WELL WATER FLOW METERS All Floridan aquifer production wells must be equipped with totalizing flow meters throughout the duration of this certification. Such meters must maintain a 95% accuracy, be verifiable and be installed according to the manufacturer's specifications. V/XVIII. CALIBRATION OF FLOW METERS OUC, et al., must have all flow meter(s) calibrated once every 3 years within 30 days of the anniversary date of certification issuance, and recalibrated if the difference between the actual flow and the meter reading is greater than 5%. SJRWMD form EN-51 must be submitted to the SJRWMD within 10 days of the inspection/calibration. V/XIX. MAINTENANCE OF FLOW METERS OUC, et al., must maintain the required flow meter(s). In case of failure or breakdown of any meter, the SJRWMD must be notified in writing within 5 days of its discovery. A defective meter must be repaired or replaced within 30 days of its discovery. V/XX. DELINEATION OF LIMITS OF CONSTRUCTION Prior to construction, OUC, et al., must clearly delineate the limits of construction on-site. OUC, et al., must advise the contractor that any work within the Riparian Habitat Regulation Zone outside the limits of construction, including clearing, is a violation of this certification order. V/XXI. BACKGROUND ASSESSMENT PLAN Prior to commencement of construction, a Background Assessment Plan of the areas to be enhanced or mitigated must be submitted to the SJRWMD, DER, and SFWMD for review and joint approval. Data obtained through the Background Assessment Plan must include the following: (a) site specific topographic survey information referenced to NGVD; (b) survey of historic and existing ordinary high, normal or chronic pool water elevations referenced to NGVD based upon biological/physical wetland indicators; (c) a narrative describing the species composition, health and extent of pre-enhanced areas; and (d) quantitative information regarding the species composition including coverage and composition of understory, midcanopy and canopy species. V/XXII. COMPLETION OF BACKGROUND ASSESSMENT The background assessment must be completed pursuant to the approved Background Assessment plan prior to construction. V/XXIII. INITIATION AND COMPLETION OF ENHANCEMENT MITIGATION PLAN Following completion of the background assessment, and prior to the commencement of construction associated with the transmission line or the access roads, planting and construction associated with the approved Enhancement Mitigation Plan must be initiated, and then must be completed within 12 months after initiation. V/XXIV. CRITERIA FOR SUCCESS OF ENHANCEMENT AND MITIGATION Following completion of the background assessment, before any planting in the mitigation and enhancement areas, OUC, et al., must submit for the joint approval of SJRWMD, DER, and SFWMD a plan setting forth appropriate criteria for determining success of all wetland and upland enhancement and mitigation areas. OUC, et al., shall implement and maintain the mitigation and enhancement areas to ensure that the success criteria are achieved. V/XXV. MONITORING PLAN FOR ENHANCEMENT AND MITIGATION Within 30 days of completion of the initial planting, OUC, et al., must submit to the SJRWMD, DER, and SFWMD for review and joint approval, two copies of a monitoring plan detailing the site specific methods to be used for monitoring the enhancement and mitigation areas, so that the achievement of the success criteria can be quantitatively and qualitatively demonstrated. The monitoring plan must include the location, size and number of monitoring quadrants or transect lines, the location and number of photographic stations, the location of the wetland(s) to be enhanced and mitigated, the location of staff gauges and/or piezometers, and other pertinent factors. OUC, et al., shall monitor the enhancement and mitigation areas until the approved success criteria has been achieved. V/XXVI. SURVEY OF ENHANCEMENT AREAS OUC, et al., must submit to the SJRWMD, DER, and SFWMD two (2) copies of an as- built survey of the enhancement areas certified by a registered surveyor or professional engineer showing dimensions of all planted areas, invert(s) elevation of the proposed culvert in enhancement area 3.6(A), and the final grade of all plugged ditches. An inventory of the planted species within the wetland enhancement areas will be shown on the survey. In areas where planting occurs, the inventory must include the type, number, distribution, and size of the planted vegetation, and must be referenced to the as-built survey. The as- built survey must be submitted to the referenced agency parties within thirty (30) days of completion of the initial planting. V/XXVII. MONITORING REPORTS FOR THE ENHANCEMENT AND MITIGATION AREAS Following joint approval of the plan referenced in Condition No. 26, OUC, et al., must furnish the SJRWMD, DER, and SFWMD with two copies of all Monitoring Reports for the enhancement and mitigation areas describing the status of the mitigation and enhancement areas until the enhancement and mitigation areas achieve the success criteria. V/XXVIII. REVISIONS TO ENHANCEMENT AND MITIGATION If it is determined that successful enhancement is not occurring based on the monitoring reports or trends, OUC, et al., must, within 30 days, provide the SJRWMD, DER and SFWMD with a narrative describing the type and causes of failure with a complete set of plans for the redesign and/or replacement planting of the mitigation and enhancement areas demonstrating that the success criteria can be achieved. Within 30 days of joint agency approval of the amended plans, OUC, et al., must implement the redesign and/or replacement planting. Following completion of such work, the success criteria as stated above or as modified by subsequent approval of the plan must again be achieved. In addition, the monitoring required by the conditions of this permit must be conducted. V/XXIX. EROSION AND SEDIMENT CONTROL DURING CONSTRUTION OUC, et al., must select, implement, and operate all erosion and sediment control measures required to retain sediment on-site and to prevent violations of water quality standards as specified in Chapters 17-302 and 17-4, F.A.C. OUC, et al., is encouraged to use appropriate Best Management Practices for erosion and sediment control as described in the "Florida Land Development Manual: A Guide to Sound Land and Water Management" (DER, 1988). All erosion and sediment control measures must remain in place at all locations until construction is completed and the soils are stabilized. Thereafter, OUC, et al., will be responsible for the removal of the control measures (except for the control measures in the areas of fill for the unpaved access road which shall be permanent). V/XXX. EROSION AND SEDIMENT CONTROL DURING OPERATION Following the completion of construction, OUC, et al., must construct and maintain a permanent protective vegetative and/or artificial cover for erosion and sediment control on all land surfaces exposed or disturbed by construction or alteration of the certified project. A permanent vegetative cover must be established within 60 days after planting or installation. V/XXXI. INCORPORATION OF MITIGATION PLAN The proposed mitigation plan submitted to SJRWMD by OUC for the Curtis H. Stanton Energy Center, Unit 2, dated June 21, 1991, July 20, 1991, September 11, 1991, September 18, 1991, and September 19, 1991 is incorporated as a condition of this certification except where specifically superseded by certification conditions. V/XXXII. COMPLETION OF SURFACE WATER MANAGEMENT SYSTEM Construction or alteration of the surface water management system must be completed and all disturbed areas must be stabilized in accordance with the submitted plans and certification conditions prior to use of the infrastructure for its intended purpose. V/XXXIII. RETENTION/DETENTION STORAGE AREAS At a minimum, all retention/detention storage areas must be constructed to rough grade prior to the placement of impervious surface within the area to be served by those facilities. To prevent reduction in storage volume and percolation rates, all accumulated sediment must be removed from the storage areas prior to final grading and stabilization. V/XXXIV. ACCESS ROAD AND TRANSMISSION LINE CONSTRUCTION PLANS Final Access Road and Transmission Line construction plans must be submitted to the SJRWMD at least 30 days prior to commencement of construction. The final plans must be consistent with the plans and calculations received by the SJRWMD on July 22, 1991, such that the requirements of Chapters 40C-4, 40C-41 and 40C- 42, F.A.C. continue to be met. V/XXXV. ACCESS ROAD FILL The fill material for the access roads must satisfy the soil properties assumed in the calculations received by the SJRWMD on July 22, 1991. If fill is to be acquired on site, a plan depicting the location of the area to be used for fill for the Access Roads must be submitted to the SJRWMD at least 30 days prior to commencement of construction. Access to the on-site fill material must be shown on the plan. V/XXXVI. CONTRACTOR REVIEW AND POSTING OF CONDITIONS OF CERTIFICATION OUC, et al., must require the contractor to review and maintain a copy of this document, complete with all conditions, attachments, and exhibits, in good condition and posted on the construction site. Part VI Conditions Recommended by the Florida Department of Transportation VI/I. CONSTRUCTION IMPACT MITIGATION PROGRAM OUC shall develop and implement at its own expense a construction traffic impact mitigation program after consultation with DOT, and report that will be submitted to DOT prior to commencement of construction of Stanton Unit 2. The program will detail the actions that OUC will take to reduce the impacts of construction traffic, which report shall address the following actions: OUC shall actively promote and encourage car-pooling by construction companies and workers, including contractors and subcontractors, from whom it obtains construction services, and OUC shall further explore with appropriate public mass-transportation providers in the area the possibility of park-and- ride service to the site. OUC shall utilize to the extent practicable the existing railway access to the Stanton site for the delivery of equipment and materials needed for the project construction. OUC will explore with its contractors and subcontractors the practicability of staggering construction employee work schedules, and encourage the staggering of shifts to the extent feasible to mitigate peak hour traffic congestion problems. OUC will consult with the appropriate Winter Park DOT personnel regarding the practicality of providing temporary traffic control devices and alteration of signal times to assist in maintaining proper traffic flow at the most affected intersections which are the intersections of Alafaya Trail with both the East-West Expressway and State Road 50. OUC shall suggest and encourage the use by construction personnel of alternate public road access to the Stanton site as appropriate to alleviate traffic congestion. Part VII Conditions Stipulated for the Red-Cockaded Woodpecker Management Area VII/I. RED-COCKADED WOODPECKER MANAGEMENT AREA IDENTIFICATION All lands depicted on Figure 4.2 (attached hereto) of the August 1981 red- cockaded woodpecker (RCW) Management Plan, except for the area specifically identified as "construction impact of proposed generating Units 1, 2, 3, and 4" constitute the red-cockaded woodpecker management area subject to the Management Plan specified in Condition XXXI of the Site Certification granted OUC by the Siting Board on December 14, 1982. (DOAH Case No. 81-1431) VII/II. USE AND LIMITATIONS OF THE RCW AREA With regard to the RCW management area, in addition to Condition XXXI of the December 14, 1982 Order of the Florida Siting Board: OUC may conduct activities within the RCW management area described in Condition XXXI which are provided for in the Siting Board's certification orders for Units 1 and 2, including without limitation the execution of habitat restoration, enhancement, and creation required as mitigation. OUC may conduct management, including maintenance in their existing configuration and condition, of existing unpaved private roads utilized by OUC, maintenance of existing water and sewer lines, of existing transmission lines and substation, and other maintenance and management activities within the area of Condition XXXI which are consistent with its purposes. OUC shall take appropriate action to manage the RCW management area to achieve the purposes required by Condition No. XXXI with regard to the red- cockaded woodpecker, and in general to preserve the natural conditions of the area, including other protected species of native wildlife, vegetation, wetlands, and particularly the tributaries and headwaters of the Econlockhatchee River. OUC may act to implement the red-cockaded woodpecker management plan, to monitor its effectiveness, and to react to fire, flood, or other unforeseeable natural or manmade disturbances. Any reports generated by OUC concerning activities within or management of the RCW management area shall be provided to the Florida Game and Fresh Water Fish Commission. OUC shall allow only those activities of others within the RCW Management Area which are consistent with its management in a natural state. Such activities shall be limited to environmentalrestoration, scientific research, habitat management (such as controlled burning) and nature study. Unless specifically authorized by an order of the Siting Board, dredging, filling, construction of buildings, road-ways, dumping of debris, excavation, and clearing of native vegetation shall be prohibited in the area defined by Condition XXXI. The provisions of Sections 403.516(1) (a) and (b) notwithstanding, OUC agrees that any activity prohibited in this paragraph within the area described in the RCW management area shall be authorized only by affirmative vote of the Siting Board. OUC hereby stipulates as a factual matter, which shall be binding on it, and all of its officers, agents, attorneys, and employees, that the "alternate access road" authorized by this supplemental certification completes the necessary roadway access for Units 1 and 2, to allow the full development thereof. Any additional access for electric power generation, and any additional facilities necessary for the construction of Units 3 and 4 will be the subject of a comprehensive Supplemental Certification application or applications for Units 3 and 4. If OUC determines to pursue a modification of its certification with regard to the easement recorded December 30, 1987, at ORB 3946, Page 3187, Orange County, Florida, it shall do so as a ministerial act only and shall not actively utilize its resources, funds or personnel to support such an application. [Final page of conditions of certification is a map "areas of construction impacts of red-cockaded woodpeckers" which is attached to all hard copies of this order.] APPENDIX B TO RECOMMENDED ORDER, CASE NO. 91-1813EPP The following constitutes my specific rulings pursuant to Section 120.59(2), Florida Statutes, on the proposed findings of fact submitted by the parties in this case. Specific Rulings on Proposed Findings of Fact Submitted by the Applicants, OUC, et al. Each of the following proposed findings of fact is adopted in substance as modified in the Recommended Order. The number in parentheses is the Finding of Fact which so adopts the proposed finding of fact: 4(4); 6(1); 8(2); 9(3); 10(7); 14(8); 15(9); 20-22(10-12); 24-28(13-17); 40-61(18-40); 70-82(41-53); 84- 86(54-56); 89(57); 90(58); 97-100(60-63); 109(59); 110(64); 112(70); 115-117(71- 73); 120(83&84); 121 & 122(85); 123(86); 124(87-91); 125(92);136-148(93-105); 149(108); 151(111); 191-201(114-124); 203 & 204(125 & 126); 206-209(127-130); 212(131); and 215-223(132-140). 2. Proposed findings of fact 1-3, 5, 11, 12, 16-19, 23, 29-33, 38, 39, 62-69, 83, 101-108, 111, 113, 114, 118, 119, 127, 128, 150, 152, 202, 205, 210, and 211 are subordinate to the facts actually found in this Recommended Order. 3. Proposed findings of fact 7, 13, 87, 88, 91-96, 126, 129-135, 153-190, 213, and 214 are unnecessary. 4. Proposed findings of fact 34-37 are irrelevant. Specific Rulings on Proposed Findings of Fact Submitted by Department of Environmental Regulation 1. Each of the following proposed findings of fact is adopted in substance as modified in the Recommended Order. The number in parentheses is the Finding of Fact which so adopts the proposed finding of fact: 1-104(1-104) and 105- 127(114-136). Specific Rulings on Proposed Findings of Fact Submitted by St. Johns River Water Management District 1. Each of the following proposed findings of fact is adopted in substance as modified in the Recommended Order. The number in parentheses is the Finding of Fact which so adopts the proposed finding of fact: 1(4); 4-6(1-3); 9(8); 10- 13(10-13); 23(93); 34-36(93-95); 39(98); 41-44(99); 47(100); 49(102); 52(104); 53-55(105-107); 56(109); 58(109); 67-72(41-46); 73-84(46-52); 86(55); 87(39 & 40); 88(125); 90(128); and 91(40). 2. Proposed findings of fact 2, 3, 7, 8, 14-22, 24-33, 37, 38, 40, 46, 48, 50, 51, 62, 63, 85, and 92 are subordinate to the facts actually found in this Recommended Order. Proposed finding of fact 57 is unnecessary. Proposed findings of fact 45, 59-61, 64, 65, and 93 are irrelevant. Proposed finding of fact 66 is unsupported by the credible, competent and substantial evidence. COPIES FURNISHED: Richard Donelan, Assistant General Counsel Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, FL 32399-2400 Thomas B. Tart, General Counsel Orlando Utilities Commission 500 South Orange Avenue Orlando, FL 32801 Kenza Van Assenderp, Attorney at Law C. Laurence Keesey, Attorney at Law Young, van Assenderp, Varnadoe & Benton P. O. Box 1833 Tallahassee, FL 32302-1833 Fred Bryant, Attorney at Law Moore, Williams, Bryant & Peoples 306 East College Avenue Tallahassee, FL 32302 James Antista, General Counsel Florida Game and Fresh Water Fish Commission Bryant Building 620 South Meridian Street Tallahassee, FL 32399-1600 Ken Plante, General Counsel Florida Department of Natural Resources 3900 Commonwealth Boulevard Tallahassee, FL 32399 Kathryn Mennella Senior Assistant General Counsel St. Johns River Water Management District P. O. Box 1429 Palatka, FL 32178-1429 G. Stephen Pfeiffer, General Counsel Kathryn Funchess, Assistant General Counsel Department of Community Affairs 2740 Centerview Drive Tallahassee, FL 32399-2100 Cliff Guillet East Central Florida Regional Planning Council 1011 Wymore Road, Suite 105 Winter Park, FL 32789 Tom Wilks, Attorney at Law Orange County 201 South Rosalind Avenue 6th floor Orlando, FL 32801 John Fumero, Attorney at Law South Florida Water Management District 3301 Gun Club Road P. O. Box 24680 West Palm Beach, FL 33416-4680 Michael Palecki Bureau Chief, Electric and Gas Division of Legal Services Florida Public Service Commission 101 East Gaines Street Fletcher Building, Room 212 Tallahassee, FL 32399-0850 Hamilton S. Oven, P.E., Administrator Siting Coordination Office Division of Air Resources Management Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, FL 32399-2400 Charles Lee Senior Vice President Florida Audubon Society 460 Highway 435, Ste. 200 Casselberry, FL 32707 William H. Roberts Assistant General Counsel Department of Transportation 605 Suwannee Street, MS-58 Tallahassee, FL 32399-0458 Honorable Lawton Chiles Governor State of Florida The Capitol Tallahassee, FL 32399 Honorable Robert A. Butterworth Attorney General State of Florida The Capitol Tallahassee, FL 32399-1050 Honorable Bob Crawford Commissioner of Agriculture State of Florida The Capitol Tallahassee, FL 32399-0810 Honorable Betty Castor Commissioner of Education State of Florida The Capitol Tallahassee, FL 32399 Honorable Jim Smith Secretary of State State of Florida The Capitol, PL-02 Tallahassee, FL 32399-0250 Honorable Tom Gallagher Treasurer and Insurance Commissioner State of Florida The Capitol Tallahassee, FL 32399-0300 Honorable Gerald A. Lewis Comptroller State of Florida The Capitol, Plaza Level Tallahassee, FL 32399-0350
Findings Of Fact There is no dispute as to the facts involved in this rule challenge. Johnson Controls, Inc. is a large corporation operating throughout the United States. It engages in the business of manufacturing electrical components and in constructing, installing and servicing electrical control systems and other phases of electrical contracting work. As its name implies, Johnson Controls' primary emphasis in the electrical field is in selling, installing, and maintaining systems for fire, security, heating, air conditioning, and energy consumption controls. Johnson Controls is presently licensed to do electrical contracting work by 23 counties and municipalities in Florida and in 49 of the 50 states. Winfred Allen Infinger holds a B. E. degree in Technology and Construction, a journeyman electrician's license in Pinellas County, and is fully qualified by training and experience to be the qualifying agent of Johnson Controls in this application. In its letter of May 8, 1979 denying petitioner's application, Respondent, through its executive director, stated the following grounds: Your application failed to meet the qualification as that of a Florida licensed electrical contractor (468.181(5)) whose services are unlimited in the Electrical Field. The review of your application reflects that Johnson Controls, Inc., is a specialty contractor and presently Florida Statutes, Chapter 468, Part VII does not provide for licensure of specialty contractors.
The Issue The issue to be determined is whether the Governor and Cabinet, sitting as the Siting Board, should approve the Site Certification Application ("Application") submitted by Florida Power & Light Company ("FPL"), pursuant to the Florida Power Plant Siting Act ("PPSA"), sections 403.501 through 403.518, for the construction and operation of a new electrical power generation facility, Dania Beach Energy Center ("DBEC") at FPL's existing Lauderdale Site in Broward County, Florida; and, if so, the Conditions of Certification that should be imposed.
Findings Of Fact The Parties FPL is the applicant for site certification for the DBEC electrical power plant5/ at issue in this proceeding. FPL is the largest electric utility in Florida, serving approximately 4.9 million customer accounts. Its service territory covers approximately 28,000 square miles, in all or part of 35 counties in Florida, and in Georgia. Its 53 existing electrical power generating units are located at power plants throughout its service territory, and consist of diverse generation technologies, including nuclear units, coal-burning units, combined cycle units, oil/gas steam units, combustion turbines, gas turbines, and solar facilities. As of December 2016, FPL had a total system electrical power generation capacity of 26,267 megawatts ("MW"). DEP is the state agency charged with administering the PPSA, which is codified at chapter 403, part II. Specifically, the SCO administers the PPSA and coordinates the site certification process, including receiving comments from the affected agencies and preparing the PAR, which contains the proposed Conditions of Certification.6/ Sierra is a national non-profit environmental advocacy organization. A key component of Sierra's mission is to advocate for the use of clean energy sources. As discussed below, Sierra was granted intervenor status pursuant to section 403.508(3)(e), subject to proving that its substantial interests are affected in this proceeding. The DBEC Electrical Power Plant FPL's Lauderdale Site FPL owns and operates the Lauderdale Site, an existing electrical power generating facility site located on approximately 392 acres in the City of Dania Beach and the City of Hollywood, in Broward County, Florida. The Site is approximately one mile west of Interstate 95 and approximately 1/4 mile south of Interstate 595. It has served as an operating power plant site for more than 90 years, and has existing infrastructure consisting of a transmission switch yard, a gas yard, an existing gas transmission pipeline, an existing electrical transmission system, water lines, fuel storage tanks, and a sewer line. Currently, the Lauderdale Site features five electrical power generation units: Units 4 and 5, which consist of four combined cycle units comprised of four 1990s-vintage combustion turbines ("CTs"), four heat recovery steam generators ("HRSGs"), and two 1950s-vintage steam turbines; Unit 6, which consists of five 200-MW single cycle CTs used as "peakers" to generate additional electrical power during periods of peak demand; and two 35 MW units. Location of DBEC DBEC is proposed to be constructed on the portion of the Lauderdale Site that is located within the City of Dania Beach. The City of Dania Beach recently amended its Comprehensive Plan to add the Electrical Generation Facilities use category to the Future Land Use Element and to so designate, on its Future Land Use Map, the portion of the Lauderdale Site on which DBEC will be constructed. DBEC is proposed to be constructed and operated on the portion of the Lauderdale Site on which Units 4 and 5 currently are located. These units will be completely dismantled and removed before construction of DBEC commences.7/ DBEC will use much of the existing infrastructure that currently serves Units 4 and 5. This infrastructure includes existing fuel and storage tanks, an existing gas transmission pipeline, existing electrical transmission lines, existing cooling water intake at the Dania Cutoff Canal, and existing cooling water discharge structures. The major new components of DBEC will be constructed at an elevation of 11.5 feet above mean sea level. The existing infrastructure that will be used by DBEC will not be raised above its current elevation above mean sea level. Unit 7 Technology Unit 7, as proposed, will consist of a new two-on-one combined cycle electrical power generation unit with a nominal rating of 1,200 MW. A combined cycle electrical generation system generates electrical power in two cycles. In the first cycle, ambient air is drawn into the multistage compressor, where it is compressed, then directed to the combustor section, where fuel——in this case, natural gas——is introduced, ignited, and burned. The hot combustion gases are diluted with additional cool air and directed to the turbine section, where they expand, causing the CT, which is connected to a generator, to rotate, producing electricity. The captured gases are then routed to a HRSG, which begins the second cycle. In this cycle, the heat from the captured gases is used to convert water to steam, which drives a steam turbine generator ("STG"), producing additional electricity. Each CT/HRSG combination is termed a "train." Unit 7 will have two CT/HRSG trains, each having a gross generation capacity of 400 MW at an inlet air temperature of 75 degrees Fahrenheit. These two CT/HRSG trains will be connected to one STG having a generation capacity of 400 MW. The combination of the two CT/HRSG trains with one STG gives rise to the "two-on-one combined cycle" label for this type of power generation unit. Combined cycle systems, such as the one that will constitute Unit 7, are significantly more efficient than single cycle units that involve only combustion turbines. This increased efficiency is due to the addition of the second cycle, which uses captured exhaust heat from the first cycle to create steam, which is then used to turn a steam turbine, thereby generating an additional 400 MW of electricity per total amount of fuel burned. Operating efficiency for combined cycle units is measured in terms of "heat rate," which is an expression of how efficiently the fuel is converted to electrical energy. The lower the heat rate, the more efficient the electrical power generation unit. Unit 7 is a modern combined cycle plant and is expected to achieve a heat rate of approximately 6,119 British Thermal Units ("BTUs") per kilowatt hour. By contrast, Units 4 and 5——which are also combined cycle units but use older, less efficient equipment——have an average heat rate of approximately 7,800 BTUs per kilowatt hour. As noted above, Unit 7 will use natural gas as its primary fuel. The natural gas will be delivered to the DBEC site through an existing natural gas pipeline, which originates offsite and is not part of this site certification proceeding.8/ Ultra-low sulfur distillate ("ULSD") oil will be used as the back-up fuel. Unit 7 Effect on FPL System-wide Natural Gas Consumption As noted above, Unit 7 will use the most modern combined cycle technology. Dr. Steven Sim, FPL's director of Integrated Resource Planning, prepared a projection of the effect Unit 7 will have on natural gas consumption by FPL's electrical power generation units on a system-wide basis. Using a model that simulates the operation of all electrical generating units on FPL's system, FPL compared, for natural gas fuel consumption on a system-wide basis, two scenarios: one in which Units 4 and 5 continue to operate indefinitely and Unit 7 is not constructed and operated; and one in which Units 4 and 5 are retired in the fourth quarter of 2018, and Unit 7 is constructed and commences operation in mid-2022. The inputs to the model included a range of information, including the electrical load that FPL will serve in the future, on an hourly, monthly, and yearly basis, for a period of 30 years; information, for each of FPL's 53 electrical power generation units regarding individual generating capacity, fuel use efficiency, scheduled maintenance outages, and forced outages; fuel costs; environmental compliance costs; and the addition of other power-generation resources to meet future forecasted demand. The model was used to determine which of FPL's generating units operate during each hour, in order to determine how to most economically generate electrical power. The model projected a significant reduction in natural gas consumption by FPL on a system-wide basis over a 30-year horizon if Units 4 and 5 are retired in late 2018 and Unit 7 commences operation in 2022. Conversely, if Units 4 and 5 are not retired and continue to operate9/——which will be the case if Unit 7 is not certified——the model showed that FPL will consume substantially more natural gas on a system-wide basis over a 30- year horizon, from 2018 through 2047, than if Unit 7 is certified, constructed, and begins operating in 2022. Assuming Units 4 and 5 are retired in 2018 and Unit 7 commences operation in 2022, the model-generated comparative natural gas consumption amounts shows a consistent system-wide decrease in natural gas consumption in amounts ranging from slightly over two million cubic feet per year to slightly over six million cubic feet per year, for a projected total decrease in system-wide natural gas consumption of nearly 134 million cubic feet over the 30-year horizon. This is because the operation of Unit 7 will displace less-efficient gas burning units that otherwise would be used if Unit 7 does not operate. Further, because the model-generated projected natural gas consumption amounts simply compared the "with Units 4 and 5 and without Unit 7" scenario to the "without Units 4 and 5 and with Unit 7" scenario, with all other variables being held constant, the projected natural gas consumption differential between the two scenarios would not change, regardless of whether, and which, additional types of energy-generation resources were added to FPL's system. Dr. Sim acknowledged that the social costs of carbon were not considered as part of the modeling of FPL's system-wide projected natural gas consumption. However, he noted that as a practical matter, because Unit 7 will operate more efficiently, FPL will demand less natural gas on a system-wide basis to fuel its electrical power generating units. As a result of reduced demand, less natural gas will need to be produced and transported by pipeline to fuel FPL's electrical power plant generating system. Public Service Commission Need Determination Pursuant to section 403.519, FPL filed a petition for determination of need for DBEC with the PSC in October 2017. Sierra intervened into the need determination proceeding. The final hearing was held on January 17, 2018. The PSC issued the Need Determination for DBEC Unit 7 on March 19, 2018. This Order, which constitutes final agency action, was not appealed. During the need determination proceeding, Sierra contended, and presented evidence in an effort to show, that renewal energy sources and technologies, such as solar facilities, could be deployed incrementally to delay or potentially entirely forestall the need for Unit 7. Thus, as part of the need analysis, the PSC specifically considered the feasibility of using renewable generation options and sources, including solar facilities. The PSC specifically determined that the use of such generation options and sources, including solar facilities, was less cost-effective than DBEC. The PSC found that: "[n]o additional cost-effective renewable resource has been identified in this proceeding that can mitigate the need for new generation. Similarly, no additional cost-effective [Demand Side Management] has been identified in this proceeding that can mitigate the need for new generation." Based on the evidence and argument presented in the need determination proceeding, the PSC granted the Need Determination for DBEC Unit 7, specifically finding and concluding that "the Dania Beach Clean Energy Center Unit 7 is the most cost-effective alternative that maintains Florida Power & Light Company's system and Southeastern Florida area reliability compared to other alternatives[.]" Section 403.519(3) states: The commission shall be the sole forum for the determination of [need], which accordingly shall not be raised in any other forum or in the review of proceedings in such other forum. In making its determination, the commission shall take into account the need for electric system reliability and integrity, the need for adequate electricity at a reasonable cost, the need for fuel diversity and supply reliability, whether the proposed plant is the most cost-effective alternative available, and whether renewable energy sources and technologies, as well as conservation measures, are utilized to the extent reasonably available. The commission shall also expressly consider the conservation measures taken by or reasonably available to the applicant or its members which might mitigate the need for the proposed plant and other matters within its jurisdiction which it deems relevant. The commission's determination of need for an electrical power plant shall create a presumption of public need and necessity and shall serve as the commission's report required by s. 403.507(4). An order entered pursuant to this section constitutes final agency action. § 403.519, Fla. Stat. (emphasis added). Pursuant to this statute, the PSC is the only entity authorized to determine whether an electrical power plant is needed, and whether, given the need for the power plant, the applicant should be required to implement renewable energy sources and technologies, including the use of solar generation facilities. Here, the PSC determined that DBEC is needed, and further determined that the use of renewable energy sources and technologies, such as solar technology, was not cost-effective, and, therefore, was not reasonably available. Pursuant to the plain language of section 403.519(3), it is beyond the scope of this proceeding for the undersigned or the Siting Board to require, as a condition of site certification for DBEC, the use of alternative energy sources or technologies, such as solar or other forms of renewable energy, or to deny DBEC's site certification on the basis that such technologies are not proposed as part of the project. DBEC Emissions and Air Construction/Prevention of Significant Deterioration Permit Florida's Air Quality Regulatory Program In Florida, DEP implements the federal air regulatory programs under the Clean Air Act, subject to approval and oversight by the United States Environmental Protection Agency ("EPA"). Under this system, DEP is the permitting authority, while EPA retains commenting authority. DEP rules implementing the Clean Air Act consist of several air quality regulatory programs. Pertinent to this proceeding are the National Ambient Air Quality Standards ("NAAQS") and Prevention of Significant Deterioration ("PSD") programs. Under the Clean Air Act, EPA is required to promulgate NAAQS for certain air pollutants called "criteria" pollutants. The primary NAAQS establish levels of air quality that are necessary to protect the public health, with an adequate margin of safety to protect sensitive populations. Secondary NAAQS also may be established to protect the public welfare, which can include environmental impacts. 40 C.F.R. § 50.2(b). NAAQS have been developed for six air pollutants: sulfur dioxide, nitrogen dioxide, carbon monoxide, ozone, certain sizes of particulate matter, and lead. NAAQS have not been established for greenhouse gases ("GHGs"). For each of the six criteria air pollutants for which NAAQS have been developed, EPA has designated areas within each state that either meet or do not meet the NAAQS for that specific pollutant. Areas in which the NAAQS for a specific criteria air pollutant is met are termed "attainment" areas for that pollutant, while areas in which the NAAQS is not met for a specific criteria pollutant are termed "nonattainment" areas for that pollutant. Attainment areas are classified as Class I, which need special air quality protection; or Class II, which do not need special air quality protection. Everglades National Park and designated national wilderness areas are the only Class I attainment areas in Florida. All other attainment areas in Florida are designated as Class II. Broward County, including the DBEC site, is in a Class II attainment area for all NAAQS. The PSD program applies in attainment areas to limit the air quality impacts that may result from new or modified major sources of air pollution. Its purpose is to assure that the air quality in areas meeting the NAAQS does not significantly deteriorate below an established baseline. Under the PSD program, all major new sources of air pollution are subject to preconstruction review to determine whether significant air quality deterioration will result from the facility. As part of the PSD review, the new source is required to demonstrate compliance with PSD increments, which effectively constitute small amounts of air quality impacts that new or modified major sources of air pollution cannot exceed. PSD increments are more stringent than NAAQS, and, as such, they protect against air quality degradation in attainment areas. If an area meets the NAAQS for a specific criteria pollutant, PSD increments prevent the addition of that pollutant in greater than that incremental amount over an established baseline concentration for that pollutant. No PSD increments have been established for GHGs. The PSD program also requires demonstration that the air pollution source will use the Best Available Control Technology ("BACT"). BACT is defined, in pertinent part, as: an emission limitation based on the maximum degree of reduction of each pollutant subject to regulation under this chapter emitted from or which results from any major emitting facility, which the permitting authority, on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cleaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant. 40 U.S.C. § 7479(3). More simply stated, BACT is the maximum degree of emission reduction that is available and feasible for the source, taking into account environmental, energy, economic impacts, and other costs. BACT requires a "top-down" analysis, which starts with the most stringent emission limits demonstrated feasible for a specific air pollution source category, as applied throughout the country. EPA has created a software tool accessible on its website, that enables a review of different source categories to determine the most stringent applicable control technology that meets the definition of BACT for that particular source type. BACT also must be at least as stringent as new source performance standards ("NSPS"), which are EPA-developed emissions limits for specific pollutants emitted by new or modified air pollution sources within a particular source category. The NSPS applicable to combined cycle combustion turbines, such as those that will comprise Unit 7, are nitrogen oxides, sulfur dioxide, and GHGs. DBEC Emissions DBEC will have several sources of air emissions. These consist of the two CTs that are part of the CT/HRSG trains discussed above; an auxiliary boiler; two emergency diesel generators, two natural gas heaters; a fire water pump diesel engine; a 14-cell auxiliary cooling system; and circuit breakers containing sulfur hexafluoride located in the Unit 7 power block. Of these, the CTs constitute the most significant air emissions source. DBEC's air emissions sources will emit nitrogen oxides, carbon monoxide, volatile organic compounds, sulfur dioxide, sulfuric acid, particulate matter ("PM") 10 and PM2.5, and GHGs. The GHGs emitted by DBEC will consist primarily10/ of carbon dioxide, with small amounts of methane.11/ DBEC's Air Construction/PSD Permit FPL applied to DEP for an air construction/PSD permit for DBEC in July 2017. DEP issued the air construction/PSD permit for DBEC ("Air Permit") in December 2017. The Air Permit was not challenged and became final agency action on December 24, 2017. It is valid through December 31, 2027. Pursuant to section 403.509(5), the Air Permit is not subject to revision or modification in this proceeding.12/ Because DBEC will emit 100 tons per year or more of regulated pollutants and is included in a source category to which the 100-tons-per-year threshold applies, it constitutes a major stationary source of air pollution. See Fla. Admin. Code R. 62-210.200(154)(a)1. Therefore, under Florida and federal law, FPL was required to obtain an air construction/PSD permit for DBEC. As part of the PSD review, FPL was required to perform a control technology review; to demonstrate that all applicable state and federal emission limiting standards would be met; and to determine and implement BACT to control the emissions. Projected emissions of carbon monoxide, volatile organic compounds, sulfur dioxide, sulfuric acid, PM10 and PM2.5, and GHGs underwent PSD review. Initial PSD modeling for projected carbon monoxide and sulfur dioxide emissions showed that these emissions would not exceed "significant impact levels," so no further review beyond the modeling was required. Initial modeling showed that PM10 and PM2.5 emissions would exceed the "significant impact level," so the modeling results were compared to the Class I and Class II PSD increments. This comparison showed that neither PM10 emissions nor PM2.5 emissions would exceed the increments for these pollutants. Accordingly, FPL demonstrated that DBEC would comply with the incremental standards for these pollutants. DBEC also meets BACT for volatile organic compounds emissions. The primary BACT for GHG emissions for Unit 7, as a combined cycle unit, is the efficiency of the unit itself in producing electrical power using low-GHG emitting fuels, such as natural gas. As previously discussed, Unit 7 will be an extremely efficient combined cycle unit that will use natural gas as its primary fuel. The Air Permit limits the emissions rates for, and amounts of, GHG emissions. These are consistent with BACT, as determined comparing DBEC's control technology to all other types of GHG control technology for CTs throughout the country. The Air Permit also imposes an extremely stringent methane monitoring requirement. Pursuant to these measures, DBEC was determined to meet the BACT requirement applicable to GHGs.13/ Additionally, DBEC will meet the NSPS applicable to CTs.14/ Specifically, DBEC emissions of nitrogen oxides will be 7.5 times lower than the NSPS limit for that pollutant, and DBEC emissions of sulfur dioxide will be ten times lower than the NSPS standard for that pollutant. Accordingly, DBEC will meet the NSPS for these pollutants. DBEC also will meet the applicable NSPS for GHGs.15/ The NSPS for GHG emissions applicable to combined cycle CTs is 1,000 pounds per MW hour ("lbs/MWh"). DBEC is projected to produce 727 lbs/MWh of GHGs when burning natural gas——well below the 1,000 lbs/MWh NSPS limit. The Air Permit also imposes emissions standards for carbon monoxide, PM10 and PM2.5, sulfur dioxide, sulfuric acid mist, volatile organic compounds, and GHGs. The competent, credible evidence established that replacing Units 4 and 5 with Unit 7 will reduce the emissions of nitrogen oxides, PM10 and PM2.5, volatile organic compounds, sulfur dioxide, and carbon monoxide by approximately 6.6 million pounds for the period from 2018 to 2047. The evidence also established that replacing Units 4 and 5 with Unit 7 is projected to result in an approximately 22-percent reduction in GHGs generated, measured in lbs/MWh, assuming Unit 7 is operated at the same frequency as Units 4 and 5. This comparative reduction in GHG emissions on a lbs/MWh basis underscores the efficiency of Unit 7 compared to Units 4 and 5. Additionally, the credible evidence established that the operation Unit 7 will result in a system-wide reduction of GHG emissions for the period from 2018 to 2047.16/ The retirement of Units 4 and 5 in 2018 and commencement of operation of Unit 7 in 2022 may not result in reduced total amounts of GHG emissions generated at the Lauderdale Site. This is because even though Unit 7 is substantially more efficient than Units 4 and 5——so will burn substantially less natural gas——it may operate more often because it will be the most efficient electrical power generating unit in FPL's electrical power generation system. However, the competent, credible evidence showed that the operation of Unit 7 will reduce GHG emissions across FPL's electrical power generating system because it will be operated more often than other, less efficient units, thereby displacing the use of those units across FPL's electrical power generation system. Stated another way, because Unit 7 will be a significantly more efficient electrical power generating unit—— meaning that it will produce more electricity per cubic foot of natural gas than FPL's less efficient units——it will be operated more frequently than FPL's less efficient units, resulting in reduced consumption of natural gas on a system-wide basis. Reduced natural gas consumption on a system-wide basis will result in a reduced total amount of GHGs generated on a system-wide basis from FPL's electrical power generating plants. The competent, credible evidence establishes that the retirement of Units 4 and 5 in 2018 and the addition of Unit 7 in 2022 will result in a total reduction of approximately 8.1 million tons17/ of GHG emissions in the form of carbon dioxide18/ across FPL's electrical power generation system for the period from 2018 to 2047.19/ Sierra contends that DBEC will "[e]mit millions of tons more [GHGs] every year than the units it replaces." As discussed above, the evidence shows that the operation of Unit 7 in conjunction with the retirement of Units 4 and 5 in 2018 may not result in reduced GHG emissions at the Lauderdale Site because, due to its efficiency, Unit 7 may be operated more frequently and at higher capacity. However, the competent, credible, and persuasive evidence establishes that the total GHG emissions from FPL's electrical power plant generating units will be reduced on a system-wide basis by approximately 8,123,624 tons over the period between 2018 and 2047. Further, Sierra's position that retiring Units 4 and 5 in 2018 and operating Unit 7 beginning in 2022 will result in a greater total amount of GHGs being emitted appears grounded in the assumption that if Unit 7 does not go into operation, FPL will retire Units 4 and 5 by 2033. However, this assumption is not supported by any competent substantial evidence in the record,20/ and was directly contradicted by Dr. Sim, who testified that Units 4 and 5 realistically could operate indefinitely. In sum, the competent, credible, and persuasive evidence shows that if DBEC does not commence operation in 2022, and Units 4 and 5 continue to operate indefinitely, FPL's GHG emissions on a system-wide basis will be approximately 8,123,624 tons more for the period between 2018 and 2047 than if Units 4 and 5 are retired in 2018 and Unit 7 commences operation in 2022. In sum, FPL demonstrated that DBEC meets all applicable state and federal air regulatory and permitting requirements for DBEC and, specifically, for Unit 7. As discussed above, FPL demonstrated that DBEC will meet the applicable BACT requirement——which literally means the best available control technology——for GHG emissions, as well as other emissions from Unit 7 and other emissions sources. Additionally, the air construction/PSD permit establishes emissions limits for DBEC, and, specifically, for Unit 7, and FPL demonstrated, to DEP's satisfaction, that its emissions control technology will meet the applicable standards, which are more stringent than applicable NSPS limits. Thus, FPL demonstrated that DBEC will meet state and federal law regarding emissions limitations for GHGs and other pollutants emitted by DBEC. Sierra's Contentions Regarding GHG Emissions from DBEC Notwithstanding that FPL demonstrated that DBEC meet all applicable air rules and regulations, Sierra contends that the Siting Board should either deny the site certification for DBEC or approve it with conditions (addressed below) because, it alleges, FPL and/or DEP failed to consider or address numerous environmental issues regarding projected GHG emissions for DBEC. These alleged deficiencies are: failure of FPL and/or DEP to perform modeling of the "the environmental impact" of DBEC's GHG emissions; failure of FPL and/or DEP to analyze the "social costs of carbon" emitted by DBEC; failure of FPL and/or DEP to perform a "life-cycle analysis" to analyze DBEC's GHG emissions "from start to finish, . . . from gas generation to gas burn"; failure of FPL and/or DEP to consider the cumulative impacts of DBEC's emissions combined with GHG emissions "from other existing and foreseeable permitted sources in Florida and elsewhere"; and failure of FPL and/or DEP to consider the use of solar electrical power generation.21/ Each of these challenges is addressed below. Failure to Model Endpoint Environmental Impact With respect to FPL's and/or DEP's alleged failure to perform modeling of "the environmental impact" of DBEC's GHG emissions, the evidence establishes that FPL and DEP complied with the applicable state rules and federal regulatory requirements in addressing GHG emissions from DBEC. To that point, Syed Arif, who performed the air construction/PSD permit application review, testified that modeling of the environmental impacts of DBEC's projected GHG emissions offsite was not performed because it is not required by the applicable state rules and federal regulations. Indeed, EPA's PSD Guidance document22/ specifically states that "[w]hen conducting a BACT analysis for GHG's, the environmental impact analysis should continue to concentrate on impacts other than direct impacts due to emissions of the regulated pollutant in question." This document further states, in pertinent part: When weighing any trade-offs between emissions of GHGs and emissions of other regulated NSR pollutants, EPA recommends that permitting authorities focus on the relative levels of GHG emissions rather than the endpoint impacts of GHGs. As a general matter, GHG emissions contribute to global warming and other climate changes that result in impacts on the environment and society. However, due to the global scope of the problem, climate change modeling and evaluations of risks and impacts of GHG emissions currently is typically conducted for changes in emissions orders of magnitude larger than the emissions from individual projects that might be analyzed in PSD permit reviews. Quantifying these exact impacts attributable to the specific GHG source obtaining a permit in specific places is not currently possible with climate change modeling. Given these considerations, an assessment of the potential increase or decrease in the overall level of GHG emissions from a source would serve as the more appropriate and credible metric for assessing the relative environmental impact of a given control strategy. EPA PSD Guidance, at pp. 41-42 (emphasis added). In sum, state and federal PSD permitting law does not require an analysis of endpoint impacts of GHGs, and, further, expressly recognizes that due to the global scope of GHG emissions' contribution to climate change, climate change modeling and risk/impact evaluation of GHG emissions is conducted on a scale orders of magnitude larger than the emissions from individual projects. Additionally, the guidance expressly recognizes that determining the exact climate change impacts due to GHGs emitted on a source-specific basis is not currently possible with climate change modeling. Sierra's contention that the site certification for DBEC should be denied or additional GHG-related conditions imposed due to project-specific environmental endpoint impacts is not persuasive, because it is not grounded in applicable law and, as discussed above, is not possible using current climate change modeling. Failure to Consider and Address Social Costs of Carbon Sierra also contends that the site certification for DBEC should be denied or additional GHG-related conditions imposed because FPL and/or DEP failed to analyze the social costs of carbon emitted by DBEC, particularly by Unit 7, and failed to mitigate or minimize those costs. The social cost of carbon is defined as the present monetary value of the additional damages caused by emitting one more ton of carbon dioxide. In general terms, the social cost of carbon is the economic cost per ton of emissions. For each incremental ton of carbon emissions, there is an incremental amount of harm. There are different methods, or models, for determining the social cost of carbon. They vary depending on the types of data used in the model, as well as how the models address issues such as the rate of climate change; whether the models adequately and accurately address catastrophic risk; and whether the models address "tipping points" at which climate change becomes abruptly and irreversibly worse. Sierra's expert on the social cost of carbon, Dr. Frank Ackerman,23/ presented the results of integrated assessment models used to estimate the social cost of carbon.24/ These types of models have been applied in various studies to estimate, in 2017 dollars, the cost per metric ton of carbon dioxide. These studies generated estimates of the social cost of carbon ranging from as low as $39 per metric ton in 2020 to as high as $1,821 in 2050, with each study generating a range of projected values for the first year modeled——either 2020 or 2025——through the last year modeled——either 2050 or 2055. These widely-ranging values for the modeled years over these 30-year periods are due to the substantial uncertainty and disagreement regarding the rate and extent of climate change, and whether there are tipping points that must be taken into consideration. Ackerman estimated the social cost of carbon, as of 2012, as ranging from $33 to $1,048 per metric ton of carbon dioxide in 2020, to $75 to $1,821 per metric ton of carbon dioxide in 2050. Ackerman prepared a report analyzing the social cost of carbon from DBEC's projected GHG emissions. He attempted to compare the costs of DBEC's emissions with the benefits of DBEC's operation. In assessing the social cost of carbon emitted by DBEC, Ackerman considered the damage to tourism; human health; unique wildlife and ecosystems, including the Everglades; and property loss due to sea level rise and exacerbated king tides. He acknowledged that while it can be very difficult to estimate the true monetary value of the social cost of carbon for a project due to the aforementioned uncertainties, it is possible to arrive at estimates that represent a "floor," or minimum value, of damage due to GHG emissions from a specific project. Ackerman used the federal government's estimated social cost of carbon of $70 per ton of carbon dioxide25/——which, in Ackerman's view, underestimates the value of damages due to carbon dioxide emissions——and multiplied it by the GHG emissions, in tons, for each year of the DBEC project's projected life. Using two different annual GHGs emissions projections for DBEC—— 4.13 million metric tons or 3.04 million metric tons——he determined that the value of damages due to carbon dioxide emitted by DBEC would range from $213 million to $289 million on an annual basis.26/ Ackerman testified that, according to a research project conducted by Columbia University and the Rhodium Group, out of the 48 contiguous states, Florida will experience the greatest damage from climate change——which is projected to negatively impact the state's gross domestic product ("GDP") by between 10 and 24 percent by 2100. Using this study's projected GDP impacts and assuming that Florida experiences, to the year 2100, the same growth rate it has experienced over the past 20 years, Ackerman estimated that the monetary impact to Florida's economy from climate change may be between $500 million to $1.1 trillion annually by 2100. Ackerman also attempted to quantify DBEC's proportion of that impact on Florida. Using the two values of projected carbon dioxide emissions from DBEC and comparing them to global carbon dioxide emissions projections, Ackerman estimated that DBEC accounts for approximately 1/115,000th to 1/120,000th of total global carbon dioxide emissions on an annual basis. Using those proportions and the valued damage of global climate change to Florida, he estimated that the present value of the damages resulting from DBEC's annual carbon dioxide emissions would range from $8.4 million and $27 million per year. Ackerman also compared these annual projected social costs of carbon dioxide to the assumed $8.29 million annual benefits of the DBEC project to FPL's ratepayers. Based on this comparison, he concluded that the damages from DBEC's carbon emissions greatly outweigh DBEC's benefits to FPL ratepayers. Ackerman did not perform any analysis of DBEC's economic effects on the local community. He also did not take in account the effect that the increased efficiency of Unit 7 would have on FPL's system-wide emissions of GHGs through 2040. He acknowledged that if greenhouse gas emissions are reduced as a result of Unit 7, then the overall harm and damage from the social costs of carbon would also be reduced. As he put it: "[t]he social cost is a per ton harm, so if fewer tons, smaller harm. . . . A reduction in emissions is a reduction in harm." Ackerman testified that emitting any amount of GHGs has a social cost, but that "[a] smaller amount of emission is better. A smaller amount of emissions represents a smaller harm." While the evidence shows that GHG emissions from DBEC will result in increased social costs of carbon on a per-ton basis compared to a zero emissions baseline, the competent, substantial, and persuasive evidence establishes that the operation of Unit 7 will reduce FPL's GHG emissions on a system- wide basis by approximately 8.1 million tons by 2047, due to the retirement of older, less-efficient Units 4 and 5 and the reduced use of older, less-efficient generating units that produce greater quantities of GHG emissions.27/ Based on the foregoing, it is determined that retiring Units 4 and 5 in 2018 and operating Unit 7 commencing in 2022 will result in a net total reduction in the amount of GHG emissions from FPL's electrical power generating units on a system-wide basis——which, in turn, will result in lower social costs of carbon than if Unit 7 is not operated and Units 4 and 5 continue to operate indefinitely into the future.28/ Failure to Perform Life-Cycle Analysis Additionally, Sierra contends that the site certification for DBEC should be denied or additional conditional GHG-related conditions imposed because FPL and/or DEP failed to perform a "life-cycle analysis" to analyze DBEC's GHG emissions "from start to finish, . . . from gas generation to gas burn," which would include GHGs emitted by natural gas production and transport by pipeline to the DBEC site. This contention disregards that such an analysis is beyond the scope of this proceeding. This proceeding specifically applies only to "electrical power plants" as that term is defined in section 403.503(14). Pursuant to that definition, the scope of this proceeding is limited only to considering the impacts of, and imposing conditions on, facilities that fall within that definition. By this statute's plain terms, associated facilities that are directly or indirectly connected to the electrical power plant are to be considered only if they are owned by the applicant. As discussed above, the evidence establishes that Florida Gas Transmission Company owns the pipeline that transports natural gas to the DBEC site. No evidence was presented showing that FPL has any ownership interest in this pipeline, or that FPL has any ownership in sources which may produce gas that is ultimately transported to DBEC for use as fuel for Unit 7. Therefore, any GHG impacts associated with the operation of the pipeline to transport natural gas to DBEC are beyond the scope of this proceeding.29/ Failure to Consider Cumulative Impact of GHG Emissions Sierra also contends that the site certification for DBEC should be denied or additional GHG-related conditions imposed because FPL and/or DEP did not consider the cumulative impacts of DBEC's GHG emissions combined with those from "other existing and foreseeable permitted sources in Florida and elsewhere." As previously discussed, Florida and federal air statutes and rules do not impose cumulative impacts assessment in the PSD permitting process. Further, EPA's PSD Guidance expressly recognizes that climate change modeling and impacts evaluation of GHG emissions is conducted for changes in GHG emissions that are orders of magnitude larger than those from individual projects, and that determining the exact impacts attributable to a specific GHG source is not possible under current climate change modeling. Failure to Consider Using Solar Power Generation Technology Sierra also contends that the site certification for DBEC should be denied or additional conditions imposed because FPL and/or DEP "did not consider using solar generation." As discussed above, the PSC's Need Determination for Unit 7 considered and specifically rejected the use of photovoltaic (solar) facilities as a cost-effective alternative to Unit 7 as proposed. As discussed above, the PSC is the sole forum for determining need for electrical power plants subject to the PPSA. § 403.519, Fla. Stat. The PSC's need determination considers, among other things, the need for electric system reliability, the need for fuel diversity, whether the proposed plant is the most cost-effective alternative, and whether renewable energy resources may mitigate the need for the proposed electrical power plant. Thus, section 403.519 vests sole jurisdiction in the PSC to determine, as part of the need determination process, whether solar facilities should be required to be implemented as part of an electrical power plant's need determination. Therefore, the decision whether to impose a requirement for DBEC to implement solar facilities is beyond the scope of this proceeding. DBEC Stormwater Management System and Flooding Issues The stormwater management system for DBEC was designed to ensure that stormwater received onsite does not flood onsite facilities and to ensure that stormwater leaving the site does not cause offsite flooding or pollution. The stormwater management system for DBEC consists of a system of culverts, catch basins, ditches, storm sewer inlets, an underground storm sewer system, and ponds. The collection and conveyance structures collect the stormwater onsite and convey it to the ponds, which collect and store the water, then release it offsite at a controlled rate. Compliance with Applicable Stormwater Management Requirements The DBEC stormwater management system is designed in accordance with, and meets, all applicable stormwater management requirements of the City of Dania Beach, the City of Hollywood, Broward County, and the South Florida Water Management District ("SFWMD"), including regulations specifically directed toward protecting land uses against flooding. Broward County's land development code regulations require the floor elevation of the power plant facilities to be elevated to at least 5.5 feet North American Vertical Datum of 1988 ("NAVD88"), or approximately 6.5 feet above mean sea level, to withstand flooding from a 100-year, 72-hour storm event. The City of Dania Beach requires new or substantially improved power generation structures to be elevated three feet above the Federal Emergency Management Agency's ("FEMA") 100-year Base Flood Elevation established on the FEMA Flood Insurance Rate Map ("FEMA Map"). FEMA's 100-year Base Flood Elevation is three feet NAVD88; thus, the City of Dania Beach requires DBEC's power generation structures to be elevated to six feet NAVD88, which is approximately seven feet above mean sea level. To be conservative, FPL proposes to elevate the minimum floor elevation of DBEC's power generation structures to 10.5 feet NAVD88, or 11.5 feet above mean sea level——an additional five feet above Broward County's flood elevation requirement. This far exceeds both Broward County's and the City of Dania Beach's minimum flood elevation requirements. Broward County also required FPL to compare the base elevation of the stormwater management ponds to future groundwater elevation established on the Broward County Future Conditions Average Wet Season Groundwater Map ("Groundwater Map"), to ensure that the ponds would be sufficiently elevated to hold enough water to prevent flooding during storm events. The Groundwater Map depicts a projected future average wet season groundwater elevation of 2.5 feet above mean sea level——i.e., 1.5 feet NAVD88——in the year 2060. The base of the onsite stormwater storage ponds will be constructed one to two feet above this elevation. Additionally, the stormwater management system ponds have been designed to provide adequate storage to accommodate a 100-year, 72-hour storm event, so that the project does not have stormwater offsite impacts. Projected Sea Level Rise and DBEC Design The design elevation of DBEC's power block and stormwater management ponds adequately accounts for sea level rise. At Broward County's request, FPL compared the base flood elevation of the DBEC power block to the 2015 Unified Sea Level Rise Projection for Southeast Florida ("USLRP") document. This document, which was prepared by a technical working group on behalf of Palm Beach, Broward, Miami-Dade and Monroe counties, projects future sea level rise in South Florida, including Broward County. The USLRP contains a graph30/ consisting of four curves31/ depicting projected sea level rise from 1992 (the baseline year) to 2100 for the southeast Florida region.32/ The table below summarizes the projected sea level rise corresponding to each curve on the USLRP graph for the year 206033/. Name of Sea Level Rise Projection Predicted Sea Level Rise by 2060 (inches) NOAA High Curve 34 USACE High Curve 26 IPCC AR5 Curve 14 NOAA Intermediate/Low Curve 10.5 The area between the IPCC AR5 Curve and the USACE High Curve is recommended in planning design elevation for most projects that fall within a short-term planning horizon, and applies to "most infrastructure projects, especially those with a design life expectancy of less than 50 years."34/ Additionally, the USLRP states that "[p]rojects in need of a greater factor of safety related to potential inundation should consider designing for the [USACE High Curve]. Examples of such projects may include evacuation routes planned for reconstruction, communications and energy infrastructure, and critical government and financial facilities."35/ DBEC has a design life of 40 years and constitutes energy infrastructure. Therefore, the USACE High Curve is appropriate to use in designing the DBEC project to account for projected sea level rise by 2060. By contrast, the NOAA High Curve is used to plan high- risk projects that will be constructed after 2060; projects that are not easily replaceable or removable, have a long design life— —i.e., more than 50 years; or are critically interdependent with other infrastructure of services. Examples of infrastructure expressly identified in the USLRP document to which the NOAA High Curve is appropriately applied include nuclear power plants,36/ wastewater treatment facilities, levees or impoundments, bridges along major evacuation routes, airports, seaports, railroads, and major highways. DBEC does not fall within any of these categories; accordingly, the NOAA High Curve is not recommended for use in designing the DBEC project to account for projected sea level rise by 2060. Nonetheless, FPL took a conservative approach in determining the appropriate design elevation for the project over its projected design-life. Specifically, FPL added one inch to the USACE High Curve projection to account for two additional years of sea level rise beyond the end of DBEC's design-life in 2060. This resulted in a projected 27 inches of sea level rise by 2062. FPL then added this projection to the Broward County existing flood level requirement of 6.5 feet above mean sea level to determine potential flood levels in 2062. This calculation showed that an elevation of 8.75 feet above mean sea level is necessary to protect against sea level rise by 2062, using the USACE High Curve as the design benchmark. Because the minimum concrete base on which the power block will be elevated to 11.5 feet above mean sea level, it will be sufficiently elevated to protect against projected sea level rise by 2062. To further ensure that the design elevation of 11.5 feet above mean sea level is adequate to protect against a realistic, reasonably-projected "worst case" scenario, FPL compared the design elevation of 11.5 feet above mean sea level to the 34-inch sea level rise projected by the NOAA High Curve by 2060. Adding the 34 inches to Broward County's existing flood level requirement of 6.5 feet above mean sea level results in a design elevation of approximately 9.5 feet above mean sea level needed to address the NOAA High Curve projection by 2062. Thus, DBEC's minimum floor elevation of 11.5 feet above mean sea level exceeds the recommended design elevation, even when compared to sea level rise projected by the NOAA High Curve in 2062. FPL also used the NOAA Sea, Lake, and Overland Surges from Hurricanes ("SLOSH") model to address potential storm surge in determining the design elevation for DBEC's power block. This model projects storm surges for different categories of hurricanes and tidal events. FPL applied the SLOSH model to sea level rise projected by the USACE High Curve to predict storm surge height at the DBEC site by 2060, and then compared those results to the FEMA Map. The SLOSH model indicated lower elevations than the FEMA Map, which takes storm surge into account in determining the 100-year flood elevation. Accordingly, the 11.5 foot above mean sea level design elevation on which the DBEC power block will be constructed is more conservative than, and, thus, more protective than, a design based on the SLOSH model. As discussed above, FPL used the Groundwater Map to establish the bottom elevation of DBEC's stormwater ponds. The Groundwater Map, which relies on the USACE High Curve, projects groundwater levels at the DBEC site will be at approximately 1.5 feet NAVD88 by 2060. Because the bottom elevation of the stormwater ponds will be one to two feet above this projected level, they will adequately account for projected sea level rise by 2060. As noted above, certain existing infrastructure is not being replaced, so will not be elevated. These structures, which were constructed in compliance with the regulatory requirements in effect at the time they were approved, are constructed at six to seven feet NAVD88 above mean sea level. The highest flood elevation on the FEMA Map is at elevation 5.5 feet NAVD88 in 2060. Thus, it is unlikely that these structures will be subject to flooding by 2060. In designing DBEC, FPL reasonably relied on the sea level rise projections in the USLRP. That document, which was developed specifically for use in structural design and land use planning to address projected sea level rise, was created by the local governments in south Florida and provides the best scientific consensus view of future sea level rise.37/ FPL's expert, Dr. George Maul,38/ concurred that FPL reasonably relied on the USACE High Curve in designing the floor of DBEC's power block at 11.5 feet above mean sea level. In Maul's opinion, the USACE High Curve's projection for sea level rise is reasonable and appropriate for use in southeast Florida over the next 60 years.39/ Maul questioned the reliability of the NOAA High Curve, which predicts a rate of sea level rise twice as high as that experienced exiting the last Ice Age. He further noted that, in any event, the USACE High Curve and the NOAA High Curve differ by only a few inches in projected sea level rise by 2060. Dr. Harold Wanless40/ testified on behalf of Sierra regarding the relationship between climate change and sea level rise, hurricanes, and their effects on coastal marine environments. Specifically, Wanless testified regarding a range of factors that may cause the rate of sea level rise to accelerate. According to Wanless, research shows that sea level rise began to accelerate in approximately 1993 due to melting of the Greenland and Antarctic ice sheets.41/ Based on this research, Wanless disputes the accuracy of government predictions that do not take this phenomenon into account. In his testimony regarding the projected rate and extent of sea level rise over time, Wanless presented a graphic adapted from a January 2017 NOAA publication showing three global sea level curves——the "intermediate/high," "high," and "extreme" curves——projecting sea level rise through the year 2100. All of these curves on Wanless' adapted graphic assume Greenland and Antarctic ice sheet loss. Based on the extreme curve, Wanless projected that global sea level rise "could be" three feet by 2059. Notably, no evidence was presented regarding the probability of this projected sea level rise scenario. To depict local sea level rise in southeast Florida through 2100, Wanless added "local influences" to the 2017 NOAA curves, which consisted of higher water levels on the western side of the Gulf Stream due to its deceleration, and the gravitational redistribution of water due to decreasing ice sheet mass in Antarctica and Greenland. Specifically, Wanless added to the 2017 NOAA extreme curve sea level rise projection of three feet by 2062, 15 percent additional sea level rise to account for deceleration of the Gulf Stream, and 52 percent additional sea level rise to account for redistribution of water due to decreased gravitational pull by Greenland and Antarctica. Applying these local influences, Wanless projected that there "could be" an approximate 5.2 feet of local sea level rise by 2062. Again, no evidence was presented regarding the probability with which this projected local sea level rise scenario may occur. Upon full consideration of the testimony by Maul and Wanless, the undersigned concludes, based on the competent, substantial, and persuasive evidence, that the USACE High Curve, rather than Wanless's local influence sea level projection curve, is the more reasonable benchmark to apply in determining the appropriate design elevation for the DBEC power block. Wanless's local sea level rise projection is substantially based on the assumption that redistribution of the Earth's mass will significantly contribute to local sea level rise; however, Wanless himself noted that this phenomenon only recently has become the focus of research, and that "we're still learning."42/ Maul counseled against attempting to project long-term sea level rise using short periods of record data. To that point, he testified that trends derived from short records are less reliable as projections because they are affected by inter- annual and decadal climate and oceanographic patterns that are superimposed on the long-term rise of global sea level. Maul's research of historical 19-year periods43/ over which sea level rise rates have been observed by use of tidal gauges shows significant variability between 19-year periods. He testified, credibly, that in his recent review of tidal and sea level records for Key West, "I found we can pick a 19-year period where that particular 19 years is twice the long-term [sea level] range and other times where it's half the long-term range." He also testified that in looking at 19-year records a year at a time, "I find times when that short time scale is much, much higher than a long-term average and other times when it's much less than the long-term average. So you can either overestimate or underestimate what's happening when choosing short records." On that basis, Maul disputes that "since the year 2000, there has been a rapid acceleration in sea level rise." He testified, credibly, that he has not observed any statistically significant increase in sea level at Key West since 2000. Maul also opined, based on his own research, that there is no statistically significant slowing of the Gulf Stream. Sierra did not present persuasive evidence specifically refuting Maul's conclusion regarding slowing of the Gulf Stream.44/ In any event, the DBEC power block minimum floor elevation has been set at 11.5 feet above minimum sea level—— well above the 34- to 37-inch global sea level rise projected by the 2015 NOAA High Curve and the 2017 NOAA Extreme Curve, and also well above Wanless' projected local 5.2-foot local sea level rise by 2060. Sierra also contends that the minimum design elevation for the DBEC power block does not adequately consider storm surges associated with hurricanes. In support, Wanless presented graphics generated using LiDar, a light-detection and ranging technology, showing the elevation above mean sea level of Broward County, including the DBEC site. One graphic shows the current elevation of the DBEC site as approximately two feet above mean sea level. Other graphics assume a two-foot global mean sea level rise by 2060; a four-foot rise by 2089; a six-foot rise by 2110; an 8-foot rise by 2127; and a ten-foot rise in 2142. Each of these graphics shows the DBEC site as being inundated by sea level rise by 2060. Wanless also presented graphics for the period from 2018 to 2060, depicting the effect of adding storm surges of four feet and nine feet to regional sea level influences, king tides, and global mean sea level. According to these graphics, adding a four-foot storm surge may result in water heights of as much as 11 feet above present global mean sea level on the DBEC site by 2060, and adding a storm surge of nine feet may result in water heights of as much as 15 feet above present global mean sea level on the DBEC site by 2060. Wanless's storm surge scenarios entail layering contingencies on top of contingencies——each contingency fraught with uncertainty. Stated another way, each assumed condition on which Wanless relies to project storm surge heights of 11 and 15 feet has its own inherent uncertainty. To that point, the evidence showed that while it is well-accepted that climate change is occurring and that, as a result, global sea levels are rising, there is substantial lack of consensus in the scientific community and regulatory agencies regarding the extent and rate of global sea level rise in the future. Further, as discussed above, currently there is not a consensus that the Gulf Stream is slowing or that water mass is being redistributed due to the melting of the Greenland and Antarctic ice sheets——two contingencies that substantially contributed to Wanless' projection of a 5.2-foot local sea level rise by 2060. Additionally, as with Wanless's other projections, no evidence was presented regarding the probability that his projected water height scenarios on the DBEC site, assuming four- and nine-foot storm surges, would occur. Based on the foregoing, it is determined that the 11.5 foot above mean sea level design elevation for DBEC adequately addresses future storm surges. As previously discussed, certain existing infrastructure will be used for DBEC. These components were built years ago, complied with code requirements for elevation at the time they were constructed, and currently comply with those code requirements.45/ In sum, the competent substantial evidence establishes that the DBEC site design, as currently proposed, complies with all applicable state and local regulatory requirements. The competent, substantial, and persuasive evidence further establishes that DBEC site design elevation, which exceeds all applicable regulatory requirements, will adequately protect against flooding and inundation due to global and local sea level rise and storm surges. Other Impacts Water Resource Impacts The construction and operation of DBEC will not adversely impact water resources. The primary water uses for DBEC consist of cooling water, process water, service water, irrigation, and potable water. The cooling system for DBEC will use cooling water withdrawn from the Dania Cutoff Canal, which currently serves, and since 1927 has served, as the cooling water source for the electrical power generating facilities on the Lauderdale Site. DBEC will not require an increase in the rate or amount of cooling water withdrawn from the canal. Because the withdrawal rate will not increase, the through-screen velocity through the cooling water intake structure will not increase. This helps ensure that the project will not adversely impact fish or shellfish by impingement or entrainment. Additionally, no increase in the authorized quantity of industrial wastewater discharge will be required. The cooling system has been designed to ensure that DBEC will meet existing permitted National Pollutant Discharge Elimination System ("NPDES") thermal discharge limits. The average amount of process water used is anticipated to decrease. DBEC will continue to receive potable water from the City of Hollywood, and potable water use is not anticipated to increase. Sanitary Waste Disposal and Solid and Hazardous Waste The City of Hollywood will provide sanitary waste disposal services to DBEC. The operation of DBEC will generate small amounts of solid waste, which will be recycled, reused, disposed onsite, disposed in licensed offsite landfills, or otherwise appropriately disposed via approved disposal methods. The Lauderdale Site is a conditionally-exempt small quantity generator of hazardous waste and is anticipated to remain so during the construction and operation of DBEC. Hazardous waste generation by DBEC is anticipated to be less than 100 kilograms per month. FPL will contract with an approved and licensed hazardous waste disposal entity to handle and dispose of any hazardous waste generated by DBEC in a manner that complies with all federal, state, and local environmental regulations. Terrestrial Impacts The DBEC project will affect approximately 134 acres of the 392-acre Lauderdale site, which has continuously been used for industrial activities for the past 90 years. As such, the Lauderdale site is disturbed and does not constitute prime wildlife habitat for unique wildlife species. The upland and wetland habitat onsite is low-quality, and consists of a mixture of nuisance exotic and native species. Due to the disturbed nature of the site and the lack of significant wildlife habitat, no change in floral or faunal populations, including commercially- or recreationally-important species, is anticipated due to DBEC. Additionally, the site does not contain significant areas of preferred habitat for nesting, roosting, or foraging by state and/or federal endangered, threatened, or candidate species. Approximately 18.67 acres of low-quality wetlands, 0.12 acres of disturbed exotic and native hardwood systems, and a small area of low-quality isolated freshwater marsh will be impacted by dredging and filling. These wetland impacts will be mitigated through purchase of mitigation credits from the Everglades Mitigation Bank. Impacts on Aquatic Species DBEC project will continue to withdraw water from the existing Dania Cutoff Canal and to discharge cooling water into ponds and, ultimately, offsite. Proximate aquatic systems are subject to tidal influences and fresh water discharges through SFWMD canals. The waters in the vicinity of the DBEC site are designated Class III marine waters. Existing stresses on aquatic systems in the vicinity of DBEC include altered hydrology, altered salinity, elevated nutrient and organic loads, power plant intake/discharge, physical alterations, and pressures from fishing and boating. DBEC will address impacts to these aquatic systems, as appropriate, through obtaining an NPDES permit for the cooling water discharge. Additionally, FPL will use best management practices during construction to control erosion, sedimentation, and runoff to prevent water quality degradation. Significant impacts to aquatic resources and biological communities are not anticipated. During DBEC construction, FPL will continue to discharge warm water consistent with the Manatee Protection Plan established under the NPDES permit for the existing electrical power plant facility. The Lauderdale Site will continue to provide a warm water refuge for manatees during and after DBEC is constructed. Transportation Impacts A traffic analysis for construction and operation of DBEC was performed and provided in the site certification application. During peak construction, approximately 500 vehicles per day are anticipated to enter and exit the DBEC site. A traffic impact analysis showed that additional construction-related traffic will not degrade roadway system operating conditions. FPL will develop a traffic management plan to minimize level of service deficiencies due to construction traffic. FPL has agreed, pursuant to the Conditions of Certification, to work with the City of Hollywood to improve roadway operations at site access locations. No adverse impacts to traffic flow are anticipated from DBEC operation. Archaeological and Historical Site Impacts A cultural resource assessment of the DBEC site determined that no archaeological or historical structures that are listed, eligible, or potentially eligible for listing in the National Register of Historic Places, are present. Noise A computer program predicted environmental noise impacts from DBEC. Most of the noise sources, which consist of the steam turbine, the gas turbines, the electric generators, and the compressors, are located in enclosed structures, which helps mitigate impacts. The DBEC sound profile will not be significantly different than that for Units 4 and 5. The Lauderdale Site is in a highly-developed area having other proximate industrial and urban uses, including a waste-to-energy center, a shipping center, a recycling center, the Fort Lauderdale-Hollywood International Airport, and several major highways. DBEC is projected to comply with the Broward County and City of Hollywood noise ordinances. DBEC's normal operation is not anticipated to exceed the City of Dania Beach's maximum permissible noise levels. However, as part of the site certification application, FPL has requested a variance from the City of Dania Beach noise ordinance, chapter 17, article IV, sections 17-79 through 17-90, for noise levels that may occur on an infrequent and short-term basis during startup, shutdown, and upset conditions. The City of Dania Beach does not object to FPL's request for the variance. The undersigned recommends approval of FPL's request for a variance from the City of Dania Beach noise ordinance, chapter 17, article IV, sections 17-79 through 17-90. Climate Change "Climate change" is a term used to describe changes in global temperature, global sea level rise, and other conditions associated with those effects, including changes in precipitation, winds, waves, and climates. Climate change is occurring globally and locally, including in southeast Florida. Climate change is caused, in substantial part, by the emission of GHGs. Water vapor, carbon dioxide, and methane are the most significant GHG contributors to climate change. Atmospheric concentrations of gaseous carbon dioxide and methane are increasing. Since the Industrial Revolution, the global atmospheric concentration of carbon dioxide has dramatically increased, from 280 parts per million ("ppm") to 410 ppm at present——almost 100 times faster than historical increases in atmospheric carbon dioxide concentration during previous interglacial periods. Most of the increase in atmospheric carbon dioxide concentration has occurred since World War II and is primarily due to human population increase, global industrialization, and increased burning of fossil fuels on a global basis. GHGs cause climate change by trapping solar radiation in the Earth's atmosphere, thereby warming the atmosphere. Once carbon dioxide is emitted, it persists in the atmosphere for approximately 4,000 years. Climate change is responsible for causing sea level to rise on a global and local basis. The main drivers of sea level rise are atmospheric and ocean warming, which increase the ocean's mass through melting land and sea ice and increase the ocean's volume through thermal expansion. Increasing the concentration of carbon dioxide in the atmosphere increases the rate of climate change, which, in turn, accelerates sea level rise. The last time atmospheric concentrations of carbon dioxide were at or above 400 ppm, sea level was approximately 20 meters, or 70 feet, higher than current level. At that level, a substantial portion of the land mass that constitutes the state of Florida was inundated. The evidence shows that global sea level does not rise in a gradual linear manner, but instead rises in rapid pulses followed by pauses. Although it is well-established that sea level is rising on a global and local basis, there currently is little consensus regarding the rate of sea level rise. Due to its low elevation, southeast Florida is particularly vulnerable to sea level rise. Many urban areas in southeast Florida experience substantial flooding during rainfall events. The evidence shows that sea level rise is likely a contributing cause. Sea level rise causes substantial coastal hazards, including inundation of land, higher storm surges, higher king tides, increased flood height and frequency, coastal erosion and destruction of coastal mangroves and other ecosystems, erosion and destruction of coastal barrier islands, and saltwater intrusion into freshwater aquifers and ecosystems. These impacts will worsen or accelerate with sea level rise. The cumulative addition of carbon dioxide to the atmosphere is warming the atmosphere, which, in turn, is causing ocean temperatures to rise on a global basis. In particular, the upper ocean has warmed substantially on a global basis since 1997, due to increasing human population and the corresponding increased burning of fossil fuels. Increased carbon dioxide in the atmosphere is being transferred to the oceans, causing them to acidify. Some scientific studies indicate that climate change will cause more severe storm and weather events. Some scientific studies indicate that climate change will result in threats to human health, native wildlife and ecosystems, agriculture, and the tourism industry. In sum, the competent, persuasive evidence establishes that climate change is occurring, that it is primarily caused by GHGs emissions, and that every ton of GHGs emitted into the atmosphere contributes to climate change. The competent, persuasive evidence also establishes that as a result of climate change, sea level is rising globally, and, to a certain extent, locally,46/ and that sea level rise already is causing environmental adverse impacts.47/ SCO and Affected Agencies' Review of Application The PPSA establishes a centralized, coordinated process for licensing electrical power plants that generate 75 MW or more of electrical power. §§ 403.502, 403.503(14), Fla. Stat. Site certification for an electrical power plant constitutes a license that addresses and encompasses the regulatory requirements of the agencies that are involved in the site certification application review process. The SCO is an office within DEP's Division of Air Resource Management. It is responsible for coordinating and overseeing the electrical power plant site certification application review process. The SCO also serves as administrative staff for the Siting Board. The SCO's responsibilities include receiving site certification applications, preparing a schedule of deadlines and milestones applicable to the site certification application review process, determining completeness48/ of the application based on the recommendations of affected agencies,49/ receiving each affected agency's preliminary statement of issues, receiving each affected agency's report, and preparing the PAR.50/ §§ 403.5064, 403.5066, and 403.507, Fla. Stat. The PAR addresses the proposed electrical power plant's compliance with all applicable non-procedural requirements of the affected agencies51/ and contains copies of the affected agencies' reports; comments from other agencies or persons; any variances and waivers from applicable regulatory requirements that have been requested and the SCO's recommendation regarding the request; the SCO's recommendation regarding whether site certification should be approved, denied, or approved with conditions; and proposed conditions of certification. § 403.507(5)(a), Fla. Stat. The affected agencies' reports provide the agencies' specialized knowledge on matters within their jurisdiction and expertise, so are a crucial component of the PAR. Each affected agency conducts a substantive review of the site certification application to determine whether the electrical power plant complies with that particular agency's applicable substantive rules, regulations, ordinances, standards, and criteria. The affected agency's report must specifically address these topics and must state whether, based on its substantive review, the agency recommends that the electrical power plant be approved, denied, or approved with conditions. The report also must include any conditions of certification that the agency recommends be imposed regarding matters within that agency's jurisdiction. § 403.507(3), Fla. Stat. Conditions of certification are regulatory requirements imposed to minimize and mitigate the potential adverse effects of the construction and operation of the electrical power plant with respect to the environment and public health. Because the conditions of certification are regulatory requirements, each affected agency that recommends a specific condition of certification must possess the legal authority to impose that condition. § 403.507(3)(c), Fla. Stat. To that end, the affected agency is required to cite the specific statute, rule, or ordinance that authorizes the imposition of that specific condition. Because each affected agency possesses legislatively or constitutionally delegated regulatory authority over specific matters, the SCO does not conduct an independent review as to whether the proposed electrical power plant meets those affected agencies' nonprocedural requirements, and instead relies on each affected agency's specific regulatory knowledge and expertise regarding matters that are within its substantive regulatory jurisdiction. FPL submitted the Application for DBEC to the SCO on July 27, 2017. The Application was referred to DOAH and was distributed to the affected agencies for review and comment regarding completeness of the Application. The affected agencies needed additional information, so the Application was determined incomplete. After FPL provided the requested information, the Application was deemed complete on October 27, 2017. Pursuant to section 403.507(3), the SFWMD; Florida Fish and Wildlife Conservation Commission ("FFWC"); Florida Department of Transportation ("DOT"); Florida Department of Economic Opportunity ("DEO"); Florida Department of State, Division of Historical Resources ("DHR"); DEP; Broward County; the City of Dania Beach; and the City of Hollywood reviewed the Application and submitted agency reports to the SCO. Each of these affected agencies submitted recommended conditions of certification to be included in the site certification as conditions specifically designed to address matters within that particular agency's regulatory jurisdiction. Each agency concluded that if DBEC complies with the conditions of certification recommended by that agency, it will meet all applicable non-procedural requirements, rules, and ordinances within that agency's jurisdiction. Each affected agency recommended that DBEC be approved, subject to the conditions of certification recommended by that agency. Each agency report is briefly discussed below. PSC Need Determination As previously noted, the PSC issued the Need Determination for DBEC on March 19, 2018. Pursuant to section 403.507(4)(a), the Need Determination constitutes the PSC's agency report for DBEC. In determining the need for DBEC, the PSC considered critical components of need, including forecasted load, necessary reserve margin, projected load generation and imbalance, and area reliability margin. The PSC determined that FPL demonstrated the need for DBEC Unit 7 in the 2024-to-2026 timeframe, in order to maintain its electrical system reliability and integrity. The PSC found that: No cost-effective [Demand Side Management] or renewable resources have been identified that could mitigate the need for DBEC Unit 7. DBEC Unit 7 is expected to provide adequate electricity at a reasonable cost to FPL's customers. DBEC Unit 7 is projected to reduce overall natural gas consumption and reduce emissions compared to maintaining the existing Lauderdale units. DBEC Unit 7 is the most cost-effective alternative that maintains FPL's system and Southeastern Florida area reliability compared to other alternatives. South Florida Water Management District SFWMD determined that there will be no increase in water use for DBEC, and that the cooling water, potable water, and process water sources will remain the same as for the units currently existing at the Lauderdale Site. SFWMD determined that if DBEC complies with SFWMD's recommended conditions of certification, it can be constructed and operated in compliance with the applicable statutes and rules within SFWMD's jurisdiction. Florida Fish and Wildlife Conservation Commission FFWCC's report noted that several listed wildlife species were observed onsite or have a moderate to high likelihood of occurrence onsite. Additionally, the West Indian Manatee will be affected by ceasing operation of Units 4 and 5 before the construction of DBEC. FFWCC recommended conditions of certification requiring biological surveys, monitoring for impacts to listed species, and also recommended a condition of certification to require temporary heaters to be used during DBEC construction to maintain a warm water refuge for manatees. Department of Transportation DOT determined that, with the exception of construction-related traffic, DBEC is not anticipated to adversely affect the State Highway System in the vicinity of the plant. DOT recommended certification of DBEC, contingent on DBEC's compliance with its recommended conditions of certification. Department of Economic Opportunity DEO anticipates that DBEC will provide economic and fiscal benefits to the City of Dania Beach, Broward County, and the surrounding area. DEO recommended approval without any recommended conditions of certification. Division of Historical Resources DHR did not object to DBEC, noting that all current matters pertaining to historical resources were addressed. Department of Environmental Protection DEP reviewed solid waste and hazardous waste, environmental resource permitting, industrial wastewater, and stormwater management issues within its jurisdiction and determined that DBEC will meet all applicable regulatory requirements, provided it complies with the proposed conditions of certification. DEP recommended conditions of certification to address solid waste and hazardous waste, environmental resource permitting, industrial wastewater, and stormwater management issues within its jurisdiction. Local Governments Broward County, the City of Dania Beach, and the City of Hollywood each recommended approval of DBEC, subject to recommended conditions of certification regarding matters within its regulatory jurisdiction. The City of Dania Beach did not object to the variance sought by FPL related to noise limits in the City of Dania Beach's Code of Ordinances for transient and infrequent noises associated with unit startup, shutdown, and upset conditions. Preliminary Analysis Report and Recommended Approval with Conditions of Certification On April 2, 2018, the SCO issued the PAR for DBEC. The PAR describes the project and summarizes the affected agencies' substantive review of DBEC. Based on the agencies' reports, recommended conditions of certification, and unanimous approval recommendation, the SCO determined that FPL has provided reasonable assurance that, considering and balancing the factors in section 403.509(3)(a) through (g), DBEC can be certified. The PAR recommends approval of the site certification for DBEC, subject to the proposed Conditions of Certification ("COC") attached thereto, which were compiled from the affected agencies' recommended conditions of certification submitted as part of their agency reports. Sierra contends that because the SCO did not conduct an independent review of whether DBEC meets the nonprocedural requirements of the affected agencies, it was not able to determine whether FPL provided reasonable assurance that the site certification complies with the agencies' applicable statutes, rules, regulations, and other requirements. This contention is rejected. The purpose of the affected agency's review and report submittal requirement in section 403.507 is to ensure that the agency legally and factually vested with the substantive jurisdiction and expertise over a specific regulated area is an integral part of the site application review process. To that end, each agency is charged with submitting recommended conditions of certification that are specifically keyed to addressing issues within that agency's substantive jurisdiction and expertise. The purpose of affected agency involvement in the site certification process would be defeated if the SCO——which is not an expert over the matters within the various affected agencies' substantive jurisdiction—— was authorized to second-guess these agencies' determinations and to modify or reject their recommended conditions of certification. Further, and fundamentally, the SCO is not statutorily authorized to conduct such an independent review. Notably, Sierra has not cited any statutory, rule, or case law authority to support its position.52/ Notice, Public Outreach, and Public Hearing All public notices required by the PPSA were provided. FPL timely published the notice of filing of the Application, as required by section 430.5115(1)(a), and notice of the certification hearing, as required by section 403.5115(1)(e). DEP published notice of the filing of the Application and the certification hearing in the Florida Administrative Register, as required by section 403.5115(4). Additionally, FPL provided direct written notice that the Application had been filed to property owners and residents within three miles of the project area, as required by section 403.5115(6)(a). FPL also engaged in public outreach for the project, including providing a toll-free phone number at which information regarding the project could be obtained, a website containing information about the project, and electronic mail contact information. Additionally, FPL sent 310 letters to residents of the neighborhood closest to the project and sent 1,600 mailers to residents and property owners in the vicinity of the site, inviting them to an open house that was held on May 24, 2017. FPL hosted another open house in June 2017 for residents of the neighborhood immediately south of the project site. A public hearing was held on May 15, 2018, from 6:00 p.m. until 8:03 p.m. Many members of the public provided comments on the DBEC project,53/ and were able to ask questions of representatives from FPL and DEP. The public hearing comments were recorded and transcribed as part of the Transcript of the certification hearing.54/ Federal Permits As discussed above, an air construction/PSD permit has been issued for DBEC. FPL has applied for an NPDES permit and a permit from the United States Army Corps of Engineers under section 404 of the Clean Water Act. These permits and approvals are not part of, or subject to revision, modification, or revocation in, this proceeding. Variance As discussed above, FPL has requested a variance from the City of Dania Beach noise ordinance in Chapter 17-86 of the City's Code of Ordinances, which establishes the permissible sound levels for receiving land use categories. Specifically, FPL requested a variance from the City's maximum permissible sound levels for: Noise due to emergency or upset conditions for all time periods and all receiving land use categories; Noise due to transient conditions associated with unit startup and shutdown shall be limited to 70 dB(A) for all time periods and all receiving land use categories, except for Industrial land use which shall retain a limit of 75 dB(A). Currently, the area in which the Lauderdale Site is located experiences significant noise from the combined effect of a range of industrial and urban activities, including the operation of Units 4 and 5 at the Lauderdale Site. DBEC's projected noise profile is not materially different than that of the existing power plant operation at the Lauderdale Site. Transient and infrequent conditions at the Lauderdale Site, including unit startup, shutdown, and upset conditions occasionally occur for short periods of time. These conditions also are expected to occasionally occur at DBEC. The variance is limited in nature, and the noise levels necessitating a variance are expected to be infrequent and short-lived during unit startup, shutdown, or upset conditions. The City of Dania Beach does not oppose the variance. Given the limited nature of the variance, lack of opposition, and that similar noise levels currently occur at the Lauderdale Site, it is determined that the requested variance is reasonable, and, therefore, should be granted. The Siting Board's Role and Authority Section 403.509(3) sets forth the Siting Board's authority and duty under the PPSA. In considering whether to approve, approve with conditions, or deny a power plant site certification license, the Siting Board must consider all factors in section 403.509(3)(a) through (g). The Siting Board possesses broad authority under the PPSA in considering whether to certify an electrical power plant. With the exception of the need determination and federal permits, the Siting Board is not bound by the conditions of certification proposed by the SCO or the affected agencies, and may modify, remove, or add conditions of certification, as authorized, to protect the broad interests of the public and minimize adverse impacts of the electrical power plant on the environment and human health. See § 403.502(2), Fla. Stat. Comparative Impacts and Benefits of DBEC As discussed above, DBEC will emit GHGs into the atmosphere. Therefore, DBEC's emissions will increase the amount of carbon dioxide in the atmosphere when compared to a zero emissions scenario——i.e., no GHG emissions at all. However, the alternatives in this proceeding do not entail a zero GHG emissions alternative to DBEC. As discussed above, the PSC found and concluded, in the Need Determination, that with the retirement of Units 4 and 5, DBEC is needed to meet a projected future electrical power demand. As part of the Need Determination, the PSC concluded that no additional cost-effective renewal resource——such as solar or wind generation technology——could mitigate the need for DBEC. The PSC also concluded that no new demand side management——i.e., conservation——could mitigate the need for DBEC. In so determining, the PSC established, as a baseline condition to this proceeding, that DBEC, a natural gas-fueled facility, is the most cost-effective means of meeting projected future electrical power demands if Units 4 and 5 are retired. Thus, given the Need Determination, the only alternative available to constructing DBEC is to continue operating Units 4 and 5 indefinitely.55/ As previously discussed, Units 4 and 5 are less efficient units that burn substantially more natural gas than will Unit 7. Therefore, if Units 4 and 5 continue to operate indefinitely——as will be the case if DBEC is not certified——they will burn more natural gas, resulting in the emission of greater amounts of GHGs over their operation life than would the construction and operation of Unit 7, combined with FPL's reduction of the use of less-efficient units in its system. The competent, substantial, and persuasive evidence establishes that the retirement of Units 4 and 5 in 2018, along with the construction and operation of DBEC in 2022 and FPL's concomitant reduction in the use of other less-efficient, more- polluting units in its system, will result in the emission of approximately 8.1 million tons less GHGs into the atmosphere over a 30-year period than if DBEC is not approved and Units 4 and 5 continue to operate indefinitely. Because DBEC will, through system-wide reduced GHG emissions, result in a net environmental benefit as compared to the alternative of continuing to operate Units 4 and 5 indefinitely into the future, DBEC should be weighed as a net positive in considering and balancing the site certification criteria in section 403.509(3). Other measures, discussed above, that DBEC will include and implement to minimize offsite impacts include using the existing transmission line system, existing natural gas pipeline, existing site access, and using a previously-developed power generation site. DBEC will not require new water sources, will not result in a new or expanded surface water discharge, and will reduce the use of processed water by approximately 22 percent. Additionally, upon its operation, DBEC will provide a warm water refuge for manatees.56/ In sum, the undersigned finds that DBEC's benefits, discussed at length above, outweigh its adverse impacts. This determination is more fully addressed in the Conclusions of Law, below. Sierra's Standing Sierra has intervened in this proceeding pursuant to section 403.508(3)(e), which confers party status on persons or entities who demonstrate that their substantial interests will be affected by this proceeding. Sierra is a national non-profit organization. Sierra and its members are committed to protecting the environment. Sierra focuses extensive effort and resources toward combating climate change through advocating the displacement of fossil-fuel energy sources, which emit GHGs, in favor of renewable energy sources and energy sources, such as solar power, wind power, and energy storage and batteries. Consistent with that mission, Sierra's members are concerned about climate change resulting from GHG emissions and the adverse impacts of climate change on human health, property, wildlife, and sensitive ecological systems, and many are actively involved in efforts aimed at reducing GHG emissions on a global and local basis. Several Sierra members testified at the certification hearing regarding the environmental and personal harms they allege they will suffer due to climate change——to which, Sierra alleges, DBEC will contribute. These alleged harms include rising sea level, saltwater intrusion, contamination of drinking water aquifers, property damage due to flooding and increased storm intensity, adverse impacts on recreational activities due to degradation of coral reef and mangrove ecosystems, algal blooms, and human health impacts. Sierra has nearly 38,000 members who live in Florida. Approximately 18,000 Sierra members live in FPL's service territory.57/ The relief Sierra requests in this proceeding is set forth below. Generally, Sierra requests either that the site certification for DBEC be approved, subject to additional conditions that Sierra proposes, or be denied. Relief Requested by Sierra On May 2, 2018, Sierra filed Sierra's Statement on Relief ("Statement on Relief"), identifying the relief it seeks in this proceeding. That relief was set forth in nine sequentially-numbered paragraphs. On May 8, 2018, FPL filed Florida Power & Light Company's Motion to Strike paragraphs 1 through 7 of the Statement on Relief. On May 11, 2018, Sierra filed Sierra Club's Opposition to Florida Power & Light Company's Motion to Strike. At the commencement of the certification hearing, the undersigned struck paragraphs 6 and 7 of the Statement on Relief and reserved ruling on the other forms of relief requested in paragraphs 1 through 5, 8 and 9, pending development of the evidentiary record in this proceeding. The undersigned has ruled on these paragraphs in the Conclusions of Law, below. Sierra requests the following relief in paragraphs 1 through 5, 8, and 9 of its Statement on Relief, which remain at issue in this proceeding: Paragraph 1 of Sierra's Statement of Relief requests the Siting Board to require FPL to limit the annual emission of GHGs from DBEC to the existing annual GHG emission levels from Units 4 and 5, and require FPL to terminate GHG emissions from DBEC at the same date that FPL planned to retire Units 4 and 5, in 2033, subject to any required operation to meet electric reliability needs. Paragraph 2 of Sierra's Statement of Relief requests the Siting Board to require FPL to comply with FPL's stated system- wide GHG commitment to DEP and the PSC, and upon which FPL relies in seeking approval for DBEC——specifically, that DBEC's operation reduces FPL's system-wide annual emissions of GHGs from its current baseline by at least the amount committed to by FPL. As part of this requirement, approval of DBEC should be conditioned on FPL's system-wide annual emissions of GHGs being lower than its current baseline by at least the amount committed to by FPL, and never exceeding that reduced level of GHGs during each year of the lifespan of DBEC. Paragraph 3 of Sierra's Statement of Relief requests the Siting Board to require FPL to develop a locally-sited public stakeholder process that provides municipalities and other governmental entities that have adopted, or that in the future adopt, carbon reduction or clean energy commitments, a means to work with FPL to develop a binding plan to meet the commitments of the municipalities and other governmental entities, subject to any governmental approvals required by law, and that such processes allow interested persons, including non-governmental organizations, a meaningful opportunity to participate. Paragraph 4 of Sierra's Statement of Relief requests the Siting Board to require FPL to evaluate, every five years, in a detailed, transparent process with opportunity for meaningful public participation, the Climate Change Damages resulting from 40 years of GHG pollution from building and operating DBEC as proposed, and approve DBEC subject to the opportunity for the Siting Board to reevaluate the approval of DBEC, including whether there are additional reasonable and available methods that should be adopted to minimize the Climate Change Damages caused by DBEC, and to impose further conditions, including future emissions reductions of DBEC. The impacts of DBEC must be evaluated individually, as well as in the context of cumulative impacts from other GHG emissions. In this evaluation, FPL must examine reasonable and alternative methods to minimize the adverse effects of DBEC's emissions, including sequestration of GHGs and the ability to avoid the emissions. Paragraph 5 of Sierra's Statement of Relief requests the Siting Board to require FPL and DEP to reevaluate, on a five-year basis, and in a detailed, transparent process with opportunity for meaningful public participation, the Climate Change Damages which pose a risk to the DBEC facility specifically, and approve DBEC subject to the opportunity for the Siting Board to reevaluate the approval of DBEC, including whether there are additional reasonable and available methods that should be adopted to minimize the Climate Change Damages to the DBEC facility, and to impose further conditions, including future emissions reductions of DBEC. Paragraph 8 of Sierra's Statement of Relief requests the Siting Board to deny DBEC's site certification. Paragraph 9 of Sierra's Statement of Relief requests that the ALJ and the Siting Board provide such relief as is just and reasonable.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law it is RECOMMENDED that the State of Florida Siting Board enter a final order approving DBEC, subject to the Conditions of Certification contained in the PAR, and approving the variance to the City of Dania Beach Code of Ordinances, Chapter 17, Article IV, Noise, Section 17-86, as set forth in the PAR. DONE AND ENTERED this 30th day of July, 2018, in Tallahassee, Leon County, Florida. S CATHY M. SELLERS Administrative Law Judge Division of Administrative Hearings The DeSoto Building 1230 Apalachee Parkway Tallahassee, Florida 32399-3060 (850) 488-9675 Fax Filing (850) 921-6847 www.doah.state.fl.us Filed with the Clerk of the Division of Administrative Hearings this 30th day of July, 2018.
The Issue Whether Respondent committed the offenses set forth in the Administrative Complaint and, if so, what penalty should be imposed.
Findings Of Fact Petitioner, the Department of Business and Professional Regulation (Department), is a state agency charged with the duty and responsibility of regulating the practice of electrical contracting pursuant to Chapters 20, 455, and 489, Florida Statutes. At no time material hereto has Respondent been certified or licensed as an electrical contractor pursuant to Chapter 489, Part II, Florida Statutes. In September 1997, Respondent contracted with William and Carol Pike of McAlpin, Florida, for the installation of a room addition to the Pike's mobile home. The addition was not new, but had been used by a previous customer. The addition was to be connected to the main part of the house. The installation of the addition was completed in October 1997. The Pikes paid the full contract price of $8,636.00 to Respondent for the installation of the addition. The installation of the room addition required certain electrical work including: the addition had to be wired to the existing mobile home; electrical outlets and lights were wired into the addition; and a new outside light was added at the back door. The Pikes did not have any problems with the wiring of the room addition until April 6, 2001, when a power outage occurred in the area resulting in the Pike's losing electrical power. When the electricity was restored, the Pikes still had no electricity in the room addition. The Pikes contacted the local power company and upon checking, the Pikes were informed that the problem was inside their home. The morning after the power outage, the Pikes called Corbett's Mobile Home Center in an effort to get someone out to their home that day for the needed repairs. Robert Corbett was out of town and they were unable to reach anyone there who could come out to the Pike's home that day which was a Saturday. The Pike's then called Steve Frazier at Santa Fe Electrical Services, to check out the problem. Upon examination, Mr. Frazier found several problems with the electrical wiring under the house including open splices, wires spliced together, hot and ground wires reversed and no junction boxes on the wire junctions. Mr. Frazier recommended that the Pikes contact the original contractor to fix the problem and to leave the breaker off for their safety. The Pikes contacted Respondent and Respondent sent "Billy" to the Pike's residence on Tuesday, April 10, 2001. Billy was unable to correct the problem. The Pikes requested that Respondent send out the original permit with the repairmen. Respondent sent Billy and another person out to attempt to fix the problem but they were unsuccessful in doing so and did not bring any permit. The Pikes were not comfortable with what they perceived to be the level of competency of these employees of Respondent and they asked the men to leave. The Pikes then hired Steve Frazier to correct the wiring problems with the room addition. The electrical work performed by Frazier to correct the wiring problems included: re-wiring and running new wire to outlets; installation of several junction boxes; and repairing open splices in the walls and ceiling. Mr. Frazier obtained the appropriate permit, completed the work of rewiring and obtained a final inspection which was approved. The Pikes paid $855.00 to Santa Fe Electrical Services for this repair work. The Pikes filed a complaint with the Suwannee County Licensing Board. According to Pat Sura, a building inspector with the Suwannee County Building Department, the installation of the room addition is akin to the construction of an addition at a site and requires an electrical license and a permit. This differs from wiring a double-wide mobile home together, as that does not require a permit. The Department incurred investigative costs in the amount of $659.48 in this case.
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law set forth herein, it is RECOMMENDED: That the Department of Business and Professional Regulation enter a final order finding that Respondent violated Section 489.531(1), Florida Statutes, that an administrative penalty of $1,000.00 be imposed, and that Respondent pay Petitioner's costs of investigation in the amount of $659.48. DONE AND ENTERED this 14th day of December, 2001, in Tallahassee, Leon County, Florida. BARBARA J. STAROS 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 14th day of December, 2001.
