The Issue The issue is whether to approve an application by Respondent, Dan R. Hughes Company, L.P. (applicant or Hughes), for an oil well drilling permit authorizing the drilling of an exploratory oil well in Collier County, Florida.
Findings Of Fact The Parties Mosher resides on a three-acre lot at 4695 26th Avenue Southeast, Naples, Florida. His residence is around 2,500 feet west of the proposed wellsite, but Mosher says that the eastern edge of his lot "might be 2,000 feet" from the drilling site. He has not, however, measured the actual distance to confirm this assertion. Preserve is a Florida non-profit corporation whose purpose is to educate the public on issues affecting the preservation and protection of the environment, particularly the environment of south and southwest Florida. It was formed in response to Hughes' intention to drill for oil in the area. The corporation is not a membership organization; rather, it has around 25 non-member, active volunteers, six member directors, and an unknown number of donors. Excluding Mosher, the other member directors live between three and ten miles away from the proposed wellsite. The record does not show where the 25 volunteers reside. The corporate representative testified that four directors, including Mosher, regularly use the Florida Panther National Wildlife Refuge (Refuge) to observe wildlife and habitat. However, the public access point to the Refuge appears to be at least several miles from the wellsite. Based upon an email survey, he stated that a "substantial number [around 36] of donors and volunteers utilize the panther refuge," but he was unaware of when, or how often, this occurred. About every six weeks, meetings are conducted at Mosher's home, which are attended by some, but not all, of the directors and volunteers. Schwartz's primary residence is in Lake Worth (Palm Beach County) where he serves as the unpaid executive director of the South Florida Wildlands Association.3 He sometimes provides paid tours in the Everglades and Big Cypress Swamp and has led "numerous" free hikes into panther habitat to look for signs of panthers. These hikes are limited to the hiking trails in the southeast corner of the Refuge, which is the only area that can be accessed by the public. He represented himself as an advocate for the protection of wildlife habitat in the greater Everglades, with a particular interest in the Florida panther. Hughes is a Texas limited partnership engaged in the business of oil and gas exploration, which is registered to do business in the State of Florida. Hughes has applied for a permit to drill an exploratory well for oil in Collier County. If the well is commercially viable, Hughes must apply for an operating permit at a later time. The Department has jurisdiction to issue permits for the drilling and exploring for, or production of, oil under part I, chapter 377. Pursuant to that authority, the Department reviewed the oil and gas well drilling permit application. The Application and Project After the application was deemed complete by the Department, it was distributed for comment to a number of local, state, and federal agencies. While some commented on the application, no agency had any unresolved concerns at the end of the application process. Hughes met all rule requirements for performance bonds or securities, and it provided all information required by rule. The proposed site is located on the southeast corner of an active farm field in the Big Cypress Swamp watershed, just north of a speedway now used as a test track. Surface holes for oil wells are commonly located on farm land, and farm fields are compatible with oil wells. Based upon a mineral lease between Hughes and the owner of the land, Collier Land Holdings, Ltd., Hughes has the right to locate and drill the well at the proposed surface hole location. The Refuge was established by Congress in 1989 to protect the Florida panther and its habitat and is located approximately 20 miles east of Naples. Around 98 percent of the Refuge is closed to any public activity. The project is consistent with the comprehensive conservation plan for the Refuge prepared by the United States Fish and Wildlife Service (USFWS), in that the plan recommends "slant drilling" off of the Refuge. Although Mosher and Preserve argue that the drill hole should be moved further east into wetlands, and Schwartz contends that it should be moved further west away from the Refuge, the proposed location of the drilling pad and project site is reasonable with respect to the nature, appearance, and location of the proposed drilling site. Likewise, the location is reasonable with respect to the type, nature, and extent of Hughes' ownership. The proposed activity can best be characterized as a "resource play," where an operator drills toward a known resource. This is distinguished from a wildcat operation, where the operator is drilling in an unproven area. Hughes proposes to target the rubble zone (i.e., the lower zone) within the lower Sunniland formation, a geologic formation thousands of feet below the ground surface that runs through southwest Florida. Hughes will first drill a vertical pilot hole and then drill horizontally from the hole bottom in a southeast direction toward a formerly drilled oil well known as the Tribal Well. In order to increase the probability of locating commercially available petroleum, Hughes plans to proceed from west to east in order to arrive at a perpendicular direction of existing limestone fractures as the drilling approaches the Tribal Well. When that well was drilled vertically into the rubble zone in the 1970s, oil rose to the ground surface. Thus, the indicated presence of oil is sufficient to warrant and justify the exploration for oil at this location. The proposed depth of the pilot hole is 13,900 feet measured depth (MD/13,900 feet true vertical depth (TVD)), which will allow assessment of the upper Sunniland, lower Sunniland, and Pumpkin Bay Formations. If the evaluation determines that the well will likely be commercially productive, Hughes will complete a 4,100-foot horizontal leg in the lower Sunniland rubble zone with a landing depth at 12,500 feet MD/12,064 TVD and a total depth of 16,600 feet MD/12,064 feet TVD. The footprint for the drilling pad will be 225 feet by 295 feet, or 2.6 acres, with a two-foot earthen berm around the perimeter of the operating area to contain all water on the site. A secondary containment area within the perimeter of the site will be covered by high-density polyethylene to contain and collect any accidental spills. A drilling rig, generators, and other drilling equipment will be on the pad during drilling operations. A maximum of 20 persons will be at the site, and then only for one day of operations. At all other times, Hughes anticipates there will be a five-person drill crew plus support personnel on site. After drilling, Hughes will remove its equipment. Once the access road is built and the equipment put in place, the drilling activities will take place 24 hours per day, seven days per week, and will be completed in approximately 60 to 70 days. The on-site diesel generators will run simultaneously 24 hours per day while drilling is taking place. The pad will be illuminated at night with lights on the drilling derrick and throughout the pad. Construction of the drilling pad will require trucking around 12,000 to 14,000 cubic yards of fill to the drilling location. Additional traffic for bringing in fill, piping, and related equipment will occur, but the exact amount of traffic is unknown. The South Florida Water Management District (SFWMD) previously approved an environmental resource permit (ERP) to allow the construction and operation of a surface water management system on Camp Keais. The United States Army Corps of Engineers (USACE) also permitted the same system under the Clean Water Act. The latter permit requires mitigation for wetlands and Florida panther habitat compensation. Based on the proposed wellsite, the SFWMD modified the ERP to allow a culvert and access to the proposed wellsite. In addition to the oil drilling permit application, Hughes has applied for two water well drilling permits from the SFWMD, and an injection well drilling permit. Petitioners and Intervenor's Objections The challengers have raised a number of objections that they assert require denial of the application. Conflicting testimony was presented on these issues, which has been resolved in Respondents' favor as being the more credible and persuasive testimony. Mosher and Preserve Mosher and Preserve raise two broad objections. First, they contend that hydrogen sulfide gas (H2S) is likely to be encountered in the drilling of the proposed well. They further contend that the H2S contingency plan submitted by Hughes is not sufficient to evacuate the public in the event of an incident where H2S is uncontrollably released under pressure. Second, they contend that the Committee did not review the application under the process contemplated by section 377.42(2). Except for these two objections, they agree that no other issues remain. See TR., Vol. I, p. 33. Within the petroleum industry, drilling operators create H2S plans when there is reason to believe that the operator may encounter H2S while drilling. This practice is codified in Florida Administrative Code Rule 62C-27.001(7), which requires a contingency plan only when H2S is "likely" to be encountered while drilling. The plan must "meet generally accepted industry standards and practices," and it must contain measures "for notifying authorities and evacuating civilians in the event of an accident." Id. See also rule 62C-26.003(3), which requires a contingency plan "if appropriate." The plan is prepared for two main users: the personnel working at the drilling site; and local emergency management officials, who must plan and train for the implementation of emergency activities. The parties agree that the "generally accepted industry standards and practices" for the oil and natural gas industry are found in the operating standards and recommended practices adopted by The American Petroleum Institute (API), a trade association for the oil and natural gas industry. Recommended Practice 49 (API 49) is the generally accepted industry standard for oil and gas drilling operations likely to encounter H2S and was relied upon by all parties throughout the hearing. The standard includes guidance on personnel protection measures, personnel training, personnel protection equipment, and community contingency planning. API 49 recommends the use of a community warning and protection plan when atmospheric H2S exposures beyond the well site could exceed potentially harmful exposure levels and could affect the general public. Mosher/Preserve's expert opined that H2S might be encountered at levels as high as 21 percent (210,000 parts per million (ppm)) in southwest Florida, and that "it's quite likely" H2S would be encountered at the proposed wellsite. At the same time, however, he agreed with the assessment of Respondents' experts that the likelihood of encountering H2S at this site was merely "possible," "sporadic," and "unlikely," and that there was "zero" potential of a severe H2S release under high pressure. Florida has two major oil producing areas: the Sunniland Trend in southwest Florida and the Smackover formation near Jay, Florida, in the northwest part of the state. Unlike the Smackover formation which has higher temperatures and pressures and a high concentration of H2S, the Sunniland Trend has normal temperatures and pressures and a sporadic presence of H2S. Less than two percent of wells in southwest Florida have been reported to contain H2S, and those reports relate to production wells where bacteria (biological contamination) was likely introduced into the formation during production. Of over 300 oil wells drilled in southwest Florida, only six were reported to have encountered H2S. Notably, the Tribal Well, located 1.5 miles to the southeast of the proposed site, encountered relatively low pressure during drilling and had no H2S, and another well located 12 miles to the north likewise had no high pressure or H2S. It is unlikely that Hughes will encounter high pressure or H2S if it drills at the proposed site. Even though it is unlikely that high pressure or H2S will be encountered during the drilling of this proposed well, Hughes still submitted an H2S contingency plan as part of the drilling application. The Department determined the plan provided an effective design to detect, evaluate, and control any hazardous release of H2S. In response to public concerns, in January 2014 Hughes revised its plan to provide more protections. The revised plan exceeds the guidance provided in API 49. The revised plan clarifies and adds multiple protections, including implementing the plan at a vertical depth of 9,000 feet, which is 2,700 feet before the zone that Mosher claims could contain H2S; clarifying that an H2S alarm notification at 15 ppm would result in an instant well shut-in (i.e., closure of the well) to prevent the escape of H2S; instituting a reverse 911 call system to allow local officials to notify the public by telephone of any incident; creating an air dispersion model to understand the likelihood of public exposure; and adding H2S scavengers to the drilling mud. Adding H2S scavengers in the mud is a protective measure. Specifically, the zinc oxide scavengers will react with H2S to create benign zinc sulfide and water. Even if H2S is present in the formation, the H2S scavengers will neutralize the H2S before it could reach the surface. The H2S scavengers will effectively eliminate the likelihood of H2S escaping from the well during drilling operations. The drilling plan requires the Trinity C formation (which Hughes estimated will begin at a depth of around 11,850 feet) to be cemented off and sealed once drilled. This formation will not be encountered in the first 15 or 20 days of drilling. Once encountered, the formation will be exposed for only four to six days. Even if H2S were encountered during this short exposed duration, all of the protections included in the revised plan would be in place, including overbalanced drilling mud, H2S scavengers, blowout preventers, H2S monitors, and alarms. When wells are drilled, there are numerous personnel monitoring the drilling fluid, or mud, which is designed not only to carry cuttings to the surface, but more importantly to act as a barrier to keep fluids or gasses in the geologic formation. The mud is weighted with additives to combat reservoir pressures. Drill operators want the same amount of mud pumped into the hole as the amount flowing back up. If more fluid is flowing back up, then the mud is not heavy enough to hold back the fluids or gasses encountered. If this imbalance occurs, the well is shut- in immediately and the mud weight is adjusted. A shut-in can be accomplished in just a few seconds. Anything in a shut-in well will stay in the well. Hughes' normal drilling plan is to slightly overbalance the mud weight. This ensures that nothing unintentionally escapes from the reservoir. Mosher and Preserve contend that if H2S is encountered, dangerous concentrations of H2S would leave the wellsite. In response to this type of concern, as part of the revised plan, Hughes conducted an air dispersion model using the methodology provided by API 49. The API 49 model is a Gaussian model with default values reflecting the worst-case exposures. The peer- reviewed and conservative model calculated by Dr. Walker looked at H2S concentrations of 10, 15, and 100 ppm. At the extreme case, a 100-ppm release at the well would be reduced below 10 ppm within about 20 feet from the well and further reduced to one ppm within 60 feet from the well. Although H2S is unlikely to escape the well, 100 ppm was selected as a precautionary level because this level is an immediate danger to human life and health. Reaching 100 ppm is highly unlikely because at an instantaneous reading of 15 ppm, the well is immediately shut-in. The air dispersion model results demonstrate that atmospheric H2S exposures beyond the wellsite could not exceed potentially harmful exposure levels nor could exposures affect the general public. Thus, even though the plan includes a community warning and protection provision, it is not required under API 49. In an abundance of caution, however, the plan provides for a public notification zone of 2,000 feet in case of an H2S release. This zone is two orders of magnitude beyond the 20- foot, 10 ppm distance dispersion of H2S based on the modeled worse case release and exceeds any required notification zones in other states. The notification boundary is conservative, as compared with industry standards. While Mosher's expert recommended more stringent standards than API 49, he knew of no contingency plan for an oil drilling permit in the United States that included his recommended standards. Mosher's expert testified that based on his review of literature, the lowest observable adverse effect from H2S was at concentrations of 2.1 ppm. Based on a worst case scenario release of 100 ppm of H2S, the gas would disperse to a concentration of 2.1 ppm in less than 40 feet from the well. The property boundary abutting the neighborhood to the west is over 800 feet from the well. API 49 expressly provides that wellsite personnel should be provided protection devices if concentrations of H2S exceed 10 ppm for an eight-hour time-weighted average. The revised plan requires wellsite personnel to don a self-contained breathing apparatus if the monitors encounter an instantaneous reading of 10 ppm H2S. Instantaneous readings are more protective of human health than the time-weighted averages proposed by Mosher's expert. Using an instantaneous trigger is another area where the revised plan exceeds the recommendation of API 49. The greater weight of evidence demonstrates that the H2S contingency plan meets or exceeds guidance of API 49. The revised plan requires hands-on training for public officials and fire/rescue staff before reaching the depth of 9,000 feet. The revised plan further requires hands-on training and drills related to the procedures for use, and location of, all self- contained breathing apparatus and evacuation procedures. The plan is a complete and accurate contingency plan that will assist operators and local emergency management in the unlikely event of an H2S escape. It exceeds the degree of caution typically employed in industry standards. Mosher and Preserve contend that the plan fails to include specific instructions and training for nearby residents in the event of an emergency. However, emergency plans are designed for use by operators at the facility and the local emergency management officials rather than nearby residents. Thus, the Department did not require the applicant to provide specific instructions for those residents. Mosher and Preserve also contend that the plan fails to adequately describe the evacuation routes in the event of an emergency. However, evacuation routes and the potential closure of roads are normally in the domain of local governments, as the operator and Department have no control over this action. Mosher and Preserve contend that the plan does not include complete and accurate information for all property owners in the area. This is understandable since some property owners either failed to respond to inquiries by Hughes when it assembled the information for the plan or were reluctant to provide any personal information. Recognizing this problem, the Department reviewed the website of the Collier County property appraiser to complete the information. To the extent information on certain parcels may not be complete, Hughes can update that aspect of the plan on an on-going basis before operations begin. If a permit is issued, the Department will continue to coordinate with Collier County and other local emergency management officials for the purpose of planning to implement the contingency plan. Based on the foregoing, the evidence establishes that the probability of a dangerous release of H2S beyond the wellsite is highly remote and speculative in nature. The revised contingency plan is consistent with industry standards and satisfies the requirements of the rule. Schwartz Like Mosher and Preserve, Schwartz agreed that except for the concerns expressed in his amended pleading, no other issues remain. Schwartz first contends that Hughes did not demonstrate sufficient efforts to select a proposed location for drilling to minimize impacts as required by rule 62C-30.005. Subparagraph (2)(b)1. requires that drilling sites be located "to minimize impacts on the vegetation and wildlife, including rare and endangered species, and the surface water resources." In particular, Schwartz is concerned about the potential impact on the Florida panther, an endangered species. Hughes selected the proposed site primarily because of its proximity to the Tribal Well, which had a significant show of oil. In order to increase the chances for commercial production, the horizontal segment of the well needs to be perpendicular to the natural fractures in the limestone. In this location, Hughes must drill horizontally from west to east in the direction of the Tribal Well. Hughes was unable to locate the well on the automotive test track directly south of the agricultural field and west of the Tribal Well because of objections by Harley-Davidson, then the owner of the track. A second proposed location just east of the test track was considered but Harley-Davidson would not grant access from the track to the upland sites on the adjacent location. A third option was to construct a lengthy access road from the north to one of the upland sites just east of the test track. However, this alternative would have resulted in significant impacts to wetlands and native vegetation. The proposed site offers the least amount of environmental impact. It is 1.5 miles from the Tribal Well. It has no federal or jurisdictional wetlands on the site, and groundwater modeling submitted with an application for a water use permit demonstrated that the proposed use of water will not adversely affect surrounding wetlands. The proposed access road and drilling pad will not impact any cypress-mixed forest swamps, hardwood hammocks, mangrove forests, archeological sites, or native ceremonial grounds. Nor will they adversely affect known red-cockaded woodpecker colonies, rookeries, alligator holes, research sites, or pine uplands. The evidence establishes that Hughes chose a site that minimized environmental impacts. Schwartz also contends that the wellsite activities will directly decrease the recovery chances of the Florida panther. According to Schwartz, this decrease will occur because the activities involve creating an access road, truck traffic, noise, lights, and vibrations. He also asserts that the proposed wellsite will result in a small amount of direct habitat loss when the cattle field is converted to a drilling pad. The USFWS has developed a panther scientific habitat assessment methodology. It relies upon peer-reviewed studies that found that panthers will select land cover types while avoiding others. The methodology ranks the value of land cover types from zero to ten based on the potential for panther selection. Applying the USFWS' scoring to the proposed wellsite, an improved pasture area has a value of 5.2, which means the land cover is neither actively selected nor avoided by panthers. The areas to the south and east of the proposed wellsite are forested wetlands and forested uplands, which have substantially higher values that range from 9.2 to 9.5. If converted to an open water reservoir under the Camp Keais ERP, the site value would be zero, the land cover type most avoided by panthers. The underlying USACE permit specifically required panther habitat compensation. Hughes' expert established that the proposed site minimizes impacts on wildlife by avoiding habitat selected by panthers such as wetlands, forested uplands, saw palmetto thickets, fresh water marshes, prairies, and native habitats. Based on a dozen visits to the site for the purpose of conducting vegetation mapping and wildlife surveys, the expert concluded there are no panthers currently known to be living, breeding, or denning on the site. A home range for a panther is the area providing shelter, water, food, and the chance for breeding. The typical home range for a male panther is 209 square miles, and female home ranges average around 113 square miles. The evidence establishes the proposed drilling activity will not interfere with the panthers' use of the site. Approval of the permit will not remove or push any panthers out of their home range. Hughes' expert opined that the four male panthers, which historically traversed the area within a mile of the proposed wellsite, would only likely move through the area every 15 or 20 months or longer. The temporary nature of the drilling activities means the panthers may not even be near the location during that time. If a panther is near the location and frightened by any activities, it will avoid the area, but will eventually return. Based on the large home range of the panther, the temporary activities will not increase the likelihood of intraspecies aggression or decrease panther survivability. The more persuasive evidence is that panthers are adaptable. They are habituated to the drilling operations in southwest Florida based on over a hundred thousand telemetry data points taken near 93 oil wells in the primary zone. Panthers are not threatened by the presence of humans. In fact, they live and den in and around residential communities and active agricultural operations. Panthers need prey, water, and shelter. The drilling activities will not adversely affect prey availability or impact water resources. The proposed wellsite's location within a disturbed agricultural field will not impact the panther's ability to shelter. During the permit review process, the Department requested input from the USFWS, the Florida Fish and Wildlife Conservation Commission (FFWCC), and other interested parties regarding the proposed drilling permit. No formal comments were offered by the USFWS, and its biologist for conservation planning indicated informally that the surface impacts from an oil well are "very minor." Likewise, the FFWCC offered no formal comments on the application. The evidence supports a finding that the proposed permit activities will not affect the panther's use of, or travel to and from, the Refuge. The activities will not affect the panthers' availability of prey or increase panther competition for food or home range territory. The drilling will not adversely affect the panther's breeding, survivability, or the recovery of the species. The only other threatened or endangered species found in the vicinity of the proposed site was an eastern indigo snake, which was located two and one-half miles away and would not travel to the proposed wellsite, as its home range is up to a maximum of 450 acres. Schwartz further contends that section 377.242 requires that the permit be denied because the proposed wellsite is within one mile from the seaward (western) boundary of the Refuge. The Refuge is located entirely inland and does not have a seaward boundary, as contemplated by section 377.242(1)(a)3. Therefore, no drilling will be located within one mile of the seaward boundary of any state, local, or federal park, aquatic preserve, or wildlife preserve. This is consistent with the Department's routine and long-standing interpretation of the statute. Big Cypress Swamp Advisory Committee Petitioners and Intervenor initially contended that the permit should be denied because a meeting of the Committee was never convened pursuant to section 377.42. The Committee, however, met on March 11 and 31, 2014. Although a majority of the Committee voted to recommend that the Department deny the permit on various grounds, the recommendation of the Committee is not binding on the Department, and after consideration, was rejected. In their Proposed Recommended Orders, the opponents now contend that the permit should be denied because the Committee did not meet before the Department issued its proposed agency action. For the reasons stated in the Conclusions of Law, this contention is rejected.
Recommendation Based on the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the Department enter a final order issuing Permit No. 1353H, without further modifications. DONE AND ENTERED this 3rd day of June, 2014, in Tallahassee, Leon County, Florida. S D. R. ALEXANDER 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 3rd day of June, 2014.
Findings Of Fact Based upon the prehearing statement, the testimony of the witnesses, and the documentary evidence received at the hearing, the following findings of fact are made: The Petitioner is a Florida corporation in good standing, authorized to do business in this state. The Petitioner owns and controls the site which is the subject matter of these proceedings. Such site is located in Brevard County, Florida. The Department has identified the subject site as DER facility no. 05- 8500985 (the facility). At all times material to this case, the facility consisted of: three underground storage tanks (UST), one 3000 gallon UST used for storing diesel fuel, one 1000 gallon UST used for storing diesel fuel, and one 1000 gallon UST used for storing gasoline; five monitoring wells; and pipes and pumps related to the foregoing system. The facility constituted a storage tank system as defined in Section 376.301, Florida Statutes, and Rule 17-761.200(38), Florida Administrative Code. The Petitioner holds, and is named insured for, third party pollution liability insurance applicable to the facility. Such insurance was issued pursuant to Section 376.3072, Florida Statutes. The policy for the foregoing insurance, policy no. FPL7622040, was in force from March 22, 1991 through March 22, 1992. The Department issued a notice of eligibility for restoration insurance to Petitioner for the above-described facility. Based upon the foregoing, the Petitioner is a participating owner or operator as defined in Chapter 17-769, Florida Administrative Code. Pursuant to Section 376.3073, Florida Statutes, Brevard County operates a local program that has been approved by the Department. Such local program is managed by the Brevard County Office of Natural Resources Management (County). In July, 1990, a discharge of diesel fuel occurred at the Petitioner's facility. Petitioner's employees estimated that approximately twenty gallons of diesel fuel filled the pump box overflowed from the pump box across the seawall into the adjacent waters. Upon discovering the discharge, Petitioner shut down diesel fuel dispensing until repairs could be made to the apparent cause of the leak. Additionally, the diesel fuel remaining in the pump box and on top of the tank area was removed. Contaminated soil in the pump box was also removed. The apparent cause of the discharge described above was attributed to cracked pipe fittings which were repaired by Glover Oil Co. within a few days of the discharge. No detailed inspection was made to the system to determine if additional sources of discharge existed. Petitioner did not complete a discharge reporting form (DRF) for the above-described incident until April 18, 1991. The April DRF was completed after Petitioner was directed to do so by Ms. DiStasio, an inspector employed by the County. From August, 1990 until May, 1991, at least one monitoring well at the Petitioner's facility showed free product accumulating in the well pipe. The exact amounts of the free product found are unknown, but reports estimated the level at 100 centimeters. From August, 1990 until September, 1991, the Petitioner did not undertake any measure to explore the origin of the free product found in the monitoring well. Further, the Petitioner did not report the monitoring well testing results as a suspected or confirmed discharge. In April, 1991, an inspection of the Petitioner's facility was performed by Ms. DiStasio. That inspection resulted in a letter to the Petitioner that outlined several violations at the facility. Among those violations listed was the Petitioner's failure to report a suspected or confirmed discharge. At the time of the April, 1991 inspection, Petitioner had reported neither the July, 1990 discharge (a known discharge) nor the monitoring well test results (at the minimum a suspected discharge). In connection with the July, 1990 discharge, following the repairs made by Glover Oil, Petitioner did not have the system pressure tested. Only the area visible from the pump box was checked for leakage. In July, 1991, when Ms. DiStasio performed a re-inspection of the facility, she found Petitioner had not (in the interim period, April through July, 1991) taken any steps to test the system or to remove the fuels from the suspect tanks. Since the free product continued to appear in the monitoring well, a pressure test of the system would have definitively answered the discharge question. Alternatively, the removal of the fuels would have prevented further seepage until the system could be pressure tested. On August 6, 1991, the Petitioner issued a letter that advised the County that it had stopped dispensing fuel at the facility. The tanks were not drained, however, until on or about September 11, 1991. Further, the August, 1991, letter acknowledged that the Petitioner "had proposals for initial remedial cleanup related to diesel contamination in the tank field area." Obviously, the Petitioner must have contemplated a need for such cleanup. On September 11, 1991, at the Petitioner's request, Petroleum Equipment Contractors, Inc. attempted to pressure test the 3000 gallon diesel tank. The purpose of the pressure test was to determine if the diesel system had a leak. The company could not even run the test on the tank because of the defective system. A similar test on the Petitioner's gasoline tank passed without incident. Once the Petitioner learned the results of the test, it initiated Initial Remedial Action (IRA) as described on the IRA report filed by Universal Engineering Sciences. The IRA consisted of the removal of the excessively contaminated soil, approximately 74 cubic yards, and the removal of the USTs. The foregoing work was completed on or about September 15, 1991. On October 4, 1991, the Petitioner filed a discharge reporting form dated October 2, 1991, that identified September 11, 1991, as the date of discovery for the discharge. This discharge discovery was allegedly made incidental to the diesel tank pressure testing failure. No reference was made to the months of monitoring well reports showing a free product. On October 8, 1991, Ms. DiStasio prepared a Florida Petroleum Liability Insurance and Restoration Program Compliance Checklist that reported the Petitioner was not in compliance with applicable statutes and rules. When Petitioner applied for restoration coverage under the statute on January 31, 1992, such request was denied by the Department on March 6, 1992. The basis for the denial was as follows: Failure to notify the Department of a positive response to sampling within three working days of testing, pursuant to the rule in effect at the time of the initial response (17-61.050(1), Florida Administrative Code). An inspection by Brevard County on April 17, 1991, revealed that free product had been detected in one monitoring well since July 1990. The discharge reporting form was not submitted until October 2, 1991.
Recommendation Based on the foregoing, it is RECOMMENDED: That the Department of Environmental Regulation enter a final order denying Petitioner's claim for restoration coverage under the Florida Petroleum Liability Insurance and Restoration Program. DONE and ENTERED this 31st day of December, 1992, in Tallahassee, Leon County, Florida. JOYOUS D. PARRISH 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 31st day of December, 1992. APPENDIX TO CASE NO. 92-2121 RULINGS ON THE PROPOSED FINDINGS OF FACT SUBMITTED BY THE PETITIONER: Paragraphs 1, 2, 8, 12, 15, 16, 17, and 18 are accepted. Except as found above, paragraph 3 is rejected as not supported by the record cited. It is accepted that Brevard County acted as the local agent in this case. Paragraph 4 is rejected as not supported by the record. With regard to paragraph 5, substituting "A" for "The" and "confirmed" for "discovered" the paragraph can be accepted; otherwise rejected as contrary to the record. Similarly, with the substitution of the word "confirmation" for "discovery" in Paragraph 6, the paragraph can be accepted; otherwise rejected as contrary to the record. No suitable explanation was offered by the Petitioner for why, if a discharge were not reasonably suspected, it retained the company to immediately remove the USTs upon the failed pressure testing. Clearly, the Club had a notion the tanks were a discharge problem. Paragraph 7 is rejected as contrary to the weight of the evidence. While there was some confusion as to the exact volume of free product in the monitoring well, there was clear evidence that such was reported for many months prior to the confirmation in September, 1991. Further, the main confusion regarding the product found in the well was not as to its existence, but as to the individual's knowledge of the metric measurement of it. One hundred centimeters of product in a two or three inch pipe would not be a minute amount. Except as addressed in the foregoing findings, paragraph 9 is rejected as contrary to the weight of the evidence. Petitioner did not undertake all repairs necessary to abate a discharge problem. Paragraph 10 is rejected as not supported by the weight of credible evidence or irrelevant. Clearly, as early as August, 1990, Petitioner knew or should have known of a discharge problem based upon the monitoring well report; that all of the discharge did not necessarily flow from the fittings that had been repaired is irrelevant. Further, Petitioner did no testing to verify that the replaced fittings had solved the discharge problem (especially in light of the well reports). Paragraph 11 is rejected as an inaccurate restatement of the exhibit. Paragraph 13 is rejected as contrary to the weight of the evidence. Incidentally, the hearing in this case was in the year 1992. Paragraph 14 is rejected as contrary to the weight of credible evidence. RULINGS ON THE PROPOSED FINDINGS OF FACT SUBMITTED BY THE RESPONDENT: Paragraphs 1 through 11 are accepted. Paragraph 12 is rejected as a misstatement of the exhibit cited. Paragraphs 13 through 27 are accepted. COPIES FURNISHED: Brigette A. Ffolkes Assistant General Counsel Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Scott E. Wilt MAGUIRE, VOORHIS & WELLS, P.A. 2 South Orange Plaza P.O. Box 633 Orlando, Florida 32802 Carol Browner, Secretary Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Daniel H. Thompson, General Counsel Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400
The Issue Whether DNR should establish an exceptional drilling unit or units in order to prevent waste and to avoid the . . . risks . . . from . . . an excessive number of wells, Section 377.25(2), Florida Statutes (1983)? The respondents expressly declined to raise any question as to the petitioners' standing or party status.
Findings Of Fact Petitioner W. J. Jordan and apparently all the other petitioners are owners of mineral rights under the northwest quarter of the southeast quarter of Section 13, Township 5 North, Range 29 West, Santa Rosa County, Florida. T. R. Miller owns the mineral rights under the northeast quarter of the southeast quarter of Section 13 and has leased them to Smackco. Near the center of the southeast quarter of Section 13 (the existing unit) respondent Smackco drilled the L. W. Roberts 13-4 well. NOT COMMERCIALLY PRODUCTIVE Smackco drilled the L. W. Roberts 13-4 well down to the Norphlet formation and went 49 feet further, into the Norphlet sands, before giving up its efforts to extract oil from the well. Although Smackco did find a mixture containing 28 to 30 percent hydrocarbons, the hydrostatic head precluded commercial production. If the well had come in, royalties would have inured to the benefit of petitioners, T. R. Miller, and the owners of the mineral rights under the southern half of the existing unit. Although the evidence showed that extracting oil from the L. W. Roberts 13-4 well was not commercially feasible now, it did not establish that the price of oil will never rise to the point that production would make economic sense. ADDITIONAL DATA At least three other oil wells have been drilled at the Mount Carmel Prospect in Township 5 North, Range 29 West, Santa Rosa County, Florida. In keeping with applicable statutes and rules, these wells are also located at or near the center of their respective quarter sections. Except where no governmental sections are laid out (offshore or in Spanish land grants), or where all rights affected by a change are in one ownership, DNR has adhered to the concededly arbitrary use of quarter sections as drilling units. Information gained from the wells drilled at the Mt. Carmel Prospect, and from seismic tests performed there formed the basis for uncontroverted expert opinion that a sandy mass, known to geologists as the Norphlet structure, lies almost three miles below the earth's surface; and that a pool of oil floats on salt water within the Norphlet structure, as shown in the Appendix to this order. The L. W. Roberts 13-4 is on the northern edge of the pool that the geologists hypothesize. The geophysicist's testimony that the Jay fault running northwest southeast and the smaller almost perpendicular fault running off to the northeast lie approximately as depicted in the Appendix was also uncontroverted. These faults may act as walls keeping oil on one side. The faults themselves do not hold oil. THE NEXT WELL If a new well were drilled in the center of the northwest quarter of Section 16, at a point one half mile due south of the L. W. Roberts 13-4, see Appendix, it would be near the western edge of the pool of oil, if the geologists are right. (If the geologists are wrong, drilling there might mean hitting the fault zone, as happened with the Franks Pittman well.) Drilling a quarter mile north, at the center of the first proposed drilling unit, would reduce the risk of hitting the fault, and might make commercial production of a substantial amount of oil possible. DRAINAGE LIKELY Smackco's geophysicist conceded that hydrocarbons at the L. W. Roberts 13-4 and hydrocarbons under the northwest quarter of the existing unit "very possibly" will migrate to a well in the center of the proposed drilling unit, if hydrocarbons are extracted in large quantities there. A well of the kind and to the depth contemplated can be expected to drain 160 acres more or less. The geologists cannot know precisely what the situation is three miles down on the basis of the information they have at hand. They may be mistaken now about the location of oil just as they were when they recommended earlier well sites in the Mt. Carmel Prospect.
Recommendation Upon consideration of the foregoing, it is RECOMMENDED: That DNR deny Smackco's petition for exceptional drilling units. DONE and ENTERED this 2nd day of March, 1984, in Tallahassee, Florida. ROBERT T. BENTON, II Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32301 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 2nd day of March, 1984. COPIES FURNISHED: James Reddick, Esquire and Dan Stewart, Esquire Suite 5 808 Caroline Street, Southeast Milton, Florida 32570 J. Nixon Daniel, III, Esquire and Spencer Mitchem, Esquire Beggs & Lane Post Office Box 12950 Pensacola, Florida 32576-2950 Charles J. Hardee, Esquire Department of Natural Resources 3900 Commonwealth Boulevard Tallahassee, Florida 32303 Elton Gissendanner, Director Department of Natural Resources Executive Suite 3900 Commonwealth Building Tallahassee, Florida 32303 * NOTE: Original Recommended Order has an appendix map which is available for review in the Division's Clerk's Office.
Findings Of Fact Upon consideration of the oral and documentary evidence adduced at the hearing, as well as the stipulations of fact entered into by the parties prior to the hearing, the following relevant facts are found: Petitioner Manasota-88, Inc., is a nonprofit corporation organized for the protection of the environment and has members who are residents of Manatee County. This organization filed a timely petition for hearing on the subject November 19, 1980, and January 1981 permit revisions. The intervenor Manatee Energy Company is the owner and operator of a crude oil splitter located in Port Manatee, Manatee County, Florida. This facility is a potential source of air pollutants, received a construction permit in 1978, and is permitted to operate under Permit Number A041-26555 issued by the DER in March of 1980. The intervenor's application to obtain a construction permit indicated a total process input rate of 15,000 to 22,000 barrels per day of crude oil. The splitter was to be fueled by either liquid petroleum gas or fuel oil with a sulfur content of 0.7 percent weight or less. The type of crude oil to be processed was not specified. The application further specified that the maximum heat input rate would be 70 million BTU/hr, and that the normal operating time would be 350 days per year, seven days per week and 24 hours per day. DER's Permit Number A041-26555, which authorized the operation of the crude oil splitter, described the facility as follows: ". . .a Crude Oil Splitter (15,000 BPSD) to separate crude oil by distillation into jet fuel (JP4 and/or Jet A), diesel fuel, and Bunker C. This permit includes the furnaces, boiler, burnoff flare, and storage tanks under the supervision of Manatee Energy. Combustion devices to be fired with LPG or fuel oil with a sulfur content of 0.7 percent or less. Facility located at Port Manatee." This permit also included specific conditions limiting particulate and sulfur dioxide emissions in terms of an amount of emissions per unit of heat input into the furnace and boiler. Because the crude oil splitter operates as a closed system, the heat input to the combustion units--the furnace and boiler-- determines the level of emissions from those sources. During the application and original permit process, Manatee Energy Company did not know the precise quality or grade of crude oil which would be utilized. In the early course of operations, it was discovered that considerably larger volumes of input (as much as 28,000 barrels per day), if processed at the normal design heat input rate, would not result in atmospheric emissions which violated the original permit conditions. For this reason, Manatee Energy Company, by letter dated October 22, 1980, and supplemented by letter dated October 29, 1980, sought a "clarification" in the conditions pertaining to its operating permit. In effect, Manatee Energy Company wanted to know if the original permit allowed a product input of greater than 15,000 barrels per day if other limitations on emissions from the furnace and boiler would not be violated. In support of its request for clarification, Manatee Energy Company submitted data regarding results from emission tests. The information submitted was not on a DER application form and did not include the certification of a professional engineer registered in the State of Florida, DER has subsequently received a letter dated November 22, 1982, from a Florida registered engineer certifying that the data submitted by Manatee Energy Company on October 22 and 29, 1980, was in conformity with sound engineering principles and offering the opinion that current permit conditions would not be violated by the facts submitted. DER responded to the October 22 and 29, 1980, letters from Manatee Energy Company by issuing a revised operating permit on November 10, 1980. This revised permit deleted the prior restriction on product input rate (15,000 barrels per day) contained in the project description and added a specific condition restricting the maximum heat input to the crude oil furnace to 55 million BTU per hour and to the boiler to 15 million BTU per hour. The permit revision issued by DER on November 10, 1980, did not allow a change in the physical premises of the plant, a change in the sulfur content of the fuel, or a change in the amount of heat input to the plant. Consequently, Manatee Energy Company did not request, and the revision did not allow, any additional atmospheric emissions, nor did it allow any increase in emissions which would exceed the limitations imposed in the original operating permit. An increase in the rate at which raw material is processed does not result in an increase in emissions. A cap on the amount of heat input also caps the amounts of emission. Stated differently, if the combustion of the fuel is being held constant by a limitation on the amount of allowable heat input, there will be no increase in emission regardless of the product input rate. The main effect of an increase in product input is on storage. The furnace and the boiler burn the same fuel. Further operating experience revealed that the boiler did not require 15 million BTU of heat input to perform its function, but only required 5 or 6 million BTU depending on the type of oil or other circumstances, such as wind. Manatee Energy Company therefore sought another clarification of the conditions of its operating permit as to the need to have separate allocations of heat input to the furnace and the boiler. In response to this request, DER, by letter dated January 19, 1981, changed the permit conditions by restricting the combined heat input to the furnace and boiler to 70 million BTU per hour, and removing the separate allocations of 55 million BTU/hr for the furnace and 15 million BTU/hr for the boiler. No changes were made to the emissions or the quality of fuel authorized under the original permit. This revision was not preceded by a permit application on a DER form certified by a professional engineer registered in the State of Florida. The level of emission from the furnace and boiler at the heat input capacity of 55 million BTU per hour and 15 million BTU per hour, respectively, would be the same as the level of emission from the furnace and boiler at the combined heat input capacity of 70 million BTU per hour. Therefore, the January 1981 permit revision did not allow emissions in excess of that allowed by the November 1980 permit revision. The 70 million BTU per hour heat input rate to the furnace and boiler specified in the two challenged revisions is the same as that indicated in the construction application submitted by Manatee Energy Company for the crude oil splitter. There being no increases in allowable heat input to the furnace and boiler, there is no increase in pollutant emissions from the two sources. By letter dated July 1, 1982, Manatee Energy Company requested that the storage tanks be deleted from Permit Number A041-26555 for the reason that it no longer contemplated using this previously leased tankage in connection with further refinery operations. By letter dated September 14, 1982, DER informed Manatee Energy Company that its permit was being changed by deleting reference to the storage tanks in the project description and by replacing a condition concerning the storage tanks with the following language: "6. The crude oil splitter cannot be operated unless the necessary storage tanks are in the possession and control of Manatee Energy Company, the tanks meet all Department regulations, and Manatee Energy Company obtains the required permit(s)." This permit revision or modification is not the subject of challenge in the instant proceeding. It is relevant only to illustrate that any issue as to an increase in hydrocarbon discharges resulting from increased production is now mooted, since the storage tanks were the only source of hydrocarbon and volatile organic compound emissions associated with the crude oil splitter.
Recommendation Based upon the findings of fact and conclusions of law recited herein, it is RECOMMENDED that the Intervenor's request for revisions to its Permit Number A041-26555 be GRANTED as proposed by the Department of Environmental Regulation on November 10, 1980, and January 19, 1981. Respectfully submitted and entered this 17th day of March, 1983, in Tallahassee, Leon County, Florida. DIANE D. TREMOR, Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32301 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 17th day of March, 1983. COPIES FURNISHED: Thomas W. Reese 123 Eighth Street, North St. Petersburg, Florida 33701 Martha Harrell Hall Assistant General Counsel 2600 Blair Stone Road Tallahassee, Florida 32301 W. Guy McKenzie McKenzie & Panebianco Post Office Box 1200 Tallahassee, Florida 32302 Victoria Tschinkel, Secretary Department of Environmental Regulation 2600 Blair Stone Road Tallahassee, Florida 32301
Findings Of Fact It was Stipulated by the parties that the Petitioner timely filed a notice of protest and formal written protest (if section 120.53(5), Fla. Stat. (1986) is applicable) and timely filed a petition for formal administrative hearing. The Petitioner did not receive a written notice of the recommended award of the District as intended by paragraph 9 of the General Conditions of the second invitation for bids, and it did file a notice of protest with seventy-two hours of receiving notification of the District's decision to award the contract to Mid America as intended by paragraph 10 of the General Conditions, P. Ex. 3. It was Stipulated by the parties that the substantial interests of the Petitioner are at stake in this proceeding. The Department of Water Resources is involved in groundwater studies throughout the nineteen Florida counties that comprise the District, and is responsible for the District's drilling program. In the past, the District's waterwells have been in the 500 to 800 foot range, and have been constructed of 4, 6, and 8 inch casing. The Water Resources Department is currently constructing a regional groundwater monitoring network in the nineteen counties. The underlying geological formations differ greatly from county to county, and several water tables often have to be Penetrated before the well reaches the Floridan acquifer. To maintain mud circulation, it is often necessary to case off portions of the well from water table to water table. Moreover, wells are often in unconsolidated formations, and casing is needed to provide support for the hole, Particularly in the upper portions of the well. For these reasons, the District plans to construct step or telescoping wells in the regional groundwater monitoring network. The District expects that it will need to set 16 inch casing in the first eighty feet of some of these wells. In about 1984, by competitive bids, the St. Johns River Water Management District (the District) leased a Speedstar 15-III drill rig from Mid America Drilling Equipment, Inc. This rig was a Size larger than the drill rig that is the Subject of this formal administrative hearing, and had been manufactured in 1978. The District was satisfied with the performance of the larger Speedstar drill rig, and had very few problems with it. District staff became familiar with the operation of the rig. As the lease neared the end of its term, the District began to explore the question whether it should continue to lease, or should purchase its own rig. A member of the District Board Suggested that the District consider acquisition of a rig over a period of years by lease-purchase. This suggestion was adopted by the Department of Water Resources of the District. Due to his familiarity with the Speedstar rig, Mr. Munch decided to use that rig as a basis for bid specifications, but to use the next smaller size, a Speedstar SS-135. Mr. Munch copied the specifications from a Speedstar SS-135 specification sheet as the specifications for the first invitation for bids. Mr. Munch has had no education in engineering or in drill rig design. He has a degree and field work experience in geology, and is a licensed water well contractor. He has been a project manager on projects when outside contractors set 16 inch casing in wells as deep as 2,000 feet, but he has not personally set a 16 inch casing. P. Ex. 1 is the first invitation for bids and specifications for the invitation for bids, as well as the bid of the Petitioner, the George F. Failing Company. This invitation for bids was published on or about August 26, 1986. The invitation for bids provided six bid blanks providing six bid alternatives. The bid blanks appeared as follows: One Year Lease $ /month, renewal $ /month Two Year Lease-purchase $ /year, buy-out $ Three Year Lease-purchase $ /year, buy-out $ Four Year Lease/purchase $ /year, buy-out $ Five Year Lease/purchase $ /year, buy-out $ * * * Suggested Purchase Price $ Less 3 percent for payment in 20 days Four bids were received pursuant to this invitation for bids, including the Petitioner's bid and the bid of Mid America Drilling Equipment, Inc., P. Ex. 7. The four bids were opened on September 11, 1986. Mid America was the only bidder that bid a one year lease with an option to renew. Mid America, the Petitioner, and G & R Machine and Welding, Inc., were the only bidders to bid a lease-purchase. The Petitioners bid was $163,565.00 as an outright purchase price for a Failing model CF-15 and, relevant to the second bid, $5,432.00 per month for a three year lease-purchase, with the rig owned at the end of the three year lease period with no further buy-out payment. The Petitioner did not bid a one year lease. P. Ex. 1. Mid America bid $179,823.00 as an outright purchase price on a Speedstar SS135, and $56,340.00 per year for a three year lease-purchase, with a buy-out price of $61,920.00. Mid America also bid a one year lease at $6,125 per month, with a renewal at $5,288.00 per month. P. Ex. 7. Robert Schenk is the District's Director of the Division of General Services, and as such, Mr. Schenk was responsible for District Purchasing and evaluation of the bids received pursuant to the invitation of bids. Mr. Schenk Prepared an analysis of Several of the bids, including G & R Machine, Mid America, and the Petitioner. P. Ex. Mr. Schenk testified that he felt that the Mid America bid was unclear because of the total amount of the bid calculated over the years. He Said that he considered the Mid America bid for a three year lease-purchase to be ridiculous and out of line because it was $50,000 greater than the outright purchase bid. The bid of the Petitioner for a three year lease- purchase was about $32,000 higher than its bid for an outright purchase. P. Ex. 8. G & R Machine also bid a Speedstar SS-15. Mid America's three year lease-purchase bid was about $35,000 higher than the G & R Machine bid for the same three year lease-purchase. ($230,940.00 compared to $195,664.32.) P. Ex. 8. The bid of Mid America was also high compared to the bid of G & R Machine for a four and a five year lease-purchase, but was comparable for a two year lease-purchase and for an outright purchase. The bid of the Petitioner was $16,000 lower than the Mid America or G & R Machine bids for an outright purchase, was $31,000 lower than the G & R Machine bid and $34,000 lower than the Mid America bid for a two year lease-purchase, and was Slightly higher than the G & R Machine bid on all other bids. The bid of the Petitioner was substantially lower than the Mid America bid on all bids analyzed on P. Ex. 8. Although the Mid America bid was high, it was not an unclear bid. The bid of Mid America was clear and unambiguous. P. Ex. 7. Mr. Schenk thought that the Petitioner's bid was the clearest bid received in the first invitation for bids. Apparently on the same day as the bid opening, which was September 11, 1986, Mr. Schenk had one of his assistants telephone Mid America to ask that it clarify its bid. In response, on the same day as the bid opening, September 11, 1986, Mid America sent the District a letter, P. Ex. 9, which effectively lowered its bid for a three year lease-purchase by $36,612.00. This letter was ultimately not considered by the District in the evaluation of the bids. On September 23, 1986, four staff members of the Department of Water Resources, including Mr. Munch and Barbara A. Vergara, Director of that Department, recommended by memorandum to Mr. Schenk that the Mid America bid for a Speedstar SS-135 for an outright purchase price of $179,823.00 be accepted. These staff members were of the opinion that the drill rig bid by the Petitioner "did not meet all of the bid Specifications due to slight manufacturing differences." But they were also of the opinion that "[t]hese differences may not be critical to the performance and capabilities of the equipment." P. Ex. 10. The staff comparison of the Mid America bid and the Petitioner's bid included calculations for rental costs due to the differing delivery times of the equipment, and calculated that the Mid America bid had a net cost of $184,435 compared to the Petitioner's bid having a net cost of $182,013. Attached to the staff recommendation of September 23, 1986, was a comparison of the three drill rigs by specifications. The comparison used the incorrect specification sheet for the Mid America rig, and thus contained the following errors: the rig bid by Mid America had a single sheave, 3 part block, not a double sheave, 4 part block; the rig also had a working hook load of 20,000 pounds, not 32,700 pounds. Two to four days after September 11, 1986, (the date of the letter from Mid America changing its bid for a three year lease-purchase) Robert Auld, the Florida Branch Manager for the Petitioner, learned that such a letter had been requested, written, and received by the District, and called District staff to protest. Mr. Schenk thereafter apparently concluded that solicitation and receipt of the bid change from Mid America had been procedurally erroneous because he testified that as a result of all of the discussion and criticism that surrounded that event, on the second invitation for bids he concluded that he was procedurally unable to contact any of the bidders to request clarification of bids, even though he then thought that the Petitioner's bid was unclear. Mr. Schenk decided to reject all the bids from the first invitation for bids before Mr. Auld's telephone call. P. Ex. 15, p. 10. But he did not communicate this decision to the staff of the Department of Water Resources before they wrote their memorandum that was initiated through the chain of command on September 23, 1986. Mr. Schenk initially decided to reject all of the bids because the bidders had not all bid on all of the requested alternatives. Later, other reasons for rejection of all of the bids became apparent. Another major reason for rejection of all of the bids was because the specifications were drawn from the Speedstar SS-135 specifications, and unfairly eliminated the Petitioner's rig. Mr. Auld admitted that the Failing CF-15 did not meet the specifications of the first invitation for bids because the Failing CF-15 did not have an 8 1/2 inch rotary table, but was of the opinion that it met all other specifications. Mr. Schenk also rejected all of the bids because of the irregularity of having solicited and received the bid change from Mid America. On October 1, 1986, the District informed all bidders that the bids were all rejected and that the purchase would be again advertised for bids. No protest was filed concerning the first invitation for bids, and it was ruled during the formal administrative hearing that the foregoing facts are admissible as explanatory of the basis for the second invitation for bids, and not as a basis for challenge to the first invitation for bids. Mr. Munch then drafted specifications for the second invitation for bids. This time, he Specified "Speedstar SS-135 or equivalent." Mr. Munch had determined from his experience with the rented Speedstar that the Speedstar SS-135 was capable of fulfilling the needs of the District for drilling. His intention was to allow bids for other types of drill rigs that were the equivalent of a Speedstar SS-135. Ms. Vergara defined the term "equivalent" to mean no differences between a Speedstar SS-135 and the alternative drill rig with respect to doing work in the field that needs to be done by the District. At some time before the second invitation for bids was advertised, or at least before the second bids were filed, the District became Primarily (though not exclusively interested in receiving bids on a three year lease-purchase of a drill rig. Both the Petitioner and Mid America knew this before they prepared their second bids. P. Ex. 3 is the second advertisement for bids and was published on November 6, 1986. The advertisement asks for bids on a "lease-purchase of One Rotary Drill Rig." The attached sheet marked "specifications" stated that what was sought was a "[b]id for purchase or one year lease of a new Speedstar 135 rotary drill rig or at least the equivalent equipment with the following options." Following that were eight technical specifications. The second invitation for bids also specified the following: "Bidder must indicate any and all exceptions to specifications. "Bid shall be awarded to the lowest qualified, responsible bidder whose bid meets all specifications in the Invitation to Bid, including delivery, price and other factors most advantageous to the District." All bidders were to bid using the bid blank attached to the invitation for bids. The bid blank was different from the first invitation for bids apparently with the intent to make bid comparisons easier. The bid blank provided the following alternatives for bids: Purchase Price $ Lease Price $ /Month, first year (renewable) $ /Month, second year (renewable) $ /Month, third year One year guarantee non-routine, major maintenance and repair on lease equipment (renewable annually for term of leased $ . Make and Model of Equipment . Manufacturers Warranty . (minimum of 6 months or 1000 hours) Delivery days (from date of order) Delivery Charges $ . Location of Maintenance Services . Since the District was then "primarily" (but not exclusively) "interested in" a three year lease-purchase, the bid blank form was incomplete and unclear. Paragraph A) of the bid blank form clearly provides for a bid for an outright purchase only, not a "lease-purchase." And Paragraph B) provides only for a lease without any mention of purchase; Paragraph B) asks for a price by month for the first year, with the notation that the lease is renewable (apparently at the option of the District, a lease price by month for the second year, with the notation again that the lease is renewable (at the option of the District), and a lease price per month for a third year, with no mention of any further renewability. Paragraph B) says nothing about purchase of the drill rig, ownership at the end of the lease term, or the buy- out price at the end of the lease term. Moreover, the rest of the invitation for bids is similarly incomplete and unclear. Although the first page of the invitation for bids states that bids were requested on a "lease-purchase" of one rotary drill rig, the specification sheet attached to the invitation stated the specification that the bid should be "for purchase or one year lease...." P. Ex. 3 (E.S.). The specification said nothing about a three year lease-purchase. P. Ex. 3, the second invitation for bids, was sent to all entities that had submitted a bid in response to the first invitation for bids. These included five companies that were Speedstar SS-135 dealers and the Petitioner. Only two bids were received in response to the second invitation for bids, one from Mid America and one from the Petitioner. The second Mid America bid is P. Ex. 11. The Petitioner's second bid is P. Ex. 4. The bids were opened on November 20, 1986. The opening was attended by Ron Owens, President of Mid America, and Robert Auld. Mr. Schenk announced that the Petitioner was the apparent low bidder. Mr. Schenk may have only intended his announcement of apparent low bid to have been with relationship to the bid for outright purchase. A bid tabulation sheet was prepared. P. Ex. Mr. Schenk also announced that the recommendation by the staff to the District Board as to which company should be awarded the contract would be made at the next Board meeting. At that time, the next Board meeting was January 14, 1987. The Petitioner's bid, typed on the bid blank required by the District, provided in pertinent part the following: Purchase Price $146,976.00 Lease Price $ NO BID /Month, first year (renewable) (OWNED AT END OF SECOND YEAR) $6,885.00 /Month, second year (renewable) (OWNED AT END OF THIRD YEAR) $4,592.00 /Month, third year One year guaranteed non-routine, major maintenance and repair on lease equipment (renewable annually for term of lease) $NOT AVAILABLE Make and Model of Equipment FAILING MODEL CF-15 Combination Drill GEORGE E. FAILING COMPANY standard Manufacturers Warranty warranty policy will apply, extended for 9 months (minimum of 6 months or 1000 hours) Delivery 120 days (from date of order) Delivery Charges $ NO CHARGE Location of Maintenance Services GEORGE E. FAILING COMPANY 2101 Starkey Road Largo, Florida 33541 Mid America Submitted its bid on the bid blank form as follows: Purchase Price $179,823.00 Lease Price $5,241.00 /Month, first year (renewable) $5,241.00 /Month, Second year (renewable) $5,241.00 /Month, third year (SEE CONDITIONS BELOW) One year guaranteed non-routine, major maintenance and repair on lease equipment (renewable annually for term of lease) $3,000.00 per year Make and Model of Equipment Speedstar SS-135 Manufacturers Warranty 6 months or 1000 hours (minimum of 6 months or 1000 hours) Delivery 21 days (from date of order) Delivery Charges $ Included/No Charge Location of Maintenance Services Ocala, Florida * * * CONDITIONS #1. If the lease is written for a guaranteed 36 month period, there will be a purchase option available at the end for $1.00 #2. If the lease is written as a yearly renewable lease and runs 3 consecutive years there will be a purchase option available after the 36th payment for $8,092.00. The bid of Mid America was for a Speedstar SS-135, and thus complied with the specifications in that respect. The bid of Mid America was clear and enable the District to understand what its annual budgetary obligations might be should the alternatives in the bid be accepted. The Mid America bid provided the following three alternatives: Outright purchase for $179,823, which was $32,847 more than the bid of the petitioner of $146,976. Payment of a total of $188,676 over a three year period plus an additional payment of $8,092 at the end of the lease if the lease were to be written as yearly renewable for 3 consecutive years, for a total cost of $196,768. Payment of a total of $188,676 (plus a $1 buy-out option) over a three year period if the lease were to be written for a guaranteed 36 month period. This is the alternative ultimately accepted by the District. After publication of the second invitation for bids, but before the opening of those bids, Ms. Vergara appeared before the District Board to explain the manner in which the invitation for bids had been drafted. In particular she explained that the invitation used a "brand name or equivalent" specification. She further advised the Board that the staff recommended the Speedstar SS-135 as the equipment most capable of handling the drilling needs of the District, and that any equipment purchased must be at least equivalent to the Speed star SS-135. At some time before the opening of the second set of bids, Mr. Munch and his supervisor, Ms. Vergara, traveled to the offices of Mid America and inspected a Speedstar SS-135. The owner and President of Mid America was Present to explain the design advantages of the Speedstar SS-135. He was a Salesman, and had no background in engineering or drill rig design. None of the District staff visited the Petitioner's place of business to inspect a Failing CF-15. Mr. Munch and Ms. Vergara did not see a Failing CF-15 until preparations began for the formal administrative hearing. In a deposition prior to the formal hearing, Mr. Schenk testified under oath that the staff had already decided that they wanted a Speedstar SS-135 rather than a Failing CF-15 based upon the report of Ms. Vergera to the District Board. In a deposition prior to the formal hearing, Mr. Munch testified that he was never asked which rig he would rather have, that the issue was Strictly a cost decision, that he probably would have had no objection to purchase of the Failing CF-15 had it been cheaper than the Speedstar SS-135, and that the Failing CF-15 would probably have done the job needed by the District to be done. On December 12, 1986, Mr. Schenk sent a memorandum to the District Board concerning the purchase of the rotary drill rig. The memorandum advised the Board that the District had received two bids. It then presented five alternatives for the Board to consider. All of the bid alternatives (alternatives 1 through 4) related to the Mid America bid on the Speedstar SS-135, and presented all of the options bid by Mid America. None of the bid alternatives related to the petitioner's bid. The District Board was not advised as to the comparative purchase prices bid by the two bidders (the Petitioner's price being $32,000 less than Mid America's), it was not advised as to the two interpretations of the three year option in the Petitioner's bid, and it was not advised that under the second interpretation of the Petitioner's three year lease-purchase bid, the Petitioner's bid had a net cost, after accounting for delivery time, that was $9,529 less than the Mid America bid. (See finding of fact 60.) Mr. Schenk thought that paragraph B), as modified by the "CONDITIONS" placed on the bid by Mid America, presented an option to "renew" the lease monthly at $5,241 per month, for an annual cost of $62,892. Evidentially, then, Mr. Schenk thought that the word "renewable" pertained to renewal by month. P. Ex. 15, p. 2, para. 2. With respect to this option, nothing is mentioned about purchase. Mr. Schenk also treated the word "renewable" to be intended to be exercised annually, resulting in a three year lease (renewable annually). The differing use of the word "renewable" came as a result of the modifications placed on the bid form by Mid America. The District Board chose option 3, which was condition number 1 on the bid blank submitted by Mid America, (a guarantee 36 months lease with a purchase option of $1.00) with the addition of the words "Subject to the availability of funds." The Second invitation for bids had Stated in Paragraph 3 of the third page that "all lease-purchase agreements must include a nonappropriation of fund Paragraph as required by Florida Statutes." Thus, the condition that the lease be "guaranteed" was modified by the District consistent with the specification of the invitation for bids relating to the appropriation of funds. On the day of the District Board meeting approving a lease-purchase with Mid America, January 14, 1987, the District entered into a contract with Mid America for the lease-purchase of a Speedstar SS-135. SJRWMD Ex. 3. The lease agreement contains a Paragraph allowing the District to terminate the lease upon nonappropriation of funds, Subject to certain conditions. Id., para. 11. In February, 1987, Mr. Auld learned at a trade show in Orlando that the District had awarded the contract to Mid America. Mr. Auld called Ms. Mildred Horton, the Assistant Executive Director of the District, to ask for the reasons why his bid was not accepted. Ms. Horton wrote a letter to Mr. Auld dated February 17, 1987, Setting forth the reasons for the award to Mid America and attaching two amortization Schedules, one for each bid. The letter and attachments is P. Ex. 6. Ms. Horton stated that the Schedules attached were the only ones in existence, to her knowledge. None of the reasons given by Ms. Horton for the rejection of the Petitioner's bid could have been known prior to the opening of the bids. The amortization schedules attached to Ms. Horton's letter had been prepared by Mr., Schenk. The schedule for the Petitioner's bid showed a total cost over a three year period of $224,344, which resulted in an effective interest rate of 31 percent compared to the outright purchase price on the Petitioner's bid of $146,976. The schedule assumes that the Petitioner's bid was for a monthly payment of $6,885 for two years followed by a monthly payment of $4,592 in the third year. P. Ex. 6. Mr. Schenk testified that he considered the possibility that the Petitioner's bid for a three year lease purchase was $4,592 per month for 36 months, and prepared an alternative amortization table based upon that possible interpretation as well as the amortization table attached to the letter sent to Mr. Auld by Ms. Horton described above. P. Ex. 12. Mr. Schenk concluded, however, that the Petitioner's bid should be interpreted as a bid of $6,885 per month for two years and $4,592 for the third year, for a total cost of $224,344. He testified that it was confusing that the Petitioner's bid did not contain a price for the first year, but he also concluded that the price of $6,885 placed on the second line of paragraph B) of the Petitioner's bid was intended to be a price for both the first year and the second year. He further testified that the Petitioner's bid may have been more understandable had the word "renewable" been stricken on the bid form. Finally, he testified that he disregarded the additions to the Petitioner's bid form because these were "alterations" to the form, but considered the additions to the bid form by Mid America because these were only "additions." As discussed above, after the Second invitation for bids was published, the District was Primarily interested in receiving bids for a three year lease-purchase. The bid blank in the second invitation for bids, however, failed to provide a clear method for bidders to bid that option. Paragraph B) of the bid blank drafted by the District was defective because it did not in any manner state that a purchase (a transfer of ownership) was included in the "lease" for which a price was being asked, because it failed to state whether the District wanted bids on a one year lease- purchase, a two year lease-purchase, a three year lease-purchase, or only a lease for those periods of time, because the word "renewable" was susceptible of being interpreted as renewal from month to month as well as from year to year, as so construed in Mr. Schenk's December 12, 1986 recommendation to the District Board. Paragraph B) was also defective because it failed to provide a place to show the price of the purchase option at the end of the lease, or zero if there were to be none. Without the "CONDITIONS" attached to the Mid America bid, the filled-in blanks of Paragraph B) on the bid form only resulted in a bid on a lease. Mr. Schenk recognized this as he construed Paragraph B) of the form as only asking for a lease bid when he informed the District Board of option number 2 in his memorandum of December 12, 1986. P. Ex. 13. Since the bid form was defective, it was foreseeable that bidders would have to have added additional words to the bid form to make it sensical. It was also foreseeable that different bidders would take different approaches in trying to draft additions to the form to enable them to bid all critical aspects of a lease that included a purchase at the end of the lease. The bid of the Petitioner should have been construed with this foreseeability in mind. In particular, the failure of the Petitioner to place a price on the first line of paragraph B) (relating to the first year) coupled with the placing of a price at the second year line and the third year line, and the addition of the words "owned at end of second year" and "owned at end of third year" should have been construed as the Petitioner's attempt, like the attempt of Mid America, to cure the ambiguities in the bid form. As discussed above, without such words, a price in the first line of paragraph B) of the bid form would have only been a bid for a renewable lease for one year, with no purchase option. The District argues that it did not ask for a bid on a two year lease-purchase, and that the Petitioner's attempt to bid on that as well as on a three year lease-purchase caused confusion. But the problem is that the bid form, as discussed above, did not ask for any purchase associated with a lease, and asked for prices for a lease that could have either a one, two or three year term based upon the option to renew. It was not unreasonable, then, for the Petitioner to have bid a two year lease-purchase. The interpretation of Petitioner's bid as a bid for a total cost of $224,344 over three years is not reasonable. The interpretation of the Petitioner's bid as providing for a total cost of $224,344 over three years results in an interest cost of 31 percent, a rate of interest that is facially unreasonable. But more important if, as assumed in that interpretation, the District were to enter into a contract with the Petitioner at a monthly charge of $6,885 per month for two years, it would own the Failing drill rig at the end of the second year. This is so because the Same line that contains the price ($6,885) also has the added words "owned at end of second year." If it owned the rig after two years, the District Surely would not continue leasing it for the third year at $4,592 per month. Payment of $6,885 for 24 months would cost a total of $165,240, which reasonably compares to Petitioner's outright purchase price of $146,976, plus the cost of paying over a two year period. Since it was more reasonable to construe line two of the Paragraph B) of the Petitioner's bid form as a bid for a two year lease-purchase, the third line should have been given the same construction, that is, to construe the price placed on the line as the price each month for the entire period (here, three years) with ownership automatic at the end of the term. The reasonable interpretation of line 3 of Paragraph B) of the Petitioner's bid is for a lease-purchase for three years at $4,592 per month, for a total cost over three years of $165,312, the rig then being owned by the District at the end of 36 months with no buy-out cost. The reasonableness of this interpretation is further supported by the fact that payment of $165,312 on a machine that cost $146,976 to buy outright results in an interest rate for payment over three years of 7.9 percent, which is a normal and usual interest rate that would be expected in a competitive bid. P. Ex. 12. Mid America's bid offered to deliver in 21 days, while the Petitioner offered to deliver in 120 days. Since the District was then renting drilling equipment at $4,612 per month, it would potentially have incurred about one month extra rental ($4,612) on the Mid America bid, and $18,448 for four months extra rental on the Petitioner's bid, or an additional cost of $13,836 on the Petitioner's bid. Including this cost of rental during the potential delivery period, the net cost of the Petitioner's three year lease-purchase bid was $183,760, and the net cost of the Mid America bid alternative that was accepted by the District was $193,289. Thus, with respect to the bid actually accepted by the District, the Petitioner's bid was $9,529 less than the bid of Mid America. During the formal administrative hearing, it appeared from the evidence that the District relied upon the following additional issues, other than price, as the reasons for selection of the Mid America bid: One year guaranteed non-routine, major maintenance and repair on the lease equipment, renewable annually for the term of the lease. A manufacturers warranty of at least 6 months or 1,000 hours. The delivery date. The location of the maintenance Services. All of the foregoing were bid specifications printed on the bid form. P. Exs. 11 and 4. Of these, only the issue of non-routine maintenance was mentioned in the letter of Ms. Horton to Mr. Auld on February 17, 1987. P. Ex. 6. Mid America bid $3,000 per year for non-routine maintenance. The Petitioner Stated on its bid form that this item was "not available." Non-routine maintenance is needed only at the end of the warranty Period. In the industry, its is well understood that non-routine maintenance normally does not apply and is not Purchased until the end of the warranty period. The District had not purchased the non-routine maintenance at the time of the formal administrative hearing. The prices quoted in the bids, pursuant to the invitation for bids, were to have been fixed only for 90 days. Thus, it is uncertain whether the $3,000 bid of Mid America for non-routine major maintenance would still hold. The term "non-routine, major maintenance and repair" was not further defined by the bid form. Although the Petitioner did not bid on non-routine maintenance, it did offer a one year warranty which was six months beyond the minimum specified by the District. Thus, for this six months period only, the Petitioner effectively provided a free non-routine maintenance offer at least to extent of the warranty. But the Petitioner failed to offer non-routine major maintenance for the 24 month period following the first year of the lease. Both bidders complied with the specifications with respect to the manufacturer's warranty, but the Petitioner offered a warranty that was better by six months. The District Board was incorrectly advised that the Petitioner's warranty was only for 90 days (and thus not in compliance with specifications). P. Ex. 13. The delivery date was considered during the hearing only with respect to the cost of rental of equipment until the new rig would be delivered, and thus was an element of net cost discussed above. The Petitioner's delivery date caused its bid to have an additional rental cost of $13,836 as compared to the Mid America bid, but the Petitioner's total net cost still was lower than the Mid America bid, as discussed above. The Petitioner's location of maintenance services was Largo, Florida, and Mid America's location was Ocala, Florida. Mid America's location is approximately 100 miles closer to Palatka than the Petitioner's location. The difference is a difference of about 4 hours in travel time, roundtrip, or only two hours for delivery of a part. Mr. Schenk testified that this factor carried only "some weight." Mr. Schenk did not know how often maintenance at the seller's location might occur, what percentage of maintenance might be in the field rather than in the seller's shop, or the problems that might occur from lack of a part. From the testimony of Mr. Winchester, who was the only rig expert who testified, and the testimony of Mr. Munch regarding the leased Speedstar rig, it appears that maintenance on the rig for major problems should not occur very often, if at all, and that many problems can be corrected in the field. In most cases, parts will have to come overnight by bus. It is inferred that a part from Ocala will arrive no sooner by overnight bus than a part from Largo by overnight bus. Thus, the closer location of the Mid America shop is of little importance on this record. The February 17, 1987, letter from Ms. Horton to Mr. Auld Stated that the failure of the Petitioner to bid on a one year lease was one of the reasons for not accepting the Petitioner's bid. As discussed above, the District was primarily seeking a three year lease-purchase, not a one year lease, and communicated this to the two bidders. Indeed, it was the existing one year lease that prompted the desire by the Board to explore a purchase over time. The District did not enter into a one year lease with Mid America, either. Thus, a bid on a one year lease was not a material or substantial part of the bid specifications. Specification number 2, listed as a desired option, was that the drill rig have a five speed transmission. The Speedstar SS-135 had a five speed transmission, thus giving it a lower first gear, and the Failing CF-15 did not. There is no evidence that the Petitioner could have have offered a five speed-transmission. On the other hand, there is no evidence that a four speed transmission would not effectively meet the needs of the District. The only evidence was that the five speed transmission would have a lower first gear, but there was not substantial evidence that the District would encounter drilling circumstances needing only the lower gear of the Speedstar SS-135. When the rotary table is retracted on the Speedstar SS- 135, the opening is 18 inches in diameter, thus allowing the Speedstar SS-135 to set 16 inch casing. The Speedstar SS-135 otherwise marginally has the power and related mechanical ability to drill and set 16" casing, particularly lighter PVC casing, to depths of 80 feet in about six hours. Drilling the first 80 feet in six hours is very slow in comparison to the normal operation of either the Speedstar SS-135 or the Failing CF-15, and would be more a matter of use of the mud pump to wear away the soil rather than actually drilling the hole. However, the Speedstar SS-135 is in fact being used in Florida by other owners to drill and set 16 inch casing. When the rotary table is retracted on the Failing CF-15, the opening is 14 1/2 inches in diameter, and thus the Failing CF- 15 does not have any capacity to drill or set 16 inch casing. If the District had chosen the Failing CF-15, in those cases in which it needed to drill and set 16 inch casing, it would have to contract out to a larger drill rig to drill and set such casing. In all other respects the Speedstar SS-135 and the Failing CF-15 are functionally equivalent machines, and are considered to be equivalent in the industry. For the most part, the design differences explained by Mr. Munch with respect to the video tape of views of both machines were not differences causing the machines to be not functional equivalents, except as discussed above. The recommendation of the staff of the District to purchase the Speedstar SS-135 would probably have been the same, based upon factors other than price, had the staff considered the bid of the Petitioner to have been $9,529 less than that of Mid America for a three year lease-purchase, as discussed in finding of fact 60. While the District entered into the process of obtaining bids for the drill rig with a preference for a rig capable of performing like the Speedstar SS-135, it did not intend to favor the Mid America Company over the Petitioner, nor did it act in bad faith. At all times relevant to these invitations for bids and award of the contract, the District did not have rules governing purchasing of commodities or governing the notification to interested persons concerning the procedures for contesting a proposed purchase. It did not have any policy or rule requiring that the lowest bid be accepted without consideration of other factors. It did have written policies, SJRWMD Exs. 1 and 2, providing for the following: Purchases in excess of $5,000 must be advertised in a newspaper of general circulation no less than ten days prior to bid opening. The District Purchasing Director may withdraw the entire proposal, and may reject all bids or parts of bids, if the District's interest will be served by that action. Departments or Divisions of the District submitting requisitions must do so with items described in such terms to allow unrestricted bidding and to afford full opportunity to bid to all qualified bidders. Any purchase order made contrary to the provisions of the purchasing policies shall be of no effect and void.
Recommendation For these reasons, it is recommended that the St. Johns River Water Management District enter its final order that the bid of the George E. Failing Company pursuant to Bid Number 87-01, second call for bids, dated November 6, 1986, was properly rejected because it did not meet all specifications of the invitation to bid. DONE and ENTERED this 28th day of August, 1987. WILLIAM C. SHERRILL Hearing Officer Division of Administrative Hearings The Oakland Building 2009 Apalachee Parkway Tallahassee, Florida 32399-1550 (904) 488-9675 Filed with the Clerk of the Division of Administrative Hearings this 28th day of August, 1987. APPENDIX TO RECOMMENDED ORDER, CASE NO. 87-1606BID The following are rulings upon findings of fact proposed by the parties which have been rejected. The numbers correspond to the numbers used by the parties. Findings of fact proposed by the George F. Failing Company: 2. The third sentence is rejected because Mr. Munch chose the Speedstar SS-135 as a basis for the Specifications due to his familiarity with the leased drill rig of the same make. 6. Not relevant. 19 and 20. Mr. Auld's testimony that a manufacturer's warranty on a 1985 truck would be less inclusive that on a 1987 truck was hearsay, and cannot support a finding of fact as to that point. Thus, those portions of these proposed findings concerning a 1985 truck are irrelevant. 36. Ms. Vergara did not testify that the planned monitoring wells would be 2,000 feet deep. 38. Subordinate to finding of fact 71. 45. Rejected by finding of fact 42. Rejected by finding of fact 50. There is no evidence that the Speedstar SS-135 bid by Mid America was a display model. The delivery date of the Speedstar SS-135 is not in evidence. Findings of fact proposed by the St. Johns River Water Management District: 4. There is no evidence as to the depths of the proposed monitoring well network, and thus a finding of fact that the depth will be 1000 feet cannot be made. 8. The existence of a buy-out price in the first Mid America bid did not cause the bid to be unclear. 12. The fourth sentence, as to what the District thought the second bid blank "should" contain, is not supported by the evidence. The last sentence is rejected because it is not clear that the bid blank was a "renewable lease-purchase in one year intervals." See findings of fact 34, 55, and 56. 14. The evidence is that the Speedstar SS-135 can set 16 inch casing, not 17 1/2 inch casing. The findings concerning the failure of the Petitioner's bid to give the District the option of being able to "exit the lease" in one year is rejected because that option was securely provided in the invitation for bids, so securely so that it was construed by the District to be an implicit part of the Mid America bid that ultimately was accepted by the District. See finding of fact 50 concerning the non-appropriation of funds condition. Additionally, the findings concerning the inability of the District to construe the bid of the Petitioner to know its first year fiscal obligations are rejected for the reasons stated in findings of fact 56 through 58. The second sentence is rejected for the reasons stated in findings of fact 34 and 55. The last sentence is rejected by these findings of fact as well; the ambiguity was created by the bid form, not by the bidders. These findings of fact have essentially been rejected by findings of fact 34 and 55. Further, the word "renewable" was not inconsistent with ownership at the end of a two year period because the word "renewable" could be given the construction given it by Mr. Schenk, renewable from month to month. See finding of fact 49. 22 and 23. Rejected for the reasons stated in findings of fact 34 and 55 through 58. These proposed findings of fact are essentially correct as a matter of law, but are not facts. These findings of fact are rejected by findings of fact 34 and 55 through 58. 27. The last sentence of proposed finding of fact (4) is rejected for the reasons stated in finding of fact 66. 29. Subordinate to finding of fact 71. 32. While these Proposed findings are true and have been Substantially adopted, the proposed findings are not relevant in view of the stipulations contained in findings of fact 1 and 2. COPIES FURNISHED: Dale Twachtmann, Secretary Department of Environmental Regulation Twin Towers Office Building 2600 Blairstone Road Tallahassee, Florida 32399-2400 Daniel H. Thompson, Esquire General Counsel Department of Environmental Regulation Twin Towers Office Building 2600 Blairstone Road Tallahassee, Florida 32399-2400 Henry Dean, Executive Director St Johns River Water Management District Post Office Box 1429 Palatka, Florida 32078-1429 Linda M. Hallas, Esquire 9455 Koger Boulevard, Suite 209 St. Petersburg, Florida 33702 Wayne E. Flowers, Esquire Post Office Box 1429 Palatka, Florida 32078-1429
Findings Of Fact Friends of Lloyd, Inc. is a Florida non-profit corporation formed for the purpose of protecting Jefferson County from harmful development. The Council of Neighborhood Associations of Tallahassee/Leon County (CONA) is a non- profit Florida corporation whose members are the neighborhood associations in Leon county; members of those associations reside in 42 Leon County neighborhoods dispersed throughout Leon County. CONA's purposes and goals include protection of the quality of life and environment in Leon County. The Thomasville Road Association's members are principally residents of Leon County. The Association was formed to promote responsible growth management in northern Leon County. None of the Petitioners are owners or "developers" of a Development of Regional Impact within the terms or scope of Chapter 380, Florida Statutes. Rather, Petitioners are members of non-profit organizations interested in the environment and growth management of Leon County. The Department of Community Affairs (the "Department") is the state land planning agency with the power and duty to administer and enforce Chapter 380, Florida Statutes, and the rules and regulations promulgated thereunder. Sections 380.031(18), and 380.032(1), Florida Statutes (1987). Texaco is a business entity that proposes to develop a "tank farm" near the community of Lloyd in Jefferson County, Florida. The Texaco tank farm is a "petroleum storage facility" as that term is used in Rule 28-24.021, F.A.C. Colonial is a business entity that proposes to develop a petroleum pipeline that will connect to the Texaco tank farm. The pipeline is designed to carry and contain petroleum products For purposes of standing, the parties have stipulated that certain environmental hazards can reasonably be expected to occur as a result of the existence of the pipeline/tank farm. No competent evidence was submitted regarding those hazards. As a result of the stipulation, Petitioners have each established injury-in-fact so that they are "adversely affected" by the challenged rule to an extent sufficient to confer upon them standing to maintain this action under Section 120.56, Florida Statutes. On September 7, 1989, one of the Petitioners sent Respondent a letter suggesting that the proposed tank farm development to be built in Jefferson County should be required to undergo review as a DRI. Enclosed with the letter was a proposed circuit court complaint pursuant to Section 403.412(2)(c), Florida Statutes. Petitioner expressed its intention of filing this circuit court action, but first provided Respondent a copy of the proposed complaint in accordance with the provisions of Section 403.412, Florida Statutes. In two letters dated September 8 and 25, 1989, Petitioner supplied additional information to Respondent concerning the tank farm project and contended that in making its determination as to whether the development must undergo DRI review, Respondent should consider the storage capacity of both the tank farm and the pipeline. On October 9, 1989, Respondent answered Petitioner's first letter, and stated that the proposed project was not required to undergo DRI review because the total storage capacity of the tanks was only seventy-eight percent (78%) of the threshold set out in Chapter 28-24, F.A.C. On October 13, 1989, Respondent answered Petitioner's second and third letters, stating that with respect to the pipeline, it has been long standing departmental policy to interpret "storage facilities" as meaning only the tanks, not the pipeline, when determining whether petroleum storage facilities meet the DRI thresholds set out in Chapter 28-24. The proposed tank farm would have nine tanks with a total capacity of 155,964 barrels, which is, as Respondent determined in its letters, approximately seventy-eight percent (78%) of the applicable DRI threshold for "petroleum storage facilities" set forth in Chapter 28-24, F.A.C. The proposed pipeline's capacity over its approximate forty-five mile length from Bainbridge, Georgia to the tank farm is approximately 34,000 barrels. The proposed pipeline's volume flow capacity from the Florida/Georgia state line to the site of the prosed tank farm is approximately 13,500 barrels over approximately 18 miles. If the pipeline's volume capacity from Bainbridge, Georgia is added to the tank farm's volume capacity, the resulting project would be approximately ninety-five percent (95%) of the applicable DRI threshold in Chapter 28-24. If the pipeline's volume capacity from the state line is added to the tank farm's volume capacity, the resulting project would be approximately eighty-five percent (85%) of the threshold. In either instance, the project would exceed the eighty percent (80%) threshold that may require it to undergo DRI review although the project would be Presumed not to be a DRI under the Statute. The Department does not require developments outside Chapter 28-24's enumeration to undergo DRI review. The Department has never treated petroleum Pipelines as "petroleum storage facilities," or as otherwise subject to DRI review. On Several occasions, the Department has applied the petroleum storage facility guideline and standard to petroleum tank farms without determining whether a pipeline was attached to the tank farm. On one prior occasion, the Department has explicitly stated that Petroleum Pipelines are not subject to DRI review. The Petitioners contend that Department's Position that pipelines are not "petroleum storage facilities" is an invalid policy because it has not been adopted as a rule. There is no dispute the Department's Position on this issue has not been promulgated as a rule. If a facility were represented to be a Petroleum pipeline, but was actually designed as and operating as a petroleum storage facility, the Department would apply the Petroleum storage facility DRI guideline and standard to that facility.
The Issue The issue is whether the application of Petroleum Products Corporation for reimbursement of the cost of assessment and clean-up of soil and groundwater contamination at its site in Broward County, Florida, under the State Underground Petroleum Environmental Response Act of 1986 should be granted.
Findings Of Fact The Legislature provided a system for the clean-up of sites contaminated as the result of the storage of petroleum or petroleum products in the State Underground Petroleum Environmental Response Act of 1986 (Super Act), Chapter 86-159, Laws of Florida, codified primarily as Section 376.3071, Florida Statutes. The Super Act contains a reimbursement program funded by the Inland Protection Trust Fund. Section 376.3071(12), Florida Statutes, permits reimbursement of allowable costs for the rehabilitation of sites contaminated from discharges related to the storage of petroleum or petroleum products. Petroleum Products Corporation owns a parcel of land located at 3130 Southwest 17th Street, Pembroke Park, Florida. From 1959 to 1970 Petroleum Products Corporation operated a facility on that land which collected used oil from service stations and automobile dealerships, processed it, and sold it either as fuel oil or lubricating oil. About 90% of 150,000 gallons of used oil processed monthly at the facility was sold as fuel; the remaining oil was sold as lubricating oil, but even when sold as lubricating oil, it was sometimes burned as fuel because re-refined oil makes good fuel. The storage tanks were located on the southeastern portion of the property, near Carolina Road. The facility used a two-phase distillation process. Used oil was distilled to remove water, after which it could be sold as fuel oil. If processed in the second phase, for sale as lubricating oil, it was distilled further, and treated with sulfuric acid and clay to remove additives and residue, and change color. This phase produced a waste consisting of acid/clay sludge. This sludge is generally very black, and has a pH of approximately 3. It is very viscous, and has the consistency of roofing cement; laymen would describe it as tar. It does not flow easily, but is liquid enough to be pumped. This processing also occurred in the southeast part of the property. While the recycling facility produced lubricating oil using the acid/clay treatment from 1959 to 1970, the acid sludge was hauled to a municipal dump, or placed in pits dug into the ground on the north and east of the plant site. When the pits were dug, they were dug below the water level, and there was water in the pits before the sludge was dumped in them. The disposal of sludge in pits on the recycling site was a prevailing industry practice, and violated no regulatory requirements at the time. Operators considered on-site disposal of sludge preferable to hauling sludge to a landfill. During periods of heavy rain, some of the sludge may have overflown the pits and spread to nearby land, where it would become mixed with the surface soil. Petroleum Products Corporation ceased making lubricating oil in 1970, but continued to process used oil into fuel oil. The local Broward County Pollution Control Agency asked Petroleum Products Corporation to remove the acid/clay sludge from its property, and to refill the pits with other fill material. Petroleum Products Corporation acceeded to this request, and a great volume of sludge, perhaps hundreds of thousands of gallons, was removed from the pits, which were then refilled under the supervision of the Broward County Pollution Authority. Receipts Petroleum Products Corporation produced at the hearing, or thereafter from the custody of the U. S. Environmental Protection Agency, show that more than 150 truck loads of sludge were removed and hauled to landfills operated by Metropolitan Dade County or by the City of Surfside. Some pockets of the sludge remain at the site of the pits because they were not completely emptied. The backfill was clean fill, and the area was then bulldozed so that warehouses could be constructed in the area. This filling and bulldozing changed the contour of the land from what it had been in the past. The Department contends that much of the sludge was spread out over an extended area of the site, and not removed to landfills. The evidence is persuasive that almost all of the sludge from the pits was removed to landfills. The testimony of Mr. Blair denying that the sludge was spread was credible. In addition, on-site spreading of the sludge would have been impracticable. As a tar-like substance, if spread out, it would have been tracked everywhere. It would stick to the tracks or wheels of any vehicles operating on the surface, and was so acidic it would burn or irritate the skin of anyone who came in contact with it. It would be extremely difficult to perform maintenance on equipment used to spread the sludge because of the need to clean the sludge off, so that the mechanic would not be burned. In addition, there are a large number of receipts evidencing the systematic hauling of the sludge to landfills. The logic of Mr. McDonnell's testimony is persuasive: If you have the alternate, which they obviously did, of hauling it away and simply dumping it, no one would go out and deliberately choose to do a very difficult job [spreading the sludge over the property] where there is an easy alternative available to them. (Tr. 285) Although the facility ceased its re-refining of lubricating oil in 1970, it continued to collect, process, and sell used oil as a fuel until 1984. About 150,000 gallons per month of used oil were processed and sold as fuel. The oil was typically crank case engine oil which contained the substances normally found in used oil of that type. There is no persuasive evidence that Petroleum Product Corporation ever received any hazardous waste, or mixed used oil with any hazardous waste. Used oil is not listed as a hazardous waste by the U.S. Environmental Protection Agency or by the Department. The used oil collected and recycled at Petroleum Product's facility was pumped into and stored in above-ground storage tanks. There were, over time, from 10 to 25 tanks, which ranged in size from 12,000 to 20,000 gallons. Normally, the facility stored between 400,000 and 500,000 gallons of used oil. Occasionally, the facility also received virgin oil, but it was processed quickly or sold because of its higher value. At the peak of its operation, the facility had 25 to 35 storage tanks. Recycling operations had slim profit margins and were small operations. Storage tanks, pumps, and other equipment were bought used, often from other businesses dealing in virgin petroleum products. That used equipment was often rusty or deteriorating. Tank bottoms could have holes in them as the result of rust from standing water; tanks were sometimes riveted, and would have side or bottom leaks. The tanks had virtually no overfill protection. When oil was pumped in, it would overflow from the top and run down the sides. Operators were typically not careful with the oil, because it had a very low value, about 2 to 5 cents a gallon. A spill of a few thousand gallons was regarded as an inconsequential matter. The pumps used in storing oil often had leaks in packing seals, or had screw joints which would leak. Tank valves, also usually bought as used equipment, were often installed without new stem packing, and also would leak during operation. Almost no preventive maintenance was done, because it was not cost-effective to do so. Equipment was repaired only if its current state of repair interfered with operations, which usually meant that leaks were not repaired until they created a fire hazard. Leaks and spills from used oil storage tanks, including their pumps, valves, and piping, were common. A great volume of used oil leaked or spilled from Petroleum Products Corporation's tanks, pumps, and piping over its 25 year operation. There were also large oil spills resulting from four or five major fires at the facility in the 1960s. The fire in 1963, which may have been the result of vandalism, caused 40,000 to 60,000 gallons of use oil to spill from storage tanks; 8 or 10 tanks were destroyed. There were no dikes, so that the oil flowed freely. When firemen used water on the fire, the oil was absorbed into the soil. Another major fire occurred in October, 1966 in which three oil storage tanks collapsed spilling about 50,000 gallons of oil. Another 25 foot high oil tank collapsed on a firetruck. There is no way to know, with certainty, the volume of used oil, virgin oil, and lubricating oil which spilled or leaked into the ground on the site. It is reasonable to believe that 9 to 12 gallons of oil would have leaked or spilled each day at the facility, which would have resulted in spill of over 100,000 gallons of oil. This estimate, made by Mr. McDonnell, is credible and is conservative, given the volume of oil also spilled during the fires. Petroleum Products Corporation does not contend that the leaks and spills from process tanks, rather than from storage tanks, are eligible for reimbursement of site assessment and cleanup costs. Oil leaked from both, however, and once in the ground, the oils are indistinguishable. Due to the capacity of the tanks and the years they were in use, however, it is reasonable to assume that 15% or less of the leaks and spills were attributable to process tanks. After processing, most of the oil was burned as fuel. Some was used as a lubricant. The only difference between used oil sold as fuel or lubricant was that the lubricating oil had the additives removed and the color changed. Both burn well. There is an insufficient basis in this record to justify the Department's interpretation excluding this site from eligibility for cleanup because oil processing ocurred at the site to produce lubricating oil. Section 376.3071 does not disqualify all or part of a site from eligibility for cleanup reimbursement because a portion of the used oil stored there was ultimately used as lubricants. In 1984 a Department investigator asked Petroleum Products Corporation to install exploratory wells to determine whether there was contamination at the site. Petroleum Products engaged the firm of Dames & Moore to undertake a preliminary investigation, which revealed that there was groundwater contamination in the form of floating hydrocarbons. On April 1, 1985, the United States Environmental Protection Agency and Petroleum Products Corporation entered into a consent order agreement which required the removal of 17 above-ground tanks leaking used oil into the ground, which constituted a continuing source of contamination. Petroleum Products Corporation contracted with Conversion Technology Corporation to recover and recycle the oil and wastes, with Waldron's tank cleaning services to clean the empty tanks and drum the sludge, with Cuyahoga Wrecking Service to make the tanks inoperable, and with Seven & Seven Transporters to remove the waste to a disposal facility. The employee of the U.S. Environmental Protection Agency who was in charge of the site commended Petroleum Products Corporation for its cleanup effort, and wrote as the OSC [on- scene coordinator] for this EPA-monitored cleanup I may say that [Petroleum Products Corporation] exemplified industrial cooperation and responsibility in combating the vexing problem of hazardous waste management. (Petitioner's Exhibit 9) Petroleum Products Corporation cooperated with the Environmental Protection Agency and with the Department in determining how to deal with the contamination. It has already spent approximately $150,000 to perform remedial action. Contamination at the site is of three types: oil floating in the groundwater, soil contamination, and groundwater contamination. It is not possible to clean any individual phase of the contamination without affecting the other phases. Attempts at remediation must be monitored to prevent an influx of organic contaminants into the aquifer. Similarly, the cost related to the cleanup of an individual phase of contamination cannot be isolated because of the inter-related nature of the cleanup phases. The creation of a cone of groundwater depression is necessary for any recovery of the free or floating oil. The cost of recovery of the free product cannot be separated from groundwater cleanup because it is necessary to treat large quantities of groundwater involved in creating a cone of depression. To the extent that a proportion of the cost might be estimated, the cost associated with the recovery of free product would be a minor portion of the overall cleanup. There is currently a free product recovery effort in place at the site, which is intended to prevent further migration of the product off-site. This ongoing action is not considered an element of the site cleanup. The most feasible method of cleanup for the free product will involve the excavation of the soils to create a trench. The free product and ground water will be recovered as they flow into the trench. During October and November of 1984, Environmental Science and Engineering, Inc., a consulting firm working under contract with the Department, assessed the extent of free floating oil in the groundwater under the Petroleum Product Corporation's site. Those consultants found a free floating layer of oil from 5" to 30" thick under approximately one-half of the one acre site Petitioner still owns. The free product generally mirrors the location of the former recycling facility and its storage tanks. The viscosity of the free product is comparable to about 40-weight engine oil. Environmental Science and Engineering estimates that the floating layer of oil contains 20,000 to 60,000 gallons of recoverable petroleum product. The direction of ground water flow and the migration of contaminants off-site is to the east or southeast. The soil above the oil layer has been saturated with oil because of the fluctuations of the layer with movement of the water table as the area experiences heavy rains or dry spells. Wells drilled in the location of the former sludge lagoons to the north and east of the plant site reveal a heavy slightly liquid type of sludge. The oil in the lagoon sites is immobile, and no free product collects in the wells after 24 hours. One sample collected in the mason jar shows a slight degree of oil separation after 24 hours. This anecdotal evidence of separation is not very informative, and is not persuasive that oil separates from the remaining sludge on-site. See, Finding 32, below. A second assessment of soil and groundwater contamination was done by another consulting firm under contract with the Department, Ecology and Environment, Inc. That study showed free floating product at the site. The only calculation of the amount of free floating oil was that done by Environmental Science and Engineering, Inc., see, Finding 29, estimating that there would be 20,000 to 60,000 gallons of recoverable oil. That calculation understates the amount of oil in the ground. The estimate given by George McDonnell of 103,000 gallons is more persuasive. It is consistent that the large amounts of oil which leaked or spilled at the site over a 25 year period. It is unlikely that any appreciable portion of the approximately 103,000 gallons of floating oil has its genesis in the separation of oil from the acid/clay sludge which had been disposed in the two lagoons for the following reasons: Oil associated with acid/sludge would be quite acidic, and have a pH between 2 and 4. The pH scale is not a linear scale, so differences in pH are quite dramatic as the pH values change. Samples of free product shows a uniform pH of approximately 6 or 7. In almost all 31 monitoring or observation wells the pH is consistent with the characteristics of used oil, (a pH of 6 or 7), not the pH of sludge (a pH of 2 to 4). The only sample which disclosed a low pH was that taken in monitoring well number 3 which was located in the former sludge lagoon site. The groundwater flows to the east or southeast. This does not explain the presence of free product to the west and southwest of the sludge pits nor the absence of free product to the east of the pits. The viscosity of the oil is similar to that of 40-weight engine oil and not highly viscous, as the tar-like sludge would be. The oil in the sludge pits is basically immobile and no free product surfaced in the monitoring well after waiting 24 hours. The pH of the free product is nearly neutral. The Department believes that the sludge was mixed with lime rock or fill and spread over the site to increase the pH of the oil. This is unpersuasive. Mixing with lime rock would increase the pH of the sludge (tend to bring it towards neutral) but it would not cause the dramatic lowering of acidity which would bring the sludge to a pH of 6 or 7. In addition, the viscosity of the sludge would not be so changed by mixing the sludge with fill that its viscosity would become similar to that of 40-weight engine oil. To believe that the free product results from sludge disposal rather than leaks ignores the normal operating practice of used oil recovery facilities in the late 50s and 60s where spills from storage tanks, pumps, and piping were very common. Little of the free product has been recovered through the current remediation efforts. If not recovered, over time the approximately 103,000 gallons of floating oil will spread to adjacent property. To recover this oil by conventional trench or well recovery operations will probably cost $250,000 or more. The capital cost of the groundwater recovery/discharge system, with monitoring wells, will be about $85,000; cost of operating and maintenance are approximately $180,000. The firm of Ecology & Environment, Inc., collected soil samples at 56 locations in two phases in its remedial investigation. Forty-six of the samples were taken at shallow depths (27 at 8 inches, 19 at approximately 10 inches); 10 more samples were taken in the old disposal pit sites at depths between 0 and 35 feet). The two primary classes of contaminants found in the soil were lead and organics (hydrocarbons associated with petroleum products). Both contaminants are found in used oil. The lead and organic contaminants were found in the shallow soils over the southern half of the site. Very little contamination was found beyond the main area of site activity. The soil contamination was concentrated in the plant and former disposal pit areas. Samples with high lead concentrations were found in the former disposal pit sites. Contamination extended to a depth of 25 feet in one soil sample from a former pit, where oily plastic sludge was found with fine sand or clay. The two former pit sites are the only places with documented contamination below a 10 foot depth. Although the organic contamination extended laterally further than the lead contamination, Environment & Ecology concluded that the wider distribution did not reflect contamination from Petroleum Product Corporation's activities. The general area has long been the site of commercial and industrial activities, and there are many other possible sources for contamination including a firing range, which would have been disposing of lead bullets fired at the range, a generator plant, and a former spray-painting facility. Solvents and other chemicals used in these activities would contribute to soil and groundwater contamination. The consultants had been told by area businesses that small scale dumping of industrial chemicals in the vicinity has been common. Soil samples revealed a "great deal of heterogeneity." There was no uniform distribution of soils in the shallow zone. This probably occurs because after the reprocessing operations ended in 1970, the land was cleared and filled, so that many of the warehouses now in the area could be constructed. Most of the upper 8 to 10 feet is fill material. The ground water was monitored by installing 38 wells on the site, most of which were screened at depths of 10 to 12 feet. Five intermediate wells with depths of 50 feet and two deep wells of 100 to 200 feet were also installed. Every sample exhibited a pH of between 6.4 and 7.4. The primary contaminants were lead, organics, and chromium. The evidence does not indicate the source of the chromium. It is unrelated to Petroleum Product Corporation's activities. The groundwater contamination, both metal and organic, was only in the shallow zone. It extends laterally roughly to the same extent of the shallow contamination found in the soil. This suggests that the contaminants in the soil migrated due to seepage from rainfall or fluctuation in the water table into the groundwater. The water table is about five feet below the land surface. The Department has argued that the contaminants in the soil and groundwater were caused by mixing and spreading of the sludge material during the early 1970s over the surface of the area. This hypothesis has already been rejected for the reason stated in Findings 7 and 8, above. It is more likely that the soil contamination resulted from frequent spills and leaks of oil from storage tanks years ago. The soil contaminants are those found in used oil. The area generally is flat. There was no impediment to oil spills flowing over a large surface area, following the contour of the land at that time. Depending on the method used to clean up the site, the cost of rehabilitating the area will range between two and forty-six million dollars. It will cost over one million dollars to recover and treat contaminated groundwater. Approximately 110,000 cubic yards of contaminated soil must be removed and treated, the majority of that coming from the area outside the former sludge pits. The presence of contamination at the site is to be expected, given the site's former use. All of the 8 turnpike facilities and 8 maintenance yards operated by the Florida Department of Transportation report petroleum contamination from tanks, and the Department of Transportation has estimated cleanup cost will range from $20 to $30 million, although DER believes the cost may be $5 million. The cleanup will be funded by the Inland Protection Trust Fund, as would the reimbursement in this case. The cost of rehabilitation is in the range of estimates that the Department has received for other petroleum contamination sites. In summary, the Petitioner's site is contaminated primarily from leak and spills of used and virgin oils processed or unprocessed and from storage tanks, pumps and integral piping. Small spills were continuous and some associated with fires were massive. The only portion of the site not contaminated due to leaks and spills is the residual soil and groundwater contamination from the sludge disposal pits, which is a small part of the overall contamination.
Recommendation Based upon the foregoing Findings of Fact and Conclusions of Law, it is RECOMMENDED that the application of Petroleum Products Corporation fo eligibility to participate in the cleanup program funded by the Inland Protection Trust Fund be granted. DONE and ENTERED this 9th day of July, 1990, at Tallahassee, Florida. WILLIAM R. DORSEY, JR. 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 9th day of July, 1990. APPENDIX Rulings on Findings of Fact proposed the Petitioner: As will be obvious, the proposed order submitted by Petroleum Products Corporation comported closely with the Hearing Officer's view of the evidence, and with some modification was essentially adopted as proposed. Adopted in Finding of Fact 3. Adopted in Finding of Fact 3. Adopted in Finding of Fact 4. Adopted in Finding of Fact 4. Adopted in Finding of Fact 5. Adopted in Finding of Fact 6. Adopted in Finding of Fact 6. Adopted in Findings of Fact 7 and 8. Adopted in Finding of Fact 8. Adopted in Findings of Fact 9 and 10. Adopted in Finding of Fact 10, to the extent necessary. Adopted in Finding of Fact 11. Adopted in Finding of Fact 12. Adopted in Finding of Fact 13. Adopted in Finding of Fact 14. Adopted in Finding of Fact 15. Generally adopted in Finding of Fact 16. Rejected as subordinate. Rejected as unnecessary and subordinate. Adopted in Finding of Fact 17. Adopted in Finding of Fact 18. Adopted in Finding of Fact 19. Adopted in Finding of Fact 20. Generally adopted in Finding of Fact 21. Adopted in Finding of Fact 22. Adopted in Finding of Fact 23. Adopted in Finding of Fact 24. Adopted in Finding of Fact 24. Adopted in Finding of Fact 24. Adopted in Finding of Fact 28. Adopted in Finding of Fact 29. Adopted in Finding of Fact 30. Adopted in Finding of Fact 31. Adopted in Findings of Fact 31 and 32. Adopted in Finding of Fact 33 Rejected as repetitious of Finding of Fact 6. Rejected, see Findings of Fact 25 and 26. Adopted in Finding of Fact 24. Adopted in Finding of Fact 34. Adopted in Finding of Fact 35. Adopted in Finding of Fact 36. Adopted in Finding of Fact 37. Adopted in Finding of Fact 38. Adopted in Finding of Fact 39. Adopted in Finding of Fact 40. Adopted in Finding of Fact 41. The spreading theory is rejected in Findings of Fact 7 and 8. Rejected as unnecessary. Adopted in Finding of Fact 42. Adopted in Finding of Fact 42. See also the stipulation of the parties entered as Exhibit 22. Rejected as unnecessary. Rulings on Findings of Fact proposed by the Department. Adopted in Finding of Fact 1. Adopted as modified in Finding of Fact 2. Discussed in the Conclusions of Law, see page 20. Adopted in Finding of Fact 3. Adopted in Finding of Fact 3. Implicit in Findings of Fact 3 and 6. Adopted in Finding of Fact 6. Adopted in Finding of Fact 5. Adopted in Finding of Fact 4. Adopted in Finding of Fact 4. Rejected as unsupported by the transcript references given. Adopted in Finding of Fact 5. Adopted in Finding of Fact 5. Adopted in Finding of Fact 5 Rejected as unnecessary. Generally rejected; see Finding of Fact 6 concerning the filling of the disposal pits. While some pockets of sludge remain at the site of the pits, the volume is difficult to determine. In an absolute sense, those pockets may contain a substantial amount of sludge, but on a comparative basis, by far the greatest part of the sludge was removed. Rejected as unnecessary. Generally adopted in Finding of Fact 32(1), but see the final sentence of (1). Generally adopted in Findings of Fact 25, 28, and 34. Generally adopted in Finding of Fact 28, since the recycling facility and storage tanks were on the southern part of the property. Rejected as unnecessary. Adopted in Finding of Fact 26. Adopted in Finding of Fact 26. Adopted in Finding of Fact 3. Implicit in Finding of Fact 11. Adopted in Finding of Fact 11. Adopted in Finding of Fact 4. Rejected because the process tanks necessarily store the product being processed, serving as a vessel to contain the product. Rejected, see Finding of Fact 3 with respect to the turnover in the volume of used oil processed at the facility. Only about 10 percent of the oil was reprocessed as lubricating oil. This is more significant than the volume of the tanks. See also Tr. 24 with respect to the storage capacity, and Finding of Fact 11. Rejected as unnecessary. Rejected because the surficial drainage has probably been changed by the filling and regrading of the property in preparation for building the warehouses. See Finding of Fact 6. The current surficial flow says little about the flow when the facility operated in the late 1950's and throughout the 1960's. Adopted in Findings of Fact 15 through 19. Adopted in Findings of Fact 17 and 18. Adopted in Finding of Fact 17. Generally rejected, the evidence is persuasive that about 50,000 gallons of oil were lost in the 1966 fire. (See Tr. 36-37.) Adopted in Finding of Fact 25. Adopted in Finding of Fact 26. Adopted in Finding of Fact 26. Adopted in Finding of Fact 26. Adopted in Finding of Fact 27. Adopted in Finding of Fact 27. Rejected as unnecessary. Adopted in Finding of Fact 27. Adopted in Finding of Fact 27. Adopted in Finding of Fact 27. Adopted in Finding of Fact 27. Adopted in Finding of Fact 27. Rejected, the free product covers approximately one-half acre. Rejected, the more persuasive evidence is the 103,000 gallons estimated by Mr. McDonnell. See Finding of Fact 31. Rejected as unnecessary. Rejected as unnecessary. See Findings of Fact 28 and 34. Rejected because it is unlikely that sludges are separating in the former sludge lagoon. See Finding of Fact 30. The source of the oil is more likely the substantial loss of oil which occurred from the fires and from leaks over the years which is now floating above the ground water. Generally adopted in Finding of Fact 28. Generally adopted in Finding of Fact 28. Rejected as unpersuasive. Rejected, the source of the free product is not leaching from the disposal pit, but the oil from over flows and leaks during operation as well as large inundations during fires. Adopted in Finding of Fact 4. Adopted in Finding of Fact 4. Adopted in Finding of Fact 4. Rejected, see Finding of Fact 30. Rejected because oil does not separate from the sludge. Rejected for the reason given for rejecting Finding of Fact 63. Rejected, the seepage is not the result of separation in the disposal pits, but from the plume of free product in the ground above the ground water. Rejected as unnecessary, but the similarity of the oil seeping from the sludge pit area to waste oil is consistent with its source as leaks and spills inicident to fires. Rejected because the sludge does not separate. Rejected because the sludge does not separate. Rejected because the sludge does not separate, see Finding of Fact 30. Rejected as unnecessary; obviously as there is no more storage, so there is no more source for leaks or spills. 71-73. Discussed in Finding of Fact 30. Rejected because liquid product will not accumulate. Rejected because the sludge does not separate. Adopted in Finding of Fact 32(1). Adopted in Finding of Fact 32(5). Adopted in Finding of Fact 32(1). Rejected for the reason stated in Finding of Fact 32(5). Rejected for the reason stated in Finding of Fact 32(5). Rejected as unnecessary and for the reason stated in Finding of Fact 32(5). Adopted in Finding of Fact 32(1), which is consistent with the source of the free product being used oil rather than separation from sludge remaining onsite. 83-84. Rejected as unnecessary. Rejected as unnecessary. Rejected because the testimony of Mr. McDonnell has been accepted. Rejected as unnecessary. Adopted in Finding of Fact 27. Rejected as redundant. Adopted in Finding of Fact 34. Adopted in Finding of Fact 34. Implicit in the finding that lead is a contaminant found in used oil. See Finding of Fact 34. Adopted in Finding of Fact 4. Rejected as unnecessary. Generally adopted in Finding of Fact 34. Generally adopted in Finding of Fact 34. Adopted in Finding of Fact 35. Rejected as unnecessary. Rejected as unnecessary; see also, Finding of Fact 6. Adopted in Finding of Fact 32(1). Rejected as unnecessary. Rejected as unnecessary. Rejected as unnecessary, although there were disposal pits in the north and eastern parts of the property. Adopted in Finding of Fact 34 with respect to location, but the testimony with respect to spreading of the sludge is rejected. See Finding of Fact 7. It is unlikely that sludge was spread over the site. The more likely explanation for the appearance of sludge in the lithologic logs for the southern end of the site is that the disposal lagoons periodically overflowed after heavy rains and provided a mechanism for the active transport of sludge out of the disposal pits into some areas on the southern end of the site. Apparently the northern area now occupied by the warehouses was higher, because no sludge was found in observation wells 4, 5 and 19. Rejected, page 41 of DER's Exhibit 3 shows no sludge at observation well 5, which the proposed finding implies. 107-112. Generally rejected because the testimony with respect to the surface flow from the tank area being to the south is rejected because the grading of the property as the warehouses were built likely changed the contour of the land. Mr. Levin's testimony was not particularly strong; for example, at page 25 of his prefiled direct testimony he states, "And for the shallow soil contamination I would still have to lean towards the fact that the materials were mixed and spread." 113-114. The sludge contamination is not the predominant or source of contamination. Rather, it is the oils which floated across the land and were carried into the soil and resulted from the leaks and spills. 115-120. Generally accepted in Finding of Fact 36, although subordinate to that finding. 121. Generally accepted, although the soil contamination by lead is attributable to leaks and spills from the used oil. 122-124. Rejected as unnecessary. Accepted in Finding of Fact 25. Accepted in Finding of Fact 38. 127-128. Subordinate to Findings of Fact 36, especially the last sentence, and 38. Subordinate to Finding of Fact 39. Subordinate to Finding of Fact 39, especially the last sentence. Rejected as unnecessary. 132-134. Accepted in Finding of Fact 39. 135. Rejected because the soil contamination is the result of leaks and spills of oil. 136-137. Rejected, it is more likely that the neutral pH of the ground water is the result of the essentially neutral contaminant, the used oil. Rejected as unnecessary. Rejected as unnecessary, although consistent with Finding of Fact 39 that the lateral extent of ground water contamination mirrors the soil contamination which has resulted from leaks and spills. 140-141. The predominant source of contamination is leaks and spills. 142. Rejected, the area affected by the leaks and spills is large, due especially to the fires and consequent loss of large amounts of oil from tanks. See Finding of Fact 41. 143-144. Rejected as irrelevant and unnecessary. 145. Although true, not relevant. 146-148. Rejected, whether the Environmental Protection Agency is correct or not in its assessment is not at issue here. This site was contaminated by used oil. 149-150. Although true, not relevant. Implicitly accepted in that no finding with respect to "bias" has been made. Rejected as legal argument. Rejected because the predominate source of contamination is an eligible source. Rejected, but the source here falls within the statutory directive. Rejected. The site here is predominantly contaminated by used oil, which is eligible. The eligible portion is not a minor part of the entire of the contamination. COPIES FURNISHED: R. L. Caleen, Jr., Esquire OERTEL, HOFFMAN, FERNANDEZ & COLE Post Office Box 6507 Tallahassee, Florida 32314-6507 Gary Early, Esquire Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Dale H. Twachtmann, Secretary Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 Daniel H. Thompson, General Counsel Department of Environmental Regulation Twin Towers Office Building 2600 Blair Stone Road Tallahassee, Florida 32399-2400 =================================================================
The Issue The issues to be determined in this case are whether Respondents should pay the administrative penalty, investigative costs, and attorney’s fees and undertake the corrective actions that are demanded by the Florida Department of Environmental Protection (the “Department”) as set forth in the Final Amended Notice of Violation, Orders for Corrective Action, and Administrative Penalty Assessment.
Findings Of Fact The Parties The Department is the administrative agency of the state of Florida having the power and duty to protect Florida’s air and water resources and to administer and enforce the provisions of chapters 376 and 403, Florida Statutes, and the rules promulgated thereunder in Florida Administrative Code Title 62. Germain is a licensed Florida attorney. From May 2006 to January 2013, Germain was the record owner of the real property at 1120 West Main Street, Leesburg, Lake County, Florida (the “Germain property”). Leesburg’s is an active Florida corporation that was incorporated in January 2013 by Germain. Germain is Leesburg’s sole corporate officer and sole shareholder and has managerial authority over the Germain property. John Doe 1-5 is a placeholder designation used by the Department for the purpose of covering all potential entities to which Germain might transfer the property. No other such entity materialized. Background A gas station was operated on the Germain property continually from the 1920s through the late 1980s. During the 1980s and perhaps for a longer period, C.E. Griner operated the gas station under the name Griner’s Service Station. Griner’s Service Station had at least three underground storage tanks (“USTs”) used to store leaded and unleaded gasoline. In 1989 or 1990, Griner ceased operation of the gas station and the USTs were filled with concrete and abandoned in place. The Germain property has not been used as a gas station since that time. In 1990, the Department inspected the Germain property and prepared a report. The inspection report noted that the USTs at the Germain property “were not cleaned properly prior to filling with concrete.” The report also noted that the tanks were not properly abandoned in place. No evidence was presented to explain in what way the tanks were not properly abandoned, or to indicate whether the Department took any enforcement action based on this report. In 1996, Gustavo Garcia purchased the Germain property from Griner. In May 2006, Germain purchased the property from Garcia. Another gas station, operating for many years under several names (now “Sunoco”), is located at 1200 West Main Street, across a side street and west of the Germain property. Since 1990, one or more discharges of petroleum contaminants occurred on the Sunoco property. There were also gas stations at the other two corners of the Main Street intersection, but no evidence was presented about their operations or conditions. In March 2003, apparently as part of a pre-purchase investigation, testing was conducted at the Sunoco property that revealed petroleum contamination in the groundwater. Soil contamination was not reported. S&ME, Inc. (“S&ME”), an environmental consulting firm, subsequently submitted a discharge report to the Department’s Central District Office in Orlando. Later in 2003, S&ME conducted an initial site assessment for the Sunoco property. In the report it produced, S&ME noted that it found concentrations of petroleum contaminants in the groundwater that were above the Department’s Groundwater Cleanup Target Levels (“GCTLs”). The concentrations exceeding GCTLs were in samples taken from the eastern side of the Sunoco property, closest to the Germain property. In 2004, S&ME completed a Templated Site Assessment Report for the Sunoco property. Groundwater samples from the eastern portion of the Sunoco property again revealed petroleum contamination exceeding GCTLs. Garcia, who owned the Germain property at the time, allowed S&ME to conduct soil testing on the Germain property. The soil samples were taken by direct push methods and were tested with an organic vapor analyzer (“OVA”), which revealed toluene, ethylbenzene, total xylenes, naphthalene, 1-methyl naphthalene, and total recoverable petroleum hydrocarbons exceeding the Department’s Soil Cleanup Target Levels (“SCTLs”). In 2005, another private environmental consulting firm, ATC Associates, Inc. (“ATC”), performed a Supplemental Site Assessment on the Sunoco property and produced a report. As part of its assessment, ATC installed three monitoring wells on the Germain property and collected groundwater samples. These groundwater samples revealed petroleum constituent concentrations that exceeded GCTLs and were higher than concentrations found in groundwater samples taken under the Sunoco property. Both the 2004 and 2005 site assessment reports concluded that the groundwater in the area flowed from the southeast to the northwest; that is, from the Germain property toward the Sunoco property. Germain referred to a figure in S&ME’s 2004 report that he claimed indicated a southeasterly flow of groundwater from Sunoco toward the Germain property. However, a preponderance of the evidence establishes that groundwater flow in the area is generally northwesterly from the Germain property toward the Sunoco property. Based on the results of its testing, ATC concluded in its site assessment report that the groundwater contamination on the eastern portion of the Sunoco property had migrated from the Germain property. ATC also took soil samples from the Germain property. It screened the soil samples with an OVA and reported petroleum contamination exceeding the Department’s SCTLs. Petroleum contamination in soil typically does not travel far horizontally. It remains in the vicinity of the source. Therefore, the soil contamination found on the Germain property indicates an onsite source of the contamination. All of the assessment reports were filed with Seminole County, presumably with the Department of Public Safety, Emergency Management Division, which is the local entity with which the Department contracted to inspect and manage petroleum facilities in the area. These reports were public records before Germain purchased his property. A June 2005 Memorandum from Seminole County informed Bret LeRoux at the Department’s Central District Office that ATC’s 2005 site assessment report indicated the Germain property was the source of petroleum contamination. The Memorandum recommended that the Department contact the owner of the property about the contamination. The Memorandum was filed at the Department. After the Department received the Memorandum, it requested and received the site assessment reports from Seminole County. The Department did not notify Garcia or the public about the contamination in 2005. The Department did not notify Germain about the contamination until August 2007. All Appropriate Inquiry The principal factual dispute in this case is whether Germain undertook “all appropriate inquiry into the previous ownership and use of” the Germain property before purchasing it, as required by section 376.308(1)(c)1/: [A person acquiring title to petroleum- contaminated property after July 1992] must also establish by a preponderance of the evidence that he or she undertook, at the time of acquisition, all appropriate inquiry into the previous ownership and use of the property consistent with good commercial or customary practice in an effort to minimize liability. Before he purchased the Germain property in 2006, Germain knew that it had been a gas station for a number of years. Garcia told Germain that the USTs had been filled with concrete and were “within the law.” Germain was also aware that the Sunoco USTs had recently been excavated and that there was a problem with the tanks and possible contamination there. Germain said he spoke with neighbors about the property, but he did not say what he learned from them. Before the purchase, Germain conducted a visual inspection of the property and saw “several little metal plates” in the parking lot. Germain claimed it was only later that he learned that some of the plates were covers for groundwater monitoring wells. Germain said he visited and reviewed files at a Lake County office, but he was not specific about which county offices he visited. He also went to the Leesburg Historic Board to review property records. Germain’s testimony was not clear about what records he saw on these visits. Germain did not go to the office of the Seminole County Department of Public Safety, Emergency Management Division, to view records pertaining to the Germain property. He did not claim to have gone to the Department’s Central District Office in Orlando. In other words, Germain did not go to the offices of the agencies responsible for regulating petroleum USTs. Nor did Germain say that he talked to any knowledgeable employee of these agencies by telephone about possible contamination issues on the Germain property. While at a Lake County office, Germain searched the DEP website and saw two documents that indicated the USTs on the Germain property had been closed in place. One of the documents indicated a cleanup status of “no contamination.” Germain claimed that he relied on these documents to conclude that the property was clean. The Department explained that the phrase “no contamination” is used in its database as a default where no contamination has been reported and no discharge form has been filed. It is not a determination based on a site investigation that the site is free of contamination. However, the Department had received information that the Germain property was contaminated, so its explanation of the “no contamination” status for the Germain property was unsatisfactory. Germain does not practice environmental law. He neither claimed nor demonstrated knowledge or experience with the legal or factual issues associated with petroleum contamination. Germain did not present evidence to establish that he followed “good commercial or customary practice” in his investigation of the property as required by section 376.308(1)(c). Good commercial practice in the purchase of property upon which potentially contaminating activities have occurred entails consultation with a person with appropriate knowledge and experience. Germain did not consult with an environmental attorney or environmental consultant regarding the potential liability associated with property used as a gas station. If Germain had hired an environmental consultant to assist him, the consultant would have known where to find public records about the gas station, including any soil and groundwater analyses. An environmental consultant would have seen the site assessment reports and other public records that indicated petroleum contamination on the Germain property. A consultant would likely have recommended a Phase I environmental site assessment (“ESA”). A Phase I ESA entails, generally, determining past uses of a property, inspecting the property for visible indications of potential contamination, and reviewing aerial photographs, historical documents, and public records related to the property and its surroundings. A Phase II ESA would follow if potential contamination is discovered and usually includes taking soil and groundwater samples. In considering whether all appropriate inquiry was undertaken by a purchaser of contaminated property, section 376.308(1)(c) directs the court or administrative law judge to take into account: any specialized knowledge or experience on the part of the defendant, the relationship of the purchase price to the value of the property if uncontaminated, commonly known or reasonably ascertainable information about the property, the obviousness of the presence or likely presence of contamination at the property, and the ability to detect such contamination by appropriate inspection. Germain did not have specialized knowledge regarding the regulation of petroleum USTs. However, as a lawyer, he was familiar with the practice of employing or working with professionals with specialized knowledge in order to achieve the objectives or solve the problems of his clients. If Germain’s legal assistance had been sought by a client to solve an environmental problem, Germain would have declined to proceed because he did not possess the requisite knowledge or he would have sought the assistance of an environmental lawyer or environmental consultant. In purchasing the Germain property, Germain did not undertake the reasonable steps a lawyer must take for a client. No evidence was presented about the relationship of the purchase price to the value of the Germain property. Germain did not show that the site assessment reports and other documents discussed above were not “reasonably ascertainable information.” Although a visual inspection by a lay person would not have disclosed the presence of contamination at the property, an environmental consultant would have recognized the groundwater monitor wells and would have known to seek information about the reason for their installation and the groundwater sampling results. Taking all relevant considerations into account, Germain failed to show that he made all appropriate inquiry before he purchased the Germain property. Germain transferred the property to Leesburg’s in January 2013 in part to limit his potential personal liability for petroleum contamination. The Germain property is Leesburg’s primary asset. Because Leesburg’s took title to the Germain property after the NOV was issued, it had full knowledge of the contamination and cannot claim to be an innocent purchaser. Post-Purchase Investigation In August 2007, the Department sent Germain a letter informing him that the Department had reason to believe his property was contaminated with petroleum and requiring him to conduct a site assessment pursuant to rule 62-770.600(1).2/ In September 2007, the Department sent Germain the 2004 and 2005 site assessment reports. Germain did not conduct a site assessment. At the final hearing, the Department did not state whether it had made any effort to take enforcement action against Griner, whom the record evidence indicates was the owner of the gas station when the discharge occurred. In 2012, the Department issued Germain a notice of violation for failing to conduct a site assessment and remediation. After Germain transferred the property to Leesburg’s, the Department issued the Final NOV to add Leesburg’s as a Respondent. The Final NOV seeks penalties of $10,000 against Germain, and $10,000 against Leesburg’s. While investigating this matter, the Department incurred expenses of $11,380.37 in investigative costs. Confirmation of On-site Contamination Despite the site assessment reports that documented contamination on the Germain property, Germain disputed the Department’s claim that the property was contaminated. The Department conducted testing and completed a Site Investigation Report in 2010. Because Germain would not allow the Department onto his property, the Department installed groundwater monitoring wells adjacent to the Germain property to the west and south, and collected groundwater samples. The Department confirmed the northwesterly flow of groundwater documented in previous reports and found elevated levels of petroleum contaminants above GCTLs, including benzene, ethylbenzene, toluene, xylene, total lead, EDB, and total recoverable petroleum hydrocarbons. Monitoring wells west of, or downgradient of, the Germain property showed high levels of groundwater contamination, while monitoring wells to the south and southeast, or upgradient of the property showed no signs of contamination, indicating that the source of the groundwater contamination was on the Germain property. Based on the site assessments and its own investigation, the Department determined that the Germain property is the source of petroleum contamination detected along the eastern portion of the Sunoco property. Germain and Leesburg’s did not present any expert testimony to support their claim that the Germain property is not contaminated or that the contamination migrated to the Germain property from offsite. A preponderance of the record evidence shows that the Germain property is the source of the petroleum contamination found in the onsite soil and groundwater, as well as in groundwater on the eastern portion of the Sunoco property.
The Issue Whether Petitioner, Hendry Energy Services, LLC (“Hendry Energy”), is entitled to issuance of an operating permit recertification of the Red Cattle Co. #27-4 well, and an Oil and Gas Drilling Permit, Permit No. OG 0904AH.
Findings Of Fact Parties Hendry Energy is a Florida Limited Liability Company organized under the laws of the State of Florida. At all relevant times, Hendry Energy could lawfully conduct business in the State of Florida. The Department is the state agency with the authority under chapter 377, part I, Florida Statutes, to issue permits for the drilling for, exploring for, or production of oil, gas or other petroleum products which are to be extracted from below the surface of the land. Background Regarding the Mid-Felda Oil Field The Mid-Felda Field is an established oil field in Hendry County, Florida, discovered in 1977. The Mid-Felda Field generally exists within Sections 22, 23, 26, 27, 34, and 35 of Township 45 South, Range 28 East. The Mid-Felda Field includes three historically producing wells: RCC 27-4 (Permit No. 904), Red Cattle #27-1 (Permit No. 983), and Turner #26-3 (Permit No. 949). The RCC 27-4 was originally drilled and completed in 1977; the Turner #26-3 (“Turner 26-3”) was drilled and completed in 1979; and the Red Cattle #27-1 (“RC 27-1”) was drilled and completed in 1979. All three wells were vertical completions, meaning that the wellbore is vertical or nearly vertical from the surface- hole to the bottom-hole location. All three wells are located in routine drilling units. Routine drilling units are based on the U.S. Government Surveyed Township and Range system. The RCC 27-4 routine unit consists of the southeast quarter section of Section 27, Township 45 South, Range 28 East. The Turner 26-3 routine unit consists of the southwest quarter section of Section 26, Township 45 South, Range 28 East. The RCC 27-1 routine unit consists of the northeast quarter section of Section 27, Township 45 South, Range 28 East. RCC 27-4 is located approximately in the center of the southeast quarter section of Section 27. The true vertical depth of RCC 27-4 is approximately 11,686 feet. Turner 26-3 is located approximately in the center of the southwest quarter section of Section 26. The true vertical depth of Turner 26-3 is approximately 11,518 feet. Between 1978 and 2000, wells in the Mid-Felda Field produced nearly 1,500,000 barrels of oil. The RCC 27-4 and Turner 26-3 produced approximately 700,000 barrels each. The RCC 27-1 and Turner 26-3 have been plugged and abandoned. The RCC 27-4 has been temporarily abandoned with a plug installed. Facts Regarding Geophysical and Geological Data Supporting the Proposed New Bottom-Hole Location In 2013, Hendry Energy began engaging in production curve analysis of the existing wells in the Mid-Felda Field, conducted subsurface geological mapping of the Mid-Felda Field, and performed a 3D seismic survey of the Mid-Felda Field. Mr. Whitaker, a petroleum engineer, analyzed the historic production of the Mid-Felda Field, specifically production from the RCC 27-4 and the Turner 26-3 wells. This analysis was to determine whether there is additional recoverable oil that can be exploited from the Mid-Felda Field. Mr. Whitaker charted the field performance data as a graph of the production rate over time and the cumulative production versus the water to oil ratio. Using this analysis, he was able to determine that economically recoverable oil reserves likely remain in the Mid-Felda Field. Petroleum geologist Barry Falkner analyzed the subsurface geological data and developed reservoir maps for the Lower Sunniland C reservoir in the Mid-Felda Field. These maps depict the Top of Porosity, Average Permeability, and the Net Oil Pay Isopach, collectively describing the reservoir quality. Mr. Falkner also developed structural cross sections of the underground structure, on a north-south and east-west direction in the Mid-Felda Field. A 3D seismic study was conducted and analyzed by Charles Morrison, a petroleum geophysicist. The subsurface geological and geophysical seismic data revealed a structural high point at approximately 11,340 feet to 11,400 feet below ground level located on the section line between the southwest quarter of Section 26 (i.e., the routine drilling unit for the Turner 26-3 well, which was a producer) and the southeast quarter of Section 27 (i.e., the routine drilling unit for the RCC 27-4 well, which was a producer). RCC 27-4 and Turner 26-3 were drilled to depths of 11,686 feet and 11,518 feet respectively. These completion depths are both below the identified structural high point. As oil is produced, the water level in and around the well rises resulting in more water being produced and an increasing water-to-oil ratio. This phenomenon occurred in both RCC 27-4 and Turner 26-3 with the result that these wells are no longer economically productive. Accordingly, these two wells cannot extract oil reserves that may be present in the structure above their completion depths. A high point in the reservoir structure indicates a location where the presence of oil is likely. The geological and geophysical data indicate that the identified high point and point of thickness in the Sunniland C structure is a “closed contour,” which also indicates a trap of oil in the reservoir. The oil located at the top of a reservoir structure and above the completion depths of adjacent wells is also known as “attic oil.” Furthermore, a review of the subsurface geological data revealed a point of thickness in the reservoir structure as depicted on the map of the seismic data presented with net pay isopach for the Sunniland C structure. With the combined analysis of the field performance, the geophysical seismic interpretations, and the geological data, Hendry Energy identified the location of an optimal point in the subsurface structure from which Hendry Energy believes it can produce the most oil economically. This optimal point is located on the section line between the south halves of Section 26 and Section 27, between the existing RCC 27-4 and Turner 26-3 wells. Proposal to Reenter and Redrill Existing RCC 27-4 and Establish New Nonroutine Unit Based on the optimal extraction point identified through Hendry Energy’s geophysical and geological analysis of the Mid-Felda Field, Hendry Energy proposed to establish a new, nonroutine unit (consisting of the eastern half of the southeast quarter of Section 27 and the western half of the southwest quarter of Section 26), reenter the existing RCC 27-4 well, and drill a new horizontal well to the identified target bottom-hole location. Mr. Hancer, director of Hendry Petroleum, the parent company to Hendry Energy, testified that “[a]s a result of the studies that [Hendry Energy] conducted, the 3D seismic survey and the subsurface mapping and the production curve analysis, we discovered a structure that straddles the section lines between Sections 27 and 26, and we requested the establishment of a new drilling unit in order to be able to drill to that optimal bottom-hole location. And this application [Joint Exhibit 2] is a request for approval of that well.” The optimal target bottom-hole location cannot be reached by a routine, or statutory, drilling unit because of the setback requirements from section lines applicable to the bottom-hole location in routine units. See Fla. Admin. Code R. 62C-26.004(4)(a). However, establishing a nonroutine unit would allow Hendry Energy to access the target bottom-hole location. The proposed nonroutine unit is necessary to produce the “attic oil” that may exist at the proposed bottom-hole location. The identified optimal bottom-hole location is located approximately at the center of the proposed nonroutine unit, as required by section 377.25(3). Facts Regarding the Need to Horizontally Complete a New Bore to Access the Remaining Reserves from the Subsurface Structure To recover the remaining attic oil, Hendry Energy must hit a bottom-hole location at the top of the identified structure. A horizontal entry and a lateral completion of the well are required to economically drain the remaining attic oil reserves identified at this location in the Mid-Felda Field. The surface-hole location of the existing RCC 27-4 well is the optimal surface entry point to achieve a horizontal and lateral completion in the target bottom-hole location. Mr. Whitaker testified that “27-4 offers several different advantages, and we looked at this real closely, because, again, we’re all into – part of the exploitation effort is efficiency and that means capital efficiency and recovery efficiency. . . . And when you look at the geometry of where the wells sit and with the desired completion method, with the entry angle and then the lateral, 27-4 became the optimal point.” Facts Regarding the Drilling Application On April 12, 2016, Hendry Energy submitted an application for a permit to establish a new, nonroutine unit and drill a new horizontal well in the Mid-Felda Field in Hendry County, Florida (File No. 0904AH; PA No. 304674). By stipulation, except for the issue of preventing waste, the parties agree that Hendry Energy’s Oil and Gas Drilling Permit Application satisfies the criteria of chapter 377 and chapters 62C-26 through 62C-30, with regards to drilling a new oil well. Facts Regarding the Establishment of a Nonroutine Unit and the Prevention of Waste Rule 62C-26.004(6) provides: “The Department may grant drilling permits within shorter distances to adjacent drilling unit boundaries or on different drilling units than those prescribed in this rule whenever the Department determines that such steps are necessary to protect correlative rights or to prevent waste.” The terms “waste” and “physical waste” are statutorily defined as: The inefficient, excessive, or improper use or dissipation of reservoir energy; and the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or wells in a manner that results, or tends to result, in reducing the quantity of oil or gas ultimately to be stored or recovered from any pool in this state. The inefficient storing of oil; and the locating, spacing, drilling, equipping, operating, or producing of any oil or gas well or wells in a manner that causes, or tends to cause, unnecessary or excessive surface loss or destruction of oil or gas. The producing of oil or gas in a manner that causes unnecessary water channeling or coning. The operation of any oil well or wells with an inefficient gas-oil ratio. The drowning with water of any stratum or part thereof capable of producing oil or gas. The underground waste, however caused and whether or not defined. The creation of unnecessary fire hazards. The escape into the open air, from a well producing both oil and gas, of gas in excess of the amount that is necessary in the efficient drilling or operation of the well. The use of gas for the manufacture of carbon black. Permitting gas produced from a gas well to escape into the air. The abuse of the correlative rights and opportunities of each owner of oil and gas in a common reservoir due to nonuniform, disproportionate, and unratable withdrawals, causing undue drainage between tracts of land. § 377.19(31), Fla. Stat. The paragraphs of the definition specifically at issue were paragraphs (b), (f), and (k). Hendry Energy performed extensive geophysical and geological due diligence in the Mid-Felda Field to identify and assess the likelihood of finding producible quantities of oil in the field. As a result, Hendry Energy identified an optimal location in the subsurface structure of the Mid-Felda Field for exploiting oil reserves remaining in the field. This optimal target straddles the Section 26 and 27, Township 45 South, Range 28 East, section lines. Hendry Energy’s oil and gas drilling application proposes the establishment of a nonroutine drilling unit, consisting of 160 acres straddling Section 26 and 27. This proposed drilling unit consists of portions of two existing routine drilling units and wells, the RCC 27-4 and the Turner 26-3. Both wells previously produced oil in economic quantities until they were no longer economically viable. Hendry Energy’s application locates the nonroutine unit and the proposed bottom-hole at the optimal location for extracting any remaining oil. This is verified by the geophysical and geological analysis conducted. This target bottom-hole cannot be accessed from a routine drilling unit. As stated by Michael Whitaker, Hendry Energy’s expert in petroleum engineering, “[T]he statutory units as they exist today, even if we wanted to reactivate them, just physically don’t permit us to reach the target.” The drilling permit application proposes using existing surface infrastructure of the RCC 27-4 well. Using the existing surface-hole location and surface infrastructure of the RCC 27-4 well is the most efficient manner of draining the remaining reserves. The existing RCC 27-4 surface-hole is in the optimal location and provides the proper geometry for a lateral completion in the target bottom-hole. Not allowing the target bottom-hole location or attempting to drain the target point from another surface location would reduce the quantity of oil ultimately recovered and leave underground waste. Specifically, failure to authorize the permit for the well as proposed by Hendry Energy will prevent recovering the oil and thus leaving the oil underground without benefit to Hendry Energy or the mineral owners and other stakeholders. Mr. Hancer testified that a horizontal completion of the well allows the operator to more efficiently reach and drain oil from the underground structure. This increases the ultimate recovery and minimizes underground waste. Increased recovery equates to increased royalty payments. The remaining reserves are contained in an area that lies across the section lines of Section 26 and 27. The proposed nonroutine unit also lies across the section lines of Section 26 and 27. This proposed unit allows for a proportionate production of oil and therefore protects correlative rights. The proposed horizontal completion penetrates the structure in a way that encompasses portions of both Section 26 and 27, and therefore implicates the mineral owners in both sections. The proposed well will be draining the minerals of both parties, and thus paying royalties to both parties, creating a fair and equitable arrangement. Over 90 percent of the mineral rights in the proposed unit have been leased to Hendry Energy, evidencing the mineral owners’ desire to drain the reserves in the nonroutine unit. The greater weight of evidence supports that the nonroutine unit is necessary to prevent waste.
The Issue The issues in these consolidated cases are whether Coastal Petroleum Company is entitled to an oil and gas exploration permit (Permit no. 1281) and, if so, what conditions should attach, including a reasonable surety amount.
Findings Of Fact Parties The applicant Coastal Petroleum Company, (Coastal) is an oil and gas company originally named Arnold Oil Exploration Company, formed in 1941 as a Florida corporation. Its majority owner is Coastal Caribbean Oils and Minerals, Ltd., a company publicly traded on the Boston Stock Exchange. Phillip Ware is president of Coastal, having been elected to that position in 1985. The Department of Environmental Protection (DEP) is the agency of the state responsible for implementing laws and regulations governing oil and gas permits. DEP was created pursuant to Section 20.255, Florida Statutes, as the successor agency to the Florida Department of Environmental Regulation and Department of Natural Resources. The Environmental Petitioners are the Florida Wildlife Federation, Inc., Sierra Club, Florida Chapter, and Florida Audubon Society, Inc. Florida Wildlife Federation and Florida Audubon Society are non-profit Florida corporations and citizens of the state. The St. George Island Civic Club is an organization formed by and on behalf of property owners and residents of St. George Island, Franklin County, Florida. The Administration Commission is a collegial body composed of the Governor and Cabinet of the State of Florida, pursuant to Section 14.202, Florida Statutes. The Attorney General of the State of Florida has intervened in this proceeding pursuant to Section 403.412(5), Florida Statutes. The Attorney General, Environmental Petitioners and St. George Island Civic Club oppose the grant of Permit no. 1281 to Coastal and support a surety requirement in at least the amount established by the Administration Commission on the recommendation by DEP. (DOAH Cases Nos. 96-4222 and 96-5038.) Coastal supports the intended grant of its permit except for certain conditions which it claims are without authority; Coastal opposes the surety recommended by DEP and set by the Administration Commission. (DOAH Cases Nos. 97-4362 and 97-4591.) The Project The activity that is the subject of the application at issue (Permit no. 1281) is Coastal's drilling of a single exploratory oil and gas well in the Gulf of Mexico within waters of the State of Florida, approximately nine miles south of St. George Island in Franklin County. The target of the exploration is an anticipated structural oil trap within the Jurassic Smackover and Norphlet geological formations. These are the same formations which provide commercially-viable oil production in the Jay field in northwest Florida. The anticipated well depth is 13,000 to 15,600 feet but the permit would allow drilling to the basement or 18,000 feet, whichever occurs first. Coastal's drilling contractor, Noble Drilling Company, has drilled wells all over the world since 1925. It has been responsible for approximately 10 percent of all the wells drilled in the Gulf of Mexico, or about 190 wells a year, for both major and small independent oil companies. If permitted, Noble will install a portable drilling rig, the Paul Wolff, or similar sister rig, with three columns and footing that will sit on the relatively featureless sea bottom at Coastal's offshore site. The rig will be staffed by a trained Noble crew and will be operated in a zero-discharge mode. That means nothing will be allowed to escape from the rig into the water, including drill cuttings, sewage treatment water, garbage or rain water. Surrounding the rig will be a high seas oil fence with locks, a cleanup crew and vessel, and an evacuation vessel. When drilling is completed, the rig will be removed and the well either abandoned or transferred to production mode with a production platform. With the exception of a 90-day test period covered by the initial drilling permit, all production- related activity must be permitted under a separate application which is not the subject of this proceeding. The Application Process On March 16, 1992, Coastal submitted 5 offshore drilling applications to the DEP, Bureau of Geology. Assigned numbers 1277-1281, two proposed sites were offshore of Franklin County, and three were offshore of southwest Florida. Later, applications 1277-1280 were withdrawn and only Permit no. 1281 proceeded through review to a Notice of Intent to Issue. As required, Coastal submitted DEP's one-page Form 3 and included a location plat and filing fee. The application form is only for drilling an exploratory well and not for any oil or gas production. The application's number "1281" denotes that 1280 drilling applications have preceded it since the 1940's when DEP's predecessor agency began formal review. Not all of these proceeded through complete review; many were withdrawn, but most were approved. Coastal's was not a routine application. Since the 1940's, leases and activities related to offshore oil and gas exploration in Florida have been the subject of continuous legal disputes. Most applications are for on-shore drilling and DEP's regulations and review process are more relevant to those land- based operations. The review of Coastal's application therefore, by DEP staff, Ed Garrett, and others, was a commonsense extrapolation from their checklist and other sources reasonably, but not directly, related to the application at hand, for example, federal rules governing outer continental shelf (OCS) drilling. On April 8, 1992, Ed Garrett detailed in a letter to Phillip Ware the following information needed to complete the application: A professional ecological/biological survey and report and photodocumentation of the proposed drill site to permit staff review of the bottom areas and potential impact on natural resources; An assessment of ambient conditions in the vicinity of the well site, including potential impacts on coastal habitats, air quality, endangered and threatened species, marine mammals, birds, commercial fishing, recreational resources and archeological resources; A zero discharge policy for offshore drilling consistent with the policy established in 1982 when the DEP issued a drilling permit to Getty Oil for drilling in East Bay; An oil spill response plan for recapture of escaped pollutants; A description of the offshore drilling rig to be used; A hurricane response plan, also an item related to the prior Getty drilling permit; A surety in the amount of $15,000,000, to be recommended by staff to the Governor and Cabinet (a sum of $50,000,000 for all 5 wells was also addressed); Description of how the rig design will account for potential Karst collapse; Description of helicopter activity associated with field operations; Description of support locations and facilities to be used with the drill site, including proposed plan for transport of crude oil; a casing program; A cementing program; List of proposed drilling muds and their chemical components; A hydrogen sulfide contingency plan; and A blowout prevention plan. Mr. Ware addressed each of these requirements in a response dated November 24, 1992. In lieu of the surety, he enclosed a check to the Petroleum Exploration and Production Bond Trust Fund in the amount of $4,000 pursuant to Section 376.40, Florida Statutes. His response included detailed attachments describing the proposed drilling operation. DEP furnished copies of the application and additional materials to interested parties, including the Big Bend Sierra Club and Florida Audubon Society, on November 25, 1992. The Sierra Club had previously sent a letter concerning Coastal's permit application. On December 18, 1992, a meeting was held to consider the materials furnished by Coastal. A letter dated January 11, 1993, from Jeremy A. Craft, Director of the Division of Resource Management, to Phillip Ware addresses deficiencies in the November 1992 submittal specifically related to the site-specific photodocumentations survey, environmental conditions and assessment of impacts, hydrogen sulfide contingency plan, zero discharge requirement, and oil spill contingency plan. The letter also states that the agency completed its own natural resource damage assessment using the schedule prescribed in Section 376.121, Florida Statutes, and data submitted by Coastal, and staff determined that, in addition to joining the Petroleum Exploration and Production Trust Bond Fund, security of $500,000,000 would be required to cover potential liability for damages and $15,000,000 would be needed to cover cleanup costs. Phillip Ware responded by the January 15, 1993, deadline, providing additional information and agreeing that the following would be performed as a condition of the permit: magnetometric and side sonar surveys of the drill site, hydrogen sulfide dispersion model, and oil spill trajectory analysis. Protesting the requirement for additional surety, Coastal offered the value of its leases as evidence of its ability to pay for any damages and cleanup costs. Walter Schmidt, Chief of the Florida Geological Survey, with other agency staff, reviewed the latest submittals and recommended denial of Coastal's permit, primarily based on failure to provide liquid financial surety of sufficient value "to cover any and all potential damages to the environment." On February 22, 1993, the Florida Department of Natural Resources issued its final order memorializing the January 26, 1993, decision of its head, the Governor and Cabinet, denying Coastal's permit application. Consistent with the notice of rights included in the order, Coastal timely filed a petition for a formal hearing, and later requested an informal administrative hearing on the issue of the agency's authority to require additional surety. Individuals with royalty interest in the potential oil and gas production petitioned and were granted leave to intervene in the administrative proceeding. No other parties intervened. On December 17, 1993, the assistant secretary of DEP, acting as hearing officer in the informal proceeding, entered his Final Order denying Coastal's petition and adopting the order previously entered on February 22, 1993, as the agency final order. Coastal appealed. On February 9, 1995, the First District Court of Appeal reversed denial of Coastal's application, holding that the Department had no authority to require surety in excess of that authorized by statute. See Coastal Petroleum Company v. Department of Environmental Protection, 649 So. 2d 930 (Fla. 1st DCA 1995), cert. denied, 660 So. 2d 772 (Fla. 1995). During the remand to the Department, the Board of Trustees of the Internal Improvement Trust Fund voted to require a $1,900,000,000 bond as a condition of the lease and DEP again denied Coastal's application for failure to provide this additional surety. On April 26, 1996, the First District Court of Appeal again reversed the denial of Coastal's application, again holding that the Department had no authority to require surety in excess of that authorized by statute. See Coastal Petroleum Company v. Department of Environmental Protection, 672 So. 2d 574 (Fla. 1st DCA 1996) and Coastal Petroleum Co. v. Chiles, 672 So. 2d 571 (Fla. 1st DCA 1996). On August 16, 1996, DEP officially notified Coastal that it had prepared and was ready to issue Permit no. 1281, but required Coastal to publish a Notice of Intent to Issue Permit. Permit no. 1281, according to the Intent to Issue, included the following special conditions: Coastal shall conduct a magnetometer and side scan sonar survey; Coastal shall complete comprehensive spill trajectory analyses; Coastal shall complete an inventory of oil spill equipment to be stored on the drilling rig, service boats and at the Apalachicola staging location; and Coastal shall prepare a hydrogen sulfide dispersion model with site specific runs. On May 7, 1997, during the pendancy of this proceeding on DEP's Intent to Issue, Chapter 97-49, Laws of Florida, became law and provided authority to require additional surety for certain drilling operations in coastal waters. The new law provided that the Administration Commission would determine the amount of such surety at the recommendation of DEP. On August 11, 1997, DEP applied the new law to Permit no. 1281 and recommended the amount of the surety should be set at $4,249,637,886. On September 9, 1997, the Administration Commission voted and gave Notice and Order of Intent to Set Surety in the amount of $4,249,637,886 for Permit no. 1281. In determining that Coastal was entitled to its permit, DEP staff considered the three criteria found at Section 377.241, Florida Statutes. Those criteria are addressed separately from the surety requirement in the findings of fact, below. Permit Criteria and Conditions The nature, character and location of lands involved. (Section 377.241(1), Florida Statutes) The proposed drill site is south of St. George Island, Franklin County, within the outer limits of the jurisdictional waters of the state in the Gulf of Mexico. At this site the ocean floor is below approximately 40 feet of water. A photodocumentation survey provided by Coastal reveals the condition of the immediate site as mostly barren sand with very sparse animal and plant life, mostly echinoderms such as sand dollars and sea stars, and algae. Impact by a drilling rig set here on the ocean floor would be minimal due to low diversity and low density of biota, the majority of which is mobile and able to avoid direct impact. The magnetometer and side scan sonar programs required by DEP and provided by Coastal reveal no geological hazards, deep-seated faults, archeological sites or anything out of the ordinary at the proposed drilling site. The drilling rig and operation will have virtually no effect on the immediate site. The experience of offshore operations in Louisiana and elsewhere is that fishing is enhanced in the area by the attraction of fishes to the artificial reef created by a rig. Section 377.241, Florida Statutes, which describes the three criteria guiding the issuance of drilling permits was created in 1961. The preamble of the law found at Chapter 61- 299, Laws of Florida, suggests that the legislative concern for the nature of the lands involved was that owners of lands subject to oil, gas and mineral rights should not be unduly burdened or restricted from developing homes, farms, commercial uses or other appropriate land uses. This intent plainly affects land-based drilling projects more than offshore projects such as this. The closest shore to the site is St. George Island, to the north. Lands to the east, west and south are many miles away. St. George Island residents and business owners are sincerely worried about the specter of oil rigs on the horizon, though there is no evidence that the single rig that is the subject of this proceeding could be seen from any land. The obvious threat to St. George and other sensitive barrier islands, to Apalachicola Bay (a special management area), to the world-renown beaches, and to the commercially and environmentally treasured lands along the Florida panhandle coast, would be from an oil spill. The potential costs of a spill are addressed below in the assessment of an appropriate surety, but for the purposes of considering this first permit criteria, it is found that the chance of a damaging spill from drilling the proposed exploratory well is extremely remote. Drilling operations consist of setting up a drilling rig, which is floated to the location and submerged, allowing the rig to rest on the sand bottom; driving a large diameter conductor pipe into the ground, thereby allowing all operations to be conducted within the conductor pipe; drilling the first shallow hole and setting the "surface casing" pipe; sending cement through the pipe and up the outside to seal the pipe, to close the rock layers, and to serve as a base to control the well in the event of a blowout; and continuing to drill the hole until the total depth of the well is reached, when it will again be cased in the same manner with production casing. The rock cuttings are brought to the surface by circulating drilling fluids, also known as "mud", which are water-based solutions of natural materials; then the rock bits are screened and removed so the mud may continue to circulate within the closed system. The risk of oil spills from exploratory oil and gas drilling operations is very small because of the redundant systems and multiple lines of defense against uncontrolled blowouts. The lines of defense include hydrostatic pressure control by the use of weighted drilling fluids, well control systems including redundant blowout preventors, a well control service company, and the use of trained and certified personnel. Most blowouts are gas, not oil, and most blowouts stop themselves by bridging within a few days. The proposed Permit no. 1281 well is less likely to spill any oil because it will be a zero discharge well; the well will be drilled by one of the largest drilling contractors in the world, Nobel Drilling; the rig will be drilled with federally- certified crews trained in well control; the rig will be surrounded by a high seas oil fence with locks; there will be onsite oil spill equipment and personnel; there is redundant blowout equipment on this rig; and the environmental compliance officer will train all workers to observe proper procedures. The operations will be comparable to that of Getty Oil's exploration project in East Bay, which in the words of DEP's oil and gas section administrator, was "an absolutely first class operation. You could eat off the deck. Well, I wouldn't, but it looked clean enough." (transcript, p. 777) The U.S. Department of Interior, Minerals Management Service (MMS) maintains statistical data based on reports of accidents occurring on the outer continental shelf (OCS) resulting in oil spills greater than one barrel (42 gallons). MMS regulations require that oil and gas operators report orally and in writing all spills of oil and liquid pollutants to the MMS District Supervisor. Data from the reports are relied on by the industry, by scientists and by regulatory agencies. According to MMS data for the years 1971-1995, out of a total of 24,237 well starts, 999 barrels of crude oil and condensate were spilled from offshore wells under federal jurisdiction. When oil is spilled on the water, natural weathering processes immediately begin to work on the oil: evaporation reduces the volume of the oil, with light oils evaporating quickly; bacteria literally begin eating the oil and oil products; sunlight degrades the oil; and the oil begins to dissolve and dissipate into the water. These natural processes are especially effective at this site because the oil involved would likely be a very light 50 API gravity oil, as is other Smackover oil in Florida; the climate is warm and the bacteria which eat the oil and oil products are plentiful in this region; the area receives much sunlight; and warmer water promotes the dissolution and dissipation of the oil into the water. Oil is a naturally-occurring substance. Natural oil seeps in the Gulf of Mexico release large quantities of oil and gas into the sea that is weathered and dissipated as described above. The seeps, discovered through satellite photography, are estimated to produce as much as 120,000 barrels a year from vents in the continental shelf off the Louisiana coast. The nature, type and extent of ownership of the applicant, including such matters as the length of time the applicant has owned the rights claimed without having performed any of the exploratory operations so granted or authorized. (Section 377.241(2), Florida Statutes) In 1941, the Florida Legislature enacted Chapter 20680, Laws of Florida, authorizing the Board of Trustees of the Internal Improvement Fund (Trustees) to negotiate, sell, and convey oil and gas leases on lands and water bottoms owned by the State of Florida. Pursuant to that law, Coastal's predecessor, Arnold Explorations, Inc., acquired three leases, numbers 224-A, 224-B and 248, encompassing the territorial waters of the state along the west coast, from Apalachicola to south of Naples, as well as Lake Okeechobee and other fresh water bodies. The 50+ years' history of those leases is chronicled in volumes of legal documents and court opinions commencing, it appears, with a Florida Supreme Court opinion in Watson v. Holland, 20 So. 2d 388 (Fla. 1945), which upheld the leases against a challenge by then Attorney General J. Tom Watson. Proposed Permit no. 1281 is within lease 224-A, which includes the northern portion of Coastal's off-shore lease area. Coastal, alone and through arrangements with other oil companies, including Mobil Oil Corporation, conducted geologic and seismic studies to locate oil and other minerals covered by the leases. Coastal, also through joint venture arrangements with other companies, drilled some exploratory wells off the west coast of Florida; these did not produce oil and were, therefore, "dry" wells. Through the years Coastal has satisfied its obligations to pay annual rentals and perform certain minimum activity under its leases. In 1976, Coastal settled federal litigation between Coastal, the Trustees and the Army of Corps of Engineers, by relinquishing its exploration rights to all but the most off- shore portion of its lease area (7.36-10.36 miles offshore). Coastal retained a "residual royalty" interest in the near shore area (coast to 4.36 miles off-shore) and surrendered altogether its interests in the middle portion. (See Coastal Petroleum v. Chiles, et al, 701 So. 2d 619 (Fla. 1st DCA 1997), which upheld denial of Coastal's inverse condemnation action based on the state's enactment of a statute prohibiting offshore oil and gas exploration in Coastal's royalty interest areas. This opinion provides an outline of the vicissitudes of Coastal's defense of its leases.) Activity by Coastal over the past 50 years, through its partners and joint venturers, belies the Environmental Petitioners' claims that Coastal has "abandoned" oil exploration in favor of a more lucrative settlement or buy-out by the state (the "Greenmail" theory). For many of the 50 years, litigation has eclipsed oil, gas and mineral exploration in the vast leases. Not all of the litigation was initiated by Coastal and by all published reports none has been found to be frivolous. The proven or indicated likelihood of the presence of oil, gas or related minerals in such quantities as to warrant the exploration and extraction of such products on a commercially profitable basis. (Section 377.241(3), Florida Statutes) Oil and gas exploration is a risky business. Depending on the area of the world, you may have a one in 10 chance, or one in 50 chance of hitting the right spot. If you finally hit, you must expect to pay for all of the prior misses. In the experience of Phillip Ware, the standard industry expectation is a one in 10 chance in a frontier area such as this. Permit no. 1281 would be a "wildcat" well, that is, a well drilled outside of a producing field. This third criterion has rarely, perhaps only once, been used by DEP to deny an application, as DEP interprets its requirement very liberally. If the statutory criteria intended the likelihood of the presence of oil to be better than 50 percent, every application would have to be denied. From the statistics maintained by the agency, Ed Garrett determined a drilling success rate in wildcat wells throughout Florida has been about 2-3 percent. Some wells drilled in a producing field come up dry, even as close as one- half mile from a producing well. When DEP, through Ed Garrett and its other staff reviewers, applied the third criterion to Coastal's application the agency considered wells to the north drilled into Smackover and Norphlet, productive formations found in the northern Gulf of Mexico and inland up into Arkansas, and it determined that the siting of proposed Permit no. 1281 was reasonable. The "commercially profitable" prong of the criterion is also tricky, since fluctuating oil prices engendered by wholly unpredictable world events can result in a well that is valuable when it is first drilled becoming useless by the time production and transportation facilities are established. Coastal presented sufficient evidence of the anticipated commercial profitability of the well. Reasonable, competent, credible geologists can disagree, as evidenced by the range of opinions presented by the experts in this proceeding, but all agree on one immutable principle: the only way we can determine whether oil is present is to dig a hole. Phillip Ware is a reasonable geologist, registered to practice geology in the State of Florida. His experience in the past 20 years has been as an employee and then president of Coastal. In the early years he operated as an oil scout and as an assistant to the vice-president, Joe Banks. In that capacity, and continuing to the present, he has monitored all relevant oil and gas activities in the area, reviewed oil and gas drilling logs, kept track of current drilling, including industry developments and rumors, and stayed current with publications and public data on oil, gas and mineral exploration. In selecting the site for Coastal's application, Phillip Ware reviewed documents from the Florida Geologic Survey and elsewhere describing oil exploration wells drilled in state waters, including wells drilled by Coastal through its joint venturers, California Oil Company and Mobil. He reviewed many scholarly and scientific and industry publications; he reviewed available seismic studies as well as a map made by Joe Banks, who died in 1979. The contour lines drawn on Banks' map, as interpreted by Phillip Ware, show a promising geologic structure at the site of Permit no. 1281. A geologic formation is a specific layer of rock large enough to be mapped over a large geographic area. Jurassic period Smackover and Norphlet formations have been the prolific source of oil in the Jay fields northwest of Permit no. 1281. An embayment is a shallow restricted area of prehistoric sea where formations are deposited, in this case, the Smackover and Norphlet formations. The Apalachicola embayment, centered along the present Apalachicola River, has been studied extensively in the last 20 years and its existence at the site of proposed Permit no. 1281 is the subject of substantial dispute between Coastal and the Environmental Petitioners in this proceeding. After DEP issued its intent to issue the permit and the Environmental Petitioners filed their challenge raising the issue of the likelihood of finding oil, Coastal hired a series of experts who reviewed the same data considered by Phillip Ware, and other data, and derived their own opinions regarding the viability of the oil prospect. Petroleum geologists describe three or four essentials for an oil field. The source rock, which is organically rich and subjected to heat over a long period, forms oil and gas. The reservoir rock may also be the source rock if there was no migration of the petroleum, but if the petroleum has migrated, the reservoir rock is its final resting place. The reservoir must have porosity and permeability to allow the petroleum to enter and move about. The structure, which may be part of the reservoir, is an upper level or trap which contains the oil. Cap rock or seal is what holds the petroleum within the structure, keeping it from escaping to the surface. A structure or trap for the oil may be a geological fault or an anticline, when the cap has formed a dome shape which captures and holds the oil. The process of determining whether these elements exist beneath the earth's surface, or in this case, below the ocean floor, requires the acquisition of data from prior wells. Even dry wells provide a wealth of information. Magnetic, seismic and gravity testing (called geophysical testing) also yields valuable data. From the available data, geologists are able to extrapolate and map the subsurface of a given area. The more data that is available, the more accurate is the map. Geophysical testing, however, is highly expensive, and prospects have been drilled without such site-specific tests, the interpretations of which can be subjective. DEP staff geologists considered Phillip Ware's selected site as reasonable, based on their own conclusions that Smackover and Norphlet trends likely extended southeast through the Florida panhandle and into the area offshore of Franklin County. These conclusions are supported by the extensive evidence and testimony of Coastal's experts. Charles Morrison gathered and reviewed all geophysical information available, chose the best of that information, had the information reprocessed using current computer methods, analyzed and correlated the information, did regional mapping, and then mapped the structures in the area. His work included identifying geologic faults, the interface of large blocks of the earth which have moved up, down or sideways, and which may also thereby create a trap for oil. He also mapped a large faulted structure or trap called an anticline, or dome, independently confirming the selection made by Mr. Ware, and he concluded that the structure was a good quality, drillable prospect. Barry Faulkner, hired by Coastal to review its leases including Lease 224-A, is a professional geologist in Florida and was chief geologist for Getty Oil Company. In that position he reviewed large projects and was successful in his analysis; he evaluated hundreds of prospects including prospects in Florida; he has laid out well-tie and speculative seismic programs near and in Florida; he has prepared basin analyses for Florida in the past; he has reviewed all the relevant geologic literature; he has reviewed all relevant logs and records of the Bureau of Geology which keeps such records; he has reviewed all of Coastal's relevant records; he has reviewed and considered Mr. Morrison's work in light of his own experience; and he performed many analyses on the above data and information. He independently concluded, based upon his analyses, that the Smackover was of sufficient thickness and that source, reservoir, seal and a trap exist in the Smackover and Norphlet geologic formations at the location of Permit no. 1281. Barry Faulkner estimated the chances of source rock, reservoir rock, cap rock and trap as 80 percent, 60 percent, 80 percent and 70 percent, respectively, at the proposed well site, for a risk factor of 1 chance in 4 that the well would be productive. The Environmental Petitioners' less-thorough analysis yielded a much less optimistic estimate of 20 percent, 17 percent, 30 percent and 20 percent. Employing Barry Morrison's risk computation methodology to the deflated estimate would yield a risk factor below the 2-3 percent actual success rate supported by DEP's statistics, an example of the vast range of speculation but hardly sufficient to defeat this permit. Before the 1943 Sunniland oil field was discovered (the first major field in Florida, in southwest Florida), hundreds of dry hole wells were drilled. Hundreds of dry holes were found before Florida's second major oil field, the 1969 Jay field, was established. The fact that no leases were recently bid in federal off-shore waters and few oil and gas leases were entered in the last 10 years in the Apalachicola Basin is not competent evidence of any poor viability of Coastal's site. The regulatory climate, including federal and state moratoria on off-shore exploration activities, must also be considered an explanation for the inactivity. Permit Conditions Permit no. 1281, as described in DEP's intent to issue, includes 7 general permit conditions relating to compliance with other applicable laws and regulations, obtaining other required licenses or permits, notifying DEP's Oil and Gas Section in advance of drilling, and submitting required drilling logs and forms. These are standard conditions applied to any similar permit. The proposed permit also includes these special permit conditions: Prior to the commencement of drilling operations, Coastal shall conduct and submit to the Department for review and approval a magnetometer and side scan sonar survey. Prior to the commencement of drilling operations, Coastal shall complete and submit for department review and approval comprehensive spill trajectory analyses. Prior to the commencement of drilling operations, Coastal shall complete and submit to the Department for review and approval an inventory of oil spill equipment to be stored on the drilling rig, service boats, and at the Apalachicola staging location. Coastal shall maintain zero discharge conditions at the drill rig site and shall utilize zero discharge equipment as described in the application package. Prior to the commencement of drilling operations, Coastal shall submit to the Department for review and approval a hydrogen sulfide dispersion model with site-specific runs. In addition, Coastal shall incorporate the site-specific information and procedures stated in the January 15, 1993, letter into the Hydrogen Sulfide Contingency Plan submitted to the Department. Prior to the commencement of drilling operations, Coastal shall publish in the Apalachicola Times and post in appropriate public facilities in the region an explanation of the hydrogen sulfide warning signals and evacuation notices and procedures. Coastal shall carry out bottom sampling according to the schedule described in the January 15, 1993, letter to the Department. This sampling is to detect accidental discharges of drilling muds. (CPC Exhibit No. 119) Only special conditions a), b), c), and e) are still in controversy and Coastal claims that DEP does not have the authority to require these items. Under protest, each has been completed and submitted to DEP and are included in the record of this proceeding. (Inventory of equipment is CPC Exhibit no. 97; the side scan sonar survey is CPC Exhibit no. 185; the magnetometer survey is CPC Exhibit no. 186; and the hydrogen sulfide dispersion model with specific reins is CPC Exhibit no. 233.) The agency had a sound rational basis to require each item. While in the beginning of the review process DEP imposed the items as part of the application submittal, it eventually adopted these requirements as permit conditions, as suggested by Phillip Ware in his January 15, 1993, response. (CPC Exhibit no. 87) The issue is moot, as DEP concludes in its proposed recommended order; Coastal has fulfilled the special conditions and Coastal needs only to formally submit the documents, with updates where necessary. The Environmental Petitioners amended their petition to delete their claim that more seismic, specifically 3D seismic testing, should be conducted as a condition of the permit. No evidence suggests that such a condition is necessary. The site selected by Coastal for its permit application is at the intersection of two good quality seismic lines, interpreted by competent expert witnesses as contributing to their credible opinions that the site is a commercially-viable prospect. There was some evidence that, as a condition for the Getty Oil drilling permit off-shore of Pensacola, drilling was prohibited during hurricane season. No party here has suggested or put on evidence of the need for this condition or any special condition other than those conditions addressed above. The Surety The most significant condition of the permit is the surety required by Section 377.2425(1), Florida Statutes, to assure that the operations under the permit will be ". . . conducted in a safe and environmentally compatible manner." Prior to the 1997 adoption of Chapter 97-49, Laws of Florida, any applicant had the option of either supplying cash, a bond or letter of credit; or paying an annual fee to the Minerals Trust Fund. The 1997 legislature withdrew that second option for applicants for oil and gas exploration, drilling and production in coastal waters. Specifically, Chapter 97-49 (Section 377.2425(1)(c), Florida Statutes) requires: (c) An applicant for a drilling or operating permit for operations planned in coastal waters that by their nature warrant greater surety shall provide surety only in accordance with paragraph (a), or similar proof of financial responsibility other than as provided in paragraph (b). For all such applications, including applications pending at the effective date of this act and notwithstanding the provisions of paragraph (b), the Governor and Cabinet in their capacity as the Administration Commission, at the recommendation of the Department of Environmental Protection, shall set a reasonable amount of surety required under this subsection. The surety amount shall be based on the projected cleanup costs and natural resources damages resulting from a maximum oil spill and adverse hydrographic and atmospheric conditions that would tend to transport the oil into environmentally sensitive areas, as determined by the Department of Environmental Protection. (emphasis added) Section 377.2425(1), Florida Statutes, as amended, denies permittees of offshore wells the option of using the Minerals Trust Fund under paragraph (1)(b). Instead, surety for wells drilled and operated in coastal waters must be covered by a surety provided as described in paragraph (1)(a) of the statute. As discussed in the conclusions of law, below, Permit no. 1281 is a pending application to drill for oil and gas in coastal waters, and is subject to the surety requirement outlined in Chapter 97-49, Laws of Florida. DEP prepared and submitted its recommendation for a $4,249,637,886 surety amount to the Administration Commission. On September 9, 1997, the Administration Commission adopted the recommendation through its Notice of Intent To Set Surety. The surety amount set under Chapter 97-49, Laws of Florida, must be based on the projected cleanup costs and natural resource damages of a "maximum oil spill." However, Chapter 97- 49, Laws of Florida, contains no definition of that term. Oil spills can occur in a number of different ways, depending upon the source (i.e., vessels, pipelines, storage tanks, and drilling or production facilities.) While exceedingly rare, the most disastrous oil spills from drilling or production platforms are the result of a "blowout" from a variety of causes. A "blowout" is generally defined as an uncontrolled flow of formation fluids (oil, gas and water) up through the well bore hole, and exiting directly from the well into the atmosphere or ocean waters. Anatomy of a Blowout Oil and gas are contained within underground reservoirs at varying pressures which can amount to thousands of pounds per square inch (psi). Once a hole is drilled from the surface down into these reservoirs, the pressurized formation fluids will tend to "migrate" or escape under extremely high pressure. To counteract this pressure, weighted drilling mud is pumped into the well. The weight of the mud resting on top of the formation fluids forms a "hydrostatic head pressure" by pressing downward to contain the pressurized fluids. However, if the drilling mud is not sufficiently weighted, or there is not enough drilling mud resting on top of the pressurized fluids, the drilling mud pressing downward becomes insufficient to counteract the pressure of the formation fluids. The result is termed a "kick." A "kick" is a threatened blowout, where insufficient hydrostatic head pressure allows the influx of formation fluids into the well. The kick, and subsequent blowout, can be a subtle intrusion; or in a serious event, drilling mud and formation fluids can be expelled from the well very violently and under considerable pressure. The impending high pressure of a kick is usually detected, and can be safely siphoned off under controlled conditions by way of a complex system of plumbing and gauges termed a "christmas tree." If not contained, blowouts can cause considerable damage to the drilling rig. In extreme cases, the drilling rig may collapse onto the well head, aggravating the spill and making it more difficult to halt the flow of oil from the well. Blowouts are usually contained through the practice of well control. Initially, the well is monitored, and the drilling mud/formation fluid balance is carefully maintained to avoid a kick or to quickly control a kick. As a fallback, the well can be capped at the surface by use of blowout preventers or "BOPs." BOPs and other devices used for well control have been standard equipment used by the petroleum industry worldwide for several decades. Located at the well head, BOPs come in a number of configurations (sheer rams, pipe rams, annular preventers, for example) and several different types are normally used in conjunction with one another as a redundant system. Florida requires that BOPs be in place for all drilling and production facilities in the state as well as for those in federal waters. Permit no. 1281 requires Coastal Petroleum to use BOPs on its drilling platform. The evidence and testimony adduced at trial demonstrate that widespread use of BOPs and other well control devices on a state, national and international scale has not completely eliminated the occurrence of blowouts. Blowouts, like most major accidents, are rare, but they do happen. Despite continually upgraded safety features, blowouts continue to occur worldwide, in the United States, and in the Gulf of Mexico as the result of human error or a chain of several errors or miscalculations, possibly combined with mechanical failures. Such an event occurred in 1979 in the Gulf of Mexico in Mexico's Campeche Bay, an area called the "Golden Lane" because of its extraordinary oil production. The well, Ixtoc I, was a single exploratory well, in Mexican waters and governed by Mexican regulations. Its blowout resulted in the most disastrous accidental oil spill in history. The Ixtoc I well was drilled by the Mexican National Oil Company (Petroleos Mexicanos or "PEMEX"). The semisubmersible drilling rig was provided by SEDCO, Inc., of Dallas, Texas. Under a separate agreement, SEDCO also provided maintenance personnel, a rig superintendent and an assistant to advise PEMEX in the operation of the drilling rig. The SEDCO 135 drilling rig was equipped with the standard BOP devices, including (1) pipe rams -- hydraulic shutters that snap shut around the drill pipe and prevent oil from flowing up in the space between the drill pipe and the casing (known as the annulus); (2) sheer rams -- hydraulic shutters that sheer through the drill pipe and block oil flowing up through the drill pipe; and (3) annular BOP -- which hydraulically inflates to further close off the annulus and seal off the space around the drill pipe. On June 3, 1979, the Ixtoc I well experienced a kick while removing the drill pipe from the hole. The sudden pressure increase, in conjunction with a chain of human errors and miscalculations, quickly led to a blowout condition. The BOPs were activated, but were unable to contain the upward surge for formation fluids and the well blew out. Oil and gas "gushed" from the drill pipe under extreme pressure (approximately 30 meters/100 feet into the air), and the associated petroleum fumes quickly led to a fire. All personnel were forced to abandon the drilling rig. Most of the equipment and machinery on the rig was destroyed, and the drilling tower collapsed into the sea. When the drilling rig collapsed and sank to the sea floor it buckled the marine riser and damaged the BOP stack at the well head location on the bottom. Initially, the Ixtoc I well discharged oil into the sea at an estimated rate of 30,000 barrels per day, although as much as half was consumed by the fire. This flow rate was gradually reduced during the course of the capping efforts after PEMEX contracted with several American and international firms trained in oil spill response. A massive cleanup effort was begun using firms from several counties, including the United States. However, the flow of oil from the Ixtoc well continued for nearly 295 days (almost 10 months), during which time repeated efforts were made to reduce and ultimately halt the flow. The total amount of oil discharged in the Ixtoc spill is estimated in a range between 120 and 170 million gallons. Oil reached and damaged the distant coast of Texas. The extensive damage to the SEDCO 135 semisubmersible rig rendered it useless in capping the well, and ultimately two relief wells (Ixtoc 1A and Ixtoc 1B) were drilled to "kill" the well. A relief well consists of drilling a new hole down near the depth of the formation, and then intersecting the original (blownout) well from the side. Weighted drilling mud is then pumped down the relief well and into the original well in order to regain a balance between the drilling mud and the pressure of the formation, thereby halting the flow of oil up the original well. A relief well can take as little as 30 days to drill, assuming no difficulties arise to slow the drilling operation. Under normal to adverse circumstances, a relief well may also take as long as three to four months to drill down to depth, locate the original well, and to intersect that well. Additionally, it will take time to locate another drilling platform, transport said platform to the site of the blowout, and to set up that platform and prepare it for drilling operations. During the time needed to locate, transport and set up the rig, to drill the new well, to intersect the original well, and to pump weighted mud into the original well, oil may continue to flow out of the blownout well. As described in paragraph 42, above, spills from offshore drilling operations in U.S. waters are exceedingly small. Equipment has been improved, personnel are better-trained and the activity is highly regulated and monitored by state and federal authorities. The Property of Oil Oil is a complex substance, actually comprised of several different types of components: volatiles, aromatics, resins and asphaltines. The volatiles include compounds such as benzene, toluene, ethylbenzene and xylene, which are highly toxic. The aromatics can include compounds with high and low molecular weights, and they, too, are highly toxic. Fortunately both volatiles and aromatics evaporate quickly and will not persist long in heavy concentrations once the oil s released into the water. The resins and asphaltines are the heavier compounds that persists much longer in the water. Crude oils vary in their density. This density is usually a function of the proportion of lighter volatiles and aromatics versus heavier resins and asphaltines. The different densities of crude oil are measured on a API (American Petroleum Institute) Index, with lighter crude oils (those containing a larger portion of the volatile and aromatic compounds) registering higher on the API Index than the heavier, thicker crudes. Thus, the lighter crudes are more toxic, but a larger proportion of the compounds within these oils will evaporate and disburse more quickly. Consistent with oil extracted from the target formations at the Jay field, any crude oil discovery at Coastal's proposed site is likely to be a very light crude with an API density between 40 and 50. In contrast, the oil spilled from Ixtoc I was between 29 and 33 degrees API. Once spilled into the water, oil immediately begins a process of "weathering," whereby the chemical and physical properties of the oil are altered. The more toxic aromatic and volatile compounds quickly begin to evaporate. As much as 50 percent of the mass of the oil may be lost through evaporation into the atmosphere and dissolution into the water column within the first 48 hours. At the same time, the oil emulsifies by mixing with the surrounding water. This forms an oil/water mix called "emulsion" or "mousse" which is thicker and stickier. In this emulsified mixture of oil and water, the spill can actually grow to 3 or 4 times its original mass, and can persist for a much longer period of time. As the oil emulsifies, the evaporation and dissolution of the volatile and aromatic toxic compounds is slowed. This emulsion remains potentially toxic through direct contact and ingestion, but primarily injures by smothering or through long-term exposure to organisms. The Department's Estimate of Natural Resource Damage In calculating the projected natural resource damage portion of its recommendation, DEP utilized the natural resource damage compensation schedule (the Formula) found at Section 376.121, Florida Statutes. The Formula was adopted by the Florida legislature after extensive collaboration between DEP and representatives of the petroleum industry. The Formula does not calculate projected cleanup costs. The Formula is used to assess damage after an actual oil spill or other pollution event and, with the exception of the Coastal permit case, has never been used to estimate costs prior to an actual spill event. The Formula requires the input of several factors in order to compute natural resource damages. These factors are: location of the discharge factor (designed as "L"), [Section 376.121(5)(a)1, Florida Statutes]; special management area factor (designated as "SMA"), [Section 376.121(5)(a)2, Florida Statutes]; pollutant category factor (designated as "PC"), [Section 376.121(5)(a)3, Florida Statutes]; habitat area factor (designated as "A"), [Section 376.121(5)(a)4, Florida Statutes]; volume of the discharge (designated as "V"), [Section 376.121(2)(a), Florida Statutes]; the deaths of threatened or endangered species (designated as "ETS"), [Section 376.121(6), Florida Statutes]; a base value of $1 per gallon of pollutant discharged (designated as "B"), [Section 376.121(4)(a), Florida Statutes]; and the cost of conducting a damage assessment as determine by DEP (designated as "DA"), [Section 376.121(4)(d), Florida Statutes]. Under the Formula, natural resource damages are compensated as follows: The amount of compensation assessed under this schedule is calculated by: multiplying $1 per gallon . . .by the number [of gallons discharged], times the location of the discharge factor, times the special management area factor. Added to the amount obtained in paragraph (a) is the value of the observable natural resource damage, which is calculated by multiplying the areal or linear coverage of impacted habitat by the corresponding habitat factor, times the special management factor. The sum of paragraphs (a) and (b) is then multiplied by the pollutant category factor. The final damage assessment figure is the sum of the amount calculated in paragraph (c) plus the compensation for death of endangered or threatened species, plus the cost of conducting the damage assessment as determined by the department. Section 376.121(4), Florida Statutes. Expressed mathematically, the Formula is represented as: {(B)(V)(L)(SMA)+(A)(SMA)} (PC)+(ETS)+(DA) Utilizing the Formula to project damages from a hypothetical spill requires a series of assumptions in order to derive the variables described above; those variables are then factored in the equation. The Formula requires a pollutant factor. Section 376.121(2)(b), Florida Statutes, categorizes the types of pollutants involved, and assigns a multiplier to each category of pollutant based on the severity each can have on the environment. The toxicity, dispersibility, solubility and persistence in the environment are all factors taken into account by the legislature in categorizing pollutants and assigning a multiplier to each. Section 376.121(2)(b), Florida Statutes. Crude oil is contained within Category 2, along with waste oils, lubricating oils, tars and asphalts. Section 376.121(2)(b), Florida Statutes. The Formula does not distinguish between light, medium or heavy crudes (those with high, medium or low API density numbers), but instead includes all crudes within Category 2. Section 376.121(2)(b), Florida Statutes. Those pollutants listed in Category 2, including crude oils, receive a multiplier of 4 when factored into the Formula. Section 376.121(5)(a)3., Florida Statutes. To derive the volume or "V" of the Formula, the actual amount of oil that is discharged directly into the water is used. The volume variable under the formula is not adjusted to consider evaporation, emulsification, dispersion or cleanup in coming up with the "V" used in the equation. The "raw" volume is used. The weathering process undergone by the pollutant is instead accounted for in calculating the amount or area of habitat injured by the pollutant or the "A" variable in the Formula. Section 376.121(2)(b), Florida Statutes. Relating the Formula to Chapter 97-49, Laws of Florida, the volume or "V" must represent a "maximum oil spill." DEP considered several different methods for deriving the volume of the "maximum oil spill," including reviewing area oil spill contingency Plans and other sources for similar terminology. "Maximum Oil Spill" is not a term used in the industry or previously by regulatory agencies. DEP ultimately settled on basing its spill volume on the Ixtoc I blowout described above, utilizing 150 million gallons (a mid-range between the estimated 120 and 170 gallons spilled over time by Ixtoc I) for a total of approximately 3.5 million barrels. In deriving the habitat factor (A) to plug into the Formula, it was necessary for DEP to assume a spill boundary -- the total area within which some resources would be affected by the spilled oil. In its recommendation to the Administration Commission, DEP identified a spill boundary extending from Gulf County and east and south to the Hernando/Pasco county line -- a distance of 222.8 miles. The counties included within this area of potential impact were: Gulf, Franklin, Wakulla, Jefferson, Taylor, Dixie, Levy, Citrus and Hernando Counties. Conjecture that the spill would flow primarily west, rather than east, resulted in less damage and therefore less than the statutory "maximum." The Department relied on a number of sources in deriving the spill boundary for its "maximum oil spill" under the statute. Initially, the Department reviewed hypothetical spill trajectory models prepared in conjunction with proposed oil and gas leasing in federal waters off southeast Florida. As with the spill volume, the Department rejected the use of a hypothetical model and instead referred, in part, to data from past oil spills. On March 24, 1989, the oil tanker Exxon Valdez ran aground, spilling 11.2 million gallons of crude oil into Prince Williams Sound, Alaska. Containment was highly effective for the first three days, but when the winds and seas increased with a storm event, the oil was blown beyond any hope of containment. The oil traveled on a 70-mile trajectory. Field surveys identified 790 miles of shoreline within Prince Williams Sound which received oil, over 200 of which were classified as heavily oiled. Additionally, more than 2400 miles of shoreline in the Kenai Peninsula/Kodiak Island region were found to be oiled. The Department also relied on data submitted by Coastal Petroleum as part of the application for Permit no. 1281. In particular, the Department referred to Coastal's November 23, 1992, and January 15, 1993, submittals. In its November 23, 1992, submittal, Coastal evaluated the potential impacts of an oil spill, confining their search to a specifically identified area between St. Joseph Bay in Gulf County to Anclote Key in Hernando County. In its January 15, 1993, submittal Coastal, then conducted an economic analysis of these same areas. In that analysis, the Gulf, Franklin and Wakulla County area is designated as the "primary impact area" while the remaining 15 counties to the east and west are designated as "secondary impact areas." In deriving the habitat areas within DEP's spill boundary, the Florida Marine Research Institute, a bureau of the agency, was used. Using a comprehensive Florida Marine spill Analysis System (a subset of the Marine Resource Geographic Information System) database, acreages for habitat and linear beach were provided. The compensations schedule for various forms of habitat is found in Section 376.121(5)(a)4., Florida Statutes. In computing the projected habitat coverages (A) within the defined spill boundary, DEP did not assume that the oil would damage or destroy 100 percent of all habitat types within this boundary. Rather, the agency accounted for evaporation and dissolution of the oil, and assumed some cleanup efforts would be underway. For those habitats that are principally submerged for the majority of the time (such as seagrasses) only 1 percent of those resources within the spill boundary were assumed to suffer damage. DEP reasoned that the oil would float over top of these submerged habitats. Only a very small percentage of seagrasses in shallow water would be impacted by oil. This would typically occur during low tide, or by oil that has begun to settle into the water column. For emergent habitats that are located along the shoreline or within the intertidal zone, DEP assumed a five-times greater possibility of exposure to oil. Thus, for habitats such as saltmarsh, mangrove and oyster reef, it was assumed that the maximum oil spill would damage 5 percent of the total area of these resources. Sandy beach habitat, by virtue of its location relative to the well and within the intertidal zone, was found to be at much greater risk. For that reason, the agency assumed damage to 25 percent of the linear area of sandy beach within the spill boundary. These same assumptions, with one notable exception, were originally used in calculating the previous two surety amounts prior to the passage of Chapter 97-49, Laws of Florida. The notable exception was for sandy beach. In the most current surety calculation, coverage of sandy beach was reduced from 50 percent down to 25 percent to reflect the general absence of that environment throughout much of the spill boundary area. In computing the projected natural resource damages, the Formula treats natural resource damages differently when they occur within a special management area. Those resources damaged within a special management area are multiplied by an additional special management area factor (SMA). Section 376.121(5)(a)2., Florida Statutes. Special management areas are defined by statute as "areas designated because of their unique habitats; living resources; recreational use; aesthetic importances; and other ecological, educational, consumptive, intrinsic, scientific, and economic values." Section 376.121(2)(c)2., Florida Statutes. Special management areas include: state parks; recreation areas; national parks, seashores, estuarine research reserves, marine sanctuaries, wildlife refuges, and national estuary program water bodies; state aquatic preserves and reserves; classified shellfish harvesting area; areas of critical state concern; federally designated critical habitat for endangered or threatened species; and outstanding Florida waters. Section 376.121(2)(c)2, Florida Statutes. Most of the area in question is within some form of special management area as defined by statute. DEP's recommendation assumed that the 1 percent, 5 percent and 25 percent of the overall habitats damaged by the maximum oil spill would be within any one of these several special management areas. The Formula also requires a location of discharge factor. Section 376.121(5)(a)1, Florida Statutes. Under the statute, the location factor is either 8 (representing inshore discharges); 5 (representing nearshore discharges) or 1 (representing offshore discharges). Section 376.121(5)(a)1.a., Florida Statutes. Since the proposed well and origin of the discharge is an offshore well located 9 miles off the coast, a location of the discharge factor of 1 was used. The Formula also includes a factor for the death of any endangered or threatened species (ETS). Compensation for the death of any animal designated as an endangered species is $10,000 per animal, while each threatened species killed is compensated at $5,000 per animal. Section 376.121(6), Florida Statutes. For the purposes of DEP's surety recommendation, no endangered or threatened species were presumed killed and no specific evidence was provided by any party to determine any better estimate for this factor. The Department assumed $10,000 administrative costs for the final factor in the Formula (DA) described in paragraph 107, above. Coastal's Methodology for Projecting Natural Resource Damages Dr. Deborah French was qualified as an expert in oil spill events. Since 1985 she has been performing oil spill modeling and working on models to be used for calculating natural resource damage assessments for a variety of clients, including the U.S. Department of Interior (DOI) and the National Oceanic and Atmospheric Administration (NOAA). She has also worked on environmental impact assessments and is widely published. Dr. French prepared Coastal's "Oil Spill Trajectories and Analysis of Maximum Credible Natural Resources Damages", having already been involved in developing the computerized system for natural resources damage assessments under contract with DOI. Dr. French's model is widely used throughout the world by governments and private industry to predict the movement of oil on water and to the shore. The model has been validated by comparison with numerous actual oil spills and is a reliable and reasonable way to determine which habitats could be damaged or require cleanup because of a hypothetical oil spill. The model takes into account relevant data of various kinds to predict the movement and fate of oil spilled on the water, including the precise location, the flow rate of the well, the duration of the flow, the characteristics of the oil, the wind record, the record of water currents, a digitized geographic map including water depths, and the digitized types and location of the habitats in the area. Dr. French utilized the precise location of Permit no. 1281. Dr. French used two flow rates for the well, a "maximum probable" flow rate of 1,654 barrels per day and in the event it were determined to be applicable, a "worst case" flow rate of 5,948 barrels per day. These flow rates are the average and highest initial flow rates of the 122 producing wells in the Jay oil field from the Smackover geologic formation, the target of the Permit no. 1281 well.2 Although these flow rates are not blowout rates (and none of these wells has blown), it is reasonable and reliable to use them as a predicted rate because the Jay oil field is a large sample of the target Smackover formation in Florida; the Jay Smackover flow rates are flow rates after acid stimulation and not the two or three times smaller unstimulated natural rates; and DEP's own expert, Ed Gambrell, admitted that he would expect that if a blowout occurred it would be two or three times the flowing rate. Thus, it is likely the stimulated figures represent a blowout condition from the same well in the unstimulated natural condition it would be in at the time of drilling. DEP's choice of the volume of Ixtoc as the basis for the agency's calculation is neither reasonable nor reliable because of the unique characteristics of that well: its extraordinary rate of flow; its extraordinary duration of flow; the fact it was located in Mexican waters, governed by Mexican regulations and attitudes; and it was at a time before the industry became more sophisticated and highly regulated. The Ixtoc well was drilled into one of the most prolific areas in the world, that is, "the Golden Lane," an area noted for unusually high flow rates. One well there flowed 455,000 barrels per day, and the Ixtoc well itself was estimated to flow 30,000 barrels per day. Initial production rates there are some of the highest in the world. In contrast, the Smackover geologic formation in Florida is far less productive, with wells averaging less than 2,000 barrels a day of flow after stimulation to enhance their even lower unstimulated natural flow rates. Dr. Schmidt, who selected the Ixtoc well volume, admitted he did not expect another "Golden Lane" off Apalachicola. In addition to flow rate, duration is also important to the volume of a spill. The Ixtoc well flowed for 295 days before it was brought under control. Other wells have never flowed for such a duration before being brought under control. In fact, even without being brought under control, most wells bridge off by themselves within a few days. Dr. French used two durations of flow: a "maximum probable" duration of 5 days and, in the event it were applicable, a "worst case" duration of 21 days. Her model is conservative, as it assumes no cleanup, burning or other diminution of the spill amount. Within 24 hours, more than 50,000 barrels a day of oil spill recovery capacity could be on site and the HOSS barge system, which can recover 18,000 barrels a day by itself, could be deployed in a few hours. Conservatively, the well would be brought under control in 3 weeks in the unlikely event it were to blowout. There is a very large capability in and near Florida for cleanup and capture in 2 days; the use of 5 days allows for weather problems as well as setup of the HOSS barge, the use of 21 days is an outside limit worst-case scenario. The Department attempted to show a longer duration should be used based on a possibility that a relief well would be required to kill the flow. There has never been such a case in the U.S. Gulf of Mexico offshore areas in the last fifteen years in thousands of wells. The only such case pointed to, in Louisiana, involved a very complex multiple well production platform. The maximum probable rate of 1,654 barrels per day multiplied by the maximum probable duration of 5 days, or 8,270 barrels, is a maximum probable. It would be reasonable and reliable to use this as the maximum oil spill for calculating the amount of the surety because this exceeds by more than eight times the total spillage from all exploratory wells drilled in the United States Gulf of Mexico federal waters in the last 25 years. If the worst case situation were determined to be proper, the worst case rate of 5,948 barrels per day multiplied by the worst case duration of 21 days, or 124,908 barrels, is the volume of the worst case oil spill. No well in the history of the United States oil production has ever spilled more oil than this volume. Dr. French utilized the characteristics of a South Louisiana API gravity 35 crude oil, but the expected oil from the 45-50 API gravity oil from the Smackover geologic formation is a much lighter oil. Dr. French's use of this medium crude oil makes her conclusions very conservative because a greater percentage of the lighter oil will quickly evaporate. Dr. French used the wind record gathered by NOAA at a buoy near St. George Island, which is reasonable and reliable because these are actual winds recorded in the area by the federal government. Dr. French used water currents calculated from recorded winds, because there is no recorded current information. Currents in this area of the Gulf of Mexico are an insignificant factor. She used a hydrodynamic model provided by Dr. Wilton Sturges at Florida State University (FSU) and from that was able to obtain data on currents for the same area and time as the wind data for the analysis. By using the above factors, Dr. French used a maximum oil spill and the most adverse hydrographic and atmospheric conditions in her analyses which would be most likely to damage habitats in the area. Dr. French used depth data maintained and distributed by the U.S. Department of Commerce, National Geophysical Data Center. Finally, Dr. French used the digitized types and location of the habitats in the area she obtained from Dr. Jacqueline Michel, which maps and data were prepared for and accepted by the State of Florida and used by DEP in calculating its own habitat damages. With this data for the maximum probable and worst case scenarios, Dr. French ran 200 trajectory analyses for each of five times of the year from the wind record. Dr. French used this stochastic mode (trajectory analysis) to determine the potential or probability of any spot in the entire area to be touched by oil in any amount for each time of the year. This also allowed her to determine the transport time to any area and her analysis revealed two things with particular relevance: spills in June were the worst case in transporting oil toward shore and sensitive habitats; and that by the time oil got to Lighthouse Point to the east, the very light oil had weathered for eight days and what remained was in a nontoxic state. From the wind record Dr. French identified the most adverse winds for each scenario which would transport oil the fastest to shore so as to be least weathered and most toxic to maximize the habitat that could be damaged. The historic winds that would transport the oil the fastest to shore occurred beginning June 1, 1989, and were 12 knots to the northeast for the worst case scenario and to the north for the maximum credible scenario. This choice of wind was reasonable and reliable to use to maximize the habitat that could be damaged by each scenario because although winds in excess of this have occurred, winds greater than 12 knots entrain the oil and reduce its impact on habitats. The effects of high winds, including hurricanes, during a spill event is to hinder response efforts. Hurricanes themselves can have a beneficial effect of scrubbing clean the shoreline. Having identified the events with a maximum potential for damage to habitats near the Permit no. 1281 location, Dr. French ran specific data for each scenario to determine the actual habitat that would be damaged from the hypothetical spill. The runs of these two scenarios, that is, maximum credible and worst cases, identified the habitats that would be affected by the hypothetical spill. Dr. French utilized her model and analyses in deriving compensation estimates under the Florida Natural Resource Damage Assessment. She found, however, that the Formula is not clear on the appropriate threshold thickness where a habitat is considered oiled enough to be injured. The Formula, since it applies to damage assessment after a spill, would rely on field observations of actual, rather than forecasted, impacts to habitats. Based on scientific literature describing field observations after oil spills, Dr. French and her firm developed a model for federal natural resource damage assessments. That model includes a 14 millimeter threshold. DEP used a 1 millimeter threshold for its analysis, so Dr. French included runs of both thresholds in her application of the Florida NRDA compensation schedule. She opined, however, that a 1 millimeter oil slick would unlikely significantly injure a shoreline habitat or a submerged habitat, since in the latter habitat, exposure to oil is from entrained or dissolved oil in the water under the slicks. The results obtained by Dr. French under the scenarios applying the direction of spill likely to oil and effect the greatest amount of shoreline and habitat are as follows: NE 21 days NE 5 days (worst case) (maximum credible) > 14 millimeter $43,905,858 $ 2,781,318 > 1 millimeter $86,510,064 $ 2,930,214 Projected Cleanup Costs In addition to projected natural resource damage, Chapter 97-49, Laws of Florida, requires the surety amount recommended by DEP and adopted by the Administration Commission to include projected cleanup costs. In developing projected cleanup costs for the "maximum oil spill" DEP initially contacted several industry trade groups and corporations experienced in oil spill cleanups. The unanimous response was that no two spills are alike. There are so many variables to take into account that it is impossible to find an "average" cost for cleanup of an oil spill. The agency then looked to the recent experience of the 1993 Tampa Oil Spill, resulting from a collision of barges and a tanker, spilling heavy, persistent, no. 6 fuel oil. Specifically, DEP looked to what it had: an unaudited reimbursement claim for cleanup submitted by the responsible party in the amount of $53,000,000. The actual amount spent on cleanup of the Tampa Bay Oil Spill may be over $70,000,000. However, since the reimbursement claim had not yet been audited to verify the amounts claimed, DEP conservatively used the lower number. The agency then divided the smaller number ($53,000,000) by 14, the number of miles of affected shoreline. Then, again in light of the uncertainty as to what might have been included in the reimbursement claim, the Department further reduced the amount by nearly a third, resulting in $2.5 million per mile of shore to be cleaned. That amount, when multiplied by the 222.8 miles of linear coast within DEP's spill boundary for a Coastal spill, produced a figure of $557,000,000. That calculation excluded an additional 20 miles of seawalls that required pressure cleaning as a consequence of the Tampa spill. In determining the extent of shoreline requiring cleanup, DEP utilized a linear coastline measurement, rather than measuring the sinuosity of the shoreline. This linear coastline measurement thus conservatively excluded additional miles attributable to rivers, inlets, bays and streams. In contrast, Dr. French's trajectory model predicts real shoreline effects. The DEP cleanup estimate, like its damage estimate, is flawed and unreliable. It is based on a unique event with little in common with the circumstances surrounding any possible Coastal well blow out. Cleanup costs are highly related to the type of oil spilled, the geography of the area in which it is spilled, and the rate of the spill, among other factors. The Tampa Bay spill was a complex event involving a collision of three ships and a fire. The oil released was very heavy, with an API gravity of 10.5, a sticky viscous, coating substance which persists on the shoreline. Often no shoreline cleanup is attempted for lighter oils as they tend to be washed off by the tides and small storms, and mechanical interference often exacerbates the damage. The DEP estimate of shoreline length is based, not on an actual trajectory study, but on a misunderstanding of earlier Coastal submittals and a "thumbnail guess." Jacqueline Michel was Coastal's expert regarding cleanup costs. She has a Bachelor's degree in geology, a Masters in hydrogeology, and a Ph.D. in geochemistry, and she has been involved in oil spill cleanup and response and assessment since 1976, including Ixtoc's effect in South Texas, the Exxon Valdez, and the Tampa Bay spill referenced above. She and her company are part of a government response team under contract with the federal government, and she is involved in about 50 oil spills a year, from various causes, all over the world. Dr. Michel's company has developed a digitized data base creating an atlas of oil sensitive habitats, biological resources and human resources that might be sensitive to an oil spill. Called Environmental Sensitivity Index (ESI) maps, these data collections are obtained from existing agencies with whom the company works closely to assure that the collections are accurate and usable. One such agency is the Florida Marine Research Institute (FMRI), within DEP. Dr. Michel's cleanup costs assessment for Coastal included these steps: Obtain information on the duration and coverage of oil slicks on water and the areal and lineal extent of shoreline oiling by habitat type from the trajectory modeling work by Applied Science Associates, Inc. (ASA, 1997)(Dr. French) Obtain unit costs for labor, equipment, supplies, etc. from published summaries (Etkin, 1994), spill response contractors, and other vendors. Derive level of effort estimates for different types of response and cleanup efforts, from documentation of previous spills and guidelines provided by spill response contractors in the Gulf of Mexico. Use unit costs and level of effort to estimate daily costs for different components of a response and cleanup operation. Components included: On-water recovery (both offshore and nearshore skimming operations); Shore-based support for skimming operations and handling/disposal of recovered liquids; Commercial aircraft support for overflights; Shoreline cleanup operations, including bird rescue and cleaning; Federal agencies' cost for response; -U.S. Coast Guard (including the National Strike Force) -U.S. Navy -National Oceanic and Atmospheric Administration -Department of Interior -U.S. Environmental Protection Agency State agencies' cost for response Disposal of oily wastes Develop total costs for the two release scenarios; and Compile recent oil spill costs for representative spills and develop tables on costs/gallon spilled. (Coastal Exhibit no. 394) Dr. Michel's estimate included cleanup of oil with a thickness of 1 millimeter or greater since this thickness is assumed to generate sheens that respond to sorbents and sorbent booms in marshes and manual or mechanical removal from beaches. No oil recovery off-shore was considered in the analysis of the amount of shoreline contamination, resulting in a conservative, credible estimate. Based on trajectory data provided by Dr. French and the resultant "worst case" and "maximum probable" scenarios Dr. Michel determined cleanup costs of $137,968,507 (worst case) and $19,713.046 (maximum probable). A "Reasonable" Surety Returning to the Formula in Chapter 376.121, Florida Statutes, the most significant difference between DEP's methodology and Coastal's is the assignment of a value for volume. In spite of its being a real life example of a maximum oil spill, Ixtoc I is not a reasonable source for deriving the volume of a maximum oil spill at the proposed permit site. That "it happened" does not mean that it will happen here. The geology and geography of the site, the level of regulatory scrutiny, and the quality of staff and equipment proposed by the applicant and required by the agency, must be considered to determine a "reasonable" surety specific to this single well- drilling permit. Volume in Dr. French's application of the formula was derived from the most relevant data available: wells drilled in the target Smackover formation 140 miles to the northwest. While the "maximum probable" scenario she adopted is plainly more likely, her "worst case" scenario better effectuates the legislature's directive that the surety be based on a "maximum oil spill." For reasons discussed above, Dr. French's trajectory method is credited and best reflects the "adverse hydrographic and atmospheric conditions that would tend to transport the oil into environmentally sensitive areas." Her trajectory established that oil from a 21-day worst case spill would reach almost the same distances as DEP's projection, but she reasonably factored the density of the oil and determined that its toxicity, and damage potential would be mitigated by the time most of the shoreline was oiled. It is highly unlikely that injury to most habitat will occur with a threshold thickness of less than 14 millimeter of oil, but competent evidence of the sensitivity of nursery and breeding habitat and of organisms related to early stages of the life cycle of shellfish and other creatures, supports adopting the more conservative scenario, with 1 millimeter thickness of oil. Appropriately, and consistent with DEP's application of the formula, Dr. French considered a factor of 2 for "special management area" since a hypothetical discharge will originate outside of a special management area but will impact natural resources within the Apalachicola Bay special management area. Dr. French, like DEP, considered a factor of 4 for the category of pollutant (category 2, in the statute includes crude oil). The Formula does not refine categories of crude into light or heavy API density, but if it did, the light crude anticipated from the source at issue would likely merit a factor of 2 or 3. In her trajectory model, Dr. French assumed the density of Louisiana crude, a heavier, less volatile oil, rendering her results as to area coverage very conservative. In summary, the most reasonable, best-supported estimate of natural resource damages resulting from a "maximum oil spill and adverse hydrographic and atmospheric conditions that would tend to transport the oil into environmentally sensitive areas" is $86,510,064. (Coastal Exhibit no. 391, tables 5.6 and 5.12) $86,510,064, added to Dr. Michel's "worst case" response and cleanup estimate of $137,968,507, plus $10,000 DEP administrative costs, results in a reasonable surety amount of $224,488,571. Costs and Attorney's Fees Both Coastal and the Environmental Petitioners have included requests for costs and attorney's fees in their respective petitions. This lengthy proceeding, competently and diligently tried by all parties, yields no evidence of bad faith or improper purpose or any other basis for award of fees cognizable under Chapter 120.
Recommendation It is hereby RECOMMENDED: That a final order be entered by the Department of Environmental Protection granting Permit no. 1281, with the conditions described in paragraphs 74 and 75 and a surety to be established by Final Order of the Administration Commission in the recommended amount of $224,488,571. DONE AND ENTERED this 8th day of April, 1998, in Tallahassee, Leon County, Florida. MARY CLARK 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 Filed with the Clerk of the Division of Administrative Hearings this 8th day of April, 1998.
