Section 096-600-9 - Standard Operating ProceduresA.Transfers Between Land Based Oil Terminal Facilities and Vessels.(1) Personnel. For transfers at an oil terminal facility, the facility must provide the transporter with a written transfer procedure. This procedure must be acknowledged in writing by the transporter. A transfer is considered to begin when the person in charge on the transferring vessel or facility and the person in charge on the receiving facility or vessel first meet to begin completing the declaration of inspection.(2) Inspections. Inspections are required at the beginning of each transfer and as needed to verify the tightness of the loading and offloading lines, valves, and other attached apparatuses. Inspection logs must be retained at the facility for at least 3 years.(3) Tank Capacity. Persons transferring oil shall assure that the high level alarms on the receiving tank are set at such a level that if an alarm should occur during the oil transfer there would be sufficient time to shutdown the oil transfer operation prior to overfilling the tank. This alarm level must be verified to the Department's satisfaction by a signed agreement with the local fire suppression agency or by demonstrating that there is sufficient shutdown time to the Department.(4) Bonding Cable. Pipelines on wharves must be adequately bonded and grounded if Class I or Class II liquids are handled. If excessive stray electrical currents are encountered, insulating joints must be installed. Bonding and grounding connections on all piping must be located on the wharf side of the hose riser insulating flanges. The bonding cable must incorporate a meter or other suitable positive means of determining a ground. Typical methods for protection against stray current hazards at wharves are illustrated in API RP 2003, Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents. Any bonding cable employed between the wharf piping and the vessel must employ an explosion-proof switch as a method of completing the connection. Insulating flanges properly installed in accordance with API 2003 can be used instead of a bonding cable to isolate the vessel from the terminal piping during product transfers across the pier.(5) Safe Transfer Operations. Oil transfer operations are not permitted when any of the following conditions arise: (a) If any weather-related condition develops that, in the opinion of the dock watchman, terminal supervisor or watch officer, is too severe for operations to be safely continued;(b) If a fire occurs on the dock, tank vessel, adjacent tank vessel, or in the nearby vicinity;(c) If a tank vessel breaks loose or if another vessel comes alongside which is not under control or is emitting sparks from its stack or is apt to collide or to otherwise present a hazard to the tank vessel in berth at the terminal;(d) If an oil spill occurs aboard the tank vessel, an adjacent vessel, or on the dock, or if a leak develops in a joint of hoses or piping which is not able to be stopped by tightening;(e) If in the opinion of the dock watchman, terminal supervisor, or watch officer a vapor condition develops aboard or around the tank vessel or dock which would be too serious to safely continue operations;(f) If any other emergency occurs which, in the opinion of the dock watchman, terminal supervisor, or watch officer constitutes a potential hazard to the tank vessel or facilities; or(g) If at any time the high level alarm system within the terminal activates to warn of a possible or pending overflow.(6) Illumination. A person may not transfer or cause to be transferred or consent to the transfer of any bulk oil after dark unless the point of transfer is illuminated to a minimum standard of 50 lux.(7) Open Hatch Transfer. Transfer of oil by means of a hose through an open hatch is prohibited. An exception may be made only when an emergency arises and this is the only means available to move oil from one vessel compartment to another or to unload oil from a vessel for purposes of reducing or preventing pollution, or for preventing foundering. Such emergency exceptions are allowed only when all possible precautions to prevent discharge to the waters of the State have been taken. The owner or operator shall notify the Commissioner or the Commissioner's designee and the local fire suppression agency prior to commencing such emergency transfer operations.(8) Sample Collection. A terminal operator may not transfer or cause to be transferred or consent to the transfer of any bulk oil until a sample of the oil to be transferred has been collected, identified by proper labeling, and stored in a place acceptable to the Department. Oil terminal facilities with automatic sampling capabilities are not required to presample. The sample must be stored for a minimum of fifteen days. The Department shall determine the information to be provided with each sample and may require chemical analysis of the sample. Sampling must be done in accordance with Appendix B. Samples must be stored at the facility or at the lab where the samples are analyzed in accordance with chain-of-custody protocols.(9) Anticipated Transfer. The terminal owner or operator shall notify the Supervisor of the appropriate Department Regional Office of the Division of Response Services, at least 12 hours in advance of any transfer of bulk oil. The notification must include the following information:(a) Terminal name and location, or anchorage if the transfer will be offshore;(b) Approximate amount of oil to be transferred;(e) Expected time and date of vessel arrival(s). Should unusual circumstances make it impossible to provide 12-hour notice, the terminal operator shall notify the Commissioner as soon as possible. Notification is not required for bunkering.
(10) Declaration of Inspection. A copy of any "Declaration of Inspection" required by the United States Coast Guard for a tank vessel transferring oil at an oil terminal facility must be in the possession of the terminal operator or the operator's representative and must be available to the representative of the Commissioner who shall, on demand, be given the opportunity to verify that the condition of the vessel is as stated in the "Declaration of Inspection."(11) Other Reports and Forms. The oil terminal facility operator shall also complete and submit such other forms, checklists, and reports as the Commissioner may require.(12) General Safety Provisions. (a) Signs. During the time a tank vessel is in berth, a warning sign carrying letters not less than 2 inches high on a contrasting background must be displayed on the dock and near the gangplank. This sign must read substantially as follows: WARNING-NO OPEN LIGHTS, NO SMOKING, NO UNAUTHORIZED VISITORS.(b) Hazardous Vapor. When in the opinion of the terminal operator or the Commissioner's representative a hazardous vapor condition develops on a dock or on any vessel, all transfer operations involving such vessels must be stopped and all sources of ignition such as smoking, use of matches, lighters and open flame except boiler fires must be eliminated and prohibited.(c) Transfer of Sour Crude. An oil terminal facility must take special precautions for the transfer of sour crude oil to minimize the release of vapors during the transfer period.(d) Multiple Vessel Mooring. A tank vessel may not be secured alongside another tank vessel at a pier except while taking bunker fuel aboard. A tow boat must stand by alongside or in the notch during the transfer of bunker fuel from a bunker vessel to a tank vessel. The bunkering vessel must be moved away from the tank vessel immediately after completion of the loading process.(13) Vessel Pre-Transfer Conference. A person may not commence or consent to the commencement of bulk oil transfer operations at an oil terminal facility unless the following items have been reviewed, agreed upon and complied with by both vessel and facility personnel:(a) A sufficient number of adequately trained oil terminal facility personnel are assigned to be constantly on duty during cargo transfer operations to keep the transfer operation under constant observation and to ensure immediate action in case of a malfunction;(b) Cargo sequence for loading or discharging products and the proper pipe for each product must be established;(c) The handling rate at which oil will be transferred must be established. Reduced rates are required when commencing transfer, changing the lineup, topping off tanks or nearing completion of transfer. The amount of time to be given when the vessel or terminal desires to start, or stop, or change the rate of flow must be determined;(d) A positive communication and signal system must be operable during transfer operations;(e) The emergency procedures to be followed in order to stop and contain any discharge must be established;(f) Vessel and facility personnel responsible for transfer shall always be clearly identifiable. Prior to transfer operations, terminal and vessel personnel responsible for transfer shall be made known to each other; and(g) The oil terminal facility must have written operation guidelines pertaining to dock operations for vessels coming to or alongside its dock during abnormal weather conditions.(14) Transfer Hoses. A person may not transfer or cause to be transferred or consent to the transfer of any oil between an oil carrying vessel and an oil terminal facility unless the following conditions are met:(a) All oil terminal facility transfer hoses must be of a type designed specifically for the oil transferred. Transfer hoses must be tested annually to 1.5 times the maximum working pressure (i) For pipe that can be visually examined, the test pressure must be maintained for a minimum of 10 minutes and held for such additional time as may be necessary to conduct the examination for leakage, or(ii) For pipe that is buried or insulated and cannot be visually inspected, the pressure must be maintained for one hour.(b) As provided for below, each oil terminal facility hose must be marked with:(i) The products for which the hose is to be used for or the words "oil service";(ii) Maximum allowable working pressure;(iii) Date of manufacture; and(iv) Date of the most recent test performed. The information described in subparagraphs (i-iv) above need not be marked on the hose if it is recorded elsewhere in the hose records at the facility and the hose is marked to identify it with the location of that information. The logbook or records must be available for inspection on demand by a representative of the Commissioner.
(c) Hoses must be supported to avoid crushing or excessive strain. Flanges, joints, and hoses must be checked visually for cracks and wet spots before each use.(d) Oil terminal facility hose handling rigs must allow adjustment for vessel movement and hoses must be long enough so that they are not strained by any movement of the vessel.(e) Hose ends must be blanked tightly when hoses are moved into position to be connected and immediately after they are disconnected, and must be drained either into the vessel tanks or into suitable shore receptacles before they are moved away from their connections.(f) Hoses may not be permitted to chafe on the dock or vessel or be in contact with hot surfaces such as steam pipes. Hoses may not be exposed to any sources of corrosion.(g) Hoses no longer in service must be removed from the transfer area.(15) Mooring Lines. Mooring lines must be tended during transfer operations to prevent excessive movement of the vessel.(16) Fire Main Connections. Serviceable fire hose sufficient to reach all parts of the vessel and dock with approved combination nozzles attached must be connected to the fire main on the vessel and/or on the dock and be ready for instant use during the time a vessel is in berth. The fire main must have a master valve at the head of the dock so the fire main can be kept dry in cold weather and wet in warm weather. The fire main on the dock must be at least 6 inches in diameter. The fire main must always be charged to the master valve. The owner or operator of an oil terminal facility not meeting these requirements shall file an alternate fire protection plan with the Department. The alternate plan must be approved by the State Fire Marshal's Office or local fire suppression agency.(17) Fire Wires. During transfer operations, fore and aft fire wires must be rigged on the offshore side of the vessel for use by tugs in removing the vessels from the pier in event of fire.(18) Vessel to Shore Transfer. A person may not transfer or cause to be transferred or consent to the transfer of any bulk oil from any tank vessel to a land based oil terminal facility unless: (a) All cargo risers not intended for use in the transfer are blanked;(b) Sea valves connected to the cargo piping and stern loading connections are tightly closed and sealed with a numbered seal which is logged in the logbook of the vessel;(c) Piping and valves in the pump rooms and on deck are checked by the master of the vessel, senior deck officer or deck officer on duty, or licensed tanker man to see that they are properly set for discharging cargo. An additional check must be made for the same purposes each time the setting is changed;(d) Full rate of transfer is not attained until shore lines are proven clear; and(e) On completion of transfer operations, hoses or other connecting devices are drained of the remaining oil. A drip pan must be in place when breaking a connection and the end of the hose or other connecting devices must be blanked off before being moved.(19) Shore to Vessel Transfer. A person may not transfer or cause to be transferred or consent to the transfer of any bulk oil from a land based oil terminal facility to any tank vessel unless: (a) All sea valves connected to the cargo piping, stern discharge and ballast discharge valves are closed and sealed with a numbered seal which is logged in the logbook of the vessel and with the responsible vessel officer of the vessel;(b) All hose riser valves not to be used in the transfer are closed and blank flanged, and all air valves on headers are closed;(c) During the topping off process, special attention is paid to the loading rate, the number of tanks open, the danger of air pockets and the inspection of tanks already loading. Shore personnel must be given notice of the slowdown for topping off; and(d) Upon completion of loading, all tank valves and loading valves are closed. After draining, hoses must be disconnected and hose risers blanked.(20) Scuppers. A person may not transfer or cause to be transferred or consent to the transfer of any bulk oil between a tank vessel and a land based oil terminal facility unless the scuppers of the vessel are plugged watertight during the oil transfer operation, except on tank vessels using water for deck cooling. However, it is permissible to remove scupper plugs as necessary to allow run-off of water provided a vessel crew member stands watch to re-close the scuppers in case of an oil discharge.(21) Tank Tops and Hatch Covers. When transferring oil, tank tops and hatch covers must be closed. Ullage caps or plugs may only be opened on tanks that are to be loaded or unloaded and all open ullage holes must be covered with flame screens which must be kept in place during the transfer except for the minimum time necessary to observe transfer progress, take samples or take ullage readings. If a tow boat or other vessel such as a bunker barge or lighter is moved alongside for the purpose of serving the vessel, and if that tow boat or other vessel is steam propelled or propelled by an internal combustion engine, tank tops, tank hatches and ullage plugs or caps must be kept open only on those tanks from which oil is being withdrawn. Any such open ullage plugs or caps must have flame screens in place. When there is no longer any possibility of sparks or other source of ignition, normal procedure may be resumed.(22) Ports and Doors to Crew Quarters. When loading and unloading oil, all ports and doors facing the cargo decks or facing a breeze bringing vapors from another vessel must be closed except to allow for passage of personnel.(23) Blowing of Boiler Tubes. During transfer operations, blowing of boiler tubes or other work on the boilers which could cause the emissions of sparks or soot from the stacks is prohibited.(24) Spillage During Transfer. Transfer operations must cease if a discharge of oil to the waters of the State occurs during such transfer. Operations may resume when, in the judgment of the Commissioner's representative adequate steps have been taken to control the discharge and to prevent further discharge. In making this judgement, the Commissioner's representative may consult with the United States Coast Guard or Local Fire Chief, if necessary.(25) Contingency Plan. Each owner or operator of an oil terminal facility shall have available for inspection by the Commissioner or a representative of the Commissioner, a copy of any oil discharge response plan required to be submitted to the President of the United States under the federal OPA 90.(26) Operations Plans. The owner or operator of each oil terminal facility shall have an operations plan available for inspection upon request of the Commissioner or representative of the Commissioner. The operations plan must describe in detail the equipment and procedures used at that terminal for the prevention of oil spills and the protection of the public health, safety, welfare, and environment.(27) Spill Prevention Control and Countermeasure (SPCC) Plan. The owner or operator of an oil terminal facility shall comply with all the requirements of the Spill Prevention Control and Countermeasures Plan in Oil Pollution Prevention, 40 C.F.R. pt. 112, incorporated by reference herein.(28) Inventory Records and Fees. Records of all monthly fees paid to the Maine Ground and Surface Waters Clean-up and Response Fund for all applicable product transfers, annual reports on transfers, and third party observer records must be available for inspection upon the request of the Commissioner or a representative of the Commissioner. All inventory records must be retained for a minimum of 10 years. Fees on transfers must be paid monthly and accompanied by the applicable Department form. If no transfers are received during a month, the form must be filed with the Department stating that no transfers occurred. In the case of an enforcement action, the record retention timeframe is automatically extended until the action is resolved.B.Booming of Vessels(1) All tank vessels and tank barges, engaged in transfer operations, must be protected by an oil boom device to catch and contain oil discharges. The boom must completely surround the vessel at a minimum distance of 50 feet from the vessel and be secured in place by sufficient anchors, except:(a) When engaged in the actual vessel to vessel bunkering operations while at anchorage;(b) When personnel safety conditions, weather, wind, sea, or ice conditions are such that a boom is not able to be wholly or partially deployed, and the terminal operator reports this fact to the Commissioner. Reporting must be prior to transfer, whenever conditions develop which require removal of the boom, or when conditions are such that only a partial boom is appropriate to deploy. If the Commissioner's offices are closed, reporting must be on the next working day following the transfer; or(c) When a portion of the oil has a flash point of -45symbol 176 \f "Symbol" F or less, and an ignition temperature of 536symbol 176 \f "Symbol" For more, such as gasoline.(2) The boom used to enclose the tank vessel must be of a type suited to the conditions of wind, currents, and waves found at the transfer site at the time the transfer takes place, and must be capable of retaining the maximum most probable discharge from the tank vessel under the conditions normally found at the transfer site at the time the transfer takes place unless subparagraph (1)(b) applies. Maximum most probable discharge means a discharge of: (1) 2,500 barrels of oil for a vessel with an oil cargo capacity equal to or greater than 25,000 barrels; or(2) 10% of the vessel's oil cargo capacity for vessel with a capacity of less than 25,000 barrels.(3) If a terminal operator believes it is impossible or wholly impracticable to implement the booming requirement in whole or in part on a regular basis, the operator may apply to the Department for complete or partial exemption from this requirement. The marine oil terminal application must set forth in detail the reasons why such complete or partial exemption should be granted. The Department may set any reasonable conditions in granting any such exemption.C.Land Based Oil Terminal Facilities.(1) Inventory Control/Overfill Protection.(a) Inventory Reconciliation. The liquid level in a tank must be gauged at least once every 7 days and the measurements compared to previous readings. A record of the measurements must be maintained for inspection by the Commissioner or representative of the Commissioner. Tank gauging also is required prior to any delivery of oil into a storage tank at a facility.(b) Mandatory Loss Reporting. Any liquid level measurements that, after reconciliation of inventory, indicate a loss of liquid of at least 0.5% of throughput on a monthly basis, must be immediately investigated. This investigation must include determining if a loss of material has occurred, the estimate of how much material is unaccounted for, the reason for the loss, and what happened to the material. The potential loss of material in excess of 0.5% must be reported to the Commissioner: (i) Within 24 hours of discovery of the potential loss, if the investigation is not concluded, or(ii) Within 2 hours of discovering that the loss was a result of a spill or leak. All investigations for potential loss of material in excess of 0.5% must be kept on file for review by the Department.
(c) Overfill Prevention. Tank overfilling must be prevented by the following measures: (i) High liquid level alarm with audible and visual signals; and(ii) High-high liquid level alarm with audible and visual signals.(d) Overfill protection systems must be tested before each transfer or monthly, whichever is the least frequent.(2) Maintenance and Inspection. Prior to operation and as a condition of continued operation of an oil terminal facility, a maintenance and inspection program must be implemented by the facility operator as follows: (a) Daily visual inspection of aboveground tanks, piping, equipment and discharge control devices and surrounding areas to detect possible oil discharges and to determine and carry out any maintenance necessary to prevent discharges from occurring. The operator shall make a list of daily inspection procedures and inspection logs available upon request of the Commissioner or representative of the Commissioner.(b) A documented monthly visual inspection of the facility, including but not limited to, tanks and all ancillary devices (vents, water drawoff, etc.), valves, piping, spill containment dikes and other spill holding areas, oil/water separators and equipment.(c) Monthly visual tank inspection, including, but not limited to the following: (i) Inspection of exterior surfaces of tanks for discharges and maintenance deficiencies;(ii) Identification of cracks, wear, corrosion, thinning, poor maintenance and operating practices, settlement, swelling of tank insulation, malfunctioning equipment, structural or foundation weaknesses; and(iii) Inspection and monitoring of discharge detection systems, or warning systems.(d) Tank De-watering. An appropriate schedule for removal of water from tanks must be included in the maintenance and inspection program. Maintenance to remove water from tanks must be appropriately handled. Discharge of water from tank bottoms must be to an appropriate treatment facility. Oil removed from the tank as part of the water bottom drawoff maybe returned to the tank.(e) Cathodic Protection System. A monthly inspection must be performed on any impressed current cathodic protection system. Monthly voltage and current readings must be in the range to provide adequate cathodic protection levels per NACE SP0169 for underground piping or NACE SP0193 for above ground storage tanks. An annual structure to soil and structure to structure potential test must be performed by a cathodic protection tester for impressed current systems as well as annual structure to soil potentials for galvanic systems. All readings and repairs must be documented and made available at the time of the inspection and submitted to the Department at the request of the Commissioner or the Commissioner's representative.(f) Underground Piping. All underground oil piping must be inspected or tested to verify the integrity of the piping in accordance with API Standard 570, Piping Inspection Code: In-Service Inspection, Rating, Repairs and Alternation of Piping Systems. Verification by pressure testing must consist of holding pressure at 1.5 times the maximum operating pressure for a period of one hour on an annual basis. Verification by use of internal inspection devices designed to verify the structural integrity of the pipe by measuring pipe wall thickness and indicating geometric irregularities of the piping is an acceptable alternative. Verification by the use of internal inspection devices must be performed no more than 5 years from the most recent internal inspection and every 5 years thereafter. Pressure testing or internal inspection is not required on underground piping equipped with secondary containment or a leak detection system. The Commissioner may also require testing if there is reason to suspect a discharge.(g) Aboveground Piping Tightness Testing. Tightness testing is required for aboveground piping no more than 10 years after installation and every 5 years thereafter in accordance with API 570. Aboveground piping must be hydrostatically pressure tested to 1.5 times the maximum operating pressure for a period of one hour. For the purpose of this paragraph a hydrostatic pressure test may be performed using hydrocarbon product or water. Verification by use of internal inspection devices, designed to verify the structural integrity of the pipe by measuring pipe wall thickness and indicating geometric irregularities of the piping, is an acceptable alternative. Verification by internal inspection devices must be performed no more than 5 years after the most recent internal test and every 5 years thereafter. If the piping, including insulated piping, can be visually inspected 360 degrees around over its entire length, then tightness testing is not required.(h) Internal Tank Inspection. All field constructed tanks must be internally inspected as follows: (i) Tanks with an RPB that have no internal tank bottom liner, no cathodically protected bottom, and that do not contain # 6 fuel oil or asphalt must be internally inspected no more than 10 years after a prior internal inspection, and every 10 years thereafter;(ii) Tanks with an RPB, an internal tank bottom liner, a cathodically protected bottom, and that do not contain # 6 fuel oil or asphalt must be internally inspected no more than 20 years after a prior internal inspection, and every 20 years thereafter;(iii) Tanks containing #6 fuel with or without a cathodically protected bottom must be internally inspected no more than 20 years after a prior internal inspection, and every 20 years thereafter;(iv) Tanks containing asphalt with or without a cathodically protected bottom must be externally and internally inspected no more than 20 years after a prior external/internal inspection, and every 20 years thereafter.(i) Internal inspections must be in accordance with API 653. If, during an inspection, evidence is found of a change from the original physical condition of the tank, then the suitability of the tank for continued service must be evaluated in accordance with API 653. Internal inspections and suitability for service evaluations must be conducted by an API 653 certified inspector. Inspection records must be retained for review by the Commissioner or representative of the Commissioner. Any hole or failure of a tank or piping must be reported to the Department.(j) For the purpose of this Chapter, the following inspection requirements must meet the intent of API 653, Section 6.5, Alternative to Internal Inspection to Determine Bottom Thickness for Asphalt Tanks. (i) Inspections for indications of asphalt seepage and foundation stability, such as erosion or fill migration or settlement, must be performed around the exterior perimeter of the tank where the tank floor is flush with the ring wall foundation or pad foundation. For the purposes of this Section, the pad foundation refers to earth or concrete.(ii) The area around the external shell to floor joint must be inspected for indications of seepage or cracked weld seams.(iii) If the tank wall or floor is of riveted construction, rivets must be inspected for indications of seepage or corrosion which could indicate a rivet losing strength. Insulation must be temporarily removed to allow inspection of rivets at 10 to 16 locations. If the inspection reveals a significant number of leaking rivets, a weep for walls and 25% of the 10 to 16 locations for a floor, then an expanded detailed inspection plan must be prepared and submitted to the Department for approval. Subsequent inspections must consist of inspection locations in areas not previously inspected. Repair of leaking rivets may be made using the best acceptable industry practices in use at that time. Thermal expansion and contraction of the shell, rivet and hole must be accounted for in determining the proper repair procedure.
(iv) The tank perimeter must be inspected for indications of tank settling such as floor or shell deformations. If the exterior of the tank is insulated, inspections for shell deformation must be conducted from the interior of the tank. The exterior floor elevations must be checked at 8 evenly spaced locations around the perimeter of the tank using a level. Records of the elevations must be maintained for comparison with measurements taken during subsequent inspections to detect any long-term settling.(v) Floor thickness must be measured at 6 to 8 locations distributed throughout the interior bottom. At least one of these points must be within 6 inches of the shell. Asphalt at these points must be removed to expose bare metal. If there is any evidence of external or internal corrosion of the tank shell or floor, the floor thickness must be measured at the suspected point of minimal floor thickness. The minimum floor thickness observed must be used to compare with acceptable minimum thicknesses. If corrosion is present, allowances must be made for future metal loss in determining whether to replace the tank bottom or schedule for the next inspection.(vi) In the event that inspection of the tank reveals weld cracks, leaking rivets or other indications of joint failure, the entire floor must be cleaned and inspected, or replaced with a new floor in accordance with API 653.(vii) The inspection of the balance of the tank and any repairs or modifications must be in accordance with API 650 and 653.(3) Steam or Heating Devices. A person may not discharge exhaust steam containing oil from any coil or other device used to heat oil either directly or indirectly onto lands adjacent to or into any surface or ground waters of the State.(4) Records. Owners or operators shall maintain records documenting required training, inspections, tests, maintenance and repairs. Unless otherwise specified, such records must be kept on file at the facility for a minimum of three years and must be available for inspection upon the request of the Commissioner or representative of the Commissioner. In cases involving enforcement action, the three-year period for maintaining such records is automatically extended until the action is resolved.(5) Financial Responsibility Requirements. (a) Financial Assurance for Closure and Remediation Costs. The Commissioner requires evidence of financial assurance in the amount of at least $2 million per facility as a condition of an operating license to ensure proper closure and remediation of facilities. This evidence must accompany any new, renewal or transfer application for a marine oil terminal license. Financial assurance can be established, subject to the approval of the Commissioner, by any combination, of the following: insurance and risk retention group coverage, guarantee, surety bond, letter of credit or trust fund. In determining the adequacy of evidence of financial assurance, the Commissioner shall consider the financial mechanisms in 40 C.F.R., §§ 280.96 through 280.99 and 280.102 through 280.103 except the term "underground tank" or "UST" must be replaced with or include the addition of, "aboveground tank" or "AST", as applicable. Any bond filed must be issued by a bonding company authorized to do business in the United States. Any guarantee must specify the relationship of the entity providing the guarantee to the licensee and applicant. Financial instruments must also be updated when estimated costs for closure and remediation of the facility change, at license renewal, or prior to expiration dates or non-renewal of the financial instruments, and in the case of guarantee on an annual basis.
The Commissioner may require a change in the amount of financial assurance required if after a review of a preliminary closure plan and engineering assessment of probable closure and remediation costs the review indicates a change in the requirement would be appropriate.
(b) Preliminary Closure Plan. A preliminary closure plan must accompany the financial assurance instrument and must detail the approach for completing closure in accordance with Section (12)(D) of this Chapter. The plan must include an engineering assessment of probable closure costs completed in support of this Section, and that must include a detailed cost analysis of all closure and remediation actions. The engineering assessment must include:(i) For any underground piping proposed to remain in place, a feasibility assessment for removal of underground piping in accordance with Section (12)(D)(2) of this Chapter, including the supporting rationale;(ii) The removal of all underground piping not covered by (i) above;(iii) The removal of all tanks and aboveground piping;(iv) The cost for removal of all ancillary equipment such as oil water separators, transformers, additive tanks, and containment structures;(v) The cost of an investigation into contamination from spills, releases and disposal activities that have occurred on the site;(vi) The cost of removal of contamination and cleanup of the site for expected areas of contamination and where a discharge has occurred, such that the facility site is suitable for the most protective use level (generally residential use, although occasionally a different use has more protective levels). Where contamination is likely to discharge to surface water or ground water, the cost to clean up to applicable cleanup standards protective of surface water and ground water; and Note: For purposes of demonstrating adequate funding in a financial assurance mechanism to fully complete closure, the preliminary closure plan and associated cost estimate is intended to be a conservative view of what actions will be necessary to complete closure. The assumptions used in arriving at the cost estimate associated with the preliminary closure plan may vary from the actual site conditions at the time of the final implementable closure plan. A preliminary closure plan is a future looking plan. The closure plan in Section (12)(D) of this Chapter is a plan that would be implemented at closure with consideration of actual site conditions at the time of closure.
(vii) A contingency amount of 25%. The engineering assessment may not consider the salvage value for scrap metal, used equipment, additives or other wastes including waste oils. The engineering assessment must include costs for the required work to be performed by a third party.
Note: Consult Standards for Owners and Operators of Hazardous Waste Treatment, Storage, and Disposal Facilities, 40 C.F.R. § 264.142, Cost Estimate for Closure for assistance in conducting a cost estimate. Other documents that provide helpful information are RCRA, Superfund & EPCRA Call Center Training Module (Introduction to RCRA Financial Assurance), Items to Submit for RCRA Closure Cost Estimate, and Transmittal of Interim Guidance on Facilities Subject to RCRA Corrective Action. Each of these documents includes information on cost estimating, the types of financial instruments and other general financial guidance.
(c) Liability Insurance Requirements. Owners or operators shall maintain a minimum of $1,000,000 per occurrence and $2,000,000 annual aggregate in liability insurance exclusive of legal defense costs, for third parties to address damage to their property or personal injury. The Commissioner may require at their sole discretion, if deemed appropriate, an increase in the amount of liability insurance when taking into consideration such factors as the size and location of the facility and the proximity of neighbors and sensitive resources to the facility. Insurance policies must provide full coverage of the facility without exclusions or limitations including exclusions for self insured retention for a portion of the policy and loading or offloading exclusions. Documentation of liability insurance must be submitted with the license application, when the policy changes, and upon request of the Department. Documentation must include a certificate of insurance and the signed insurance policy in effect.06-096 C.M.R. ch. 600, § 9