Production facilities. "Facility specific contingency plans are not practicable in many cases, particularly as they relate to onshore oil production operations. The profitability of these operations, especially stripper operations, would be utterly destroyed by the costs associated with preparation, implementation, review, revision, and other work associated with contingency planning." (42, 58)

Production flowlines and trunklines. "Language should be included that excludes production flowlines and trunklines from this requirement. At most production facilities, dikes are installed around tank batteries, but not around flowlines because it is impractical to do so. As written, the regulation would require submission of spill contingency plans for all such facilities." (167)

Rack to tank piping. "Proposed section 112.7( d) does not specifically address pipes running from the terminal rack to a tank( s), that will be by necessity outside of secondary containment. IFTOA believes that the facility should maintain a contingency plan to address potential discharges from such pipes reviewed and certified by the PE." (54)

Clarifications.

Contingency plan vis a vis Facility Response Plans. Asks if we intend the terms facility specific response plan and contingency plan as used in the preamble to mean the same thing. (54)

Costs. Contingency planning is not practicable because the costs are too high. However, these commenters did not provide specific cost estimates. (42, 101, 110, 113, 114, L15) We should "be sensitive to the interest and concerns" of small businesses in developing the Phase Two rule. (48) "It is recommended that the Agency's current strategy of requiring elementary contingency planning steps be continued for SPCC Plans for small facilities." (101)

Dispersants. "While it is desirable to obtain approval from the Regional Administrator before using dispersants, NJDEPE is concerned about how state approvals of such use will be handled. NJDEPE's rules presently require approval of either this department or the federal on scene coordinator. Would this approval be sufficient under this proposal?" (147) 186 Disposal of recovered oil and other materials.

Favors proposal. "We strongly agree that provisions for waste disposal should be addressed in contingency plans, including provisions for the temporary storage of recovered oil and oily waste." (193)

Opposes proposal. "The SPCC Plan should focus on spill control and countermeasures rather than disposal of discharged substances, since the disposal of recovered oil, used sorbents, and other materials is regulated by state regulations, by RCRA, or existing federal regulations." (L30)

EPA review and approval. "It is not clear from the proposal whether such a contingency plan must be reviewed and approved by the Registered PE or the RA of EPA. Review by the RA is duplicative, time consuming, and unnecessary." (54) Our proposed requirement that owners or operators submit contingency plans to the RA would require the RA to review and approve a substantial number of plans. (58) We should delete the contingency plan submittal requirement because the RA already has the authority under §112.4 to call for Plans from those facilities that may be defined as "problem facilities." (101) "It does not state that it must be provided to the Regional Administrator any more than the SPCC Plan must be provided. It must be provided if requested by the Regional Administrator, but the preamble language infers that submittal of every contingency plan to the RA is automatic upon being developed." (165, L15)

Electrical equipment facilities. Questions whether we would be able to both review and approve all submitted plans within an acceptable time frame and maintain program credibility. (111) "It is unnecessarily burdensome and expensive, however, to submit such plans to the Agency for numerous substations." (161) "

Review times. "In addition, such a review process could result in project delays. If the Agency intends to pursue this requirement, the regulations should address a reasonable deadline (such as 30 days) that the Agency would have to review and approve the contingency plan." (90, 161) We should clarify whether the contingency plan would be due to the RA within two months of the effective date of the final rule. We should allow owners or operators at least six months to update their existing SPCC Plans. (141)

Financial responsibility. The reference to "financial responsibility requirements" is superfluous. Equipment, personnel, and other spill related expenses are operating expenses for most manufacturing entities, and would impose no financial responsibility. (162)

Formats. 187 Generic contingency plans (electrical substations). "Since all substations are very similar in design and spill response would be conducted by the same personnel, PEO suggests that use of more generic, area wide contingency plans be allowed for facilities such as substations." (41)

HAZWOPER Plans. "The contingency plan requirement should be dropped for `small size facilities' which have a HAZWOPER plan and trained response team." (62, 152)

RCRA contingency plan. "The elements discussed that would make up the Contingency Plan are similar in nature to those that the RCRA regulations require for hazardous storage facilities. In an effort to minimize redundancy, the RCRA Contingency Plan should be allowed to be used in lieu of a separate Contingency Plan to satisfy this rule." (87, 186)

Specific format. "Finally, we recommend the oil spill response plan required under 40 CFR 112.7( d) specify a specific format for its development. We recommend that the contents include at least the same requirements found in the OPA amendments to the FWPCA." (171)

Stand alone section.

Should not stand alone. "If a discharge occurs, personnel may need to respond to operation and maintenance procedures, as well as responding to a cleanup. Referring to two sections for one discharge is not effective." (38)

Should stand alone. "Maintaining the contingency plan as a separate section of the SPCC plan makes good operational sense. Large documents which contain non essential information are seldom if ever used, and difficult to use." (62, 190)

Location of contingency plan. We should require the owner or operator to keep the contingency plan on site at the facility and available for the RA's review during normal working hours. This would reduce the unnecessary administrative burden associated with submission of the contingency plan. (90)

Mandatory secondary containment. We should require secondary containment for all facilities threatening ground or surface waters. Contingency plans will not stop petroleum from reaching surface waters as effectively as "in place properly designed and maintained secondary containment systems." (111)

PE certification. Asks if it is necessary for a Professional Engineer to certify a contingency plan. (121)

Practicability. Our definition of practicable is not specific enough. We should provide guidance on practicability, otherwise, owners or operators may base practicability on 188 the economics of preparing a contingency plan rather than installing prevention equipment. (1153 (1993 commenter))

Scope of the contingency plan. "... EPA should make clear that a contingency plan is required for that portion of the facility that is outside of secondary containment." (54)

Response: Additional information. We have modified the 1991 proposal by withdrawing proposed §112.7( d)( 1). We also have withdrawn the 1993 proposal which would have required a response plan for a facility lacking secondary containment.

Applicability. Under the current rule, contingency planning is necessary whenever you determine that a secondary containment system for any part of the facility that might be the cause of a discharge as described in §112.1( b) is not practicable. This requirement applies whether the facility is manned or unmanned, urban or rural, and for large and small facilities. Facility components that might cause a discharge as described in §112.1( b) include containers, piping, valves, or other equipment or devices. Contingency planning is necessary for all facilities to avert and adequately respond to discharges as described in §112.1( b) regardless of facility size, if the facility lacks secondary containment. It is also necessary in areas historically not subject to natural disasters, because spills can also be caused by human error or mechanical failures.

Completely buried tanks. We note that completely buried tanks, as defined in §112.2, and connected underground piping, underground ancillary equipment, and containment systems that are subject to all of the technical requirements of 40 CFR part 280 or a State program approved under 40 CFR part 281 are not subject to part 112. 40 CFR 112.( d)( 2)( i). Those tanks, piping, and ancillary equipment that remain subject to the SPCC program are therefore subject to contingency planning requirements in the appropriate case.

Electrical equipment. Any facility without secondary containment must prepare a contingency plan when secondary containment is not practicable. See the discussion under §112.7( d) in today's preamble. We disagree that the preamble language should be construed as granting a blanket impracticability determination to any facility (including facilities with electrical equipment). Such a determination is a facility specific one.

FRP facilities. In response to comment, we have revised the rule to exempt from the contingency planning requirement any facility which has submitted a response plan under §112.20 because such a response plan is more comprehensive than a contingency plan following part 109.

We disagree that facility response planning is beyond our statutory authority, since it is a procedure or method to remove discharged oil. See section 311( j)( 1)( A) of the CWA. However, while we disagree that such planning is expensive and lacking in environmental benefit, we agree that the current contingency plan arrangements which reference 40 CFR part 109 should be 189 sufficient to protect the environment, and that a facility response plan as described in §112.20 is therefore unnecessary for a facility that is not otherwise subject to §112.20. We agree with the commenter that structures or equipment might achieve the same or equivalent protection as response planning for some SPCC facilities. Therefore, we are withdrawing that part of the 1993 proposal related to response planning in proposed §112.7( d)( 1), but are retaining the current contingency planning provisions, which require a contingency plan following the provisions of 40 CFR part 109. We also believe that response plans should be reserved for higher risk facilities, as provided in §112. 20.

Clarifications.

Contingency plan vis a vis Facility Response Plans. The terms facility specific response plan (FRP) and contingency plan have different meanings. The oil spill contingency plan is part of the SPCC Plan, required when secondary containment is not practicable at a facility. The FRP, addressed in §§ 112.20 21, is separate from the SPCC Plan, and is required only for a certain subset of SPCC facilities.

Costs. We note that we did not finalize the 1991 or 1993 contingency planning proposals. Thus there are no new costs for such planning.

Dispersants. We withdrew the proposed reference to the use of dispersants in §112.7( d) in 1993. Dispersant use is governed by subpart J of the NCP.

EPA review and approval. We have withdrawn the proposed submittal requirement because we believe it is sufficient that the contingency plan be available for on site inspection. The contingency plan must be made a part of the SPCC Plan, and therefore, PE certification is required. In certifying the SPCC Plan, the PE attests that the owner's or operator's judgment of impracticability is correct.

Disposal of recovered oil and other materials. We agree that we should not require an owner or operator to address the disposal of recovered oil and other materials in a facility specific contingency plan because this discussion is already required under §112.7( a)( v).

Financial responsibility. We have deleted the proposed recommendation concerning financial capability in making written commitments of manpower, equipment, and materials from the rules because we do not wish to confuse the regulated community by including discretionary requirements in a mandatory rule.

Formats. For §112.7 contingency planning requirements, an owner or operator may use a contingency plan prepared under other State or Federal authority as long as the plan follows part 109, or is supplemented so that it meets all of part 109's requirements. 190 Generic contingency plans (electrical substations). We agree that an owner or operator may create a multi facility contingency plan. Such plan must include all elements required for individual contingency plans. It must also include sitespecific information. However, the site specific information might be maintained in a separate location, such as a central office, or an electronic data base, as long as such information is immediately accessible to responders and inspectors. Where you place that site specific information is a question of allowable formatting, an issue subject to RA discretion.

HAZWOPER Plans. The RA has discretion to accept any format that meets the requirements of 40 CFR part 109. Where such alternate format does not meet all of part 109's requirements, the owner or operator may supplement it so that it does.

RCRA. A contingency plan prepared under RCRA rules might suffice for purposes of the rule if the plan fulfills the requirements of part 109, and the PE certifies that such plan is adequate for the facility. If the RCRA contingency plan satisfies some but not all SPCC requirements, you must supplement it so that it does.

Specific format. It is unnecessary to specify a format for a contingency plan because we do not believe that there is a single format applicable to all facilities.

Stand alone section. We have withdrawn the proposed requirement that the contingency plan be a stand alone section of the SPCC Plan. The owner or operator has flexibility to determine where to incorporate the contingency plan within the SPCC Plan.

Location of contingency plan. Today we have finalized the 1991 proposal that the Plan must be available at the facility if it is normally attended at least four hours per day, or at the nearest field office if it is not so attended. A Plan must always be available without advance notice, because an inspection might not be scheduled. You are not required to locate a Plan at an unattended facility because of the difficulty that might ensue when emergency personnel try to find the Plan. However, you may keep a Plan at an unattended facility. If you do not locate the Plan at the facility, you must locate it at the nearest field office.

Mandatory secondary containment. We agree that an in place, properly designed, and maintained secondary containment system is the most effective way to prevent a discharge as described in §112. 1( b). However, for certain facilities, secondary containment may not be practicable because of geographic limitations, local zoning ordinances, fire prevention standards, or other good engineering practice reasons.

Part 109 requirements. In following the provisions of part 109, you must address the oil removal contingency planning criteria listed in 40 CFR 109.5 and ensure that all response actions are coordinated with governmental oil spill response organizations. 191 The absence of secondary containment will place extreme importance on the early detection of an oil discharge and rapid response by the facility to prevent that discharge. Part 109 was originally promulgated to assist State and local government oil spill response agencies to prepare oil removal contingency plans in the inland response zone, where EPA provides the On Scene Coordinator. The basic criteria for contingency planning listed in §109.5 apply to any SPCC regulated facility that has adequately justified the impracticability of installing secondary containment, irrespective of whether it is a government agency or the facility is located in the coastal (U. S. Coast Guard) or inland (EPA) response zone. Because the contingency plan involves good engineering practice and is technically a material part of the Plan, PE certification is required.

PE certification. The contingency plan is a technical part of the SPCC Plan which must be certified by a PE.

Practicability. We believe that it may be appropriate for an owner or operator to consider costs or economic impacts in determining whether he can meet a specific requirement that falls within the general deviation provision of §112.7( a)( 2). We believe so because under this section, the owner or operator will still have to utilize good engineering practices and come up with an alternative that provides "equivalent environmental protection." However, we believe that the secondary containment requirement in §112.7( d) is an important component in preventing discharges as described in §112.1( b) and is environmentally preferable to a contingency plan prepared under 40 CFR part 109. Thus, we do not believe it is appropriate to allow an owner or operator to consider costs or economic impacts in any determination as to whether he can satisfy the secondary containment requirement. Instead, the owner or operator may only provide a contingency plan in his SPCC Plan and otherwise comply with §112. 7( d). Therefore, the purpose of a determination of impracticability is to examine whether space or other geographic limitations of the facility would accommodate secondary containment; whether local zoning ordinances, fire prevention standards, or safety considerations would prohibit the installation of secondary containment; or, if the installation of secondary containment would defeat the goal of the regulation to prevent discharges as described in §112.1( b).

Review of contingency plans. We note that the preamble to the 1993 proposed rule (at 58 FR 8841) suggested that response plans would not have to be submitted to the Regional Administrator unless "otherwise required by the rest of today's proposed rule." However, proposed §112.7( a)( 2) would have required that the owner or operator submit to the Regional Administrator any Plan containing a proposed deviation, including a deviation for the general secondary containment requirements in §112.7( c). In any case, we agree with commenters that the contingency plan (or any other deviation) should not have to be submitted to the Regional Administrator for his review and approval because we believe that it is sufficient that the contingency plan (or other deviation) be available for on site inspection. We have therefore withdrawn that part of the proposal. See also the discussion on §112.7( a)( 2). 192 Scope of the contingency plan. The contingency plan is applicable to the entire facility because it involves the capacity of the entire facility to prepare for and respond to a discharge as described in §112.1( b).

Small facilities. We disagree that contingency planning is too costly for small facilities. Such planning helps to save money when a discharge occurs. The requirements for contingency planning are fewer than the requirements for response planning. Response planning is required only for higher storage, higher risk facilities.

Written commitment. A "written commitment" of manpower, equipment, and materials means either a written contract or other written documentation showing that you have made provision for those items for response purposes. Such commitment must be shown by: the identification and inventory of applicable equipment, materials, and supplies which are available locally and regionally; an estimate of the equipment, materials, and supplies which would be required to remove the maximum oil discharge to be anticipated; and, development of agreements and arrangements in advance of an oil discharge for the acquisition of equipment, materials, and supplies to be used in responding to such a discharge. 40 CFR 109.5( c).

The commitment also involves making provisions for well defined and specific actions to be taken after discovery and notification of an oil discharge including: specification of an oil discharge response operating team consisting of trained, prepared, and available operating personnel; predesignation of a properly qualified oil discharge response coordinator who is charged with the responsibility and delegated commensurate authority for directing and coordinating response operations and who knows how to request assistance from Federal authorities operating under current national and regional contingency plans; a preplanned location for an oil discharge response operations center and a reliable communications system for directing the coordinated overall response actions; provisions for varying degrees of response effort depending on the severity of the oil discharge; and, specification of the order of priority in which the various water uses are to be protected where more than one water use may be adversely affected as a result of an oil discharge and where response operations may not be adequate to protect all uses. 40 CFR 109.5( d).

X  F: Integrity and leak testing  §112.7( d)

Background: Section 112.7( d) of the current rule sets out requirements for a facility when secondary containment is not practicable. In such cases, the owner or operator must explain the impracticability; provide a contingency plan following the provisions in 40 CFR part 109; and provide a written commitment of manpower, equipment, and materials to control and remove any harmful quantity of discharged oil. In 1991, we proposed adding a requirement in §112.7( d) for the owner or operator of a facility without secondary containment to conduct integrity tests of tanks at least once every five years. We also proposed adding a requirement for integrity and leak testing of valves and piping at least once a year. 193 Comments: Alternatives to integrity testing.

Engineering evaluation instead. Rather than requiring an owner or operator to conduct integrity tests of underground piping, we should require an owner or operator to conduct an "engineering evaluation" of unprotected, underground piping to test its integrity. (67, 91)

Applicability.

Ancillary equipment. "..., because spills and leaks most commonly occur due to equipment failures related to piping, valves, and pumps, ATA recommends expanding the integrity test to cover ancillary equipment. The same 5 year and 10 year testing schedules proposed for tanks are reasonable for ancillary equipment." (107)

Electrical equipment. "... this provision is impracticable because certain types of electrical equipment, such as underground transmission cable systems, cannot be integrity tested, while ones that can be tested, such as transformers, must be taken out of service to be tested. Moreover, this requirement is unnecessary because electrical equipment in service is constantly being tested because the equipment will fail if there is a leak." (74, 125, 156, 158, 183, 189, 192) It is unnecessary and inappropriate to apply the §112.7( d) integrity testing requirements to oil filled equipment, because typical substation transformers are protected by alarm systems sufficient to alert operators of leaks. Integrity testing this equipment would result in an unnecessary expense. (158) "This is another instance where a size differential could be used to exempt oil filled electrical equipment from these inappropriate and unnecessary requirements." (183)

Fixed aboveground piping. Proposed §112.7( d) should apply only to fixed aboveground piping that lacks secondary containment. It appears that §112.7( d) applies to aboveground and underground tanks, valves, and piping; and it is highly unlikely for buried tanks, piping, or valves to have secondary containment. Further, proposed §112.7( d) "defeats the discretionary testing schedule contained in §§ 112. 8( c)( 4) for buried metallic tanks and 112. 8( d)( 4) for buried piping." (102)

Flowlines and gathering lines. "Further, the alternate to 40 CFR section 112.7( c) requires flow lines testing. The pressure test provision offer little advantage over normal flowline pressure, which is present at all times. Typically, flowline leaks are small and routine inspection at road crossings provides sufficient protection from oil entering Waters of the U. S. However, the voluntary Contingency Plan requirement provides added protection." (110) The required annual pressure testing of flowlines and gathering systems would be costly for small operators. We should exclude flowlines and gathering systems from the §112.7( d) testing provisions. (28, 31, 101,165, L15). 194 Impracticality. We should not require annual integrity leak testing of tanks where installation of secondary containment is impractical. Monthly visual inspection of tanks, valves, and aboveground piping provides adequate protection to the environment. (1155 (1993 commenter))

Phase in. We should require tanks subject to §112.7( d) to comply with the provisions within five years of the promulgation date of the final rule and every five years thereafter. (125)

Production facilities. We should clarify whether secondary containment is inapplicable for offshore and coastal production facilities, and therefore, whether the proposed integrity testing requirements are necessary at such facilities. "In all other cases," the integrity testing requirements should not be applicable to the production industry. (1199 (1993 commenter))

Small facilities.

Supports testing requirements. "The testing of tanks for integrity is needed. While most large corporations perform testing at some frequency, most smaller businesses do not. Exemptions because of size or quantity of oil stored should not be granted because the smaller facilities generally are more in need of testing." (3, 4, 27, 95)

Opposes testing requirements. "EPA should make a distinction between large and small facilities, and should require integrity testing only on larger tanks such as those commonly located at complicated fuel distribution sites, commonly known as tank farms. Facilities which are primarily engaged in vehicle refueling operate above ground tanks which typically hold significantly less than that found at tank farms are suitable for visual inspections. EPA should realize that presently, there exists a limited amount of organizations which perform integrity tests on above ground tanks. If EPA were to promulgate an integrity test requirement on all aboveground tanks, many trucking facilities will find it difficult and expensive to identify appropriate testing agents." (53, 70) Proposed §112.7( d) integrity testing requirements would be burdensome for small remote facilities. We should require integrity testing only at a facility with a storage capacity greater than 42,000 gallons and without the structures or equipment listed in proposed §112.7( c). (78, 145, L3) We should require integrity testing for facilities with a storage capacity greater than 100,000 gallons, and testing of valves and piping located directly above or on a pervious surface of such tanks. (90,1137 (1993 commenter)) The §112.7( d) requirement should apply only to tanks with more than 660 gallons, because the costs of integrity testing smaller tanks outweigh the benefits. (125) The §112.9( d) provisions provide adequate environmental protection for small facilities. (145)

Tank failure. "Integrity testing at other than ten (10) year intervals should only be required if a tank failure has occurred within the last 5 years or the tank is 195 used to store materials that are corrosive to the tank material. The small tanks at E& P operations are not likely to be susceptible to conditions requiring the five year inspection regimen." (114)

Underground cable systems. Current technology does not allow an owner or operator to apply the secondary containment, inspection, and integrity testing requirements of the SPCC program to underground cable systems. (92, 98, 125) Proposed §112.7( d) is inappropriate for underground cable systems because there is no efficient system for integrity testing miles of interconnected piping. An owner or operator must keep underground cable systems in service. It is impossible for an owner or operator to develop a site specific contingency plan for underground cable, since such systems cover large geographical areas. (125) We should not require an owner or operator to prepare a Plan for or integrity test cable systems. (164, 165)

Unprotected underground piping. We should limit annual integrity and leak test requirements to unprotected underground piping. (167)

Within structures, small tanks. "We propose an exemption for integrity testing of all tanks which: are contained within a building or have a maximum capacity of less than 2000 gallons; have all sides visible, and; which are visually inspected (along with any associated piping and ancillary equipment) at least monthly." (54, 71, 78, 90, 101, 109, 110, 162, 167, 175)

Cost. Integrity testing is too costly. (28, 31, 54, 57, 58, 90, 102, 110; 1137,1145 (1993 commenters).) The proposed requirement to test tanks without secondary containment annually would be costly and would restrict the owner's or operator's ability to conduct necessary inventories and to "meet supply and demand needs." It would be impossible for the facility to operate if all tanks were taken out of service for testing every year. (25) We did not adequately consider the costs associated with the integrity testing for high pour point (e. g., 60 "

F) bulk storage tanks, because proposed §112.7( d) would require an owner or operator to completely drain and clean a tank. Such integrity tests would pose an unnecessary cost given the low risk of spills from such tanks. (90) We did not consider the cost of integrity testing substations and other oil filled equipment in our economic impact analysis for the rulemaking. Such testing is impractical since owners or operators would have to test individual equipment pieces. (L2)

Discretionary testing. We should allow an owner or operator to determine the integrity of aboveground piping through frequent visual inspection and observation of the product flowing through the line. We should allow an owner or operator to conduct visual inspections to comply with the §112.7( d) integrity testing requirement. (54) The requirement to conduct integrity testing applies to aboveground and buried tanks, piping, and valves should be discretionary. If the requirement were discretionary, the owner or operator could set a testing frequency based on facility specific factors such as the facility's age, soil corrosiveness, and corrosion protection. Such a discretionary 196 provision "defeats the discretionary metallic testing scheduled contained in §112. 8( c)( 4) for buried metallic tanks and §112. 8( d)( 4) for buried piping." (102)

Frequency of testing.

Support for proposal. General support for our proposal to specify time periods. (148, L1) Support for proposal to perform integrity testing of tanks once every five years at facilities without secondary containment. (95, 101, 102, L1, L2) Support for testing valves and piping once a year at such facilities. (80, 117) Support for integrity testing for cathodically protected piping every five years (167) and at the time of installation, modification, repair, and relocation (67).

Opposition to proposal. We should not require integrity testing of tanks every five years. (57, 78, 90, 101, 109, 128, L2, (1137, 1145, 1146, 1199 (1993 commenters)) Imposing these specific time periods is unnecessary and would provide "no improvement in the quality of SPCC plans." (155)

Cost. The proposed requirement to test tanks with secondary containment every five years would be costly and would obstruct handling necessary inventories. The proposed requirement would reduce the commenter's facility's ability to meet supply and demand, and it would be impossible to operate the facility if all tanks were out of service for testing every year. (25)

Excessive. "This requirement is not realistic for the oil and gas industry in Appalachia. It is recommended that the current language from §112.7( e)( 5) be retained." (54, 67, 91, 95, 101, 102, 109, 167, 175, L2; (1137, 1145, 1146, 1199 (1993 commenters)). New tanks need less inspections than older ones, and we should only require an owner or operator to test a tank every five years after the first fifteen years of the tank's manufacturing date. (1165 (1993 commenter)) We should only require integrity testing less frequently than every 10 years only if a tank failure has occurred within the last five years, or if the tank contains corrosive materials. Small tanks at exploration and production (E& P) operation sites are unlikely to require integrity testing every five years. We should require integrity testing of pipes, valves, and fittings when corrosion or leakage has occurred or is "potentially severe." (114) We should only require an owner or operator to test valves and piping without secondary containment once every five years, and we should require an owner or operator to include in the Plan a schedule of visual inspections for such valves and piping. (95, L2) Such an approach would reduce the amount of waste generated by integrity testing and provide a reasonable integrity testing schedule. (95)

Maintenance instead. Routine inspection and maintenance of aboveground storage tanks and associated pipes, valves, and pumps is sufficient to eliminate the potential of a significant spill. We should require integrity testing only when the owner or operator detects something that may lead to a discharge. Inspections allow an owner or operator to determine whether maintenance and 197 repairs are required to prevent a discharge. (54, 71, 78, 90, 101, 109, 110, 162, 167, 175)

Material repairs. Integrity testing is necessary only after material repairs. (78)

Mines. "For some small mining facilities, these testing requirements would be overly burdensome and quite expensive.... EPA should take into account the quantity of oil stored at a facility, and allow small facilities, with secondary containment, the right to inspect and monitor at the operator discretion, in accordance with good engineering practice." (10)

Need for testing. We should develop an "administrative record" to determine the need for integrity testing. We should not require an integrity testing schedule in Phase One without stating what types of tests meet "statutory objectives." (75)

Negative or no environmental impact. Integrity testing can negatively impact the environment. (90, 95) Annual testing would not significantly increase the level of environmental protection. (L2)

System failures. Integrity testing may exacerbate the probability of system failures. (67, 91, 1146, 1155 (1993 commenters))

Tank construction. We should base the frequency of integrity testing on such factors as the tank construction material and the nature of the material in the tank. (190)

Unnecessary. "This testing requirement would be costly to impose and lacks justification. Tanks with and without secondary containment deteriorate at the same rate and there is no reason to impose different testing requirements. The lack of secondary containment should be compensated for by site specific contingency plans." (57)

Weekly inspections instead. Instead of requiring annual integrity and leak testing, we should allow an owner or operator to conduct weekly inspections for oil leaks or spills during normal production facility operating conditions. There is a low risk of significant spills at production facility oil gathering systems because individual wells are located in a central processing storage facility. (1145 (1993 comment))

More frequent testing. We should permit more frequent inspection and monitoring than the rule requires. (87)

Guidance. We should set guidelines and recommendations in §112.7( d) for inspections and testing procedures and include proven and acceptable test methods in the regulation. We should include in §112.7( d) specific integrity testing procedures required for electrical equipment. (27, 80, L2) 198 Integrity testing. We should revise §112.7( d) to define integrity testing. (70) We did not define periodic integrity testing in the proposed rule, noting that we define the term in current §112.7( e)( 2)( vi). (1149 (1993 comment))

Methods of testing.

Acoustic emission testing. We should allow for acoustic emission testing instead of hydrostatic testing as covered by API Standard 653. The tests are equally effective, but acoustic emission testing reduces wastewater production. (1135 (1993 comment))

API standards. "In lieu of frequent `integrity testing, ' we suggest that the EPA adopt the inspection portion of API 653, which allows up to 20 years between inspections. Integrity testing should be defined as the evaluation of a tank for serviceability. Short of a hydrostatic test, comprehensive tank inspection is the only method to evaluate the serviceability of a tank. The tank inspection method presented in API 653 details the tank components that should be examined and appropriate examination methods." (1145, 1149 (1993 commenters))

Hydrostatic testing. We should allow an owner or operator to supplement hydrostatic testing with other inspection techniques while the tanks are in service and not being tested. This would allow an owner or operator to schedule tank outages when it is most convenient. (25)

"No appropriate technology." There is no appropriate technology for testing fiberglass tanks or aboveground storage tanks. (62)

Pressure testing. Pressure testing could perforate a weakened section of piping, and compel an owner or operator to isolate and repair the section to avoid a corrosionrelated leak. A corrosion related leak could easily develop the day after the owner or operator performs pressure testing. (28, 31, 101, 165, L15) Frequent pressure testing of buried tanks and piping will create  not prevent  pollution, since owners or operators must conduct pressure testing with the oil contained in the system or must drain the oil and replace it with water. Pressure testing generates solid wastes, and that owners or operators must treat and dispose of the oily waste. (102) Pressure testing of tanks, valves, and equipment can weaken the integrity of a steel tank and contribute to failures of such tanks, valves, and equipment. (128)

Reference to §112.7( c). Our cross reference to §112.7( c) is unclear. It is unclear whether the §112.7( c) reference refers to the existing or the proposed rule. Proposed §112.7( d) integrity testing requirement appears to refer only to tank batteries with dikes, berms, or retaining walls sufficiently impervious to contain spilled oil. (955 (1993 commenter))

Visual inspection. 199 Frequency.

Weekly inspection. We should allow an owner or operator to conduct daily or weekly visual inspections of valves and pipes. (1145,1199 (1993 commenters))

Monthly inspection. We should require an owner or operator to conduct a visual inspection of valves and aboveground piping at least once a month. (67, 91, 167)

Periodic inspection. "To require annual integrity and leak testing of aboveground piping and valves is unrealistic and could exacerbate the probability of or initiate system failures. The requirement should read "visually inspect valves and aboveground piping periodically and conduct an engineering evaluation of unprotected underground piping once every five years." (67, 101, 128, 167,175; 1146 (1993 commenter)). We should require periodic visual examinations similar to the examinations proposed under §112.9( e). (101)

Internal and external inspection. We should clarify whether a visual inspection must be both internal and external. (76)

Supplement to inspections. An owner or operator should supplement integrity testing with visual inspections (95, 102) and recordkeeping (128). We should supplement visual inspections of aboveground valves and piping with a five year integrity testing schedule. (175)

Response: Support for proposal. We appreciate commenter support.

Applicability. Integrity testing is essential for all aboveground containers to help prevent discharges. Testing will show whether corrosion has reached a point where repairs or replacement of the container is needed. Therefore, it must apply to large and small containers, containers on and off the ground wherever located, and to containers storing any type of oil. From all of these containers there exists the possibility of discharge. We agree that integrity testing of aboveground piping should be discretionary when the facility has secondary containment which would contain a discharge from such piping. Integrity and leak testing requirements are also applicable for containers and valves and piping that are entirely within buildings, or within mines, because in either case, such containers, or valves and piping may become the source of a discharge as described in §112.1( b). We have revised the rule to reflect that the requirement applies only to onshore and offshore bulk storage facilities. Therefore, a facility with only oil filled electrical, operating, or manufacturing equipment need not conduct such testing. We disagree that testing of valves, gathering lines, and flowlines would be prohibitively costly. In 1991, we estimated tank integrity testing and leak testing costs of buried piping. We estimated the costs as $465 per tank, $155 for equipment, and $310 for installation. Small facilities were assumed to have no buried piping. Medium sized facilities were assumed to bear first year costs for tank installation and testing of $4,704 and subsequent year costs of $1,449. Large facilities were assumed to incur a first year 200 cost of $11,313, and subsequent year costs of $3,519. We believe that this provision represents a negligible additional burden because most facilities are already testing such valves and gathering lines according to industry standards as a matter of good engineering practice. We believe that if such testing is done in accordance with industry standards, costs will be minimized because such standards will likely include options appropriate to the equipment tested at a reasonable cost.

We decline to exclude from §112.7( d) all tanks that are less than 15 years old, since the corrosion and discharge rates of one container will differ from the next. We also decline to require integrity testing only when the owner or operator determines that there is a risk of discharge, since that standard is not objective. We also disagree that we should only require owners or operators to integrity test valves and piping when corrosion or leakage has occurred or is potentially severe because it is inappropriate to require a test only when the system or equipment shows signs of potential failure. The idea of testing is to prevent such corrosion or leakage. Likewise, a weekly inspection for leaks is not the equivalent of conducting integrity tests. Visual inspection must be combined with some other technique.

Electrical equipment. Because electrical, operating, manufacturing equipment are not bulk storage containers, the requirement is inapplicable to those devices or equipment. 56 FR 54623. Also, as noted by commenters, methods may not exist for integrity testing of such devices or equipment.

Fixed aboveground piping. Section 112.7( d) applies both to completely buried and aboveground tanks, valves, and piping, including gathering lines and flowlines. There is no conflict with either §112.8( c)( 4) or (d)( 4). Section 112.8( c)( 4) provides for "regular" testing of completely buried tanks. Section 112.8( d)( 4) provides for "regular" inspection of aboveground valves, piping, and appurtenances, and integrity and leak testing of buried piping at the time of installation, modification, construction, relocation, or replacement. Section 112.7( d) provides for "periodic" integrity testing, and "periodic" integrity and leak testing. Either "periodic" or "regular" testing should be conducted according to industry standards. Thus, there is no conflict between the rule provisions.

Impracticality. Integrity testing under §112.7( d) must be performed if the facility lacks secondary containment. You have discretion as to the method of testing, but it must be performed if it is possible to do so. If it is impossible, then the owner or operator must explain his reasons for nonconformance with the requirement, and provide equivalent environmental protection by some other means.

Phase in. We disagree that there should be a phase in period. We believe that the time allowed in §112.3 for Plan amendment and implementation allows ample time for both existing and future facilities to comply with the changes in the rule. 201 Underground cable systems. Because electrical, operating, manufacturing equipment are not bulk storage containers, the requirement is inapplicable to those devices or equipment. 56 FR 54623. Also, as noted by commenters, methods may not exist for integrity testing of such devices or equipment.

Unprotected underground piping. We do not require periodic integrity testing for underground piping, since uncovering buried piping may present an undue hazard. Integrity and leak testing must be conducted when buried piping is installed, modified, constructed, relocated, or replaced. For comments on integrity testing requirements for cathodically protected piping and unprotected underground piping, see the comments on §112.8( c)( 4) and (d)( 1) in today's preamble.

Costs. We disagree that integrity testing is too costly because industry standards will likely incorporate options appropriate to the equipment at reasonable cost. It may help save the owner or operator money by preventing a discharge as described in §112.1( b). In 1991, we estimated tank integrity testing and leak testing costs of buried piping. We estimated the costs as $465 per tank, equipment of $155, and installation costs of $310 per tank. Small facilities were assumed to have no buried piping. Medium sized facilities were assumed to bear first year costs for tank installation and testing of $4,704 and subsequent year costs of $1,449. Large facilities were assumed to incur a first year cost of $11,313, and subsequent year costs of $3,519. We assume that this provision represents a negligible additional burden because most facilities are already testing such valves and gathering lines according to industry standards as a matter of good engineering practice.

Frequency of testing. We have modified our proposal in response to comments. We require such testing on a periodic basis instead of at a prescribed frequency, both for containers and for valves and piping. "Periodic" testing means testing according to a regular schedule consistent with accepted industry standards. We believe that use of industry standards, which change over time, will prove more feasible than providing a specific and unchanging regulatory requirement. As required by §112.8( c)( 6), integrity testing of containers must be accomplished by a combination of visual testing and some other technique.

We disagree that required integrity testing may force an owner or operator to shut down the facility or its systems. Because such testing is performed on a periodic or scheduled basis, the owner or operator has discretion as to the schedule to keep the facility open as much as possible.

Integrity and leak testing. In response to a commenter who asked for a clarification of integrity testing, "integrity testing" is any means to measure the strength (structural soundness) of the container shell, bottom, and/ or floor to contain oil and may include leak testing to determine whether the container will discharge oil. Facility components that might cause a discharge as described in §112.1( b) include containers, piping, valves, or other equipment or devices. Integrity testing includes, but is not limited to, 202 testing foundations and supports of containers. Its scope includes both the inside and outside of the container. It also includes frequent observation of the outside of the container for signs of deterioration, leaks, or accumulation of oil inside diked areas. Such testing is also applicable to valves and piping. See API Standard 653 for further information on this term.

Leak testing for purposes of the rule is testing to determine the liquid tightness of valves and piping and whether they may discharge oil. Facilities that store oil, whether they are mines or other businesses, are required to employ integrity testing for their bulk storage containers, and integrity and leak testing for their valves and piping, to help prevent discharges. Containers that do not store oil, but merely use oil, are not subject to the requirement.

Methods of testing. We do not prescribe the method of testing, except to require that visual inspection must be combined with some other technique. We agree that an owner or operator may supplement hydrostatic testing with other inspection techniques while the tanks are in service and not being tested.

We disagree that visual inspection and nondestructive shell thickness testing are insufficient. Such testing should give the owner or operator an indication of the container's integrity.

We disagree that an "engineering evaluation" of unprotected, underground piping is acceptable in lieu of an integrity and leak test because such evaluation may not provide equivalent environmental protection as integrity and leak testing of valves and piping. Likewise, a "routine inspection" of flowlines does not rise to the level of integrity and leak testing.

We disagree that integrity testing would require an owner or operator to completely drain and clean high pour point bulk storage containers. Testing may be possible without such drainage, either by using a particular method, for example, a robot, or performing such testing during regularly scheduled maintenance.

We also disagree that integrity testing will exacerbate the probability of system failures or negatively impact the environment. Integrity testing is a non destructive type of testing that should not affect system failures. Its only effect on the environment should be a positive one, to help prevent a discharge as described in §112.1( b).

An owner or operator must consider the tank design and its construction material when determining an appropriate testing schedule and method, and may determine a periodic testing schedule and method based on good engineering practice, relevant industry standards, and optimal use of facility resources. The owner or operator must also consider factors such as the potential for tank failure, tank design, and tank material when determining an appropriate testing schedule and method. Among these factors should be how the material stored effects the structural integrity of the tank. We disagree with the commenter who stated that integrity testing is necessary only after 203 material repairs. A discharge may occur at any time, regardless of whether an owner or operator has conducted repairs.

Guidance. Due to rapidly changing technology, we cannot list all types of integrity testing methods. There is no single operational standard we can prescribe for all non transportation related facilities. However, we include industry standards in the preamble to today's final rule to assist the reader. See the discussion in §§ 112.7( d) and 112.8( c)( 6). We also list organizations that help to formulate industry standards in section IV. D of today's preamble.

Pressure testing. We do not require pressure testing. Therefore, none of the problems cited with such testing are relevant.

Reference to §112.7( c). The reference in proposed §112.7( d) was to proposed §112.7( c). Section §112.7( d) integrity testing and integrity and leak testing requirements apply to any facility which lacks secondary containment.

Visual inspection. The rule requires visual testing in conjunction with another method of testing, because visual testing alone is normally insufficient to measure the integrity of a container. Visual testing alone might not detect problems which could lead to container failure. For example, studies of the 1988 Ashland oil spill suggest that the tank collapse resulted from a brittle fracture in the shell of the tank. Adequate fracture toughness of the base metal of existing tanks is an important consideration in discharge prevention, especially in cold weather. Although no definitive non destructive test exists for testing fracture toughness, had the tank been evaluated for brittle fracture, for example under API standard 653, and had the evaluation shown that the tank was at risk for brittle fracture, the owner or operator could have taken measures to repair or modify the tank's operation to prevent failure.

For certain smaller shop built containers in which internal corrosion poses minimal risk of failure; which are inspected at least monthly; and, for which all sides are visible (i. e., the container has no contact with the ground), visual inspection alone might suffice, subject to good engineering practice. In such case the owner or operator must explain in the Plan why visual integrity testing alone is sufficient, and provide equivalent environmental protection. 40 CFR 112.7( a)( 2). However, containers which are in contact with the ground must be evaluated for integrity in accordance with industry standards and good engineering practice.

X  G: Inspections, tests, and records  §112.7( e)

Background: Under §112.7( e)( 8) of the current rule, an owner or operator must maintain inspection records as part of an SPCC Plan for three years. In §112.7( e) of the 1991 proposed rule, we proposed to extend the period for retaining records of inspections, test results, and written procedures from three to five years. We proposed this extension to be consistent with the Federal statute of limitations on assessing civil penalties for violating the SPCC rule. We also proposed that these records be 204 maintained with an SPCC Plan, and not as part of an SPCC Plan. In 1997, we proposed to retain the three year record retention standard.

Comments: Editorial suggestion. In the first sentence of §112.7( e), we should change the word shall to must. (121)

Form of records. "... written procedures for testing only should be omitted from the proposed rule." Believes that "written procedures for testing can be quite lengthy and would have meaning to the tester only." (37) 40 CFR part 112 should include the testing required by 40 CFR part 280. (47)

Date. Each inspection and test report should be dated. (47)

Electronic format. "Using electronic media for the storage and retrieval of standard operating practices, inspection protocols, testing procedures, and maintenance records is becoming commonplace in industry. BP requests that language be inserted in this section to allow the use of computers or other electronic devices for the purpose of satisfying this section." (96)

Repairs and training. In §112.7( e), we should require owners or operators to keep records and tests of all major repairs and of employee training, in addition to written procedures and records of inspections and tests. (147)

Maintenance with Plan.

Accessible location. "FINA proposes that the records be maintained at the facility or at an alternate location accessible within 24 hours." (25, 37, 38, 47, 67, 83, 187)

Principal place of business. Owners or operators should maintain records for the most current three years with the Plan, and should maintain records for the remaining two years at the facility's principal place of business. (54)

Required inspections and tests. "It would be helpful if EPA could include a list of all inspections and tests required by this part." (16)

Time period.

Opposes 5 year proposal. (22, 33, 67, 101, 113, 167, 181, 187) An obligation to maintain records for five years places an undue administrative burden on facility owners or operators. (45, 113, 181) A five year record retention provision is inconsistent with other environmental protection regulations. (See, for example, Resource Conservation and Recovery Act regulations, 40 CFR parts 264 and 265, and Department of Transportation requirements.) (35, 78, 109, 153) We should require owners or operators to retain records in accordance with other 205 State and Federal agency requirements to avoid additional and unnecessary costs. (114)

2 years. We should reduce the record retention period to two years. (45)

Phase in. "API suggests that in order to be consistent with record retention requirements under the NPDES program of the CWA, records should only be retained for three years. However, if the Agency insists on a new five year requirement, because the required records have only been maintained for three years consistent with the current regulation, there will be a need for at least a phase in period to bring those records which were retained into compliance with this new provision." (67, 79, 95, 101, 102)

3 years. Retaining records for three years should be adequate, since we require the review and recertification of an SPCC Plan every three years. (66)

Small facilities.

Opposes requirement. The proposed requirement to maintain records with the SPCC Plan for five years would be particularly burdensome for small facilities. (28, 58, 62, 101) Proposed §112.7( e) is only appropriate for large facilities. (192)

Favors requirement. Maintaining records with the Plan should only apply to small facilities. (9, 77)

Response: Editorial suggestion. In response to the comment that we change shall to must in §112.7( e), we agree, and have made that change throughout the rule to further our plain language objectives.

Form of records. Records of inspections and tests required by this rule may be maintained in electronic or any other format which is readily accessible to the facility and to EPA personnel. Whatever format you use, however, must be readily accessible to response personnel in an emergency. If such records are produced in a medium that is not readily accessible in an emergency, they must also be available in a medium that is. For example, records might be electronically produced, but computers fail and may not be operable in an emergency. For electronic records, or records produced in another medium, therefore, backup copies must be readily available on paper. At least one version of the records should be written in English so that they will be readily understood by an EPA inspector.

Usual and customary business records may be those ordinarily used in the industry, including those made under API standards, Underwriters' Laboratories standards, NPDES permits, a facility's Q. S. 9000 or ISO 14000 system, or any other format acceptable to the Regional Administrator. If you choose to use records associated with compliance with industry standards, such as Underwriters' Laboratories standards, you 206 must closely review the inspection, testing, and record keeping requirements of this rule to ensure that any records kept in accordance with industry standards meets the intent of the rule. Some standards have limited record keeping requirements and may only address a particular aspect of container fabrication, installation, inspection, and operation and maintenance. The intent of the rule is that you will not have to maintain duplicate sets of records when one set has already been prepared under industry or regulatory purposes that also fully suffices for SPCC purposes. The use of these alternative record formats is optional; you are not required to use them, but you may use them.

We disagree that we should omit written procedures for testing. Such procedures are essential for implementation of testing and inspection requirements, and must be described in the Plan. We disagree that we should include the testing requirements of 40 CFR part 280 in the rule, however, such procedures may be applicable, subject to good engineering practice.

Date. Dated records are essential to document compliance with both substantive and recordkeeping requirements. Dated records are also consistent with usual and customary business practices.

Maintenance with Plan. We agree with commenters that it is not necessary to maintain records as part of the Plan. Therefore, today's rule allows "keeping" of the records "with" the Plan, but not as part of it. In the current rule, such records "should be made part of the SPCC Plan...." 40 CFR 112.7( e)( 8). Because you continually update these records, this change will eliminate the need to amend your Plan each time you remove old records and add new ones. You still retain the option of making these records a part of the Plan if you choose.

Records required. The rule permits use of usual and customary business records, and covers all of the inspections and tests required by this part as well as any ancillary records. "Inspections and tests" include not only inspections and tests, but schedules, evaluations, examinations, descriptions, and similar activities required by this part.

Required inspections and tests. After publication of this rule, we will list all of the inspections and tests required by part 112 on our website (www. epa. gov/ oilspill). The applicability of each inspection and test will depend on the exercise of good engineering practice, because not every one will be applicable to every facility.

Time period. We agree with commenters that maintenance of records for three years is sufficient for SPCC purposes, since that period will allow for meaningful comparisons of inspections and tests taken. Therefore, there will also be no new costs. We note, however, that certain industry standards, for example API Standards 570 and 653, may specify record maintenance for more than three years. 207 We disagree that we should require record retention in accordance with State and other Federal requirements. State and Federal record retention requirements vary, making it difficult to establish a single standard.

X  H: Training  §112.7( f)

Background: Section 112.7( e)( 10) in the current rule prescribes the employee training requirements and discharge prevention procedures that a facility owner or operator must observe. It provides that owners or operators are responsible for properly instructing personnel, and scheduling and conducting spill prevention briefings at intervals frequent enough to assure adequate understanding of the SPCC Plan. In 1991, we redesignated §112.7( e)( 10) as §112.7( f), and proposed to require: (1) an owner or operator to conduct training exercises at least annually for all personnel, and train new employees within their first week of work; and, (2) an owner or operator to schedule and conduct spill prevention briefings at least once a year. We also proposed specific training subjects for inclusion in the training program.

Comments: Support for proposal. "Shell agrees with this proposal and has been conducting such retaining at their facilities." (10, 27, 96, 143, 147, 185)

Applicability.

Bulk storage. We should require staff training for major bulk terminal and tank farm facilities. (192)

Existing programs. Facilities should be allowed to incorporate SPCC training provisions into already existing training programs required by other Federal or State regulations. (91, 96, 162)

Operation and maintenance of equipment. "The rule should only apply to `personnel involved in oil transfer operations, emergency response, and countermeasure activities." It should not apply to clerks, secretaries, and like employees. (14, 35, 42, 45, 48, 57, 62, 66, 67, 71, 77, 88, 92, 98, 103, 115, 117, 125, 141, 164, 167, 173, 175, 180, 181, 182, 187, 189, L7, L12, L18, L24)

Small facilities. We should provide for a small facility exemption. (79, 109, 175, 180, 182)

Content of training. Training should address the initial response to a spill, such as emergency notification and implementation of emergency containment measures. Exercises of these emergency plans should be conducted at least annually. (1) Objects to the proposal that employees be trained in maintenance of oil storage equipment or oil transfer procedures. (42, 125)

Discharge prevention briefings. "API suggests that section 112.7( f)( 3) be amended to require `briefings for operating personnel at least once a year ... to assure understanding 208 of the SPCC plan for that facility in conjunction with the annual training. ' This paragraph should also require briefings of `new operational employees during their indoctrination with their job responsibilities, and as appropriate for all affected operational personnel when changes are made to the existing Plan necessitating recertification." (67) Favors the present requirement to hold spill prevention briefings "at intervals frequent enough to assure adequate understanding of the SPCC Plan." (78)

Documentation. The rule should include a provision that owners or operators document each training session and spill response drill conducted, and maintain training session and drill records for five years. (47, 96)

Editorial suggestion. We should clarify proposed §112.7( f), in which we continue to use the word should. The commenter suggested that we replace should with either shall or "it is recommended" to avoid confusion. (16)

Timing of employee training.

Support for annual training requirement. We should allow owners or operators to coordinate SPCC Plan training with local oil spill response organizations or Local Emergency Planning Committees (LEPCs) whenever possible. (27) Favors proposed provision for annual training exercises. (27, 34, 141)

Opposition to prescribed training periods. We should avoid requiring a period for conducting training exercises. (62, 66, 71, 109, 113, 128)

Drills. The annual training should not be considered a full scale SPCC drill. (L3)

New employees. We should define the phrase new employee. (103) Others oppose the provision to train new employees within one week of employment, arguing that such a provision is impractical, and called for employer discretion in scheduling training. Some suggested varying time periods in lieu of one week. Those suggestions ranged from one month to one year, with alternatives suggested such as "as soon as practical," "prior to operation but before one year," "within one week of job assignment," "a more reasonable time period," "after training," and "until the next annual training for all employees." (5, 28, 31, 34, 35, 36, 38, 55, 57, 62, 66, 67, 70, 71, 77, 79, 87, 89, 90, 92, 93, 96, 98, 101, 103, 113, 114, 115, 117, 118, 125, 128, 133, 141, 145, 155, 158, 162, 164, 173, 182, 187, 189, L6, L7, L14, L29)

Response: Support for proposal. We appreciate commenter support.

Applicability. We believe that training requirements should apply to all facilities, large or small, including all those that store or use oil, regardless of the amount of oil transferred in any particular time. Training may help avert human error, which is a principal cause of oil discharges. "Spills from ASTs may occur as a result of operator error, for example, during loading operations (e. g., vessel or tank truck  AST transfer operation), 209 or as a result of structural failure (e. g., brittle fracture) because of inadequate maintenance of the AST." EPA Liner Study at 14. The 1995 SPCC Survey found that operator error was the most common spill cause for facilities in 9 of the 19 industry categories that reported having spills. Also, the August 1994 draft report of the Aboveground Oil Storage Facilities Workgroup called "Soil and Ground Water Contamination from Aboveground Oil Storage Facilities: A Strategic Study" presented data on causes of discharges from two studies. Both studies showed that error during product transfer activities is one of the biggest known causes of discharges at AST facilities. Two other studies also support our contention: Carter, W. J., "How API Viewed the Needs for Aboveground Storage Tanks," Tank Talk, Vol. 7, July/ August 1992, p. 2.; and U. S. EPA, "The Technical Background Document to Support the Implementation of OPA Response Plan Requirements," Emergency Response Division, Office of Solid Waste and Emergency Response, February 1993, p. 4 19. We have therefore retained the applicability of training to all facilities. The 1993 proposal would have limited training requirements to only certain facilities which received or transferred over the proposed amount of oil. Facilities which receive or transfer less than the proposed amount might also have discharges which could have been averted through required training. Also the proposed rule would have exempted many facilities that use rather than store oil from its scope. Therefore, we have provided in the rule that all facilities, whether bulk storage facilities or facilities that merely use oil, must train oilhandling employees because all facilities have the potential for a discharge as described in §112.1( b), and training is necessary to avert such a discharge.

We agree with the commenter that training is only necessary for personnel who will use it to carry out the requirements of this rule. Therefore revised paragraph (f)( 1) provides that only oil handling personnel are subject to training requirements, as we proposed in 1993. "Oil handling personnel" is to be interpreted according to industry standards, but includes employees engaged in the operation and maintenance of oil storage containers or the operation of equipment related to storage containers and emergency response personnel. We do not interpret the term to include secretaries, clerks, and other personnel who are never involved in operation or maintenance activities related to oil storage or equipment, oil transfer operations, emergency response, countermeasure functions, or similar activities.

Existing programs. You may incorporate SPCC training requirements into already existing training programs required by other Federal or State law at your option or may conduct SPCC training separately. You may coordinate such training with training on other subjects, or with other agencies like LEPCs or oil spill response organizations.

Content of training. Specifying a minimum list of training subjects is necessary to ensure that facility employees are aware of discharge prevention procedures and regulations. As suggested by a commenter, we have added knowledge of discharge procedure protocols to the list of training subjects because such training will help avert discharges. Therefore, we have specified that training must include, at a minimum: the operation and maintenance of equipment to prevent the discharge of oil; discharge 210 procedure protocols; applicable pollution control laws, rules, and regulations; general facility operations; and, the contents of the facility Plan. As noted above, we require response training for facilities that must submit response plans, but such training is not necessary for all SPCC facilities.

In response to the utility commenter who asserted that utility employees do not need to be trained in the maintenance of oil storage tanks because such maintenance does not involve the transfer and handling of oil, we note that training must address relevant maintenance activities at the facility. If there is no transfer and handling of oil, such topic need not be covered in training.

Discharge prevention briefings. Annual discharge prevention briefings are necessary, but there should be more frequent briefings where appropriate. Such briefings are necessary to refresh employees' memories on facility Plan provisions and to update employees on the latest prevention and response techniques. Training must include the contents of the facility Plan. Although it is desirable, we disagree that we should require SPCC briefings to include emergency response training. That training is already required for those facilities which must prepare response plans.

Documentation. You must document that you have conducted required training courses. Such documentation must be maintained with the Plan for three years.

Editorial suggestion. We agree with the commenter, and have made the editorial change from "should" to "must" for all requirements. We have eliminated all recommendations from the rule to avoid confusing the regulated public with what is mandatory and what is discretionary. Therefore, no shoulds remain in the rule.

Timing of employee training. We agree with commenters who thought it desirable to leave the timing and number of hours of training of oil handling employees, including new employees, to the employer's discretion. "Proper instruction" of oil handling employees, as required in the rule, means in accordance with industry standards or at a frequency sufficient to prevent a discharge as described in §112.1( b). This standard will allow facilities more flexibility to develop training programs better suited to the particular facility. While the rule requires annual discharge prevention briefings, we also agree that the annual briefings required are not drills. In any case, the SPCC rules do not require drills, as explained below.

For purposes of the rule, it is not necessary to define a "new employee" because all oilhandling personnel are subject to training requirements, whether new or not. You do, however, have discretion as to the timing of that training, so long as the timing meets the requirements of good engineering practice.

Unannounced drills. The proposed yearly frequency for unannounced drills is also unnecessary because such drills are already required at FRP facilities, which are higher risk facilities. We do not believe that the risk at all SPCC 211 facilities approaches the same level as at FRP facilities. Therefore, we are not finalizing this proposal, and there are no new costs.

X  I: Security (excluding oil production facilities)  §112.7( g)

Background: Since vandalism is a factor in many spills, we proposed in 1991, to modify the provisions for adequate and effective security. We also proposed to redesignate §112.7( e)( 9) as §112.7( g). These provisions would prevent facility access by unauthorized persons and prevent tampering with equipment and tanks. We proposed in §112.7( g)( 1) to recommend  not require  that owners or operators fully fence all plants handling, processing, or storing oil, and ensure that gates are locked or guarded when the facility is not in production or is unattended.

In §112.7( g)( 2), we proposed to clarify that under current §112.7( e)( 9)( ii), an owner or operator must have adequate security to ensure that valves remain in the closed position when in non operating or non standby status. These valves include master flow and drain valves and any other valves that permit direct outward flow of the tank's contents to the surface. This proposal would allow owners or operators more flexibility in choosing a method of securing the valves, because the current rule requires the valves to be locked.

We proposed editorial changes in redesignated §112.7( g)( 3) (currently §112.7( e)( 9)( iii)) to require that an owner or operator lock the starter control on all pumps in the "off" position. When the pumps are in a non operating or non standby status, the owner or operator would have to locate the starter control at a site accessible only to authorized personnel.

Proposed §112.7( g)( 4) (currently §112.7( e)( 9)( iv)) would require an owner or operator to ensure that oil pipeline loading and unloading connections are securely capped or blank flanged when not in service or standby service for an extended time. We proposed to clarify that "an extended time" is six months or more.

We proposed to recommend in redesignated §112.7( g)( 5) (currently §112.7( e)( 9)( v)) that facility lighting be commensurate with the facility type and location.

Comments: Support for proposal. Favors recommendations for establishing security at a facility. (143)

Opposition to proposal. We should tailor security requirements to specific facility needs. The PE and any responsible company official should determine the security requirements. (162)

Applicability.

Mobile facilities. "Mobile facilities should be exempt from the requirements as well. When in operation they are manned 24 hours per day. In addition, the 212 physical requirements such as landing, loading and unloading connections are not applicable to a mobile facility." (128)

Editorial suggestion. We should define the term "plant." Security options often are limited for facilities located in residential areas. (37)

Fences.

Recommendation. We should recommend that owners or operators fully fence plants with a chain link fence with barbed wire  an adequate system for deterring vandalism. (16) Supports §112.7( g)( 1) recommendation to fence a facility, since owners or operators need discretion not to fence where it is impracticable or undesirable. (57)

Requirement. We should change the proposed §112.7( g)( 1) recommendation to a requirement or delete it. (121)

Loading/ unloading connections. "Larger facilities often have seasonal or contractual variations in the use of lines, pumps, racks and connections. Therefore, it would be costly and impractical to blank off lines only to reopen them in the seventh month. At such facilities, an unused tank would be closed but the piping would remain open. Accordingly, the regulation should recognize normal operating procedures at some facilities and provide operating flexibility while maintaining the necessary security." (54) We should specify that "securely capped" connections include quick disconnect fittings. (92) We should clarify that the second sentence in §112.7( g)( 4) regarding the loading and unloading connection provision included piping emptied of liquid content either by draining or by inert gas pressure. (121) Supports proposal that "an extended time" means more than six months. (147)

Starter controls on pumps. "IFTOA recommends that EPA modify the requirement so that it would apply to facilities, not pumps, that have been closed for six months or more and the rule should be amended to read `locked in the `off' position or electronically disconnected. ' Disconnection, of course, serves the same purpose and frequently is much easier to control." (54) "There is no need for the double security being proposed with the word `and' instead of `or' in the aforementioned requirement. Such double security offers no additional benefit to deter vandals or other unauthorized persons." (67, 79, 85, 95, 102) "At a large facility, such a security requirement becomes unwieldy. The potential for losing keys or having the locks become inoperative due to freezing conditions is great." (88) We should state that pumps must be locked in the" off" position. (121)

Response: Support for proposal. We appreciate commenter support.

Applicability of requirements. We asked in the 1991 preamble (at 56 FR 54616) for comments as to whether provisions proposed as discretionary measures or recommendations should be made requirements. We were concerned whether these 213 proposed measures represented good engineering practice for all facilities. Specific comments are discussed below. In the case of proposed §112.7( g)( 1) and (5) as requirements, we have decided to retain the requirements as requirements rather than convert those paragraphs into recommendations as proposed. We have done this because we believe that fencing, facility lighting, and the other measures prescribed in the rule to prevent vandalism are elements of good engineering practice in most facilities, including mobile facilities. Where they are not a part of good engineering practice, we have amended the proposed provision allowing deviations, §112.7( a)( 2), to include the provisions in §112.7( g).

Editorial suggestion. We agree that the term "plant" has no clear meaning. Therefore, in paragraph (g)( 1), we have substituted the term "facility" in its place, which is a defined term in these rules.

Fences. Fencing helps to deter vandals and thus prevent the discharges that they might cause. In response to the commenter who argued that fences should be topped with barbed wire, or otherwise designed to deter vandalism, we agree. When you use a fence to protect a facility, the design of the fence should deter vandalism. Methods of deterring vandals might include barbed wire or other devices. If any type of fence is impractical, you may, under §112.7( a)( 2), explain your reasons for nonconformance and provide equivalent environmental protection by some other means.

Loading/ unloading connections. In response to comment, we have decided to retain the current time line in §112.7( g)( 4), i. e., "an extended time," instead of specifying a sixmonth time line, due to the need for operational flexibility at facilities. We define "an extended time" in reference to industry standards or, in the absence of such standards, at a frequency sufficient to prevent any discharge. The appropriate method of securing or blank flanging of these connections is a matter of good engineering practice, and might include "quick disconnect fittings" as a possible deviation under §112.7( a)( 2). In any case, a secure cap is one equipped with some kind of lock or secure closure device to prevent vandalism. We disagree that the requirements of this paragraph should apply to the owner or operator of a facility instead of the owner or operator of the piping because a facility might place only some piping out of service for a period of time, and let other piping remain in service. Therefore, the owners or operators of some piping might escape the requirements of the rule and be more likely to discharge oil.

We disagree that this requirement is costly or impractical. The requirement may save money by preventing costly discharges and cleanups.

Regarding making the §112.7( g)( 4) requirements apply to facilities (not piping), we decline to make this change because facilities in service often place some, but not all, of the piping out of service for some period. The current requirement covers any piping out of service for an extended time, regardless of whether the facility is in service.

In response to comment, we note that paragraph (g)( 4) applies to piping emptied of liquid content either by draining or by inert gas pressure. 214 Starter controls on pumps. We disagree that the requirements to have the starter control locked in the off position and be accessible only to authorized personnel are redundant. Restricting access to such pumps prevents unauthorized personnel from accidentally opening the starter control. These measures are necessary to prevent discharges at small as well as large facilities because the threat of discharge is the same regardless of the size of the container, and a small discharge may be harmful to the environment. If the potential for losing keys, weather conditions such as frequent freezing, or other engineering factors render such a measure infeasible, you may use the deviation provisions in §112.7( a)( 2) if you can explain your reasons for nonconformance and provide equivalent environmental protection by some other means.

A facility may have some, but not all, pumps out of service for various periods  even during facility operations. We decline to exempt pumps which are out of service for six months or more because it would reduce the effectiveness of this preventive measure by leaving some piping unprotected for up to half a year.

Valves. Revised §112.7( g)( 2) requires you to ensure that the master flow and drain valves and other valves permitting outward flow of the container's contents have adequate security measures. The current rule requires that such valves be securely locked in the closed position when in non operating or non standby status. Today's revised rule allows security measures other than locking drain valves or other valves permitting outflow to the surface. Manual locks may be preferable for valves that are not electronically or automatically controlled. Such locks may be the only practical way to ensure that valves stay in the closed position. For electronically controlled or automated systems, no manual lock may be necessary. The rule gives you discretion in the method of securing valves. We believe that this flexibility is necessary due to changes in technology and in the use of manual and electronic valving.

X  J: Facility tank car and tank truck loading/ unloading racks  §112.7( h)

Background: Section 112.7( e)( 4) of the current rule describes the precautionary measures an owner or operator must undertake in tank car and tank truck loading/ unloading racks to prevent discharges during transfers. Section §112.7( e)( 4)( i) requires that tank car and tank truck loading and unloading procedures meet the Department of Transportation's (DOT) minimum requirements and regulations. Section 112.7( e)( 4)( ii) requires that, where rack area drainage does not flow into a catchment basin or treatment facility designed to handle spills, an owner or operator must use a quick drainage system. Further, the containment system must be able to hold at least the maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded at the plant. Under §112.7( e)( 4)( iii), an owner or operator must use an interlocked warning light, physical barrier system, or warning signs in loading/ unloading areas to prevent vehicular departure before complete disconnect. Section 112.7( e)( 4)( iv) of the current rule describes the examination and maintenance requirements that must be completed prior to filling and departure. 215 In 1991, we reproposed current §112.7( e)( 4), with a few changes. In §112.7( h)( 1), we proposed language requiring that tank truck loading/ unloading procedures meet the minimum requirements and regulations established by State and Federal law, in place of the current requirement that these procedures comply with DOT requirements and regulations.

Comments: Alarm or warning systems. EPA should consider "adding the additional requirement that wheel chocks be used during all tank truck transfers "to guarantee that tank trucks will not roll unexpectedly while the loading arm is attached and the driver is out of the cab." (16) We should revise §112.7( h)( 3) to include additional industry standard equipment, and read as follows: "( 3) An interlocked warning light or physical barrier system, vehicle brake interlock system, or warning signs, or a system substantially similar in effectiveness shall be provided . . ." (83)

Applicability. Asks us to clarify which types of facilities are subject to these provisions. (79) Asks whether this section applies only to facilities "routinely used for loading or unloading of tanker trucks from or into aboveground bulk storage tanks" or to any loading or unloading operation. (125)

Phase in. We should allow facility owners or operators at least two years to comply with the requirements of this section. (71) We should provide more than 60 days from the date we promulgate the final rule. (125)

Production facilities. "We believe that EPA should clarify that the provisions of this section do not apply to crude oil transfers from production fields into tank trucks. Adequate protection from the small drips that may occur from transferring crude to a tank truck is provided by a small sump or catchment basin." (75, 145, 167)

Small facilities. We should exempt small oil production facilities. (28, 79, 175) We should exempt small aboveground tanks containing 1,000 barrels or less of oil. A portable drip plan has been sufficient for the degree of spill risk at such facilities. (67, 91, 101) Onshore production facilities should be exempted because they are small and have a negligible spill history. (167)

Warning system. Asks whether the interlocking warning system requirement applies to tank batteries, plants, or both. (28, 101)

Cost. Most Appalachian oil production operations would have to newly install the secondary containment system required under this section. Asks whether we factored the economic impact of installing such containment into the fiscal impact of the proposed rule. (28, 31, 113, 165, 187, L15)

Editorial suggestions. We should replace loading/ unloading rack with loading/ unloading area in the section title to clarify that the provisions apply to all types of loading/ unloading stations. (47) We should define facility tank car and tank truck 216 loading/ unloading racks to clarify the type of facility to which this provision applies. (58, 79) We should move all of §112.7( h) to §112.8. (121)

Other State or Federal law. "While SPCC facilities are subject to such requirements in addition to the SPCC rules, failure to meet such other requirements should not constitute a violation of the SPCC rules." (67) We should remove the reference to other state and federal law from the rule. (121) "The Company feels that proposed §112.7( h) should be eliminated. ... These are Department of Transportation items and should be covered by that Department's rules governing loading, unloading, and vehicle inspection. The compliance onus should be on the transporter." (164)

Secondary containment.

Support. Some degree of secondary containment is necessary during truck loading, but questions the need for such a large catchment system. (187)

Contingency plan instead. We should allow a strong contingency plan in place of secondary containment. (28, 31, 101, 165, L15)

Methods. We should clarify whether the use of any of the discharge prevention systems in §112.7( c) would satisfy §112.7( h)( 1) that the containment system be designed "to hold at least the maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded in the plant." (115)

Quick drainage system. We should define the term quick drainage system. Asks whether there are other acceptable ways to comply with this regulation (e. g., blocking nearby storm drains). (29) Recommends that we allow owners or operators to use the drainage control structures/ equipment listed in §112.7( c) in place of the quick drainage system. (124)

Completely buried tanks. "The Ohio Utilities request U. S. EPA interpretation on whether such requirement applies solely to aboveground tank loading and unloading areas, or whether it would also apply to underground storage tank loading and unloading areas as well. If this provision attempts to regulate underground storage tanks loading and unloading areas, the Ohio Utilities strongly believe that such attempted regulation is inappropriate and would result in a multiplicity of regulation since the federal underground storage tank regulations, 40 CFR part 280, already regulate, to some extent, the loading and unloading procedures of underground storage tanks." (189)

Response personnel instead. "Because many tank car loading/ unloading facilities are located on railroad property, or modifications that could undermine the railway bed are subject to railroad approval, providing containment for railcars is typically not feasible. ... Operators should have the option of providing for response personnel to be placed on alert when such an activity is to take place, and, where site conditions allow, provide a capture plan similar to, but more 217 limited in scope, than a full contingency plan. This would encourage secondary containment for storage tanks and other potential sources." (76)

Unnecessary, procedures instead. "GM believes that mandatory tank car loading and unloading containment systems designed to hold at least the maximum capacity of any single compartment of a tank car or tank truck is unnecessary and costly. The cost to renovate existing loading and unloading areas at large manufacturing facilities is substantial and may have negligible environmental benefit if a spill does not occur or if the spill is not the entire contents of the tanker. ... GM recommends that in lieu of mandatory containment of the entire contents of the largest compartment of the tanker, an owner be allowed to demonstrate that procedures are in place to ensure that personnel are present at all times to supervise tank truck loading and unloading." (90)

Vehicle drain closure. "Accordingly, EPA should delete that portion of proposed section 112.7( h)( 4) relating to examination and repair of trucks from the final rule. First, in most cases the trucks that pull up under a terminal's rack do not belong to the owner or operator of the facility. They are the property of petroleum marketers who are independent from the facility owner or operator. ... Second, facility employees are not trained or capable of properly examining and repairing trucks to prevent leakage, and such an obligation certainly could result in a major safety problem. Third, many facilities are completely automated or automated during certain periods of time during the day or night; there is no one at the facility. Thus, the requirement would prevent the operation of terminals at these times and would substantially disrupt the petroleum distribution system nationwide. Fourth, the Department of Transportation imposes the responsibility for maintenance and repair of motor vehicles on the owner or operator of the vehicle, the individual who controls the vehicle. EPA should adopt the same policy." (54, 115)

Response: Alarm or warning systems. The requirement to provide a warning light or other physical barrier system applies to the loading/ unloading areas of facilities. We have amended the rule on the suggestion of a commenter to include "vehicle brake interlock system or other system substantially similar in effectiveness," and "wheel chocks." The examples listed in the rule of potential warning systems are merely illustrative. Any other alarm or warning system which serves the same purpose and performs effectively will also suffice to meet this requirement.

Applicability. This section is applicable to any non transportation related or terminal facility where oil is loaded or unloaded from or to a tank car or tank truck. It applies to containers which are aboveground (including partially buried tanks, bunkered tanks, or vaulted tanks) or completely buried (except those exempted by this rule), and to all facilities, large or small. All of these facilities have a risk of discharge from transfers. Our Survey of Oil Storage Facilities (published in July 1996) showed that as annual throughput increases, so does the propensity to discharge, the severity of the discharge, and, to a lesser extent, the costs of the cleanup. Throughput increases are often associated with transfers of oil. 218 The requirements contained in this section, including those for secondary containment, warning systems, and inspection of trucks or cars for discharges are necessary to help prevent discharges. If you can justify a deviation for secondary containment requirement in paragraph (h)( 1) on the basis that it is not practicable from an engineering standpoint, you must provide a contingency plan and take other actions to comply with §112.7( d). If you seek to deviate from any of the requirements in paragraphs (h)( 2) or (3), you must explain your reasons for nonconformance, as provided in §112.7( a)( 2), and provide measures affording equivalent environmental protection.

We disagree that a contingency plan (whether labeled "strong" or otherwise) is a preferable alternative to secondary containment. Secondary containment is preferable because it may prevent a discharge that may be harmful as described in §112.1( b). A contingency plan is a plan for action when such discharge has already occurred. However, as noted earlier, if secondary containment is not practicable, you must provide a contingency plan and take other actions as required by §112.7( d). EPA will continue to evaluate the issue of whether the provisions for secondary containment found in §112.7( h)( 1) should be modified or revised. We intend to publish a notice asking for additional data and comment on this issue.

We disagree that the section regulates activities already under the purview of the U. S. Department of Transportation. We regulate the environmental aspects of loading/ unloading transfers at non transportation related facilities, which are legitimately part of a prevention plan. DOT regulates other aspects of those transfers, such as safety measures.

Phase in. None of the requirements of §112.7( h) are new, therefore compliance is already required, and no phase in is necessary.

Cost. We believe that we have considered costs adequately, and invite the interested reader to review the Regulatory Analyses in the docket for this rulemaking. This is not a new requirement, and therefore, none of the costs are "new". Appalachian and other oil production operators who are presently in compliance with these provisions will not incur additional economic impact as a result of the revision.

Editorial suggestion. We disagree that we should change loading rack to "loading/ unloading area" because we did not propose the change. We disagree that we should move the requirements to §112.8. We intend §112.7( h) to apply to all facilities, including production facilities; §112. 8 does not cover production facilities.

Other State or Federal law. We have withdrawn, as unnecessary, proposed §112.7( h)( 1), which would have required that facilities meet the minimum requirements of Federal and State law. Those requirements apply whether they are mentioned or not.

Secondary containment. As noted above, the requirement for secondary containment applies to all facilities, whether with aboveground or completely buried containers. This 219 includes production facilities and small facilities. The method of secondary containment must be one of those listed in the rule (see §112.7( c)), or some similar system that provides equivalent environmental protection. The choice of method is one of good engineering practice. However, in response to comments, we note that sumps and drip pans are a listed method of secondary containment for offshore facilities. A catchment basin might be an acceptable form of retention pond for an onshore facility. Whatever method is implemented, it must be capable of containing the maximum capacity of any single compartment of a tank car or tank truck loaded or unloaded in the facility. A discharge from the maximum capacity of any single compartment of a tank car or tank truck includes a discharge from the tank car or tank truck piping and hoses. This is the largest amount likely to be discharged from the oil storage vehicle. A requirement that secondary containment be able to hold only five percent of a potential discharge when procedures are in place to prevent discharges fails to protect the environment if there is human error in one of those procedures. In case of discharge, the secondary containment system must be capable of preventing a discharge from that maximum capacity compartment to the environment. As mentioned above, if secondary containment is not practicable, you may be able to deviate from the requirement if you provide a contingency plan and otherwise comply with §112.7( d).

Regarding the presence of personnel (as supervisors) to substitute for secondary containment, we agree that spill prevention is always preferable to spill containment. However, preventive measures do not replace the need for a secondary containment system as these measures will never completely eliminate the potential for a spill to occur. Such measures, however, might be part of the contingency plan required when secondary containment is impracticable.

Quick drainage system. A quick drainage system is a device that drains oil away from the loading/ unloading area to some means of secondary containment or returns the oil to the facility. We note that this provision does not apply to any UST system excluded from part 112 under §112.1( d)( 4).

Vehicle drain closure. We believe that the requirement to check vehicles for discharge is important to help prevent discharges. If the check were not done, the entire contents of the vehicle might be discharged. We further believe that the responsibility for compliance with proposed §112.7( h)( 3), as well as with all provisions of the rule, continues to rest with the owner or operator of the facility when those vehicles are loading or unloading oil at the facility. If personnel are not present to inspect the vehicles, the owner or operator must explain his reasons for nonconformance and provide equivalent environmental protection by some other means. See §112.7( a)( 2).

X  K: State rules  §112.7( j)

Background: Section 112.7( e) of the current rule requires an owner or operator to discuss conformance with §112.7 or more stringent State rules, requirements, and guidelines. In §112.7( i) of the 1991 proposed rule (redesignated as §112.7( f) in the final rule), we reproposed the requirement that in addition to the minimal prevention 220 standards listed under §112.7( c), (e), (f), (g), and (h) the owner or operator include in an SPCC Plan a complete discussion of conformance with the applicable requirements and "other effective spill prevention and containment requirements listed in §§ 112.8, 112.9, 112.10, and 112.11 (or, if more stringent, with State rules, regulations, and guidelines).

Comments: Editorial suggestion. We should move §112.7( i) to §112.7( a)( 3). (121) "The proposed language which ties this section to the requirements in other sections of this regulation should be more clearly limited to those sections which are applicable to the facility in question. For example, requirements in section 112.8 ... should not (by the requirement in 112.7( i)) be applied to any portion of any production facility." (L12)

Delegation. We should delegate SPCC program activities to States or explore opportunities to enter into contracts and other cooperative agreements with States. Delegating responsibility to the States would decrease costs to implement the program, and the number of inspections would increase. (27, 52, 111, 154, 185, 193) We should explore the possibility of a grants program to encourage State involvement. (27, 111)

Federal and State regulation.

Consistency with States. Urges "... EPA to be as consistent as possible with rules being adopted or developed by Washington and other states regarding standards for oil spill contingency and prevention plans given federal statutory limitations." (185)

DOT rules. Asks why the proposed requirements are more restrictive than the United States Department of Transportation's (DOT's) requirements for transportation related facilities. The DOT facilities pose a higher risk of discharging oil than our non transportation related facilities. (119)

Duplication. Our proposal is duplicative of other Federal and State programs, is confusing, and hinders an owner's or operator's ability to comply with applicable regulations. We should coordinate with other Federal and State agencies in revising the SPCC regulation. (35, 42, 82, 88, 111, 133, 139, 153, 173, 185, 193) We should exempt all facilities currently covered by other equivalent regulatory programs. (62, 173)

Environmental overkill. "Several of these proposed regulations are more restrictive than State regulations, are environmental overkill, and would result in a facility incurring considerable expense to come into compliance." (88)

Federal regulation unnecessary. "While the need for federal regulations is evident in some cases, this is not one of them. In many cases, the proposal overlaps programs already in place at the state level and thwarts the efforts of industry to comply with these environmental protection programs. Each state is unique in its geography, history, and environmental protection goals. Therefore, if states deem oil pollution prevention regulations are necessary to protect its 221 citizens, the states should be allowed to draft regulations that will work to solve their own unique problems." (139, 185, 193)

NPDES. We should exempt facilities or tanks covered by a NPDES discharge permit. (35, 173)

State regulation unnecessary. "With regard to expense, the act of encouraging State and Federal governments `to supplement the Federal SPCC programs' invites yet another raid on the treasuries of companies through `revenue enhancing' permit fees. Additionally, when blanket `encouragements' are extended, consideration should be given to the potential for a chaotic lack of uniformity that inevitably results." (45, 82)

One plan. We should require one plan for facilities covered under the Clean Water Act (CWA), the Resource Conservation and Recovery Act (RCRA), and SARA Title III. (80)

Other law. We should clarify that an owner or operator must comply with any applicable section of §§ 112.8 through 112.11 provision referenced in §112.7( i). For example, a reference in §112.7( i) to §112.8 would apply only to onshore facilities, excluding production facilities. (L12)

Response: Consistency in rules. As noted above, you may now use a State plan as a substitute for an SPCC Plan when the State plan meets all Federal requirements and is cross referenced. When you use a State plan that does not meet all Federal requirements, it must be supplemented by sections that do meet all Federal requirements. At times EPA will have rules that are more stringent than States rules, and some States may have rules that are more stringent than those of EPA. If you follow more stringent State rules in your Plan, you must explain that is what you are doing.

Cross referencing of requirements. In response to the commenter who believed that proposed §112.7( i) (redesignated in today's rule as §112.7( j)) might require him to discuss inapplicable requirements, we note that you must address all SPCC requirements in your Plan. You must include in your Plan a complete discussion of conformance with the applicable requirements and other effective discharge prevention and containment procedures listed in part 112 or any applicable more stringent State rule, regulation, or guideline. If a requirement is not applicable to a particular type of facility, we believe that it is important for an owner or operator to explain why.

Delegation. We have no authority under the Clean Water Act to delegate our program or elements of it to the States. However, States may enact their own programs. Government agencies at the State and tribal level often exercise authority over SPCCregulated facilities that is similar to EPA's authority. Closer coordination with such government agencies could effectively expand SPCC's reach and effectiveness while helping State and tribal programs administer their own activities. This could be accomplished by the development of Memorandums of Understanding (MOUs) and 222 Interagency Agreements (IAGs) with individual States and tribes. EPA will also explore the development of a State and tribal partners program. In such a program States and tribes would participate on a voluntary basis and agree to perform some program functions and report information to a common information system in a prescribed format. EPA would maintain the databases and provide training and administrative support to participating States and tribes. This could include delivery of a fuels management class, and the sponsorship of training and conferences in every region for States and tribes to better understand the regulated universe and to better inspect target facilities. We will also explore better data tracking and sharing with States.

Editorial suggestion. We believe that provision fits better at the end of §112.7 than in §112.7( a)( 3) because it references not only the provisions of §112.7, but the applicable sections of the part which follow, as well as reference to State rules, regulations, and guidelines.

To simplify the rule language, we have amended the proposed rule to state that you must discuss all applicable requirements in the Plan instead of listing all of the sections individually.

Federal and State regulation. Both the States and EPA have authority to regulate containers storing or using oil. We believe State authority to regulate in this area and establish spill prevention programs is supported by section 311( o) of the CWA. Some States have exercised their authority to regulate while others have not. We believe that State SPCC programs are a valuable supplement to our SPCC program. When no State program exists, the Federal program becomes even more necessary.

We also note that you may use NPDES records for SPCC purposes, and may use a Best Management Practices Plan as an SPCC Plan if it meets all SPCC requirements, or may supplement so that it does. See §§ 112.7 (introduction), 112.7( e), 112.8( c)( 3)( iv), and 112.9( b)( 1).

We also note that our facilities differ from DOT facilities in many important aspects, therefore different rules are necessary.

Other law. Final §112.7( j) refers to applicable requirements in all of part 112 or more stringent State law.

Preemption. We do not preempt State rules, and defer to State rules, regulations, and guidelines that are more stringent than part 112. 223 Category XI: Onshore facility Plan requirements (excluding production facilities)

XI  A: Facility Drainage  §112.8( b)

Background: Facility drainage. In 1991, we proposed several changes to §112.7( e)( 1) of the current rule on facility drainage at onshore facilities (excluding production facilities). We proposed to redesignated §112.7( e)( 1)( i) through (iv) of the current rule as §112.8( b)( 1) through (4). The proposed paragraphs addressed requirements for: facility drainage at a diked area, (b)( 1); the prohibition on a flapper type drain for diked areas, (b)( 2); drainage systems for undiked areas, and a diversion system for a facility where drainage failed to meet the requirements of paragraphs (b)( 1)( 3), (b)( 4).

In 1991, we proposed to redesignate §112.7( e)( 1)( i) of the current rule on facility drainage from diked areas, as §112.8( b)( 1). We proposed to redesignate §112.7( e)( 1)( ii) of the current rule, on the prohibition on flapper type drains for diked areas, as §112.8( b)( 2). We left redesignated paragraphs (b)( 1) and (2) substantially the same as the equivalent provisions in the current rule. We proposed to redesignate §112. 7( e)( 1)( iii) of the current rule, on covered drainage systems for undiked areas, as §112.8( b)( 3). However, in proposed paragraph (b)( 3), we clarified that an undiked area must drain into a pond, lagoon, or catchment basin only if the area is located such that it has a reasonable potential to be contaminated by an oil discharge. We also proposed to recommend  rather than require  that an owner or operator avoid placing a catchment basin in an area subject to periodic flooding. We proposed to redesignated §112.7( e)( 1)( iv) of the current rule as §112.8( b)( 4). In paragraph (b)( 4), we proposed a requirement that at a facility without a drainage system described in paragraphs (b)( 1) through (3), a diversion system must retain oil in the facility, rather than return oil to the facility after the oil already was discharged.

XI A( 1) Diked storage area drainage  §112.8( b)( 1)

Comments: Applicability. "Broadly read this could require a pond or lagoon to capture drainage from every inch of our manufacturing facilities." Suggests limiting proposal to "areas with potential to receive spills from tanks greater than 660 gallons or areas with tanks regulated under these rules." (126)

Electrical equipment. The diked storage area drainage requirement should not apply to electrical utility systems (such as lubrication systems and hydraulic lift systems) that use oil for operational purposes. We should not regulate these systems as we would regulate a storage tank. (125)

Secondary containment. "For facilities with site wide containment, or that have substantial storm water draining onto and across the site, providing such detention is not practical, and, ... , may encourage/ justify reliance on contingency plans in lieu of containment." (76) 224 De minimis amounts of oil. It would be impossible for owners or operators to ensure that "no oil" would be discharged into water from diked areas, because the human eye is incapable of perceiving minute amounts of oil in water. We should create a more objective standard, such as the "oil sheen" standard that appears in 40 CFR 110.3. (125)

Oil/ water separators. "The use of oil water separators, underflow uncontrolled discharge devices, and other apparatus can substantially reduce the potential of a significant spill of floating or other products which can be separated by gravity." (76, 125)

Response: Applicability. We disagree that we should limit the scope of this section to facilities having areas with the potential to receive discharges greater than 660 gallons or areas with tanks regulated under these rules. Small discharges (that is, of 660 gallons or less) as described in §112.1( b) from diked storage areas can cause great environmental harm. See section III. F of the preamble to today's rule for a discussion of the effects of small discharges. We disagree that this section should apply only to areas with tanks regulated under these rules because this rule applies to regulated facilities, not merely areas with regulated tanks or other containers. A facility may contain operating equipment within a diked storage area which could cause a discharge as described in §112.1( b).

We disagree that the requirement is not practical for facilities with site wide containment, or that have substantial storm water draining onto and across the site. Where oil/ water separators, underflow uncontrolled discharge devices, or other positive means provide equivalent environmental protection as the discharge restraints required by this section, you may use them, if you explain your reasons for nonconformance. See §112.7( a)( 2). However, you must still ensure that no oil will be discharged when using alternate devices.

De minimis amounts of oil. This rule is concerned with a discharge of oil that would become a discharge as described in §112.1( b). When oil is present in water in an amount that cannot be perceived by the human eye, the discharge might not meet the description provided in 40 CFR 110.3. Therefore, such a discharge might not be a discharge in a quantity that may be harmful, and therefore not a reportable discharge under part 110. However, a discharge which is invisible to the human eye might also contain components (for example, dissolved petroleum components) which would violate applicable water quality standards, making it a reportable discharge. Therefore, we are keeping the language as proposed, other than making some editorial changes.

XI A( 2) Diked storage areas  valves used; inspection of retained stormwater

112.8( b)( 2)

Comments: Innovative devices. "This section should be modified to make clear whether drainage systems that allow the passage of water but not oil, such as drains equipped with imbiber beads, may be used for facility drainage." (39, 76,125) 225 Response: Innovative devices. This rule does not preclude innovative devices that achieve the same environmental protection as manual open and closed design valves. If you do not use such valves, you must explain why. The provision for deviations in §112.7( a)( 2) allows alternatives if the owner or operator states his reasons for nonconformance, and provides equivalent environmental protection by some other means. However, you may not use flapper type drain valves to drain diked areas. And if you use alternate devices to substitute for manual, open and closed design valves, you must inspect and may drain retained storm water, as provided in §112.8( c)( 3)( ii), (iii), and (iv), if your facility drainage drains directly into a watercourse, lake, or pond bypassing the facility treatment system.

XI A( 3) Drainage from undiked areas  §112.8( b)( 3)

Comments: Support for proposal. We should permit facility drainage systems from undiked areas to flow into ponds, lagoons, or catchment basins designed to retain spilled oil or into the plant water treatment system, if that system is designed to retain spilled oil. (121) "Section 112.8( b)( 3) clearly envisions and allows for facilities which have undiked oil storage areas and provides a standard for the capture of any spill from such areas through the use of catchment basins, lagoons and the like using a design of the facility's choosing. Velsicol supports such a standard for undiked oil storage areas." (L26)

Catchment basins. "It is highly unlikely that catchment basins will operate effectively during a flood event. Since these types of facilities could cause significant harm to the environment, EPA should require that catchment basins not be located in areas subject to flooding." (12) "Catchment basins in areas subject to flooding essentially ensure eventual surface water contamination. The proposed regulations should be expanded to require that no new facilities used for oil or hazardous substance storage are sited in floodplains, and drainage systems for existing facilities are engineered (even if it requires pumping of contaminated water to a higher level for storage prior to treatment) so that minimal amounts of contaminated water are retained in areas subject to periodic flooding." (44)

Applicability  generally. We should require facility drainage systems from undiked areas to flow into a pond, lagoon, or catchment basin "where possible" or "if practicable." (54) It is impossible to specify what constitutes proper drainage control for all types of facilities. Therefore, we should retain the verb "should" as in the current rule "to allow for the exercise of good engineering practice." (125)

Electrical equipment. "It would be very impractical to divert flow across an entire site to a pond, lagoon or catchment basin where such flow is currently uncollected or, if collected, is diverted to a storm drainage system prior to discharge. Indeed, for electrical equipment, there is an inherent inconsistency between the drainage requirements of proposed §112.8( b)( 3) and the secondary containment exclusion of proposed §112.8( c)( 2). ... A suggested method for reducing the impracticality and inconsistency of the proposed requirement is to 226 limit the applicability of §112. 8( b)( 3) to "systems with a potential for oil spill `discharge' into or upon the navigable waters of the United States rather than the broader and more encompassing potential for `contamination'." (100) The drainage requirements would impose a substantial financial burden on facility owners or operators and the burden on the electrical utility industry would outweigh the environmental benefits. (125) In urban areas, it would be impossible for owners or operators to meet the drainage requirements for transformers in vaults in large office and apartment buildings, and underneath urban streets. "Similarly, there is simply no space at such sites to construct the drainage control structures required by the proposal." (125, 189)

Alternatives. "If it is the intent of the US EPA to require catchment for such areas, the operator should have the option of providing spill control by committing to the regular inspection of, and immediate clean up of spills, within such areas." (76) Asks clarification as to whether a properly sized and operated oil/ water separator meets the §112.8( b)( 3) requirement for drainage control. (92, 125)

Response: Support. We appreciate commenter support.

Applicability. We disagree that the rule language should become a recommendation because we believe that it is important to control the potential discharges the rule addresses. The rule does this by requiring retention of water within the facility from undiked areas if there is no provision for flow into ponds, lagoons, or catchment basins designed to retain oil or return it to the facility. Where a diversion system is infeasible, if you explain your reasons for nonconformance, you may provide equivalent environmental protection by an alternate means.

In response to the commenter who questioned the applicability of this paragraph to areas under aboveground piping and loading/ unloading areas, we note that both areas are subject to the rule's requirements if they are undiked.

Electrical equipment. The requirements of paragraph (b)( 3) apply to a facility with electrical equipment. If you determine it is infeasible to comply with the requirements of the paragraph, you must explain your reasons for nonconformance, and provide equivalent environmental protection. 40 CFR 112.7( a)( 2).

Alternatives. The rule does not limit you to the use of drainage trenches for undiked areas. Other forms of secondary containment may be acceptable. The rule only prescribes requirements for the drainage of diked areas, but does not mandate the use of diked areas. However, if you do use diked areas, the rule prescribes minimum requirements for drainage of those areas. Also, if the requirement is not practical, you may explain your reasons for nonconformance and provide equivalent environmental protection under §112.7( a)( 2).

XI A( 4) Diversion systems  §112.8( b)( 4) 227 Comments: "Ohio EPA agrees with the proposed language regarding facility drainage. The proposed language requires, rather than suggests, that facility drainage flow to a catchment basin, Also, oil is to be `retained' at the facility, rather than `returned. ' While we understand that this change implies that the spill should not leave the facility boundaries, it should be further clarified." (27) We should require the owner or operator either to retain oil within the facility or return it to the facility, whichever is applicable. The diversion system requirement should apply only to the "petroleum areas of the facility such as tanks, pipes, racks, and diked areas" because "drainage from the rest of the facility should not be contaminated and thus should not have to be diverted." (54)

Response: The rule accomplishes the aim of retaining within the facility minimal amounts of contaminated water in undiked areas subject to periodic flooding. It is better that a diversion system retain rather than allow oil to leave the facility, thus enhancing the prevention goals of the rule. Furthermore, it should be easier to retain discharged oil rather than retrieve oil that has been discharged from the facility. Therefore, we agree with the commenter that "retained" oil is oil that never leaves the facility. We also agree that the rule applies only to drainage from the "petroleum" (or other oil) areas of the facility such as tanks, pipes, racks, and diked areas, because the purpose of the SPCC rule is to prevent discharges of oil, not of all runoff contaminants. Amendment of the rule language is unnecessary because all of the rule applies only to "petroleum" or "oil" areas of the facility. Therefore, we have promulgated the rule language as proposed with a minor editorial change.

XI A( 5) Drainage systems  §112.8( b)( 5)

Comments: PE certification. We should add a section to the rule requiring that Professional Engineers (PEs) certify the design and construction of the storm water drainage system and the sanitary sewer system, because the PE is in the best position to prepare the spill containment parts of the SPCC Plan. (47)

Response: PE certification. PE certification is already required for the design of stormwater drainage and sanitary sewer systems by current rules because those systems are a technical element of the Plan. Therefore, we are keeping the language as proposed.

XI A( 6) FEMA requirements  Proposed §112.8( b)( 6)

Comments for this section were combined with comments for section XII D.

XI  B: Bulk storage containers  §112.8( c)

XI B( 1) Material and construction  §112.8( c)( 1)

Background: Section 112.7( e)( 2)( i) of the current rule (redesignated as §112.8( c)( 1) of the final rule) requires an owner or operator of an onshore bulk storage facility to ensure 228 that the material and construction of tanks used to store oil are compatible with the material stored and conditions of storage. In §112.8( c)( 1), we proposed a new recommendation that the construction, materials, installation, and use of tanks conform with relevant portions of industry standards such as API, NFPA, UL, or ASME standards.

Comments: Support for proposal. "Based on the preamble, it is apparent that the use of industry standards is intended to be a recommendation and not a requirements. Valvoline fully supports the use of standards in this manner as they were not developed for use as regulatory requirements and are not applicable or necessary in all possible situations. As a result, their use should be discretionary utilizing good engineering practices as appropriate. However, the wording utilized in section 112. 8( c)( 1) taken in conjunction with section 112.7( a) is contradictory as to whether or not the use of industry standards is a recommendation or a requirement." (67, 95, 102, 115, 148)

Opposition to proposal. We should not place recommendations in the regulation. We should not ask owners or operators to consider good engineering practice since this makes the regulation unenforceable. Instead, we should tell the owner, operator, or certifying engineer what good engineering practice requires. We should substitute proposed §112.8( c)( 2) with the proposed §112.8( c)( 1) text and delete the recommendation, which is "advisory and unenforceable." (121)

Additional industry standards. In §112.8( c)( 1), we should reference the Steel Tank Institute (STI) standard F911 91, "Standard for Unitized Steel Aboveground Storage Tank Systems with Open Top Secondary Containment." (140) The industry standards listed in the preamble are "extremely important," but these standards do not address the physical site and its surrounding lands and waters. (L4)

Requirement instead. The rule should require, not recommend, that tanks meet industry standards. "At a date certain, all existing tanks should be upgraded to meet industry codes. Moreover, all new and reconstructed tanks should be subject to applicable codes." (44) We should change §112.8( c)( 1) to require the following: "All tanks constructed after the effective date of this part must be constructed to one of the following industry standards (list here the standards acceptable to EPA). The owner or operator shall retain records, as part of the (SPCC Plan), to show which standard was used in the construction of the tank, and a certification plate, setting forth the standard to which the tank was constructed and the date of its construction shall be permanently affixed to the tank." (121)