Recordkeeping. The recordkeeping provisions in proposed §112.9( c)( 1) are overly burdensome and of little benefit. (28, 58)

Small facilities. We should exclude small facilities from the recordkeeping requirements. (58)

Response: Applicability. We believe that this requirement must be applicable to both large and small facilities to help prevent discharges as described in §112. 1( b). The risk of such a discharge and the accompanying environmental damage may be harmful whether it comes from a large or small facility. We disagree that the recordkeeping is burdensome. If you are an NPDES permittee, you may use the stormwater drainage records required pursuant to 40 CFR 122.41( j)( 2) and 122.41( m)( 3) for SPCC purposes, thereby reducing the recordkeeping burden.

Editorial changes and clarifications. In response to the commenter's suggestion, the reference to "navigable waters" becomes a reference to "a discharge as described in §112.1( b)." "Central treating stations" becomes "separation and treating areas." Such areas might be centrally located or located elsewhere at the facility and might include both separation and treatment devices and equipment. The reference to "rainwater is being drained" becomes "draining uncontaminated rainwater." We clarify that accumulated oil on rainwater must be disposed of in accord with "legally approved methods," not "approved methods."

Alternatives. We should modify proposed §112.9( c)( 1), allowing owners or operators to recycle accumulated oil on the rainwater by other methods. This modification would allow flexibility to seek alternate, environmentally sound recycling methods. (L12) 276 Engineering methods. "Equivalent" measures referenced in the rule might, depending on good engineering practice, include using structures such as stand pipes designed to handle flow through conditions at water flood oil production operations, where large volumes of water may be directed to oil storage tanks if water discharge lines on oil water separators become plugged. Any alternate measures must provide environmental protection equivalent to the rule requirement.

Industry standards. Industry standards that may assist an owner or operator with facility drainage include API Recommended Practice 51, "Onshore and Oil and Gas Production Practices for Protection of the Environment."

Recordkeeping. We agree that a five year record retention period is longer than necessary and have deleted the proposed requirement in favor of the general requirement in §112.7( e) to maintain records for three years. However, this requirement must apply to both large and small facilities to help prevent discharges as described in §112. 1( b). The risk of such a discharge and the accompanying environmental damage from a small facility may be as harmful as from a large facility. If you keep stormwater drainage records required pursuant to 40 CFR 122.41( j)( 2) and 122.41( m)( 3), you may use such records for SPCC purposes, thereby reducing the recordkeeping burden.

XII  B( 2): Drainage ditches, accumulations of oil  §112.9( b)( 2) (proposed as §112.9( c)( 2))

Background: Under §112.7( e)( 5)( ii)( B) of the current rule, an owner or operator of an onshore production facility must inspect and remove accumulations of oil from field drainage ditches, oil traps, sumps, or skimmers. In 1991, we proposed to redesignate §112.7( e)( 5)( ii)( B) as §112.9( c)( 2), and to require the owner or operator to remove oilcontaminated soils as well as accumulated oil within 72 hours, if immediate removal was not feasible. We solicited comments on the appropriate amount of time for discovery and removal of accumulated oil, recognizing that production facilities may not be staffed during a given 72 hour period.

Comments: Authority. EPA lacks CWA authority for this provision. CWA addresses clean water, not "clean dirt." (28, 58)

Clarifications  "accumulation," "oil contaminated soil." We should clarify the terms accumulation and oil contaminated soil in the context of the proposed requirement to remove accumulated oil or oil contaminated materials within 72 hours. (28, 58, 71, 101, 153)

Inspection schedule. "Field drainage ditches, etc., should have a schedule set for inspection of accumulations of oil. OHIO EPA recommends monthly inspections, and within 24 hours of a 25 year storm event." (27) 277 72 hour cleanup standard.

Opposition to proposal.

Bioremediation. "Accumulated oil should be picked up and properly hauled. However, problems associated with oil contaminated soil can often be addressed as well or better if the material is left in place. Bioremediation techniques and other measures which may be used under existing laws are less expensive and create less waste than removal procedures." Proposal may limit bioremediation or other cleanup techniques. Clean up should be allowed in accordance with State and local requirements. (31, 67, 86, 90, 91, 99, 101, 144,145, 160, 167, 173)

Costly. "Landfill space is at a premium and on site bioremediation has the potential to prevent environmental harm in a more cost effective manner with equivalent environmental results." (99, 101, 160)

Impractical or impossible. "In addition, the 72 hour requirement is unreasonable in many instances. In cases where a significant amount of oil has been released, or in remote locations, where it may be difficult to mobilize the equipment needed, or in snowy areas where leaks cannot be easily observed, it may be virtually impossible to complete cleanup within 72 hours." (31, 67, 71, 86, 91, 101, 153, 160, 167, 173, 175, 187, L12, L18) An owner or operator may be unable to obtain proper regulatory authorization to remove and dispose of oil contaminated soil within 72 hours. (31, 86, 153) Removal within 72 hours from the time of the spill would be difficult at an unattended facility. (102) Frequently, it is technically infeasible to remove contaminated soil because of "structural concerns" or the volume of soil. (153, 173) Some facilities have oil contaminated soil from past spills. (162)

Landfill disposal problems. The requirement to remove all oil contaminated soil could compound landfill disposal capacity problems. (99, 165, L15)

Navigable waters. We should require the owner or operator to remove the accumulation of oil only if that oil might reach navigable waters. (L12)

Safety or health problems. The 72 hour requirement could pose a safety or health hazard to employees. (102)

Unnecessary. The 72 hour requirement would be excessive and unnecessary because spill response procedures already must be described in the SPCC Plan. (31, 86) It is unnecessary to remove all spilled oil within 72 hours if the containment system is designed to be impervious to oil for a longer period of time. (71) 278 Time calculations.

Discovery. Since the time when the spill occurred may be unknown, any time frame for removing oil or oil contaminated materials should be based on when the spill is discovered. (67, 71, 91, 102, 133, 153, 167, 173)

72 hour cleanup standard  suggested alternatives.

As soon as practical. We should require that the owner or operator complete clean up operations "as soon as practical" or "within a timely manner," or "after the spill is discovered." (78, 101, 102, 133, 153, 167, 173, 187)

Immediately upon discovery. We should revise the proposal to require that cleanup operations begin immediately upon discovery of a spill, and that every reasonable effort be made to complete the clean up within 72 hours. (153)

Initiation within 72 hours. We should require the initiation of remedial activities to begin within 72 hours from when the spill occurred. (18)

Precautions. "During remediation operations, precautions are taken to prevent contamination of surface water by stormwater runoff. A dike or ditch may be constructed around the area, or oil absorbent materials may be placed around the area. Covering with plastic film is another acceptable means to temporarily prevent stormwater contamination during remediation operations." (99)

Response: Authority. We have adequate authority to require cleanup of an accumulation of oil, including on soil and other materials, because section 311( j)( 1)( C) of the CWA provides EPA with the authority to establish procedures, methods, and equipment and other requirements for equipment to prevent discharges of oil. The broad definition of "oil" under CWA section 311( a)( 1) covers "oil refuse" and "oil mixed with wastes other than dredged spoil." If field drainage systems allow the accumulation of oil on the soil or other materials at the onshore facility and that oil threatens navigable water or adjoining shorelines, then EPA has authority to establish a method or procedure, i. e., the removal of oil contaminated soil, to prevent that oil from becoming a discharge as described in §112.1( b). The cleanup standard under this paragraph requires the complete removal of the contaminated oil, soil, or other materials, either by removal, or by bioremediation, or in any other effective, environmentally sound manner.

Clarifications  "accumulation," "oil contaminated soil."

Accumulation. We retain the term "accumulation of oil," but elaborate on its meaning. "Accumulation of oil" means a discharge that causes a "film or sheen" within the field drainage system, or causes a sludge or emulsion there (see 40 CFR 110.3( b)). An accumulation of oil includes anything on which the oil gathers or amasses within the field drainage system. An accumulation of oil may include oilcontaminated soil or any other oil contaminated material within the field drainage 279 system. See also the discussion of "accumulation of oil" included with the response to comments of §112.8( c)( 10).

Oil contaminated soil. We eliminated the term "oil contaminated soil" because oil must accumulate on something, such as materials or soil.

Inspection schedule. We have retained the "regularly scheduled intervals" standard for inspections. This standard means regular inspections according to industry standards or on a schedule sufficient to prevent a discharge as described in §112.1( b). Whatever schedule for inspections is selected must be documented in the Plan. We decline to specify a specific interval because such an interval might become obsolete with changing technology.

72 hour cleanup standard. We agree that the 72 hour cleanup standard might preclude bioremediation and have therefore deleted it. Instead we establish a standard of "prompt cleanup." "Prompt" cleanup means beginning the cleanup immediately after discovery of the discharge or immediately after any actions necessary to prevent fire or explosion or other imminent threats to worker health and safety.

Precautions. We note that an owner or operator may choose to spread plastic film over the diked area to prevent the occurrence of an accumulation of oil. However, he must dispose of the film properly.

XII  C: FEMA requirements  proposed §112.9( c)( 3)

Comments for this section are addressed in Subcategory XVI B: State programs, SARA Title III, wellhead protection, flood related requirements, OSHA, and industry standards.

XII  D: Production facilities  bulk storage containers  §112.9( c) (proposed §112.9( d))

XII  D( 1) Material and construction  §112.9( c)( 1)

Background: Section 112.7( e)( 5)( iii)( A) of the current rule provides that for an onshore production facility, tanks should not be used for storing oil unless the tank material and construction are compatible with the material stored and the storage conditions. In 1991, we proposed to redesignate the current rule provision as §112.9( d)( 1), and to recommend that tank construction and operation conform to relevant industry standards because applying these standards reflects good engineering practice.

Comments: Local standards. "OOGA seeks clarification that USEPA recognizes that local standards sometimes control industry standards on certain issues and that such could occur under this provision." (58)

Recommendation v. requirement. `Proposed section 112.9( d) should require, rather than recommend, that tanks meet industry standards. At a date certain, all existing tanks 280 should be upgraded to meet industry standards. Moreover, all new and reconstructed tanks should be subject to applicable codes." (44)

Response: Recommendation v. requirement. We are retaining the mandatory requirement to use no container for the storage of oil unless its material and construction are compatible with the material stored and the conditions of storage, as proposed. We have deleted the recommendation that materials, installation, and use of new tanks conform with relevant portions of industry standards because we do not wish to confuse the regulated public over what is mandatory and what is discretionary. However, we endorse its substance. In most cases good engineering practice and liability concerns will prompt the use of industry standards. See §112.3( d)( 1)( iii). In addition, a requirement is not necessary or desirable because local governmental standards on construction, materials, and installation sometimes control industry standards on these matters.

XII  D( 2) Secondary containment  §112.9( c)( 2)

Background: In 1991, we proposed in §112.9( d)( 2) (redesignated as §112.9( c)( 2) in the final rule) (§ 112.7( e)( 5)( iii)( B) of the current rule) to clarify that required secondary containment must include sufficient freeboard for precipitation. We also reproposed the requirement to confine drainage from undiked areas.

Comments: Applicability.

Oil leases. The proposal is "is too vague and comprehensive to be applied to oil leases. It would be applicable to entire leases covering hundreds of acres if interpreted improperly." (31, 101, 165, L15)

Clarification.

Accumulation. "Is accumulated oil and contaminated soil to be removed from diked areas under this provision? What is contaminated soil? What are the cleanup standards under this provision? What is an `accumulation'." (58)

Methods. We should not allow alternate secondary containment systems such as those outlined in §112.7( c)( 1) of this part. (121)

NPDES rules. "The new EPA NPDES storm water program clearly and very thoroughly regulates potential precipitation drainage related pollution from these sources. The requirements in this sentence amount to a duplicative regulatory requirement by the same agency." (28, 101, L12)

Sufficient freeboard. We do not set a standard for "sufficient" freeboard. The owner, operator, or Professional Engineer (PE) should be able to determine the appropriate size for secondary containment on a site by site basis. (75) 281 Response: Applicability. The requirement applies to oil leases of any size. Secondary containment is not required for the entire leased area, merely for the contents of the largest single container in the tank battery, separation, and treating facility installation, with sufficient freeboard to contain precipitation.

Clarification.

Accumulation. We retain the term "accumulation of oil," but elaborate on its meaning. "Accumulation of oil" means a discharge that causes a "film or sheen" within the field drainage system, or causes a sludge or emulsion there (see 40 CFR 110.3( b)). An accumulation of oil includes anything on which the oil gathers or amasses within the field drainage system. An accumulation of oil may include oilcontaminated soil or any other oil contaminated material within the field drainage system. See also the discussion of "accumulation of oil" included with the response to comments of §112.8( c)( 10).

Methods. We disagree that we should not allow alternate secondary containment systems such as those in §112.7( c)( 1). We note that no single design or operational standard is appropriate for all onshore production facilities. An owner or operator must choose the appropriate secondary containment system compatible with good engineering practice.

NPDES rules. We deleted the proposed reference to undiked areas "showing a potential for contamination" because drainage from any undiked area poses a threat of contamination. When drainage from such areas is covered by storm water discharge permits, that part of the BMP might be usable for SPCC purposes. There is no redundancy in recordkeeping requirements, because you can use your NPDES records for SPCC purposes.

Sufficient freeboard. In response to the comment as to how an owner or operator might determine how much freeboard is sufficient, we have revised the rule to provide that freeboard sufficient to contain precipitation is the standard. We have recommended a standard for sufficient freeboard in the final rule. That standard is sufficient freeboard to contain a 25 year, 24 hour storm event. However, because of the difficulty and cost of securing recent information concerning such events, we are not making this a rule standard.

XII  D( 3): Container inspection  §112.9( c)( 3)

Background: Section 112.7( e)( 5)( iii)( C) of the current rule provides that production tanks must be visually inspected on a periodic schedule and the foundation and supports of aboveground tanks must be inspected for deterioration. In 1991, we proposed to designate §112.7( e)( 5)( iii)( C) as §112.9( d)( 3) (redesignated as §112.9( c)( 3) in the final rule) and to require tank examinations at least once a year. We also proposed that an owner or operator keep schedules and records of examinations for the last five years, regardless of change in ownership. 282 Comments: Extent of inspection.

Visual inspections. "It is not practicable to internally visually examine tanks on an annual basis due to the number that would need to be taken out of service at any one time to meet the requirement. API agrees with scheduled visual external examinations of tanks but believes that internal examinations and inspections should be accomplished in accordance with API Recommended Practice 12R1." (67, 85, 167)

Frequency of inspection.

Support for proposal. "Ohio EPA agrees with the provision for annual inspections of tank batteries, and with the requirement to keep the record of inspection for five years." (27)

More frequent inspections. We should direct owners or operators to examine production tanks quarterly. (121)

Opposition to proposal. "Requiring an annual tank inspection and record maintenance is an unnecessary expense. " (101)

"If possible." We should require examining a tank's aboveground foundation and supports only "if practical" or "if possible." An owner or operator might be unable to inspect a tank where the foundation settled or there is a lack of space. (67, 173)

Triennial inspection. Documenting an annual inspection would increase paperwork with no benefit to small facilities. The existing provision is adequate. "More importantly, the three year review of the SPCC Plan pursuant to section 112.5( b) is more than sufficient to document a visual inspection of the facilities." (58, 70)

Record maintenance.

Opposition to proposal. "OOGA is uncertain of the recordkeeping requirement under this provision. Undeniably, owners of crude oil production facilities routinely inspect their storage tanks. To document these inspections seems to serve no useful purpose." (58, 70) "The agency does not indicate a reason for increasing the records retention requirement from three to five years. Most if not all CWA related programs have a mandatory three year records retention requirement. EPA needs to explain their reason( s) for the more costly five year mandatory requirement. This request is made for every EPA mandatory five year record retention requirement in this proposed rule." (L12)

PE Certification. "Regular inspections and record maintenance provisions should not require the certification of a Registered Professional Engineer, which is one possible interpretation of these requirements, as records are included in the Plan." (101, 165, L15) 283 Phase in. The rule should provide for a two year phase in period so that the facility will have the required five years of records. (102)

Response: Extent of inspection. We disagree that the inspection of containers should be limited to external inspection. Internal inspection is also necessary to detect possible flaws that could cause a discharge. The inspection must also include foundations and supports that are on or above the surface of the ground. If for some reason it is not practicable to inspect the foundations and supports, you may deviate from the requirement under §112.7( a)( 2), if you explain your rationale for nonconformance and provide equivalent environmental protection.

API standards. Regarding the comment that we should require internal examinations and inspections in accordance with an API practice, we note that while API standards may be sufficient for many facilities, no single design or operational standard is appropriate for all non transportation related facilities. An owner or operator should choose the appropriate standard in the exercise of good engineering practice.

Visual inspection. Visual examinations must be in accordance with §112.9( c)( 3) specifications, and must include the foundations and support of each container.

Frequency of inspection. We have maintained the current standard for frequency of inspection because we agree that inspections in accordance with industry standards are necessary. Those standards may change with changing technology, therefore, a frequency of "periodically and upon a regular schedule" preserves maximum flexibility and upholds statutory intent.

Owner/ operator discretion. We decline to give an owner or operator absolute discretion to inspect if practical or possible; instead we recommend inspection according to industry standards. Whatever frequency of inspection that is chosen must be noted in the Plan.

Record maintenance. Recordkeeping is necessary to document compliance with the rule. We have deleted the proposed requirement to maintain records of these inspections for five years, irrespective of ownership, because it is redundant with the general requirement in §112.7( e) to maintain Plan records. Section 112.7( e) requires record maintenance for three years. However, you should note that certain industry standards (for example, API Standard 653 or API Recommended Practice 12R1) may specify that an owner or operator maintain records for longer than three years.

PE Certification. We do not require a PE to certify inspection records because such records are not part of the Plan.

XX  D( 4) Good engineering practice  tank batteries  §112.9( c)( 4) 284 Comments: Good engineering practice. "Proposed section 112.9( d)( 4) should contain a requirement for fail safe engineering of oil production facility tanks, just as onshore bulk storage is required to be fail safe engineered (see proposed section 112.8( c)( 8)), to avoid confusion among the regulated community and to improve spill prevention." (27, 44)

Small facilities. "Single tanks with a capacity of 10, 000 gallons or less and facilities with a capacity of 40,000 gallons or less should be exempt from this section." (28, 101)

Too expensive. "Engineering tanks into a `fail safe engineering condition' is prohibitively expensive and unnecessary as far as Appalachian production is concerned." (101)

Vacuum protection. "Installation of vacuum protection on every tank could cost in excess of $100/ tank. We doubt this has been calculated in the potential fiscal impact of these proposals." (28, 31, 101, 165)

Response: Good engineering practice. We agree with the commenter that we should retain this section as a requirement both to improve spill prevention and to avoid confusion among the regulated community because of the similar requirement for bulk storage containers at facilities other than production facilities. Therefore, there are no new costs. Nevertheless, we believe that the costs of these measures are not excessive for small or large facilities because you have flexibility as to which measures you use, and may choose the least expensive alternative listed in §112.9( c)( 4). For example, should vacuum protection be too costly, you are free to use another alternative. Furthermore, you may also deviate from the requirement under §112.7( a)( 2) if you can explain nonconformance and provide equivalent environmental protection by some other means. We revised the paragraph on vacuum protection to clarify that the rule addresses any type of transfer from the tank, not merely a pipeline run.

Vacuum protection. We note that the rule does not require vacuum protection, merely consideration of its use. You may choose to use vacuum protection, another of the listed measures, or an alternative that provides equivalent environmental protection.

XII  E: Facility transfer operations  §112.9( d) (proposed as §112.9( e))

Background: Current §112.7( e)( 5)( iv) provides requirements for facility transfer operations for onshore oil production facilities. In §112. 7( e)( 5)( iv)( A), an owner or operator is required to examine "periodically on a scheduled basis" all aboveground valves and pipelines. In §112.7( e)( 5)( iv)( B), an owner or operator is required to examine salt water disposal facilities "often." In §112. 7( e)( 5)( iv)( C), an owner or operator is required to have a program of flowlines maintenance for their production facilities and we list specific elements that the program must include, such as periodic examinations and adequate records, as appropriate for the individual facility.

In 1991, we redesignated §112.7( e)( 5)( iv)( A)( C) as §112.9( e)( 1)( 3), and proposed several changes. In §112.9( e)( 1), we proposed requiring an owner or operator to examine aboveground valves and piping monthly, and to include examination schedules 285 and records in the Plan for five years. We did not propose any changes to §112.9( e)( 2). In §112.9( e)( 3), we maintained the requirement that an owner or operator have a flowlines maintenance program, but proposed recommending, rather than requiring, that he include in the flowlines maintenance program the specific elements that the current rule requires. We proposed to change this requirement to a recommendation because the circumstances of locations, staffing, and design vary between facilities. We also proposed changing the periodic examination requirement to a recommendation that an owner or operator examine flowlines monthly.

XII  E( 1)  Inspection of aboveground valves and piping  §112.9( d)( 1)

Comments: Editorial suggestion. The rule should be clarified that "only inspections related to transfer operations are intended by inserting `associated with transfer operations' between `piping' and `shall' in the first line of proposed 112.9( e)( 1)." (75)

Frequency of inspection.

Opposition to proposal.

Burdensome. Such a requirement would be unreasonably burdensome. The condition of valves and piping does not change significantly within a month. (67, 91, 133, 173, 187, L18)

Unwarranted. "( I) nformal, regular visual inspections, with no record keeping requirements" should continue. (67) Field personnel routinely notice and fix any oil leaks associated with aboveground valves and pipelines. (101) Monthly inspections of aboveground valves and pipelines "may not be warranted." (175)

Suggested alternatives.

Every 6 months. "The condition of valves and piping does not change significantly within a month's time. Therefore, a more appropriate formal inspection frequency with documentation requirements is semi annual. More informal, regular visual inspections, with no record keeping requirements should continue." (67, 91, 133, 173, 187, L18)

Performance standard instead. "The inspections standard ... should be amended to reflect a performance standard instead of a prescribed monthly inspection.... A generalized performance standard should be included that requires a minimum inspection interval, such as annual inspection, which could be altered to meet specific facility conditions." (31, 86, 160)

Recordkeeping.

Opposition to proposal. The proposed record keeping requirement is unnecessary, of little value, and "prohibitively expensive." (28, 101) Well attendants check 286 Appalachian Basin well sites (including all aboveground piping, valves, joints, gauges, pipe supports, etc.) on a near daily basis, noting necessary repairs. Documenting monthly examinations is unnecessary and a "waste of limited resources and time." It is meaningless to keep records of inspections where no problems were found. (71)

All facilities. We should delete the record keeping requirement for all facilities; documenting monthly visual inspections would drastically increase paperwork with no benefit for small facilities. (70)

PE certification. We should not require PE approval of the owner's or operator's maintenance records, as these records are included in the Plan. (101, 165, L15)

Small facilities. We should exempt small facility owners or operators from the requirement to include aboveground valve and pipeline examination schedules and records in the Plan for five years. (58, 86)

Response: Editorial suggestion. We agree with the commenter and have changed the rule language to provide that §112.9( d)( 1) applies to "aboveground valves and piping associated with transfer operations."

Frequency of inspections. We have retained the current inspection frequency of periodic inspections, but editorially changed it to "upon a regular schedule." Our decision accords with the comment which sought a performance standard instead of a prescribed monthly inspection. The standard of inspections "upon a regular schedule" means in accordance with industry standards or at a frequency sufficient to prevent discharges as described in §112.1( b). Whatever frequency of inspections is selected must be documented in the Plan.

Recordkeeping. We agree that a five year record retention period is longer than necessary and have deleted the proposed requirement in favor of the general requirement in §112.7( e) to maintain records for three years. However, comparison records for compliance with certain industry standards may require an owner or operator to maintain records for longer than three years.

PE certification. PE certification of these inspections and records is not required.

Small facilities. We disagree that we should exempt either a large or small facility owner or operator from the requirement to include aboveground valve and pipeline examination schedules and records in the Plan because those records are needed to document compliance with the rule.

XII  E( 2) Salt water disposal facilities  §112.9( d)( 2)

Comments: Sudden change in temperature. "A sudden change of temperature" is a rather vague indicator of potential system upsets. This commenter assumes that the 287 Agency means a rather sudden `drop' (as in freezing temperatures) that could cause system upsets. This requirement needs further clarification." (187)

Applicability. Salt water disposal facility examination requirement should not apply to storage facilities with de minimis amounts of oil. (28, 58, 101)

Frequency of inspection. To be consistent with other proposed inspection frequencies, the inspection frequency of salt water disposal facilities should be quarterly, rather than weekly. (114)

Response: Applicability. The rule applies to any regulated facility with salt water disposal if the potential exists to discharge oil in amounts that may be harmful, as defined in 40 CFR 110.3. This standard is necessary to protect the environment.

Frequency of inspections. Inspections of these facilities must be conducted "often." "Often" means in accordance with industry standards, or more frequently, if as noted, conditions warrant. Whatever frequency of inspections chosen must be documented in the Plan.

Sudden change in temperature. A sudden change in temperature means any abrupt change in temperature, either up or down, which could cause system upsets.

XII E( 3) Flowlines maintenance  §112.9( d)( 3)

Background: In 1991, in §112.7( e)( 3) (redesignated in the final rules as §112.9( d)( 3)), we maintained the requirement that an owner or operator have a flowlines maintenance program, but proposed recommending, rather than requiring the owner or operator to include in the flowlines maintenance program the specific elements that the current rule requires. We also changed the periodic examination requirement to a recommendation that owners or operators examine flowlines monthly.

Comments: Applicability.

Small facilities. Asks that we exempt small facilities from the flowlines maintenance program requirement. (58)

Frequency of inspections.

Opposition to proposal. We should delete the entire recommendation, and keep only the requirement that production facility owners or operators have a flowlines maintenance program. (121)

Costly. It is cost prohibitive and impossible for owners or operators of Appalachian oil gathering line systems to provide corrosion protection for the bare steel pipe used in these systems. The "use of coated lines and cathodic protection is cost prohibitive." (28, 31, 101, 165, L15) 288 Impossible. "These oil gathering line systems are buried in colder parts of the Appalachian basin, and monthly inspection of them is thus not possible." (28, 31, 165, L15)

Lack of manpower. Owners or operators do not have enough manpower to inspect flowlines monthly. (91, 133, 173)

Unwarranted. "Unless a flowline is known to have problems, monthly inspections may not be warranted. Many production facilities are unmanned and the cumulative length of flowlines can be several miles, so the proposed monthly timeframe may be burdensome." (175)

Suggested inspection alternatives.

Periodic. "Periodic inspections based on engineering judgment and historical data are sufficient to detect any significant deterioration in flowline condition." (67, 85, 91, 160, 173, 175)

Quarterly. (114)

Semi annual. (L18)

Annual. (133).

Response: Applicability. A program of flowlines maintenance is necessary to prevent discharges both at large and small facilities. However, we have deleted the proposed recommendation regarding the specifics of the program from the rule. We took this action because we are not including recommendations in the rule in order not to confuse the public over what is mandatory and what is discretionary. This rule contains only mandatory requirements.

Corrosion protection, flowlines replacement. While we have deleted the recommendation from rule text due to reasons explained above and therefore, the rule imposes no new costs, we recommend corrosion protection, we recommend corrosion protection, and flowlines replacement when necessary, because those measures help to prevent discharges as described in §112.1( b).

Cost. We disagree that the cost of this requirement is excessive or impossible. We do not prescribe the specifics of the program and the owner or operator may use any program (not necessarily the most expensive) effective to maintain the flowlines and prevent a discharge as described in §112.1( b). The requirement is a current one and is necessary to prevent discharges as described in §112.1( b).

Frequency of inspections. In the proposed recommendation we suggested that you conduct monthly inspections for a flowlines maintenance program. We now recommend that you conduct inspections either according to industry standards or at a frequency 289 sufficient to prevent a discharge as described in §112.1( b). Under §112.3( d)( 1)( iii), the Professional Engineer must certify that the Plan has been prepared in accordance with good engineering practice, including consideration of applicable industry standards. 290 Category XIII: Plan requirements for onshore drilling/ workover facilities  §112.10 Background: Under §112.7( e)( 6)( i) of the current rule, an onshore drilling and workover facility owner or operator must position or locate mobile drilling or workover equipment to prevent spilled oil from reaching navigable waters. Section 112.7( e)( 6)( ii) requires that, depending on location, it may be necessary to use catchment basins or diversion structures to intercept and contain spills of fuel, crude oil, or oily drilling fluids. Section 112. 7( e)( 6)( iii) requires the owner or operator install a blowout prevention (BOP) assembly and well control system before drilling below any casing string or during workover operations.

In 1991, we redesignated §112.7( e)( 6)( i), (ii), and (iii) as §112. 10( b), (c), and (d), respectively. We proposed to add §112.10( a), which proposed that in addition to the specific spill prevention and containment procedures listed under §112.10, an onshore oil drilling and workover facility owner or operator must also address the general requirements listed in §112.7. Under proposed §112.10( b), an owner or operator would have to locate mobile drilling or workover equipment to prevent spilled oil discharges. Under proposed §112.10( c), we proposed that depending on the location, catchment basins or diversion structures may be necessary to intercept and contain spills of fuel, crude oil, or oily drilling fluids. Under proposed §112.10( d), we proposed to require that when necessary, before drilling below any casing string or during workover operations, an owner or operator install a blowout prevention assembly and well control system capable of controlling any wellhead pressure that may be encountered while that blowout assembly is on the well.

Comments: Support for proposal. Section §112.10 requirements should include workover and drilling equipment, human activity is often associated with accidental releases. (27)

§112.10( a). "Change to: `In addition to the specific spill prevention and containment procedures listed under this section, onshore oil drilling and workover facilities must also address the requirements listed under section 112.7 and paragraph 112.8( c)( 11) in the SPP. ' (Note: the caveat `excluding production facilities' should probably be removed from 112.8( c).)" (121) In §112.10( a), we should require an onshore oil drilling and workover facility owner or operator to "address the applicable general requirements." (128)

Editorial suggestion. Asks for a definition of "onshore drilling and workover facilities." (154)

§112.10( b)  We should require positioning or locating mobile drilling or workover facilities to prevent oil discharges. (121) "We are categorically opposed to this requirement. The mobile drilling and workover contractor has absolutely no control as to the location of the rig unit.... The contractor has no input as to the site design nor responsibility for its maintenance." (128) Section 112.10( b) is unnecessary because it duplicates Bureau of Land Management (BLM) and State regulatory programs. (167) We should change 291 §112.10( b) to clarify that an owner or operator must prevent spilled oil discharges to navigable water. (L12)

§112.10( d)  The rule should be revised to provide that: "Well service jobs, such as installing a rod pumping unit, may not require a BOP assembly and associated well control system." "BOP are not now, and should not become, a requirement for all operations. Service jobs such as the change out of a rod pumping unit, or the batch treatment of a well with corrosion inhibitor are minimal risk operations and do not normally require the use of BOP systems. These service jobs are minimal risk because they can be performed with existing wellhead equipment in place. If any unexpected pressure is incurred during the service job, then existing valves can be utilized to control the pressure." (67, 91)

Gauge negative. We should explain the term gauge negative. (110)

Response: Support for proposal. We appreciate the commenter support.

§112.10  We disagree that an onshore oil drilling and workover facility owner or operator must address the §112.8( c)( 11) requirements for mobile or portable oil storage tanks unless he has such containers. Section 112.8( c)( 11) pertains only to onshore bulk storage containers (except production facilities).

§112.10( a)  We also disagree that it is necessary to revise the rule to require compliance with applicable §112.7 general requirements because the owner or operator must address all general requirements in §112.7 and all specific requirements in subparts B or C, as appropriate, for the type of facility he owns or operates. If a requirement is not applicable, the owner or operator must explain in the Plan why.

Editorial suggestion. The new definition for "production facility" in §112. 2 includes the procedures, methods, and equipment referenced in this section, making a definition of "onshore drilling and workover facilities" unnecessary.

§112.10( b)  We agree with the commenter that the contractor is not normally responsible for site location, nor site design or maintenance. Such decisions are the responsibility of the facility owner or operator. The owner or operator of the facility has the responsibility to locate mobile equipment so as to prevent a discharge as described in §112.1( b).

We disagree that we should change the word equipment to facilities in §112.10( b). A facility may include structures, piping, and equipment. This paragraph is directed to the threat of discharge from equipment.

We have revised §112.10( b) to provide that an owner or operator must position or locate mobile drilling or workover equipment to prevent a discharge as described in §112.1( b), rather than to prevent spilled oil discharges, as proposed. A discharge as described in 292 §112.1( b) includes a discharge to navigable waters, adjoining shorelines, or affecting certain natural resources.

We disagree that §112.10( b) duplicates BLM and State regulatory programs. The BLM program is not specifically directed to preventing discharges of oil, and to the extent it meets SPCC requirement, any documentation from it may be usable in an SPCC Plan. Likewise for documentation from State regulatory programs.

§112.10( d)  Where BOP assembly is not necessary, as for certain routine service jobs, such as the installation of a rod pumping unit or the batch treatment of a well with corrosion inhibitor, the owner or operator may deviate from the requirement under §112.7( a)( 2), and explain its absence in the Plan. When BOP assembly is unnecessary because pressures are not great enough to cause a blowout, it is likewise unnecessary to provide equivalent environmental protection.

Gauge negative. Gauge negative is the pressure condition in a wellbore that results when the pressure exerted by the hydrocarbon reservoir is less than the hydrostatic pressure exerted by the column of drilling fluid in the wellbore. A gauge negative condition will not give rise to a pressure imbalance likely to cause a blowout. See 56 FR 54625. 293 Category XIV: Requirements for offshore oil drilling, production , or workover facilities  §112.11 Background: Section §112.11 includes SPCC Plan requirements for an owner or operator of an offshore oil drilling, production, and workover facility.

XIV  1 General and specific requirements  §112.11( a)

Comments: State rules. "This section should be deleted because current State spill prevention, water discharge, and hazardous material regulations adequately provide spill protection in inland water areas such as lakes, rivers, and wetlands." (128)

Response: State rules. We disagree with the commenter that these rules are unnecessary because not every State has rules to protect offshore drilling, production, and workover facilities. While some States may have rules, some State rules may not be as stringent as the Federal rules. In any case, Congress has intended us to establish a nationwide Federal program to protect the environment from the dangers of discharges as described in §112. 1( b) posed by this class of facilities. Therefore, we have retained the section, as modified. We note, however, that if you have a State SPCC plan or other regulatory document acceptable to the Regional Administrator that meets all Federal SPCC requirements, you may use it as an SPCC Plan if you cross reference the State or other requirements to the Federal requirement. If it meets only some, but not all Federal SPCC requirements, you must supplement it so that it meets all of the SPCC requirements.

XIV  2 Definition reference; MMS jurisdiction  proposed §112.11( b)

Background: In §112.7( e)( 7)( i) of the current rule, the term oil drilling, production, or workover facilities (offshore) is defined. In 1991, we redesignated §112.7( e)( 7)( i) as §112.11( b), and referenced the proposed §112.2 definition of offshore oil drilling, production, and workover facilities. The proposed rule also would have provided that a facility subject to the Operating Orders, notices, and regulations of the Minerals Management Service (MMS) is not subject to part 112.

Comments: We should delete §112.11( b) because it is unnecessary. (121)

Response: The proposed 1991 section referenced the definition of "offshore oil drilling, production, and workover facility," which is now encompassed within the definition of "production facility" in §112. 2. A new sentence would have referenced the exemption of facilities subject to Minerals Management Service (MMS) Operating Orders, notices, and regulations from the SPCC rule. MMS jurisdiction is outlined in Appendix B to part 112. Since none of the proposed language is mandatory, we have deleted it because we have included only mandates in this rule so as not to confuse the regulated public over what is required and what is discretionary. We received no substantive comments on this paragraph. 294 XIV  3 Facility drainage  §112.11( b) (proposed as §112.11( c))

Background: In §112.7( e)( 7)( ii) of the current rule, requirements for oil drainage collection equipment are described. In 1991, we redesignated §112.7( e)( 7)( ii) as §112.11( c), and proposed to require removal of collected material from oil drainage "as often as necessary to prevent overflow, but not less than once a year."

Comments: Removal of collected oil. We should delete the modification that owners or operators remove collected material at "least once a year," because the current requirement is sufficient. (31, 86)

Response: Removal of collected oil. EPA agrees with the commenter's suggestion that the current rule is sufficient to prevent discharges as described in §112.1( b), and therefore we have deleted the "at least once a year" standard. You must remove collected oil as often as is necessary to prevent such discharges.

XIV  4 Sump systems  §112.11( c) (proposed as §112.11( d))

Background: Under §112.7( e)( 7)( iii) of the current rule, an owner or operator of a facility with a sump system to adequately size the sump and drains must have a spare pump or equivalent method available for removing liquid from the sump, and assure that oil does not escape. In 1991, we redesignated §112.7( e)( 7)( iii) as §112. 11( d) (redesignated in the final rule as §112.11( c)). We also proposed that the owner or operator must employ a monthly preventive maintenance inspection and testing program to assure reliable operation of the liquid removal system and pump start up device.

Comments: Frequency of inspections. "Semi annual, instead of monthly inspection and testing of the liquid removal system would be preferable." (L18)

Response: Frequency of inspections. We have retained the current rule language requiring a "regularly scheduled" preventive maintenance program because we believe that the frequency of maintenance should be in accordance with industry standards or frequently enough to prevent a discharge as described in §112.1( b). Whatever schedule is chosen must be documented in the Plan.

XIV  5 Corrosion protection  §112.11( g) (proposed as §112.11( h))

Background: Under §112.7( e)( 7)( vii) of the current rule, an owner or operator must equip tanks with suitable corrosion protection. In 1991, we redesignated §112.7( e)( 7)( vii) as §112.11( h) (redesignated in the final rule as §112.11( g)). We also recommended that an owner or operator follow the appropriate National Association of Corrosion Engineers standards for corrosion protection. 295 Comments: Industry standards. We should either delete the proposed recommendation or make it a requirement for new construction. (121) We should modify §112.11( h) to incorporate other industry recommended corrosion control practices, particularly STI standards. (140)

Response: Industry standards. In response to the comment, we have deleted the recommendation because we do not wish to confuse the regulated community over what is mandatory and what is discretionary. These rules contain only mandatory requirements. We expect that facilities will follow industry standards for corrosion protection as well as other matters (see §112.3( d)( iii)), but decline to prescribe particular standards in the rule text because those standards are subject to change, and we will not incorporate a potentially obsolescent standard into the rules.

XIV  6 Pollution prevention system testing and inspection  §112.11( i) (proposed as §112.11( j))

Background: Under §112.7( e)( 7)( ix) of the current rule, an owner or operator must test and inspect pollution prevention equipment and systems periodically, commensurate with the complexity, conditions, and circumstances of the facility. In 1991, we proposed to redesignated §112.7( e)( 7)( ix) as §112.11( j) (redesignated in the final rule as §112.11( i)). We proposed to require that an owner or operator use simulated spill testing to test and inspect human and pollution control and countermeasure systems, unless he can demonstrate that another method provides equivalent protection. We also proposed requiring periodic testing and inspection of pollution prevention equipment at least monthly.

Comments: Frequency of testing. "Simulation testing on a monthly basis is excessive." (42, L12)

Annual response drills. MMS requires only annual spill response drills for outer continental shelf operations. "We suggest this is an adequate frequency. Requiring more frequent simulations would overburden facility operators unnecessarily." (75, L12)

Recommendations instead. We should convert periodic reviewing, testing, and inspecting provisions from requirements to recommendations. We can not justify these provisions either economically or as benefits conferred on society. (42)

Semi annual testing. "...( A) semi annual, instead of monthly, requirement for testing and inspection of pollution prevention equipment would be preferable." (L18)

Response: Frequency of testing. We have retained the current requirement for testing on a "scheduled periodic basis" commensurate with conditions at the facility because we believe that testing should follow industry standards or be conducted at a frequency 296 sufficient enough to prevent a discharge as described in §112.1( b) rather than any prescribed time frame. Whatever frequency is chosen must be documented in the Plan.

We disagree that we cannot justify the costs and benefits. This rule is necessary to ensure that systems that prevent discharges function properly.

XIV  7 Blowout prevention  §112.11( k) (proposed as §112.11( l))

Background: Under §112.7( e)( 7)( xi) of the current rule, before an owner or operator drills below any casing string and during workover operations, he must install a blowout prevention (BOP) assembly and well control system. Further, this BOP assembly and well control system must be capable of controlling any expected well head pressure while it is on the well. In 1991, we proposed to redesignate §112.7( e)( 7)( xi) as §112.11( l) (redesignated in the final rule as §112.11( k)), but otherwise reproposed without substantive change.

Comments: Alternatives. "There are occasions where this is not warranted or impractical to implement." Exception should be made for drilling below conductor casing. (L12)

Response: Alternatives. The question of whether blowout prevention is warranted or impractical or not for drilling below conductor casing is one of good engineering practice. Acceptable alternatives may be permissible under the rule permitting deviations (§ 112.7( a)( 2)) when the owner or operator states the reasons for nonconformance and provides equivalent environmental protection in another way.

XIV  8 Extraordinary well control measures  §112.11( m)

Background: Under §112.7( e)( 7)( xii) of the current rule, an owner or operator must provide extraordinary well control measures in the event of an emergency. In 1991, we proposed to redesignate §112.7( e)( 7)( xii) as §112.11( m). We proposed to recommend – instead of to require – that an owner or operator provide extraordinary well control measures if emergency conditions occur (e. g., fire, loss of control). We also recommended varying the degree of control system redundancy with hazard exposure and probable failure consequences. Further, we recommended that an owner or operator include redundant or "fail close" valving in surface shut in systems.

Comments: We should delete proposed §112.11( m) or make it a requirement. (121)

Response: In response to comment, we have deleted the text of the recommendations from the rules because we do not wish to confuse the regulated community over what is mandatory and what is discretionary. However, we endorse its substance. This rule contains only mandatory requirements.

XIV  9 Piping; corrosion protection  §112.11( n) (proposed as §112.11( p)) 297 Background: In §112.7( e)( 7)( xvi) of the current rule, we require an owner or operator to protect from corrosion all piping appurtenant to the facility. In 1991, we proposed to redesignate §112.7( e)( 7)( xvi) as §112.11( p) (redesignated in the final rule as §112.11( n)), and proposed to retain the requirement. We also proposed to recommend – rather than to require – that the owner or operator discuss in the SPCC Plan the corrosion protection method used, such as protective coatings or cathodic protection.

Comments: We should delete the recommendation that an owner or operator discuss the corrosion protection method used in the SPCC Plan. (121)

Response: In response to comment, we have deleted the recommendation to discuss the method of corrosion protection, because it is surplus. In your SPCC Plan, you must discuss the method of corrosion protection you use. See 112.7( a)( 1).

XIV  10 Written instructions for contractors  proposed §112.11( s)

Background: Under §112.7( e)( 7)( xiii) of the current rule, an owner or operator must prepare written instructions for contractors and subcontractors to follow whenever contract activities involve servicing a well or systems appurtenant to a well or pressure vessel. In 1991, we proposed to redesignate §112.7( e)( 7)( xiii) as §112. 11( s). We proposed to recommend – rather than require – that the owner or operator prepare written instructions for contractors or subcontractors to follow in such circumstances.

Comments: Liability. "The regulations appear to mandate involvement and control by an operator over the activities of contractors who perform services on offshore facilities. This creates two very serious problems. First, the contractors are hired to perform special services. The contractor is able to do his work more safely if he is allowed to direct his own activities. Second, operators expose themselves to various types of liability by virtue of the degree of control exercised over contractors." (42)

Requirement instead. We should continue to require – rather than recommend – that owners or operators prepare written instructions for on site contractors and subcontractors. (121)

Response: We have deleted the proposed recommendation because we wish to avoid confusing the regulated community over what is mandatory and what is discretionary. This rule contains only mandatory requirements. 298 Category XV: Relationship to other programs of the rule XV A: UST part 112 Background: In 1991, we noted that a number of underground and aboveground oil storage tanks are subject to both the SPCC regulation (40 CFR part 112) and the underground storage tank (UST) regulation (40 CFR part 280). In §112.1( d)( 2)( i) and (ii), we proposed that the calculation of a facility's underground and aboveground storage capacity should not include USTs, as defined in §112.2( v). To avoid duplicative regulation, in §112.1( d)( 4), we proposed to exclude from SPCC regulation USTs subject to the technical requirements of 40 CFR part 280, reasoning that the UST program offered comparable environmental protection. We noted that USTs not subject to all of the technical requirements of the UST provisions would be subject to the SPCC requirements. We also noted that the SPCC program would still regulate tanks that are not completely buried, because tanks with exposed surfaces exhibit a greater potential to discharge oil into navigable waters and other surface waters.

Comments: For comments on this issue, see section IV. B of this document.

Response: See section IV. B of this document for response.

XV  B: State programs, SARA Title III, wellhead protection, flood related requirements, OSHA, and industry standards  part 112 Background: In the preamble to the 1991 proposed rule, we discussed the relationship between the SPCC regulation and other programs, including State programs; the Superfund Amendments and Reauthorization Act (SARA) Title III or the Emergency Planning and Community Right to Know Act (EPCRA); State wellhead protection (WHP) programs under the Safe Drinking Water Act (SDWA); flood related requirements under Executive Order (EO) 11988, "Floodplain Management;" and the Occupational Safety and Health Act (OSHA).

XV B 1 State programs Background: See section X. K of this document.

Comments: For comments on State issues, see section X. K of this document.

Response: For responses on State issues, see section X. K of this document.

XV B 2 SARA Title III and wellhead protection Background: In 1991, we specified how coordination between Federal, State, and local agencies is possible through additional authorities – SARA Title III in particular. We said that we expected to work closely with States to develop mechanisms for sharing 299 information about facilities and oil discharges to improve environmental protection and public health. We indicated that the proposal requires an owner or operator to ensure that any SPCC contingency plan is compatible and coordinated with local emergency plans, including those developed under SARA Title III.

We noted that States must adopt and submit to EPA a wellhead protection (WHP) program. We also noted that an owner or operator must comply with both the State WHP program and the SPCC regulations, and that meeting the SPCC requirements did not necessarily ensure compliance with a State WHP program.

Comments: Support for coordination. Support for coordination of the SPCC program with SARA Title III. (29, 11) Support for coordination with WHP programs. (27)

Response: Support for coordination. We appreciate commenter support.

XV B 3 Flood related requirements Background: In §§ 112.8( b)( 6) and 112.9( c)( 3), we recommended – in accordance with EO 11988, "Floodplain Management" – that the SPCC Plan address precautionary measures for facilities in locations subject to flooding. We noted that the National Flood Insurance Program (NFIP) definition of structures included ASTs. We described some of NFIP's requirements and standards, and encouraged owners or operators to consider and comply with the requirements in 44 CFR 60.3 when preparing and implementing an SPCC Plan. We also proposed recommending that an SPCC Plan "address precautionary measures for facilities in locations subject to flooding." In proposed §§ 112.8( b)( 6) and 112.9( c)( 3), we recommended that the SPCC Plan "address additional requirements for events that occur during a period of flooding."

Comments: Editorial suggestion. We should move issues related to flooding from the prevention related SPCC requirements to the SPCC contingency plan requirements in §112.7( c). (12)

Mitigation measures of NFIP. "At a minimum, EPA should address the mitigation measures of the National Flood Insurance Program (NFIP) ... more definitively in the rule rather than addressing them under the preamble." "At a minimum, ..., facility owners or operators should undertake the following: 1) Identify whether the facility is located in a floodplain in the SPCC plan; 2) if the facility is located in the floodplain, the SPCC plan should address to what extent it meets the minimum requirements of the NFIP; and 3) if a facility does not meet the minimum requirements of the NFIP, the SPCC plan should address appropriate precautionary and mitigation measures for potential flood related discharges." EPA should also consider requiring facilities in areas subject to 500 year events to address minimum NFIP standards. (12)

NPDES rules. The proposed requirements are duplicative of, and may conflict with, storm water regulations. (35) 300 Recommendation or requirement. We should require – rather than recommend – that NFIP facility owners or operators address precautionary and mitigation measures in the SPCC Plan. (3, 12, 27, 114, 121) Since oil storage facilities could cause significant environmental damage and impact health and safety in a flood, we should require that in areas subject to a 500 year flood event, a facility owner or operator must address NFIP standards in the SPCC Plan. We should clarify that §§ 112.8( b)( 6) and 112.9( c)( 3) reflect the preamble language. (12)

Subject to flooding. We should clarify the term subject to flooding. (9, 27, 115)

Response: Recommendation or requirement.

§112.8( b)( 6). We deleted this recommendation because it is more appropriately addressed in FEMA rules and guidance, including the definitions the commenters referenced. We disagree that the proposed recommendation should be made a requirement because flood control plans and design capabilities for discharge systems are provided for under the storm water regulations, and further Federal regulations would be duplicative.

Other Federal rules also apply, making further SPCC rules unnecessary. Oil storage facilities are considered structures under the National Flood Insurance Program (NFIP), and therefore such structures are subject to the Regulations for Floodplain Management at 44 CFR 60.3. Some of the specific NFIP standards that may apply for aboveground storage tanks include the following: (1) tanks must be designed so that they are elevated to or above the base flood level (100 year flood) or be designed so that the portion of the tank below the base flood level is watertight with walls substantially impermeable to the passage of water, with structural components having the capability of resisting hydrostatic and hydrodynamic loads, and with the capability to resist effects of buoyancy (44 CFR 60.3( a)( 3)); (2) tanks must be adequately anchored to prevent flotation, collapse or lateral movement of the structure resulting from hydrodynamic and hydrostatic loads and the effects of buoyancy (40 CFR 60.3( c)( 3)); for structures that are intended to be made watertight below the base flood level, a Registered Professional Engineer must develop and/ or review the structural design, specifications, and plans for construction, and certify that they have been prepared in accordance with accepted standards and practice (40 CFR 60.3( c)( 4)); and, tanks must not encroach within the adopted regulatory floodway unless it has been demonstrated that the proposed encroachment would not result in any increase in flood levels within the community during the occurrence of the base flood discharge (40 CFR 60.3( d)). Additionally, the NFIP has specific standards for coastal high hazard areas. See 40 CFR 60.3( e)( 4).

§112.9( c)( 1). We have deleted the recommendation because we do not wish to confuse the regulated public over what is mandatory and what is discretionary. These rules contain only mandatory requirements. However, we support the substance of the recommendation, and suggest that a facility in an area prone to 301 flooding either follow the requirements of the NFIP or employ other methods based on good engineering practice to minimize damage to the facility from a flood.

Subject to flooding. Because we have not adopted the recommendation that an owner or operator address precautionary measures for facilities located in areas subject to flooding, we have not defined the term subject to flooding, nor have we moved it to §112.7( c).

XV B 4 OSHA Background: In 1991, we said that a number of AST owners or operators are subject to OSHA requirements under 29 CFR 1910.106, and we described some of these OSHA requirements. We noted that these requirements are important for implementing effective spill prevention programs and should be incorporated into SPCC Plans using good engineering practice.

Comments: Asks why we said that OSHA requirements are necessary for an effective spill prevention program, when OSHA requirements "stand on their own." Inclusion of OSHA requirements in the SPCC Plan would be unnecessarily duplicative. (34) "We do not recall an OSHA requirement that dike walls must average six feet in height and that earthen dikes must be three feet in height and two feet wide at the top. Where in the regulations are these requirements located. (101,165, L15)

Response: We agree that OSHA requirements are independent of SPCC requirements. It is not necessary to duplicate compliance with those requirements in an SPCC Plan.

XV B 5 Industry standards Comments: We should include applicable industry standards in the SPCC regulation. (46) Our proposal is superfluous for smaller capacity ASTs because ASTs and petroleum hazardous substances are "de facto regulated" by fire and safety authorities (e. g., the National Fire Protection Association, the Western Fire Chiefs Association, and the National Building Code Association). (50) Urges referencing of Steel Tank Institute standards in rule. (140)

Response: Throughout the rule we generally allow for the application of industry standards where the standards are both specific and objective, and their application may reduce the risk of discharges to and impacts to the environment. We recognize that as technology advances, specific standards change. By referencing industry standards throughout the preamble, we anticipate that the underlying requirements of the rule itself will change as new technology comes into use without the need for further amendments. We believe that industry standards today represent good engineering practice and generally are environmentally protective. However, if an industry standard changes in a way that would increase the risk of a discharge as described in §112.1( b), EPA will apply and enforce the present day standard (or, if that is not possible, its equivalent in riskassessment terms) rather than the future, less protective standard. 302 Under the terms of this rule, when there is no specific and objective industry standard that applies to your facility (for example, whether there is no standard or a standard that uses the terms "as appropriate," "often," "periodically," and so forth), you should instead follow any specific and objective manufacturer's instructions for the use and maintenance or installation of the equipment, appurtenance, or container. If there is neither a specific and objective industry standard nor a specific and objective manufacturer's instruction that applies, then it is the duty of the PE under §112.3( d) to establish such specific and objective standards for the facility and, under §112.3( d), he must document these standards in the Plan. If the PE specifies the use of a specific standard for implementation of the Plan, the owner or operator must also reference that standard in the Plan.

Throughout today's preamble, we list industry standards that may assist an owner or operator to comply with particular rules. The list of those standards is merely for your information. They may or may not apply to your facility, but we believe that their inclusion is helpful because they generally are applicable to the topic referenced. The decision in every case as to the applicability of any industry standard will be one for the PE.

For your convenience, we are including a list of organizations in today's preamble that may be helpful in the identification and explanation of industry standards. 1 See Analysis of the Number of Facilities Regulated by EPA's SPCC Program and Analysis of the Applicability of EPA's SPCC Program to the Electric Utility Industry, June 1996, U. S. EPA.

303 Category XVI: Economic analysis Background: In 1991, we prepared two preliminary economic analyses: "Economic Impact Analysis of the Proposed Revisions to the Oil Pollution Prevention Regulation," and "Supplemental Cost and Benefit Analysis of the Proposed Revisions to the Oil Pollution Prevention Regulation." The first analysis developed cost estimates for the proposed notification along with three other proposed requirements that were determined to result in non negligible costs to the regulated community. The second analysis estimated the economic effects of the proposed rule based on alternative expectations about how the regulated community would interpret certain proposed revisions. We presented the results of these studies in the preamble to the proposed rulemaking and invited comment on both the methodology used and the results obtained.

XVI  A: Estimated universe of regulated facilities Comments: Electrical equipment. The Economic Impact Analysis underestimated the number of electric utility facilities subject to the SPCC regulations. As many as 100,000 electric utility facilities  including 48, 000 electrical substation type facilities, 48, 000 industrial or commercial customer locations, and 1,600 other locations  could be subject to the rule. This figure could include 80, 000 electric utility sites. As a result, these figures would result in industry wide costs of $2 billion and $1 billion, respectively. (125, 175)

Production facilities. We should revise the number of oil production facilities included in the economic analyses to reflect the final division of responsibility between the Department of the Interior (DOI) and EPA as required by Executive Order (EO) 12777. We did not include in the analyses a facility category encompassing drilling rigs and workover units. Since we included such a category of operations in the regulations, we should include these operations in the economic analyses as well. (128)

Truck st ops. Our Economic Impact Analysis (EIA) and Supplemental Cost and Benefit Analysis do not identify truck stops as a facility category, and was therefore concerned that the US truck stop industry would not be subject to the SPCC regulations. (43)

Response: Electrical equipment. The1995 SPCC Survey indicated that about 2,600 electric utility industry facilities were regulated by the program. We later increased our estimate to 3,700 to account for possible shortcomings in the development of the original estimate. 1 We recognized the possibility that the large number of transformers and other types of oil filled electrical equipment that are associated with the estimated 3,700 primary electric utility establishments may not have been fully reflected in the burden estimates for electric utilities included in the 1991 proposed rulemaking analyses. As a result, we have reflected in the Information Collection Request (ICR) and economic analysis for the final rule an increase in the unit burden for a primary electric utility establishment to account for associated oil filled electrical equipment (e. g., transformers). 304 As a result of these changes made to the final rule, we expect many utilities to see a decline in compliance costs.

Production facilities. We conducted a survey of oil storage and production facilities in 1995 to better estimate the number of regulated facilities. This survey defined oil production facilities as leases, which corresponds to the definition found in the SPCC rule. In the oil industry, a lease is generally regarded as a single oil field operated by a single operator. At the time of the survey, we had already signed a Memorandum of Understanding (MOU) with DOI and the Department of Transportation (DOT) (February 3, 1994) that redelegated the responsibility to regulate certain offshore facilities located in and along the Great Lakes, rivers, coastal wetlands, and the Gulf Coast barrier islands from DOI to EPA. As a result, the 1995 survey provided us with a revised estimate of the total number of oil production facilities regulated under the SPCC program, including drilling rigs and workover units. We used this estimate to calculate the economic effects associated with the final rule.

Truck st ops. In the 1995 survey, we classified truck stops as gasoline service stations to the extent that they both share the same primary Standard Industrial Classification (SIC) Code (5541). Regardless of their SIC Code, facilities are subject to the requirements of the SPCC regulation based on the total amount of oil storage capacity and the reasonable possibility of a discharge as described in §112. 1( b). As a result, all truck stops that have an oil storage capacity greater than 1,320 gallons aboveground or 42,000 gallons underground are subject to the SPCC requirements. However, completely buried storage capacity subject to all of the technical requirements of 40 CFR part 280 or a State program approved under 40 CFR part 281 does not count in the calculation of part 112 storage capacity.

XVI  B: Impacts on small businesses Comments: Costs. We underestimated the cost and level of effort necessary to develop Plans that would meet the requirements we proposed in 1991. (16, 36, 110) The proposed regulation "would significantly impact small operators." (28) The regulation imposes costs, but does not provide any incremental benefit. (28, 31, 34) Our proposed administrative and training requirements would overpower small facilities. (72, 178) The regulations would drastically impact small oil production facilities, although these facilities rarely have the types of spills the SPCC rule is intended to correct. If adopted, the proposed rule would compel extremely costly facility changes, and would be economically detrimental to Appalachian Producers. (101) The proposed rule could contribute to the elimination of many members of the New York oil and gas production community. (165) We failed to recognize the number of small facilities subject to the rule. (L17)

Regulatory Flexibility Act. The proposed rule would substantially impact small facilities, and we should therefore perform a Regulatory Flexibility Analysis (RFA). (28, 58, 59, 101, 113, 127, 165, L15) Our Regulatory Flexibility Act certification ignores the proposed rule's impacts on many small shipyards, which qualify as small businesses. (45) The 305 proposed requirements would have a substantial economic impact on the Ohio oil and gas producing industry. We conducted an inadequate economic analysis of the economic impact upon small entities. Our analysis disregards the Regulatory Flexibility Act requirements. (58) We need to perform an RFA if the proposed rules apply to owners or operators of small aboveground storage tanks. (65)

Secondary containment. The potential danger from a small spill is insignificant compared to the burden imposed on small operations. (149) This regulation is an unwarranted financial burden for owners or operators of small aboveground tanks facilities with secondary containment. (L17)

Small entity. Our method of defining small entity led to an inconsistency with the intent of the Regulatory Flexibility Act. We originally applied the eligibility requirements for Small Business Administration (SBA) assistance to define small entity, and that when we excluded this method in favor of another, our actions were inconsistent with the intent of the Regulatory Flexibility Act. (58) Appalachian Producers could classify as small entities under the Regulatory Flexibility Act. (101)

Response: Costs. We disagree with the commenters who stated that the proposed rule would substantially impact small businesses. We conducted a small business screening analysis that we included with the EIA (January 1991). The purpose of conducting this small business analysis was to determine if a formal RFA would be required.

In determining whether a rule has a significant economic impact on a substantial number of small entities, the impact of concern is any significant adverse economic impact on small entities, since the primary purpose of the regulatory flexibility analyses is to identify and address regulatory alternatives "which minimize any significant economic impact of the proposed rule on small entities." 5 U. S. C. Sections 603 and 604. Thus, an agency may certify that a rule will not have a significant economic impact on a substantial number of small entities if the rule relieves regulatory burden, or otherwise has a positive economic effect on all of the small entities subject to the rule. This rule will significantly reduce regulatory burden on all facilities, particularly small facilities. For example, the rule exempts the smallest facilities from its scope. It also gives all facilities greater flexibility in recordkeeping and other paperwork requirements. Finally, it gives small businesses and all other facilities the flexibility to use alternative methods to comply with the requirements of the rule if the facility explains its rationale for nonconformance and provides equivalent environmental protection. We have therefore concluded that today's final rule will relieve regulatory burden for all small entities. After considering the economic impacts of today's final rule on small entities, we believe that this rulemaking will not have a significant economic impact on a substantial number of small entities.

Regulatory Flexibility Act. An RFA is not required if the rule will not cause significant adverse economic impacts on a substantial number of small entities, which is what the small business analysis concluded. To make this determination, we evaluated baseline and post compliance financial ratios for typical small firms to evaluate the potential for adverse impacts of bankruptcy. We evaluated four different ratios for firms in 24 different 306 industry categories. Only one of these ratios identified impacts  the ratio that assessed the proportionate impact to small entities compared to larger entities. For six of our 24 industries, the ratio estimated that small entities could be affected in a manner disproportionate to the impact on larger entities. However, the remaining three financial ratio tests showed no significant impact to these industries. As a result, we believe we were correct to state that the rule would not have a significant impact on a substantial number of small entities. We arrived at the same conclusion for the final rule as we have included many other revisions from the 1997 proposed rulemaking that are designed to eliminate many of the smaller facilities from the rule as well as to reduce the overall burden to those facilities that remain regulated under the final rule.

The compliance costs used to estimate post compliance financial ratios reflected both the one time and recurring costs that we estimated in the 1991 Economic Analysis, which we added together to calculate the maximum estimated first year burden imposed by compliance. If a firm was not adversely impacted in the first year  when both the onetime and annual recurring costs occurred  we assumed that it would not be subject to a significant adverse economic impact in subsequent years.

We also disagree with the comment that we failed to assess the rule's potential impact on small shipyards. We estimated several different financial impacts for numerous facility types manufacturing transportation equipment (SIC 37). Ship building and repairing is a subset of this industrial category (SIC 373) and thus, was captured by our analysis.

Secondary containment. Although we characterized the proposed 72 hour impermeability standard as a baseline, we have not adopted this standard in the final rule. We have retained the current standard which states that dikes, berms, and oil retaining walls must be sufficiently impervious to contain oil, which more accurately reflects current industry standards and practices. We also note that several industry standards exist concerning loading areas (e. g., API 2610) and that the final rule merely clarifies existing SPCC requirements.

Small entity. As described in the Economic Analysis for the final rule, we are using SBA definition of small entity. Recently, the categorization of the SBA definitions was revised to correspond to the North American Industry Classification System (NAICS) rather than SIC codes. This change does not affect the SPCC analysis because for the most part, the definitions that applied to facilities based on SIC codes also apply to facilities that are based on NAICS codes, and have the same thresholds for determining if the facility is a small business.

XVI  C: Use of incorrect data Comments: Disagree with our use of the SBA's FINSTAT database to create a financial analysis of the crude oil and natural gas industries. The database contains business financial information collected between 1976 and 1983  the zenith of the petroleum crude and natural gas production industry  and that simply adjusting the data for inflation does not accurately capture the industry changes following that period. (58, 128) 307 We should reject the EIA because the document's compliance costs estimates are different than those in the Supplemental Cost and Benefit Analysis. We should have revisited the EIA using the new estimates to determine if the proposed rule would have a significant impact on small entities. (58)

Response: We recognized the limitations of SBA's FINSTAT data in our 1991 Small Business Analysis. However, we relied on the data to perform our analysis because at the time, it represented the largest, publicly available database with financial information on small, privately held firms. We also chose to conduct our analysis using a different definition of small business than that used by the SBA in order to better estimate the proposed rule's impacts on the smallest of the small businesses. Had we used the SBA's definition, we would have included in the analysis over 90 percent of the firms in the affected SICs. As a result, the analysis would have been skewed to estimate the effects on the larger of the small businesses, which presumably would have more resources and would be less impacted by the proposed revisions. By concentrating on the smallest of the small businesses, we were better able to determine the effects that the proposed rule would have on small firms.

We have always treated these provisions as requirements and thus as part of baseline expenditures by regulated firms. For the most part, small facilities should experience a reduction in compliance burden due to the rise in the regulatory threshold, new formatting options, and flexibility to use alternative methods.

XVI  D: Miscalculation of costs Comments: Agriculture. The proposed rule would impose a substantial burden on the agriculture industry, and therefore the industry deserves special consideration. The proposed rule overlaps with other regulations. (139)

Appalachian and Ohio producers. The proposed regulatory changes would significantly impact small oil and gas producers in the Appalachian Basin by regulating almost all tankage in existence, increasing the number of facilities regulated, increasing the extent and complexity of spill contingency plans, and requiring the implementation of new and expanded construction and operations provisions. (28) The proposed revisions will dramatically impact Ohio oil and natural gas producers. (58, 59, 70) The proposed revisions will pose severe and unique economic hardships to Appalachian Producers. (101, 113) The proposed rule's benefits do not match the costs for producers in the Appalachian Basin, and we should regulate only facilities storing large amounts of oil, and not smaller oil and gas producers. The regulatory changes will cause a large percentage of oil and gas wells in the area to cease operations. (165)

Compliance. The small business impact analysis and the EIA cost estimates are sensitive to assumptions of existing compliance. When we relax this assumption in the SBA, compliance costs increase substantially. (182) 308 Costs: PEs, mandatory requirements, reliance on dispersants. Our economic analysis does not truly represent the costs to the regulated community, because we did not properly analyze the following requirements: the specific Professional Engineer (PE) provision found in §112.3( d), the mandatory requirements for medium and large facilities; and the §112.7( d)( 1) contingency Plan prohibition on reliance on dispersants. (L27)

Definitions: navigable waters, discharge. We have severely underestimated the economic impact on part 112 facilities because the definitions of navigable waters and discharge have changed drastically since SPCC guidelines were first implemented. (28)

Facility notification. The proposed notification form would pose a greater amount of burden for facility owners or operators than we estimated. Outside persons  such as outside contractors or upper management  would be needed to complete the form. The burden would be substantially greater for those facilities without SPCC Plans. (34, 48, 187, 189)

Hours burden. Our hours burden estimate of five to 10 hours per year is too low, and estimates industry burden to be about 144 hours per facility  40 hours per year to comply with the regulation, 40 hours to prepare a training program, 40 hours to prepare training program materials, and 24 hours for employee training. (35) Appalachian facilities would incur a greater hours burden than our estimates because such facilities are remote and widely dispersed. (59)

Secondary containment. Our industry cost estimate for the proposed regulations  of $441 million in the first year and $71.8 million each subsequent year  is erroneously low. (28, 31, 36, 58, 113, 165) Comrnenters came to this conclusion by calculating compliance cost estimates for the following requirements: 72 hour impermeability for secondary containment and diked areas, and installation of containment systems at all truck loading locations. (28, 165) The majority of owners or operators would have to modify or recertify Plans to meet the proposed regulatory changes. (36) The true compliance costs are at least $892 million, as we estimated in the Supplemental Cost and Benefit Analysis. (58) Due to the financial burden, we should not require owners or operators of aboveground tank facilities with secondary containment and total storage capacity of less than 10,000 gallons to develop a Plan. (L17)

Small business. The proposed revisions would have a severe economic impact on small businesses throughout the country. (50, 58, 110, 139, 182) The proposed rule imposes on small facilities a disproportionately high level of costs as compared to environmental benefits, because such facilities pose a relatively small risk of spills. (62, 125, 156)

Small discharges. The regulation is costly and unnecessary, and we have not established that problems even exist with discharges from small crude oil production facilities. Consequentially, we should gather up to date, realistic data to make an informed decision. (101) 309 Stripper operations. The proposed revisions would cause many small stripper operations to go out of business. (110) The rule disproportionately impacts small entities

specifically stripper operations  relative to medium and large entities, because the Petroleum Extraction Industry's compliance cost to sales comparison impact is nearly twice as high as other industry's, and exceeds the 110 percent ratio. (L27)

Training. We should clarify which category of individuals must receive mandatory training, because as the rule is currently written, the economic analysis' cost estimate for training is insufficient. (45)

Response: Agriculture. Our Small Business Analysis also considered impacts to small farmers, by analyzing small firms in SIC 1 (agricultural crop production) and SIC 2 (agricultural livestock production). For both SIC Codes, we estimated that the proposed rule would have an insignificant impact on these entities. We arrived at a similar conclusion for the final rule, as we have adopted few new requirements and have provided a de minimis exemption. In addition, we are no longer regulating the smallest facilities. We have also adopted a number of provisions designed to reduce the overall burden for the remaining regulated facilities, which includes eliminating overlap with other Federal requirements (e. g., UST requirements, flexibility in Plan formatting).

Appalachian and Ohio producers. We considered the potential impacts on small firms in our Small Business Analysis. In our analysis of SIC 131, crude oil and natural gas production, we determined that small firms in this industry were unlikely to close as a result of the compliance costs associated with the proposed rule. However, these firms may experience disproportionate impacts compared to larger firms. In the final rule, we introduced a de minimis storage capacity, which may benefit a number of the smaller oil production firms. For the firms that remain in the SPCC program, we are finalizing a rule that promotes flexibility and has few new requirements. As a result, we believe that most oil and gas production firms will experience roughly a 40 percent reduction in burden and costs over time.

Compliance. In response to the comment that our analysis hinges on our assumption of existing compliance, we note that our assumption of a baseline of full industry compliance is consistent with OMB guidelines for preparing regulatory impact analyses. We produced a Supplemental Analysis to estimate the cost of certain provisions of the proposed rule under the assumption that a number of owner or operators have interpreted the proposed changes as substantive changes in their duties to comply with this regulation. The commenter is correct to point out that as a result of the relaxed assumptions concerning baseline activities, estimated compliance costs increased. In the final rule, we have decided not to adopt many of the proposed revisions that would have added to the baseline compliance costs for facilities (e. g., notification). We also are providing a number of revisions in the final rule designed to decrease the overall compliance burden to regulated facilities as well as to offer facilities increased flexibility to meet their obligations under the rule.

Costs: PEs, mandatory requirements, and reliance on dispersants. 310 Dispersants. In 1991, under §112.7( d)( 1), we proposed language clarifying the contents of an appropriate oil spill contingency plan. We omitted the reference to 40 CFR part 109 and instead, specified basic requirements for an oil spill contingency plan. However, in the final rule, we did not adopt the proposed language and instead retained the existing reference to 40 CFR part 109.

Mandatory requirements. We disagree that we ignored mandatory requirements in our economic analysis for medium and large facilities. We provided cost estimates in the economic analysis for small, medium, and large facilities. We discussed every proposed revision and noted its effect on the regulated community in the analysis. We did not propose nor did we finalize any requirements that are dependent on facility size.

PEs. Final §112.3( d) does not contain a State specific certification requirement for PEs, because the SPCC program is national in scope and therefore State expertise is not necessary.

Definitions: navigable waters, discharge. We have made very little substantive change to the definitions of navigable waters and discharge since 1973. The new definition of navigable waters adds clarity and more examples, and is now consistent with other regulatory definitions of the term. The new definition of discharge was made consistent with the Clean Water Act definition as amended in 1978, which exempted certain discharges associated with NPDES permits. This change would not result in an increase in economic impact  rather, some facilities will no longer be regulated as a result of the revised definition because they are no longer expected to discharge oil, leading to a decrease in economic impact. In any case, any change in economic impact due to this definition revision is the result of the change to the statute.

Facility notification. We have decided to withdraw the proposed facility notification requirement because we are still considering issues associated with establishing a paper versus electronic notification system, including issues related to providing electronic signatures on the notification. Should the Agency in the future decide to move forward with a facility notification requirement, we will repropose such requirement.

Hours burden. We have adopted a model facility approach in estimating the approximate hours burden for facilities to comply with the rule. We adopted this approach to better characterize the diverse universe of regulated facilities. We developed eight different model facilities for this rulemaking – which we designed to represent the typical facility in each category  based on oil storage capacity and primary use of oil. We acknowledge that some facilities may experience a higher hours burden and cost for select activities. However, on average, we believe that the hours burden and cost incurred by our eight different model facilities adequately characterize the approximate burden to other facilities with similar characteristics.

Secondary containment. We disagree with the commenters who asserted that we underestimated the cost to comply with the secondary containment and truck loading area 311 requirements. We noted in our 1991 economic analysis that we considered these costs as part of the baseline cost of compliance, which are not affected by the proposed rule. In response to an OMB comment, we later costed out these provisions in a supplemental analysis. In that analysis, we estimated that 78 percent and 88 percent of the regulated community were already in compliance with these requirements, respectively, and would not be affected by the proposed rule change.

Since we last performed these analyses, API has issued several industry standards, including API 653 and 2610, which address many of the provisions in the SPCC rule. As a result, the final rule relies on current industry standards and practices, where feasible. In the final rule, we withdrew the proposed 72 hour impermeability standard for secondary containment and maintained the current requirement that dikes, berms, and oil retaining walls must be sufficiently impervious to contain oil. As a result, the final rule reflects current industry standards and poses no additional requirements on industry.

Small business. We disagree that we failed to analyze the impact of the proposed revisions on small businesses. We direct the commenter to the 1991 Small Business Analysis that is appended to the Economic Analysis wherein we analyze the effects of the rule on small business. We also disagree that costs would be disproportionately high for small facilities compared to the benefits. Although our small business analysis did identify that small facilities in some industries could be disproportionately affected, in no instances did it show that these facilities would be significantly impacted. We expect the impact of the final rule will be less than we originally estimated because we have incorporated several changes to reduce the overall compliance burden (for example, the rise in regulatory threshold  see §112.1( d)( 2)( ii)). Also, to calculate total aboveground storage capacity, a facility owner or operator need only count containers greater than 55 gallons. The de minimis capacity will eliminate from the rule the smallest of the regulated facilities. We believe that the cost of compliance for smaller facilities will be less than that for larger facilities because smaller facilities are generally less complex than larger facilities. As a result, it will take less effort to prepare and implement a Plan. The supporting analyses for the final rule provides more detailed explanations of our assumptions concerning this issue.

Small discharges. A small discharge may have a harmful environmental effect. Therefore, small production facilities need prevention measures to avert costly discharges. Recent analysis confirms this statement. See the Denial of petition requesting amendment of the Facility Response Plan rule, 62 FR 54508 et seq., October 20, 1997.

Stripper operations. We disagree that the rule would have an adverse economic impact on stripper wells. We specifically analyzed the impact that the rule would likely have on small businesses involved in crude oil and natural gas extraction (SIC 131). In conducting our closure analysis, we looked specifically at three financial ratios  return on assets, total debt to total assets, and compliance costs to net sales. These tests failed to indicate that small firms in SIC 131 would be significantly impacted. We did find, however, that small firms in SIC 131 may experience disproportionate impacts compared to larger firms in their industry. This was recognized in the Small Business Analysis. 312 Training. In the final rule, we have clarified the language regarding training requirements to apply only to oil handling personnel. See §112.7( f). We have not provided a cost estimate for this requirement, because we have always required a facility owner or operator to provide adequate training for facility personnel. The final rule merely clarifies that an owner or operator does not need to train all personnel  only oil handling personnel.

XVI  E: Additional costs Comments: Baseline costs. Changing the regulatory language from should to shall will impose additional costs on part 112 facilities. (45, 113, 125, L27) Electrical utilities industry must perform substantial construction as a result of the changes. These changes are impracticable and unnecessary to address any reasonable risk of discharge at electrical facilities. (125) We incorrectly assume that many facilities are already in full compliance with industry standards, and that we should not consider this scenario as the baseline. (L27)

Impermeability requirements. We should not require owners or operators of Appalachian Production facilities to meet the impermeability standards due to the limited environmental benefit and high associated costs. (101) We did not address in the analyses two specific requirements in the proposed revisions  the requirements for containment systems and diked areas to be impervious to oil for 72 hours. These requirements would require significant capital expenditures for many facility owners or operators. (182)

Paperwork Reduction Act. The time estimates we listed in the Paperwork Reduction Act certification are erroneous, and too low. (45)

PEs. Requiring an independent or outside PE for Plan certification would be extremely expensive for facilities located in remote areas. (59, 65) Requiring the use of an independent or outside PE would be incredibly burdensome to facility owners or operators. (59, 67, 110, 187) Discussions with a PE concerning the use of alternative measures are not negligible costs. Regarding the EIA, we should not have included as a benefit, the requirement for a PE to have no financial interest in the facility because it was not included in the proposed revisions. (L27)

Regular inspection of storage tanks. Requiring regular inspection of storage tanks would impose a significant burden on facility owners or operators. (65)

Vacuum protection, equalizing lines, reinstallation of dike drains. Asks us to clarify whether we had included the cost of vacuum protection installation into the cost analysis. (31, 101, L15) Asks us to clarify that we had included the cost of equalizing lines installation as specified in §112.9( d)( 4)( ii) into the cost analysis. (101) We should include in the economic analyses the cost of reinstalling tank dike drains as required in §112.9( c), because owners or operators of facilities have removed over 100,000 forewall drains as a result of the part 112 rules of 1973. (L27) 313 Weight restrictions. We failed to recognize the substantial costs to owners or operators of determining accurate weight restrictions. (76)

Response: Baseline costs. We note that we only costed out in our analysis the incremental effects associated with the proposed regulatory changes. We did not determine the costs of complying with the existing rule. We have always accounted for these requirements in the information collection burden estimates for the rule, and have always assumed 100 percent compliance by the regulated community. Consequently, because we are merely clarifying in the final rule what is already required of the regulated community and because we have accounted for these costs in our continuing analyses of the program, we have treated these costs as baseline in the analyses supporting this rulemaking.

Impermeability requirements. We withdrew the proposed 72 hour requirement. We are maintaining the extant requirement that dikes, berms, and oil retaining walls must be sufficiently impervious to contain oil. Therefore, there are no incremental costs. The revised rule, like the current rule, does not require a specific impermeability for dikes and does not require a specific method of secondary containment at loading areas, and this flexibility is reflected in our cost estimates.

Paperwork Reduction Act. To estimate the burden, we used estimates based on an engineering approach assuming certain small facility characteristics. We note that the actual burden for individual facilities may be greater or less than twelve hours, but consider this estimate to be a fair assumption for the average facility.

PEs. These commenters were principally concerned that we did not fully account for the cost to a facility owner or operator for a PE to visit each facility before certifying a Plan. We note that we did not propose this requirement, but requested comments on it. In the final rule, we require either the PE or the PE's agent to visit and examine the facility before the PE certifies the Plan. An agent might include an engineering technician, technologist, graduate engineer, or other qualified person to prepare preliminary reports, studies, and evaluations after visiting the site. The PE, after reviewing the agent's work, could then legitimately certify the Plan. Also, in the final rule, we allow the PE to be an employee of the facility as well as registered in a different State than the facility is located, in order to approve a Plan. The rationale is that SPCC work is national in scope and therefore State expertise is unnecessary.

We disagree that the burden for a PE to discuss a deviation in a Plan is an incremental cost. Under the current rule, the PE has the same flexibility in the application of good engineering practice. Therefore, such discussion is a baseline activity.

Although we did not propose in 1991 that the certifying PE have no direct financial ties to the facility, we note that we requested comments regarding this issue. In any event, we did not adopt such a provision in the final rule, and note that the benefits of the final rule do not include any consideration of whether the PE has a financial interest in the facility. 314 Regular inspection of storage tanks. Regular inspection of storage containers is already required under the current rule. Therefore, it is a baseline cost and not an incremental effect of the final rule.

Reinstallation of dike drains. We disagree that we should include in the economic analyses the cost of reinstalling tank dike drains because neither the current rule nor the final rule requires such reinstallation.

Vacuum protection, equalizing lines. Vacuum protection and overflow equalizing lines are measures an owner or operator must consider under the current rule. Our economic analyses only costed out the incremental effects of the proposed rule, not the existing rule's requirements. Therefore, we considered the cost associated with these activities as a baseline cost and we did not include them in our economic analyses.

Weight restrictions. We have deleted the proposed recommendation concerning weight restrictions. Therefore, there are no incremental costs to the owner or operator.

XVI  F: Costs to the electric utility industry Comments: Costs. Our compliance costs for the electric utility industry are erroneously low. Owners or operators of electrical equipment storing 10,000 gallons of oil or less should not be subject to the SPCC requirements because such equipment poses a small amount of environmental risk. (125) We failed to consider the impact of the rule on electrical substations and installations in the current Regulatory Impact Analysis (RIA). As a result, the cost of compliance cited in the RIA is erroneously low. We should prepare a new RIA that accurately reflects the impact of the rule on electric utilities. (130) It would be costly and time consuming to comply with the SPCC regulations for facilities with electrical equipment. (41, 184, 189)

High viscosity. We should exclude from the proposed secondary containment provisions and integrity testing requirements bulk storage tanks that hold high viscosity petroleum products. We should not require integrity testing and secondary containment for high pour point bulk storage containers, and we did not analyze the costs associated with the proposed requirement. (125)

Impact. If electrical equipment is subject to SPCC regulations, then the number of covered utility industry facilities would increase substantially and the rule would have a greater impact on the electric utility industry than we anticipated. (125, 189)

Regulatory alternatives. In order to comply with the proposed rules, the electric utility industry faces significantly higher costs than we estimated, yet the industry poses an insignificant environmental risk. The commenter provided cost estimates for the electric utility industry to comply with the following requirements: constructing secondary containment and drainage systems; testing tanks for integrity; complying with the impermeability requirement; and writing and implementing Plans at substations. Because of these costs, the commenter suggested the following alternatives: 315 ° State that electrical equipment is not be subject to SPCC regulations. ° Modify the SPCC risk criteria to ensure that only the facilities which pose a real risk of harm are covered by the program. ° Address specific elements of the proposal that are impracticable or impose undue costs for the avoided risk as applied either to electrical equipment or tanks. (125)

Response: Cost, impact, regulatory alternatives. We disagree that it would be costly for facilities with electrical equipment to comply with the SPCC regulation, and that subjecting electrical equipment to the regulations would have a greater impact on the electric utility industry than we anticipated. Such facilities must only comply with requirements for oilfilled electrical equipment, and have considerable flexibility in doing so. Furthermore we have exempted the smallest containers and facilities from the rule. Therefore, costs will be mitigated.

In our analysis of the effects of the proposed and final rule, we incorporated a model facility approach. We estimated the costs of complying with the incremental effects of the proposed and final rule changes based on the characteristics assigned to these model facilities. In reality, some facilities may incur greater costs, while other facilities incur lower costs. Since the 1991 rule was proposed, we have redefined our treatment of electric utilities to reflect the slightly greater burden that they may incur to comply with this rule. This change was incorporated in 1997, in response to industry comments concerning our Information Collection Request renewal activities for the SPCC program. We also note that many of the estimates provided by the commenters are not associated with the proposed revisions, and we already require facilities to consider or implement many of these activities.

We note, however, that the final rule provides increased flexibility for an owner or operator. In fact, many of the changes reduce the overall burden to electrical utilities. We clarify in the final rule that electrical equipment is subject only to the general SPCC requirements, and not the more specific requirements for bulk oil storage containers. Secondary containment is still required for all facilities under §112.7( c). If it is not practicable for safety or other valid engineering reasons, under §112.7( d), the owner or operator may provide a contingency plan following 40 CFR part 109, and otherwise comply with the requirements of that section. Furthermore, an owner or operator may deviate from most of the rule's substantive requirements if he explains his reasons for nonconformance and provides equivalent environmental protection. 40 CFR 112.7( a)( 2). This provision also cuts costs.

We agree that any equivalent prevention plan acceptable to the Regional Administrator qualifies as an SPCC Plan as long as it meets all Federal requirements (including certification by a Professional Engineer), and is cross referenced from the requirement in part 112 to the page of the equivalent plan. We do not agree that we should specify acceptable formats. We give examples of those acceptable formats, but those examples are not meant to be exhaustive. See the discussion on §112.7( c) in today's preamble and in this document. 316 One example of an equivalent plan might include a multi facility plan for operating equipment. This type of plan is intended for electrical utility transmission systems, electrical cable systems, and similar facilities which might aggregate equipment located in diverse areas into one plan. Examples of operating equipment containing oil include electrical equipment such as substations, transformers, capacitors, buried cable equipment, and oil circuit breakers.

A general, multi facility plan for operational equipment used in various manufacturing processes containing over the threshold amount of oil might also be acceptable as an SPCC Plan. Examples of operating equipment used in manufacturing that contains oil include small lube oil systems, fat traps, hydraulic power presses, hydraulic pumps, injection molding machines, auto boosters, certain metalworking machinery and associated fluid transfer systems, and oil based heaters. Whenever you add or remove operating equipment in your Plan that will either increase or decrease the potential for a discharge as described in §112.1( b), you must amend your Plan.

Multi facility plans would include all elements required for individual plans. Site specific information would be required for all equipment included in each plan. However, the sitespecific information might be maintained in a separate location, such as a central office, or an electronic data base, as long as such information was immediately accessible to responders and inspectors. If you keep the information in an electronic data base, you must also keep a paper or other backup that is immediately accessible for emergency response purposes, or for EPA inspectors, in case the computer is not functioning. Where you place that site specific information would be a question of allowable formatting, as is the question of what is an "equivalent" plan; an issue subject to RA discretion.

Finally, we note that many of the smaller substation facilities will be exempted from the SPCC regulations due to the changes to §112.1( d) in the final rule – specifically, the introduction of a 55 gallon de minimis threshold as well as the elimination of the 660 gallon threshold.

High viscosity. If the owner or operator wishes to deviate from secondary containment requirements, he may only do so because secondary containment is not practicable in the application of good engineering practice. He must also follow the requirements of §112.7( d) in such case. If he wishes to deviate from integrity testing requirements, he must follow §112.7( a)( 2). However, both of these activities are baseline activities, and therefore, not incremental costs.

XVI  G: Miscellaneous cost issues Comments: Bioremediation. We are incorrect to assume that Appalachian producers would use off site disposal for remediation, because the high costs associated with travel time and distance would dictate another method. (101) We should specifically allow the use of bioremediation and on site disposal following a spill event, because of the high costs associated with off site disposal. (113) 317 External heating systems. Objects to the cost to facility owners or operators of installing external heating systems. (76)

Extraction industry  discretionary provisions. The cost of the regulation is greater than indicated in the economic analysis, because the petroleum extraction industry is unable to take advantage of the discretionary provisions for medium or large facilities. The petroleum extraction industry is able to take advantage of the discretionary training provision. (L27)

Farmers. Farmers cannot afford to comply with the proposed regulations, and requested that we create an exemption for farmers based on tank size and risk. (106)

Insufficient information. We have provided insufficient useful information regarding the economic analyses in the preamble to the proposed rule. Therefore, the public cannot understand or comment on the proposed rule. (110)

Jurisdiction, wetlands, sensitive ecological areas. We should reflect in the benefit analysis our change in jurisdiction modified by EO 12777. (128) We should clearly define the jurisdiction of the regulation as well as the terms wetlands and sensitive ecological areas, because the potential costs of the proposed regulation could be devastating for the regulated community. (139)

Permanently closed containers. We should consider tanks previously removed from service as permanently closed. Owners or operators would have to bear significant costs to permanently close tanks so the tanks will not apply towards the storage capacity threshold calculation. (101)

Recordkeeping requirements. Under §112.9( d) and (e), we should not require owners or operators to retain inspection and test records for five complete calendar years irrespective of ownership, due to the financial burden on the facilities. (113)

Scientific rationale. We need scientific justification for the proposed revisions. (127, 132, 139, 160, L27)

Secondary containment. Provides cost estimates for many elements of the proposed rule. (31) Produces compliance estimates based on a small, single facility common to oil and gas production in Ohio. (70) The largest single cost to facilities is the proposed §112.7( c) requirement that dikes, berms, and oil retaining walls must be sufficiently impervious to contain oil. The commenter estimated startup costs to be $10,425 and annual costs to be about $260 per facility. (25, 70)

State and local regulation. The proposed revisions are unnecessary because State and local agencies already regulate aboveground storage tanks. (127, 139)

Triennial review. Questions our cost estimates regarding the triennial Plan review and evaluation. The requirement would cost a well operator $500 for PE certification, and a 318 tank battery operator $3,000 for PE certification. The requirement would cost owners or operators of onshore production facilities $2. 7 million. (103, 113, 187)

Response: Bioremediation. We agree with the commenter that bioremediation may be a proper disposal method. We do not assume any particular facility will use bioremediation, but it is an available option.

Existing program. We disagree that the revisions to the rule would unnecessarily raise the cost of compliance over the current program because the majority of the changes are clarifications of existing requirements. Also, we did not adopt all of the proposed changes, some of which, like facility notification, would have raised costs. Further, the final rule reduces the regulatory burden by: reducing the total number of facilities subject to the rule; introducing flexibility in formatting and recordkeeping; and, by encouraging the use of industry standards to comply with SPCC requirements.

External heating systems. We deleted the proposed recommendation to consider the feasibility of installing an external heating system from §112.8( c)( 7). That proposed recommendation is currently a requirement. Therefore, we have reduced costs for an owner or operator.

Extraction industry  discretionary provisions. The rule does not prescribe differing requirements for facilities merely based on size. We have not established discretionary provisions for any facilities. All of the rule provisions are mandatory. However, an extraction facility may avail itself of a deviation in the same manner as any other facility.

Farmers. We disagree that farmers cannot afford to comply with the rule. However, in the final rule, we have raised the regulatory threshold. We no longer regulate a facility that stores 660 gallons or more of oil in a single aboveground tank, so long as the aggregate aboveground storage capacity does not exceed 1,320 gallons. We expect that a significant number of small facilities  including farms  will benefit from this change, and expect the majority of small facilities with a single oil tank to no longer be regulated. We refer the commenter to the supporting analyses for more specific estimates on the estimated impacts. We also exempt containers of less than 55 gallons from all rule requirements.

Insufficient information. We disagree that we failed to provide sufficient information regarding the economic analysis in the preamble. We summarized the results of the economic analyses therein. The economic analyses are available for review in the public docket for those wishing to review more specific information on the approach we used to estimate our results. We believe that many of the commenters who were concerned about the costs and benefits of the proposal will find that the changes made in the final rule are to their benefit.

Jurisdiction, wetlands, sensitive ecological areas. The applicability of the rule is clearly set out in §112.1. We have added a definition for wetlands in the final rule to provide 319 clarity for the regulated community. We discussed sensitive environments in the final 1994 Facility Response Rule. See 59 FR 34070, 34089, July 1, 1994.

In our analysis of the impact of the final rule, we consider the jurisdictional effects of EO 12777 (56 FR 54757, October 22, 1991). Section( b)( 1) of EO 12777 delegates to the EPA authority in section 311( j)( 1)( C) relating to the establishment of procedures, methods, and equipment, and other requirements for equipment to prevent and to contain discharges of oil and hazardous substances from non transportation related onshore facilities. Section( b)( 2) of EO 12777 delegates similar authority to contain discharges of oil and hazardous substances from vessels and transportation related onshore facilities and deep water ports to the Secretary of Transportation. Section( b)( 3) of the EO delegates similar authority for offshore facilities, including associated pipelines, other than deep water ports, to the Secretary of the Interior. An MOU between EPA, DOT, and DOI, found at Appendix B to part 112, redelegated from DOI to EPA the responsibility for non transportation related offshore facilities located landward of the coast line. Similarly, the MOU redelegated from DOI to DOT the responsibility for transportation related offshore facilities, including pipelines, landward of the coast line. Thus, only a small fraction of SPCC regulated facilities are affected by the EO and MOU, and the majority of those facilities were already taken into account in the benefits analysis.

Permanently closed containers. We believe that containers that have been permanently closed according to the standards prescribed in the rule qualify for the designation of "permanently closed," whether they have been closed before or after the effective date of the rule. Containers that cannot meet the standards prescribed in the rule will not qualify as permanently closed. To clarify when a container has been closed, we have amended the rule to require that the sign noting closure show the date of such closure. The date of such closure must be noted whether it occurred before or after the effective date of this provision. Some States and localities require a permit for tank closure. A document noting a State closure inspection may serve as evidence of container closure if it is dated.

Recordkeeping requirements. We agree that a requirement to retain records for five years is too long, and have withdrawn the proposed requirement in favor of the general requirement in §112.7( e) to maintain records for three years.

Secondary containment. We appreciate the comments providing associated cost of compliance data. We note that we have improved the methodology used to estimate the effects of the rule by expanding the types of model facilities used in the analysis. The costs we have estimated for each model facility type are approximations that are meant to reflect average costs to a facility having similar characteristics as our model facility. In reality some facilities will experience higher or lower costs than what we have estimated. Overall, however, we believe that this technique gives us a reasonable estimate of the program's entire costs and cost savings.

Scientific rationale. We believe that each of the revisions to the SPCC rule being adopted have an adequate scientific, policy, and legal basis. In response to comment, we have not promulgated a number of proposed provisions. 320 State and local regulation. We disagree that the rule is unnecessary because State and local agencies already regulate aboveground storage tanks. 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. We do not preempt State rules, and defer to State law that is more stringent than part 112.

We also note that 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.

Triennial review. We have extended the time in which an owner or operator must review the Plan from at least once every three years to at least once every five years. As a result, we expect that facility owners or operators will experience an overall reduction in the annualized cost of conducting such a review. The costs associated with this activity are baseline costs that we have already determined in numerous information collection burdens. The impacts of this change are discussed in the supporting analyses to the rule. Further, we have clarified in the final rule that a PE must certify only technical Plan amendments.

XVI  H: Miscalculation of benefits Comments: Costs, benefits. The benefit values calculated in the analyses are too great, and the economic benefit of applying the proposed changes to oil and gas production facilities is far outweighed by the cost. The benefits of the proposed changes would be at most in the tens of thousands of dollars per year. (28, 165) We failed to accurately predict the costs, and we overestimated the benefits of the proposed regulation in spite of the economic analyses. (35) We quantified the benefits in incredibly broad terms, and we counted spill reductions as benefits, even though we already counted these as benefits of prior regulations. (128)

Discharges avoided. Disagrees with our estimate found in the Supplemental Cost and Benefit Analysis for the benefits associated with avoiding cleaning up an oil spill. The cost to clean up such a spill is considerably less, and therefore our benefit estimation is too high. (101) Although we cite as a potential benefit the increased revenue from sales of petroleum products not lost in spills, a facility owner or operator already strives to avoid spill events wherever possible due to the stated incentive. (L27) 321 Facility notification. We have not described how we monetized the benefits of the proposed notification form and regulatory revisions. However, we cannot possibly monetize these benefits without first identifying any problems with the current SPCC program. (31, 34) We should not count as a benefit compliance with the proposed notification provision, and noted that this action is actually a burden. (128)

Human health and the environment. The benefits resulting from the proposed regulations will have little if any benefit in protecting human health or the environment and do not justify the standards we are requiring for facilities subject to the part 112 requirements. (28, 74, 110, 113, 137, 149, 160, 192)

Response: Costs, benefits. We disagree that we failed to accurately predict the costs, and that we overestimated the benefits of the rule in spite of the economic analyses. We believe that we have adequately explained in our economic analysis the methods used to predict costs and benefits. The final rule will reduce costs by millions of dollars a year for regulated facilities.