Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications shall identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this action may be changed in light of the comments received.

Submit comments using the following format:

• Organize comments issue-by-issue. For example, discuss a request to change the compliance time and a request to change the service bulletin reference as two separate issues.

• For each issue, state what specific change to the proposed AD is being requested.

• Include justification ( e.g. , reasons or data) for each request.

Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.

Commenters wishing the FAA to acknowledge receipt of their comments submitted in response to this action must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket Number 2000-NM-256-AD.” The postcard will be date stamped and returned to the commenter.

Any person may obtain a copy of this NPRM by submitting a request to the FAA, Transport Airplane Directorate, ANM-114, Attention: Rules Docket No. 2000-NM-256-AD, 1601 Lind Avenue, SW., Renton, Washington 98055-4056.

The Departmento de Aviacao Civil (DAC), which is the airworthiness authority for Brazil, notified the FAA that an unsafe condition may exist on certain EMBRAER Model EMB-145 series airplanes. The DAC reported an instance of the loosening of the bolts on the hinge fittings which attach the spring tab and the servo tab to the rear spar of the elevators and indicated that the resulting loss of attachment rigidity may lead to undesirable levels of vibration. The DAC also notified the FAA that the bonding jumpers held in position by bolts on the hinge fittings may interfere with the leading edge of the spring tab.

The actions specified by the proposed AD are intended to prevent the spring tab or the servo tab from becoming disconnected, resulting in structural failure. The actions are also intended to prevent damage to the leading edge of the spring tab, which could result in loss of control of the elevator.

EMBRAER has issued Service Bulletin 145-55-0009, Change No. 02, dated May 19, 2000, which describes procedures for a one-time inspection of the bolts on the hinge fittings that attach the spring tab and the servo tab to the rear spars of the elevators for evidence of loosening. The service bulletin also describes procedures for a one-time inspection of the region of the hinge fittings on the spring tab for interference of the bonding jumpers with the leading edge of the spring tab.

If no discrepancies are found, operators must perform follow-up repetitive inspections as specified in the service bulletin. If discrepancies are found, operators must perform modifications, such as replacing the bolts with improved bolts, installing washers, installing lockwire or changing its position, and changing the position of the bonding jumpers. Accomplishment of the actions specified in the service bulletin is intended to adequately address the identified unsafe condition.

The DAC issued Brazilian airworthiness directive 98-05-02, dated May 28, 1998, which referred to Embraer Service Bulletin 145-55-0009, initial release or further revisions approved by the Brazilian airworthiness authority.

This airplane model is manufactured in Brazil and is type certificated for operation in the United States under the provisions of § 21.29 of the Federal Aviation Regulations (14 CFR 21.29) and the applicable bilateral airworthiness agreement. Pursuant to this bilateral airworthiness agreement, the DAC has kept the FAA informed of the situation described above. The FAA has examined the findings of the DAC, reviewed all available information, and determined that AD action is necessary for products of this type design that are certificated for operation in the United States.

Since an unsafe condition has been identified that is likely to exist or develop on other airplanes of the same type design registered in the United States, the proposed AD would require accomplishment of the actions specified in the service bulletin described previously, except as described below.

The intervals between repetitive inspections in the proposed AD (stated in flight hours) differ from those recommended in the manufacturer's service bulletin (stated to coincide with operators' “A” checks). However, because regularly scheduled maintenance intervals, such as “A” checks, may vary from operator to operator, there would be no assurance that the inspections would be accomplished during the maximum intervals proposed by this AD. These intervals are intended to maintain an adequate level of safety within the fleet.

Another difference concerns the compliance time for accomplishment of the terminating action. The manufacturer's service bulletin recommends that, if no discrepancy is found during the initial inspection described in Part I, the terminating action described in Part II, III, or IV may be accomplished at any time, at the operator's discretion. However, the FAA has determined that requiring a specific compliance time is necessary to adequately address the identified unsafe condition. In developing an appropriate compliance time for this proposed AD, the FAA considered not only the manufacturer's recommendation, but also the degree of urgency associated with addressing the subject unsafe condition and the average utilization of the affected fleet. In light of these factors, the FAA finds a compliance time of 2,000 flight hours for accomplishing the terminating actions to be warranted, in that it represents an appropriate interval of time allowable for affected airplanes to continue to operate without compromising safety.

Finally, Brazilian airworthiness directive 98-05-02 refers to EMBRAER Service Bulletin 145-55-0009, initial release, or further revision approved by the Brazilian airworthiness authority. The proposed AD refers to EMBRAER Service Bulletin 145-55-0009, Change No. 2, dated May 19, 2000, which includes procedures for repetitive inspections for interference between the bonding jumpers and the leading edge of the spring tab.

The FAA estimates that 71 airplanes of U.S. registry would be affected by this proposed AD.

The initial inspection would take 2 work hours per airplane at an average labor rate of $60 per hour. Based on these figures, the cost impact on U.S. operators of the initial inspection (Part I) specified in the proposed AD is estimated to be $8,520, or $120 per airplane.

The cost impact on U.S. operators of follow-on actions is specified in the following table:

The cost impact figures discussed above are based on assumptions that no operator has yet accomplished any of the proposed requirements of this AD action, and that no operator would accomplish those actions in the future if this proposed AD were not adopted. The cost impact figures discussed in AD rulemaking actions represent only the time necessary to perform the specific actions actually required by the AD. These figures typically do not include incidental costs, such as the time required to gain access and close up, planning time, or time necessitated by other administrative actions.

The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption ADDRESSES .

Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:

Interested persons are invited to participate in the making of the proposed rule by submitting such written data, views, or arguments as they may desire. Communications should identify the Rules Docket number and be submitted in triplicate to the address specified above. All communications received on or before the closing date for comments, specified above, will be considered before taking action on the proposed rule. The proposals contained in this document may be changed in light of the comments received.

Comments are specifically invited on the overall regulatory, economic, environmental, and energy aspects of the proposed rule. All comments submitted will be available, both before and after the closing date for comments, in the Rules Docket for examination by interested persons. A report summarizing each FAA-public contact concerned with the substance of this proposal will be filed in the Rules Docket.

Commenters wishing the FAA to acknowledge receipt of their mailed comments submitted in response to this proposal must submit a self-addressed, stamped postcard on which the following statement is made: “Comments to Docket No. 2000-SW-17-AD.” The postcard will be date stamped and returned to the commenter.

Any person may obtain a copy of this NPRM by submitting a request to the FAA, Office of the Regional Counsel, Southwest Region, Attention: Rules Docket No. 2000-SW-17-AD, 2601 Meacham Blvd., Room 663, Fort Worth, Texas 76137.

On June 28, 1985, the FAA issued AD 85-14-06, Amendment 39-5089 (50 FR 28561, July 15, 1985) to require repetitive inspections and to repair or replace the fuselage frame at the fuselage tailboom interface. On August 8, 1985, the FAA issued AD 85-14-06 R1, Amendment 39-5121 (50 FR 37173, September 12, 1985), to require repetitive visual inspections and to repair or replace the frame, as necessary. That AD also requires fastener torque checks and re-torquing, as necessary. That action was prompted by reports of cracked frames at the fuselage-to-tailboom interface. The requirements of that AD are intended to prevent a cracked frame, tailboom failure, and subsequent loss of control of the helicopter.

Since the issuance of that AD, we have been notified that the inspection interval of the frame at the fuselage-to-tailboom interface in the current AD does not coincide with the maintenance manual. The FAA has determined that this may create confusion among operators as to when the inspections are required.

We have identified an unsafe condition that is likely to exist or develop on other Eurocopter France Model AS350 and AS355 helicopters of these same type designs. The proposed AD would supersede AD 85-14-06 R1 and would require the same actions as the existing AD except to increase the inspection interval from 1,200 hours TIS to 2,500 hours or 6 years TIS, whichever occurs first, to coincide with the maintenance manual to eliminate confusion and unnecessary costs. To compensate for the increase in the inspection interval, we propose that the initial inspection interval be reduced from 100 hours TIS to 30 hours TIS and that the visual inspection be changed to a dye-penetrant inspection.

The FAA estimates that 475 helicopters of U.S. registry would be affected by this proposed AD, that it would take approximately 8 work hours per helicopter to accomplish the proposed actions, and that the average labor rate is $60 per work hour. Based on these figures, the total cost impact of the proposed AD on U.S. operators is estimated to be $228,000 assuming no cracked frames are discovered.

The regulations proposed herein would not have a substantial direct effect on the States, on the relationship between the national Government and the States, or on the distribution of power and responsibilities among the various levels of government. Therefore, it is determined that this proposal would not have federalism implications under Executive Order 13132.

For the reasons discussed above, I certify that this proposed regulation (1) is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979); and (3) if promulgated, will not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act. A copy of the draft regulatory evaluation prepared for this action is contained in the Rules Docket. A copy of it may be obtained by contacting the Rules Docket at the location provided under the caption ADDRESSES.

Accordingly, pursuant to the authority delegated to me by the Administrator, the Federal Aviation Administration proposes to amend part 39 of the Federal Aviation Regulations (14 CFR part 39) as follows:

On August 25, 2000, the Coast Guard published a notice of proposed rulemaking (65 FR 51787). The NPRM proposed to change the regulations governing the operation of the State Road 789 drawbridge across Longboat Pass, Manatee County, and the New Pass bridge, Sarasota County, in Longboat Key, Florida. The comment period ended on October 24, 2000. The Coast Guard has received requests from the U.S. Army Corps of Engineers, Manatee County, the town of Longboat Key, and the city of Sarasota for additional time to comment on this proposed rule. The Coast Guard believes additional time to comment on this notice of proposed rulemaking would be beneficial. Therefore, the Coast Guard is reopening the comment period for 60 days. All comments must be received by February 6, 2001.

Under the authority of 38 U.S.C. chapter 37, VA guarantees loans made by private lenders to eligible veterans to purchase, construct, improve, or refinance their homes (the term veteran as used in this document includes any individual defined as a veteran under 38 U.S.C. 101 and 3701 for the purpose of housing loans). This document proposes to amend VA's loan guaranty regulations for both manufactured homes and conventionally built homes by adding new advertising and solicitation disclosure requirements.

We have become aware of written advertisements and solicitations from private lenders that appear to falsely state or imply that they came from VA. For example, one solicitation from a private lender stated that it was from the “Government Loans Programs” and contained a reference to a VA case number. Another solicitation from a private lender stated that “[I]n accordance with regulations determined by the Department of Veterans Affairs this notice is officially issued to * * *” Another solicitation from a private lender stated that “The Veterans Benefit Administration known as VA, a division of the United States Department of Veterans Affairs is working with lenders to inform you * * *” Other solicitations from private lenders stated that they were from the “V.A. Loan Department,” “Veterans Department,” “Direct VA Streamline Department,” “Authorized VA Loan Center,” and “VA Conversion Center.” One solicitation from a private lender not only stated on the envelope that it was from the “Department of Veterans” but included the statement “Official Business, Penalty For Private Use, $300.”

Further, we have recently become aware of written advertisements and solicitations from private lenders that appear to falsely state or imply that they have been given special authority by VA to offer a unique loan product. For example, one solicitation from a private lender stated that “you are now eligible to take advantage of the Exclusive VA STREAMLINE refinance program.” Another solicitation from a private lender stated that “The Veterans Administration in conjunction with * * * Mortgage offers a unique program * * *”

To address these issues regarding advertisements and solicitations, we are proposing to establish advertising and solicitation requirements. We propose that any advertisement or solicitation in any form ( e.g., written, electronic, oral) from private lenders concerning housing loans to be guaranteed or insured by the Secretary must not include information falsely stating or implying that it was issued by or at the direction of VA or any other department or agency of the United States and must not include information falsely stating or implying that the lender has an exclusive right to make loans guaranteed or insured by VA.

If the proposed requirements are adopted, noncompliance may lead to suspension, debarment, or limited denial of participation in the VA housing loan program pursuant to 38 CFR part 44. Also, under 38 CFR part 44, such action could affect the lender's ability to participate in other governmental programs.

The Secretary hereby certifies that the adoption of the proposed rule would not have a significant economic impact on a substantial number of small entities as they are defined in the Regulatory Flexibility Act, 5 U.S.C. 601-612. The proposed rule would not have more than a minuscule effect on any small entities. Therefore, pursuant to 5 U.S.C. 605(b), the proposed rule is exempt from the initial and final regulatory flexibility analysis requirements of sections 603 and 604.

For the reasons set out in the preamble, 38 CFR part 36 is proposed to be amended as set forth below.

For additional information see the direct final rule which is published in the Final Rules Section of this Federal Register .

Comments . Comments and data may be submitted by electronic mail (e-mail) to: a-and-r-docket@epa.gov. Electronic comments must be submitted as an ASCII file to avoid the use of special characters and encryption problems and will also be accepted on disks in WordPerfect® version 5.1, 6.1 or Corel 8 file format. All comments and data submitted in electronic form must note the docket number: A-99-40. No confidential business information (CBI) should be submitted by e-mail. Electronic comments may be filed online at many Federal Depository Libraries.

Commenters wishing to submit proprietary information for consideration must clearly distinguish such information from other comments and clearly label it as CBI. Send submissions containing such proprietary information directly to the following address, and not to the public docket, to ensure that proprietary information is not inadvertently placed in the docket: Attention: Warren Johnson, c/o OAQPS Document Control Officer (Room 740B), U.S. EPA, 411 W. Chapel Hill Street, Durham, NC 27701. The EPA will disclose information identified as CBI only to the extent allowed by the procedures set forth in 40 CFR part 2. If no claim of confidentiality accompanies a submission when it is received by the EPA, the information may be made available to the public without further notice to the commenter.

Persons interested in presenting oral testimony or inquiring as to whether a hearing is to be held should contact Ms. Maria Noell at least 2 days in advance of the public hearing. Persons interested in attending the public hearing must also call Ms. Noell to verify the time, date, and location of the hearing. The address, telephone number, and e-mail address for Ms. Noell are listed in the preceding FOR FURTHER INFORMATION CONTACT section. If a public hearing is held, it will provide interested parties the opportunity to present data, views, or arguments concerning today's action.

The docket is an organized and complete file of all the information considered by the EPA in the development of this rulemaking. The docket is a dynamic file because material is added throughout the rulemaking process. The docketing system is intended to allow members of the public and industries involved to readily identify and locate documents so that they can effectively participate in the rulemaking process. Along with the proposed and promulgated standards and their preambles, the contents of the docket will serve as the record in case of judicial review (see section 307(d)(7)(A) of the CAA.) The regulatory text and other materials related to this rulemaking are available for review in the docket or copies may be mailed on request from the Air Docket by calling (202) 260-7548. A reasonable fee may be charged for copying docket materials. In addition to being available in the docket, an electronic copy of today's action will also be available on the WWW through the Technology Transfer Network (TTN). Following signature, a copy of today's action will be posted on the TTN's policy and guidance page for newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg . The TTN provides information and technology exchange in various areas of air pollution control. If more information regarding the TTN is needed, call the TTN HELP line at (919) 541-5384.

Categories and entities potentially regulated by this action include:

This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this action. To determine whether your facility is regulated by this action, you should examine the applicability criteria in § 63.211 of the proposed rule. If you have any questions regarding the applicability of this action to a particular entity, contact the person listed in the preceding FOR FURTHER INFORMATION CONTACT section.

The information presented in this preamble is organized as follows:

Section 112 of the CAA requires us to list categories and subcategories of all major sources and some area sources of HAP and to establish NESHAP for the listed source categories and subcategories. The major sources covered by today's proposed NESHAP are new and existing sources that produce PVC and copolymers. Major sources of HAP are those that are located within a contiguous area and under common control and have the potential to emit 9.1 megagrams per year (Mg/yr) (10 tons/yr) or more of any one HAP or 22.7 Mg/yr (25 tons/yr) or more of any combination of HAP.

Section 112 of the CAA requires that we establish NESHAP for the control of HAP from both new and existing major sources. The CAA requires the NESHAP to reflect the maximum degree of reduction in emissions of HAP that is achievable. This level of control is commonly referred to as MACT.

The MACT floor is the minimum control level allowed for NESHAP and is defined under section 112(d)(3) of the CAA. In essence, the MACT floor ensures all major sources achieve the level of control already achieved by the better-controlled and lower-emitting sources in each source category or subcategory. For new sources, the MACT floor cannot be less stringent than the emission control that is achieved in practice by the best-controlled similar source. The MACT standards for existing sources can be less stringent than standards for new sources, but they cannot be less stringent than the average emission limitation achieved by the best-performing 12 percent of existing sources (or the best-performing 5 sources for categories or subcategories with fewer than 30 sources).

In developing MACT, we also consider control options that are more stringent than the floor. In considering whether to establish standards more stringent than the floor, we must consider cost, non-air quality health and environmental impacts, and energy requirements.

The EPA recognized that PVC and copolymer production would not be addressed by the Hazardous Organic NESHAP (HON) (40 CFR part 63, subparts G, F and H), which address the requirements of section 112(d) of the CAA for the manufacturing of synthetic organic chemical manufacturing industry (SOCMI) chemicals, including ethylene dichloride (EDC) and vinyl chloride monomer (VCM). Therefore, on July 16, 1992 (57 FR 31576), the EPA listed PVC and Copolymers Production as a separate source category. This source category was listed because we had not yet evaluated whether the existing part 61 NESHAP, specifically the Vinyl Chloride NESHAP (40 CFR part 61, subpart F) was sufficient as MACT. Now that we have evaluated it and are proposing to find it adequate, the requirements constitute MACT in accordance with CAA section 112(d) and (q)(1). In addition, as with other NESHAP issued under the authority of CAA section 112(d), today's proposed NESHAP will also be subject to CAA section 112(f).

Polyvinyl chloride and copolymer products are not considered toxic, but the VCM feedstock is toxic, and the copolymer feedstocks, when they are used, may also be toxic chemicals ( i.e. , vinyl acetate and vinylidene chloride).

Acute (short-term) exposure to high levels of vinyl chloride in air has resulted in central nervous system effects, such as dizziness, drowsiness, and headaches in humans. Chronic (long-term) exposure to vinyl chloride through inhalation and oral exposure in humans has resulted in liver damage. There are positive human and animal studies showing adverse effects which raise a concern about potential reproductive and developmental hazards to humans from exposure to vinyl chloride. Cancer is a major concern from exposure to vinyl chloride via inhalation, as vinyl chloride exposure has been shown to increase the risk of a rare form of liver cancer in humans. The EPA has classified vinyl chloride as a Group A, known human carcinogen. In addition, VCM is explosive when airborne in concentrations between 4 and 22 percent by volume. For these reasons, special care ( e.g. , nitrogen blankets and polymerization inhibitors) must be taken in storage and shipment of VCM, and manufacturing processes using VCM must control the VCM emissions, worker exposure, and the residual content of VCM in products.

The primary acute (short-term) effects in humans from vinylidene chloride (1,1 dichlorethylene) exposure are on the central nervous system, including central nervous system depression and symptoms of inebriation, convulsions, spasms, and unconsciousness at high concentrations. Low-level, chronic (long-term) inhalation exposure of vinylidene chloride in humans may affect the liver. Animal studies indicate that chronic exposure to vinylidene chloride can affect the liver, kidneys, central nervous system, and lungs. No studies were located regarding developmental or reproductive effects in humans, but birth defects have been reported in offspring of pregnant animals that had inhaled vinylidene chloride. Human data are considered inadequate in providing evidence of cancer from exposure to vinylidene chloride. Limited animal cancer data have shown an increase in kidney and mammary tumors, while other studies have not shown an increase in tumors. Vinylidene chloride has been classified as a Group C, possible human carcinogen.

Acute (short-term) inhalation exposure of workers to vinyl acetate has resulted in eye and upper respiratory tract irritation. Chronic (long-term) occupational exposure results in upper respiratory tract irritation, cough, and/or hoarseness. Nasal epithelial lesions and irritation and inflammation of the respiratory tract were observed in mice and rats chronically exposed by inhalation. No information is available on the reproductive, developmental, or carcinogenic effects of vinyl acetate in humans. Some limited animal data suggest reduced body weight, fetal growth retardation, and minor skeletal fetal defects at high exposure levels. An increased incidence of nasal cavity tumors has been observed in rats exposed by inhalation. The EPA has not classified vinyl acetate for carcinogenicity.

The PVC and Copolymers Production source category includes all sources that are new and existing major sources that polymerize vinyl chloride monomer alone, or in combination with other materials, to produce PVC and copolymers.

We estimate there are 28 PVC and copolymer manufacturing plants operating in the United States. This source category was listed under CAA section 112 because it contains major sources of HAP. Although today's proposal applies only to these major sources in the source category, the existing part 61 NESHAP make no distinction between major and area sources and, therefore, continue to apply to both. Likewise, the existing part 61 NESHAP make no distinction between new and existing sources and, therefore, require the same emission standards for both. Rationale for why we decided that new source MACT should be the same as existing source MACT in today's proposed NESHAP is discussed in section III.B.

Although demand for PVC and copolymers has increased slightly in the last year, this increase and anticipated future increases are within the capacity of the current facilities. For this reason, we anticipate near zero growth of this source category beyond the existing sources over the next 5 years.

Polyvinyl chloride and copolymer products have a large number of commercial and industrial applications. It is the manufacture of the resins used to make these products that is considered PVC and copolymers production. The resins are produced in a variety of mediums resulting from one of four basic polymerization process types: suspension, emulsion, bulk, and solution. Producing these resins involves batch reactor processes where VCM is polymerized with itself as a homopolymer or copolymerized with varying amounts of vinyl acetate, ethylene, propylene, vinylidene chloride, or acrylates. The resulting resins are generally dried into nontoxic powders or granules that are compounded with auxiliary ingredients and converted into a variety of plastic end products. These end products can be used in a large number of applications, including latex paints, coatings, adhesives, clear plastics, rigid plastics, and flooring.

The PVC is not a HAP, but manufacturing PVC requires VCM, which is a HAP, as a primary feedstock, and trace amounts of unreacted VCM may linger in the PVC product. There are basically two ways for HAP to be introduced to the atmosphere from these processes: either the HAP is released from an opening or leak in the process equipment, or the residual HAP ( i.e. , unreacted VCM) in the product become airborne. Stripping at the production stage to recover unreacted feedstock reduces the air emissions from the product by reducing the residual HAP in the product.

The affected source is the collection of all equipment and activities necessary to produce PVC and copolymers. To determine whether a facility is affected by today's action, you should examine the applicability criteria at 40 CFR 61.60(a)(3), (b) and (c).

The following emission types ( i.e. , emission points) are currently covered by the existing part 61 NESHAP: reactor opening losses, equipment leaks, storage vessels, process vents, hoses and lines, wastewater operations, and major releases from process upsets.

As provided under the authority of CAA section 112(d) and (q), we are proposing that you comply with all the requirements of the Vinyl Chloride NESHAP, as specified at 40 CFR part 61, subpart F. The Vinyl Chloride NESHAP sets forth emission standards in the forms of numerical emission limits and work practices. The Vinyl Chloride NESHAP also sets forth all requirements for monitoring, test methods, recordkeeping, and reporting.

All existing sources, as defined at 40 CFR 61.02, should already be in compliance with today's proposed NESHAP since we are proposing that owners or operators comply with all the requirements of the Vinyl Chloride NESHAP.

Therefore, we believe that the requirement to set a compliance date that is as expeditious as practicable is satisfied by setting the compliance date on [the effective date for the final rule] for existing sources. A new source must be in compliance with the NESHAP on [the effective date of the final rule] or at start up, whichever is later.

Although the existing part 61 NESHAP contain standards for alternative controls, stripping is the primary control used for limiting VCM and other HAP emissions.

Through stripping operations, residual unreacted VCM in the PVC and copolymers is minimized before subsequent process steps ( e.g. , product drying) occur. Stripping is also an economical way to recover unreacted feeds, primarily VCM, following the polymerization process. In stripping out the VCM from the product, other residual HAP are also removed. As a result, the stripping really controls all HAP by removing the unreacted chemicals from the PVC and copolymers before the product is exposed to the atmosphere during later processing steps, which typically include drying. It is important that these HAP be removed before drying, not only because dryers efficiently convey dilute HAP emissions to the atmosphere, but also because these HAP are explosive under certain conditions.

In addition to stripping, other HAP control measures include operating under a closed-vent system with add-on control ( e.g. , flare) to incinerate HAP gases not returning to the process, minimizing the presence of HAP before opening a reactor or piece of process equipment containing VCM and other HAP, ongoing leak detection and repair (LDAR), ongoing area monitoring to sample the ambient air for the presence of VCM as a precautionary early warning of a major release, and other special care.

Because there are fewer than 30 sources in this source category, to identify the existing source MACT floor, we look at the average emission limitation achieved by the five best performing sources. Since all 28 sources are subject to the existing part 61 NESHAP, we did not identify a group of five sources as best performers. Rather, we have identified the existing part 61 NESHAP as the existing source MACT floor.

We are aware that some States have added numerical emission limits in facilities' permits that are lower than the numerical limits specified in the part 61 NESHAP. We do not believe, however, that using these lower State limits is an appropriate basis for identifying a group of five best performers in setting a new, lower emission limit within the context of a part 63 NESHAP.

These lower State numbers are in addition to the limit in the part 61 NESHAP, and they correspond to a longer averaging time. Unlike other NESHAP which may allow quarterly or annual averaging times to achieve a limit, the part 61 NESHAP require daily compliance with the limit on an instantaneous basis. Since process variability is inherent in even normal operations in the batch processes where PVC and copolymers are produced, facilities must set operational parameters below regulatory limits to ensure that the instantaneous limits are not exceeded.

Also, these State limits are set based on the products each facility is manufacturing since PVC and copolymers vary in their ability to be stripped based on their morphology and resistance to sheer. Depending on the resins being produced, State operating permits generally stipulate lower numerical limits over a longer averaging time, in addition to the instantaneous daily limits required by the part 61 NESHAP. These permit conditions are good practice on the part of the State permitting authorities for ensuring control consistency over longer periods for the specific facilities. However, we do not believe that new part 63 NESHAP, based on the average of the best quarterly or yearly limits, would result in any greater emissions reductions beyond the current levels resulting from the part 61 NESHAP since we would have to factor in the wide range of product variability to set limits achievable across the source category.

We are also proposing new source MACT equivalent to existing source MACT. Although some processes may be able to strip and achieve a HAP concentration lower than the limit specified in the Vinyl Chloride NESHAP, such a lower limit would not be applicable across the source category due to variations in the processes and product characteristics.

After stripping, some unreacted VCM will remain suspended in the product. The amount of VCM remaining in a product varies with the product design. Excessive stripping could sheer some of the products while other products can strip to very low levels of residual HAP. Also, these residual HAP generally provide a necessary part of the product design characteristics. The existing part 61 NESHAP took this into account when requiring residual VCM to be limited to below 400 parts per million (ppm) for all cases except for certain dispersion resins.

We have also not identified any work practice standards more stringent than those required by the Vinyl Chloride NESHAP, which require that equipment be vapor tight and any HAP release to the atmosphere be less than 10 ppm VCM. In comparison to LDAR provisions or low concentration cutoffs (typically at 20 ppm) in other NESHAP, the Vinyl Chloride NESHAP work practice standards are more stringent.

The Vinyl Chloride NESHAP apply to sources that manufacture EDC, VCM, and PVC and copolymers. The sources that manufacture EDC and VCM are not the subject of today's proposal because they are already subject to the HON, which is the NESHAP for the source category that produces SOCMI chemicals. The PVC and copolymers are not considered SOCMI chemicals since they are produced in batch process reactors, which are distinctly different than the continuous process units employed by the SOCMI chemical manufacturers. Hence, PVC and copolymers were not included in the HON applicability because they are a separate source category and unique to SOCMI.

Since the Vinyl Chloride NESHAP reside in 40 CFR part 61, and since today's proposal incorporates the existing standards, it is appropriate that the General Provisions to part 61 continue to apply. Today's proposed NESHAP affect only new and existing “major sources,” which is a concept not used in part 61. Therefore, in order to properly address applicability as it pertains to part 63 standards, certain terms and provisions in the General Provisions of part 63 that delineate MACT applicability, construction and reconstruction (specifically, provisions in §§ 63.1 and 63.5) would also need to apply. Since today's proposed NESHAP require that reconstructed sources comply with the new source MACT requirements, they would be subject to the new source requirements under part 61 even though the term “reconstruction” is not used in part 61. Within §§ 63.1 and 63.5, the provisions in § 63.1(a)(9) through (12) regarding notices, time periods, and postmarks; and the references in §§ 63.5, 63.6, 63.9 and 63.10 regarding administrative compliance, notification and recordkeeping procedures should be disregarded since these procedures are already defined in the part 61 General Provisions.

We anticipate that all existing sources (an estimated 28 sources) are major sources, and that any new sources will also be major sources, as defined by the CAA. Part 70 requires that all major sources retain reports and records for 5 years under § 70.6(a)(3)(ii)(B), even though the 40 CFR part 61 NESHAP only require that reports and records be retained for 3 years. Under part 70, affected sources are expected to be in compliance with applicable standards on a continuous basis, and exceedances or excursions outside the established limits or parameter ranges, including those that occur during periods of startup, shutdown or malfunction, are considered deviations under § 70.6(a)(3)(iii)(B).

The 40 CFR part 61 NESHAP do not rely on the recent publication of performance specification (PS) 8 for volatile organic compound (VOC) continuous emissions monitoring system (CEMS), PS 9 for gas chromatographic CEMS, or the quality assurance requirements for VOC measurement in 40 CFR part 60, appendix F, procedure 1. We are soliciting comment on whether or not we should require PS 8 and 9, and appendix F in lieu of, or as an option to, the monitoring requirements in § 61.68.

There are no environmental, energy or economic impacts anticipated from these proposed NESHAP beyond the current requirements of 40 CFR part 61, subpart F, which are already in effect.

Under Executive Order 12866 (58 FR 51735, October 4, 1993), EPA must determine whether the regulatory action is “significant” and therefore subject to review by the Office of Management and Budget (OMB) and the requirements of the Executive Order. The Executive Order defines “significant regulatory action” as one that is likely to result in a rule that may:

(1) Have an annual effect on the economy of $100 million or more or adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, public health or safety, or state, local, or tribal governments or communities;

(2) create a serious inconsistency or otherwise interfere with an action taken or planned by another agency;

(3) materially alter the budgetary impact of entitlements, grants, user fees, or loan programs, or the rights and obligation of recipients thereof; or

(4) raise novel legal or policy issues arising out of legal mandates, the President's priorities, or the principles set forth in the Executive Order.

Pursuant to the terms of Executive Order 12866, it has been determined that this rule is not a “significant regulatory action” because none of the listed criteria apply to this action. Consequently, this action was not submitted to OMB for review under Executive Order 12866.

Executive Order 13132, entitled “Federalism” (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.” “Policies that have federalism implications” is defined in the Executive Order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.” Under Executive Order 13132, EPA may not issue a regulation that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by State and local governments, or EPA consults with State and local officials early in the process of developing the proposed NESHAP. The EPA also may not issue a regulation that has federalism implications and that preempts State law unless EPA consults with State and local officials early in the process of developing the proposed NESHAP.

If EPA complies by consulting, Executive Order 13132 requires EPA to provide to OMB, in a separately identified section of the preamble to the rule, a federalism summary impact statement (FSIS). The FSIS must include a description of the extent of EPA's prior consultation with State and local officials, a summary of the nature of their concerns and EPA's position supporting the need to issue the regulation, and a statement of the extent to which the concerns of State and local officials have been met. Also, when EPA transmits a draft final rule with federalism implications to OMB for review pursuant to Executive Order 12866, it must include a certification from EPA's Federalism Official stating that EPA has met the requirements of Executive Order 13132 in a meaningful and timely manner.

This proposed rule will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, the requirements of section 6 of the Executive Order do not apply to this rule.

Under Executive Order 13084, EPA may not issue a regulation that is not required by statute, that significantly or uniquely affects the communities of Indian tribal governments, and that imposes substantial direct compliance costs on those communities, unless the Federal government provides the funds necessary to pay the direct compliance costs incurred by the tribal governments, or EPA consults with those governments. If EPA complies by consulting, Executive Order 13084 requires EPA to provide to OMB, in a separately identified section of the preamble to the rule, a description of the extent of EPA's prior consultation with representatives of affected tribal governments, a summary of the nature of their concerns, and a statement supporting the need to issue the regulation. In addition, Executive Order 13084 requires EPA to develop an effective process permitting elected officials and other representatives of Indian tribal governments “to provide meaningful and timely input in the development of regulatory policies on matters that significantly or uniquely affect their communities.” Today's proposed rule does not significantly or uniquely affect the communities of Indian tribal governments. No tribal governments own or operate PVC and copolymer production facilities. Accordingly, the requirements of section 3(b) of Executive Order 13084 do not apply to today's proposed NESHAP.

Executive Order 13045 (62 FR 19885, April 23, 1997) applies to any rule that: (1) is determined to be “economically significant” as defined under Executive Order 12866, and (2) concerns an environmental health or safety risk that EPA has reason to believe may have a disproportionate effect on children. If the regulatory action meets both criteria, EPA must evaluate the environmental health or safety effects of the planned rule on children, and explain why the planned regulation is preferable to other potentially effective and reasonably feasible alternatives that EPA considered.

The EPA interprets Executive Order 13045 as applying only to those regulatory actions that are based on health or safety risks, such that the analysis required under section 5-501 of the Executive Order has the potential to influence the regulation. This rule is not subject to Executive Order 13045 because it is based solely on technology performance. No children's risk analysis was performed because no alternative technologies exist that would provide greater stringency at a reasonable cost. Furthermore, this proposed rule has been determined not to be “economically significant” as defined under Executive Order 12866.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on State, local, and tribal governments and the private sector. Under section 202 of the UMRA, EPA generally must prepare a written statement, including a cost-benefit analysis, for proposed and final rules with “Federal mandates” that may result in expenditures by State, local, and tribal governments, in aggregate, or by the private sector, of $100 million or more in any 1 year. Before promulgating an EPA rule for which a written statement is needed, section 205 of the UMRA generally requires EPA to identify and consider a reasonable number of regulatory alternatives and adopt the least-costly, most cost-effective, or least-burdensome alternative that achieves the objectives of the rule. The provisions of section 205 do not apply when they are inconsistent with applicable law. Moreover, section 205 allows EPA to adopt an alternative other than the least-costly, most cost-effective, or least- burdensome alternative if the Administrator publishes with the final rule an explanation why that alternative was not adopted. Before EPA establishes any regulatory requirements that may significantly or uniquely affect small governments, including tribal governments, it must have developed under section 203 of the UMRA a small government agency plan. The plan must provide for notifying potentially affected small governments, enabling officials of affected small governments to have meaningful and timely input in the development of EPA's regulatory proposals with significant Federal intergovernmental mandates, and informing, educating, and advising small governments on compliance with the regulatory requirements.

The EPA has determined that this proposed rule does not contain a Federal mandate that may result in expenditures of $100 million or more for State, local, and tribal governments, in the aggregate, or the private sector in any 1 year. There are no cost burdens introduced by today's proposed rule. Thus, today's proposed rule is not subject to the requirements of sections 202 and 205 of the UMRA. In addition, EPA has determined that this proposed rule contains no regulatory requirements that might significantly or uniquely affect small governments because it contains no requirements that apply to such governments or impose obligations upon them. Therefore, today's proposed rule is not subject to the requirements of section 203 of the UMRA.

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of today's proposed rule on small entities, small entity is defined as: (1) a small business whose parent company has fewer than 750 employees; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of today's proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities. We have determined, following discussions with State and industry representatives, that the scope of today's proposed rule includes no small entities as defined above. But, even if a small entity was within the scope of today's proposed rule, no adverse impact to the small entity would result, since today's proposed rule creates no new requirements or burdens for any of the affected entities.

The EPA continues to be interested in the potential impacts of the proposed rule on small entities and welcomes comments on issues

The OMB has approved the information collection requirements contained in 40 CFR part 61, subpart F (Vinyl Chloride NESHAP) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq., and has assigned OMB control No. 2060-0071. An Information Collection Request (ICR) document was prepared by EPA (ICR No. 186.08), and a copy may be obtained from Sandy Farmer by mail at Office of Environmental Information, Collection Strategies Division (2822), U.S. EPA, 1200 Pennsylvania Avenue NW, Washington, DC 20460, by email at farmer.sandy@epa.gov, or by calling (202) 260-2740. You may also download a copy off the Internet at http://www.epa.gov/icr.

Today's proposed NESHAP ( i.e. , proposed 40 CFR part 63, subpart J) require that PVC and copolymers production facilities continue to comply with 40 CFR part 61, subpart F. Therefore, today's proposed NESHAP add no additional information collection burden. Consequently, no ICR has been prepared for today's proposed NESHAP.

Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) directs EPA to use voluntary consensus standards in their regulatory and procurement activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e.g. , materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. The NTTAA directs EPA to provide Congress, through annual reports to the OMB, with explanations when an agency does not use available and applicable voluntary consensus standards.

This proposal references 40 CFR part 61, subpart F. Since there are no new standard requirements in these proposed NESHAP, and there are no new requirements resulting from specifying subpart F of part 61, EPA is not proposing/adopting any voluntary consensus standards in today's proposed NESHAP.

The EPA takes comment on proposed compliance demonstration requirements proposed in this rulemaking and specifically invites the public to identify potentially-applicable voluntary consensus standards. Commenters should also explain why this proposed rule should adopt them in lieu of EPA's standards. Emission test methods and performance specifications submitted for evaluation should be accompanied with a basis for the recommendation, including method validation data and the procedure used to validate the candidate method (if method other than Method 301, 40 CFR part 63, appendix A, was used).

For the reasons stated in the preamble, title 40, chapter I, part 63 of the Code of the Federal Regulations is proposed to be amended as follows:

For additional information, see the Direct Final Action which is located in the Rules Section of this Federal Register .

1. The Commission's Third Notice of Proposed Rule Making (3rd NPRM), PR Docket No. 92-257, FCC 00-370, adopted October 13, 2000, and released on November 16, 2000. The full text of this 3rd NPRM is available for inspection and copying during normal business hours in the FCC Reference Center, Room CY-A257, 445 12th Street, SW., Washington, DC. The complete text may be purchased from the Commission's copy contractor, International Transcription Service, Inc., 1231 20th Street, NW., Washington, DC 20037. The full text may also be downloaded at: http://www.fcc.gov/Wireless/Orders/2000/fcc00370.txt. Alternative formats are available to persons with disabilities by contacting Martha Contee at (202) 418-0260 or TTY (202) 418-2555.

2. The Commission proposes a transition from the site-based licensing approach to geographic area licensing because such an approach would speed assignment of subsequent AMTS licenses, reduce processing burdens on the Commission, facilitate the expansion of existing AMTS systems and the development of new AMTS systems, eliminate inefficiencies arising from the intricate web of relationships created by site-specific authorization, and enhance regulatory symmetry.

3. The Commission seeks comment on whether the use of band manager licensing may be an appropriate alternative method of accomplishing the objectives that it strives to achieve through its partitioning and disaggregation rules. Band managers would be a class of Commission licensee that would engage in the business of making spectrum available for use by others through private, written contracts.

4. The Commission seeks comment, in light of its continuing commitment to take measures to ensure that the current and future communications needs of the public safety community are addressed, on whether it should take any steps to facilitate use of AMTS spectrum by public safety entities, including setting aside some channels for public safety use.

5. The Commission proposes to modify the requirement that AMTS stations must serve a waterway because it is inconsistent with geographic licensing and could prevent service from being offered in some licensing areas. Therefore, the Commission seeks comment on its proposal that stations may be placed anywhere within a licensee's service area so long as marine-originating traffic is given priority and incumbent operations are protected. It also seeks comment on its proposal that licensees whose service areas encompass certain major waterways be required to provide coverage to those waterways, as is required of VHF public coast geographic licensees.

6. The Commission proposes to authorize two geographic area licensees in each licensing area, with each licensee authorized to use one of the two AMTS frequency blocks because it concludes that this will promote competition in the maritime CMRS marketplace. Under this proposal, incumbent AMTS licensees would be permitted to operate their systems indefinitely, and incumbents and geographic licensees would have to afford each other interference protection.

7. The Commission proposes to license HF public coast station radiotelephone frequency pairs individually, rather than in blocks, due to this frequency's propagation characteristics and insufficient demand.

8. The Commission also proposes to redistribute radiotelephone frequency pairs by permitting MF private coast stations to use unassigned public coast station radiotelephone frequency pairs in the 2 MHz band for non-CMRS services because it will promote the more efficient use of maritime spectrum and reduce congestion for MF private coast licensees.

9. Finally, the Commission concludes that the engineering study requirement for new AMTS stations that are not fill-in stations should not be eliminated because it continues to be a critical mechanism for protecting television reception.

10. As required by the RFA, the Commission has prepared this present IRFA of the possible significant economic impact on small entities of the policies and rules proposed in the Third Further Notice of Proposed Rule Making (3rd FNPRM). Written public comments are requested on this IRFA. Comments must be identified as responses to the IRFA and must be filed by the deadlines for comments on the 3rd FNPRM provided in the item. The Commission will send a copy of the 3rd FNPRM, including this IRFA, to the Chief Counsel for Advocacy of the Small Business Administration. See 5 U.S.C. 603(a). In addition, the 3rd FNPRM and IRFA (or summaries thereof) will be published in the Federal Register . See id.

11. Our objective is to determine whether it is in the public interest, convenience, and necessity to simplify our licensing process for AMTS and high seas public coast stations. These proposals include (1) converting licensing of AMTS coast station spectrum from site-based to geographic area licensing, (2) simplifying the AMTS licensing procedures and rules, (3) increasing AMTS and high seas public coast station licensee flexibility to provide service over a wide area, and (4) employing the Commission's Part 1 standardized competitive bidding procedures to resolve mutually exclusive applications. In addition, we temporarily suspend the acceptance and processing of certain AMTS and high seas public coast station applications because we believe that after the public has been placed on notice of our proposed rule changes, continuing to accept new applications under the current rules would impair the objectives of this proceeding. These proposed rules and actions should increase the number and types of communications services available to the maritime community.

1. Authority for issuance of this item is contained in sections 4(i), 4(j), 7(a), 302, 303(b), 303(f), 303(g), 303(r), 307(e), 332(a), and 332(c) of the Communications Act of 1934, as amended, 47 U.S.C. 154(i), 154(j), 157(a), 302, 303(b), 303(f), 303(g), 303(r), 307(e), 332(a), and 332(c).

13. The RFA directs agencies to provide a description of and, where feasible, an estimate of the number of small entities that may be affected by the proposed rules, if adopted. The RFA generally defines the term “small entity” as having the same meaning as the terms “small business,” “small organization,” and “small governmental jurisdiction.” In addition, the term “small business” has the same meaning as the term “small business concern” under the Small Business Act. A small business concern is one which: (1) Is independently owned and operated; (2) is not dominant in its field of operation; and (3) satisfies any additional criteria established by the Small Business Administration (SBA). A small organization is generally “any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.”

14. The proposed rules would affect licensees using AMTS and high seas public coast spectrum. In the Third Report and Order in this proceeding, the Commission defined the term “small entity” specifically applicable to public coast station licensees as any entity employing less than 1,500 persons, based on the definition under the Small Business Administration rules applicable to radiotelephone service providers. See, Amendment of the Commission's Rules Concerning Maritime Communications, Third Report and Order and Memorandum Opinion and Order, 13 FCC Rcd 19853, 19893 (1998) (citing 13 CFR 121.201, Standard Industrial Classification (SIC) Code 4812). Since the size data provided by the Small Business Administration does not enable us to make a meaningful estimate of the number of AMTS and high seas public coast station licensees that are small businesses, we have used the 1992 Census of Transportation, Communications, and Utilities, conducted by the Bureau of the Census, which is the most recent information available. This document shows that only 12 radiotelephone firms out of a total of 1,178 such firms which operated in 1992 had 1,000 or more employees. Thus, we estimate that no fewer than 1,166 small entities will be affected. Any entity that is capable of providing radiotelephone service is eligible to hold a public coast license. Therefore, we seek comment on the number of small entities that use AMTS and high seas public coast spectrum and the number of small entities that are likely to apply for licenses under the various proposals described herein.

15. We will award licenses by competitive bidding where mutually exclusive applications are filed. Prior to auction, all applicants, including small businesses, will be required to submit an FCC Form 175, OMB Clearance Number 3060-0600. If we use small business definitions for the purpose of providing bidding credits to auction participants, then all small businesses that choose to participate in these services will be required to demonstrate that they meet the criteria set forth to qualify as small businesses, as required under part 1, Subpart Q of the Commission's Rules. See 47 CFR part 1, Subpart Q. Any small business applicant wishing to avail itself of small business provisions will need to make the general financial disclosures necessary to establish that the small business is in fact small. The estimated time for filling out an FCC Form 175 is 45 minutes. Each applicant will have to submit information regarding the ownership of the applicant, any joint venture arrangements or bidding consortia that the applicant has entered into, and, if claiming eligibility for bidding credits, financial information demonstrating that the applicant qualifies as a small business. Applicants that do not have audited financial statements available will be permitted to certify the validity of their financial showings. While many small businesses have chosen to employ attorneys prior to filing an application to participate in an auction, the rules are intended to enable a small business to file an application on its own using the short form application preparation guidelines that are made available by the Commission before any auction. When an applicant wins a license, it will be required to submit an FCC Form 601 license application, which will require technical information regarding the applicant's proposals for providing service and other information. This application will require information provided by an engineer who will have knowledge of the system's design. The estimated time for completing an FCC Form 601 is one hour and fifteen minutes.

16. The RFA requires an agency to describe any significant alternatives that it has considered in reaching its proposed approach, which may include the following four alternatives: (1) The establishment of differing compliance or reporting requirements or timetables that take into account the resources available to small entities; (2) the clarification, consolidation, or simplification of compliance or reporting requirements under the rule for small entities; (3) the use of performance, rather than design, standards; and (4) an exemption from coverage of the rule, or any part thereof, for small entities.

17. In the 3rd FNPRM, the Commission proposes that the part 1 unjust enrichment provisions will govern partitioning and disaggregation arrangements involving AMTS licenses owned by small businesses that were afforded a bidding credit and later elect to partition or disaggregate their licenses to an entity that does not qualify as a small business. The alternative to applying the unjust enrichment provisions would be to allow an entity who had benefited from the special bidding provisions for small businesses to become unjustly enriched by partitioning or disaggregating its licenses to parties that do not qualify for such benefits.

18. The 3rd FNPRM solicits comment on a variety of alternatives set forth herein. Any significant alternative presented in the comments will be considered.

None.

All written comments should identify the docket and notice numbers stated in the heading of this notice. Anyone who wants confirmation of mailed comments must include a self-addressed stamped postcard. To file written comments electronically, after logging onto http://dms.dot.gov, click on “Electronic Submission.” You can read comments and other material in the docket at this Web address: http://dms.dot.gov. General information about our pipeline safety program is available at this address: http://ops.dot.gov.

We have reviewed the corrosion control standards in 49 CFR part 195 for hazardous liquid and carbon dioxide pipelines to see if any standards need to be made clearer, more effective, or consistent with acceptable safety practices. Although the likelihood of corrosion-caused accidents harming people or the environment is relatively low, we undertook the review because corrosion is the second leading cause of reported accidents on hazardous liquid pipelines, and improving the standards has the potential to reduce the number of future accidents. 1

The review began September 8, 1997, when we held a public meeting on how the part 195 corrosion control standards and the corrosion control standards for gas pipelines in 49 CFR part 192 might be improved (62 FR 44436; Aug. 21, 1997). To attract participation by corrosion experts, we held the public meeting in Oakbrook, Illinois, in conjunction with meetings of NACE International, a professional technical society dedicated to corrosion control.

The Oakbrook meeting focused on whether we should incorporate by reference NACE Standard RP0169-96, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems,” as a substitute for all or some of the part 192 and part 195 standards. Two other significant topics were whether part 192 and part 195 corrosion control standards need to be updated to ensure safety, and whether gas, hazardous liquid, and carbon dioxide pipelines should be subject to the same corrosion control standards.

For technical and other reasons, including the document's non-mandatory style, most meeting participants and subsequent commenters opposed incorporating the entire NACE Standard RP0169-96 by reference. But participants agreed universally that part 192 and part 195 corrosion control standards are largely sufficient, and although some changes may be needed, the standards should be generally the same.

Toward this end, we began to consider whether the more comprehensive part 192 standards, possibly with some changes, would be appropriate for hazardous liquid and carbon dioxide pipelines. For technical input, we met from time to time with representatives of NACE, the pipeline industry, and state pipeline safety agencies. At these meetings, we also examined whether the part 192 standards need to be more effective or clearer. As guidance for this assessment, the meeting participants developed the following principles:

• Evaluate existing data and use the evaluation to assess the need to change standards.

• Continue to improve public safety and environmental protection.

• Assess the need for corrosion control standards throughout the national pipeline system based on the risk associated with different parts of the system.

• Upgrade regulations to allow for future changes in pipeline industry technology and operating practices as appropriate.

• Strive for uniform interpretation/enforcement.

• To the extent practicable, involve all interested parties in assessing the need to change standards.

• Use the new cost/benefit policy framework being developed for RSPA's pipeline safety advisory committees in determining the costs and benefits of potential changes to standards.

• Achieve balance between performance and prescriptive language.

• Develop performance measures to assess the effectiveness of corrosion control programs.

• Focus on managing corrosion to maintain pipeline integrity.

• Provide adequate regulatory flexibility to allow operators to implement alternative measures that meet the performance requirements of the corrosion regulations.

The meetings left us with various concerns about the total effectiveness and clarity of the part 192 corrosion control standards and the suitability of applying those standards to hazardous liquid and carbon dioxide pipelines. We also knew that the National Association of Pipeline Safety Representatives (NAPSR), the Gas Piping Technology Committee (GPTC), and the National Transportation Safety Board (NTSB) had at various times recommended changes to part 192 and part 195 corrosion control standards. So, to get public comment on our concerns and the recommended changes, we held another public meeting on April 28, 1999, in San Antonio, Texas (64 FR 16885; April 7, 1999). We also invited comments on the idea of allowing operators to follow their own corrosion management plans or NACE Standard RP0169-96 as an alternative to all or part of the part 192 or part 195 corrosion control standards.

At least 180 persons attended the San Antonio public meeting. However, only a few persons made oral statements, which are summarized as follows:

The Interstate Natural Gas Association of America (INGAA) said that based on the record of low numbers of deaths and injuries, not much change in the part 192 standards is needed, even if corrosion is the second leading cause of reported pipeline incidents. INGAA attributed the good safety record to proper management of risk, saying it would be nonproductive if changes to generally applicable safety standards caused operators to shift their limited resources away from higher risk areas. INGAA emphasized the use of cost/benefit assessment in determining the need for new or revised standards. At least two other meeting participants (Enron and Columbia Gulf) expressed support for INGAA's views.

The American Gas Association (AGA) and American Public Gas Association (APGA) jointly made a statement similar to INGAA's and pointed out that DOT safety statistics do not justify changes in the present standards. AGA/APGA further noted that corrosion is not the second leading cause of incidents on gas distribution lines, but the last cause, resulting in about 4 percent of all reported incidents. The views of AGA/APGA were supported by at least one other meeting participant (Columbia Gulf) and by a majority of the persons who submitted written comments to the docket after the meeting. These subsequent written comments are condensed below under the “Comments after San Antonio” subheading.

Another participant, Global Cathodic Protection, submitted a statement, backed by 72 corrosion control practitioners, that cathodic protection criteria in appendix D of part 192 are preferred to the criteria in NACE Standard RP0169-96.

Equilon Enterprises, an operator of petroleum pipelines, did not support the alternative of corrosion management plans, because of the burden of review by government and the possibility that government reviewers and operator personnel may not be equally qualified to evaluate the plans. In addition, Equilon said that removing unnecessary differences between part 192 and part 195 standards would minimize confusion and disagreements between operators and government inspectors. On other points raised in the meeting notice, Equilon preferred that part 195 not refer to NACE Standard RP0169-96. But, Equilon did support the need for qualification requirements for bosses who lead corrosion control programs, and it thought the part 192 standards should disallow the use of bare unprotected pipe.

An engineering consultant said the “instant-off” approach to measuring cathodic protection was excessive. Similarly, the Equilon representative said that across-the-board use of the negative 850 mV criterion with instant-off readings is not productive, and that the 100 mV criterion is more cost-effective in many cases. A university professor said that corrosion control technicians do not do instant-off tests the same way. But another engineering consultant noted that NACE has a companion standard that covers instant-off tests: TM0497-97, Measurement Techniques Related to Criteria for Cathodic Protection on Underground or Submerged Metallic Piping Systems.

Following the San Antonio public meeting, the docket remained open to receive written comments on the matters addressed in the meeting notice. Sixty-two persons filed written comments. These commenters included pipeline safety agencies in Arizona and Iowa, two corrosion control firms (Corrosion Control International and Global Cathodic Protection), two operators of petroleum pipelines (Mobil Corporation and Tosco Refining Company), seven pipeline trade associations (American Gas Association (AGA), American Public Gas Association (APGA), Interstate Natural Gas Association of America, New England Gas Association, New York Gas Group, Ohio Gas Association, and American Petroleum Institute), six operators of interstate gas pipelines (CMS Energy, Columbia Energy Group, Duke Energy, Enron Gas Pipeline Group, KN Energy, and Phillips Pipe Line Company), and 43 local gas distribution companies.

General Comments. Most of the written comments specifically address RSPA concerns and other topics in the San Antonio meeting notice. Still, there were some general comments: Two gas distribution operators said that requiring operators to cathodically protect cast iron or ductile iron pipe would have a big impact on the distribution industry. These operators also suggested that small fittings made of copper or brass and steel fittings with a corrosion resistant coating should be exempt from cathodic protection requirements. Other rule changes they suggested were intended to yield savings by specifying that electronic or remote data collection can be used to meet the monitoring requirements and by extending the interval for monitoring rectifiers from every 2 months to twice a year, particularly for newly manufactured devices.

AGA/APGA welcomed minor rule changes that address clarity, consistency, technology, but said that sweeping changes are not justified by the safety data. They advised us to use cost/benefit assessment and non-regulatory approaches to perceived problems. Of the 62 commenters, 42 expressed support for the joint comments of AGA/APGA. Others, such as Mobil Corporation, Enron, and the New England Gas Association, similarly expressed doubt that substantial changes to the standards were warranted in view of the incident record. One commenter, Kansas Gas Service, backed up its claim that the present standards are adequate by referring to its own record: no reported incidents for the period 1989-98. Tosco Refining stated that making the corrosion control maintenance requirements in Parts 192 and 195 alike would mitigate compliance difficulties for companies that operate both gas and petroleum pipelines.

Comments on RSPA Concerns: This section of the preamble includes summaries of comments that specifically address RSPA's concerns about whether certain provisions of Part 192 corrosion control standards need to be improved. The AGA/APGA comments are identified because many commenters supported the AGA/APGA views. Summaries of comments on changes recommended by NAPSR, GPTC, and NTSB, on alternatives, and on topics included in the “Public Participation” section of the meeting notice are discussed afterward.

RSPA Concern: In view of the proposed rules on qualification of pipeline personnel (63 FR 57269; Oct. 27, 1998)  2 , are more specific qualification standards needed for individuals who direct or carry out corrosion control procedures?

Comments: All 23 comments on this concern opposed changing § 192.453. They said either the existing rule is adequate or the proposed rules on personnel qualification are sufficient. Most of these commenters also opposed establishing specific technical qualifications for company managers. They said these personnel need more business than technical knowledge to assure that corrosion and other maintenance problems are handled economically. AGA/APGA suggested that any remaining qualification issues be addressed in a non-regulatory way through ongoing discussions with industry training representatives at DOT's Transportation Safety Institute.

RSPA Concern: Should a cathodic protection system be installed on offshore pipelines in less than one year after the pipeline is constructed, for example, 60 days, because of the strong corrosiveness of salt water?

Comments: The two comments on this concern favored a 60-day installation period.

RSPA Concern: Is it in the interest of safety to exempt pipelines in particular environments and temporary pipelines from the coating and cathodic protection requirements?

Comments: Three commenters opposed the present exemptions, either because corrosion leaks can happen rapidly or because the installations are so varied they should be handled by waivers rather than general exemption. At the same time, three commenters supported the exemptions, contending that corrosion is usually a long term problem, many environments are not conducive to corrosion, and required monitoring would detect incipient problems. AGA/APGA said that safety data do not suggest the present exemptions have been detrimental to safety.

RSPA Concern: Should existing compressor, regulator, and measuring station piping continue to be excluded from the requirement to cathodically protect effectively coated transmission line pipe?

Comments: Five commenters said the piping should not be excluded, arguing that it does not differ from pipe that must be protected and that failures at these locations may have serious consequences. Three other commenters said they cathodically protect all their compressor, regulator, and measuring station piping.

RSPA Concern: Is the present requirement to cathodically protect certain older existing pipelines only in areas of “active corrosion” adequate for public safety? If not, what would be a cost-effective alternative standard?

Comments: Only one commenter opposed the present rule. This commenter contended that the entire pipeline needs protection because spot protection moves the corrosion problem to other places on the line. However, 13 commenters, including AGA/APGA, supported the present rule, saying that it is a cost-effective approach to protecting older lines, particularly since not all corrosion is detrimental to safety. Another commenter thought that adding cathodic protection to old bare lines in mildly corrosive or non-corrosive soils could accelerate the rate of any localized corrosion that might exist.

RSPA Concern: Is the meaning of “active corrosion” clear and technically sound? If not, how should it be changed?

Comments: None of the 12 comments advocated changing the present definition of “active corrosion.” Five commenters, including AGA/APGA, thought that possible changes would be more prescriptive, less flexible, or not appropriate for all areas.

RSPA Concern: Should the implicit requirement to coat field joints and repairs be expressly stated?

Comments: Four commenters said this requirement should be expressly stated. But four other commenters worried that singling out any item would raise questions about items not listed. Similarly, another commenter thought the implicit requirement was adequate for field joints.

RSPA Concern: Does coating need to be compatible with the anticipated service conditions, including the effects of temperature?

Comments: Four commenters agreed that such service compatibility is necessary. And one of these commenters suggested that a performance standard would improve the effectiveness of the existing rule in this regard. However, another commenter said the existing rule is adequate because service compatibility is implied.

RSPA Concern: For offshore pipelines, during installation, are special measures necessary to protect against damage to coating, including field joint coating; and, to avoid mechanical damage, are special coatings needed on J-tubes, I-tubes and pipelines installed by the bottom tow method?

Comments: There were no comments on this concern.

RSPA Concern: Are the cathodic protection system criteria in appendix D of part 192, 300 mV shift and E-log-I, obsolete, since they are not in section 6 of NACE Standard RP0169-96? If so, should operators be allowed to continue to use them on existing pipe, but not new pipe?

Comments: Three commenters favored dropping these two criteria or at least E-log-I from appendix D. Six other commenters said they would support dropping the criteria only if the criteria were known to be ineffective or no longer in use. One commenter acknowledged using E-log-I and two others said the two criteria are adequate and should be allowed. AGA/APGA and one other commenter said the NACE standard recognizes the use of other successful criteria, such as those in appendix D, and that safety data do not show that the 300 mV shift and E-log-I criteria result in higher leak rates or incidents.

RSPA Concern: Does the sampling basis prescribed for inspecting short sections of mains or transmission lines not in excess of 100 feet and separately protected service lines provide effective corrosion control, particularly as it applies to service lines that supply gas to public buildings?

Comments: Two commenters thought the present rule is ineffective, asserting that a single inspection is not enough to assess safety over a 10-year period, no matter if public buildings are involved. However, four commenters argued that because corrosion is slow, there has been no problem in sampling pipe to detect corrosion before it becomes critical. And two commenters said sampling is a cost-effective way to monitor scattered sites. AGA/APGA and two other commenters said that safety data do not show that sampled pipe has more corrosion-caused leaks than other pipe. Several commenters foresaw difficulties in defining a “public building.” Only one commenter thought that more frequent monitoring is needed for lines leading to public buildings because of the increased potential for serious consequences.

RSPA Concern: What remedial action is needed when an electrical short in a casing results in inadequate cathodic protection of the pipeline outside the casing?

Comments: Five commenters said these shorts should be cleared because other options are ineffective and imposing more current to offset the short could have adverse effects. But two other commenters said that clearing shorts can be costly if the line must be taken out of service or replaced, and that there is no consensus on adequate remediation. Another observation by one commenter was that the electrical isolation requirements are not needed since cathodic protection has to meet the criteria for adequacy.

RSPA Concern: Should newly constructed offshore pipelines be electrically isolated from bare steel platforms unless both are protected as a single unit?

Comments: The lone commenter who addressed this concern said that isolation is needed, yet concluded that a rule change was not needed because annual surveys will identify any problem.

RSPA Concern: Is electrical isolation needed where contact with aboveground structures would adversely affect cathodic protection?

Comments: One commenter said we should require isolation in all such cases. Three commenters argued that while isolation is needed a rule change is not, because annual surveys will identify any problem. Three other commenters argued that isolation is not needed if the alternative of sufficient local protection is applied.

RSPA Concern: Are accessible test leads needed on offshore risers that are electrically isolated and not accessible for testing?

Comments: The two commenters who addressed this concern said the present rule is adequate because operators must demonstrate adequate cathodic protection, which necessitates test leads.

RSPA Concern: For aluminum pipelines, should all test leads be insulated aluminum conductors and installed to avoid harm to the pipe?

Comments: There were two comments on this concern. One said test leads and connection material must be compatible with aluminum. The other said test leads must be insulated aluminum conductors and installed to avoid harm to the pipe.

RSPA Concern: Where light rail systems exist, should operators specifically be required to identify and test for stray currents and keep records of the test results?

Comments: Four commenters said such a specific requirement was needed for light rail. But three commenters disagreed, arguing the present rule is adequate because it requires operators to test for all sources of stray current, including large junk yard magnets and electric cranes.

RSPA Concern: Are special requirements needed to deal with the problem of internal corrosion in storage field piping, as evidenced by piping leaks in West Virginia and several Midwestern states?

Comments: Three commenters felt the present rule is adequate for all situations and specific requirements for storage fields are not needed. In contrast, one commenter thought the rule should specifically recognize the problems posed by such piping and require more coupons or traps where liquid might collect, pipe design that avoids liquid collection, use of lined pipe, periodic pigging, or dehydration. Another commenter thought operators should have to prepare a procedure and follow it to minimize internal corrosion.

RSPA Concern: Should new and existing pipelines be subject to the same protection requirements?

Comments: One commenter saw no need to change the distinction between new and existing pipelines. 3 Six others supported treating all aboveground pipelines alike regardless of age, but two of these commenters said the rule should apply only to “active corrosion,” not to all corrosion.

RSPA Concern: Is protection needed where corrosion is a light surface oxide or where corrosion will not likely affect the safe operation of the pipeline before the next scheduled inspection?

Comments: Six commenters thought the rule should be changed to exclude surface oxide because it does not affect pipe integrity. However, one commenter thought surface oxide indicates a coating problem that operators should identify and track through continuing surveillance. One other commenter said that even if corrosion is more than superficial, if there is no question of safety before the next inspection, then there is no present need for remedial action. Another commenter recommended limiting the rule to “active corrosion” to exclude both superficial corrosion and corrosion that would not likely advance to an unacceptable stage before the next inspection.

RSPA Concern: Is special protection needed in the splash zone of offshore pipelines and at soil to air interfaces of onshore pipelines?

Comments: Three of the four comments on this concern thought the existing corrosion rules for buried and aboveground protection are adequate. The fourth commenter said any need for special protection would be recognized during required inspections.

RSPA Concern: Should the inspection interval for onshore pipelines be extended beyond 3 years in view of the generally low incidence of serious problems on protected pipelines?

Comments: Two commenters said the present 3-year monitoring cycle is not too burdensome. In contrast, seven commenters recommended extending the inspection period beyond 3 years, saying that atmospheric corrosion is a long-term process. Six of these commenters recommended inspection every 5 years, an interval coincident with the interval of gas leakage surveys. One other commenter suggested the rule let operators determine what inspection intervals are appropriate for the pipelines involved.

RSPA Concern: For onshore pipelines, are more frequent inspections needed at soil-to-air interfaces, under thermal insulation, at disbonded coatings, and at pipe supports?

Comments: The consensus of the four comments on this concern was that no more frequent inspections than annual are needed at these locations. Two commenters said the corrosion problem at these locations is too site-specific for a general inspection rule requiring removal of coating or jackets.

RSPA Concern: For offshore pipelines, are more frequent inspections needed under poorly bonded coatings and at splash zones, support clamps, and deck penetrations?

Comments: There were no comments on this concern.

RSPA Concern: Should operators keep records of findings of non-corrosive conditions if

Comments: Two commenters agreed that if records of non-corrosive conditions no longer have a purpose, the recordkeeping requirement should be removed. But another commenter thought records of exposed pipe inspections under § 192.459 should be kept even if no corrosion is found. This commenter thought such records would be useful in surveillance under § 192.613 and in evaluating the significance of damaged pipe or coating.

RSPA Concern: Is the period for keeping corrosion control monitoring records, “as long as the pipeline remains in service,” necessary for safety or accident investigation? If not, what is an appropriate period?

Comments: One commenter believed the present retention period is needed to provide a very helpful general history of pipelines. But another commenter said that old records are never used once adverse conditions are corrected. Two commenters suggested the retention period could be reduced to 5 years or two inspection cycles, whichever is longer. A similar comment was 5 years or the next inspection cycle, whichever is longer.

Recommendation: With regard to §§ 192.457 and 192.465, NAPSR recommended changes to clarify the meaning of an “electrical survey” and where alternatives to electrical surveys may be used.

Comments: Three commenters reported that the State-Industry Regulatory Review Committee (SIRRC) had reached a consensus on “electrical survey” and alternatives. SIRRC was formed by NAPSR and industry representatives to work out differences of opinion over NAPSR's 1992 recommendations to revise part 192. 4 In a report transmitted to RSPA by a letter dated May 3, 1999, SIRRC concludes that electrical surveys are seldom used on distribution systems, so there is no advantage to requiring electrical surveys as a preferred corrosion inspection method on distribution systems. SIRRC further concludes that if electrical surveys are not used, all available information should be used to determine if active corrosion exists. Set out below are SIRRC's suggested revisions of § 192.457(b)(3) and § 192.465(e). SIRRC also said that in the suggested revision, “pipeline environment” refers to whether soil resistivity is high or low, wet or dry, contains contaminants that may promote corrosion, or has any other known condition that might influence the probability of active corrosion.

Recommendation: With regard to § 192.459, NAPSR recommended we require operators to record the condition of protective coatings whenever they inspect exposed portions of buried pipeline, arguing the records would provide a useful history of the condition of the pipelines as well as evidence that exposed pipe had been inspected as required.

Comments: Three commenters reported that SIRRC reached a consensus on recording the condition of coating when inspecting exposed pipe. SIRRC said that coating condition is important in evaluating the overall condition of a pipeline, and that this information helps meet continuing surveillance and active corrosion rules. SIRRC's suggested revision of § 192.459 follows:

Recommendation: With regard to § 192.467(d), NAPSR recommended changes that would require operators to test pipeline casings annually for electrical isolation, and to clarify what must be done to minimize pipeline corrosion if isolation is not achieved.

Comments: Three commenters reported that SIRRC did not agree on whether shorted casings are a problem or on the need to test casings, but agreed that § 192.483 should be amended to include options for dealing with shorted casings. SIRRC said its suggested options are consistent with common industry practice. SIRRC also recognized that the options were not intended as a substitute for proper cathodic protection of pipe under § 192.463. SIRRC's suggested revision of § 192.483 follows:

Recommendation: With regard to § 192.479(b), NAPSR recommended that regardless of the date of installation, all aboveground pipelines or portions of a pipeline that are exposed to the atmosphere be cleaned and either coated or jacketed with a material suitable for the prevention of atmospheric corrosion, unless the pipeline is in a non-corrosive atmosphere.

Comments: Two commenters reported that SIRRC reached a consensus that all aboveground pipe should be subject to the same protection requirement. SIRRC's suggested revision of § 192.479, which would remove the present distinction between pipelines installed before and after particular dates, is set forth below. SIRRC also explained that the term “active corrosion” does not include non-damaging corrosive films.

Recommendation: With regard to the provision in § 192.487(a) that permits general corrosion in distribution line pipe to be repaired instead of replaced, NAPSR recommended that the provision refer to generally accepted guidelines for determining what corroded areas may be repaired.

Comments: Two commenters reported that SIRRC did not address this issue. In addition, these commenters suggested we allow operators to assess the serviceability of distribution line pipe that has wall thickness less than 30 percent of nominal wall thickness instead of requiring the replacement of such pipe.

Recommendation: With regard to § 192.489(b), NAPSR recommended that we clarify that internal sealing is not an appropriate method of strengthening graphitized pipe.

Comments: Two commenters reported that SIRRC agreed to drop this recommendation, since advances in technology may produce strength enhancing liners.

The following recommendations are from an April 1995, rulemaking petition by GPTC:

Recommendation: Remove from § 192.467 the requirement that pipe be electrically isolated from metallic casings. GPTC argued there are no safety benefits from clearing shorted casings.

Comments: There were no comments on this recommendation. But see the comments above on § 192.467.

Recommendation: Amend §§ 192.465 and 192.481 to allow operators to take up to 39 months to carry out inspections of unprotected pipelines that must be done at 3-year intervals. GPTC said the extra time would add flexibility to the standards, with no reduction in safety.

Comments: The one comment on this recommendation supported the 39-month period but preferred a 5-year interval to match the interval of leakage surveys. Also, see the comments above on §§ 192.465 and 192.481.

As a result of a 1996 accident on a butane pipeline operated by Koch Pipeline Company near Lively, Texas, NTSB recommended two changes to the Part 195 corrosion control standards:

Recommendation: Revise Part 195 to require pipeline operators to determine the condition of pipeline coating whenever pipe is exposed and, if degradation is found, to evaluate the coating condition of the pipeline. (P-98-35)

Comments: There were no comments on this recommendation. But see the SIRRC comment above on § 192.459.

Recommendation: Revise Part 195 to include performance measures for the adequate cathodic protection of liquid pipelines. (P-98-36)

Comment: The only comment favored adding to Part 195 either Appendix D or NACE cathodic protection criteria.

In the San Antonio meeting notice, we suggested two alternatives to the present corrosion control standards: corrosion management plans and NACE Standard RP0169-96. Many operators get excellent results by applying pipeline-specific plans that contain corrosion control methods and management techniques not required by Part 192 or Part 195 standards. NACE Standard RP0169-96 is widely accepted as the most authoritative source of up-to-date pipeline corrosion control practices.

Comments: Two commenters favored corrosion management plans, saying they would be consistent with the risk-based approach to regulation and cost-effective, since many operators already use them. They also said that to qualify a pipeline for exemption from the standards, the plans should be designed to produce equal or better results than the standards. However, another commenter opposed the plan alternative, arguing that the review and evaluation process would further dilute government and industry resources and detract from higher priority safety matters. And the American Petroleum Institute opposed the plan alternative, saying that corrosion should be treated as part of an overall integrity management plan that may be developed after the conclusion of RSPA's risk management demonstration projects.

Topics 4 and 6 under the next heading drew additional comments on the alternatives.

1. Whether any existing standards deter or disallow the use of new technologies, and, if so, how.

Comments: The two comments on this topic were that while none of the standards disallows the use of new technology, unclear standards may deter such use.

2. The costs and benefits of any suggested changes to standards and alternatives to standards.

Comments: The only comment was that we should apply cost/benefit analysis to any suggested changes.

3. The amount of time operators may need to prepare for compliance with any suggested standards or alternatives.

Comments: The only comment was that the time needed for compliance depends on the suggested rule change.

4. With regard to the corrosion management plan and NACE Standard alternatives—

a. The bases for evaluating the adequacy of corrosion management plans.

Comments: Two commenters said the primary basis should be whether corrosion is mitigated by the plan. AGA/APGA and another commenter suggested we defer further consideration of the plan alternative until completion of work by the State/Industry/DOT Regulatory Alternative Feasibility Team, which is considering risk-based alternatives to safety standards.

b. The best way to facilitate agency review of operator decisions under the alternatives ( e.g. , prior notification, reporting, recordkeeping).

Comments: Both comments on this topic were that we should review the decisions the same as we review decisions in operators' operating and maintenance plans.

c. Whether NACE Standard RP0169-96 is adequate for pipeline corrosion control and, if so, should we incorporate it by reference in our corrosion control standards?

Comments: Only one commenter thought NACE Standard RP0169-96 would be a cost-effective alternative to existing corrosion control standards. Although another commenter said it would be all right to reference NACE Standard RP0169-96, the commenter also said it would be better to use it as a basis for changing the standards. Ten other commenters opposed using NACE Standard RP0169-96. Of these, two said the document is not adequate by itself, and it would complicate the standards if only parts were referenced. AGA/APGA and two other commenters said NACE Standard RP0169-96 is too conservative and too costly to apply, but AGA/APGA and another two commenters thought it could serve as guidance for corrosion management plans. The reason given by one commenter for opposing NACE Standard RP0169-96 was that it does not distinguish non-hazardous corrosion from corrosion detrimental to public safety.

5. For hazardous liquid pipelines—

a. Whether additional standards are needed to further reduce the possibility of damage to environmentally sensitive areas.

Comments: One commenter thought Part 195 should cross reference Appendix D or NACE RP0169 criteria for cathodic protection.

b. If Part 192 standards were applied to hazardous liquid pipelines, the changes, if any, that would be needed to account for differences between gas and liquid pipelines.

Comments: There were no comments on this topic.

6. For gas distribution systems—

a. Root causes of corrosion leaks on coated, uncoated, protected, and unprotected metallic lines.

Comments: AGA/APGA and one other commenter said that corrosion leaks on distribution lines have a low probability of resulting in reportable incidents. Three additional commenters said that corrosion leaks on properly protected pipe are rare, and that most corrosion leaks occur on unprotected bare steel that is too costly to protect. These commenters contended the best approach to combating corrosion leaks is through aggressive leak surveys.

b. Descriptions of operating/maintenance practices to minimize corrosion leaks on cathodically unprotected lines.

Comments: Six commenters reported the use of a ranking system to prioritize segments of bare steel pipe for replacement, based on age, location, leaks, size, and cathodic protection. Other practices included replacement rather than repair of bare steel, and not uprating or reconnecting cast iron, ductile iron, or bare steel pipe. Another commenter said its practices are designed to enhance economic value rather than just meet Part 192 requirements.

c. Descriptions of risk-based corrosion management programs.

Comments: The only commenter said a plan should preserve the intent of the code but allow for geography and operating condition differences.

d. The best approach to monitoring corrosion control in urban wall-to-wall paved areas.

Comments: One commenter suggested taking readings at test stations no further than one block (660 feet) apart, while another advised 1200 feet apart. Still another commenter stressed the importance of creating access openings.

7. The amount of buried piping at compressor, regulator, and measuring stations that is not cathodically protected.

Comments: Three commenters said all their piping in these locations is protected. AGA/APGA said the data are not available, but the piping poses a low risk.

8. Explicit examples of adequate compliance with particular standards that have had varied interpretations.

Comments: AGA/APGA reported that while government compliance personnel interpret some standards inconsistently, the safety statistics support adequate compliance.

9. To provide an acceptable level of safety on existing pipelines, must cathodic protection preserve the pipeline indefinitely or merely slow the rate of corrosion until the pipeline has to be rehabilitated or replaced?

Comments: Two commenters said the decision should be based on a cost/benefit assessment, considering the possible use of new materials and the future need to move or replace a pipeline due to construction by others. One other comment was that corrosion can only be mitigated and to try to do otherwise would be too expensive.

In view of the above concerns, recommendations, and comments, we are proposing to add to part 195 a new subpart H called Corrosion Control. Subpart H would prescribe corrosion control standards for new and existing steel pipelines to which Part 195 applies. Concerns, recommendations, and comments that pertain primarily to the corrosion control standards in Part 192 will be addressed in a future rulemaking proceeding on gas pipelines.

Because commenters showed little enthusiasm for the alternatives of NACE Standard RP0169-96 and corrosion management plans, we did not include either alternative in proposed Subpart H (except as provided in proposed § 195.567 regarding cathodic protection criteria). Nevertheless, because NACE Standard RP0169-96 is so widely respected, we would like to keep the floor open for further discussion of the merits of adopting it as an overall corrosion control standard for pipelines. In this regard, we invite interested persons to comment again on the pros and cons of referencing the entire NACE Standard RP0169-96 as an alternative to proposed Subpart H. This request for comment is not a rulemaking proposal. We recognize that a further notice of proposed rulemaking would be required before the entire NACE Standard RP0169-96 could be incorporated by reference as a Part 195 safety standard.

Proposed Subpart H includes many standards that are identical to present corrosion control requirements in Part 195 and standards that are substantially like present requirements in Part 192. The proposed subpart also includes standards that, while based on present Part 192 requirements, include changes we think are beneficial improvements, considering acceptable safety practices. We do not intend that proposed subpart H results in a lessening of current requirements. Each of the sections in proposed Subpart H is discussed below.

Proposed § 195.551 characterizes the activities that are covered by the proposed standards in subpart H (i.e., protecting steel pipelines against external, internal, and atmospheric corrosion). Section 195.551 is informational in nature and would not impose any obligations.

Like the present corrosion control standards in part 195 (§§ 195.236, 195.238, 195.242, 195.244, 195.414, 195.416, and 195.418), proposed Subpart H would apply only to steel pipelines. In contrast, comparable corrosion control standards for gas pipelines (subpart I of Part 192) apply to pipelines made of any metal. However, because hazardous liquid and carbon dioxide pipelines are made of steel almost exclusively, such broad coverage is not warranted for pipelines regulated by part 195.

Nevertheless, under § 195.8, operators must give us an opportunity to review the safety of any pipeline that is to be constructed with a material other than steel. In the case of a non-steel metallic pipeline, that review would include the operator's plans for corrosion control.

You should note that “breakout tanks”  5 come within the scope of proposed subpart H, because part 195 defines “pipeline” to include breakout tanks (§ 195.2). Consistent with the convention stated in § 195.1(c), proposed subpart H standards applicable to breakout tanks include standards that concern breakout tanks specifically and, to the extent applicable, standards that concern pipeline systems, or pipelines, generally. Proposed standards that concern only pipe, such as §§ 195.583 and 195.585, do not apply to breakout tanks because these standards do not affect parts of pipelines other than pipe.

The new personnel qualification standards in subpart G of part 195 (64 FR 46866; Aug. 27, 1999) apply to individuals who perform covered tasks on pipelines, including regulated corrosion control activities. However, supervision of covered tasks is not, itself, a covered task. So supervision of corrosion control activities does not come under Subpart G.

We know that prevention of corrosion-caused accidents does not depend solely on how well personnel perform covered tasks on pipelines. Prevention also depends on the correctness of critical decisions that flow from those tasks. Indeed, many Part 195 corrosion control standards require operators not only to perform tasks on pipelines, but to decide if corrective action is needed as a result of the tasks. For example, under § 195.416(d), operators must periodically inspect bare pipe and then determine if cathodic protection is needed.

Individuals assigned to perform covered corrosion control tasks on pipelines, such as collecting pipe-to-soil data, may be qualified under subpart G without knowing what corrective action, if any, should be taken as a result of the tasks. Generally these critical corrosion control decisions are made by supervisory personnel who are in charge of carrying out the corrosion control procedures under § 195.402(c). It is reasonable, we think, that individuals who direct others to carry out corrosion control procedures should have sufficient knowledge of the procedures so they understand what they are directing.

At present, § 195.403(c) regulates the qualifications of individuals assigned to supervise the performance of corrosion control procedures. This rule requires each operator to “require and verify that its supervisors maintain a thorough knowledge of that portion of the procedures established under § 195.402 for which they are responsible to insure compliance.” However, § 195.403(c) has been changed. On October 28, 2002, this rule will apply only to supervisors of emergency response procedures (64 FR 46866). Consequently, we are proposing, under § 195.553, to preserve the substance of § 195.403(c) as it now applies to supervisors of corrosion control procedures.

Proposed § 195.555 designates the pipelines covered by proposed §§ 195.557, 195.559, and 195.561. As stated below, these three proposed standards are identical to the present corrosion control standards in §§ 195.238, 195.242, and 195.244 governing coating, cathodic protection, and test leads. Like the standards they would replace, the proposed standards would apply only to pipelines constructed, relocated, replaced, or otherwise changed after §§ 195.238, 195.242, and 195.244 went into effect and to certain converted pipelines (see § 195.5(b)). The effective dates of §§ 195.238, 195.242, and 195.244 are given in § 195.401(c) and vary by pipeline. Proposed § 195.555 cross-references §§ 195.401(c) and 195.5(b).

One other existing corrosion control standard, § 195.236, applies to the same pipelines as §§ 195.238, 195.242, and 195.244. But this standard, which requires protection against external corrosion, is written in terms that may be too general. We think the standard adds nothing substantive to the more specific requirements for external corrosion protection in §§ 195.238 and 195.242. So we are proposing to drop § 195.236 and not include it in proposed subpart H.

Proposed § 195.557 is identical to § 195.238, which prescribes standards for external coating on certain buried or submerged pipeline components.

Proposed § 195.559 is identical to § 195.242, which requires certain buried or submerged facilities to be cathodically protected.

Proposed § 195.561 is substantially the same as § 195.244, which prescribes standards for the installation of test leads to measure cathodic protection on certain onshore pipelines. However, we are also proposing that at the connection to the pipeline, each bared test lead wire and bared metallic area must be coated with an electrical insulating material compatible with the pipe coating and the insulation on the wire. This provision is now in effect for gas pipelines under § 192.471(c).

Proposed § 195.563 is comparable to § 195.414(a), which requires all effectively coated pipelines to be cathodically protected, except for piping in breakout tank areas and pump stations. To avoid any duplication of proposed § 195.559, proposed § 195.563 would apply only to pipelines that are not protected under proposed § 195.559. Also, we omitted the compliance dates in § 195.414(a) from proposed § 195.563 because the dates have passed.

Proposed § 195.565 is comparable to existing § 195.416(e), which requires operators to investigate the extent of active corrosion found on exposed pipelines. We recently revised a parallel standard, § 192.459, to clarify the means and bounds of corrosion investigations on exposed gas pipelines (64 FR 56978; Oct. 22, 1999). In view of this rule change, we used § 192.459 as a model for proposed § 195.565 to provide the same clarity for similar investigations required on hazardous liquid and carbon dioxide pipelines. We believe this proposal and the associated recordkeeping under proposed § 195.587 are consistent with SIRRC's suggested changes to § 192.459 quoted above in the discussion of NAPSR's § 192.459 recommendation. Under proposed § 195.565, operators may use indirect methods, including electrical surveys or smart pigs, besides excavation and observation to look for corrosion in the vicinity of an exposed portion of pipeline.

During the course of looking for corrosion on an exposed pipeline, operators observe the condition of protective coating on the pipeline. Proposed § 195.565 would codify this inherent step by requiring operators to first see if the coating is deteriorated before they examine the exposed pipeline for corrosion. Operators' records of inspections preserve information about examinations of exposed pipe for future use, such as assessing the condition of the pipeline for purposes of corrosion control. We think the combination of proposed § 195.565 and records of examinations of exposed pipe would provide an adequate response to NTSB recommendation P-98-35 that part 195 require operators to determine the condition of external coating on exposed pipelines. Proposed § 195.587 (see below) would require operators to keep records of examinations of exposed pipe for as long as the pipe remains in service rather than 2 years as now required by § 195.404(c)(3).

NTSB has recommended that Part 195 include performance measures for the adequacy of cathodic protection (recommendation P-98-36). We support NTSB's recommendation. Consequently, we are proposing, in § 195.567, that cathodic protection comply with the criteria and other considerations in section 6 of NACE Standard RP0169-96.

In developing this proposal, we considered that in our experience operators universally apply either NACE criteria or criteria in appendix D of part 192 to determine the adequacy of cathodic protection on pipelines that come under part 195. Similarly, the comments we received on performance measures for cathodic protection were divided between the NACE criteria and the appendix D criteria. And in its April 1995 report of a review of the part 195 standards, NAPSR supported either set of criteria.

While NACE and Appendix D criteria overlap in many respects, two Appendix D criteria (300 mV shift and E-log-I) are not among the NACE criteria. We believe they were omitted because they are outmoded and lack technical validation; and the comments did not dissuade us of this concern. Given our uncertainty about appendix D, we felt compelled to limit our proposal to section 6 of NACE Standard RP0169-96.

Still it is important to recognize that under proposed § 195.567 operators would not have to use only criteria included in section 6 of NACE Standard RP0169-96. Paragraph 6.2.1 of NACE Standard RP0169-96 permits operators to use any criteria that achieves corrosion control comparable to that attained with criteria included in section 6. In addition, paragraph 6.2.1 permits operators to continue to use on existing pipelines criteria that have been successfully applied to those pipelines. Thus proposed § 195.567 would not deny operators the opportunity to use appendix D criteria that are not included in section 6 of NACE Standard RP0169-96 as long as the operators can meet the tests of comparability or successful application stated in paragraph 6.2.1 for the use of alternative criteria. Although section 6 of NACE Standard RP0169-96 does not provide measures of comparability or successful application, to comply with paragraph 6.2.1, we believe there would have to be an absence of corrosion leaks on the pipeline between cathodic protection inspections. And, if the integrity of the pipeline has been checked between cathodic protection inspections by an internal inspection device, pressure testing, or direct examination, there would have to be no signs of metal loss due to corrosion.

On the issue of correct application of the negative (cathodic) 0.85 volt criterion, we find no difference between the NACE and appendix D criteria. Both require that voltage drops other than those across the structure-to-electrolyte boundary must be “considered” for valid interpretation of measurements taken for the negative (cathodic) 0.85 volt criterion. NACE explains that consideration means the application of sound engineering practice in determining the significance of voltage drops by methods such as measuring or calculating the voltage drop, reviewing the historical performance of the cathodic protection system, evaluating the physical and electrical characteristics of the pipe and its environment, and determining whether or not there is physical evidence of corrosion.

Proposed § 195.569(a) is substantially the same as § 195.416(a), which requires annual tests of the adequacy of cathodic protection. The only difference is that proposed § 195.569(a) references proposed § 195.567 as the measure of adequacy. Proposed § 195.569(b) is identical to § 195.416(c), which requires bimonthly inspections of cathodic protection rectifiers. Although proposed § 195.569(d) has no parallel in part 195, it is comparable to § 192.465(c), which requires periodic inspections of items critical to cathodic protection. We think such inspections are common practice on pipelines subject to part 195. Proposed § 195.569(e) is identical to § 195.416(j), which requires inspections of systems used to protect the bottoms of aboveground breakout tanks.

Proposed § 195.569(c) is comparable to existing § 195.416(d), which requires electrical inspection of unprotected “bare pipe”  6 at least every 5 years to determine if protection is needed. However, like § 192.465(e), proposed § 195.569(c) would clarify that the purpose of the inspections is to detect “active corrosion” and would allow operators to use alternative means of determining active corrosion where an electrical survey is impractical. The term “active corrosion” would be defined essentially as it is in § 192.457(c), but with the additional consideration of risk to the environment. Moreover, as SIRRC recommended for gas pipelines under § 192.465(e) (see above), the alternative means of determining active corrosion would have to include an analysis and review of the pipeline's condition, based on leak repair history, exposed pipe inspection records, and the pipeline environment. In accordance with SIRRC's recommendation, we also included definitions of “electrical survey” and “pipeline environment” in proposed § 195.569(c).

Another difference between proposed §§ 195.569(c) and 195.416(d) is that, like § 192.465(e), proposed § 195.569(c) would require inspections of all unprotected pipelines, not just unprotected bare pipe. The impact of this change would be on unprotected buried piping in breakout tank areas and pump stations. At present, part 195 does not have a periodic inspection requirement for corrosion on unprotected piping in breakout tank areas and pump stations.  7 Only minor costs should result from this change in coverage, for we believe that periodic inspection of unprotected piping in breakout tank areas and pump stations is a common industry practice. The requirements for initial electrical inspection of bare pipelines (§ 195.414 (b)) and of piping in breakout tank areas and pump stations (§ 195.414(c)) have not been included in proposed Subpart H because the periods allowed for compliance have expired.

We have not proposed to increase the minimum frequency of inspections from every 5 years to every 3 years, which is the minimum frequency required by § 192.465(e) for inspecting unprotected gas pipelines. Our safety data do not show that increasing the minimum frequency to every 3 years would be likely to result in fewer reported corrosion-caused accidents on hazardous liquid or carbon dioxide pipelines. Moreover, the ASME B31.4 Code, a set of voluntary safety standards widely followed by operators of pipelines subject to part 195, specifies a minimum frequency of every 5 years for inspecting unprotected pipelines. While NACE Standard RP0169-96 requires periodic inspections to determine the need to protect unprotected pipelines, it does not prescribe the frequency of those inspections.

We also considered the need to propose a standard comparable to § 192.465(d), which requires gas pipeline operators to take “prompt” remedial action to correct any deficiencies detected by monitoring external corrosion control. But we decided such a proposal is unnecessary because § 195.401(b) requires operators to correct within a reasonable time any condition that could adversely affect safe operation, and if an immediate hazard exists, to cease operating the affected facility until the condition is corrected. Also, § 195.401(b) regulates the timing of corrective responses to any unsafe corrosion control deficiency, not just deficiencies in external corrosion control.

Proposed § 195.571 is comparable to § 192.467, which requires electrical isolation on gas pipelines to provide for adequate cathodic protection and safeguards for insulating devices. Such isolation is also a common practice on pipelines subject to part 195. However, we are not proposing to include the requirements of § 192.467(c) concerning isolation of pipelines from metallic casings. We agree with GPTC and commenters who believe the safety need to clear shorted casings is not apparent. Therefore, we have not included in proposed Subpart H SIRRC's recommended measures to remedy shorted casings.

Proposed § 195.573 is identical to § 195.416(b), which requires maintenance of test leads to provide for monitoring the adequacy of cathodic protection.

Proposed § 195.575 is comparable to § 192.473, which requires operators to minimize the detrimental effects of interference currents on gas pipelines and adjacent structures. Although at present there are no standards in part 195 concerning interference problems, we believe that most operators already have a testing program to minimize interference problems. Proposed § 195.575 has minor editorial differences from the wording of § 192.473.

Proposed § 195.577 is comparable to § 195.418, which requires protective measures to mitigate the effects of internal corrosion. However, proposed § 195.577(d) differs somewhat from § 195.418(d), which requires operators to investigate the extent of general corrosion found inside pipe that is removed from a pipeline. Proposed § 195.577(d) would clarify the required investigation by adopting wording similar to that of proposed § 195.565, which concerns the extent of external corrosion on exposed pipe. Also, under proposed § 195.577(d), an investigation would be required if the removed pipe is corroded to the extent that it must be remedied under proposed § 195.583, rather than if the pipe is generally corroded such that the wall thickness is less than that required by the pipe's specification tolerances, as § 195.418(d) now requires. This change would allow operators to take full advantage of criteria for determining the strength of corroded pipe (see proposed § 195.585). The change would also require consideration of the effect of corrosion pitting as well as general corrosion, consistent with the parallel requirement for gas pipelines in § 192.475(b).

Another difference between the proposed and existing standards is that proposed § 195.577(d) drops the remedial measures § 195.418(d) prescribes for corroded pipe. Remedial measures for corroded pipe would be governed by proposed § 195.583. This change would improve the present rule by basing the need for remediation on the strength of corroded pipe and by allowing the use of qualified repair methods that are not allowed under § 195.418(d).

Proposed § 195.579 is comparable to § 195.416(i), which requires that all pipelines exposed to the atmosphere must be protected against atmospheric corrosion by a suitable coating. The comments indicate § 195.416(i) may be overly burdensome, because it does not give operators leeway to avoid coating pipelines that have only a harmless light surface oxide or other mild form of corrosion that is unlikely to harm the pipeline before the next scheduled inspection. So proposed § 195.579 includes an exception for these circumstances. The test, investigation, or experience used to justify an exception must be appropriate to the environment of the particular pipeline facility. In addition, this exception would not apply to splash zones of offshore pipelines or to soil-to-air interfaces of onshore pipelines.

We did not adopt SIRRC's recommendation regarding comparable § 192.479 (see above) to except all but “active corrosion” from the atmospheric corrosion protection requirement. The intent of the recommendation is to distinguish harmless rust from serious metal loss, but we believe this objective is better accomplished by more descriptive wording.

Proposed § 195.581 is comparable to § 192.481, which requires operators of gas pipelines to reevaluate the adequacy of atmospheric corrosion protection at least every 3 years on onshore pipelines and at least every year on offshore pipelines. Although § 195.416(i) requires maintenance of protection on hazardous liquid and carbon dioxide pipelines, this standard may be too general because it lacks minimum inspection frequencies.

In deciding what inspection frequency is most appropriate for onshore pipelines, we considered the majority of comments on § 192.481 that favored lengthening the minimum inspection frequency from every 3 years to every 5 years. But we gave section 463.3 of the ASME B31.4 Code greater weight. This voluntary code, which is widely followed by operators of pipelines subject to Part 195, specifies a minimum 3-year inspection frequency for atmospheric corrosion protection onshore. We also considered that GPTC, in its recommendation regarding § 192.481, did not suggest extending the minimum 3-year frequency more than a marginal amount to provide flexibility. Also, two commenters said the present 3-year frequency is not too burdensome. There were no comments on the frequency of inspection offshore, and the ASME B31.4 Code does not specify a minimum frequency.

Proposed § 195.581 would require periodic “inspection” rather than “reevaluation” to avoid the possibility that decisions about the adequacy of protection might not be based on current observations. The proposed rule also recognizes the importance of paying special attention during inspections to particular pipeline areas that have historically been sources of corrosion problems, such as splash zones and pipe surfaces underneath thermal insulation. We feel that most operators already inspect aboveground pipelines for corrosion at the proposed frequencies and give careful attention to potential problem areas.

Proposed § 195.583(a) is comparable to § 195.416 (f), which regulates the repair of pipe that has general corrosion.  8 But proposed § 195.583(a) reflects the wording of § 192.485(a), a repair rule similar to § 195.416(f) that bases the need for corrective action on whether the remaining wall thickness supports the maximum allowable operating pressure. At present, § 195.416 (f) bases the need for corrective action on whether the remaining wall thickness is within the pipe specification tolerances. The revised wording would allow operators to take full advantage of criteria for determining the strength of corroded pipe (see proposed § 195.585). Proposed § 195.583(b) is identical to § 195.416(g), which regulates remedial measures for localized corrosion pitting.

Proposed § 195.585 is substantially the same as § 195.416(h), which authorizes the use of widely accepted criteria for determining the remaining strength of corroded pipe.

For hazardous liquid and carbon dioxide pipelines, requirements to keep records related to corrosion control are in § 195.404. Under § 195.404(a), operators must maintain current maps and records that identify and show the location of facilities that are cathodically protected. In addition, § 195.404(c)(3) requires operators to keep records of required inspections and tests for at least 2 years or until the next inspection or test, whichever is longer.

We are proposing to adopt new recordkeeping requirements for hazardous liquid and carbon dioxide pipelines comparable to those for gas pipelines in § 192.491. Under proposed § 195.587(a), operators would have to keep current records or maps of the location of cathodically protected piping (as they must now under § 195.404(a)), of cathodic protection facilities, and of bonded structures. Also, under proposed § 195.587(b), operators would have to keep a record of each analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required by proposed Subpart H in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. Records required by § 195.587(b) would have to be retained for at least 5 years, except that records related to determining the adequacy of, or need for, external or internal corrosion control (records related to proposed §§ 195.565, 195.569(a) and (c), and 195.577(c) and (d)) would have to be kept as long as the pipeline is in service.

The majority of comments on the appropriate period to keep records related to determining if external or internal corrosion control is adequate or needed did not support keeping these records for as long as the pipeline remains in service. Instead they mostly suggested a retention period of 5 years or the next one or two monitoring cycles, whichever is longer. But we agree with the single commenter who said keeping such records for the service life of the pipeline provides a very helpful general history. In our experience, a history of corrosion control monitoring is very useful in assessing the condition of a pipeline. If corrosion problems emerge on a pipeline, its monitoring history is considered in deciding the extent and kind of remedial action needed.

As for other records under proposed § 195.587(b) ( e.g. , records of rectifier inspections under proposed § 195.569(b)), we believe the retention period must be compatible with the normal cycle of routine compliance investigations by government inspection personnel and long enough to provide meaningful history for investigation of an accident or safety problem. A minimum 5-year retention requirement would assure that the records are available during routine inspection visits, and provide a more complete history for analyzing problems.

Proposed § 195.587(a)(2), which is based on § 192.491(a), would require operators to have current records or maps identifying the location of cathodic protection facilities, galvanic anodes, and structures bonded to cathodic protection systems. Such records are not now required by Part 195, and although operators may have them, to minimize the recordkeeping burden, the records would only be required for installations made after the final rule goes into effect.

The record retention times proposed by § 195.587(b) would only apply to records of actions that occur after Subpart H takes effect. The retention times now required by § 195.404(c)(3) would continue to apply to records of corrosion tests and inspections done before Subpart H takes effect.

RSPA does not consider this proposed rulemaking to be a significant regulatory action under Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 4, 1993). Therefore, the Office of Management and Budget (OMB) has not received a copy of this rulemaking to review. RSPA also does not consider this proposed rulemaking to be significant under DOT regulatory policies and procedures (44 FR 11034: February 26, 1979).

We prepared a Draft Regulatory Evaluation of the proposed rules and a copy is in the docket. The evaluation states that the proposed rules are, on the whole, comparable either to existing safety standards currently in part 195 for hazardous liquid pipelines or to existing safety standards in part 192 for gas pipelines. The evaluation also states that the information presented at public meetings and meetings with industry and state representatives strongly suggests that imposing gas pipeline safety standards for corrosion control on hazardous liquid pipelines would not require a significant departure from customary safety practices on liquid pipelines.

An important feature of the proposed rules not found in part 192 or part 195 is the reference to cathodic protection criteria in NACE Standard RP0169-96. The evaluation states that these criteria are well known and widely followed throughout the industry, as indicated by meetings with industry representatives and by the voluntary standards in the ASME B31.4 Code. The evaluation further states that operators who do not now apply the NACE criteria are likely to apply the criteria in appendix D of part 192. The proposed rules would allow use of appendix D criteria under conditions stated in the NACE standard.

The evaluation concludes there should be only minimal additional cost, if any, for operators to comply with the proposed rules. If you disagree with this conclusion, please provide information to the public docket described above.

The proposed rules are consistent with customary practices for corrosion control in the hazardous liquid and carbon dioxide pipeline industry. Therefore, based on the facts available about the anticipated impacts of this proposed rulemaking, I certify, pursuant to section 605 of the Regulatory Flexibility Act (5 U.S.C. 605), that this proposed rulemaking would not have a significant impact on a substantial number of small entities. If you have any information that this conclusion about the impact on small entities is not correct, please provide that information to the public docket described above.

The proposed rules have been analyzed in accordance with the principles and criteria contained in Executive Order 13084, “Consultation and Coordination with Indian Tribal Governments.” Because the proposed rules would not significantly or uniquely affect the communities of the Indian tribal governments and would not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13084 do not apply.

Section 195.587 proposes minor additional information collection requirements. Operators would be required to record the location of certain newly installed protection facilities, and keep the records for as long as the pipeline concerned is in service. In addition, records of inspections, tests, and surveys would have to be kept for as long as the pipeline is in service or for 5 years, depending on the nature of the information recorded. The present minimum retention period for these records is 2 years or the prescribed interval of test or inspection, whichever is longer (up to 5 years in some cases).

However, we believe operators already maintain records of the location of their protection facilities for as long as the pipeline is in service to be able to find the facilities for their own purposes and to carry out existing monitoring requirements in part 195. Also, we believe the burden of retaining inspection, test, and survey records for the longer period proposed would be minimal. These records are largely computerized. Maintaining these records on a floppy disk or computer file represents very minimal costs. So, because the additional paperwork burdens of this proposed rule are likely to be minimal, we believe that submitting an analysis of the burdens to OMB under the Paperwork Reduction Act is unnecessary. If you disagree with this conclusion, please submit your comments to the public docket.

This proposed rulemaking would not impose unfunded mandates under the Unfunded Mandates Reform Act of 1995. It would not result in costs of $100 million or more to either State, local, or tribal governments, in the aggregate, or to the private sector, and would be the least burdensome alternative that achieves the objective of the rule.

We have analyzed the proposed rules for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq. ). Because the proposed rules parallel present requirements or practices, we have preliminarily determined that the proposed rules would not significantly affect the quality of the human environment. An environmental assessment document is available for review in the docket. A final determination on environmental impact will be made after the end of the comment period. If you disagree with our preliminary conclusion, please submit your comments to the docket as described above.

We do not want to impose new requirements that would mandate business process changes when the resources necessary to implement those requirements would otherwise be applied to “Y2K” or related computer problems. The proposed rules would not mandate business process changes or require modifications to computer systems. Because the proposed rules would not affect the ability of organizations to respond to those problems, we are not proposing to delay the effectiveness of the requirements.

The proposed rules have been analyzed in accordance with the principles and criteria contained in Executive Order 13132 (“Federalism”). The proposed rules do not propose any regulation that (1) has substantial direct effects on the States, the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government; (2) imposes substantial direct compliance costs on State and local governments; or (3) preempts state law. Therefore, the consultation and funding requirements of Executive Order 13132 do not apply. Nevertheless, during our review of the existing corrosion control standards, representatives of state pipeline safety agencies gave us advice both in private sessions and in the two public meetings we held. In addition, our pipeline safety advisory committees, which include representatives of state governments, were, on two occasions in 1999, briefed on the corrosion control review project.

In consideration of the foregoing, we propose to amend 49 CFR part 195 as follows: