03-23179. Pipeline Safety: Further Regulatory Review; Gas Pipeline Safety Standards

AGENCY:

Research and Special Programs Administration (RSPA), DOT.

ACTION:

Final rule.

SUMMARY:

The Research and Special Programs Administration's (RSPA) Office of Pipeline Safety (OPS) is changing some of its safety standards for gas pipelines. The changes are based on recommendations by the National Association of Pipeline Safety Representatives (NAPSR) and a review of the recommendations by the State Industry Regulatory Review Committee (SIRRC). RSPA/OPS believes the changes will improve the clarity and effectiveness of the present standards.

DATES:

This Final Rule takes effect October 15, 2003.

FOR FURTHER INFORMATION CONTACT:

L. M. Furrow by phone at 202-366-4559, by fax at 202-366-4566, by mail at U.S. Department of Transportation, 400 Seventh Street, SW., Washington, DC, 20590, or by e-mail at [e-mail].

SUPPLEMENTARY INFORMATION:

Background

NAPSR is a nonprofit association of officials from state agencies that participate with RSPA/OPS in the Federal pipeline safety regulatory program. RSPA/OPS asked NAPSR to review the gas pipeline safety standards in 49 CFR part 192 and recommend any changes needed to make the standards more explicit, understandable, and enforceable. NAPSR compiled the results of its review in a report titled “Report on Recommendations for Revision of 49 CFR part 192,” dated November 20, 1992. The report recommends changes to 40 different sections in part 192.

By the time NAPSR completed its report, RSPA/OPS had published a notice of proposed rulemaking to change many part 192 standards that we considered unclear or too burdensome (Docket PS-124; 57 FR 39572; Aug. 31, 1992). Because a few of NAPSR's recommendations related to standards we had proposed to change, we published the report for comment in the PS-124 proceeding (58 FR 59431; Nov. 9, 1993). The PS-124 Final Rule (61 FR 28770; June 6, 1996) included four of NAPSR's recommended rule changes, and we scheduled the remaining recommendations for future consideration.

Because industry and State views were so divergent on NAPSR's recommendations, in October 1997, the American Gas Association (AGA), the American Public Gas Association (APGA), and NAPSR formed SIRRC to iron out their differences. In a report titled “Summary Report,” dated April 26, 1999, SIRRC agreed on all but eight of NAPSR's recommendations that we had scheduled for future consideration. SIRRC also agreed on a NAPSR resolution concerning definitions of “service line” and “service regulator” that was not among the recommendations in its 1992 report.

Based on our review of NAPSR's recommendations and SIRRC's Summary Report, on November 13, 2002, we published a notice of proposed rulemaking (NPRM) (67 FR 68815). The NPRM invited the public to comment by January 13, 2003, on proposed changes to 21 sections in Part 192. The NPRM also explained why we were not proposing to adopt some of NAPSR's recommendations.

Disposition of Comments

In response to the NPRM, we received written comments from American Gas Association (AGA), Arkansas Public Service Commission (ARPSC), Con Edison (ConEd), Dominion Resources (Dominion), Gas Piping Technology Committee (GPTC), Iowa Utilities Board (Iowa), Metropolitan Utilities District, Michigan Consolidated Gas Company (MichCon), NiSource, Inc. (NiSource), Oleksa and Associates (Oleksa), Peoples Energy (Peoples), Public Service Electric & Gas Company (PSE&G), Southwest Gas Corporation (Southwest), UGI Utilities, Inc. (UGI), and Yankee Gas Services Co. (Yankee). Commenters generally supported the proposed rule changes. However, some commenters opposed particular proposals or suggested alternatives.

This section of the preamble summarizes those latter comments and discusses how RSPA/OPS treated them in developing this Final Rule. This section of the preamble does not address comments that disagree with RSPA's/OPS's decision not to adopt particular NAPSR recommendations or that suggest additional changes to Part 192. If RSPA/OPS has not mentioned a proposed change to Part 192, RSPA/OPS did not receive significant comments on that proposal, and RSPA/OPS are adopting it as final.

Section 192.3, Definitions. RSPA/OPS proposed three changes to § 192.3. First, RSPA/OPS proposed moving the present definition of “customer meter” from within the “service line” definition to a stand-alone position. Next, RSPA/OPS proposed expanding the “service line” definition to include distribution lines that transport gas from a common supply source to adjacent or multiple residential or small commercial customers. Finally, RSPA/OPS proposed a definition of “service regulator” that would distinguish customer regulators from regulating stations.

Oleksa suggested the definition of “customer meter” would be clearer if RSPA/OPS added the words “or master meter operator” after the word “consumer.” RSPA/OPS did not consider this comment in finalizing the “customer meter” definition because RSPA/OPS did not propose to change the text of the present definition.

AGA, PSE&G, and Peoples commented that the proposed “service line” and “service regulator” definitions used different terms—“meter manifold” and “meter header or manifold”—to refer to piping assemblies between a single line and a group of meters. AGA and Peoples preferred the latter term because operators may call these assemblies either meter headers or meter manifolds. RSPA/OPS agrees that a single term is appropriate and, because of this comment, used “meter header or manifold” in the final definition of “service line.”

ConEd opposed the proposed definition of “service line” because, like the present definition, it includes interior piping that leads to meters in individual apartments or to meters in basements. Primarily because of the difficulty of checking such piping for leaks, ConEd suggested that RSPA/OPS exclude interior piping from the final definition. This comment, however, addresses an issue the NPRM did not cover. RSPA/OPS proposed to broaden the present service line definition, not limit it to outside piping. Therefore, RSPA/OPS has not considered the comment in developing the final definition.

ARPSC commented that, in its experience, lines serving multiple customers are the lines most frequently damaged by third parties, with most damage occurring at burial depths between four and 18 inches. Consequently, ARPSC suggested the burial depth of service lines supplying gas to multiple customers be at least 24 inches. RSPA/OPS did not adopt this comment because increasing burial depth is not generally recognized as one of the best ways to reduce excavation damage to buried utilities. According to a report RSPA/OPS prepared for Congress, Common Ground: Study of One-Call Systems and Damage Prevention Best Practices, the key elements in prevention of excavation damage involve the use of one-call systems, accurate utility mapping, advance notice of excavation, accurate temporary surface marking before excavation, and safe excavation practices.

Regarding the proposed “service line” definition, RSPA/OPS asked how it might define the term “small commercial customers.” In response, ARPSC said volume should be limited to 10 percent above the volume used by a normal residential customer. Iowa recommended the definitions that operators include in tariffs established under utility regulations. MichCon proposed meter capacity or type or regulator size or type as possible bases for a definition. Finally, NiSource suggested that volume be limited to no more than twice the volume used by the operator's largest residential customer.

Upon further consideration, RSPA/OPS decided not to define “small commercial customers.” As the Iowa comment suggests, distribution operators commonly use this term to refer to a class of service offered for sale under state or municipal rate regulations. Because different definitions of the term may be in use, a separate part 192 definition could lead to confusion in identifying a pipeline as a service line. So, without a part 192 definition, the term will apply in part 192 as it does in the industry, to those customers each operator defines as “small commercial customers” for tariff purposes.

Section 192.123, Design Limitations for Plastic Pipe. RSPA/OPS proposed to delete the second sentence of § 192.123(b)(2)(i) as obsolete. This sentence allows operators to use plastic pipe manufactured before May 18, 1978, and strength rated at 73 °F at temperatures up to 100 °F. RSPA/OPS also invited operators to tell us whether they still have any stockpiles of this pipe that they plan to use at temperatures above 73 °F. Only one operator responded. NiSource stated that it does not have stockpiles of plastic pipe intended for use at temperatures greater than 73 °F. Since RSPA/OPS received no adverse comment on the proposed rule change, RSPA/OPS adopted it as final.

Section 192.321, Installation of Plastic Pipe; Section 192.361, Service Lines: Installation. Section 192.321(e) requires that in transmission lines and mains, buried plastic pipe that is not encased must have an electrically conductive wire or other means of finding the pipe. Because of reported lightning damage to buried plastic pipe, RSPA/OPS proposed to add the following new requirements to this rule, and to establish similar requirements in § 192.361(g) for plastic service lines:

Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means.

Regarding proposed § 192.321(e), AGA, NiSource, Oleksa, Southwest, and Yankee were concerned that government inspectors might interpret “contact with the pipe must be minimized” too stringently. AGA and NiSource thought inspectors might interpret the term to prohibit contact with the pipe. These commenters also speculated inspectors might interpret the term to preclude trenchless installation of plastic pipe. Oleksa was concerned the proposed wording would require separation of wire from pipe even where total separation is not practicable, as in trenchless installations. Yankee wanted the final rule to state specifically that incidental contact between tracer wire and plastic pipe is all right.

RSPA/OPS thinks these proffered interpretations may be unrealistic because minimized contact implies some contact is permissible. Still, in view of the commenters' concerns, RSPA/OPS has used the following wording in the final rule: “contact with the pipe must be minimized but is not prohibited.” RSPA/OPS wants to ensure the rule does not deter the common practice in trenchless installations of randomly taping tracer wire to the pipe to control separation during installation.

AGA, GPTC, Peoples, PSE&G, and Dominion Resources thought proposed § 192.361(g) would require that steel service lines have tracer wire, because the wording was not limited to plastic pipe. To remove this potentiality, RSPA/OPS added the word “nonmetallic” to final § 192.361(g).

City Utilities and Southwest were concerned that trying to reduce the risk of lightning damage by separating tracer wire from pipe could lead to inaccurate pipe location and excavation damage. The purpose of tracer wire, as § 192.321(e) states, is to provide a means of locating buried plastic pipe. Neither present nor proposed § 192.321(e) would permit installation of tracer wire so far away from the pipe that it hampers attempts to accurately find the pipe.

MichCon suggested removing “copper” from “coated copper wire” so the rule would not preclude the installation of other types of corrosion resistant wire. RSPA/OPS did not adopt this comment because the proposed rule would allow operators to use “other means” to provide corrosion resistant wire.

Section 192.353, Customer Meters and Regulators: Location. RSPA/OPS proposed to amend § 192.353(a) to emphasize that operators must protect meters and service regulators from vehicular damage. Under the present rule, protection from vehicular damage falls under the general requirement to protect meters and service regulators from “corrosion and other damage.”

AGA, GPTC, Dominion Resources, Oleksa, Peoples, PSE&G, MichCon, and Yankee were concerned the proposed rule would apply to meters or service regulators installed indoors or other places where there is only a remote chance of vehicular damage. As stated below under the “Advisory Committee” heading, the Technical Pipeline Safety Standards Committee had a similar concern about the proposal. The committee recommended RSPA/OPS limit the requirement to outdoor installations that are clearly vulnerable to minor impact.

RSPA/OPS said in the NPRM that it expected operators would consider the location of meters and regulators in deciding whether to provide protection from vehicular damage. To insure the final rule reflects this allowance, RSPA/OPS is amending § 192.353(a) to require operators to protect outdoor installations from vehicular damage that may be anticipated. If meters or regulators are installed indoors or installed outdoors in places where anticipating damage from vehicles is not reasonable, no protection is required.

Southwest was concerned that emphasizing vehicular damage would lead to disagreements between government and operators over whether protection is adequate. Nevertheless, such disputes can arise under the present rule, because it requires protection from vehicular damage but does not specify the type or degree of protection. In this situation, operators have discretion to provide whatever type and degree of protection is reasonable under the circumstances. The final rule does not change this discretion. It merely highlights the risk of vehicular damage.

Section 192.457, External Corrosion Control: Buried or Submerged Pipelines Installed Before August 1, 1971; 192.465, External Corrosion Control: Monitoring. RSPA/OPS proposed to amend § 192.457 by removing from paragraph (b) the requirement to use electrical surveys in determining areas of active corrosion, and by removing paragraph (c). Under § 192.465(e), RSPA/OPS proposed to establish more detailed criteria for alternatives to electrical surveys, and to allow operators to use alternatives on distribution lines without first finding that electrical surveys are impractical. In addition, RSPA/OPS proposed to add definitions of “active corrosion'' (the definition now in § 192.457 (c)), “electrical survey,” and “pipeline environment.”

AGA, Peoples, and GPTC commented that moving the definition of “active corrosion” from § 192.457(c) to § 192.465(e) would make § 192.457(b) harder to understand because the term would remain in § 192.457(b). As a remedy, AGA and Peoples suggested adding to § 192.457(b) a cross-reference to the new location of the definition. Peoples also advised making the relocated definition applicable throughout Subpart I rather than just § 192.465(e). GPTC and PSE&G suggested moving the definition to § 192.451, Scope.

Removing § 192.457(c) should not affect § 192.457(b). Under § 192.457(b), the time allowed for initially determining and cathodically protecting areas of active corrosion expired August 1, 1976. And § 192.465(e) regulates all subsequent determinations and protections of areas of active corrosion. So moving the present definition of “active corrosion” from § 192.457(c) to § 192.465(e) simply places the definition where it is currently used. With such limited usage, making the definition applicable throughout Subpart I is not necessary.

As previously stated, RSPA/OPS proposed moving the definition of “active corrosion” from § 192.457(c) to § 192.465(e). However, RSPA/OPS inadvertently included in proposed § 192.465(e) a similar definition of “active corrosion” found in 49 CFR 195.553, which applies to hazardous liquid pipelines. Final § 192.465(e) includes the definition now in § 192.457(c).

The proposed definition of “electrical survey,” which SIRRC recommended, is the same definition that applies to hazardous liquid pipelines under 49 CFR 195.553. The definition is based on pipe-to-soil electrical readings over a pipeline. AGA and NiSource recommended changing “pipe-to-soil” to “potential gradient” to allow the use of “cell-to-cell” surveys, which, AGA said, are typically used on bare pipe to identify corrosion activity. MichCon was similarly concerned that other types of electrical corrosion surveys may not qualify under the proposed definition.

RSPA/OPS agrees that cell-to-cell potential testing would not meet the proposed definition of “electrical survey.” Nevertheless, proposed § 192.465(e) would not preclude operators from using cell-to-cell testing or any other useful method to find active corrosion areas. To find active corrosion without using an electrical survey, operators could use any means that includes review and analysis of certain maintenance records and the pipeline environment. If augmented by this review and analysis, cell-to-cell testing would qualify for use under proposed § 192.465(e). Therefore, RSPA/OPS did not include the commenters' suggested change in final § 192.465(e).

Southwest thought the term “closely spaced pipe-to-soil readings” was unclear, and suggested deleting “closely spaced.” However, RSPA/OPS believes the term is consistent with usual industry practices. No other commenter suggested the term would be difficult to apply. In addition, the term is part of the “electrical survey” definition in 49 CFR 195.553, which RSPA/OPS adopted without any objection from industry commenters.

Iowa commented erroneously that proposed § 192.465(e) ignores SIRRC's central theme that operators should not have to show that electrical surveys are impractical before using alternative review methods. In fact, proposed § 192.465(e) is faithful to SIRRC's theme. On distribution lines, the proposed rule would allow alternative methods regardless of the practicality of electrical surveys. Only on transmission lines would operators still have to show that electrical surveys are impractical before using alternative methods.

Section 192.479, Atmospheric Corrosion Control: General. RSPA/OPS proposed to revise § 192.479 to require the same level of protection from atmospheric corrosion on new and existing pipelines. However, in certain circumstances, operators would not have to protect pipelines from light surface oxide or from atmospheric corrosion that would not affect safe operation before the next scheduled inspection. A similar regulation is now in effect for hazardous liquid pipelines (49 CFR 195.581). In addition, RSPA/OPS proposed to amend the atmospheric corrosion monitoring requirements of § 192.481 to comport with a similar hazardous liquid pipeline regulation (49 CFR 195.583).

GPTC and PSE&G thought proposed § 192.479 would be clearer if the only exception from the protection requirement were pipe without active corrosion. This comment is similar to SIRRC's suggested change to § 192.479. Our primary reason for not adopting SIRRC's approach was the advantage to industry and government if similar corrosion control regulations governed gas and hazardous liquid pipelines. Another reason was that the proposed exceptions were consistent with SIRRC's approach, since the excepted pipelines would not have active corrosion. So, in keeping with the similar-regulations goal, RSPA/OPS has included the proposed exceptions in final § 192.479.

MichCon opposed the proposed exceptions, arguing that operators should stop further corrosion from even a light surface oxide. MichCon also suggested that cleaning and coating are more effective than assessing whether corrosion would affect safety before the next inspection. In contrast, RSPA/OPS continues to agree with SIRRC that a light surface oxide is a non-damaging form of corrosion that does not need remedial action. The absence of any other negative comment on the proposed oxide exception bolsters this position. Also, even if cleaning and coating may be a more effective long-term approach, RSPA/OPS believes operators should have the option of assigning resources to problems that pose a higher near-term risk.

MichCon was concerned that inspecting thermally insulated pipe could destroy the insulation system. It suggested making inspections “wherever practical” and sampling pipe through windows cut into the jacketing. MichCon further suggested that the final rule use the term “electrolyte-to-air interface” instead of “soil-to-air interface” to include other pipeline environments. RSPA/OPS believes MichCon has suggested a reasonable way to meet the proposed requirement to inspect thermally insulated pipe for atmospheric corrosion. The rule is designed to allow operators to choose a satisfactory compliance method. RSPA/OPS left “soil-to-air interface” in the final rule because it is one of several specifically-named environments that justify special attention during inspections.

UGI argued that because customer meter sets found inside buildings are generally in non-corrosive environments, the sets do not need inspection for atmospheric corrosion more often than every 5 years. Present § 192.481 calls for inspection at least every 3 years, and RSPA/OPS did not propose to change this interval. Thus, RSPA/OPS did not consider UGI's comment in developing final § 192.481.

AGA suggested RSPA/OPS postpone final action on the proposed revision of § 192.479 until RSPA/OPS addresses issues concerning meters inside buildings and propose other changes to the corrosion control regulations in Part 192. RSPA/OPS has not postponed final action on proposed § 192.479. It is in the interest of pipeline safety overall for RSPA to have similar atmospheric corrosion regulations for gas and hazardous liquid pipelines. Moreover, RSPA/OPS currently has no plans to further revise the Part 192 corrosion control regulations, for RSPA/OPS has closed the previously scheduled revision project (67 FR 74986; Dec. 9, 2002).

Section 192.517, Records. RSPA/OPS proposed to amend § 192.517 to require that operators keep records of required leak tests for at least 5 years. The leak tests are those that § 192.509 requires on pipelines designed to operate below 100 psig, that § 192.511 requires on service lines, and that § 192.513 requires on plastic pipelines.

AGA, Iowa, and Peoples asked us to defer final action on proposed § 192.517 until after RSPA/OPS acts on other changes to Part 192 that SIRRC suggested in a petition for rulemaking dated November 26, 2002. RSPA/OPS has not postponed final action, because RSPA/OPS believes government inspectors need the proposed records now to aid enforcement efforts. More than 10 years ago, NAPSR recognized this need in its “Report on Recommendations for Revision of 49 CFR part 192.” If RSPA/OPS decides to make additional changes to § 192.517 because of our consideration of SIRRC's petition, RSPA/OPS will include those changes in a future notice of proposed rulemaking.

MichCon and Southwest objected to the proposed rule. It was unclear to MichCon what information operators would have to record, and Southwest mistakenly assumed the information would be the same as § 192.517 requires for strength tests. As RSPA/OPS stated in the NPRM, the purpose of the proposed records is merely to show that required leak tests have been done, not to retain specific information about the tests. The content of the records would be discretionary. A mere notation showing that required tests were carried out would suffice. Section 192.709 requires records of this type for each patrol, survey, inspection, and test done on transmission lines under Subparts L and M of part 192.

Dominion commented that proposed § 192.517 would be very burdensome, pointing to the large number of leak tests done by customers' contractors on customer-owned service lines. It thought that records of these tests would be difficult for operators to obtain. RSPA/OPS thinks Dominion may have mistaken the type of record needed to comply with proposed § 192.517. Proposed § 192.517 would not require operators to obtain copies of records kept by their customers' contractors. No matter who does the testing, its own workers or its customers' contractors, operators would only have to verify that correct leak tests have been done and then record that fact. Under part 192, distribution operators are already responsible for the correct installation and leak testing of customer-owned service lines. Operators who do not install and test customer-owned service lines themselves must still verify that work done by their customers' contractors meets part 192 requirements. So the burden of keeping a record of leak tests done by customers' contractors should be no greater than for leak tests done by operators themselves.

Section 192.553, General Requirements. Section 192.553(d) requires that a new maximum allowable operating pressure (MAOP) may not exceed the maximum that part 192 allows on a new segment of pipeline constructed of the same materials in the same location. Based on a SIRRC recommendation, RSPA/OPS proposed to replace the reference to part 192 with a reference to “§§ 192.619 and 192.621,” the sections in part 192 that limit the MAOP of new pipelines.

AGA, Iowa, PSE&G, Peoples, and Southwest asked us to defer final action on the proposed change to § 192.553. They suggested RSPA/OPS wait until after RSPA/OPS acts on SIRRC's suggested change to subpart K, Uprating, included in its November 26, 2002, rulemaking petition. That change would allow operators to increase the MAOP of certain existing low stress pipelines without prior pressure testing.

RSPA/OPS has not postponed final action on proposed § 192.553(d) since the proposal involves only a simple editorial change. However, by taking this action RSPA/OPS is not foreclosing the opportunity for future rulemaking based on SIRRC's suggested change to the uprating requirements. If RSPA/OPS decides to make additional changes to § 192.553(d) because of our consideration of SIRRC's recent petition, RSPA/OPS will include those changes in a future notice of proposed rulemaking.

Section 192.743, Pressure Limiting and Regulating Stations: Testing of Relief Devices. RSPA/OPS proposed to change § 192.743(a) and (b) to allow operators to use calculations to decide if the capacity of relief devices is adequate without first having to conclude that testing the devices is not feasible. RSPA/OPS also proposed editorial changes to § 192.743(c), which requires installation of new or additional devices if the relief capacity of existing devices is inadequate.

Iowa said RSPA/OPS should change § 192.743(c) to allow operators the option of modifying existing devices or associated facilities to provide the required relief capacity. Although this comment concerns an issue RSPA/OPS did not address in the NPRM, RSPA/OPS did not interpret § 192.743(c) to require the installation of unnecessary relief devices. If operators provide adequate relief capacity by modifying existing relief devices or associated facilities, new or additional devices are not necessary.

Section 192.745, Valve Maintenance: Transmission Lines. Section 192.745 requires annual inspection of transmission line valves that operators might need during an emergency. RSPA/OPS proposed to amend this section to require that operators take prompt remedial action to correct any valve found inoperable. Although NAPSR had recommended “immediate” remedial action, RSPA/OPS proposed prompt action to allow operators some latitude in scheduling maintenance.

AGA, Gulf South, and Southwest were concerned that disagreements would arise between government inspectors and operators over the meaning of “prompt.” In this regard, City Utilities suggested RSPA/OPS define “prompt remedial action” as not to exceed 6 months. In addition, AGA, GPTC, Gulf South, Peoples, PSE&G, and Yankee suggested that instead of promptly repairing an inoperable valve, operators should have latitude to designate another valve as an emergency valve if the other valve accomplishes the same function as the inoperable valve.

Occasional disagreements over whether remedial action is done promptly may be unavoidable. However, operators can reduce opportunities for disagreements if they assign priority to inoperable emergency valves in their repair schedules. Operators can also look to their experience in promptly correcting corrosion control deficiencies under § 192.465(d). RSPA/OPS decided not to establish a time limit for “prompt remedial action” because it could promote unnecessary delay and erode the latitude operators need in scheduling repairs.

Section 192.605(b)(1) requires operators to have procedures for carrying out the valve maintenance requirements of § 192.745. In their procedures, operators identify which valves they must inspect annually because they may need them during an anticipated emergency. If different valves are available for the same function, they only have to identify and inspect one of them to meet § 192.745. So the present rule allows operators latitude to designate an equivalent alternative valve rather than repair an inoperable valve. The proposed rule would not affect this latitude. It would only affect the time to correct an inoperable valve if the operator does not designate an alternative valve. Nevertheless, to assure no one misunderstands the alternative-valve option, RSPA/OPS has included it in final § 192.745. A similar option is in proposed § 192.747 concerning the maintenance of distribution valves.

Section 192.747 Valve Maintenance: Distribution Systems. Section 192.747 requires annual inspection and servicing of each valve that operators may need for safe operation of a distribution system. RSPA/OPS proposed to amend this section to require prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve.

AGA and Southwest were concerned that disagreements would arise between government inspectors and operators over the meaning of prompt. City Utilities suggested RSPA/OPS define “prompt remedial action” as not to exceed 6 months. As RSPA/OPS stated previously regarding similar comments on proposed § 192.745, some disagreement may be inevitable, but operators can reduce the chance of disagreement by prioritizing the repair of inoperable valves. They can also consider their compliance practices in promptly correcting corrosion control deficiencies. As with final § 192.745, RSPA/OPS decided not to set a time limit on “prompt remedial action” because it could promote unnecessary delay and erode the latitude operators need in scheduling repairs.

Iowa suggested RSPA/OPS also require prompt remedial action for inaccessible valves. RSPA/OPS addressed the issue of inaccessible safety valves in the NPRM. RSPA/OPS reasoned that if a designated safety valve becomes inaccessible, usually because of paving, the operator should discover the problem no later than the next inspection. Then the operator would have to either correct the problem to enable inspection within the permitted interval or designate an alternative safety valve. Given these circumstances, RSPA/OPS did not propose an additional regulation to insure that operators promptly correct inaccessible safety valves.

Advisory Committee

The Technical Pipeline Safety Standards Committee considered the NPRM and the associated evaluation of costs and benefits at a meeting in Washington, DC on March 27, 2003. This committee is a statutory, advisory committee that advises us on proposed safety standards and other policies for gas pipelines. It has an authorized membership of 15 persons, five each representing government, industry, and the public. Each member has qualifications to consider the technical feasibility, reasonableness, cost-effectiveness, and practicability of proposed pipeline safety standards. A transcript of the meeting is available in Docket No. RSPA-98-4470.

In discussing the NPRM, the committee focused on the proposed change to § 192.353, which emphasizes that operators must protect meters and regulators from vehicular damage. One member was concerned the proposed rule would apply to installations where vehicular damage is unlikely to occur, such as inside buildings or far away from traffic. This member wanted to limit the proposed rule to installations where the potential for vehicular damage is significant. All but one committee member agreed, and the committee suggested changing the proposal to read as follows:

Each meter and service regulator installed inside a building must be installed in a readily accessible location and be protected from corrosion and other damage. Meters installed outside of buildings must also be protected from vehicular damage where they are clearly vulnerable to minor impact.

Subsequently, by unanimous vote, the committee found all the proposed rules and the associated Draft Regulatory Evaluation to be technically feasible, reasonable, cost-effective, and practicable if proposed § 192.353 were changed as the committee suggested. RSPA/OPS considered the committee's advice as set forth above under the heading “Section 192.353, Customer Meters and Regulators: Location.”

Regulatory Analyses and Notices

Executive Order 12866 and DOT Policies and Procedures. RSPA does not consider this Final Rule 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 Final Rule to be significant under DOT regulatory policies and procedures (44 FR 11034: February 26, 1979).

RSPA/OPS prepared a Regulatory Evaluation of the Final Rule, and a copy is in the docket. This regulatory evaluation concludes that because of compliance options, the changes to existing rules may actually reduce operators' costs to comply with those rules.

Regulatory Flexibility Act. This Final Rule is consistent with customary practices in the gas pipeline industry. Therefore, based on the facts available about the anticipated impacts of the Final Rule, I certify, pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605), that this rulemaking would not have a significant impact on a substantial number of small entities.

Executive Order 13175. RSPA/OPS has analyzed this Final Rule according to the principles and criteria contained in Executive Order 13175, “Consultation and Coordination with Indian Tribal Governments.” Because the Final Rule will not significantly or uniquely affect the communities of the Indian tribal governments and will not impose substantial direct compliance costs, the funding and consultation requirements of Executive Order 13175 do not apply.

Paperwork Reduction Act. Final §§ 192.517(b) and 192.605(b)(11) contain minor additional information collection requirements. Section 192.517(b) requires operators to maintain records of certain leak tests for 5 years, and § 192.605(b)(11) requires operators to have procedures for responding promptly to a report of a gas odor inside or near a building. However, RSPA/OPS believes most operators already maintain records of leak tests and have procedures for responding to reports of gas odors inside or near buildings. Also, RSPA/OPS believes the burden of retaining these records is minimal because they largely computerize them. Maintaining these records on a computer disk represents very minimal costs. So, because the additional paperwork burdens of this proposed rule are likely to be minimal, RSPA/OPS believes that submitting an analysis of the burdens to OMB under the Paperwork Reduction Act is unnecessary.

RSPA/OPS did not receive any comments on the burden of proposed § 192.605(b)(11). Comments on the burden of proposed 192.517(b) are discussed above under the heading “Section 192.517, Records.”

Unfunded Mandates Reform Act of 1995. This Final Rule will 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.

National Environmental Policy Act. RSPA/OPS has analyzed this Final Rule for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et seq.). Because the Final Rule parallels present requirements or practices, RSPA/OPS has determined that the Final Rule will not significantly affect the quality of the human environment. None of the commenters disputed this conclusion.

Executive Order 13132. RSPA/OPS has analyzed this Final Rule according to the principles and criteria contained in Executive Order 13132 (“Federalism”). The Final Rule does not establish 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.

List of Subjects in 49 CFR Part 192

• Natural gas
• Pipeline safety
• Reporting and recordkeeping requirements

For the reasons discussed in this preamble, RSPA amends 49 CFR Part 192 as follows:

PART 192—TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS

1. The authority citation for part 192 continues to read as follows:

Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53.

2. Amend § 192.3 by adding in alphabetical order definitions of “customer meter” and “service regulator” and by revising the definition of “service line” as follows:

§ 192.3

Definitions.

* * * * *

Customer meter means the meter that measures the transfer of gas from an operator to a consumer.

* * * * *

Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.

Service regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold.

* * * * *

§ 192.123

[Amended]

3. Remove the second sentence in § 192.123(b)(2)(i).

§ 192.197

[Amended]

4. In § 192.197(a), remove the term “under 60 p.s.i. (414 kPa) gage” and add the term “60 psi (414 kPa) gage, or less,” in its place.

§ 192.285

[Amended]

5. In § 192.285(d), remove the term “his” and add the term “the operator's” in its place.

6. Revise § 192.311 to read as follows:

§ 192.311

Repair of plastic pipe.

Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.

7. Revise § 192.321(e) to read as follows:

§ 192.321

Installation of plastic pipe.

* * * * *

(e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means.

* * * * *

8. Revise the first sentence of § 192.353(a) to read as follows:

§ 192.353

Customer meters and regulators: Location.

(a) Each meter and service regulator, whether inside or outside a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. * * *

* * * * *

9. Add § 192.361(g) to read as follows:

§ 192.361

Service lines: Installation.

* * * * *

(g) Locating underground service lines. Each underground nonmetallic service line that is not encased must have a means of locating the pipe that complies with § 192.321(e).

§ 192.457

[Amended]

10. Amend § 192.457 as follows:

a. In paragraph (b)(3), remove the second sentence; and

b. Remove paragraph (c).

11. Revise § 192.465(e) to read as follows:

§ 192.465

External corrosion control: Monitoring.

* * * * *

(e) After the initial evaluation required by §§ 192.455(b) and (c) and 192.457(b), each operator must, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator must determine the areas of active corrosion by electrical survey. However, on distribution lines and where an electrical survey is impractical on transmission lines, areas of active corrosion may be determined by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. In this section:

(1) Active corrosion means continuing corrosion which, unless controlled, could result in a condition that is detrimental to public safety.

(2) Electrical survey means a series of closely spaced pipe-to-soil readings over a pipeline that are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.

(3) Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.

12. Revise § 192.479 to read as follows:

§ 192.479

Atmospheric corrosion control: General.

(a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section.

(b) Coating material must be suitable for the prevention of atmospheric corrosion.

(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, the operator need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will—

(1) Only be a light surface oxide; or

(2) Not affect the safe operation of the pipeline before the next scheduled inspection.

13. Revise § 192.481 to read as follows:

§ 192.481

Atmospheric corrosion control: Monitoring.

(a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows:

If the pipeline is located:	Then the frequency of inspection is:
Onshore	At least once every 3 calendar years, but with intervals not exceeding 39 months
Offshore	At least once each calendar year, but with intervals not exceeding 15 months

(b) During inspections the operator must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water.

(c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by § 192.479.

14. Amend § 192.517 as follows:

a. Redesignate the introductory text as paragraph (a);

b. Redesignate existing paragraphs (a), (b), (c), (d), (e), (f), and (g) as (a)(1), (2), (3), (4), (5), (6), and (7), respectively; and

c. Add a new paragraph (b) to read as follows:

§ 192.517

Records.

* * * * *

(b) Each operator must maintain a record of each test required by §§ 192.509, 192.511, and 192.513 for at least 5 years.

§ 192.553

[Amended]

15. In the first sentence in § 192.553(d), remove the term “this part” and add the term “§§ 192.619 and 192.621” in its place.

16. Add § 192.605(b)(11) to read as follows:

§ 192.605

Procedural manual for operations, maintenance, and emergencies.

* * * * *

(b) * * *

(11) Responding promptly to a report of a gas odor inside or near a building, unless the operator's emergency procedures under § 192.615(a)(3) specifically apply to these reports.

* * * * *

17. Revise the first sentence of § 192.625(f) introductory text to read as follows:

§ 192.625

Odorization of gas.

* * * * *

(f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable.* * *

* * * * *

18. Revise § 192.739(c) to read as follows:

§ 192.739

Pressure limiting and regulating stations: Inspection and testing.

* * * * *

(c) Set to control or relieve at the correct pressures consistent with the pressure limits of § 192.201(a); and

* * * * *

19. Revise § 192.743 to read as follows:

§ 192.743

Pressure limiting and regulating stations: Capacity of relief devices.

(a) Pressure relief devices at pressure limiting stations and pressure regulating stations must have sufficient capacity to protect the facilities to which they are connected consistent with the pressure limits of § 192.201(a). This capacity must be determined at intervals not exceeding 15 months, but at least once each calendar year, by testing the devices in place or by review and calculations.

(b) If review and calculations are used to determine if a device has sufficient capacity, the calculated capacity must be compared with the rated or experimentally determined relieving capacity of the device for the conditions under which it operates. After the initial calculations, subsequent calculations need not be made if the annual review documents that parameters have not changed to cause the rated or experimentally determined relieving capacity to be insufficient.

(c) If a relief device is of insufficient capacity, a new or additional device must be installed to provide the capacity required by paragraph (a) of this section.

20. Amend § 192.745 as follows:

a. Designate the existing text as paragraph (a); and

b. Add paragraph (b) to read as follows:

§ 192.745

Valve maintenance: Transmission lines.

* * * * *

(b) Each operator must take prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve.

21. Amend § 192.747 as follows:

a. Designate the existing text as paragraph (a); and

b. Add paragraph (b) to read as follows:

§ 192.747

Valve maintenance: Distribution systems.

* * * * *

(b) Each operator must take prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve.

22. In § 192.753, revise the introductory text of paragraph (a) and revise paragraph (b) to read as follows:

§ 192.753

Caulked bell and spigot joints.

(a) Each cast iron caulked bell and spigot joint that is subject to pressures of more than 25 psi (172kPa) gage must be sealed with:

* * * * *

(b) Each cast iron caulked bell and spigot joint that is subject to pressures of 25 psi (172kPa) gage or less and is exposed for any reason must be sealed by a means other than caulking.

Issued in Washington, DC, on September 3, 2003.

Samuel G. Bonasso,

Acting Administrator.