[Federal Register Volume 68, Number 178 (Monday, September 15, 2003)]
[Rules and Regulations]
[Pages 53895-53902]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-23179]


=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-02-13208; Amdt. 192-93]
RIN 2137-AD01


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 
[email protected].

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 
Sec.  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

[[Page 53896]]

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 Sec.  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 [deg]F at 
temperatures up to 100 [deg]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 [deg]F. Only one operator responded. 
NiSource stated that it does not have stockpiles of plastic pipe 
intended for use at temperatures greater than 73 [deg]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 Sec.  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 Sec.  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 
Sec.  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 
Sec.  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 Sec.  192.321(e) states, is to provide a means of 
locating buried plastic pipe. Neither present nor proposed Sec.  
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 Sec.  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

[[Page 53897]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  192.457 (c)), ``electrical survey,'' and ``pipeline 
environment.''
    AGA, Peoples, and GPTC commented that moving the definition of 
``active corrosion'' from Sec.  192.457(c) to Sec.  192.465(e) would 
make Sec.  192.457(b) harder to understand because the term would 
remain in Sec.  192.457(b). As a remedy, AGA and Peoples suggested 
adding to Sec.  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 Sec.  192.465(e). GPTC 
and PSE&G suggested moving the definition to Sec.  192.451, Scope.
    Removing Sec.  192.457(c) should not affect Sec.  192.457(b). Under 
Sec.  192.457(b), the time allowed for initially determining and 
cathodically protecting areas of active corrosion expired August 1, 
1976. And Sec.  192.465(e) regulates all subsequent determinations and 
protections of areas of active corrosion. So moving the present 
definition of ``active corrosion'' from Sec.  192.457(c) to Sec.  
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 Sec.  192.457(c) to Sec.  192.465(e). 
However, RSPA/OPS inadvertently included in proposed Sec.  192.465(e) a 
similar definition of ``active corrosion'' found in 49 CFR 195.553, 
which applies to hazardous liquid pipelines. Final Sec.  192.465(e) 
includes the definition now in Sec.  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 Sec.  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 Sec.  192.465(e). Therefore, RSPA/OPS did not include 
the commenters' suggested change in final Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  192.481 to comport with a 
similar hazardous liquid pipeline regulation (49 CFR 195.583).
    GPTC and PSE&G thought proposed Sec.  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 Sec.  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 Sec.  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

[[Page 53898]]

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 Sec.  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 Sec.  192.481.
    AGA suggested RSPA/OPS postpone final action on the proposed 
revision of Sec.  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 Sec.  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 Sec.  192.517 
to require that operators keep records of required leak tests for at 
least 5 years. The leak tests are those that Sec.  192.509 requires on 
pipelines designed to operate below 100 psig, that Sec.  192.511 
requires on service lines, and that Sec.  192.513 requires on plastic 
pipelines.
    AGA, Iowa, and Peoples asked us to defer final action on proposed 
Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  192.517. Proposed Sec.  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 ``Sec. Sec.  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 Sec.  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 Sec.  
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 Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  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

[[Page 53899]]

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 Sec.  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 Sec.  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 Sec.  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 Sec.  192.745. A 
similar option is in proposed Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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

[[Page 53900]]

impose substantial direct compliance costs, the funding and 
consultation requirements of Executive Order 13175 do not apply.
    Paperwork Reduction Act. Final Sec. Sec.  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 Sec.  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 
Sec.  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.

0
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

0
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.

0
2. Amend Sec.  192.3 by adding in alphabetical order definitions of 
``customer meter'' and ``service regulator'' and by revising the 
definition of ``service line'' as follows:


Sec.  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.
* * * * *


Sec.  192.123  [Amended]

0
3. Remove the second sentence in Sec.  192.123(b)(2)(i).


Sec.  192.197  [Amended]

0
4. In Sec.  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.


Sec.  192.285  [Amended]

0
5. In Sec.  192.285(d), remove the term ``his'' and add the term ``the 
operator's'' in its place.

0
6. Revise Sec.  192.311 to read as follows:


Sec.  192.311  Repair of plastic pipe.

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

0
7. Revise Sec.  192.321(e) to read as follows:


Sec.  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.
* * * * *

0
8. Revise the first sentence of Sec.  192.353(a) to read as follows:


Sec.  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. * * *
* * * * *

0
9. Add Sec.  192.361(g) to read as follows:


Sec.  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 Sec.  192.321(e).


Sec.  192.457  [Amended]

0
10. Amend Sec.  192.457 as follows:
0
a. In paragraph (b)(3), remove the second sentence; and
0
b. Remove paragraph (c).

0
11. Revise Sec.  192.465(e) to read as follows:


Sec.  192.465  External corrosion control: Monitoring.

* * * * *
    (e) After the initial evaluation required by Sec. Sec.  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

[[Page 53901]]

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.

0
12. Revise Sec.  192.479 to read as follows:


Sec.  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.

0
13. Revise Sec.  192.481 to read as follows:


Sec.  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:

------------------------------------------------------------------------
                                              Then the frequency of
      If the pipeline is located:                 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 
Sec.  192.479.

0
14. Amend Sec.  192.517 as follows:
0
a. Redesignate the introductory text as paragraph (a);
0
b. Redesignate existing paragraphs (a), (b), (c), (d), (e), (f), and 
(g) as (a)(1), (2), (3), (4), (5), (6), and (7), respectively; and
0
c. Add a new paragraph (b) to read as follows:


Sec.  192.517  Records.

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


Sec.  192.553  [Amended]

0
15. In the first sentence in Sec.  192.553(d), remove the term ``this 
part'' and add the term ``Sec. Sec.  192.619 and 192.621'' in its 
place.

0
16. Add Sec.  192.605(b)(11) to read as follows:


Sec.  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 Sec.  
192.615(a)(3) specifically apply to these reports.
* * * * *

0
17. Revise the first sentence of Sec.  192.625(f) introductory text to 
read as follows:


Sec.  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.* 
* *
* * * * *

0
18. Revise Sec.  192.739(c) to read as follows:


Sec.  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 Sec.  192.201(a); and
* * * * *

0
19. Revise Sec.  192.743 to read as follows:


Sec.  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 Sec.  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.

0
20. Amend Sec.  192.745 as follows:
0
a. Designate the existing text as paragraph (a); and
0
b. Add paragraph (b) to read as follows:


Sec.  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.

0
21. Amend Sec.  192.747 as follows:
0
a. Designate the existing text as paragraph (a); and
0
b. Add paragraph (b) to read as follows:


Sec.  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.

0
22. In Sec.  192.753, revise the introductory text of paragraph (a) and 
revise paragraph (b) to read as follows:

[[Page 53902]]

Sec.  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.
[FR Doc. 03-23179 Filed 9-12-03; 8:45 am]
BILLING CODE 4910-60-P