[Federal Register Volume 67, Number 219 (Wednesday, November 13, 2002)]
[Proposed Rules]
[Pages 68815-68827]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-28240]



[[Page 68815]]

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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-02-13208; Notice 1]
RIN 2137-AD01


Pipeline Safety: Further Regulatory Review; Gas Pipeline Safety 
Standards

AGENCY: Research and Special Programs Administration (RSPA), DOT.

ACTION: Notice of proposed rulemaking.

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SUMMARY: RSPA is proposing to change some of the 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). We believe the changes will improve the clarity and 
effectiveness of the present standards.

DATES: Persons interested in submitting written comments on the rules 
proposed in this notice must do so by January 13, 2003. Late filed 
comments will be considered so far as practicable.

ADDRESSES: You may submit written comments by mailing or delivering an 
original and two copies to the Dockets Facility, U.S. Department of 
Transportation, Room PL-401, 400 Seventh Street, SW., Washington, DC 
20590-0001. The Dockets Facility is open from 10 a.m. to 5 p.m., Monday 
through Friday, except on Federal holidays when the facility is closed. 
Or you may submit written comments to the docket electronically at the 
following Web address: http://dms.dot.gov. See the SUPPLEMENTARY 
INFORMATION section for additional filing information.

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:

Filing Information, Electronic Access, and General Program Information

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

Background

    NAPSR is a non-profit association of officials from State agencies 
that participate with RSPA in the Federal pipeline safety regulatory 
program. Each year NAPSR holds regional meetings to discuss safety and 
administrative issues, culminating in resolutions for program 
improvement.
    In 1990 we asked NAPSR to review the gas pipeline safety standards 
in 49 CFR part 192. The purpose of the review was to identify standards 
that NAPSR considered insufficient for safety or not clear enough to 
enforce. 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, a copy of which is in the docket of the 
present proceeding, recommends changes to 40 sections in part 192.
    By the time NAPSR completed its report, we had published a notice 
of proposed rulemaking to change many part 192 standards that we 
considered unclear or overly 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. Later, at a meeting on 
corrosion problems held in San Antonio, Texas on April 28, 1999, we 
opened NAPSR's recommendations on corrosion control to further public 
discussion (Docket RSPA-97-2762; 64 FR 16885; April 7, 1999).
    In PS-124 we received 79 comments on NAPSR's recommendations, 
primarily from pipeline trade associations, pipeline operators, and 
State pipeline safety agencies. Industry commenters generally opposed 
most of NAPSR's recommendations on grounds that standards would be 
changed not for safety reasons or clarity but to make compliance 
auditing easier. In contrast, the State agencies generally supported 
NAPSR's recommendations. NAPSR denied it was merely trying to simplify 
the auditing process, and said its experience provided a unique 
perspective on which standards are ineffective or inappropriate.
    Because industry and State views were so divergent, in October 
1997, the American Gas Association (AGA), the American Public Gas 
Association (APGA), and NAPSR formed SIRRC to iron out their 
differences over the recommendations. SIRRC agreed on all but eight of 
the recommendations scheduled for future consideration. A copy of 
SIRRC's report titled ``Summary Report,'' dated April 26, 1999, is in 
the docket of the present proceeding.
    We have completed our review of NAPSR's 1992 recommendations as 
updated by SIRRC's 1999 Summary Report. The review also covered a NAPSR 
resolution on the definition of ``service line.'' Although this 
resolution was not in NAPSR's 1992 report, SIRRC dealt with the 
resolution in it's Summary Report.
    The purpose of the review was to decide which, if any, of NAPSR's 
recommendations warrant inclusion in a notice of proposed rulemaking. 
If SIRRC agreed to modify a recommendation, our review focused on that 
modification. If SIRRC did not reach agreement, we focused on NAPSR's 
recommendation in light of SIRRC's discussion. Our responses to the 
recommendations are discussed in the next section of the preamble.

Disposition of NAPSR's Recommendations

    This section summarizes NAPSR's recommendations and SIRRC's 
consideration of those recommendations. It also states our responses to 
the recommendations. For ease of reference, we have numbered the 
recommendations according to their sequence in SIRRC's Summary Report. 
The following table categorizes the recommendations according to the 
rulemaking status indicated by our responses:

------------------------------------------------------------------------
           Recommendation No.                   Rulemaking status
------------------------------------------------------------------------
7, 15, 17, 20, and 26..................  Included in previous final rule
                                          actions.
8, 9, 30...............................  Proposed in ``Periodic Updates
                                          to Pipeline Safety Regulations
                                          (1999)'' (Docket RSPA-99-6106;
                                          56 FR 15290; Mar. 22, 2000).

[[Page 68816]]

 
2, 5, 6, 11, 12, 13, 14, 29 (in part),   Proposed in present action.
 31, 32, 35 18, 24, 25, 28, 33 (in        Alternative proposed in
 part) and 34 (in part).                  present action.
1, 3, 4, 10, 16, 19, 21, 22, 23, 27, 29  No rulemaking action.
 (in part), 33 (in part), and 34 (in
 part).
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1. Section 192.3, Definitions of Main and Transmission Line. (SIRRC 
Summary Report, p. 3)

    Recommendation. To help distinguish mains from transmission lines, 
revise the definition of ``main'' and the first paragraph of the 
definition of ``transmission line'' to read:
    [sbull] ``Main'' means a pipeline installed in a community to 
convey gas to individual service lines or to other mains.
    [sbull] ``Transmission line'' means a pipeline, or a series of 
pipelines, other than a gathering line, that: (a) Transports gas from a 
gathering line, storage field or another transmission line to a storage 
field or to one or more distribution systems or other load centers.
    SIRRC. The committee reached consensus to modify the recommendation 
as follows:
    [sbull] ``Main'' means a segment of pipeline in a distribution 
system installed to transport gas to individual service lines or other 
mains.
    [sbull] In the present definition of ``transmission line,'' change 
``distribution center'' to ``distribution system'' to eliminate the 
only use of this undefined term in Part 192.
    Response: Part 192 defines ``distribution line'' but not 
``distribution system.'' So substituting ``distribution system'' for 
``distribution line'' in the present ``main'' definition and for 
``distribution center'' in the present ``transmission line'' definition 
would not necessarily add clarity to either definition. Also, by 
referring to ``mains,'' SIRRC's definition of ``main'' loops back on 
itself. Therefore, we are not proposing to adopt the SIRRC's 
suggestion.

2. Section 192.3, Definitions of Service Line and Service Regulator. 
(SIRRC Summary Report, p. 6)

    Recommendation. Adopt the following new and amended definitions to 
bring Part 192 in line with acceptable arrangements of service lines:
    [sbull] ``Customer meter'' means the meter that measures the 
transfer of gas from an operator to a consumer.
    [sbull] ``Service line'' means a distribution line that transports 
gas from a common source of supply to an individual customer, two 
adjacent or adjoining residential or small commercial customers, or to 
an aboveground meter header supplying up to ten residential or small 
commercial customer meters. A service line terminates 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.
    [sbull] ``Service regulator'' means the device on a service line 
which controls the pressure of gas delivered from a high pressure 
distribution system to the level at which it is provided to the 
customer. A service regulator may serve one customer meter, or up to 
ten customer meters grouped on an aboveground meter header.
    SIRRC. The committee suggested modification of the definitions as 
follows:
    [sbull] ``Customer meter'' means the meter that measures the 
transfer of gas from an operator to a consumer.
    [sbull] ``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 terminates 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.
    [sbull] ``Service regulator'' means the device on a service line 
which 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.
    Response. Although Sec.  192.3 already defines the term ``customer 
meter,'' the definition of this term is included in the definition of 
``service line.'' SIRRC's suggestion would merely move the ``customer 
meter'' definition to an alphabetical position in Sec.  192.3. Since 
``customer meter'' is used in part 192 in places other than the 
``service line'' definition, we agree that an alphabetical position is 
preferable. So we are proposing to amend Sec.  192.3 as SIRRC 
suggested.
    Under the part 192 definitions of ``service line'' and ``main,'' if 
an operator runs a single line from main to supply gas to two 
customers, the single line is itself a main because it is a common 
source of supply for more than one service line.\1\ Typically such 
single-line installations serve two or more adjacent single-family 
residences through branch lines connected to the single line. They also 
serve apartment buildings and shopping centers through meter manifolds, 
or meter headers.
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    \1\ Section 192.3 defines ``service line'' as ``a distribution 
line that transports gas from a common source of supply to (1) a 
customer meter or the connection to a customer's piping, whichever 
is farther downstream, or (2) the connection to a customer's piping 
if there is no customer meter.'' In addition, ``main'' is defined as 
``a distribution line that serves as a common source of supply for 
more than one service line.''
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    Because these single lines are more like service lines than mains--
their size is small, their pressure is low, and they are located on 
private property rather than under a public street or alley--many State 
pipeline safety agencies have granted waivers for the lines, permitting 
operators to treat them as service lines. Consequently, under most 
State waivers, the single lines may be designed, installed, operated, 
and maintained as service lines. They do not have to meet any part 192 
standard that applies strictly to mains. For example, Sec.  192.327(b) 
requires a minimum burial depth for mains (24 in) that is greater than 
the depth Sec.  192.361 requires for service lines (12 or 18 in). 
Single-line installations serving adjacent customers may also increase 
safety by minimizing connections to mains. These connections are 
susceptible to leaks and damage accidentally caused by street 
excavation activities.
    Since SIRRC's suggested definition of ``service line'' is 
consistent with State waivers we considered appropriate, we are 
proposing to amend Sec.  192.3 by revising the definition of ``service 
line'' as SIRRC suggested. Note, however, that the proposed definition 
uses the general term ``meter manifold'' instead of ``meter header or 
manifold.'' If adopted as final, the proposed definition would 
eliminate the need for similar waivers in the future.
    We are also proposing to adopt SIRRC's suggested definition of 
``service regulator.'' SIRRC's definition is

[[Page 68817]]

consistent with state waivers that distinguish regulators connected to 
customer meter manifolds from regulating stations that must be 
inspected under Sec.  192.739.
    We are particularly interested in receiving comments on how the 
term ``small commercial customers'' might be stated differently or 
defined to minimize potential confusion in identifying the customers 
involved. Would it be appropriate to consider a ``small commercial 
customer'' as a business that receives volumes of gas similar to the 
volumes that a residential customer receives?

3. Section 192.55(a)(2), Steel Pipe. (SIRRC Summary Report, p. 8)

    Recommendation. Delete Sec.  192.55(a)(2)(ii), which provides 
requirements for the use of new steel pipe manufactured before November 
12, 1970.
    SIRRC. The committee suggested that Sec.  192.55(a)(2)(ii) should 
not be deleted.
    Response. Although NAPSR initially thought Sec.  192.55(a)(2)(ii) 
was obsolete, several PS-124 commenters said the section should remain 
because operators have stockpiles of steel pipe manufactured before 
1970. The SIRRC Summary Report indicates operators continue to stock 
such pipe. We concur with SIRRC that Sec.  192.55(a)(2)(ii) should not 
be removed.

4. Section 192.65, Transportation of Pipe. (SIRRC Summary Report, p. 9)

    Recommendation. Delete Sec.  192.65(b), which provides requirements 
for the use of certain steel pipe transported by railroad before 
November 12, 1970.
    SIRRC. The committee agreed that Sec.  192.65(b) should not be 
deleted.
    Response. Although NAPSR initially thought Sec.  192.55(b) was 
obsolete, several PS-124 commenters said they had stockpiled pipe 
manufactured before 1970. In addition, the SIRRC Summary Report 
indicates that operators still have this pipe and that it may have been 
transported by railroad. We concur with the SIRRC's suggestion.

5. Section 192.123, Design Limitations for Plastic Pipe. (SIRRC Summary 
Report p. 10)

    Recommendation. Delete the second sentence of Sec.  
192.123(b)(2)(i), which allows plastic pipe manufactured before May 18, 
1978, and strength rated at 73 [deg]F to be used at temperatures up to 
100 [deg]F.
    SIRRC. The committee agreed that the second sentence of Sec.  
192.123(b)(2)(i) should be deleted.
    Response. NAPSR thought the second sentence of Sec.  
192.123(b)(2)(i) was obsolete. However, the PS-124 comments indicated 
that several utilities had inventories of plastic pipe manufactured 
before May 18, 1978, that they intended to use as replacement pipe. In 
contrast, the SIRRC Summary Report states that the committee members 
were unaware of any pre-1978 plastic pipe in operators' stocks. 
Moreover, the committee members had reservations about using plastic 
pipe of that vintage.
    Assuming the SIRRC Summary Report generally reflects the present 
status of operators' stocks of plastic pipe, we are proposing to delete 
the second sentence of Sec.  192.123(b)(2)(i) as obsolete. If this 
proposal were adopted as final, any stockpiled pre-1978 thermoplastic 
pipe whose long-term hydrostatic strength was determined at 73 [deg]F 
could not be used above that temperature. We are particularly 
interested in hearing from industry commenters whether they still have 
any stockpiles of this pipe that they plan to use at temperatures above 
73 [deg]F.

6. Section 192.197(a), Control of the Pressure of Gas Delivered From 
High-pressure Distribution Systems. (SIRRC Summary Report, p. 11)

    Recommendation. In Sec.  192.197(a), change ``under 60 psig'' to 
``60 psig or less.''
    SIRRC. The committee agreed that Sec.  192.197(a) should be changed 
as NAPSR recommended.
    Response. Section 192.197(a) provides that in distribution systems 
operated ``under 60 psig (414 kPa) gage,'' if service regulators meet 
certain criteria, no other pressure limiting devices are required. 
However, Sec.  192.197(b) states that if those criteria are not met in 
systems operating at ``60 psig (414 kPa) gage, or less,'' additional 
pressure control is required. Thus there is a 1 psi discrepancy between 
these two sections. We agree with SIRRC that Sec.  192.197(a) should be 
in sync with Sec.  192.197(b), particularly since Sec.  192.197(c) 
applies to systems in which the operating pressure ``exceeds 60 psig 
(414 kPa) gage.'' Therefore, we are proposing to change Sec.  
192.197(a) as NAPSR recommended.

7. Section 192.203(b)(2), Instrument, Control, and Sampling Pipe and 
Components. (SIRRC Summary Report, p. 12)

    Recommendation. In Sec.  192.203(b)(2), change ``takeoff line'' to 
``instrument, control, and sampling line'' to clarify the lines on 
which a shutoff valve must be installed.
    SIRRC. The committee agreed the recommended change to Sec.  
192.203(b)(2) is not needed.
    Response. In Docket PS-124, we modified Sec.  192.203(b)(2) by 
excepting takeoff lines that can be isolated from sources of pressure 
by other valving. The SIRRC Summary Report indicates this exception 
resolved NAPSR's concern about Sec.  192.203(b)(2). Therefore, we are 
adopting the SIRRC consensus that the recommended rulemaking action is 
not needed.

8. Section 192.225(a), Welding: General. (SIRRC Summary Report, p. 13)

    Recommendation. Change Sec.  192.225(a) to require qualification of 
welding procedures according to ``American Petroleum Institute (API), 
American Society of Mechanical Engineers (ASME), or other standards.''
    SIRRC. The committee agreed the recommended change is needed. 
However, it suggested the term ``other standards'' should be changed to 
``other accepted pipeline welding standards.''
    Response. We proposed to adopt the core of NAPSR's recommendation 
in the proceeding called ``Periodic Updates to Pipeline Safety 
Regulations (1999)'' (56 FR 15290; Mar. 22, 2000). We proposed to amend 
Sec.  192.225(a)to require operators to qualify welding procedures 
under either Section 5 of API 1104, ``Welding of Pipelines and Related 
Facilities,'' or Section IX of the ASME Boiler and Pressure Vessel 
Code. However, our proposal did not include allowing the use of ``other 
accepted pipeline welding standards,'' as SIRRC suggested, because we 
are not aware of any other generally accepted pipeline welding 
standards.

9. Section 192.241(a), Inspection and Test of Welds. (SIRRC Summary 
Report, p. 14)

    Recommendation. Change Sec.  192.241(a) to require that visual 
inspection of welding be conducted ``by an inspector qualified by 
appropriate training and experience.''
    SIRRC. The committee agreed the recommended change is needed. 
However, it suggested the term ``inspector'' should be changed to 
``person.''
    Response. In the proceeding called ``Periodic Updates to Pipeline 
Safety Regulations (1999)'' (56 FR 15290; Mar. 22, 2000), we proposed 
to amend Sec.  192.241(a) as NAPSR recommended. Although we overlooked 
SIRRC's suggestion to use ``person'' instead of ``inspector,'' we will 
consider the suggestion in developing the final rule.

[[Page 68818]]

10. Section 192.285(c) and (d), Plastic Pipe: Qualifying Persons to 
Make Joints. (SIRRC Summary Report, p. 15)

    Recommendation. In Sec.  192.285, revise paragraph(c) to require 
that persons who join plastic pipe requalify annually to make joints. 
Also, revise paragraph (d) to require that operators maintain certain 
records for use in monitoring personnel qualifications.
    SIRRC. The committee did not agree that NAPSR's recommended rule 
changes were needed. However, the committee did agree that in Sec.  
192.285(d) the term ``his'' should be replaced by a term that is not 
gender-specific.
    Response. NAPSR was concerned that while most newly installed 
distribution lines are made of plastic pipe, the qualification 
requirements for persons who join plastic pipe are less stringent than 
the qualification requirements for persons who weld steel pipe. NAPSR 
felt the plastic pipe joining and welder qualification requirements 
should be comparable because the consequences of failure of a plastic 
pipe joint may be just as severe as the consequences of failure of a 
welded joint.
    We do not believe NAPSR's reasoning is sufficient to justify 
stronger plastic pipe joining requirements. The skill needed for 
joining plastic pipe is so much simpler than the skill needed for 
welding steel pipe that the welding requirements cannot reasonably 
serve as a basis for establishing more stringent plastic pipe joining 
requirements. Therefore, we are not proposing to adopt NAPSR's 
recommended rule changes.
    It is worth noting, though, that after SIRRC completed it's report, 
we published new qualification of personnel rules in Subpart N of Part 
192. The competency evaluations required by these rules should enhance 
the qualifications of persons who make plastic pipe joints.
    Section 192.285(d) now uses the term ``his.'' As SIRRC suggested, 
we are proposing to change this term to ``the operator's.''

11. Section 192.311, Repair of Plastic Pipe. (SIRRC Summary Report, p. 
18)

    Recommendation. Remove the requirement from Sec.  192.311 that a 
``patching saddle'' must be used to repair harmful damage to new 
plastic pipelines if the damaged pipe is not removed.
    SIRRC. The committee agreed the recommended change is needed.
    Response. We concur with NAPSR that the meaning of ``patching 
saddle'' is unclear, although we have stated the term implies a plastic 
saddle adhered to pipe. Still, there are various means available to 
effect safe repairs, and we do not think it's necessary to limit the 
method of repair. Section 192.703(b) would forbid the use of any method 
that would result in an unsafe condition. So we are proposing to amend 
Sec.  192.311 as NAPSR recommended.

12. Section 192.321(e), Installation of Plastic Pipe; Sec.  192.361(g), 
Service Lines: Installation. (SIRRC Summary Report, p. 19)

    Recommendation. To prevent underground plastic pipe from being 
damaged by electrically charged tracer wire and to maintain wire 
integrity, require separation between pipe and wire, where practical, 
and require that tracer wire be protected against corrosion.
    SIRRC. The committee agreed to accept NAPSR's recommendation. It 
also agreed that Sec.  192.321, which applies to mains and transmission 
lines, and Sec.  192.361, which applies to service lines, should be 
changed as follows:
    [sbull] Revise Sec.  192.321(e) to read as follows:
    (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 shall not be wrapped around the pipe and 
contact with the pipe shall be minimized. Tracer wire or other metallic 
elements installed for pipe locating purposes shall be resistant to 
corrosion damage, either by use of coated copper wire or by other 
means.
    [sbull] Establish Sec.  192.361(g) to match proposed Sec.  
192.321(e).
    Response. Although there have been only a few instances where 
highly charged tracer wire damaged buried plastic pipe, we believe 
separating wire from pipe wherever practical is a reasonable safeguard. 
It is also reasonable that tracer wire or other metallic means of pipe 
locating be resistant to corrosion. Therefore, we are proposing to 
adopt SIRRC's consensus by revising Sec.  192.321(e) and adding Sec.  
192.361(g) as set forth below in the proposed amendments section of 
this notice.
    We recognize that continuous separation may not be ensured when 
wire and pipe are installed together in the same hole made by 
trenchless technology. In fact, in such cases the wire is often 
randomly taped to the pipe to control separation during installation. 
The proposed requirement to minimize contact with the pipe should not 
deter this common installation practice.
    Note that part 192 does not now require that underground plastic 
service lines have a means for locating the lines. However, operators 
commonly use tracer wire for this purpose as they do under existing 
Sec.  192.321(e) for locating underground plastic mains and 
transmission lines.

13. Section 192.353(a), Customer Meters and Regulators: Location. 
(SIRRC Summary Report, p. 21)

    Recommendation. Amend Sec.  192.353(a) to emphasize that vehicular 
damage is a type of damage from which meters and service regulators 
must be protected.
    SIRRC. Although the committee members agreed that the existing rule 
implicitly requires protection from vehicular damage, they did not 
agree on the need to emphasize this type of damage. Industry members 
thought emphasizing vehicular damage would cause more disputes with 
government inspectors over what level of protection is needed.
    Response. In enforcing Sec.  192.353(a), our position has been that 
the provision that meters and service regulators must be protected from 
``corrosion and other damage'' requires reasonable protection from 
vehicular damage where warranted. SIRRC's Summary Report supports this 
position. Furthermore, AGA's ``Guide for Gas Transmission and 
Distribution Piping Systems,'' which advises operators on compliance 
with Part 192, recognizes this requirement. It states with regard to 
Sec.  192.353(a) that if the potential for vehicular damage is evident, 
the meter or service regulator should be protected or an alternate 
location selected.
    NAPSR reported that its members had found meter sets that were 
damaged by vehicles or were at serious risk of such damage. When this 
information is considered in light of the industry's apparent 
understanding of the present rule, it indicates some operators may have 
been lax in providing needed protection. Emphasizing vehicular damage 
in the present rule should at least cause operators to pay more 
attention to the problem and perhaps reduce the risk of damage. So we 
are proposing to adopt NAPSR's recommendation by amending Sec.  
192.353(a) to emphasize vehicular damage.
    Although Sec.  192.353(a) affects design and does not apply to 
pipelines constructed before it went into effect, protection from 
vehicular damage is also a safety concern on earlier constructed 
pipelines. These pipelines, however, are subject to the general 
maintenance standard of Sec.  192.703(b), which requires operators to 
correct any pipeline that becomes unsafe. If the safety of a meter set 
is jeopardized by

[[Page 68819]]

vehicular traffic, the operator would have to take action under Sec.  
192.703(b) to correct the problem.

14. Section 192.457(b)(3), External Corrosion Control: Buried or 
Submerged Pipelines Installed Before August 1, 1971; 192.465(e), 
External Corrosion Control: Monitoring. (SIRRC Summary Report, p. 23)

    Recommendation. Amend Sec. Sec.  192.457(b) and Sec.  192.465(e) to 
clarify the meaning of ``electrical survey'' and what circumstances 
make an electrical survey ``impractical.'' Also, require operators to 
consider all relevant information when using an alternative to an 
electrical survey.
    SIRRC. The committee concluded that electrical surveys are seldom 
used on distribution systems, so there is no advantage to requiring 
electrical surveys as a preferred corrosion inspection method on 
distribution systems. SIRRC further concluded that if electrical 
surveys are not used, all available information should be used to 
determine if active corrosion exists. The committee agreed that the 
second sentence of Sec.  192.457(b), as it relates to distribution 
lines, and Sec.  192.465(e) should be changed to read as follows:
    [sbull] Sec.  192.457(b):
    The operator shall determine the areas of active corrosion by 
electrical survey or by analysis and review of the pipeline condition. 
Analysis and review shall include, but is not limited to, leak repair 
history, exposed pipe condition reports, and the pipeline environment. 
For the purpose of this section, an electrical survey is a series of 
closely spaced pipe-to-soil readings over a pipeline which are 
subsequently analyzed to identify any locations where a corrosive 
current is leaving the pipe.
    [sbull] Sec.  192.465(e):
    (i) For transmission pipelines, after the initial evaluation 
required by paragraphs (b) and (c) of Sec.  192.455 and paragraph (b) 
of Sec.  192.457, each operator shall, 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 shall determine the 
areas of active corrosion by electrical survey, or where an electrical 
survey is impractical, by analysis and review of the pipeline 
condition. Analysis and review shall include, but is not limited to, 
leak repair history, exposed pipe condition reports, and the pipeline 
environment.
    (ii) For distribution pipelines, after the initial evaluation 
required by paragraphs (b) and (c) of Sec.  192.455 and paragraph (b) 
of Sec.  192.457, each operator shall, 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 shall determine the 
areas of active corrosion by electrical survey or by analysis and 
review of the pipeline condition. Analysis and review shall include, 
but is not limited to, leak repair history, exposed pipe condition 
reports, and the pipeline environment.
    (iii) For the purpose of this section, an electrical survey is a 
series of closely spaced pipe-to-soil readings over a pipeline which 
are subsequently analyzed to identify any locations where a corrosive 
current is leaving the pipe.
    SIRRC also agreed that ``pipeline environment'' refers to whether 
soil resistivity is high or low, wet or dry, contains contaminants that 
may promote corrosion, or has any other known condition that might 
influence the probability of active corrosion.
    Response. We recently revised the corrosion control regulations for 
hazardous liquid and carbon dioxide pipelines in 49 CFR part 195 
(Docket RSPA-97-2762; 66 FR 66994; Dec. 27, 2001). In doing so, we 
relied on SIRRC's suggestion on monitoring unprotected gas transmission 
lines as a basis for revising the requirement to monitor unprotected 
pipe (see 49 CFR 195.573(b)). Because we believe SIRRC's approach is 
reasonable for both transmission and distribution lines, we are 
proposing to adopt the SIRRC suggestion on monitoring these lines by 
revising Sec.  192.465(e) as set forth below in the proposed amendments 
section of this notice.
    However, rather than change the second sentence of Sec.  192.457(b) 
as SIRRC suggested, we are proposing to delete the second sentence 
because we think it's unnecessary. This sentence, which is repeated in 
Sec.  192.465(e), is no longer needed in Sec.  192.457(b) because the 
time for completing the initial evaluation of the need for corrosion 
control required by Sec.  192.457(b) has expired. All subsequent 
evaluations are required by Sec.  192.465(e). Also, we are proposing to 
move the definition of ``active corrosion,'' now in Sec.  192.457(c), 
to Sec.  192.465(e).

15. Section 192.459, External Corrosion Control: Examination of Buried 
Pipeline When Exposed. (SIRRC Summary Report, p. 27)

    Recommendation. Amend Sec.  192.459 to clarify that when an 
operator examines the exposed portion of a buried pipeline, the 
operator must determine the condition of the coating and keep a record 
of the condition under Sec.  192.491.
    SIRRC. The committee agreed that records of coating condition are 
important in evaluating the overall condition of a pipeline, and that 
this information helps meet the continuing surveillance and active 
corrosion rules. The committee suggested that Sec.  192.459 be revised 
to read as follows:

    Whenever an operator has knowledge that any portion of a buried 
pipeline is exposed, the exposed portion must be examined to 
determine the condition of the coating, or if the pipeline is bare 
or the coating is deteriorated, the exterior condition of the pipe. 
A record of the examination results shall be made in accordance with 
Sec.  192.491(c). If external corrosion is found, remedial action 
must be taken to the extent required by Sec.  192.483 and the 
applicable paragraphs of Sec. Sec.  192.485, 192.487, or 192.489.

    Response. In light of NAPSR's recommendation and an earlier 
recommendation by the National Transportation Safety Board on 
inspecting exposed pipe, we revised Sec.  192.459 to require that 
operators determine the extent of any corrosion that is found on the 
exposed portion of a pipeline (64 FR 56981, Oct. 22, 1999). At a 
minimum, the present rule requires that operators inspect exposed 
pipelines to see if the coating on coated pipe has deteriorated. In 
addition, Sec.  192.491(c) requires a record of each inspection ``in 
sufficient detail to demonstrate the adequacy of corrosion control 
measures or that a corrosive condition does not exist.'' Thus we have 
essentially adopted the SIRRC consensus, because the combination of 
Sec.  192.459 and Sec.  192.491(c) adequately addresses the need to 
examine and record the condition of coating on exposed coated pipe.

16. Section 192.467(d), External Corrosion Control: Electrical 
Isolation (SIRRC Summary Report, p. 28)

    Recommendation. Amend Sec.  192.467(d) to require annual electrical 
tests on casings to determine if there is contact with the encased 
pipe. Also, require remedial action according to Recommendation No. 19 
if contact is found.
    SIRRC. The committee did not reach agreement on the need to conduct 
annual tests for shorted casings, although consensus was reached on 
remedial action as discussed below regarding Recommendation No. 19. 
Industry's position on annual testing was that separate tests on 
casings are unnecessary as long as the pipe potential is above -850Mv. 
NAPSR's position was that because a shorted

[[Page 68820]]

casing shields encased pipe from protective current, the encased pipe 
can corrode regardless of the potential of pipe outside the casing.
    Response. A large majority of PS-124 commenters opposed NAPSR's 
recommendation on the ground that no correlation had been found between 
shorted casings and corrosion of the encased pipe. One commenter 
alleged that the purpose of Sec.  192.467(c), which requires isolation 
of gas pipe from casings, is to maintain protective current levels.
    Also, several commenters addressed the shorted casing issue in 
response to our San Antonio meeting notice. Five persons said shorts 
should be cleared because using more protective current to offset the 
short could have adverse effects. Two other commenters said that 
clearing shorts can be costly if the line must be taken out of service 
or replaced, and that there is no consensus on the adequacy of other 
remedial measures. Another San Antonio commenter suggested the present 
electrical isolation requirement of Sec.  192.467(c) is not needed 
since cathodic protection has to meet the part 192 criteria for 
adequacy. In this regard, AGA's Gas Piping Technology Committee (GPTC) 
has submitted a rulemaking petition to rescind the requirement to 
isolate gas pipe from metallic casings, arguing there are no safety 
benefit from clearing shorted casings.
    Considering the conflicting opinions on the need to clear shorted 
casings to prevent pipe corrosion, we have decided not to propose to 
adopt NAPSR's recommendation for annual testing. Instead we will 
consider the recommendation in a separate rulemaking proceeding called 
``Pipeline Safety: Controlling Corrosion on Gas Pipelines'' (RIN 2137-
AD63). In that proceeding, we will examine the need to change part 192 
to improve the industry's corrosion control practices in light of new 
technology and the new requirements for hazardous liquid and carbon 
dioxide pipelines in 49 CFR part 195.
    Deferring the recommendation also will give us time to gather more 
information on the shorted casing issue. We are particularly interested 
in receiving comments from anyone who has empirical data on the 
relation of shorted casings to pipe corrosion.

17. Section 192.475(c), Internal Corrosion Control: General. (SIRRC 
Summary Report, p. 29)

    Recommendation. Amend Sec.  192.475(c) to express the permissible 
level of hydrogen sulfide in parts-per-million as well as grains.
    SIRRC. The committee agreed no further rulemaking action is needed.
    Response. The PS-124 Final Rule included NAPSR's recommended change 
to Sec.  192.475(c).

18. Section 192.479, Atmospheric Corrosion Control: General. (SIRRC 
Summary Report, p. 30)

    Recommendation. Require all aboveground pipelines exposed to the 
atmosphere to meet the same atmospheric corrosion control and remedial 
requirements, no matter when the pipeline was installed.
    SIRRC. The resolution of the committee was that all exposed 
aboveground pipe should be subject to the same atmospheric protection 
standards. The committee agreed that Sec.  192.479 should be revised to 
read as follows, and explained that ``active corrosion'' does not 
include non-damaging corrosive films:
    (a) Each aboveground pipeline or portion of a pipeline that is 
exposed to the atmosphere must be cleaned and either coated or jacketed 
with a material suitable for the prevention of atmospheric corrosion. 
An operator need not comply with this paragraph, if the operator can 
demonstrate by test, investigation, or experience in the area of 
application that active corrosion does not exist.
    (b) If active corrosion is found on an aboveground pipeline or 
portion of pipeline, the operator shall--
    (1) take prompt remedial action consistent with the severity of the 
corrosion to the extent required by the applicable paragraphs of 
Sec. Sec.  192.485, 192.487, or 192.489; and
    (2) clean and either coat or jacket the areas of atmospheric 
corrosion with a material suitable for the prevention of atmospheric 
corrosion.
    Response. Section 192.479 prescribes atmospheric protection 
requirements according to the date of pipeline installation. Pipelines 
installed after July 31, 1971, must be entirely protected from 
atmospheric corrosion, except where the operator can demonstrate that a 
corrosive atmosphere does not exist. In contrast, pipelines installed 
before August 1, 1971, need only be protected where atmospheric 
corrosion has progressed to the point that remedial action is required 
under Sec.  192.485, Sec.  192.487, or Sec.  192.489. Periodic 
monitoring to determine the need for remedial action is required by 
Sec.  192.481.
    As previously stated, we recently revised the corrosion control 
regulations in 49 CFR part 195 governing hazardous liquid and carbon 
dioxide pipelines. The old rule on protection from atmospheric 
corrosion (Sec.  195.416(i)) required full protection of all pipelines 
exposed to the atmosphere, regardless of the date of installation. 
Based on San Antonio comments that the old rule was overly burdensome, 
we revised the rule to allow operators to avoid coating pipelines they 
demonstrate will have either a light surface oxide (a non-damaging 
corrosion film) or atmospheric corrosion that will not affect safe 
operation before the next scheduled inspection (Sec.  195.581).
    We believe Sec.  195.581 is consistent with SIRRC's suggested 
change of Sec.  192.479. Section 195.581 requires the same level of 
protection for old and new pipelines. Also the exceptions for a light 
surface oxide and corrosion that will not need remedial action before 
the next scheduled inspection are equivalent to SIRRC's exception of 
non-active corrosion. One of our goals in revising the Part 195 
corrosion control regulations was to establish similar corrosion 
control requirements for gas and liquid pipelines wherever appropriate. 
Therefore, in keeping with this goal, we are proposing to use Sec.  
195.581 instead of SIRRC's suggestion as the basis for changing Sec.  
192.479. The existing standards for remedial action, Sec. Sec.  
192.485, 192.487, and 192.489, will provide a benchmark for any 
demonstrations that protection is not required before the next 
inspection.
    NAPSR did not recommend any change to the periodic monitoring 
requirements of Sec.  192.481. These requirements are comparable to the 
monitoring requirements for hazardous liquid and carbon dioxide 
pipelines under Sec.  195.583. Both sections require monitoring for 
atmospheric corrosion at least every 3 years for onshore pipelines and 
every year for offshore pipelines. And both sections require remedial 
action if harmful atmospheric corrosion is found. However, Sec.  
195.583 specifies particular pipeline features, such as soil-to-air 
interfaces, that must be inspected, and specifies what remedial action 
to take. Although these differences are minor, we think the monitoring 
requirements for gas and hazardous liquid pipelines should be in 
accord. Therefore, we are proposing to amend Sec.  192.481 to comport 
with Sec.  195.583.
    PS-124 commenters representing industry largely objected to NAPSR's 
recommendation to treat old and new pipelines alike. They feared they 
would have to fully protect all pre-August 1971 pipelines regardless of 
whether harmful corrosion was present. However, there is no basis for 
this concern under proposed Sec.  192.479. Operators would not have to 
protect any pre-1971 pipeline or portion of pipeline for

[[Page 68821]]

which the operator demonstrates by test, investigation, or experience 
appropriate to the environment of the pipeline that corrosion will only 
be a light surface oxide or not affect safe operation before the next 
scheduled inspection. We believe this approach is consistent with the 
present rule.

19. Section 192.483(d), Remedial Measures: General. (SIRRC Summary 
Report, p. 32)

    Recommendation. Specify what operators must do to protect carrier 
pipe when a shorted casing cannot be cleared.
    SIRRC. The committee agreed that Sec.  192.483(d) should be 
established to read as follows:
    (d) If it is determined that a casing is electrically shorted to a 
pipeline, the operator shall:
    (1) Clear the short, if practical;
    (2) Fill the casing with a corrosion inhibiting material;
    (3) Monitor for leakage with leak detection equipment at least once 
each calendar year with intervals not exceeding 15 months; or
    (4) Conduct an initial inspection with an internal inspection 
device capable of detecting external corrosion in a cased pipeline, and 
repeat at least every 5 years at intervals not exceeding 63 months.
    Response. As stated above in response to Recommendation No. 16, 
there is conflicting information on the need to clear shorted casings. 
Therefore, we are not now proposing to adopt SIRRC's suggested options 
for dealing with shorted casings. Instead, as with Recommendation No. 
16, we will consider this recommendation in a separate rulemaking 
proceeding called ``Pipeline Safety: Controlling Corrosion on Gas 
Pipelines'' (RIN 2137-AD63).

20. Section 192.483(e), Remedial Measures: General. (SIRRC Summary 
Report, p. 34)

    Recommendation. Amend Sec.  192.483 to refer to appropriate 
consensus standards that are to be used in determining the remaining 
strength of corroded pipe.
    SIRRC. The committee agreed that further rulemaking action is not 
needed.
    Response. The Final Rule in Docket PS-124 covered NAPSR's 
recommendation in an amendment to Sec.  192.485(c). Thus, we agree with 
SIRRC that further action is not needed.

21. Section 192.489(b), Remedial Measures: Cast Iron and Ductile Iron 
Pipe. (SIRRC Summary Report, p. 35)

    Recommendation. Clarify that internal sealing of graphitized pipe 
is not a method of strengthening the pipe.
    SIRRC. The committee agreed that the problem of graphitization 
should be addressed case-by-case rather than by changing Sec.  192.489 
as NAPSR recommended.
    Response. New technology may result in liners that strengthen as 
well as seal pipe. Therefore, we agree with SIRRC that Sec.  192.489(b) 
should not be changed as NAPSR recommended.

22. Sections 192.505(a) and 192.507, Test Requirements. (SIRRC Summary 
Report, p. 36)

    Recommendation. Amend Sec. Sec.  192.505 and 192.507 to clarify 
that the test pressure must be high enough to substantiate the maximum 
allowable operating pressure (MAOP) under Sec.  192.619(a)(2)(ii).
    SIRRC. The committee did not reach an agreement on this 
recommendation. NAPSR members contended some operators have not 
substantiated MAOP because Sec. Sec.  192.505 and 192.507 do not 
specify a minimum test pressure. On the other hand, industry members 
thought that because Sec.  192.503(a)(1) already requires that pressure 
tests substantiate MAOP under Sec.  192.619, there is no need to repeat 
the requirement in Sec. Sec.  192.505 and 192.507.
    Response. We addressed this issue once before. In 1988 we amended 
Sec.  192.503(a)(1) specifically to indicate that Sec.  192.619 
prescribes the minimum test pressure needed to substantiate MAOP (53 FR 
1635). We think this earlier action adequately clarified the minimum 
test pressures, and no further action is needed.

23. Sections 192.509(b) and 192.511(b) and (c), Test Requirements. 
(SIRRC Summary Report, p. 37)

    Recommendation. To establish consistent leak test pressures for 
mains and service lines, require that non-plastic service lines 
operated at less than 1 psig be tested to at least 10 psig. Also, 
require that each main and service line operated at 1 psig or more be 
tested to 90 psig or 1.5 times the intended operating pressure, 
whichever is higher.
    SIRRC. The committee did not reach a consensus on this 
recommendation. Industry members were concerned that additional 
equipment would be needed to test above 90 psig, and that testing 
existing service lines at higher pressures (as when service is 
reinstated or connected to a new main) could cause failures. NAPSR 
countered that operators could use plastic pipe test equipment, and 
that a test failure indicates the line is unsafe.
    Response. NAPSR felt the minimum leak test pressures prescribed by 
Sec. Sec.  192.509(b) and 192.511(b) and (c) for mains and service 
lines should be the same because mains and service lines are operated 
together. NAPSR also felt the resulting safety factors should not 
diminish as operating pressures increase, as they do under the present 
rules. Many PS-124 commenters, including some operators, agreed with 
NAPSR. However, AGA and other operators said there is no need to leak 
test steel mains and service lines operating at less than 100 psig at 
1.5 times operating pressure. These commenters argued that the purpose 
of leak tests is not to assure the pipeline is unlikely to fail at 
operating pressure, but to verify that the pipeline does not leak.
    The regulatory history does not explain why minimum leak test 
pressures under Sec. Sec.  192.509(b) and 192.511(b) and (c) are not 
consistent. Nevertheless, lack of consistency, by itself, does not 
justify additional or more stringent test requirements. A link between 
inconsistency and safety would be needed, and NAPSR did not establish 
such a link. Also, because only tests for leaks rather than pipeline 
integrity are at issue, we do not think safety factors are relevant to 
determining if the present leak test pressures are appropriate. 
Therefore, we are not proposing to adopt NAPSR's recommendation.

24. Section 192.517, Records. (SIRRC Summary Report, p. 39)

    Recommendation. To aid compliance investigations, amend Sec.  
192.517 to require that operators keep records of leak tests done under 
Sec.  192.509 for pipelines to operate below 100 psig, of leak tests 
done under Sec.  192.511 for service lines, and of leak tests done 
under Sec.  192.513 for plastic pipelines.
    SIRRC. The committee disagreed about what information is needed in 
leak test records. Also, industry members were concerned that 
distribution operators would have to keep a very large volume of 
individual records of limited use.
    Response. Section 192.517 requires operators to record certain 
information about pressure tests done under Sec. Sec.  192.505 and 
192.507 to qualify steel pipelines to operate at 100 psig or more. 
NAPSR recommended that we extend this requirement to other pipelines 
that are pressure tested for leaks. While a few PS-124 commenters 
supported the recommendation, most did not. Those who opposed the 
recommendation generally argued that since leak tests are not as 
significant as tests done under Sec. Sec.  192.505 and 192.507, it is 
unnecessary to maintain the same information about both types of tests.

[[Page 68822]]

    Without appropriate records, government inspection personnel have a 
difficult job of determining if required leak tests were indeed done. 
They may have to interview witnesses or draw inferences from related 
information. On the other hand, government's need for records must be 
weighed against the burden on operators to produce and maintain the 
records. By and large, PS-124 commenters and SIRRC industry members did 
not object to keeping records of leak tests. In fact, the SIRRC Summary 
Report states that keeping some type of leak test record is a common 
industry practice. It was the extent and volume of the records that 
SIRRC's industry members found objectionable.
    In our view, NAPSR's recommended leak test records would be too 
burdensome, because the safety significance of leak tests is less than 
that of pressure tests done to establish the MAOP of pipelines 
operating above 100 psig. At the same time, it seems that industry's 
voluntary practices may satisfy the need for records to demonstrate 
compliance with leak test requirements. Therefore, while we are not 
proposing to adopt NAPSR's recommendation, we are proposing to amend 
Sec.  192.517 to require that operators maintain a record of each test 
required by Sec. Sec.  192.509, 192.511, and 192.513 for at least 5 
years. This proposal should accommodate the industry's various 
voluntary recordkeeping practices, and allow time for government 
inspectors to view the records. The proposed rule would apply to leak 
tests done after the rule takes effect.

25. Section 192.553, Uprating: General Requirements; Sec.  192.557 
Uprating: Steel Pipelines to a Pressure That Will Produce a Hoop Stress 
Less Than 30% of SMYS: Plastic, Cast Iron, and Ductile Iron Pipelines. 
(SIRRC Summary Report, P. 41)

    Recommendation. Clarify that Sec.  192.557 does not allow MAOP to 
be increased without substantiation by pressure testing.
    SIRRC. The committee did not reach a resolution on this 
recommendation. Industry members were concerned that NAPSR's 
recommended changes to Sec.  192.557 would unintentionally prohibit the 
uprating of some pipelines that could be uprated under the present 
rule. However, the committee did agree that in Sec.  192.553(d) the 
reference to ``this part'' should be changed to ``Sec. Sec.  192.619 
and 192.621'' to specify the sections that limit MAOP.
    Response. We decided not to propose to adopt NAPSR's recommendation 
because we feel the requirement to base any increase in MAOP on a test 
pressure is clear under Sec.  192.553(d). This section limits any 
increase in MAOP to the maximum allowed for new pipelines, which, under 
Sec.  192.619(a)(2)(ii), must be based on a pressure test. However, we 
are proposing to adopt SIRRC's suggested change to clarify Sec.  
192.553(d).

26. Section 192.607, Determination of Class Location and Confirmation 
of Maximum Allowable Operating Pressure. (SIRRC Summary Report, p. 43)

    Recommendation. Remove expired compliance deadlines from Sec.  
192.607.
    SIRRC. The committee agreed the recommendation was no longer 
needed.
    Response. The Final Rule in PS-124 repealed Sec.  192.607.

27. Section 192.614(b)(2), Damage Prevention Program. (SIRRC Summary 
Report, p. 44)

    Recommendation. Require that operators notify the public and known 
excavators about excavation damage prevention programs at least once a 
year.
    SIRRC. The committee agreed to defer the recommendation to RSPA's 
damage prevention improvement team. (The work of that team has been 
assumed by the Dig Safely division of the Common Ground Alliance, a 
nonprofit organization that promotes best practices in damage 
prevention.)
    Response. The present rule requires operators to notify the public 
and known excavators ``as often as needed'' to make them aware of the 
operator's program. This open-ended frequency permits operators to vary 
the timing and number of notices to recipients according to the results 
of their programs. Presumably fewer notices would be needed in an area 
where the incidence of excavation damage is low or dropping. 
Conversely, more would be needed if the incidence is high or 
increasing. Although NAPSR felt the rule should prescribe a minimum 
rate of notification, it did not explain why annual notification is 
appropriate in all situations. And we do not have data to support such 
an across-the-board rule change. Nevertheless, we think NAPSR's concern 
is mitigated by the authority of RSPA and state agencies under Sec.  
192.603(c) to require operators to modify their damage prevention 
procedures on a case-by-case basis as needed for safety. Meanwhile, we 
are working with the Common Ground Alliance to help operators improve 
their public education programs. If the need for rulemaking on 
notification frequency becomes apparent as a result of that effort, we 
will propose the necessary rule changes.

28. Section 192.615(a)(3)(i), Emergency Plans. (SIRRC Summary Report, 
p. 45)

    Recommendation. Amend Sec.  192.615(a)(3)(i) to require that 
operators' procedures for handling emergencies provide for prompt and 
effective response to reports of gas odor inside or near buildings.
    SIRRC. The committee did not reach consensus on the recommended 
change to Sec.  192.615(a)(3)(i), because many operators consider gas-
odor reports to be potential, but not actual, emergencies. Instead, the 
committee agreed that operating and maintenance manuals under Sec.  
192.605(b) are a better place for procedures on responding to gas-odor 
reports.
    Response. We agree that not all reports of gas odor indicate that 
gas has actually been detected. Some reports may merely indicate that 
someone smells what is thought to be gas but which upon investigation 
cannot be confirmed as gas. If operators had to treat all reports of 
gas odor as emergencies, their ability to respond to true emergencies 
might decline. Thus we are not proposing to adopt NAPSR's 
recommendation.
    Regardless of whether a gas odor report is an emergency, both PS-
124 commenters and SIRRC recognized the need for prompt investigation 
of gas odor reports to determine if a hazardous situation exists. We 
believe that by and large operators respond promptly to gas odor 
reports and have procedures for doing so. Nevertheless, to insure that 
operators have adequate procedures for responding promptly to gas odor 
reports, we are proposing to adopt SIRRC's suggested alternative by 
establishing Sec.  192.605(b)(11). Because some operators may prefer to 
apply their emergency procedures to all reports of gas odor, the 
proposed rule allows them to do so.

29. Section 192.625 (f), Odorization of Gas. (SIRRC Summary Report, p. 
47)

    Recommendation. Require that operators sample gas to assure proper 
odorant concentration at least six times a year with an instrument 
capable of determining the percentage of gas in air.
    SIRRC. The committee did not agree on the frequency of sampling. 
Industry members wanted to maintain the flexibility of the current 
rule, which allows operators to determine frequency based on need. 
NAPSR members wanted to add certainty to the rule by requiring a 
sampling frequency that is in keeping with common practice.

[[Page 68823]]

    Nevertheless, the members did agree the rule should require use of 
an instrument, although they recognized that sampling for odorant 
concentration could not be done without an instrument. They also agreed 
the master meter exception should be relocated to minimize the 
potential for confusion over the acceptability of using ``sniff'' 
tests.
    Response. The present rule requires operators to conduct periodic 
sampling to assure the proper concentration of odorant. However, 
operators of master meter systems (which exist mainly in mobile home 
parks and multifamily housing) do not have to conduct sampling if the 
operator verifies the system receives properly odorized gas and 
performs ``sniff'' tests to confirm the presence of odorant at the ends 
of the system.
    NAPSR intended its recommendation to address two concerns. The 
first was that some operators, other than master meter operators, used 
``sniff'' tests rather than instruments to determine odorant 
concentration. The second was that the required sampling frequency is 
vague. Regarding the first concern, both PS-124 commenters and SIRRC 
recognized that the present sampling requirement cannot be satisfied 
without using an appropriate test instrument. Indeed we believe use of 
an instrument is common industry practice, because a sniff test cannot 
accurately determine the concentration of odorant. Therefore, we are 
proposing to amend Sec.  192.625(f) to state specifically that an 
instrument must be used to determine odorant concentration. In 
addition, we are not proposing to relocate the master meter exception, 
because we do not think its present location confuses the acceptable 
use of ``sniff'' tests.
    As to NAPSR's second concern, we are certainly mindful of the 
importance of clarity in regulations. Yet we are uneasy about proposing 
a minimum sampling frequency that is not backed by consensus or a 
safety justification that supports the frequency. At the same time, we 
are persuaded by PS-124 commenters and SIRRC's industry members' view 
that sampling frequency is more appropriately determined on the basis 
of system conditions. A system might need sampling more often than six 
times a year in problem locations but less often at locations where 
odorant concentration consistently meets requirements. Also, under 
Sec.  192.605(b)(1), each operator's operating and maintenance 
procedures must provide odorant sampling frequencies, and operators 
must be able to justify the frequencies. Finally, under Sec.  
192.603(c), government regulators are authorized to challenge any 
sampling frequencies they consider deficient on the basis of safety 
data. They may also require operators to amend their procedures after 
considering any relevant information the operator provides. We believe 
this review and amendment process serves as a check on any possible 
misuse of sampling flexibility. Therefore, we are not proposing to 
establish a minimum sampling frequency.

30. Section 192.723(b)(2), Distribution Systems: Leak Surveys. (SIRRC 
Summary Report, p. 49)

    Recommendation. Amend Sec.  192.723(b)(2) to allow leeway in 
meeting the leakage survey intervals.
    SIRRC. The committee members agreed that NAPSR's recommendation was 
appropriate.
    Response. In the proceeding called ``Periodic Updates to Pipeline 
Safety Regulations (1999)'' (56 FR 15290; Mar. 22, 2000), we proposed 
to amend Sec.  192.723(b)(2) as NAPSR recommended.

31. Section 192.739(c), Pressure Limiting and Regulating Stations: 
Inspection and Testing; Sec.  192.743(c), Pressure Limiting and 
Regulating Stations: Testing of Relief Devices. (SIRRC Summary Report, 
p. 50)

    Recommendation. Clarify the meaning of ``correct pressure'' in 
Sec.  192.739(c) and ``insufficient capacity'' in Sec.  192.743(c) by 
cross-referencing Sec.  192.201, which limits the overpressure of 
pipelines protected by pressure relieving and limiting stations.
    SIRRC. The committee agreed that both sections should cross-
reference Sec.  192.201. However, the committee revised NAPSR's 
recommended wording to clarify that the set point of overpressure 
protective devices may be above the downstream MAOP.
    Response. We are proposing to change Sec. Sec.  192.739(c) and 
192.743(c) consistent with SIRRC's suggestions. The proposed changes 
would require that relief devices at existing pressure limiting and 
regulating stations meet the same standards for operation and relieving 
capacity as newly installed relief devices. The PS-124 comments and 
SIRRC's perspective indicate that industry practices are generally in 
accord with this approach to compliance with Sec. Sec.  192.739(c) and 
192.743(c). So we believe the proposed changes would clarify these 
regulations and not add significantly to the costs of compliance.

32. Section 192.743(a) and (b), Pressure Limiting and Regulating 
Stations: Testing of Relief Devices. (SIRRC Summary Report, p. 52)

    Recommendation. In view of the disadvantages of testing relief 
devices in place (cost, noise, and potential safety hazards from 
escaping gas), change Sec.  192.743 to allow operators to use 
calculations to determine if relief devices are of sufficient capacity 
without first having to determine that testing the devices in place is 
not feasible.
    SIRRC. The committee members agreed to accept NAPSR's 
recommendation.
    Response. Under the present rule, operators may not use 
calculations to determine necessary relief capacity until they 
determine that testing existing relief devices in place is not 
feasible. In addition to SIRRC, most PS-124 commenters supported 
NAPSR's recommendation. For the reasons NAPSR advanced, we also believe 
the recommended change is appropriate. Therefore, we are proposing to 
change Sec. Sec.  192.743(a) and (b) to remove the present preference 
for testing relief devices in place.

33. Section 192.745, Valve Maintenance: Transmission Lines. (SIRRC 
Summary Report, p. 53)

    Recommendation. For each transmission line valve inspected under 
Sec.  192.745, require that operators take immediate remedial action on 
any valve found to be inoperable, inaccessible, improperly supported, 
subject to external loads or unusual stresses, or inadequately 
protected from unauthorized operation, tampering, or damage.
    SIRRC. The committee did not reach a resolution on this 
recommendation. Industry members questioned the need for the 
recommended changes.
    Response. Section 192.745 requires annual inspection of 
transmission line valves that might be needed during an emergency. 
Because Sec.  192.745 requires each inspection to include partial 
operation of the valve, there is no question operators must maintain 
these valves in an operable condition.
    Section 192.745 does not regulate how soon a valve must be 
corrected if it is found inoperable. NAPSR recommended immediate 
remedial action. Most PS-124 industry commenters preferred to act ``as 
soon as practical,'' so they would not have to disrupt other essential 
services. But NAPSR did not think this phrase reflected the urgency of 
the situation.
    In the absence of a specified time limit for remedial action, 
operators may

[[Page 68824]]

take a reasonable time. Although a reasonable time may be satisfactory 
for some maintenance duties, we agree with NAPSR that emergency valves 
found inoperable need priority attention. Therefore, we are proposing 
to amend Sec.  192.745 to require operators to take prompt remedial 
action if any valve is found inoperable. Requiring prompt action rather 
than immediate action should allow operators the latitude they sought 
in scheduling maintenance activities, yet assure a timely response.
    Part 192 design and construction regulations already address most 
of NAPSR's other objectives. For instance, Sec.  192.179(b), a design 
rule, requires that onshore transmission line block valves be readily 
accessible, protected from tampering and damage, and adequately 
supported. In addition, Sec.  192.317, a construction rule, requires 
protection of transmission lines from external loads and unusual 
stresses. Moreover, if for any reason an emergency valve becomes 
unsafe, such as by damage or loss of support, Sec.  192.703(b) would 
require remedial action. While Sec.  192.703 does not establish a time 
limit for remedial action, we think a reasonable time is sufficient for 
any deficiency that does not make the valve inoperable. Therefore, we 
are not proposing to adopt NAPSR's recommendation to shorten the 
allowable response time to deficiencies that do not make an emergency 
valve inoperable.
    Part 192 does not regulate the protection of transmission line 
valves from unauthorized operation. However, operators commonly provide 
valve security. And unauthorized operation of valves has not been a 
significant problem on transmission lines. Also, operators of large 
systems can detect unauthorized operation of valves through monitoring 
of system pressures. Following the events of September 11, 2001, we 
began working with operators and other federal agencies to consider the 
need to improve the security of critical pipeline facilities. Given 
these circumstances, we are not now proposing to regulate the 
unauthorized operation of transmission line valves.

34. Section 192.747 Valve Maintenance: Distribution Systems. (SIRRC 
Summary Report, p. 54)

    Recommendation. Change Sec.  192.747, which requires annual 
inspection and servicing of each valve that may be needed for safe 
operation of a distribution system, to apply only to valves that 
operators designate for use in an emergency. Also, require partial 
operation of each emergency valve, and immediate remedial action if the 
valve is found to be inoperable, inaccessible, improperly supported, 
subject to external loads or unusual stresses, or inadequately 
protected from unauthorized operation, tampering, or damage.
    SIRRC. Although the committee did not reach consensus on this 
recommendation, it agreed that remediation could include designation of 
an alternate emergency valve. Industry members were particularly 
concerned that partial operation could cause some valves to close 
inadvertently, with potentially dangerous consequences, and could 
damage valves not designed for frequent operation.
    Response. NAPSR's rationale for limiting the present rule to 
designated emergency valves was to make clear which valves are to be 
inspected. However, we think Sec.  192.605(b)(1), which requires 
operators to have procedures for complying with Sec.  192.747, 
adequately addresses NAPSR's concern. Operators' procedures should not 
only explain how to inspect and service valves, but also identify which 
valves are to be inspected and serviced. In addition, valves intended 
for safe operation of a distribution system may not be the same valves 
operators might designate for use in an emergency. So limiting the 
present rule to emergency valves for the sake of clarity could 
inadvertently narrow the rule.
    Still we think that any valve that may be needed for safe operation 
of a distribution system should receive priority attention if it is 
found inoperable. Therefore, we are proposing to amend Sec.  192.747 to 
require prompt remedial action if any such valve is found inoperable, 
unless the operator designates an alternate valve. For the reasons 
stated above in response to Recommendation No. 33, we are not proposing 
to adopt NAPSR's recommendation to require immediate remedial action on 
deficient valves that remain operable. Further, because of the 
possibility of adverse consequences to the valve or others, we are not 
proposing to require partial operation of valves.
    The accessibility of distribution system valves has been a safety 
problem in some situations. For instance, if a valve essential to stop 
the flow of gas in an emergency is found to be paved over, the 
resulting delay in operating the valve can worsen the emergency. We 
think Sec.  192.605(b)(1) addresses this problem. This rule requires 
distribution operators to have and follow procedures to carry out the 
safety valve maintenance requirements of Sec.  192.747. And these 
procedures should identify which distribution system valves are subject 
to Sec.  192.747. If an identified safety valve is paved over without 
notice between annual inspections, the operator should discover the 
problem no later than the next annual inspection. At that time the 
operator would have to either correct the problem in order to carry out 
the inspection or revise its procedures to designate an alternative 
safety valve.

35. Section 192.753, Caulked Bell and Spigot Joints. (SIRRC Summary 
Report, p. 57)

    Recommendation. Correct the conflict between Sec.  192.621(a)(3), 
which allows a pressure as high as 25 psig in cast iron pipe with 
unreinforced bell and spigot joints, and Sec.  192.753(a), which 
requires cast-iron bell and spigot joints subject to pressures of 25 
psig or more to be sealed.
    SIRRC. The committee members agreed the conflict should be 
corrected.
    Response. We are proposing to change Sec.  192.753 to remove the 
conflict.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Policies and Procedures

    RSPA does not consider this proposed rulemaking to be a significant 
regulatory action under Section 3(f) of Executive Order 12866 (58 FR 
51735; Oct. 4, 1993). Therefore, the Office of Management and Budget 
(OMB) has not received a copy of this rulemaking to review. RSPA also 
does not consider this proposed rulemaking to be significant under DOT 
regulatory policies and procedures (44 FR 11034: February 26, 1979).
    We prepared a Draft Regulatory Evaluation of the proposed rules, 
and a copy is in the docket. This regulatory evaluation concludes that 
the proposed changes to existing rules may actually reduce operators' 
costs to comply with those rules because some proposals have compliance 
options. If you disagree with this conclusion, please provide 
information to the public docket described above.

Regulatory Flexibility Act

    The proposed rules are consistent with customary practices in the 
gas pipeline industry. Therefore, based on the facts available about 
the anticipated impacts of this proposed rulemaking, I certify, 
pursuant to Section 605 of the Regulatory Flexibility Act (5 U.S.C. 
605), that this proposed rulemaking would not have a significant impact 
on a substantial number of small entities. If you have any information 
that this conclusion about the impact on small

[[Page 68825]]

entities is not correct, please provide that information to the public 
docket described above.

Executive Order 13084

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

Paperwork Reduction Act

    Proposed Sec. Sec.  192.517(b) and 192.605(b)(11) contain minor 
additional information collection requirements. Operators would be 
required under Sec.  192.517(b) to maintain for 5 years records of 
certain leak tests, and under Sec.  192.605(b)(11) to have procedures 
for responding promptly to a report of gas odor inside or near a 
building. However, we believe most operators already maintain records 
of leak tests and have procedures for responding to reports of gas odor 
inside or near buildings. Also, we believe the burden of retaining 
these records is minimal. These records are largely computerized. 
Maintaining these records on a floppy disk or computer file represents 
very minimal costs. So, because the additional paperwork burdens of 
this proposed rule are likely to be minimal, we believe that submitting 
an analysis of the burdens to OMB under the Paperwork Reduction Act is 
unnecessary. If you disagree with this conclusion, please submit your 
comments to the public docket.

Unfunded Mandates Reform Act of 1995

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

National Environmental Policy Act

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

Impact on Business Processes and Computer Systems

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

Executive Order 13132

    The proposed rules have been analyzed in accordance with the 
principles and criteria contained in Executive Order 13132 
(``Federalism''). The proposed rules do not propose any regulation 
that: (1) Has substantial direct effects on the States, the 
relationship between the National government and the States, or the 
distribution of power and responsibilities among the various levels of 
government; (2) imposes substantial direct compliance costs on State 
and local governments; or (3) preempts state law. Therefore, the 
consultation and funding requirements of Executive Order 13132 do not 
apply.

List of Subjects in 49 CFR Part 192

    Natural gas, Pipeline safety, Reporting and recordkeeping 
requirements.

    For the reasons discussed in the preamble, RSPA proposes to amend 
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 Sec.  192.3 by adding 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 
manifold. A service line terminates 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 which 
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]

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


Sec.  192.197  [Amended]

    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]

    5. In Sec.  192.285(d), remove the term ``his'' and add the term 
``the operator's'' in its place.
    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.
    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. 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 Sec.  192.353(a) to read as 
follows:

[[Page 68826]]

Sec.  192.353  Customer meters and regulators: Location.

    (a) Each meter and service regulator, whether inside or outside of 
a building, must be installed in a readily accessible location and be 
protected from corrosion, vehicular, and other damage. * * *
* * * * *
    9. Add Sec.  192.361(g) to read as follows:


Sec.  192.361  Service lines: Installation.

* * * * *
    (g) Locating underground service lines. Each underground 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]

    10. Amend Sec.  192.457 as follows:
    a. Remove the second sentence in paragraph (b)(3); and
    b. Remove paragraph (c).
    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 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 or the environment.
    (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 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 against 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 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:

------------------------------------------------------------------------
 
------------------------------------------------------------------------
(1) If the pipeline is located:             Then the frequency of
                                             inspection is:
  (2) Onshore.............................  At least once every 3
                                             calendar years, but with
                                             intervals not exceeding 39
                                             months
  (3) 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.
    14. Amend Sec.  192.517 as follows:
    a. Designate the introductory text as paragraph (a);
    b. In newly designated paragraph (a), redesignate paragraphs (a), 
(b), (c), (d), (e), (f), and (g) as (a)(1), (2), (3), (4), (5), (6), 
and (7), respectively; and
    c. Add 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.
    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.
    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 gas odor inside or near a 
building, unless the operator's emergency procedures under Sec.  
192.615(a)(3) specifically apply to these reports.
* * * * *
    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. 
* * *
* * * * *
    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
* * * * *
    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 so as to cause the 
rated or

[[Page 68827]]

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 Sec.  192.745 as follows:
    a. Designate the existing text as paragraph (a); and
    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.
    21. Amend Sec.  192.747 as follows:
    a. Designate the existing text as paragraph (a); and
    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 alternate 
valve.
    22. In Sec.  192.753, revise the introductory text of paragraph (a) 
and revise paragraph (b) to read as follows:


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 October 31, 2002.
Stacey L. Gerard,
Associate Administrator for Pipeline Safety.
[FR Doc. 02-28240 Filed 11-12-02; 8:45 am]
BILLING CODE 4910-60-P