[Federal Register Volume 61, Number 110 (Thursday, June 6, 1996)]
[Rules and Regulations]
[Pages 28770-28786]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-13787]



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DEPARTMENT OF TRANSPORTATION

Research and Special Programs Administration

49 CFR Part 192

[Docket PS-124; Amdt. 192-76]
RIN 2137-AC25


Regulatory Review; Gas Pipeline Safety Standards

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

ACTION: Final rule.

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SUMMARY: This final rule changes miscellaneous gas pipeline safety 
regulations to provide clarity, eliminate unnecessary or burdensome 
requirements, and foster economic growth. The changes result from a 
comprehensive review of the regulations RSPA has completed under 
President Clinton's Regulatory Reinvention Initiative to reduce the 
burden of government regulations. The changes are intended to reduce 
the costs of compliance without compromising safety.

EFFECTIVE DATE: This final rule is effective July 8, 1996. The 
incorporation by reference of certain publications listed in the 
regulations is approved by the Director of the Federal Register as of 
July 8, 1996.

FOR FURTHER INFORMATION CONTACT: A. C. Garnett, (202) 366-2036, or L. 
M. Furrow, (202) 366-4559, regarding the subject matter of this 
amendment, or the Dockets Unit, (202) 366-5046 regarding copies of this 
amendment or other material in the docket.

SUPPLEMENTARY INFORMATION:

Background

    Early in 1992, RSPA began an extensive review of the federal gas 
pipeline safety regulations (49 CFR part 192) and invited the public to 
participate (57 FR 4745, Feb. 7, 1992). The review was to see what 
changes were necessary to provide clarity, eliminate unnecessary or 
overly burdensome requirements, and foster economic growth. As a result 
of the review, RSPA published a Notice of Proposed Rulemaking (NPRM), 
proposing changes to 38 regulations in part 192 (Notice 1; 57 FR 39572, 
Aug. 31, 1992).
    Then the National Association of Pipeline Safety Representatives 
(NAPSR) reported on a separate but related review of part 192. RSPA had 
asked NAPSR to identify regulations in part 192 that may not assure 
safety or

[[Page 28771]]

that may be hard to enforce. Because the NAPSR report concerned a few 
of the regulations covered by the NPRM and had similar goals, we 
published the report and requested public comment on its various 
recommended rule changes (Notice 2; 58 FR 59431, Nov. 9, 1993). At the 
same time, we announced that in developing final rules under the NPRM, 
we would consider comments on any NAPSR recommendations that addressed 
the same issues as the NPRM. The period for public comment on the NAPSR 
recommendations was extended 90 days until April 11, 1994 (Notice 3; 58 
FR 68382, Dec. 27, 1993).
    Later on, President Clinton launched the Regulatory Reinvention 
Initiative (memorandum for Heads of Departments and Agencies; March 4, 
1995), which, among other things, directed DOT and other Federal 
agencies to review and revise existing regulations to remove 
unnecessary or burdensome requirements. Today's publication of this 
Final Rule is a major step in carrying out that directive with respect 
to DOT's pipeline safety regulations.

Advisory Committee

    The Technical Pipeline Safety Standards Committee (TPSSC), 
consisting of 15 members, was established by statute to consider the 
feasibility, reasonableness, and practicability of proposed pipeline 
safety regulations. In developing the final regulations, RSPA 
considered all final TPSSC votes and comments on the NPRM, including 
minority positions. A more detailed consideration of the TPSSC action 
is contained in the following section-by-section discussion of 
comments. A record of the TPSSC deliberation is available in the 
docket.

Discussion of Comments

    RSPA received comments on the NPRM from 36 pipeline operators, 9 
pipeline-related associations, 1 state agency, and 8 other commenters. 
More commenters submitted views on the NAPSR recommendations: 58 
pipeline operators, 10 pipeline-related associations, 4 state agencies, 
and 5 other commenters.
    The following discussion on development of the final rules explains 
how we treated TPSSC positions, comments on the NPRM, and comments on 
NAPSR recommendations related to NPRM proposals (Secs. 192.3, 192.475, 
192.485, and 192.607). We appreciate the comments on NAPSR 
recommendations that were not related to NPRM proposals. They will help 
us decide appropriate responses to those recommendations in an action 
separate from this rulemaking.
    Small Gas Systems. The NPRM invited comments on the idea of whether 
RSPA should develop separate, more appropriate safety standards for 
small gas distribution systems. Such systems include master meter 
systems and petroleum gas systems serving mobile home or apartment 
complexes.
    Although TPSSC did not address this matter, RSPA received comments 
from two pipeline operators, one state agency, and one mobile home 
association. The state agency said that it is not clear that separate 
regulations are required. This commenter suggested that a less 
complicated remedy might be to excerpt those portions of the 
regulations specifically applicable to small operators (deleting, for 
example, sections applicable to transmission lines) and publish the 
result as a guide or as instructional material.
    Three commenters supported the need for more appropriate standards 
for small gas distribution systems. A mobile home association endorsed 
the idea of developing standards for small gas distribution systems, 
such as master-meter systems serving mobile home parks, and publishing 
the standards as a new part of title 49 of the Code of Federal 
Regulations. The mobile home association commented that if it were not 
for the Guidance Manual for Operators of Small Gas Systems published by 
RSPA, the average mobile home park operator would have difficulty 
determining which regulations in part 192 apply to master-meter 
systems.
    RSPA believes that each of the suggestions has merit and will be 
useful in developing future pipeline safety agendas.

Section 192.1, Scope of Part

    Section 192.1(b)(1) excepts from the scope of part 192 certain 
gathering lines on the outer continental shelf (OCS), but does not 
except similar gathering lines located in State offshore waters. 
Section 192.1(b)(1) reads as follows: ``This part does not apply to * * 
* (o)ffshore gathering of gas upstream from the outlet flange of each 
facility on the outer continental shelf where hydrocarbons are produced 
or where produced hydrocarbons are first separated, dehydrated, or 
otherwise processed, whichever facility is farther downstream.'' 
Because RSPA treats OCS and State offshore gathering alike under part 
192, we proposed to delete the phrase ``on the outer continental 
shelf'' so the exception would cover offshore gathering no matter where 
located. We also proposed to replace ``offshore gathering of gas'' with 
``offshore pipelines,'' recognizing that the excepted pipelines may be 
either production or gathering lines.
    Twelve TPSSC members voted for the proposal, two supported it but 
recommended a change, one member opposed it, and one abstained. The 
recommended change was that ``gathering of gas'' should be retained in 
Sec. 192.1(b)(1), since proposed Sec. 192.9 refers to gathering under 
Sec. 192.1.
    We did not adopt the TPSSC minority's recommended change because 
the excepted pipelines located upstream from the referenced offshore 
facilities may be either production lines or gathering lines. Also, the 
term ``offshore pipelines'' was used in a similar revision of 49 CFR 
195.1(b)(5) that we made to clarify the jurisdiction of the hazardous 
liquid pipeline regulations over offshore pipelines (Docket PS-127; 59 
FR 33388; June 28, 1994). As discussed below under the Sec. 192.9 
heading, Sec. 192.9 has already been revised to cross-reference 
Sec. 192.1. Since the cross- reference does not refer specifically to 
gathering lines, deleting the words ``gathering of gas'' from 
Sec. 192.1(b)(1) should not hinder the understanding of Sec. 192.9.
    RSPA received 14 comments on the proposed rule change, nine from 
operators, four from pipeline-related associations, and one from a 
state agency. None of these comments opposed the proposal to change 
Sec. 192.1(b)(1).

Section 192.3, Definitions

    1. Petroleum Gas. A revised definition of ``petroleum gas'' is 
discussed below under the Sec. 192.11 heading.
    2. Secretary. The proposed revision of the definition of 
``Secretary'' is no longer needed. Because the term ``Secretary'' is 
not used in part 192, the definition of ``Secretary'' was removed from 
Sec. 192.3 in an earlier rulemaking (59 FR 17281; April 12, 1994).
    3. Transmission Line. A longstanding RSPA interpretation holds that 
the definition of ``transmission line'' in Sec. 192.3 encompasses lines 
that link gathering lines or transmission lines to large volume 
customers, such as factories or power plants. This interpretation was 
founded on the definition of ``transmission line'' in the 1968 edition 
of the American Society of Mechanical Engineers [ASME] B31.8 Code. This 
code, which was the cornerstone of part 192, defined transmission to 
end at large volume customers. RSPA proposed to codify the 
interpretation by restating the definition of ``transmission line'' 
under part 192 to

[[Page 28772]]

include a ``large volume customer'' as an end point of transmission.
    Eleven TPSSC members voted for the proposal, three supported it 
with a recommended change, and one abstained. The members who 
recommended a change thought that RSPA should define ``large volume 
customer.'' As discussed further below, the final definition includes 
an explanation of this term.
    Twenty-six entities commented on the NPRM proposal, including 19 
pipeline operators, five pipeline-related associations, one state 
agency, and one industrial consumer. Of these commenters, only eight 
expressed unqualified support. Three commenters completely opposed the 
proposal, saying it was not needed or would create confusion.
    RSPA continues to believe that the proposed change is needed. The 
present definition does not reflect RSPA's interpretation that the term 
``transmission line'' includes pipelines that connect large volume 
customers to gathering or transmission lines.
    Nine commenters thought the proposed definition would reclassify as 
transmission those pipelines that connect large volume customers to 
high pressure distribution lines. RSPA did not intend for the proposed 
change to alter the classification of distribution lines that supply 
large volume customers. To avoid this unintended outcome, the 
definition explicitly does not include lines serving large volume 
customers downstream from a distribution center.
    Four commenters said that the volume of gas transported is not an 
appropriate indicator of transmission. This group suggested that 
engineering characteristics, such as high pressure, stress level, or 
connection to a pressure limiting station are more indicative of 
transmission than the volume of gas transported. However, the purpose 
of the transmission proposal was not to open discussion on whether 
volume is an appropriate indicator of transmission. The purpose was to 
recognize that, by interpretation of the present definition, volume 
already is an established indicator of transmission, and that the 
interpretation should be codified. None of the commenters challenged 
the correctness of the interpretation. Moreover, before publishing the 
proposed definition, we referred to the 1992 edition of the ASME B31.8 
Code, a widely recognized code of voluntary standards for gas piping. 
Section 803.21 of the ASME B31.8 Code (1992 edition) defined 
``transmission line'' as ``pipe installed for the purpose of 
transmitting gas from a source or sources of supply to one or more 
distribution centers or to one or more large volume customers * * *'' 
(emphasis added). And this definition is the same in the current 1995 
edition of the code. Given our longstanding interpretation and the ASME 
B31.8 Code definition, we find it reasonable to add ``large volume 
customer'' to the definition of transmission line as proposed.
    Three commenters wanted RSPA to define ``large volume customer.'' 
We agree that an explanation of ``large volume customer'' would make 
the final definition more precise. Thus, we added a statement to the 
final definition to explain that ``large volume customer'' includes 
factories, power plants, and institutional users of gas.
    We did not specify a minimum volume of gas a pipeline must 
transport to a customer to qualify as transmission. Volumes vary, and 
setting an arbitrary threshold might unfairly reclassify some existing 
lines. However, since ``large volume customer'' and ``distribution 
center'' each mark the end of transmission under the definition, 
operators may use the volume of gas supplied to distribution centers as 
a guide to identifying large volume customers.
    The NAPSR report recommended changing the part 192 definition of 
``transmission line'' so that pipelines beginning at gathering or 
transmission lines and ending at ``distribution systems and other load 
centers'' would be classified as transmission lines. Under this 
alternative wording, load centers conceivably would include large 
volume customers.
    Most of the persons who commented directly on this NAPSR 
recommendation opposed it. A primary objection was that the recommended 
definition would needlessly reclassify as transmission low stress 
pipelines between communities or between distribution systems and high 
pressure transmission lines. In this regard, many commenters felt 
transmission should be limited to pipelines that operate at 20 percent 
or more of specified minimum yield strength (SMYS) of pipe, one of the 
characteristics under the present definition. The lack of definition of 
the term ``load center'' was another frequently stated reason for 
opposing the NAPSR recommendation. Commenters argued that introducing 
this term into the definition would lead to more, not less, confusion. 
Also several commenters thought the definition of transmission line 
should remain unchanged until RSPA completes its project to redefine 
the term ``gathering line,'' which appears in the transmission line 
definition. After considering these concerns, we agree that the NAPSR 
recommendation would not strengthen the present definition and could 
cause reclassification of many lines. Therefore, we did not adopt the 
recommendation in the final definition.

Section 192.5, Class Locations

    RSPA proposed to clarify Sec. 192.5 to minimize the possibility 
that a pipeline is classified higher than required. Inasmuch as part 
192 regulations become more stringent as pipeline classification 
increases, any over- classification results in needless expenditures.
    Fourteen TPSSC members voted for the proposal and one abstained. 
Eight operators and one pipeline-related association commented on the 
proposed change. While these commenters generally supported the need to 
clarify Sec. 192.5, two operators suggested alternative wording. Based 
on one suggestion, RSPA has combined proposed Secs. 192.5 (c)(2) and 
(c)(3) into final Sec. 192.5(c)(2).
    One focus of the NPRM was the cluster exception in existing 
Secs. 192.5(f)(2) and (f)(3). This exception provides that if a cluster 
of buildings intended for human occupancy requires a Class 2 or 3 
location, the classification ends 220 yards from the nearest building 
in the cluster, rather than at the end of the 1-mile class location 
unit that would otherwise be the basis for classification. In the NPRM 
(at 39573), we stated that adding buildings outside a cluster to those 
inside the cluster would result in over-classification of the class 
location unit. However, this statement was incorrect. The history of 
Sec. 192.5 (35 FR 13251, August 19, 1970) shows that the cluster 
exception applies only when all buildings in a 1-mile class location 
unit are in a single cluster. If a class location unit contains 
buildings outside a cluster or more than one cluster of buildings, all 
buildings in the unit must be counted to determine the classification 
of the unit. The final rule clarifies this point.
    The association that commented thought we should define the term 
``cluster.'' However, the term is used in its ordinary dictionary 
sense, and, in RSPA's experience, has not been a significant source of 
misunderstanding.

Section 192.7, Incorporation by Reference

    Section 192.7 describes the incorporation by reference in part 192 
of documents or portions of documents relevant to gas pipeline safety. 
RSPA proposed to revise Sec. 192.7(a) to clarify that when a regulation 
in part 192

[[Page 28773]]

references a document, the entire document is not necessarily 
incorporated by reference. Rather, only those portions of the document 
that are specifically referenced in the regulation or are essential for 
compliance with the regulation are incorporated by reference. Such 
portions may or may not comprise the whole document, depending on the 
scope of the reference.
    Fourteen TPSSC members voted for the proposal and one abstained. 
Commenters on the proposed change, seven operators and one pipeline-
related association, all favored the proposal. However, two of these 
commenters wanted RSPA to change the rule in a manner not proposed. 
They advised changing Sec. 192.7 to require operators to follow the 
latest published editions of documents, instead of particular editions, 
which can become obsolete before RSPA updates the references. RSPA 
believes this recommended action is inappropriate because it would hand 
over an established governmental function, rulemaking, to the private 
organizations who produce the referenced documents. Each newly 
published edition would automatically change a pipeline safety rule and 
bypass the Federal rulemaking process, which ensures fair treatment of 
all affected parties.

Section 192.9, Gathering Lines

    When the NPRM was published, Sec. 192.9 required gathering lines to 
comply with part 192 standards applicable to transmission lines without 
indicating that certain gathering lines are excepted from part 192 by 
Sec. 192.1. To highlight this exception and provide a clear 
understanding of which gathering lines must meet transmission line 
standards, we proposed to cross-reference Sec. 192.1 in Sec. 192.9.
    Thirteen TPSSC members voted for the proposal and two abstained. 
RSPA received seven comments on the proposed change, six from operators 
and one from a pipeline-related association. Only one commenter opposed 
the proposal, saying it did not see how the change would clarify the 
present rule.
    Then in 1994, in a separate, unrelated action concerning the 
passage of pigs, RSPA revised Sec. 192.9 to include a cross-reference 
to Sec. 192.1 (59 FR 17281, April 12, 1994). Thus, Sec. 192.9 has 
already been changed consistent with the proposal in this proceeding, 
and no further action is necessary.

Section 192.11, Petroleum Gas Systems (Including Changes to Secs. 192.1 
and 192.3)

    RSPA proposed several changes to the special rules in Sec. 192.11 
for petroleum gas systems: First, we proposed to require that peak 
shaving plants supplying petroleum gas by pipeline to a natural gas 
distribution system as well as pipeline systems transporting only 
petroleum gas or petroleum gas/air mixtures comply with part 192 
standards and the National Fire Protection Association (NFPA) Standards 
58 and 59. Downstream from the point where a peak shaving plant injects 
petroleum gas into a natural gas distribution system, only part 192 
would apply. Next, we proposed that the NFPA Standards prevail in the 
event of a conflict between part 192 and NFPA Standards 58 or 59. At 
the same time, we said that a conflict does not exist when NFPA 
Standards 58 and 59 are silent or nonspecific on a subject (such as for 
corrosion protection or leak detection). In this case, the operator 
would have to comply with any applicable part 192 rule. Finally, we 
proposed to add a definition of ``petroleum gas'' to Sec. 192.3, and to 
clarify under Sec. 192.1(b)(4) which petroleum gas systems are excepted 
from part 192.
    Ten TPSSC members voted for the proposal, one member supported it 
with a recommended change, three members opposed it, and one abstained. 
Two TPSSC members disagreed with the proposal that NFPA standards 
should prevail in the event of a conflict with part 192. One TPSSC 
member voted yes, but recommended that in the event of conflict the 
most stringent requirement should prevail.
    We explained in the NPRM why we believe the NFPA standards should 
have priority in direct conflict situations. The main reason is that in 
contrast to part 192, the NFPA Standards specifically cover petroleum 
gas transportation. Also, NFPA Standards 58 and 59 reflect current 
petroleum gas technology and safety practices. Given this special 
attention to petroleum gas, we do not think there is sufficient reason 
to require operators to follow part 192 instead of the NFPA Standards 
in the event of conflict, even if part 192 is more stringent.
    RSPA received eight comments in favor and three comments in 
opposition to the proposed changes to Sec. 192.11. Those commenters who 
opposed the proposal were concerned that compliance with NFPA Standards 
58 and 59 would involve significant capital expenditures. However, 
Sec. 192.11 already requires petroleum gas systems to meet NFPA 
Standards 58 and 59. And, in accordance with 49 U.S.C. Sec. 60104(b), 
none of the design, installation, construction, initial testing, or 
initial inspection requirements of NFPA Standards 58 and 59 would apply 
under part 192 to peak shaving plants now in existence. So, 
retrofitting existing plants would not be required. Although all plants 
would have to comply with the operation and maintenance requirements of 
NFPA Standards 58 and 59, overall compliance costs should be small 
because, as NFPA stated in its petition, most, if not all, existing 
plants already comply with NFPA Standards 58 and 59 to qualify for 
insurance coverage. Thus, Sec. 192.11 is revised as proposed in the 
NPRM.
    Proposed Sec. 192.1(b)(4)(i) would exclude from part 192 pipeline 
systems that transport only petroleum gas or petroleum gas/air mixtures 
to fewer than 10 customers, if no portion of the system is located in a 
public place. This exclusion is in the present Sec. 192.11(a), but in 
proposing to relocate it to Sec. 192.1(b)(4)(i), we omitted the 
parenthetical phrase ``(such as a highway).'' One commenter objected to 
the omission, saying it would leave the meaning of ``public place'' 
open to interpretation. However, our experience has been that the 
parenthetical phrase has hindered more than helped the understanding of 
public place. We have consistently interpreted ``public place'' to mean 
a place which is generally open to all persons in a community as 
opposed to being restricted to specific persons. We consider churches, 
schools, and commercial property as well as any publicly owned right-
of-way or property which is frequented by persons to be public places. 
Although Sec. 192.11(a) refers to a highway as an example of a public 
place, many operators have incorrectly considered the example to 
restrict, rather than define, the coverage of petroleum gas systems 
with fewer than 10 customers.
    Proposed Sec. 192.1(b)(4)(ii) would clarify that part 192 does not 
apply to single-tank, single-customer petroleum gas systems located 
entirely on the customer's premises, but partially in a public place. 
These systems exist, for example, at churches or restaurants, where the 
gas is used for heating or cooking. The proposal was based on the 
jurisdiction of part 192 over the distribution of gas. As indicated by 
the definition of ``service line'' (Sec. 192.3), part 192 does not 
apply to gas distribution beyond the point where metered gas enters 
customer piping. For single-tank, single-customer systems on the 
customer's premises, this point normally occurs at the tank.
    Three commenters protested that part 192 would still apply to 
single-customer, multi-tank systems on the customer's premises, 
regardless of tank size. For example, the proposed rule

[[Page 28774]]

would not exclude a two-tank system partly in a public place, even if 
the total quantity of stored gas is less than in a large single-tank 
system. Because the proposed exclusion did not rest on the quantity of 
gas delivered to the customer, we agree that the number of tanks should 
not be a factor in the exclusion of single-customer systems on the 
customer's premises. Therefore, final Sec. 192.1(b)(4)(ii) omits the 
term ``single-tank.''
    The proposed definition of ``petroleum gas'' drew no objections 
from either the TPSSC or commenters. So the definition is adopted as 
proposed.

Sections 192.14 and 192.553, Conversion and Uprating

    If a steel pipeline to be converted to gas service under part 192 
has not been designed and constructed to meet part 192 standards, it 
must be converted according to Sec. 192.14 (Sec. 192.13(a)(2)). Section 
192.14(a)(4) requires that each pipeline must be pressure tested under 
subpart J of part 192 to substantiate the maximum allowable operating 
pressure (MAOP) permitted by subpart L of part 192. Under subpart L, to 
compute the MAOP of a pipeline being converted, an operator must 
determine the design pressure of the weakest element of the pipeline 
(Sec. 192.619(a)(1)).
    Design pressure is also a factor under Sec. 192.553, which 
establishes general requirements for increasing any pipeline's MAOP 
(uprating). Under Sec. 192.553(d), an increased maximum allowable 
operating pressure may not exceed the MAOP part 192 allows for a new 
pipeline constructed of the same materials in the same location. Thus, 
to uprate a pipeline within this MAOP limit, an operator must determine 
the design pressure of the weakest element of the pipeline 
(Sec. 192.619(a)(1)).
    Because of the role of design pressure, a steel pipeline may not be 
converted or uprated when any of the pipe characteristics needed to 
calculate design pressure under Sec. 192.105 is unknown. Therefore, 
RSPA proposed to amend Secs. 192.14(a)(1) and 192.553(d) to permit the 
conversion or uprating of steel pipelines based on an approach found in 
paragraph 845.214 and Appendix N of the ASME B31.8 Code. Under the 
proposal, when design pressure is unknown, operators would have to 
pressure test the pipeline under Appendix N until pipe yield occurs. 
The first pressure that produces pipe yield, reduced by 20 percent and 
the appropriate factor under Sec. 192.619(a)(2)(ii), would be used 
instead of design pressure to calculate MAOP.
    Twelve TPSSC members voted for the proposed revision of 
Sec. 192.14, one member supported it with a recommended change, one 
member opposed it but suggested changes, and one member abstained. 
Eleven members voted for the proposal regarding Sec. 192.553, two 
supported it with a recommended change, one opposed it, and one 
abstained. The recommended changes were to make yield testing mandatory 
instead of permissive, and to allow yield testing that is based on 
other than the ``first pressure'' that produces yield, since Appendix N 
does not use that term. The reasons against the proposal were that 
yield testing appeared to be mandatory, and use of the Appendix N 
method should be discretionary.
    RSPA has adopted the recommended change regarding mandatory yield 
testing. Although, in the proposed rules, yield testing may have 
appeared permissive, RSPA clearly intended such testing to be the only 
alternative when design pressure is unknown. Therefore, in the final 
rule, if factors in the design formula are unknown, a pipeline to be 
converted or uprated would have to be pressure tested under Appendix N 
to determine pipe yield, except as discussed below for low-stress pipe.
    The TPSSC member's recommendation to delete ``first pressure'' from 
the proposed rule was not adopted. Although Appendix N does not refer 
to the first pressure that produces yield, paragraph 845.214(a)(2) of 
the ASME B31.8 Code, which applies to the establishment of MAOP when 
design pressure is unknown, provides that only the first test to yield 
can be used to determine MAOP. The proposed rules were consistent with 
this B31.8 standard, which precludes the use of higher yield pressures 
that can result from successive testing.
    RSPA did not adopt the TPSSC member's comment that use of the 
Appendix N method should be discretionary. When MAOP is determined 
without knowing the pipeline's design pressure, conformity to a 
standardized practice (Section N5.0 of Appendix N) assures additional 
safety to offset the lack of knowledge about design pressure.
    RSPA received comments on the proposed rules from 11 operators and 
three pipeline-related associations. Four operators and one pipeline-
related association recommended removal of the proposed requirement to 
use the ``first pressure'' that produces yield. Our position on this 
subject is given above in response to a similar comment by a TPSSC 
member.
    One operator and one pipeline-related association suggested 
locating the proposed amendments in Sec. 192.105 instead of 
Secs. 192.14 and 192.553. RSPA did not adopt this suggestion because 
Sec. 192.105 affects the design of new pipelines, a subject the 
proposed rules did not address.
    One operator and two pipeline-related associations argued that 
pressure testing to yield is unnecessary to qualify low-stress 
distribution lines (generally lines 12\3/4\ inches or less in nominal 
outside diameter operating at pressures less than 200 psig) for 
conversion or uprating. Part 192 recognizes that low- stress pipelines 
present a much lower risk to public safety than high-stress lines, all 
other factors being equal. For example, certain welding standards in 
subpart E are less stringent for pipelines to be operated below 20 
percent of SMYS. Because of the lower risk, the final rule provides 
that pipelines 12\3/4\ inches or less in nominal outside diameter to be 
operated at a pressure less than 200 psig may be converted or uprated 
without testing to yield. The MAOP of such pipelines may be determined 
under Sec. 192.619(a)(1) by using 200 psig as design pressure.
    An operator argued that pressure testing to yield should be 
discretionary, because sufficient safety would be provided by the 
proposed pressure reduction factors regardless of the level of test 
pressure. The commenter was also concerned that pressure testing to 
yield for an extended time could cause the growth of defects that later 
cause failure during operation. Two hours was suggested as the optimum 
hold time for yield testing, based on ongoing studies.
    RSPA did not adopt these comments. Pressure testing to yield 
exposes more material and construction defects than does testing to a 
lower pressure. With fewer defects remaining after testing to yield, 
greater long-term protection against failures due to the growth of 
unexposed defects results. RSPA intended this extra protection, 
combined with the proposed pressure reduction factors, to offset the 
absence of design pressure as a limit on MAOP. Pressure testing to 
yield appears to be reasonable since many operators already strength 
test their pipelines at or above yield for safety and efficiency 
reasons. Also, none of the other commenters or TPSSC members objected 
to pressure testing to yield, except as discussed above for low-stress 
lines. As to the optimum hold period for yield testing, because the 
matter is still being studied by industry and is not addressed by the 
procedure for yield testing under Appendix N, it is too soon to 
consider

[[Page 28775]]

establishing a special hold period for yield testing under part 192.
    The final rules have been drafted to improve clarity, to show their 
relation to design pressure and MAOP under Sec. 192.619, and to include 
the changes discussed above. The proposed amendments to 
Secs. 192.14(a)(1) and 192.553(d) are revised and published as an 
amendment to Sec. 192.619(a)(1), because this section deals 
specifically with design pressure and MAOP. Final Sec. 192.619(a)(1), 
set forth below, provides that when design pressure is unknown for 
steel pipelines being converted or uprated, a reduced value of first 
yield hydrostatic test pressure, instead of design pressure, is used to 
compute MAOP. As discussed below, final Sec. 192.619(a)(1) does not 
include the reduction factors proposed for butt and lap welded pipe 
under Sec. 192.14(a)(1)(ii). If the pipeline to be converted is 12\3/4\ 
inches or less in nominal outside diameter, 200 psig, instead of design 
pressure, may be used if the line is not yield tested. Section 
192.553(d) is also revised to refer to amended Sec. 192.619(a)(1). 
Also, because the 1992 edition of the ASME B31.8 Code is now out-of-
print, the 1995 edition is referenced in Sec. 192.619(a)(1) as shown by 
the revisions to Appendix A of part 192 (see below).

Section 192.107, Yield Strength (S) for Steel Pipe

    For pipe made according to a specification not listed in part 192 
or whose specification or tensile properties are unknown, 
Sec. 192.107(b)(1) provides that yield strength may be established by 
tensile testing in accordance with section II-D of appendix B to part 
192. When yield strength is determined by such tensile testing, 
paragraph (b)(1) requires that the yield strength used in the design 
formula of Sec. 192.105 be the lower of either 80 percent of the 
average yield strength determined by tensile testing or the lowest 
yield strength determined by tensile testing, but not over 52,000 psi. 
RSPA proposed to remove this 52,000 psi upper limit on yield strength, 
because higher strength pipe has become available since this limitation 
was adopted, and tensile testing is a generally accepted method of 
determining material properties.
    Twelve TPSSC members voted for the proposal, one member supported 
it with a recommended change and two abstained. The member recommending 
the change felt that the proposal would be better justified if we knew 
the proportion of higher strength pipe that lacks tensile documentation 
and why this information is unknown. RSPA believes this information is 
not essential in deciding whether to adopt the proposal because the 
proposed amendment has limited application. We expect operators would 
use the proposed amendment to qualify stock pipe they have stored for 
maintenance and emergencies and to qualify used pipe being reclaimed. 
In either case, the amount of pipe that would be qualified under 
proposed Sec. 192.107(b)(1)(ii) should be very small compared with all 
pipe being qualified for use in gas pipeline systems.
    RSPA received six comments on the proposed amendment. The comments 
came from five operators and one pipeline-related association, and all 
supported the proposal. In addition, one operator recommended that RSPA 
further amend Sec. 192.107 to permit the use of recognized statistical 
methods to determine yield strength from tensile tests. RSPA did not 
adopt this comment because this concept was not addressed in the NPRM 
and would require further public comment and study.
    Accordingly, Sec. 192.107 is amended as proposed in the NPRM.

Section 192.121, Design of Plastic Pipe

    RSPA proposed to add the following formula to Sec. 192.121, which 
would allow use of the Standard Dimension Ratio (SDR) in determining 
design pressure for plastic pipe:
[GRAPHIC] [TIFF OMITTED] TR06JN96.012

    SDR is a commonly used plastic pipe characteristic in the gas 
pipeline industry.
    Thirteen TPSSC members voted for the proposal and two abstained. 
RSPA received eight responses from the public, all in favor of the 
proposed rule. Therefore, the final rule is issued as proposed in the 
NPRM, except that the proposed definition is reworded to conform to 
standard usage. The final definition agrees with the SDR definition 
given in the voluntary standard referenced in part 192 for the 
manufacture of thermoplastic pipe: American Society for Testing and 
Materials (ASTM) Designation D 2513, ``Standard Specification for 
Thermoplastic Gas Pressure Pipe, Tubing, and Fittings'' (1990c 
edition).

Section 192.123, Design Limitations for Plastic Pipe

    Under Sec. 192.123, plastic pipe may not be used where pipe 
operating temperatures are below -20 deg.F. RSPA proposed to lower this 
limit to -40 deg.F in light of improvements in pipe technology. 
Additionally, RSPA proposed to clarify Sec. 192.123(b)(2), which sets 
the maximum operating temperature for thermoplastic pipe and reinforced 
thermosetting plastic pipe.
    Thirteen TPSSC members voted for the proposal and two abstained. 
RSPA received nine comments on the proposed rule changes: six from 
operators, one from a pipeline-related association, and two from 
manufacturers. The operators and the association supported the proposal 
or did not object to it. However, the manufacturers opposed the 
proposal stating that many components other than pipe that are made for 
use in gas pipeline systems do not have a low temperature rating of 
-40 deg.F, although they perform satisfactorily at -20 deg.F. One of 
these commenters argued that unsafe operation could occur if pipeline 
designers assumed that all components, such as repair and connection 
devices, fittings, valves, meters, and regulators, may be used at 
-40 deg.F.
    RSPA shares the manufacturers' concern. Therefore, the final rule 
allows the use of plastic pipe at temperatures between -20 deg.F and 
-40 deg.F only if all pipe and pipeline components whose operating 
temperature will be below -20 deg.F have a manufacturer's temperature 
rating consistent with that operating temperature.

Section 192.179, Transmission Line Valves

    Gas transmission lines must have sectionalizing block valves spaced 
according to population density under Sec. 192.179(a). RSPA proposed to 
revise this rule to allow the RSPA Administrator to approve alternative 
spacing where the operator demonstrates an equivalent level of pipeline 
safety.
    Thirteen TPSSC members voted for the proposal, one against, and one 
abstained.
    RSPA received comments from 12 operators, two pipeline-related 
associations, and a state agency. Thirteen commenters gave their full 
or qualified approval, but one association and the state agency argued 
against the proposal. Those commenters expressing qualified support 
generally felt that the proposal offered some benefit to pipeline 
operators. However, they urged that operators be permitted to determine 
spacing based on criteria similar to those for hazardous liquid 
pipelines in 49 CFR 195.260(c).
    RSPA did not adopt the comment that transmission line valve spacing 
should be governed by criteria similar to those in 49 CFR 195.260(c). 
While those criteria may be appropriate for hazardous liquid pipelines, 
we have no indication they are suitable for gas

[[Page 28776]]

transmission lines. In fact, the widely accepted voluntary standard for 
valve spacing, paragraph 846.11 of the ASME B31.8 Code, differs little 
from existing Sec. 192.179.
    As for the comments opposing the proposal, RSPA has considered the 
state agency's concern that the proposed rule would infringe on the 
authority of state agencies to grant waivers from Sec. 192.179 for 
intrastate transmission lines. (See 49 U.S.C 60118(d)). However, this 
concern has been addressed by a procedural rule (49 CFR 190.9) that 
RSPA adopted to handle petitions for finding or approval under the 
federal pipeline safety regulations. Under this rule, which would apply 
to petitions for alternative spacing under Sec. 192.179, operators of 
intrastate pipelines subject to the safety regulatory jurisdiction of a 
certified state agency must submit their petitions to that agency for 
review and recommendation before final action by the Administrator.
    RSPA does not agree with the pipeline-related association's 
suggestion that since the underlying rule is not justified, the 
proposed amendment is not needed. The basis for existing Sec. 192.179 
was the 1968 edition of the ASME B31.8 Code. As noted above, the 
current edition of that code continues to specify valve spacing similar 
to Sec. 192.179.

Section 192.203, Instrument, Control, and Sampling Pipe and Components

    Under Sec. 192.203(b)(2), each takeoff line must have a shutoff 
valve as near as practicable to the point of takeoff. RSPA proposed an 
exception for takeoff lines on pressure regulators when the lines can 
be isolated by other valves from their source of pressure.
    Eleven TPSSC members voted for the proposal, one voted against it, 
two members supported it with a recommended change, and one abstained. 
The two members recommended that we also except instrument control 
lines that are capable of being isolated from their source of pressure.
    Although the industry's use of isolatable regulators gave rise to 
the proposed rule change, isolation of a takeoff line from its pressure 
sources applies to any takeoff line capable of such isolation, not just 
takeoff lines on regulators. Therefore, the final rule excepts any 
takeoff line capable of being isolated from its sources of pressure. 
Thus, the term ``takeoff line'' includes instrument control lines that 
are designed as takeoff lines.
    RSPA received 13 public comments, all in favor of changing the 
regulation. One of these commenters offered a rewording intended to 
broaden the regulation to include control lines at both measuring and 
regulating stations. As explained above, such control lines will be 
covered by the exception when they are takeoff lines capable of 
isolation from their sources of pressure.

Section 192.227, Qualification of Welders, and Sec. 192.229, 
Limitations on Welders

    Welders qualified to weld on pipe to be operated at any hoop stress 
(Sec. 192.227(a)) must requalify every 6 months (Sec. 192.229(c)). 
However, welders qualified to weld only on pipe to be operated at low 
hoop stress (less than 20 percent of SMYS) need only requalify once a 
year (Sec. 192.227(b)), and the requalification requirements are less 
comprehensive than those for other welders.
    RSPA proposed to revise Secs. 192.227 and 192.229 to allow welders 
initially qualified for any hoop stress level, but who weld only on 
pipe to be operated at low hoop stress, to requalify under the low-
stress requirements. Such welders would then not be permitted to weld 
on pipe to be operated at 20 percent or more of SMYS unless they again 
qualify under Sec. 192.227(a).
    Twelve TPSSC members voted for and one against the proposed 
revision of Sec. 192.227, and two abstained. The TPSSC members' vote on 
Sec. 192.229 was the same as on Sec. 192.227. Eight pipeline operators 
and two pipeline-related associations also agreed with the proposal.
    A commenter suggested that the final rule make clear that either 
existing Sec. 192.229(c) or Sec. 192.227(b) can be used to requalify 
welders to weld on pipe to be operated at less than 20 percent of SMYS. 
RSPA adopted the substance of this comment by adding a sentence 
concerning low stress requalification to the final Sec. 192.229(c).
    The commenter who opposed the proposal claimed that qualification 
under Secs. 192.227(a) and (b) is inadequate. However, RSPA finds no 
justification for this claim. Section 192.227 became effective in 
February 1970. Our accident data in the intervening 26 years have not 
indicated that field welding of steel materials in pipelines presents a 
significant safety problem.
    In the final rules, proposed Sec. 192.227(c) is redesignated as 
Sec. 192.229(d). Thus, all requalification requirements appear in one 
section.

Section 192.241, Inspection and Test of Welds

    Section 192.241 requires inspection and test of welds on steel 
materials in pipelines, except welds made during the manufacture of 
pipe and pipeline components. Under existing Sec. 192.241(c) and 
appendix A to part 192, the acceptability of a weld that is 
nondestructively tested or visually inspected is determined according 
to the standards in section 6 of API Standard 1104 (17th edition).
    The Appendix of API Standard 1104, which is based on fracture 
mechanics principles, provides more detailed acceptance standards for 
weld flaws than the criteria in section 6 of API Standard 1104. RSPA 
proposed to amend Sec. 192.241(c) to permit use of the Appendix as an 
alternative acceptance standard for girth weld flaws, except welds 
unacceptable because of a crack.
    Eleven TPSSC members voted for the proposal, three members 
supported it with a recommended change and one abstained. The three 
members suggested that the word ``flaw'' be changed to ``defect''.
    In existing Sec. 192.241, neither the word ``flaw'' nor ``defect'' 
is used. The rule is written in terms of weld acceptability. Therefore, 
in response to the comments of the TPSSC members, the final rule is 
written without using either ``flaw'' or ``defect.''
    Eleven pipeline operators and three pipeline-related associations 
agreed with the proposed change. Only one commenter was opposed to 
allowing use of the Appendix of API Standard 1104. This commenter was 
concerned that industry inspection personnel may not be qualified to 
apply the complicated engineering criteria found in the Appendix. On 
the contrary, personnel who would use the Appendix must be able to 
apply it correctly. Under Secs. 192.243(b) and (c), operators must 
ensure that nondestructive testing is performed in accordance with 
written procedures by persons who have been properly trained and 
qualified.
    The final rule indicates that use of the Appendix is restricted to 
girth welds to which the Appendix applies. For example, as Section A.1 
of the Appendix provides, welds used to connect fittings and valves are 
not covered. Also, the Appendix applies only to girth welds between 
pipe of equal nominal wall thickness.

Section 192.243, Nondestructive Testing

    For pipelines subject to nondestructive testing under part 192, 
Sec. 192.243(d)(4) requires such testing for all field butt welds at 
pipeline tie-ins. RSPA proposed to amend Sec. 192.243(d)(4) to add the 
phrase ``including tie-ins of replacement sections.'' This change was 
meant to clarify that tie-ins occur in pipeline

[[Page 28777]]

replacement, as well as in new construction.
    Fourteen TPSSC members voted for the proposal and one abstained.
    Comments were received from five pipeline operators and one 
pipeline-related association, and all favored the proposed rule change. 
Section 192.243 is amended as proposed in the NPRM.

Section 192.281, Plastic Pipe

    This rule establishes standards governing the joining of plastic 
pipe. RSPA proposed to revise Sec. 192.281(c), which applies to heat-
fusion joints, to cover electrofusion, a method of heat-fusion joining. 
The proposal was that electrofusion joints must be made with equipment 
and techniques expressly prescribed by the fittings manufacturer.
    Thirteen TPSSC members voted for the proposal, one member supported 
it with a recommended change, and one abstained. The recommended change 
was that ``or the equivalent'' be added so that operators could use 
equipment and techniques equivalent to that prescribed by fittings 
manufacturers.
    RSPA received 15 comments on the proposed change to 
Sec. 192.281(c). Eleven commenters fully or partially agreed with the 
proposed rule, while four commenters objected. A commenter who 
partially agreed recommended that electrofusion be specifically 
addressed in Sec. 192.285. However, RSPA finds that step unnecessary 
because electrofusion is a type of heat fusion, and heat fusion is 
covered by Sec. 192.285(b)(2).
    The objections focused on RSPA's proposal that operators must use 
``equipment and techniques expressly prescribed by the fittings 
manufacturer.'' One commenter said that electrofusion equipment is 
expensive and that most electrofusion fittings can be installed only by 
using the fittings manufacturer's equipment. As a result, most 
operators have only a single source of electrofusion fittings. However, 
the commenter stated that electrofusion equipment under development 
will allow the installation of several different brands of 
electrofusion fittings, and that those additional sources would 
encourage competitive pricing. Other operators argued they should not 
be denied the use of procedures and equipment not expressly prescribed 
by the fittings manufacturer, as long as the procedures are qualified 
for use under Sec. 192.283.
    Since the proposal was intended to relax the current regulatory 
requirement, RSPA accepts the recommendations that operators should 
have latitude in choosing equipment and techniques for use in 
electrofusion joining. We have adopted a slight revision of the wording 
proposed by three pipeline operators and one pipeline-related 
association. This wording meets the ``or the equivalent'' 
recommendation made by the TPSSC member. Additionally, this wording 
responds to the commenter's concern that the proposed wording would 
deter competitive pricing. The adopted wording requires that the joints 
be joined using equipment and techniques of the fittings manufacturer 
or equipment and techniques shown, by testing to certain criteria of 
ASTM Designation F1055, ``Standard Specification for Electrofusion Type 
Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe 
and Tubing,'' to be at least equivalent to those of the fittings 
manufacturer. The ASTM criteria are those adopted under the next 
heading for qualifying electrofusion joining procedures.

Section 192.283, Plastic Pipe: Qualifying Joining Procedures

    Section 192.283 prescribes criteria for qualifying procedures used 
to join plastic pipe. RSPA proposed to amend this section by adding 
more appropriate criteria for procedures used to join polyethylene 
plastic pipe by electrofusion. The proposed criteria are contained in 
certain sections of ASTM Designation F1055 (1987 edition).
    Fourteen TPSSC members voted for the proposal and one member 
abstained.
    RSPA received eight comments on the proposal: seven from pipeline 
operators and one from a pipeline-related association. Seven commenters 
supported the proposal. But one opposed it, saying that the proposal 
should be withdrawn or rewritten to accept any procedure that 
demonstrates a suitable quality of joint. We believe, however, that 
allowing operators to judge the quality of an electrofusion joint 
without applying a recognized safety standard would be unacceptable. 
Because of the failure risk of plastic pipe joints, the present rule 
requires heat fusion joining methods to be qualified under generally 
recognized voluntary standards, ASTM D2513 and ASTM D2517. In the 
absence of safety data to the contrary, as a heat fusion method, 
electrofusion procedures should likewise be qualified under an 
appropriate recognized standard. Accordingly, proposed 
Sec. 192.283(a)(iii) is adopted as final. However, the proposed 
reference to the 1987 edition of ASTM Designation F1055 is updated to 
the 1995 edition, as shown by the revisions to Appendix A of part 192 
(see below). And the referenced title of paragraph 9.4 is corrected to 
read ``Joint Integrity Tests.''

Sections 192.317(a), Protection From Hazards

    This section requires that gas transmission lines and mains be 
protected from washouts, floods, unstable soil, landslides, or other 
hazards that may cause the pipeline to move or sustain abnormal loads. 
Additionally, offshore pipelines must be protected from damage by mud 
slides, water currents, hurricanes, ship anchors, and fishing 
operations. RSPA recognized that in areas susceptible to these hazards, 
such as offshore pipelines in areas where hurricanes usually pass, 
complete protection against the hazards may not be feasible. We, 
therefore, proposed to change the regulation to require that in 
construction of transmission lines and mains, operators ``take all 
practicable steps to protect'' the pipeline against the cited hazards.
    Eleven TPSSC members voted for the proposal, one member supported 
it with a recommended change, two members were opposed and one member 
abstained. The two members who opposed it said that ``all practicable 
steps to protect'' would be difficult to interpret.
    Comments were received from seven pipeline operators and two 
pipeline-related associations. All commenters gave their full or 
qualified approval.
    RSPA has issued the final rule as proposed in the NPRM. The ``all 
practicable steps to protect'' wording was left in the rule to allow 
operators flexibility in compliance; any tightening of this performance 
wording would diminish that flexibility. RSPA will interpret or apply 
the rule in light of customary pipeline design and construction 
practices in the industry.

Secs. 192.319(c) and 192.327(e), Offshore Pipe in the Gulf of Mexico 
and Its Inlets

    Under Sec. 192.612, operators had to inspect gas pipelines in the 
Gulf of Mexico and its inlets in waters up to 15 feet deep. If the 
pipelines were found exposed or to be a hazard to navigation (i.e., 
buried less than 12 inches below the seabed), the operator had to bury 
them to a depth of 36 inches in soil or 18 inches in rock.
    The part 192 review disclosed that Secs. 192.319(c) and 192.327(e), 
which govern the installation of pipe offshore, are incompatible with 
the objectives of Sec. 192.612. In water between 12 and 200 feet deep, 
Sec. 192.319(c) permits pipe to be installed at or above the natural 
bottom. And in water less than 12 feet deep, in certain circumstances 
Sec. 192.327(e) permits pipe to be buried less than 36 inches in soil 
or 18 inches

[[Page 28778]]

in rock. RSPA proposed to amend Secs. 192.319(c) and 192.327(e) to 
require that when pipe is installed offshore in the Gulf of Mexico and 
its inlets, the pipe must be installed consistent with the burial 
standards of Sec. 192.612.
    Thirteen TPSSC members voted for the proposal, one member supported 
it with a recommended change, and one abstained. One member supported 
the proposal but recommended rewording and rearrangement for clarity, 
and that Sec. 192.319(c) be moved to Sec. 192.327.
    Seven operators and four pipeline-related associations supported 
the proposed changes to Secs. 192.319(c) and 192.327(e). However, five 
commenters recommended wording changes and rearrangement for clarity, 
and five commenters suggested that Sec. 192.319(c) be moved to 
Sec. 192.327. In light of the recommendations, RSPA has clarified the 
final rule text, as set forth below.
    One pipeline-related association opposed the proposal. It 
maintained that pipe installed in water between 12 and 15 feet deep 
with less than 12 inches of cover (now acceptable under Sec. 192.319(c) 
but not Sec. 192.612) might not be an actual hazard to navigation. But 
the proposal concerned the inconsistency of Sec. 192.612 with other 
pipeline safety rules, a problem that can be resolved without reopening 
the question of what is a ``hazard to navigation'' in the Gulf of 
Mexico and its inlets. A ``hazard to navigation'' is defined in 
Sec. 192.3 to mean ``a pipeline where the top of the pipe is less than 
12 inches below the seabed in water less than 15 feet deep, as measured 
from the mean low water.'' This definition was adopted in the 
proceeding on Sec. 192.612 (Docket No. PS-120). Any remaining 
controversy over the definition may be raised by submitting a petition 
for rulemaking under 49 CFR part 106.

Section 192.321, Installation of Plastic Pipe; and Sec. 192.375, 
Service Lines: Plastic

    Section 192.321(a) requires that plastic pipe be installed below 
ground level. RSPA proposed to allow the temporary use of uncased 
(i.e., not encased) plastic pipe above ground level under certain 
conditions. The proposed conditions limited the use to (1) 30 days; (2) 
locations where the pipe is unlikely to be damaged (or is protected 
from damage) by external forces; (3) pipe that is resistant to the 
exposure to ultraviolet light and temperature extremes; and (4) pipe 
that has not been previously used above ground level.
    Nine TPSSC members voted for the proposal, one against, three 
members supported it with a recommended change, and two abstained. The 
recommended changes were similar to those made by the commenters as 
discussed below.
    RSPA received 18 comments on this proposal. Each commenter agreed 
partially with the proposed rule. Some commenters said the current rule 
should be amended to permit the permanent use of plastic above ground 
when the pipe is encased in steel conduit. However, since the proposal 
concerned only temporary usage, this comment was not adopted in the 
final rule.
    Many commenters argued that the 30-day period would be too brief. 
They suggested a longer period, such as 60 or 90 days, in view of the 
time it may take to complete a permanent installation. They cited the 
time associated with planning, obtaining governmental permits, 
acquiring easements, engaging contractors, competing work demands, and 
other unforeseen events. Several commenters suggested that no specific 
time limit be defined and that performance language be used.
    Commenters also maintained that the proposed prohibition against 
the subsequent reuse of plastic pipe above ground level is not 
justified, since commercially available plastic pipe can be exposed to 
ultraviolet light for at least 2 years with no degradation of its 
properties. These commenters argued that the rule should permit reuse 
of plastic pipe provided such use does not exceed the pipe 
manufacturer's exposure limits.
    RSPA agrees that in most cases 30 days may not be enough time for 
operators to take full advantage of a temporary aboveground plastic 
pipe installation. In a recent waiver of Sec. 192.321(a), we allowed 
the applicant to install plastic pipe above ground for a time that does 
not exceed the manufacturer's recommended maximum period of exposure 
(60 FR 55752; Nov. 2, 1995). Although commenters indicated that 
extending the limit to 2 years might not adversely affect pipeline 
safety, we are not certain 2 years would be safe for all plastic 
materials. Some pipe manufacturers may recommend less exposure time. 
Therefore, we have chosen the manufacturer's recommended maximum period 
of exposure but not longer than 2 years as the limit on the temporary 
use of plastic pipe above ground. If a manufacturer has no recommended 
maximum exposure period, then the limit would be 2 years. RSPA does not 
believe a performance standard would provide a suitable time limit, 
because the safe service life of plastic pipe exposed above ground is 
too uncertain.
    RSPA agrees that the final rule should not unduly hinder the use of 
plastic pipe. Thus, the proposed ban on reusing plastic pipe above 
ground level does not appear justified. The final rule permits 
cumulative aboveground use for the manufacturer's recommended maximum 
period of exposure but not longer than 2 years, provided the operator 
can demonstrate the cumulative time of aboveground use. In monitoring 
compliance, RSPA will consider credible evidence that demonstrates 
cumulative time of use, such as business records, work orders, or 
affidavits related to the pipe concerned.
    RSPA recognized that the changes to Sec. 192.321 affected only 
plastic mains and transmission lines. However, the need for these 
changes applies as well to plastic service lines. As with transmission 
lines and mains, in some situations operators may be able to save 
material and construction costs of service lines located outside 
buildings by temporarily installing the lines above ground. Thus, 
Sec. 192.375(a), which requires that plastic service lines outside 
buildings be installed below ground, is revised to allow temporary 
aboveground installations in accordance with Sec. 192.321(g).

Section 192.455, External Corrosion Control: Buried or Submerged 
Pipelines Installed After July 31, 1971

    Under Sec. 192.455(a)(2), a pipeline must have a cathodic 
protection system designed to protect the pipeline in its entirety. 
RSPA proposed to remove the phrase ``in its entirety'' because it is 
unnecessary to convey the meaning of the rule, and some operators have 
incorrectly assumed that pipeline casings also must be protected.
    In addition, Sec. 192.455(f)(1) exempts from corrosion control 
requirements certain metal fittings in plastic pipelines if the fitting 
is protected against corrosion by alloyage. RSPA recognized that the 
word ``alloyage'' is not in common usage and proposed its replacement 
with ``alloy composition'' to improve understanding.
    Twelve TPSSC members voted for the proposal, two members supported 
it with a recommended change and one abstained. The two members 
recommended that in proposed paragraph (f)(1), the term ``corrosion 
resistance'' be replaced by ``corrosion control,'' which is the term 
used in the existing rule and throughout subpart I. RSPA has made this 
replacement in the final rule.
    Comments were received from six pipeline operators and one 
pipeline-related association. Six commenters gave their full approval 
and the seventh was noncommittal. Therefore, except for the previously 
discussed wording

[[Page 28779]]

changes, Sec. 192.455 is adopted as proposed in the NPRM.

Section 192.475, Internal Corrosion Control: General.

    Section 192.475(c) limits the hydrogen sulfide content of natural 
gas stored in pipe-type or bottle-type holders to 0.1 grain per 100 
standard cubic feet of gas. An operator proposed that this rule be 
relaxed to allow a concentration of 0.25 grain per 100 standard cubic 
feet of gas. Because the 0.25 limit is within customary industry 
contract limits and is still lower than maximum allowable safe limits 
set by other government agencies, RSPA proposed to increase the 
allowable hydrogen sulfide limit in gas to be stored in pipe-type and 
bottle-type holders to 0.25 grain per 100 standard cubic feet of gas. 
This action would lower the cost of processing natural gas that 
contains small quantities of hydrogen sulfide.
    Thirteen TPSSC members voted for the proposal, one against, and one 
member abstained.
    Seven commenters supported the proposed change. No commenters 
opposed the change. One state agency suggested that hydrogen sulfide 
levels be expressed in parts per million in addition to grains per 100 
standard cubic feet of gas. The NAPSR report also made this 
recommendation, and all comments on the subject were supportive. RSPA 
agrees the allowable level should be stated in parts per million and 
has included this designation in the final rule.

Section 192.485, Remedial Measures: Transmission Lines

    RSPA's review of Sec. 192.485, which prescribes remedial measures 
for corroded transmission lines, disclosed that many operators need 
guidance on how to determine the remaining strength of corroded pipe. 
RSPA proposed to provide this guidance by referencing ASME B31G Manual 
for Determining the Remaining Strength of Corroded Pipelines in a new 
Sec. 192.485(c).
    Fourteen TPSSC members voted for the proposal and one member 
abstained.
    Comments relevant to proposed Sec. 192.485(c) were received from 10 
pipeline operators and two pipeline-related associations. Six 
commenters gave their full or partial support. Another six said the 
proposal was unnecessarily restrictive because it did not allow the use 
of other proven industry-developed methods for determining the 
remaining strength of corroded pipelines.
    The most noteworthy method mentioned was the method in the American 
Gas Association (AGA) report for Project PR 3-805, ``A Modified 
Criterion for Evaluating the Remaining Strength of Corroded Pipe,'' 
(December 22, 1989; AGA catalog No. L51609). Project PR 3-805 was 
undertaken to devise a criterion that, while still assuring adequate 
pipeline integrity, would eliminate, as much as possible, the excess 
conservatism embodied in the ASME B31G Manual. For a complex analysis, 
the modified criterion can be applied by using a computer program 
called RSTRENG, which is furnished with the report. The modified 
criterion can also be applied with a long-hand equation, or if a 
simplified analysis is preferred, with tables or curves.
    Evaluating the strength of corroded pipe by procedures in ASME B31G 
or the associated AGA report is subject to the limitations specified in 
the procedures. For example, the procedures are not appropriate for 
determining the ability of pipe to withstand stresses other than stress 
from internal pressure. Thus, if corroded pipe is under significant 
secondary stress (e.g., bending stress), an additional method must be 
used to determine the pipe's remaining strength.
    The NAPSR report recommended amending Sec. 192.483 to require the 
use of appropriate guides, such as those published by ASME and the Gas 
Piping Technology Committee, whenever the remaining strength of 
corroded pipelines must be determined. The majority of commenters who 
addressed this NAPSR recommendation opposed mandatory use of the 
guides. They said operators should retain the flexibility to decide 
when calculations under the guides are necessary. Even those commenters 
who supported the recommendation thought the rule should permit the use 
of other valid methods.
    After considering the comments on proposed Sec. 192.485(c) and the 
NAPSR recommendation, we believe the NAPSR recommendation would be 
unduly restrictive. Operators are now free to use any valid method to 
determine the remaining strength of corroded pipe, and we see no 
compelling reason to restrain this flexibility. The NPRM simply 
proposed to reference guidance documents that are generally available 
for operators to use at their discretion. Moreover, the proposal was 
written in a permissive sense to assist, but not restrict, operator 
decision-making. So we have amended the regulation essentially as 
proposed, but referenced both ASME B31G and the AGA report, with 
RSTRENG, to expand the information provided.

Section 192.491, Corrosion Control Records

    Under Sec. 192.491(a), operators must maintain records or maps 
showing the location of cathodically protected piping, cathodic 
protection facilities, other than unrecorded anodes installed before 
August 1, 1971, and neighboring structures bonded to the cathodic 
protection system. RSPA proposed to amend this requirement to relieve 
operators of the burden of making precise field measurements and 
preparing and maintaining records or maps showing the specific location 
of millions of individual anodes.
    The TPSSC members voted unanimously for the proposal.
    Comments on proposed Sec. 192.491(a) were received from six 
pipeline operators, two pipeline-related associations, and one state 
agency. Eight commenters expressed their full or partial support with 
one commenter opposed. RSPA has accepted the recommendation of two 
operators that in the second sentence of proposed paragraph (a), the 
phrase ``Records and maps * * *'' should, for consistency with the rest 
of this section, be changed to ``Records or maps * * *.''
    Section 192.491(b)(2) requires that operators retain records of 
corrosion control tests, surveys, and inspections for ``as long as the 
pipeline remains in service.'' RSPA proposed to reduce this retention 
period to at least 5 years for many records, because 5 years was 
thought to be adequate for compliance investigations and analysis of 
possible corrosion problems.
    The proposal did not, however, extend to records under 
Secs. 192.465 (a) and (e) and 192.475(b). These records relate to tests 
and inspections to determine the adequacy of, or need for, external and 
internal protection on existing lines. RSPA felt strongly that these 
records should continue to be kept for the service life of the 
pipeline, because they provide a valuable database for use in assessing 
corrosion problems.
    The TPSSC unanimously supported the proposal.
    Three pipeline-related associations, 10 operators, and one state 
agency commented on the proposal. Four of these commenters agreed with 
the proposal as written; the rest qualified their support by 
recommending changes.
    Five commenters, including two pipeline-related associations and a 
state agency, were not persuaded of the importance of keeping records 
of

[[Page 28780]]

corrosion monitoring under Sec. 192.465 for the life of the pipe. Most 
of these commenters declared that 5 years would be adequate, but did 
not explain why a longer period is excessive. Lacking any convincing 
documentation to the contrary, RSPA believes the current rule should 
stay in effect. In our experience, a history of corrosion monitoring 
sheds light on the possible causes of a pipeline's condition. Such 
history has proven to be a valuable resource in deciding the extent and 
kind of remedial action needed when corrosion problems emerge on a 
pipeline.
    Regarding the proposed 5-year retention time for records other than 
those required by Secs. 192.465 (a) and (e) and 192.475(b), two 
commenters said the minimum time should be 3 years to coincide with the 
longest interval between inspections. Two others suggested that instead 
of a set time, we adopt a performance standard for record retention, 
basing it on the time needed to observe trends, inquire into 
compliance, or collect superseding data. All these comments provide a 
reasonable basis for record retention. However, our main concern is 
that operators keep records for a period that is compatible with the 
occurrence of routine compliance investigations. Therefore, for 
simplicity and uniformity, we have decided to adopt the proposed 5-year 
minimum retention time.
    The state agency that commented objected to the 5-year proposal on 
grounds that it would sacrifice information about why external or 
atmospheric corrosion control was not installed on pipelines under 
Secs. 192.455, 192.457, and 192.479. RSPA believes the loss of this 
information after 5 years would not be significant, because the 
pipelines involved are covered by requirements for periodic inspections 
or tests for corrosion under Secs. 192.465 and 192.481.

Section 192.553, General Requirements

(See previous discussion under Sec. 192.14).

Section 192.607, Determination of Class Location and Maximum Allowable 
Operating Pressure

    Because Sec. 192.607 has no continuing effect and the deadlines for 
compliance have expired, RSPA proposed to remove Sec. 192.607 from part 
192.
    Fourteen TPSSC members voted for the proposal and one member 
abstained.
    Five operators, one pipeline-related association, and one state 
agency commented on the proposed removal of Sec. 192.607. Four 
operators and the association favored the idea. One operator and the 
state agency disagreed with removal, believing the rule is needed to 
tie a pipeline's maximum allowable operating pressure (MAOP) to its 
class location. Similarly, the NAPSR report recommended that we only 
remove the past compliance deadlines from Sec. 192.607, leaving the 
rest of the rule in place to regulate the relation of class location to 
stress level on high-stress pipelines.
    Section 192.607 was a transitional requirement. Its purpose was to 
establish plans under which operators initially determined class 
locations and confirmed or revised the MAOPs of their high-stress 
pipelines commensurate with their class locations. Section 192.607 
provides that the plans had to be executed in accordance with 
Sec. 192.611. This latter section together with Sec. 192.609 are 
sufficient to require that operators have up-to-date class location 
determinations for high-stress pipelines, and maintain the MAOPs of 
those lines commensurate with their class locations.
    Accordingly, Sec. 192.607 is removed from part 192.

Section 192.611, Change in Class Location

    Section 192.611 requires confirmation or revision of a pipeline's 
MAOP within 18 months after a change in class location. RSPA proposed 
to reorganize Sec. 192.611 to clarify the requirement that the MAOP 
resulting from confirmation or revision may not exceed the pipeline's 
previous MAOP. This requirement is currently set forth in 
Sec. 192.611(a)(3)(ii), suggesting that it applies only to 
confirmations or revisions under paragraph (a)(3), which is not the 
intent.
    Fourteen TPSSC members voted for the proposal and one member 
abstained.
    Five operators and one pipeline-related association commented on 
the proposal; each agreed with the proposal. Section 192.611 is, 
therefore, adopted as proposed in the NPRM.

Section 192.614, Damage Prevention Program

    To decrease excavation damage to pipelines, Sec. 192.614(b)(2) 
requires operators to notify excavators and the public about the need 
to locate buried pipelines before excavating. The NPRM proposed to 
amend the rule to clarify that in contrast to the actual notification 
required for excavators, only general notification is required for the 
public. General notice can be given through newspapers, radio, 
television, or other means of mass communication, as appropriate for 
the public in the vicinity of the pipeline.
    Fourteen TPSSC members voted for the proposal and one member 
abstained.
    Six pipeline operators and two pipeline-related organizations 
commented. Seven commenters gave their full or qualified approval and 
one commenter opposed the proposal. The qualified and negative comments 
were that the rule should inform operators of the acceptable means of 
notification. We do not feel it is necessary for the rule to do so, 
however, because the available means of giving general public notice 
are well known. The amendment to paragraph (b)(2) is adopted as 
proposed.

Section 192.619, Maximum Allowable Operating Pressure: Steel or Plastic 
Pipelines

    Section 192.619(a) prescribes six pressure limits for use in 
determining the MAOP of steel and plastic pipelines, the lowest of 
which establishes the MAOP. Paragraph (a)(4) limits the MAOP of furnace 
butt welded pipe to 60 percent of the mill test pressure. Paragraph 
(a)(5) limits the MAOP of other steel pipe to 85 percent of the highest 
test pressure to which the pipe has been subjected, whether by mill 
test or by the post installation test.
    RSPA proposed to repeal paragraphs (a)(4) and (a)(5), primarily 
because mill tests are not an adequate MAOP consideration. However, to 
assure consideration of longitudinal joint efficiency, RSPA also 
proposed, in paragraph (a)(2)(iii), that the class location pressure 
limit under existing paragraph (a)(2)(ii) be reduced for furnace butt 
welded pipe and lap welded pipe.
    Eleven TPSSC members voted for the proposal, one member supported 
it with a recommended change, two members opposed it, and one 
abstained. A member recommended that RSPA not adopt proposed paragraph 
(a)(2)(iii) because design pressure (under paragraph (a)(1)) adequately 
covers longitudinal joint concerns.
    RSPA concurs with this view as explained below in response to 
public comment.
    Thirteen operators, four pipeline-related associations, and one 
state agency commented on the proposed amendment. Two operators, one 
pipeline-related association, and one state agency commented that 
proposed paragraph (a)(2)(iii) could require operators to reduce the 
operating pressure of some pipelines or test them to higher pressures 
than they previously were tested, possibly damaging the pipelines. In 
addition, some commenters stated that proposed paragraph (a)(2)(iii) 
would duplicate use of longitudinal joint factors.

[[Page 28781]]

    Upon further consideration of our joint efficiency concern, RSPA 
concurs with these comments. Further, RSPA has no data showing that 
pipelines covered by proposed paragraph (a)(2)(iii) pose a risk that 
warrants pressure reduction or retesting. Therefore, although the final 
rule repeals paragraphs (a)(4) and (a)(5) as proposed, proposed 
paragraph (a)(2)(iii) is not adopted.

Section 192.625, Odorization of Gas

    Section 192.619(f) requires operators to conduct periodic samplings 
of gas to assure the proper concentration of odorant. Based on a 
suggestion by the Oregon Public Utility Commission, the NPRM proposed 
to allow operators of master meter systems to comply with this sampling 
requirement by (1) receiving written verification from their gas 
supplier that odorant meets the required concentration, and (2) 
conducting periodic sniff tests at system extremities to confirm that 
the gas contains odorant.
    Thirteen TPSSC members voted for the proposal, one against, and one 
member abstained.
    Comments were received from eight pipeline operators, two pipeline-
related associations, a mobile home association, and a consultant. One 
commenter favored the proposal and 11 commenters opposed it. Commenters 
opposing the proposal argued that (1) gas from a transmission line may 
be unodorized; (2) gas suppliers may be unwilling to provide written 
verification of odorization levels because of potential legal liability 
and the increased burden of providing the written verifications; (3) 
the frequencies of sniff tests and written verifications are unclear; 
and (4) the proposal would relax odorant monitoring requirements on gas 
systems which, in general, have a relatively high leakage rate.
    The purpose of the proposal was to ease the sampling requirement 
for operators of master meter systems, who largely do not have the 
training or resources to adequately carry out the requirement. The 
alternative of getting written verifications and conducting sniff tests 
should be much less burdensome than purchasing, maintaining, and using 
an odorometer or contracting for odorant testing.
    We do not feel this potential advantage is outweighed by any of the 
negative considerations the commenters raised. First of all, most 
master meter system operators purchase odorized gas from local 
distribution companies. Although some operators may receive unodorized 
gas from transmission lines and have to odorize the gas themselves, 
this situation does not warrant rejecting the proposed alternative. 
Those operators who receive unodorized gas simply would not be able to 
take advantage of the alternative. Similarly, operators could not take 
advantage of the alternative if their gas suppliers are unwilling to 
provide requested verifications of odorant level. But again this 
difficulty is no reason to deny the alternative to other operators. 
Regarding the frequency of verifications and sniff tests, the proposal 
called for an initial written verification from the gas supplier and 
periodic sniff tests thereafter. As with periodic sampling, the 
frequency of sniff tests would depend on the performance history of 
odorization in the system: the longer the period of satisfactory 
odorization, the longer the period between tests to assure proper 
odorant levels. Testing details would be specified in the operator's 
operations and maintenance manual under Sec. 192.605 and reviewed for 
adequacy by government inspectors. Finally, the charge that master 
meter systems have a high leakage rate was unsupported. In a 1984 
report, ``Exercise of Jurisdiction Over Master Meter Gas Operators,'' 
RSPA concluded that master meter systems probably have a small leakage 
rate in comparison to the leakage rate of utility distribution systems. 
And more recent safety data continue to substantiate that conclusion. 
Therefore, after weighing the comments and favorable TPSSC vote, we 
have decided to amend Sec. 192.625(f) as proposed.

Section 192.705, Transmission Lines: Patrolling

    Operators of transmission lines must patrol their rights-of-way for 
indications of certain adverse conditions. Because of repeated 
questions about whether patrols may be done from the air, RSPA proposed 
to change Sec. 192.705 to include aerial patrols as an optional method 
of compliance.
    Fourteen TPSSC members voted for the proposal and one abstained.
    Six operators and one pipeline-related association commented on the 
proposal. All but two of these commenters agreed with the proposal. One 
commenter that disagreed said a list of methods of compliance might be 
considered exclusive, thus disallowing other appropriate methods. The 
other commenter that disagreed thought the rule change unnecessary.
    RSPA believes the phrase ``or other appropriate means of traversing 
the right-of-way'' in the proposed and final rule eliminates any chance 
the list of compliance methods might be considered exclusive. Also, the 
need for the rule change is based on RSPA's experience in explaining 
the meaning of ``patrol'' under Sec. 192.705. The change to 
Sec. 192.705 is, therefore, adopted as proposed.

Section 192.709, Transmission Lines: Record Keeping

    Section 192.709 requires operators to keep various records about 
transmission lines for as long as the line remains in service. RSPA 
proposed a shorter retention span that would not affect the usefulness 
of records in determining an operator's level of compliance effort or 
in constructing the history of an accident or safety problem. RSPA 
proposed a minimum 5-year retention period for records of patrols, 
surveys, inspections, and tests, and a 1-year retention period for 
records of repairs on facilities other than pipe. We also proposed to 
clarify the information to be recorded.
    Ten TPSSC members voted for the proposal, three members supported 
it with a recommended change, one member opposed it, and one abstained. 
The recommended changes were that 5 years should be changed to 3-5 
years or to 10 years, and that leaks and linebreaks should also be 
recorded as the current Sec. 192.709 provides. The ``No'' vote was 
predicated on an alleged need to keep records of repairs on valves, 
compressors, and other non- pipe components for 3-5 years.
    As with final Sec. 192.491(c), RSPA's main concern about non-pipe 
records is that operators keep records for a minimum period that is 
compatible with the occurrence of routine compliance investigations. 
The suggested 3-5 years would not be long enough, and 10 years would be 
excessive. Therefore, we have adopted the proposed 5-year minimum 
period.
    Repair records, as currently required, already provide information 
about leaks and linebreaks. Thus, requirements to keep the records of 
leaks and linebreaks were omitted from the proposed rule as unnecessary 
in view of this existing requirement.
    As for the ``No'' vote, RSPA has adopted this minority TPSSC 
position as explained below in response to a comment by a state agency.
    Eight operators, two pipeline-related associations, and one state 
agency commented on the proposed changes to Sec. 192.709. Five of the 
operators supported the proposal without suggesting any modification.
    Two other operators suggested 3 years as an alternative to the 
proposed 5-year minimum. But, as explained above, 3 years is 
insufficient for compliance monitoring purposes.

[[Page 28782]]

    One operator thought the words ``for the useful life of the pipe'' 
under proposed Sec. 192.709(a) could be misinterpreted. This commenter 
suggested that instead we adopt the words used in Sec. 192.491(c): 
``for as long as the pipeline remains in service.'' We agree that for 
consistency the two sections should use similar wording to describe 
similar record retention requirements. This comment was, therefore, 
adopted in the final rule.
    One pipeline-related association recommended that Sec. 192.709 be 
like 49 CFR 195.404(c), which applies to hazardous liquid pipelines. We 
did not adopt this comment because Sec. 195.404(c) specifies a 2-year 
retention period for records of inspections and tests, a time we now 
find to be insufficient for purposes of compliance investigations. 
Otherwise the two sections are parallel. The other association 
reiterated its previous comment, which we opposed as discussed above, 
that record retention requirements should be performance based.
    The state agency that commented objected to the proposed 1-year 
retention time for non-pipe repairs, saying it was inconsistent with 
the proposal to keep for at least 5 years records of inspections that 
may show the need for repair. This commenter reasoned that an inspector 
might not find any record showing the needed repair was made. RSPA 
agrees that the two requirements should be congruent. Therefore, the 
final rule requires that records of non-pipe repairs made as a result 
of a required patrol, survey, inspection, or test be kept for the same 
time required for records of such patrol, survey, inspection, or test.

Section 192.721, Distribution Systems: Patrolling

    This section governs the frequency at which operators must patrol 
mains in distribution systems. The regulation is written in performance 
terms, except that mains located where anticipated movement or loading 
could cause leakage must be patrolled at intervals not exceeding 4\1/2\ 
months, but at least four times a year. RSPA proposed a more moderate 
patrol frequency of twice a year for such mains in Class 1 or 2 
locations, in recognition of the lower risk in these less densely 
populated locations.
    Twelve TPSSC members voted for the proposal, one against, one 
member supported it with a proposed change, and one abstained. The 
member against the proposal said that separating requirements on the 
basis of class locations is not always workable for distribution 
systems. Our response to this minority view is given below following 
similar comments by operators.
    Four operators and two pipeline-related associations commented on 
the proposal. Three of the operators and one association supported the 
proposal, but the other operator and association thought class location 
should not be used as a basis for patrol frequency in distribution 
systems. One commenter suggested ``rural areas'' as an alternative to 
Class 1 and 2 locations.
    RSPA agrees that the class location concept is not easy to apply in 
all distribution systems. Therefore, in the final rule, we have used 
the term ``business district'' to represent areas of higher risk and 
``outside business districts'' to represent areas of lower risk. A 
similar classification method is already in place under Sec. 192.723 
for leakage surveys in distribution systems. The new patrol requirement 
matches that method. The term ``rural area'' was not adopted because it 
lacks precedent in part 192.

Rulemaking Notices and Analyses

Paperwork Reduction Act

    This Final Rule revises information collection requirements in part 
192 that are subject to review by the Office of Management and Budget 
(OMB) under the Paperwork Reduction Act of 1995 (Pub. L. 104-13). The 
following revised regulations reduce the existing paperwork burden by 
28,326 hours:
    <bullet> Secs. 192.491 (a) and (b), ``Corrosion Control Records,'' 
reduces the paperwork burden by 22,486 hours by reducing the number of 
records, the precision of the measurements, and the amount of time the 
records must be kept.
    <bullet> Sec. 192.709, ``Transmission Lines; Record keeping,'' 
reduces the paperwork burden by 5,840 hours by reducing the amount of 
time the records must be kept.
    Persons are not required to respond to a collection of information 
unless it displays a currently valid OMB control number. OMB has 
approved the revised information collection requirements of part 192 
through May 31, 1999 (OMB No. 2137-0049).

Executive Order 12866 and DOT Regulatory Policies and Procedures

    OMB considers this final rule to be a significant regulatory action 
under section 3(f) of Executive Order 12866. Therefore, OMB has 
reviewed the final rule. Also, DOT considers the final rule to be 
significant under its regulatory policies and procedures (44 FR 11034, 
February 26, 1979).
    A final regulatory evaluation has been prepared and is available in 
the Docket. RSPA estimates the changes to existing rules will result in 
savings of $33,000,000 a year, without associated costs and with no 
adverse effect on safety. As discussed above, these savings come from 
the use of new technology, greater flexibility in constructing, 
maintaining, and operating pipelines, improved clarity, and the 
elimination of burdensome requirements.

Regulatory Flexibility Act.

    RSPA criteria for small companies or entities are those with less 
than $1,000,000 in revenues and are independently owned and operated. 
Few of the companies subject to this rulemaking meet these criteria. 
Accordingly, based on the facts available concerning the impact of this 
final rule, I certify under Section 605 of the Regulatory Flexibility 
Act that this final rule will not have a significant economic impact on 
a substantial number of small entities.

E. O. 12612

    The final rule would not have substantial direct effects on states, 
on the relationship between the Federal Government and the states, or 
on the distribution of power and responsibilities among the various 
levels of Government. Therefore, in accordance with Executive Order 
12612 (52 FR 41685; October 30,1987), RSPA has determined that the 
final rule does not have sufficient federalism implications to warrant 
preparation of a Federalism Assessment.

List of Subjects in 49 CFR Part 192

    Incorporation by reference, Natural gas, Pipeline safety, Reporting 
and recordkeeping requirements.

    In consideration of the foregoing, RSPA amends 49 CFR part 192 as 
follows:

PART 192--[AMENDED]

    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; 49 CFR 1.53.

    2. In Sec. 192.1, paragraph (b)(1) is revised and paragraph (b)(4) 
is added to read as follows:


Sec. 192.1  Scope of part.

* * * * *
    (b) This part does not apply to:
    (1) Offshore pipelines upstream from the outlet flange of each 
facility where hydrocarbons are produced or where

[[Page 28783]]

produced hydrocarbons are first separated, dehydrated, or otherwise 
processed, whichever facility is farther downstream;
* * * * *
    (4) Any pipeline system that transports only petroleum gas or 
petroleum gas/air mixtures to--
    (i) Fewer than 10 customers, if no portion of the system is located 
in a public place; or
    (ii) A single customer, if the system is located entirely on the 
customer's premises (no matter if a portion of the system is located in 
a public place).
    3. In Sec. 192.3, a definition of ``Petroleum gas'' is added and 
the definition of ``Transmission line'' is revised to read as follows:


Sec. 192.3  Definitions.

* * * * *
    Petroleum gas means propane, propylene, butane, (normal butane or 
isobutanes), and butylene (including isomers), or mixtures composed 
predominantly of these gases, having a vapor pressure not exceeding 
1434 kPa (208 psig) at 38 deg.C (100 deg.F).
* * * * *
    Transmission line means a pipeline, other than a gathering line, 
that:
    (a) Transports gas from a gathering line or storage facility to a 
distribution center, storage facility, or large volume customer that is 
not downstream from a distribution center;
    (b) Operates at a hoop stress of 20 percent or more of SMYS; or
    (c) Transports gas within a storage field. A large volume customer 
may receive similar volumes of gas as a distribution center, and 
includes factories, power plants, and institutional users of gas.
* * * * *
    4. Section 192.5 is revised to read as follows:


Sec. 192.5  Class locations.

    (a) This section classifies pipeline locations for purposes of this 
part. The following criteria apply to classifications under this 
section.
    (1) A ``class location unit'' is an onshore area that extends 220 
yards on either side of the centerline of any continuous 1- mile length 
of pipeline.
    (2) Each separate dwelling unit in a multiple dwelling unit 
building is counted as a separate building intended for human 
occupancy.
    (b) Except as provided in paragraph (c) of this section, pipeline 
locations are classified as follows:
    (1) A Class 1 location is:
    (i) An offshore area; or
    (ii) Any class location unit that has 10 or fewer buildings 
intended for human occupancy.
    (2) A Class 2 location is any class location unit that has more 
than 10 but fewer than 46 buildings intended for human occupancy.
    (3) A Class 3 location is:
    (i) Any class location unit that has 46 or more buildings intended 
for human occupancy; or
    (ii) An area where the pipeline lies within 100 yards of either a 
building or a small, well-defined outside area (such as a playground, 
recreation area, outdoor theater, or other place of public assembly) 
that is occupied by 20 or more persons on at least 5 days a week for 10 
weeks in any 12-month period. (The days and weeks need not be 
consecutive.)
    (4) A Class 4 location is any class location unit where buildings 
with four or more stories above ground are prevalent.
    (c) The length of Class locations 2, 3, and 4 may be adjusted as 
follows:
    (1) A Class 4 location ends 220 yards from the nearest building 
with four or more stories above ground.
    (2) When all buildings intended for human occupancy within a Class 
2 or 3 location are in a single cluster, the class location ends 220 
yards from the nearest building in the cluster.
    5. Section 192.7(a) is revised to read as follows:


Sec. 192.7  Incorporation by reference.

    (a) Any documents or portions thereof incorporated by reference in 
this part are included in this part as though set out in full. When 
only a portion of a document is referenced, the remainder is not 
incorporated in this part.
* * * * *
    6. Section 192.11 is revised to read as follows:


Sec. 192.11  Petroleum gas systems.

    (a) Each plant that supplies petroleum gas by pipeline to a natural 
gas distribution system must meet the requirements of this part and 
ANSI/NFPA 58 and 59.
    (b) Each pipeline system subject to this part that transports only 
petroleum gas or petroleum gas/air mixtures must meet the requirements 
of this part and of ANSI/NFPA 58 and 59.
    (c) In the event of a conflict between this part and ANSI/NFPA 58 
and 59, ANSI/NFPA 58 and 59 prevail.
    7. Section 192.107(b)(1)(ii) is revised to read as follows:


Sec. 192.107  Yield strength (S) for steel pipe.

* * * * *
    (b) * * *
    (1) * * *
    (ii) The lowest yield strength determined by the tensile tests.
* * * * *
    8. Section 192.121 is revised to read as follows:


Sec. 192.121  Design of plastic pipe.

    Subject to the limitations of Sec. 192.123, the design pressure for 
plastic pipe is determined in accordance with either of the following 
formulas:
[GRAPHIC] [TIFF OMITTED] TR06JN96.013

Where:

P=Design pressure, gauge, kPa (psig).
S=For thermoplastic pipe, the long-term hydrostatic strength determined 
in accordance with the listed specification at a temperature equal to 
23 deg.C (73 deg.F), 38 deg.C (100 deg.F), 49 deg.C (120 deg.F), or 
60 deg.C (140 deg.F); for reinforced thermosetting plastic pipe, 75,842 
kPa (11,000 psi).
t=Specified wall thickness, mm (in).
D=Specified outside diameter, mm (in).
SDR=Standard dimension ratio, the ratio of the average specified 
outside diameter to the minimum specified wall thickness, corresponding 
to a value from a common numbering system that was derived from the 
American National Standards Institute preferred number series 10.

    9. Section 192.123(b) is revised to read as follows:


Sec. 192.123  Design limitations for plastic pipe.

* * * * *
    (b) * * *
    (1) Below -29 deg.C (-20 deg.F), or -40 deg.C (-40 deg.F) if all 
pipe and pipeline components whose operating temperature will be below 
-29 deg.C (-20 deg.F) have a temperature rating by the manufacturer 
consistent with that operating temperature; or
    (2) Above the following applicable temperatures:
    (i) For thermoplastic pipe, the temperature at which the long-term 
hydrostatic strength used in the design formula under Sec. 192.121 is 
determined. However, if the pipe was manufactured before May 18, 1978 
and its long-term hydrostatic strength was determined at 23 deg.C 
(73 deg.F), it may be used at temperatures up to 38 deg.C (100 deg.F).
    (ii) For reinforced thermosetting plastic pipe, 66 deg.C 
(150 deg.F).
* * * * *

[[Page 28784]]

    10. The introductory text of Sec. 192.179(a) is revised to read as 
follows:


Sec. 192.179  Transmission line valves.

    (a) Each transmission line, other than offshore segments, must have 
sectionalizing block valves spaced as follows, unless in a particular 
case the Administrator finds that alternative spacing would provide an 
equivalent level of safety:
* * * * *
    11. Section 192.203(b)(2) is revised to read as follows:


Sec. 192.203  Instrument, control, and sampling pipe and components.

* * * * *
    (b) * * *
    (2) Except for takeoff lines that can be isolated from sources of 
pressure by other valving, a shutoff valve must be installed in each 
takeoff line as near as practicable to the point of takeoff. Blowdown 
valves must be installed where necessary.
* * * * *
    12. Section 192.227(b) is revised to read as follows:


Sec. 192.227  Qualification of welders.

* * * * *
    (b) A welder may qualify to perform welding on pipe to be operated 
at a pressure that produces a hoop stress of less than 20 percent of 
SMYS by performing an acceptable test weld, for the process to be used, 
under the test set forth in section I of Appendix C of this part. Each 
welder who is to make a welded service line connection to a main must 
first perform an acceptable test weld under section II of Appendix C of 
this part as a requirement of the qualifying test.
    13. In Sec. 192.229, paragraph (c) is revised and paragraph (d) is 
added to read as follows:


Sec. 192.229  Limitations on welders.

* * * * *
    (c) A welder qualified under Sec. 192.227(a)--
    (1) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of 20 percent or more of SMYS unless within the preceding 
6 calendar months the welder has had one weld tested and found 
acceptable under section 3 or 6 of API Standard 1104, except that a 
welder qualified under an earlier edition previously listed in Appendix 
A of this part may weld but may not requalify under that earlier 
edition; and
    (2) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of less than 20 percent of SMYS unless the welder is 
tested in accordance with paragraph (c)(1) of this section or 
requalifies under paragraph (d)(1) or (d)(2) of this section.
    (d) A welder qualified under Sec. 192.227(b) may not weld unless--
    (1) Within the preceding 15 calendar months, but at least once each 
calendar year, the welder has requalified under Sec. 192.227(b); or
    (2) Within the preceding 7\1/2\ calendar months, but at least twice 
each calendar year, the welder has had--
    (i) A production weld cut out, tested, and found acceptable in 
accordance with the qualifying test; or
    (ii) For welders who work only on service lines 2 inches or smaller 
in diameter, two sample welds tested and found acceptable in accordance 
with the test in section III of Appendix C of this part.
    14. Section 192.241(c) is revised to read as follows:


Sec. 192.241  Inspection and test of welds.

* * * * *
    (c) The acceptability of a weld that is nondestructively tested or 
visually inspected is determined according to the standards in section 
6 of API Standard 1104. However, if a girth weld is unacceptable under 
those standards for a reason other than a crack, and if the Appendix to 
API Standard 1104 applies to the weld, the acceptability of the weld 
may be further determined under that Appendix.
    15. Section 192.243(d)(4) is revised to read as follows:


Sec. 192.243  Nondestructive testing.

* * * * *
    (d) * * *
    (4) At pipeline tie-ins, including tie-ins of replacement sections, 
100 percent.
* * * * *
    16. In Sec. 192.281, paragraph (c)(3) is redesignated as paragraph 
(c)(4) and paragraph (c)(3) is added to read as follows:


Sec. 192.281  Plastic pipe.

* * * * *
    (c) * * *
    (3) An electrofusion joint must be joined utilizing the equipment 
and techniques of the fittings manufacturer or equipment and techniques 
shown, by testing joints to the requirements of 
Sec. 192.283(a)(1)(iii), to be at least equivalent to those of the 
fittings manufacturer.
* * * * *
    17. In Sec. 192.283, the word ``or'' is removed from the end of 
paragraph (a)(1)(i), paragraph (a)(1)(ii) is revised, and paragraph 
(a)(1)(iii) is added to read as follows:


Sec. 192.283  Plastic pipe; qualifying joining procedures.

    (a) * * *
    (1) * * *
    (ii) In the case of thermosetting plastic pipe, paragraph 8.5 
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static 
Pressure Test) of ASTM D2517; or
    (iii) In the case of electrofusion fittings for polyethylene pipe 
and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), 
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile 
Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM 
Designation F1055.
* * * * *
    18. Section 192.317(a) is revised to read as follows:


Sec. 192.317  Protection from hazards.

    (a) The operator must take all practicable steps to protect each 
transmission line or main from washouts, floods, unstable soil, 
landslides, or other hazards that may cause the pipeline to move or to 
sustain abnormal loads. In addition, the operator must take all 
practicable steps to protect offshore pipelines from damage by mud 
slides, water currents, hurricanes, ship anchors, and fishing 
operations.
* * * * *
    19. Section 192.319(c) is revised to read as follows:


Sec. 192.319  Installation of pipe in a ditch.

* * * * *
    (c) All offshore pipe in water at least 12 feet deep but not more 
than 200 feet deep, as measured from the mean low tide, except pipe in 
the Gulf of Mexico and its inlets under 15 feet of water, must be 
installed so that the top of the pipe is below the natural bottom 
unless the pipe is supported by stanchions, held in place by anchors or 
heavy concrete coating, or protected by an equivalent means. Pipe in 
the Gulf of Mexico and its inlets under 15 feet of water must be 
installed so that the top of the pipe is 36 inches below the seabed for 
normal excavation or 18 inches for rock excavation.
    20. In Sec. 192.321, paragraph (a) is revised and paragraph (g) is 
added to read as follows:


Sec. 192.321  Installation of plastic pipe.

    (a) Plastic pipe must be installed below ground level unless 
otherwise permitted by paragraph (g) of this section.
* * * * *
    (g) Uncased plastic pipe may be temporarily installed above ground 
level under the following conditions:

[[Page 28785]]

    (1) The operator must be able to demonstrate that the cumulative 
aboveground exposure of the pipe does not exceed the manufacturer's 
recommended maximum period of exposure or 2 years, whichever is less.
    (2) The pipe either is located where damage by external forces is 
unlikely or is otherwise protected against such damage.
    (3) The pipe adequately resists exposure to ultraviolet light and 
high and low temperatures.
    21. In Sec. 192.327, the introductory text of paragraph (a) is 
revised, paragraph (e) is revised, and paragraphs (f) and (g) are added 
to read as follows:


Sec. 192.327  Cover.

* * * * *
    (a) Except as provided in paragraphs (c), (e), (f), and (g) of this 
section, each buried transmission line must be installed with a minimum 
cover as follows:
* * * * *
    (e) Except as provided in paragraph (c) of this section, all pipe 
installed in a navigable river, stream, or harbor must be installed 
with a minimum cover of 48 inches in soil or 24 inches in consolidated 
rock between the top of the pipe and the natural bottom.
    (f) All pipe installed offshore, except in the Gulf of Mexico and 
its inlets, under water not more than 200 feet deep, as measured from 
the mean low tide, must be installed as follows:
    (1) Except as provided in paragraph (c) of this section, pipe under 
water less than 12 feet deep, must be installed with a minimum cover of 
36 inches in soil or 18 inches in consolidated rock between the top of 
the pipe and the natural bottom.
    (2) Pipe under water at least 12 feet deep must be installed so 
that the top of the pipe is below the natural bottom, unless the pipe 
is supported by stanchions, held in place by anchors or heavy concrete 
coating, or protected by an equivalent means.
    (g) All pipelines installed under water in the Gulf of Mexico and 
its inlets, as defined in Sec. 192.3, must be installed in accordance 
with Sec. 192.612(b)(3).
    22. Section 192.375(a) is revised to read as follows:


Sec. 192.375  Service lines: Plastic.

    (a) Each plastic service line outside a building must be installed 
below ground level, except that--
    (1) It may be installed in accordance with Sec. 192.321(g); and
    (2) It may terminate above ground level and outside the building, 
if--
    (i) The above ground level part of the plastic service line is 
protected against deterioration and external damage; and
    (ii) The plastic service line is not used to support external 
loads.
* * * * *
    23. In Sec. 192.455, paragraphs (a)(2) and (f)(1) are revised to 
read as follows:


Sec. 192.455  External corrosion control: Buried or submerged pipelines 
installed after July 31, 1971.

    (a) * * *
    (2) It must have a cathodic protection system designed to protect 
the pipeline in accordance with this subpart, installed and placed in 
operation within 1 year after completion of construction.
* * * * *
    (f) * * *
    (1) For the size fitting to be used, an operator can show by test, 
investigation, or experience in the area of application that adequate 
corrosion control is provided by the alloy composition; and
* * * * *
    24. Section 192.475(c) is revised to read as follows:


Sec. 192.475  Internal corrosion control: General.

* * * * *
    (c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 
standard cubic feet (4 parts per million) may not be stored in pipe-
type or bottle-type holders.
    25. Section 192.485(c) is added to read as follows:


Sec. 192.485  Remedial measures: Transmission lines.

* * * * *
    (c) Under paragraphs (a) and (b) of this section, the strength of 
pipe based on actual remaining wall thickness may be determined by the 
procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research 
Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply 
to corroded regions that do not penetrate the pipe wall, subject to the 
limitations prescribed in the procedures.
    26. Section 192.491 is revised to read as follows:


Sec. 192.491  Corrosion control records.

    (a) Each operator shall maintain records or maps to show the 
location of cathodically protected piping, cathodic protection 
facilities, galvanic anodes, and neighboring structures bonded to the 
cathodic protection system. Records or maps showing a stated number of 
anodes, installed in a stated manner or spacing, need not show specific 
distances to each buried anode.
    (b) Each record or map required by paragraph (a) of this section 
must be retained for as long as the pipeline remains in service.
    (c) Each operator shall maintain a record of each test, survey, or 
inspection required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that a corrosive 
condition does not exist. These records must be retained for at least 5 
years, except that records related to Secs. 192.465 (a) and (e) and 
192.475(b) must be retained for as long as the pipeline remains in 
service.
    27. Section 192.553(d) is revised to read as follows:


Sec. 192.553  General requirements.

* * * * *
    (d) Limitation on increase in maximum allowable operating pressure. 
Except as provided in Sec. 192.555(c), a new maximum allowable 
operating pressure established under this subpart may not exceed the 
maximum that would be allowed under this part for a new segment of 
pipeline constructed of the same materials in the same location. 
However, when uprating a steel pipeline, if any variable necessary to 
determine the design pressure under the design formula (Sec. 192.105) 
is unknown, the MAOP may be increased as provided in 
Sec. 192.619(a)(1).


Sec. 192.607  [Removed and reserved]

    28. Section 192.607 is removed and reserved.


Sec. 192.611  [Amended]

    29. In Sec. 192.611, paragraphs (b) and (c) are redesignated as (c) 
and (d), respectively; paragraph (a)(3)(ii) is redesignated as 
paragraph (b), and paragraph (a)(3)(iii) is redesignated as paragraph 
(a)(3)(ii).
    30. In Sec. 192.614, the introductory text of paragraph (b)(2) is 
revised to read as follows:


Sec. 192.614  Damage prevention program.

* * * * *
    (b) * * * 
    (2) Provide for general notification of the public in the vicinity 
of the pipeline and actual notification of the persons identified in 
paragraph (b)(1) of the following as often as needed to make them aware 
of the damage prevention program:
* * * * *
    31. In Sec. 192.619, paragraph (a)(1) is revised to read as 
follows, paragraphs (a)(4) and (a)(5) are removed, paragraph (a)(6) is 
redesignated as paragraph (a)(4), and paragraph (b) is amended by 
removing ``(a)(6)'' and adding ``(a)(4)'' in its place:


Sec. 192.619  Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) * * *

[[Page 28786]]

    (1) The design pressure of the weakest element in the segment, 
determined in accordance with subparts C and D of this part. However, 
for steel pipe in pipelines being converted under Sec. 192.14 or 
uprated under subpart K of this part, if any variable necessary to 
determine the design pressure under the design formula (Sec. 192.105) 
is unknown, one of the following pressures is to be used as design 
pressure:
    (i) Eighty percent of the first test pressure that produces yield 
under section N5.0 of Appendix N of ASME B31.8, reduced by the 
appropriate factor in paragraph (a)(2)(ii) of this section; or
    (ii) If the pipe is 324 mm (12\3/4\ in) or less in outside diameter 
and is not tested to yield under this paragraph, 1379 kPa (200 psig).
* * * * *
    32. Section 192.625 (f) is revised to read as follows:


Sec. 192.625  Odorization of gas.

* * * * *
    (f) Each operator shall conduct periodic sampling of combustible 
gases to assure the proper concentration of odorant in accordance with 
this section. Operators of master meter systems may comply with this 
requirement by--
    (1) Receiving written verification from their gas source that the 
gas has the proper concentration of odorant; and
    (2) Conducting periodic ``sniff'' tests at the extremities of the 
system to confirm that the gas contains odorant.
    33. Section 192.705(c) is added to read as follows:


Sec. 192.705  Transmission lines: Patrolling.

* * * * *
    (c) Methods of patrolling include walking, driving, flying or other 
appropriate means of traversing the right-of-way.
    34. Section 192.709 is revised to read as follows:


Sec. 192.709  Transmission lines: Record keeping.

    Each operator shall maintain the following records for transmission 
lines for the periods specified:
    (a) The date, location, and description of each repair made to pipe 
(including pipe-to-pipe connections) must be retained for as long as 
the pipe remains in service.
    (b) The date, location, and description of each repair made to 
parts of the pipeline system other than pipe must be retained for at 
least 5 years. However, repairs generated by patrols, surveys, 
inspections, or tests required by subparts L and M of this part must be 
retained in accordance with paragraph (c) of this section.
    (c) A record of each patrol, survey, inspection, and test required 
by subparts L and M of this part must be retained for at least 5 years 
or until the next patrol, survey, inspection, or test is completed, 
whichever is longer.
    35. Section 192.721(b) is revised to read as follows:


Sec. 192.721  Distribution systems: Patrolling.

* * * * *
    (b) Mains in places or on structures where anticipated physical 
movement or external loading could cause failure or leakage must be 
patrolled--
    (1) In business districts, at intervals not exceeding 4\1/2\ 
months, but at least four times each calendar year; and
    (2) Outside business districts, at intervals not exceeding 7\1/2\ 
months, but at least twice each calendar year.
    36. In Appendix A, section I. is amended by redesignating 
subsections A. through F. as subsections B. through G., respectively, 
and by adding a new subsection A.; and section II. is amended by 
redesignating subsections A. through E. as subsections B. through F., 
respectively, by adding a new subsection A. and a new subsection 12. to 
newly designated C., by redesignating newly designated subsections D.3. 
through D.5. as subsections D.5. through D.7., respectively, and by 
adding new subsections D.3. and D.4. as follows:

Appendix A--Incorporated by Reference

    I. * * *
    A. American Gas Association (AGA), 1515 Wilson Boulevard, 
Arlington, VA 22209.
* * * * *
    II. * * *
    A. American Gas Association (AGA):
    1. AGA Pipeline Research Committee, Project PR-3-805, ``A 
Modified Criterion for Evaluating the Remaining Strength of Corroded 
Pipe'' (December 22, 1989).
* * * * *
    C. * * *
    12. ASTM Designation: F1055 ``Standard Specification for 
Electrofusion Type Polyethylene Fittings for Outside Diameter 
Controlled Polyethylene Pipe and Tubing'' (F1055-95).
    D. * * *
    3. ASME/ANSI B31G ``Manual for Determining the Remaining 
Strength of Corroded Pipelines'' (1991).
    4. ASME/ANSI B31.8 ``Gas Transmission and Distribution Piping 
Systems'' (1995).
* * * * *
    Issued in Washington, DC, on May 28, 1996.
D.K. Sharma,
Administrator.
[FR Doc. 96-13787 Filed 6-5-96; 8:45 am]
BILLING CODE 4910-60-P