[Federal Register Volume 69, Number 123 (Monday, June 28, 2004)]
[Rules and Regulations]
[Pages 36024-36029]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 04-14638]



Research and Special Programs Administration

49 CFR Part 192

[Docket No. RSPA-03-16330; Amdt. 192-97]
RIN 2137-AB71

Pipeline Safety: Passage of Internal Inspection Devices

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

ACTION: Final rule.


SUMMARY: The Research and Special Programs Administration (RSPA) 
published a regulation requiring that new gas transmission lines and 
sections of existing transmission lines in which pipe or components are 
replaced be designed and constructed to accommodate the passage of 
instrumented internal inspection devices. Responding to petitions for 
reconsideration, RSPA stayed enforcement on some facilities and invited 
comments on proposed changes to the regulation. The present action 
concludes our consideration of the petitions and comments. For existing 
onshore transmission lines, this action restricts the regulation to 
replacements of pipe or components. For offshore transmission lines, 
the regulation is restricted to certain new lines that run between 
platforms or from platforms to shore. The action aligns the regulation 
with the supporting congressional directive and a related Marine Board 

DATES: This Final Rule takes effect July 28, 2004. Offshore 
transmission lines covered by revised Sec.  192.150 are those on which 
construction begins after December 28, 2005.

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



    This proceeding began when RSPA proposed regulations (49 CFR 
192.150 and 195.120) that would require operators, except in certain 
impracticable situations, to design and construct new and replacement 
gas transmission lines and new and replacement hazardous liquid 
pipelines to accommodate the passage of instrumented internal 
inspection devices (57 FR 54745; Nov. 20, 1992) (``Notice 1'').\1\ The 
proposed regulations were in response to congressional directives in 
Sections 108(b) and 207(b) of the Pipeline Safety Reauthorization Act 
of 1988 (Pub. L. 100-561; Oct. 31, 1988).\2\

    \1\ The proposed gas transmission line regulation (49 CFR 
192.150) was substantially identical to the proposed regulation for 
hazardous liquid pipelines (49 CFR 195.120). Proposed Sec.  192.150 
reads as follows:
    Sec.  192.150 Provision for internal passage of inspection 
    (a) Except as provided in paragraph (b) of this section, each 
new transmission line and each replacement transmission line must be 
designed and constructed to accommodate the passage of instrumented 
internal inspection devices.
    (b) Paragraph (a) of this section does not apply to manifolds, 
station piping (such as compressor stations, metering stations, or 
regulator stations), cross-overs, and fittings that provide branch 
line junctures (such as tees and other lateral connections), and any 
other piping that the Administrator finds in a particular case would 
be impracticable to design and construct to accommodate the passage 
of an instrumented internal inspection device. In the case of 
fittings providing branch line junctures, however, restraining 
elements must be added to the fitting so that pigs can pass in the 
direction of straight flow.
    \2\ Section 108(b) added the following new Section 3(g) to the 
Natural Gas Pipeline Safety Act of 1968: (g) Instrumented Internal 
Inspection Devices.--The Secretary shall, by regulation, establish 
minimum Federal safety standards requiring that--
    (1) the design and construction of new transmission facilities, 
    (2) when replacement of existing transmission facilities or 
equipment is required, the replacement of such existing facilities, 
be carried out, to the extent practicable, in a manner so as to 
accommodate the passage through such transmission facilities of 
instrumented internal inspection devices (commonly referred to as 
``smart pigs'').
    Section 207(b) added a similar new section 203(k) to the 
Hazardous Liquid Pipeline Safety Act of 1979.

    Instrumented internal inspection devices, also called ``smart 
pigs,'' travel with the flow of fluid in pipelines. Along the way, they 
collect data that operators subsequently analyze and investigate to 
learn the physical condition of the pipeline. However, operators cannot 
use smart pigs in pipelines that contain obstructions to their passage, 
such as short radius bends or valves that do not open fully. The 
purpose of the proposed regulations was to make pipelines open to the 
passage of smart pigs wherever practicable.
    Persons who submitted written comments on the proposed regulations 
generally sought to expand the number of impracticable situations in 
which design and construction for the passage of smart pigs would not 
be mandatory. In a Final Rule document (59 FR 17281; April 12, 1994) 
(``1994 Final Rule''), we responded to these comments by including the 
following additional exceptions in final Sec. Sec.  192.150 and 
     Pipe for which there is no commercially available smart 
     Transmission lines in Class 4 (urban) locations that 
operate with a gas distribution system.
     Piping associated with storage facilities.
     Emergency or other unforeseen construction problems for 
which the operator seeks post-construction approval.
     Offshore pipelines less than 10 inches in nominal diameter 
that transport gas or hazardous liquid to onshore facilities.
    In the 1994 Final Rule, we also changed the proposed regulations in 
response to comments that the terms ``replacement transmission line'' 
and ``replacement pipeline'' were unclear. We had used these terms to 
identify which existing pipelines operators

[[Page 36025]]

would have to modify to accommodate the passage of smart pigs. The 
commenters suggested several alternative terms, including ``replaced 
component'' or ``replaced line section.'' Although we agreed the 
proposed terms lacked clarity, we did not use the suggested 
alternatives in final Sec. Sec.  192.150(a) and 195.120(a). Instead the 
final rules required that when operators replace any line pipe or 
component, they must design and construct the entire line section 
containing the replacement to accommodate the passage of smart pigs 
(``replacement provision'').\3\ Also, based on the definition of ``line 
section'' in Sec.  195.2, we added the following definition to Sec.  
192.3: ``Line section means a continuous run of transmission line 
between adjacent compressor stations, between a compressor station and 
storage facilities, between a compressor station and a block valve, or 
between adjacent block valves.'' We rejected as fruitless the idea of 
applying the proposed terms just to replaced pipe or components. Our 
reasoning was that if operators never replaced some existing 
obstructions, the pipelines would never accommodate the passage of 
smart pigs, or become piggable.

    \3\ Final Sec. Sec.  192.150(a) and 195.120(a) are substantially 
identical. Final Sec.  192.150(a) reads as follows: Sec.  192.150 
Passage of internal inspection devices.
    (a) Except as provided in paragraphs (b) and (c) of this 
section, each new transmission line and each line section of a 
transmission line where the line pipe, valve, fitting, or other line 
component is replaced must be designed and constructed to 
accommodate the passage of instrumented internal inspection devices.

    After publication of the 1994 Final Rule, the American Gas 
Association (AGA) and the Interstate Natural Gas Association of America 
(INGAA) asked us to stay the effective date of the replacement 
provision. They argued that construction projects require lengthy 
advance planning for, among other things, design, contracting, funding, 
and government approvals, and that compliance with Sec.  192.150 would 
cause adverse consequences. In addition, AGA and INGAA each submitted a 
petition for reconsideration of the replacement provision, citing 
procedural errors. INGAA also sought exemption of all offshore gas 
transmission lines from Sec.  192.150.
    In view of the serious nature of these requests, on May 12, 1994, 
we suspended enforcement of the replacement provision, except as it 
applies to the pipe or component being replaced. Subsequently we 
published a notice proposing changes to Sec.  192.150 that would relax 
the effect of the regulation, but not fully grant the petitions for 
reconsideration (59 FR 49896; Sept. 30, 1994) (Notice of Proposed 
Rulemaking (NPRM)). Specifically the proposed changes would do the 
     For transmission lines in Class 1 and 2 locations (areas 
of low population), limit the replacement provision to the component 
being replaced, if modifying the entire line section is infeasible and 
unnecessary for future safety.
     For transmission lines in Class 1 and 2 locations, 
postpone mandatory compliance with the replacement provision, apart 
from the component being replaced, until February 2, 1995.
     Exempt all offshore transmission lines (other than new 
transmission lines 10\3/4\ inches or larger) if the operator runs 
cleaning pigs regularly to remove condensate and inspects risers 
regularly for corrosion.
    We did not propose similar changes to Sec.  195.120 primarily 
because no one requested reconsideration of Sec.  195.120. The lack of 
a request was most likely because hazardous liquid pipelines have 
historically been designed for the passage of internal inspection 
equipment. We also thought the risk of environmental damage posed by 
hazardous liquid spills weighed against changing Sec.  195.120. 
Nevertheless, since there was no apparent need to change Sec.  195.120, 
we announced in the NPRM that we would begin to enforce the replacement 
provision of that regulation in full. We also said we would continue to 
suspend enforcement on gas transmission lines until February 2, 1995, 
or until we completed action on compliance dates, whichever occurred 
first (59 FR 49897).
    After reviewing the comments on the NPRM, we realized we would not 
complete the rulemaking before February 2, 1995. So on January 30, 
1995, we issued another suspension of enforcement (60 FR 7133; Feb. 7, 
1995). On existing onshore transmission lines, we continued the 
previous suspension, and on offshore transmission lines, we suspended 
enforcement of Sec.  192.150 entirely. We said these suspensions would 
stay in effect until we responded to the comments on the NPRM and 
established new compliance dates. The suspensions did not affect new 
onshore transmission lines or replacements of pipe or components in 
existing onshore transmission lines.

Comments on the NPRM

    Fifty-seven persons responded to the invitation to comment on the 
NPRM. Comments came from pipeline operators, pipeline trade 
associations, and government agencies.
    AGA considered the proposed changes to Sec.  192.150 impracticable 
and unreasonable, and said they would not significantly reduce 
industry's costs of compliance. AGA estimated that even if the 
replacement provision applied only to Class 3 and 4 pipelines, 
compliance would cost industry more than $100 million a year. It urged 
us to rescind the replacement provision rather than adopt the proposed 
    Other commenters largely objected to the replacement provision 
without directly addressing the proposed changes. Most of these 
commenters saw the replacement provision as an unnecessary high-cost 
burden that would cause the delay of other maintenance work or safety 
objectives. Many of them suggested that on existing transmission lines 
Sec.  192.150 should apply only to replacements of pipe and components. 
Four commenters argued we should not apply the replacement provision to 
Class 3 transmission lines operated with distribution systems because 
these lines have constraints similar to those of exempt Class 4 lines. 
Six commenters, including INGAA, expected improvements in the 
technology of smart pigs would make the replacement provision 
unnecessary. INGAA also suggested that preparing line sections for 
smart pig inspections before deciding the inspections are needed is not 
proper risk management.
    Six commenters, including INGAA, suggested that Sec.  192.150 
should exempt all offshore transmission lines. Two of these commenters 
urged exemption without the proposed preconditions, which they argued 
were unnecessary in view of usual operating practices and corrosion 
control regulations. Mostly these commenters contended that designing 
and constructing these lines to provide for the future use of smart 
pigs would be very costly, technically difficult, and of almost no 
benefit to the public because of the remote location. They attributed 
the costs and difficulties to the normal configuration of offshore 
transmission lines, essentially an underwater network of different pipe 
sizes with multiple right-angle connections, making smart pig passage 
from one line to another and installation of launcher or receivers at 
connection point impracticable. However, two commenters supported the 
Marine Board's recommendation (discussed below) that, whenever 
reasonably practical, operators design new medium-to-large-diameter 
lines running between platforms and platforms to shore for the passage 
of smart pigs.
    Several commenters addressed the question of what alternative to 
the replacement provision would ensure

[[Page 36026]]

that existing transmission lines eventually accommodate the passage of 
smart pigs. A few commenters said there was no alternative. Others said 
the accommodation of smart pigs would gradually result from planned 
replacement programs or from a combination of replaced pipe and 
components, new installations, and removal of obstructions. Two 
commenters stated the alternative was continuously improving 

Advisory Committee Consideration

    The Technical Pipeline Safety Standards Committee (TPSSC) 
considered the NPRM at a meeting in Washington, DC, on May 2, 1995. 
TPSSC is a statutory, advisory committee that advises RSPA on proposed 
safety standards and other policies for gas pipelines. The committee 
has an authorized membership of 15 persons, five each representing 
government, industry, and the public. Each member has qualifications to 
consider the technical feasibility, reasonableness, cost-effectiveness, 
and practicability of proposed gas pipeline safety standards. A 
transcript of the meeting is available in the Nassif Building, Room 
7128, 400 Seventh Street, SW, Washington, DC 20590-0001.
    TPSSC's discussion at the meeting dwelled on the replacement 
provision of Sec.  192.150(a). One member thought the provision put too 
much emphasis on a single method of evaluating pipeline integrity 
(using smart pigs) when alternatives are available. Other members 
questioned the benefit of requiring operators to do more than just 
insure that replacement pipe and components accommodate the passage of 
smart pigs. Still other members were concerned the replacement 
provision would cause an undesirable reallocation of resources by 
reducing funds available for more important maintenance needs. In the 
end, TPSSC voted nine to one to recommend that we amend the replacement 
provision to apply only to replacements of pipe or components.
    The rest of TPSSC's discussion concerned application of Sec.  
192.150 to offshore transmission lines. One member stated emphatically 
that the regulation should not apply offshore because the cost of 
design and construction would be too great. An industry representative 
in the audience added that normal sub-sea designs inherently do not 
permit the passage of smart pigs due to right angles between connecting 
pipelines. This industry representative also said that other than in a 
few places, running smart pigs in offshore gas transmission lines was 
not technically feasible. With little further discussion, TPSSC voted 
unanimously to recommend that we exempt all offshore transmission lines 
from Sec.  192.150.

Resolving the Issues

    Essentially we face two issues in deciding whether to change Sec.  
192.150: The first is whether the replacement provision is justified. 
And the second is whether to exclude additional transmission lines from 
    Replacement provision. The controversy over the replacement 
provision began with our response to Notice 1 commenters who requested 
clarification of the term ``replacement transmission line.'' We had 
used the term in proposed Sec.  192.150(a) to identify the portions of 
existing transmission line that operators would have to design and 
construct to accommodate the passage of smart pigs.
    A strong inference of what ``replacement transmission line'' meant 
is found in the following excerpt from Notice 1 concerning the purpose 
of the proposed regulations:

    Sections 108(b) and 207(b) of the Reauthorization Act (Pub. L. 
100-561) require DOT to require operators to design and construct 
certain new pipeline facilities and replacement pipeline facilities 
(i.e., pipeline facilities that replace existing facilities), to the 
extent practicable, to accommodate the passage of smart pigs. To 
meet this statutory requirement, the rules proposed by this notice 
would, with limited exceptions, prohibit any physical restriction on 
the passage of a smart pig in the design or construction of new or 
replacement pipelines. (57 FR 54746).

    In the first sentence of the excerpt, the term ``replacement 
pipeline facilities'' identifies which existing facilities Congress 
wanted operators to design and construct to accommodate the passage of 
smart pigs. The parenthetical expression leaves no doubt that we 
intended the term to mean ``facilities that replace existing 
facilities.'' The second sentence further explains that to meet this 
congressional directive on existing facilities, the proposed rules 
would prohibit restrictions in ``replacement pipelines.'' Given that in 
Part 192 a ``transmission line'' is a type of ``pipeline'' which in 
turn is a type of ``pipeline facility'' (see Sec.  192.3), it follows 
that in Notice 1 we intended ``replacement transmission line'' to refer 
to a transmission line that replaces an existing transmission line.
    This interpretation of Notice 1 is consistent with the legislative 
history of Pub. L.100-561. In its report on H.R. 2266, the House bill 
that led to the pig passage requirement, the Committee on Energy and 
Commerce discussed the limited effect the bill would have on existing 
pipelines. The Committee said the ``requirement would only apply to 
repairs or replacements that * * * could be done in a manner to 
facilitate the use of smart pigs.'' (H.R. Rept. 100-445, Part 1, 100th 
Cong., 1st Sess., at 15, emphasis added).
    In the 1994 Final Rule, however, we did not refer to Notice 1 or 
the Committee report to answer commenters' questions about the meaning 
of ``replacement transmission line.'' Instead we dropped the term from 
the final regulations in favor of the replacement provision, which has 
a much broader effect than the design and construction of replacements. 
It requires that each transmission line section containing a 
replacement must be designed and constructed to accommodate the passage 
of smart pigs.
    To justify this change in the final regulations, we pointed to 
Notice 1 comments that suggested alternatives to ``replacement 
transmission line,'' such as ``replacement line section'' or 
``replacement transmission section.'' However, these comments were made 
by persons who suggested that for existing transmission lines we 
restrict application of the proposed rules to actual replacements. 
Thus, in the present reconsideration of the replacement provision, we 
looked for a better reason that would explain the change.
    We believe that reason lies in the explanation we gave in the 1994 
Final Rule for rejecting the idea that ``replacement'' should mean only 
replacement of pipe or components. We said if the regulations were so 
limited, ``then pipelines with restrictive components, such as elbows 
and tight radius field bends (which when properly maintained never need 
replacement) would never be piggable.'' (59 FR 17279). We amplified 
this reasoning--that some existing pipelines might never become 
piggable--when, in the same paragraph, we said the clear intent of the 
congressional mandate was to improve an existing pipeline's 
piggability. A further example of this reasoning is in the NPRM. There 
we explained that applying Sec.  192.150 to single components rather 
than line sections ``would result in virtually no change in the 
`piggability' of existing pipelines'' and that ``Congress clearly 
intended that change in the `piggability' occur.'' (59 FR 49897). It 
seems, therefore, that our strong interest in carrying out the will of 
Congress to make existing transmission lines piggable was behind the 
replacement provision in Sec.  192.150.

[[Page 36027]]

    Notwithstanding this prior reasoning, recent legislation and RSPA 
rulemaking have reduced the significance of the replacement provision 
in reaching the piggability goal. Section 14 of the Pipeline Safety 
Improvement Act of 2002 (Pub. L. 107-355; Dec. 17, 2002) requires gas 
pipeline operators to analyze and reduce the risks to their facilities 
in highly populated areas using integrity management programs 
prescribed by DOT regulations. Last year RSPA published the required 
regulations on integrity management programs (68 FR 69778; Dec. 15, 
2003). The backbone of the regulations is a requirement to use smart 
pigs, pressure testing, direct assessment, or an equivalent technology 
periodically to assess the effects of potential risks on pipeline 
integrity. Comments submitted in response to the rulemaking proposal 
indicated that operators strongly prefer to use smart pigs as the 
method of assessment and will modify their transmission lines as 
necessary to accommodate smart pigs. For convenience of pig launching 
and retrieving and to maximize pigging benefits, planned modifications 
most likely will include considerable mileage outside areas covered by 
the new regulations. We believe this approach is prudent because 
pigging yields much more information about the condition of a pipeline 
and should lower compliance costs when widely used. Thus, regardless of 
the replacement provision, the new integrity management regulations 
should result in increased piggability of existing transmission lines 
in and near areas of high population, areas where the risk of damage 
from a pipeline rupture is greatest.
    In sum, the NPRM commenters and the TPSSC opposed the replacement 
provision and did not back our NPRM proposal to relax it. Moreover, the 
goal of the replacement provision--ensuring the piggability of existing 
transmission--will likely be met in and near areas of greatest risk 
through compliance with the new integrity management regulations. 
Therefore, upon further consideration of the record and the integrity 
management rulemaking, we have decided to revise the replacement 
provision of Sec.  192.150(a) to apply only to replacements of pipe or 
components. Because this decision is consistent with our long-running 
stay of enforcement, it should not affect operators' current methods of 
compliance. Also, it will enable operators to focus their line 
modification resources on areas of greatest risk rather than spread 
them helter-skelter across their systems as the present rule requires.
    Offshore transmission lines. The offshore issue first arose when 11 
commenters to Notice 1 suggested we exempt all offshore pipelines from 
the final regulations. The commenters generally said design features, 
including short bends and right-angle connections, made it 
impracticable for offshore pipelines to accommodate the passage of 
smart pigs. Because of these comments, we exempted offshore pipelines 
less than 10 inches in nominal diameter that transport gas or hazardous 
liquid to onshore facilities (Sec.  192.150(b)(7) and Sec.  
    INGAA was dissatisfied with this outcome and, in its petition for 
reconsideration, asked us to exempt all new and replacement offshore 
transmission lines from Sec.  192.150. Among other things, INGAA argued 
that making offshore transmission lines piggable would be of little 
benefit because the offshore location and operators' maintenance 
practices significantly limit the risk they pose. Largely accepting 
this argument, in the NPRM we proposed to modify the offshore exemption 
in Sec.  192.150(b)(7). The modified exemption would cover all existing 
transmission lines and new transmission lines less than 10\3/4\ inches 
in outside diameter if operators regularly run cleaning pigs through 
the lines to remove condensate and regularly inspect risers for 
    To support our decision to continue applying Sec.  192.150 to new 
lines 10\3/4\ inches or larger in outside diameter, we noted that 
nothing in the record showed that offshore transmission lines are 
incapable of being designed and constructed to accommodate smart pigs. 
We also relied on a 1994 report titled ``Improving the Safety of Marine 
Pipelines'' prepared by a committee of scientists and engineers expert 
in offshore development and management. The Marine Board of the 
National Research Council established the committee in response to 
requests by RSPA and the Minerals Management Service to review and 
assess various offshore pipeline issues. The report is available on the 
Web from the National Academies Press at http://books.nap.edu/books/0309050472/html/ html/. After concluding that modification of existing 
pipelines to accommodate smart pigs would generally be uneconomic, the 
committee recommended that ``[n]ew medium-to large-diameter pipelines 
running from platform to platform or platform to shore should be 
designed to accommodate smart pigs whenever reasonably practical.''
    As stated above, NPRM commenters generally opposed applying Sec.  
192.150 to offshore transmission lines, and the TPSSC supported that 
view. The rationale related to customary offshore construction 
practices and the inability to run pigs through interconnected lines. 
However, no commenter or TPSSC member objected specifically to applying 
the regulation to new lines 10\3/4\ inches or larger in outside 
diameter, and two commenters supported the idea within the limits of 
the Marine Board's recommendation. By comparison, since the 1994 Final 
Rule took effect, Sec.  195.120 has required operators to design and 
construct offshore hazardous liquid pipelines 10\3/4\ inches or larger 
in outside diameter to accommodate the passage of smart pigs. And 
nothing presented by the NPRM commenters suggests operators cannot 
similarly design and construct new gas transmission lines.
    All these considerations, especially the Marine Board's 
recommendation, weigh toward continuing to apply Sec.  192.150 to new 
offshore transmission lines 10\3/4\ inches or larger in outside 
diameter. At the same time, we agree with the two NPRM commenters who 
suggested we limit the regulation's offshore coverage to new lines 
running from platform to platform or platform to shore whenever 
reasonably practical, as the Marine Board recommended. We also agree 
with the commenters who suggested that conditioning the exemption of 
other offshore lines on certain maintenance practices is unnecessary. 
As discussed in the NPRM, operators regularly remove condensate from 
transmission lines, and Part 192 already requires regular inspections 
for corrosion.
    However, before making a final decision, we sought further public 
input because the offshore issue had not been aired for some time. So 
we published a notice (68 FR 67128; Dec. 1, 2003) seeking comments on 
the following questions:
     Do operators of offshore gas transmission lines still 
object to applying Sec.  192.150 to new offshore transmission lines 10 
inches or larger?
     If the answer is yes, given that new hazardous liquid 
pipelines 10 inches or larger are meeting Sec.  195.120, what 
differences are there between gas and liquid pipeline design and 
construction practices that would justify exempting new offshore gas 
transmission lines 10 inches or larger from Sec.  192.150?
     Regarding the Marine Board's recommendation, when would it 
not be ``reasonably practical'' to design new gas transmission lines 10 
inches or larger running between platforms or

[[Page 36028]]

platforms and shore to accommodate the passage of smart pigs?
    We received four responses to the request for comments: Barb Sachau 
of Florham Park, New Jersey; Duke Energy Gas Transmission Corporation 
(Duke); El Paso Pipeline Group (El Paso); and INGAA. Of these 
commenters, only Duke offered useful information in response to the 
questions. Ms. Sachau merely urged us to adopt the utmost safety 
standards. El Paso supported INGAA's petition for reconsideration, but 
said it could not respond properly to the questions because the on-line 
docket (Docket No. RSPA-03-16330) did not contain the ``technical 
material'' referenced in INGAA's petition or the Marine Board study. El 
Paso said it needed more time for research, and asked us to extend the 
comment period 30 days. INGAA also requested more time to submit 
comments (15 days), stating that its time had been occupied by work 
related to RSPA's new Integrity Management Rule, published December 15, 
2003, and by end-of-year holidays.
    We did not grant El Paso's or INGAA's request to extend the comment 
period, because both commenters offered weak excuses for not meeting 
the deadline and did not suggest what new information we would receive 
if the deadline were extended. We especially differed with El Paso's 
contention that the ``technical material'' mentioned in INGAA's 
petition and the Marine Board study were not in the on-line docket. The 
only reference to technical material occurs on page 6 of the petition, 
where INGAA states: ``RSPA was provided with an abundance of technical 
reasons why offshore pipelines cannot be smart pigged.'' The context 
clearly implies that INGAA was referring to technical reasons contained 
in the rulemaking record. The 1994 Final Rule discusses these reasons, 
and we put a copy of the 1994 Final Rule in the on-line docket to make 
it easier for persons to respond to the request for comments. In 
addition, the notice included a Web address for the Marine Board study, 
effectively placing that study in the on-line docket. Although the 
comment deadline was not extended, our customary policy is to consider 
late-filed comments whenever practical, but neither commenter submitted 
anything more to the docket.
    In its comments on the offshore issue, Duke opposed applying Sec.  
192.150 to existing offshore gas pipelines. Yet it supported the Marine 
Board's recommendation on the design of certain new offshore pipelines, 
calling the recommendation an appropriate application of the 
congressional requirement. As to when designing for pig passage would 
not be reasonably practical, Duke suggested it would not be practical 
if pig launching or receiving were constrained by platform space or 
configuration. Nor would it be reasonably practical, Duke said, if the 
new pipeline were designed to have multiple lateral connections between 
launching and receiving points. Similarly, a participant at the May 2, 
1995 TPSSC meeting suggested design would not be practical if it 
includes a lateral connection large enough to cause a smart pig to 
    We agree it makes little sense to design and construct a new 
platform-connected transmission line for smart pig passage if the 
platform lacks room for equipment and handling needed to launch or 
retrieve smart pigs. We are less certain, however, about the 
consequences of designs that provide taps for future lateral 
connections, either through manifolds or more than one individual 
connection. While comments indicate that right-angle connections are 
common on offshore pipelines and impede smart pig passage from laterals 
to trunklines, it is not clear that these connections necessarily 
restrict the passage of smart pigs through the trunkline. Wye 
connections can be used in some situations to alleviate problems that 
might arise from right-angle connections, although they may not be 
suitable in all situations. Thus to be sure the pig passage requirement 
is not frustrated by designs that include taps for lateral connections, 
we believe operators should consider using non-obstructive alternatives 
wherever reasonably practical. Thus we are willing to exempt designs 
with obstructive taps only if the operator has considered alternative 
designs and can explain why they are not reasonably practical for the 
intended application.
    Accordingly, based on our earlier conclusions and Duke's latest 
input, we are revising Sec.  192.150(b)(7) consistent with the Marine 
Board's recommendation. New offshore transmission lines 10'' inches or 
more in outside diameter that run from platform to platform or platform 
to shore will have to be designed and constructed to accommodate the 
passage of smart pigs. This requirement will not apply, however, if 
platform space or configuration is not compatible with launching or 
retrieving smart pigs. Nor will it apply if the design includes one or 
more taps for lateral connections and the operator can demonstrate, 
based on investigation or experience, that use of a tap that does not 
obstruct the passage of instrumented internal inspection devices is not 
reasonably practical under the design circumstances.
    Although Sec.  192.150 already applies to new offshore transmission 
lines 10\3/4\ inches or more in outside diameter, because of our long-
running suspension of enforcement, operators will probably need time to 
plan for compliance with revised Sec.  192.150(b)(7). So we decided to 
require compliance only on lines on which construction begins more than 
18 months after the date of publication of the present Final Rule.
    The changes we are making to Sec.  192.150 remove the need to 
continue in force the suspension of enforcement dated January 30, 1995 
(60 FR 7133; Feb. 7, 1995). Therefore, we are withdrawing the 
suspension as of the effective date of this Final Rule, which is shown 
in ``Dates'' heading above.

Regulatory Analyses and Notices

Executive Order 12866 and DOT Policies and Procedures

    We do not consider this rulemaking to be a significant regulatory 
action under Section 3(f) of Executive Order 12866 (58 FR 51735; Oct. 
4, 1993). Therefore, the Office of Management and Budget (OMB) has not 
received a copy of this rulemaking to review. In addition, we do not 
consider this rulemaking to be significant under DOT regulatory 
policies and procedures (44 FR 11034: February 26, 1979).
    This rulemaking merely relaxes certain provisions of the 1994 Final 
Rule. It does not establish any new requirements. It will reduce the 
costs to pipeline operators by limiting the amount of pipelines and 
pipeline components that operators must modify onshore and reduce the 
amount of pipeline offshore that is subject to regulation. A copy of 
the regulatory evaluation is available in the public docket for review.

Regulatory Flexibility Act

    This rulemaking relaxes certain provisions of Sec.  192.150 and 
does not establish any new requirements. Therefore, based on these 
facts, I certify, under Section 605 of the Regulatory Flexibility Act 
(5 U.S.C. 605), that this rulemaking will not have a significant impact 
on a substantial number of small entities.

Executive Order 13084

    We have analyzed this rulemaking according to the principles and 
criteria contained in Executive Order 13084, ``Consultation and 
Coordination with Indian Tribal Governments.'' Because the rulemaking 
will not significantly or uniquely affect the communities of the Indian 
tribal governments and will not impose substantial direct compliance

[[Page 36029]]

costs, the funding and consultation requirements of Executive Order 
13084 do not apply.

Paperwork Reduction Act

    This rulemaking does not contain any additional information 
collection requirements.

Unfunded Mandates Reform Act of 1995

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

National Environmental Policy Act

    Because this rulemaking merely relaxes certain provisions of Sec.  
192.150 and does not establish any new requirements, it does not create 
any significant environmental issues. Therefore, we have not analyzed 
this rulemaking under the National Environmental Policy Act (42 U.S.C. 
4321 et seq.).

Executive Order 13132

    We have analyzed this rulemaking according to the principles and 
criteria contained in Executive Order 13132 (``Federalism''). The 
rulemaking does not establish any regulation that: (1) Has a 
substantial direct effect on the States, the relationship between the 
National government and the States, or the distribution of power and 
responsibilities among the various levels of government; (2) imposes 
substantial direct compliance cost on State and local governments; or 
(3) preempts State law. Therefore, the consultation and funding 
requirements of Executive Order 13132 do not apply.

Executive Order 13211

    This rulemaking is not a ``Significant energy action'' under 
Executive Order 13211. It is not a significant regulatory action under 
Executive Order 12866 and is not likely to have a significant adverse 
effect on the supply, distribution, or use of energy. Further, this 
rulemaking has not been designated by the Administrator of the Office 
of Information and Regulatory Affairs as a significant energy action.

List of Subjects in 49 CFR Part 192

    Natural gas, Pipeline safety, Reporting and recordkeeping 

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


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

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

2. Revise Sec.  192.150(a) and (b)(7) to read as follows:

Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new transmission line and each replacement of line pipe, valve, 
fitting, or other line component in a transmission line must be 
designed and constructed to accommodate the passage of instrumented 
internal inspection devices.
    (b) * * *
    (7) Offshore transmission lines, except transmission lines 10\3/4\ 
inches (273 millimeters) or more in outside diameter on which 
construction begins after December 28, 2005, that run from platform to 
platform or platform to shore unless--
    (i) Platform space or configuration is incompatible with launching 
or retrieving instrumented internal inspection devices; or
    (ii) If the design includes taps for lateral connections, the 
operator can demonstrate, based on investigation or experience, that 
there is no reasonably practical alternative under the design 
circumstances to the use of a tap that will obstruct the passage of 
instrumented internal inspection devices; and
* * * * *

    Issued in Washington, DC, on June 23, 2004.
Samuel G. Bonasso,
Deputy Administrator.
[FR Doc. 04-14638 Filed 6-25-04; 8:45 am]