**DEPARTMENT OF TRANSPORTATION**

**Pipeline and Hazardous Materials Safety Administration**

**49 CFR Parts 192 and 195**

**\[Docket No. RSPA-04-16855; Amdt. 192-101 and 195-85\]**

**RIN 2137---AD97**

**Pipeline Safety: Standards for Direct Assessment of Gas and Hazardous
Liquid Pipelines**

**AGENCY:** Pipeline and Hazardous Materials Safety Administration
(PHMSA), DOT.

**ACTION:** Final rule.

**SUMMARY:** Under current regulations governing integrity management of
gas transmission lines, if an operator uses direct assessment to
evaluate corrosion risks, it must carry out the direct assessment
according to PHMSA standards. In response to a statutory directive, this
Final Rule prescribes similar standards operators must meet when they
use direct assessment on certain other onshore gas, hazardous liquid,
and carbon dioxide pipelines. PHMSA believes broader application of
direct assessment standards will enhance public confidence in the use of
direct assessment to assure pipeline safety.

**DATES:** This Final Rule takes effect November 25, 2005. Incorporation
by reference of NACE Standard RP0502-2002 in this rule is approved by
the Director of the **Federal Register** as of November 25, 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 *buck.furrow@dot.gov*.

**SUPPLEMENTARY INFORMATION:**

**I. Background**

This Final Rule concerns direct assessment, a process of managing the
effects of external corrosion, internal corrosion, or stress corrosion
cracking on pipelines made primarily of steel or iron. The process
involves data collection, indirect inspection, direct examination, and
evaluation. Operators use direct assessment not only to find existing
corrosion defects but also to prevent future corrosion problems.

Congress recognized the advantages of using direct assessment on U.S.
Department of Transportation (DOT) regulated gas, hazardous liquid, and
carbon dioxide pipeline facilities. Section 14 of the Pipeline Safety
Improvement Act of 2002 (Pub. L. 107-355; Dec. 17, 2002) directs DOT to
issue regulations on using internal inspection, pressure testing, and
direct assessment to manage the risks to gas pipeline facilities in high
consequence areas. In addition, Section 23 directs DOT to issue
regulations prescribing standards for inspecting pipeline facilities by
direct assessment.

In response to the first statutory directive, Section 14, DOT\'s
Research and Special Programs Administration (RSPA)[^1] published
regulations in 49 CFR part 192, subpart O, that require operators to
follow detailed programs to manage the integrity of gas transmission
line segments in high consequence areas. Subpart O also requires an
operator electing to use direct assessment in its integrity management
program, to carry out the direct assessment according to §§ 192.925,
192.927, and 192.929, as appropriate.[^2]

Sections 192.925, 192.927, and 192.929 cross-reference the American
Society of Mechanical Engineers\' (ASME), ASME B31.8S-2001, "Managing
System Integrity of Gas Pipelines.\'\' ASME B31.8S-2001 describes a
comprehensive process to assess and mitigate the likelihood and
consequences of gas pipeline risks. In addition, §192.925
cross-references a NACE International (NACE) standard, NACE Standard
RP0502-2002, "Pipeline External Corrosion Direct Assessment
Methodology.\'\' NACE Standard RP0502-2002 describes a step-by-step
process for identifying and addressing external corrosion activity,
repairing defects, and taking remedial action. Other parts of §§
192.925, 192.927, and 192.929 ensure operators use appropriate criteria
in making direct assessment decisions.

**II. Proposed Rules**

In response to the second statutory directive, Section 23, PHMSA
published a notice of proposed rulemaking (NPRM) (69 FR 61771; Oct. 21,
2004). The NPRM proposed standards for using direct assessment on any
onshore gas pipeline made primarily of steel or iron and regulated by 49
CFR part 192 or onshore steel hazardous liquid or carbon dioxide
pipeline regulated by 49 CFR part 195. Under proposed §192.490, if an
operator chooses to use direct assessment to evaluate the threat of
external corrosion, internal corrosion, or stress corrosion cracking on
a regulated onshore gas pipeline, the direct assessment would have to be
done according to §§ 192.925, 192.927, or 192.929, as appropriate. For
regulated hazardous liquid and carbon dioxide pipelines, proposed
§195.588 would require similar action, except compliance with §192.927
would not be required, because §192.927 requirements are only suitable
for dry gas pipelines.

**III. Advisory Committee Recommendations**

The Technical Pipeline Safety Standards Committee (TPSSC) and the
Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC)
considered the NPRM at meetings in Washington, DC, on December 14 and
15, 2004. The TPSSC, a statutorily mandated advisory committee, advises
PHMSA on proposed safety standards and other policies concerning gas
pipelines. The THLPSSC is a similar committee that provides advice about
hazardous liquid and carbon dioxide pipelines. Each committee has an
authorized membership of 15 persons with membership evenly divided
between government, industry, and the public. Each member is qualified
to consider the technical feasibility, reasonableness,
cost-effectiveness, and practicability of proposed pipeline safety
standards. A transcript of each committee\'s meeting is available in
Docket No. PHMSA-98-4470.

After careful consideration of the NPRM, the THLPSSC voted unanimously
to recommend the following: (1) Adopt a single definition of direct
assessment for use by hazardous liquid pipeline operators inside and
outside high consequence areas; (2) state direct assessment standards
directly in part 195, rather than by cross-referencing part 192
standards; (3) consider adopting the consensus standard under
development by NACE for direct assessment of stress corrosion cracking;
and (4) amend the integrity management rule (§195.452) to allow use of
direct assessment without prior notice.

As a result of its deliberation, the TPSSC voted unanimously that
proposed §192.490 should not be applied to gas distribution lines. It
also voted unanimously that the Final Rule should distinguish direct
assessment from similar methods of assessing corrosion. Such a
distinction would identify situations where similar methods of
addressing corrosion are appropriate but are not regulated under the
proposed direct assessment standard.

**IV. Disposition of Comments and Advisory Committee Recommendations on
Proposed Rules**

We received written comments on the proposed rules from 19 sources.
These sources are categorized as follows:

  ----------------------------------- -----------------------------------
  State pipeline safety agency        Pennsylvania Public Utility
                                      Commission

  Gas pipeline operators              Duke Energy Gas Transmission(Duke),
                                      El Paso Corporation(El Paso), Nicor
                                      Gas (Nicor), NiSource Corporate
                                      Services Company (Nisource),
                                      Pacific Gas & Electric Company
                                      (PG&E), Paiute Pipeline Company
                                      (Paiute), Puget Sound Energy
                                      (Puget), Southwest Gas Corporation
                                      (SWGas).

  Gas pipeline trade associations     American Public Gas Association
                                      (APGA), American Gas Association
                                      (AGA), Interstate Natural Gas
                                      Association of America (INGAA),
                                      Northeast Gas Association (NGA).

  Gas pipeline industry committee     Gas Piping Technology Committee
                                      (GPTC).

  Hazardous liquid pipeline trade     American Petroleum Institute(API),
  associations.                       Association of Oil Pipe Lines
                                      (AOPL).

  Nonprofit organizations             Cook Inlet Regional Citizens
                                      Advisory Council, PipelineSafety
                                      Trust

  Consultant                          Glen F. Armstrong.
  ----------------------------------- -----------------------------------

Only one commenter, the Cook Inlet Regional Citizens Advisory Council
(Council), created by the Oil Pollution Act of 1990, supported the
proposed rules without change. The Council welcomed the additional
Federal standards because of the need to control pipeline corrosion. The
remaining commenters\' issues are stated below along with our
disposition of those issues and the advisory committee\'s
recommendations.

*Is this rulemaking necessary?* AGA, Duke, El Paso, GPTC, INGAA,
NiSource, and Puget claimed the integrity management regulations for gas
transmission lines (subpart O of part 192) satisfy the statutory
directive to prescribe direct assessment standards. Taking a similar
position, AOPL and API contended that Congress did not intend direct
assessment standards to apply outside integrity management regulations.
To support this position, these commenters stated that Congress did not
require operators to use direct assessment on pipelines outside
integrity management regulations. They also pointed out that direct
assessment was developed for use in integrity management programs.

Because the legislative history does not support the commenter\'s
argument that direct assessment standards should apply only to pipelines
subject to integrity management rules, PHMSA believes this rulemaking is
necessary. It is reasonable to conclude Congress did not intend to
restrict direct assessment standards to pipelines covered by integrity
management regulations. Unlike the first statutory directive concerning
direct assessment, which applies only to pipeline facilities in high
consequence areas, the second directive applies to pipeline facilities
regardless of location. Also, the first and second directives appear in
separate sections of the statute (Sections 14 and 23 of Pub. L.
107-355), with no apparent connection. Had Congress wanted to restrict
direct assessment standards to pipelines covered by integrity management
regulations, it could have expressly linked the second directive to the
first or included the second directive in the same section as the first.

*Is proposed §192.490 appropriate for gas distribution lines?* AGA,
APGA, Duke, El Paso, GPTC, INGAA, NGA, Nicor, NiSource, Paiute, and PG&E
argued direct assessment was developed for gas transmission integrity
management and has not been shown to be appropriate for gas distribution
lines. They said the relevant technical data and experience do not show
direct assessment would be effective on gas distribution lines. In
addition, some of these commenters thought because gas distribution
lines differ from gas transmission lines in design, operation,
configuration, and location, direct assessment may be impractical on gas
distribution lines. The many aboveground and belowground utility
facilities---both in-service and abandoned---were thought to pose
significant technical hurdles. The Pennsylvania Public Utility
Commission and the Pipeline Safety Trust also questioned the suitability
of direct assessment for gas distribution lines.

These comments came as a surprise to PHMSA because the two documents
that are the mainstays of the proposed direct assessment standards, ASME
B31.8S-2001 and NACE Standard RP0502-2002, can be interpreted to cover
gas distribution lines. Each document states that it applies to onshore
pipelines. Although neither document defines "pipeline,\'\' ASME\'s
B31.8 Code, to which ASME B31.8S-2001 is a supplement, defines
"pipeline\'\' as "all parts of physical facilities through which gas
moves in transportation.\'\' And "transportation of gas\'\' is defined
as the "gathering, transmission, or distribution of gas.\'\'

No matter how ASME B31.8S-2001 and NACE Standard RP0502-2002 are
interpreted, the comments persuaded us that direct assessment, as
depicted by these two documents, is not appropriate for gas distribution
lines. Both ASME B31.8S-2001 and NACE Standard RP0502-2002, were
developed during the rulemaking proceeding on gas transmission integrity
management and in furtherance of that proceeding. Consequently, neither
document was developed with a focus on gas distribution lines.
Furthermore, although both documents apply to pipelines, they do not
take full account of gas distribution line features as comments suggest
they should to treat gas distribution lines appropriately.

Given these considerations and the TPSSC\'s unanimous recommendation
that we not apply the proposed direct assessment standards to gas
distribution lines, we decided to exclude distribution lines from final
§192.490. Removing "pipeline\'\' from the proposed wording and adding
"transmission line\'\' in its place accomplishes this change.

*Would the proposed standards discourage the voluntary use of corrosion
control methods?* AGA, Armstrong, Duke, El Paso, GPTC, INGAA, NGA,
Nicor, NiSource, Paiute, PG&E, Puget, and SWGas were concerned the
proposed standards (§§ 192.490 and 195.588) would discourage operators
from voluntarily using corrosion control methods related to direct
assessment on pipelines not subject to the integrity management
regulations. Their concern stemmed from the difficulty of recognizing
when direct assessment is being used. They said performance of any one
of the four steps that constitute direct assessment could imply use of
direct assessment and lead to disagreements with government inspectors
over whether direct assessment is being used. For example, some
commenters said performing a close interval electrical survey resembled
the indirect examination step of direct assessment. Others thought
examining buried pipe for corrosion could be considered the direct
examination step. El Paso, INGAA, Nicor, and Armstrong suggested the
Final Rule clarify that operators may use corrosion control methods
related to direct assessment without having to meet the proposed direct
assessment standards.

We recognize disagreements could arise over whether the use of a
corrosion control method is part of the direct assessment process.
However, we do not think such disagreements are likely to be serious
enough to discourage operators from continuing to use such methods
separately from direct assessment. To minimize potential disagreements,
operators may explain in their corrosion control procedures the
situations in which they use methods related to direct assessment
separately from direct assessment.

In view of the commenters\' concern, PHMSA has added provisions to final
§§ 192.490 and 195.588 to clarify application of the direct assessment
standards. The statement provides that the direct assessment standards
do not apply to methods related to direct assessment, such as close
interval surveys, voltage gradient surveys, or examination of exposed
pipelines, when used separately from the direct assessment process. This
change is consistent with the TPSSC\'s second recommendation.

*Are the gas pipeline standards cross-referenced in proposed §195.588
suitable for hazardous liquid and carbon dioxide pipelines?* In their
comments on proposed §195.588, AOPL and API opposed cross-referencing §§
192.925 and 192.929 primarily because these standards refer to ASME
B31.8S-2001. They argued ASME B31.8S-2001 was developed for natural gas
transmission lines and without the involvement of hazardous liquid
pipeline operators. They were also concerned that cross-referencing part
192 gas pipeline standards could lead to misunderstandings by hazardous
liquid pipeline operators. The THLPSSC similarly opposed
cross-referencing part 192 standards.

In developing the NPRM, we assumed the cross-referenced part 192
standards and their cross-references to ASME B31.8S-2001 would be
suitable for hazardous liquid and carbon dioxide pipelines. However, the
AOPL and API comments and the THLPSSC\'s recommendation have caused us
to doubt that assumption. In addition, we are concerned that application
of the part 192 direct assessment standards to hazardous liquid and
carbon dioxide pipelines could present compliance problems. Contributing
to this concern is the comment that ASME B31.8S-2001 was not developed
with an eye to hazardous liquid pipelines. In fact, paragraph 1.1 of
ASME B31.8S-2001 specifically states that the scope of ASME B31.8S-2001
is limited to "onshore pipeline systems \* \* \* that transport gas.\'\'

Therefore, we decided not to include cross-references to part 192
standards or to ASME B31.8S-2001 in final §195.588. Instead, final
§195.588 includes a complete statement of direct assessment standards,
with cross-references only to NACE Standard RP0502-2002.

*Should the integrity management regulations for hazardous liquid and
carbon dioxide pipelines allow use of direct assessment without advance
notice?* The integrity management regulations for hazardous liquid and
carbon dioxide pipelines (§195.452) prescribe three ways to assess
pipeline integrity: internal inspection via a smart pig, pressure
testing, and any other technology the operator demonstrates can provide
an equivalent understanding of pipe conditions. However, before another
technology, such as direct assessment may be used, the operator must
notify PHMSA at least 90 days in advance (§§ 195.452(c)(1)(i)(C) and
195.452(j)(5)(iii)).

In contrast to §195.452, the proposed direct assessment standards do not
include a requirement to give 90 days\' advance notice as a precondition
to using direct assessment. We see no need to propose such a requirement
since the current Part 192 direct assessment standards do not require
operators to give advance notice before using direct assessment.

In their comments on proposed §195.588, AOPL and API suggested direct
assessment of external corrosion should be listed directly in §195.452
as a permissible method of integrity assessment. They believe that when
external corrosion direct assessment is performed according to NACE
Standard RP0502-2002, it is an acceptable use of "other technology\'\'
for which 90 days advance notice is no longer necessary. As discussed
above under Advisory Committee Recommendations, the THLPSSC also favored
listing direct assessment directly in §195.452 as a recognized
assessment method that would bypass the 90-day advance notice
requirement.

The purpose of the 90 days advance notice requirement in §195.452 is to
provide time for PHMSA and State pipeline safety agencies to review
technology other than pigging and pressure testing to learn what
information the technology provides about pipe conditions. According to
information on a PHMSA Web site
*(http://primis.PHMSA.dot.gov/iim/notifications.imd)*, several operators
have submitted notices of their intent to use direct assessment on
hazardous liquid or carbon dioxide pipelines. In a majority of cases,
there were no PHMSA or State government objections to the use of direct
assessment. Objections were raised where the notification lacked
information explaining how the direct assessment was to be performed.

When applied to direct assessment, we believe the 90-day advance notice
requirement of §195.452 is no longer useful and is inconsistent with the
proposed rules. Direct assessment is now being used under the part 192
integrity management regulations without advance notice. As a result,
government inspectors are fully aware of the direct assessment
technology and the situations for which it is suited, making advance
case-by-case review under §195.452 unnecessary. In addition, requiring
operators to follow prescribed standards when using direct assessment
will remove the primary objection previously raised about operators\'
advance notices---insufficient information to explain the method of
assessment. Therefore, we are changing §§ 195.452(c)(1)(i)(C) and
195.452(j)(5)(iii) to allow use of direct assessment in accordance with
final §195.588 without 90 days advance notice.

*What standard should apply to direct assessment of stress corrosion
cracking on hazardous liquid and carbon dioxide pipelines?* The NPRM
proposed that §192.929 be the standard for direct assessment of stress
corrosion cracking on hazardous liquid and carbon dioxide pipelines.
This standard relies largely on cross-references to ASME B31.8S-2001.

Besides their objections to cross-referencing part 192 standards and
particularly ASME B31.8S-2001, AOPL and API suggested that we not adopt
any standard for the direct assessment of stress corrosion cracking on
hazardous liquid pipelines. They said because methods of detecting
stress corrosion cracking are developing rapidly, direct assessment may
not be the optimum technology for hazardous liquid pipelines. The
THLPSSC recommended we consider adopting the consensus standard that
NACE International was developing for direct assessment of stress
corrosion cracking.

As explained above, we decided not to cross-reference directly or
indirectly ASME B31.8S-2001 in final §195.588, because the document is
closely identified with gas pipelines. Consequently, since provisions of
ASME B31.8S-2001 are an important part of the proposed stress corrosion
standard, we have not included a direct assessment standard for stress
corrosion cracking in final §195.588. As the THLPSSC recommended, we
will consider the recently published NACE Standard RP0204-2004, Stress
Corrosion Cracking (SCC) Direct Assessment Methodology, for possible
future rulemaking action. By removing the proposed cross-reference to
§192.929, final §195.588 consists of the text of §192.925 without its
cross-references to ASME B31.8S-2001.

**V. Editorial Changes**

● Final §§ 192.490 and 195.588 do not include the proposed phrase "or to
meet any requirement of this Subpart regarding that threat.\'\' The
phrase was used in the proposed rules to draw attention to situations in
which operators might choose to use direct assessment. However, the
phrase appears to be unnecessary and, according to comments, possibly
confusing.

● Final §192.490 clarifies that "direct assessment\'\' means direct
assessment as defined in §192.903.[^3] This definition applies to
"direct assessment\'\' as it is used in subpart O of part 192, including
§§ 192.925, 192.927, and 192.929---the bases of the proposed direct
assessment standards. Also, in final §192.490, instead of using the
proposed term "ferrous\'\' to limit pipelines to which the direct
assessment standards apply, we used "made primarily of steel or
iron.\'\' This change removes the possibility of confusion over the
meaning of ferrous.

● We added a similar definition of "direct assessment\'\' to §195.553,
which contains definitions applicable to subpart H of part 195,
including final §195.588. This addition satisfies the first THLPSSC
recommendation. The definition of "external corrosion direct
assessment,\'\' which was proposed through the cross-reference to
§192.925, is also added to §195.553.

● In final §195.588, we substituted "pipeline segment\'\' for the terms
"covered segment\'\' and "covered pipeline segment\'\' to avoid the
possibility that the definition of these terms in §192.903---a segment
of transmission pipeline located in a high consequence area---would
unintentionally constrain the scope of final §195.588. A footnote
resolves a similar problem in final §192.490.

● Section 192.925(b) provides that if coating damage is detected by
external corrosion direct assessment, the operator must integrate that
information with data gathered and integrated under certain other
requirements (§§ 192.917(b) and 192.917(e)(1)). These other
requirements, which involve evaluating and addressing risks besides
corrosion, including third-party damage, apply only to gas transmission
lines subject to the integrity management regulations in subpart O of
part 192. Although the proposed direct assessment standards for other
pipelines included cross-references to §192.925, the NPRM did not
address extending §§ 192.917(b) and 192.917(e)(1) to pipelines outside
subpart O by virtue of the cross-references. The focus of the NPRM was
strictly on using direct assessment to evaluate and address corrosion
risks. Using direct assessment data to evaluate non-corrosion risks to
pipeline integrity was not discussed. So it would be inappropriate to
infer that the proposed references to §192.925 meant that operators who
voluntarily use external corrosion direct assessment on pipelines
outside subpart O would also have to comply with §§ 192.917(b) and
192.917(e)(1). To ensure this possible inference does not affect the
Final Rules, final §§ 192.490 and 195.588 exclude pipelines outside
subpart O from the §192.925(b) requirement related to integrating
coating damage data. Nevertheless, for hazardous liquid and carbon
dioxide pipelines that are subject to the integrity management
regulations in §195.452, the detection of coating damage is an important
factor to consider in the information analysis required by §195.452(g)
and the continual integrity evaluation required by §195.452(j)(2).

**VI. Regulatory Analyses and Notices**

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

PHMSA has evaluated the costs and benefits of this Final Rule and a copy
of the evaluation is in the docket. The evaluation concludes operators
will incur only minimal costs to comply with the Final Rule.

*Regulatory Flexibility Act.* Under the Regulatory Flexibility Act (5
U.S.C. 601 et seq.), PHMSA must consider whether rulemaking actions have
a significant economic impact on a substantial number of small entities.
Based on the facts available about the anticipated impacts of this
rulemaking, I certify that this rulemaking will not have a significant
impact on a substantial number of small entities.

*Executive Order 13175.* PHMSA has analyzed this rulemaking according to
the principles and criteria contained in Executive Order 13175,
"Consultation and Coordination with Indian Tribal Governments.\'\'
Because the Final Rule will not significantly or uniquely affect the
communities of the Indian Tribal Governments nor impose substantial
direct compliance costs, the funding and consultation requirements of
Executive Order 13175 do not apply.

*Paperwork Reduction Act.* Operators have just recently begun to use
direct assessment to assess the effects of corrosion on onshore gas
transmission lines subject to the integrity management regulations in
subpart O of part 192. The use of direct assessment on other pipelines
regulated by part 192 or part 195 is voluntary. This Final Rule does not
change this voluntary use status. It merely sets standards for
performing direct assessment if operators choose to use it.

Pipeline operators covered by the Final Rule who choose to use direct
assessment would have to prepare appropriate plans and procedures and
keep records as required by Section 7 of *NACE Standard RP0502-2002*. To
help estimate the paperwork burden these operators would face, the NPRM
invited comments on how many operators plan to use direct assessment
voluntarily and what the burden hours and cost would be.

None of the commenters foresaw any voluntary use of direct assessment or
commented on the potential paperwork burden. This result was not a
surprise, for direct assessment is a new process and so far its use is
mostly limited to gas transmission lines subject to subpart O of part
192. Under these circumstances, it is reasonable to expect that few, if
any, operators will be affected by the Final Rule. So no net increase in
paperwork burdens is likely from this Final Rule. For this reason, we
believe that submitting an analysis of the burdens to OMB under the
Paperwork Reduction Act is unnecessary.

*Unfunded Mandates Reform Act of 1995*. This Final Rule does not impose
unfunded mandates under the Unfunded Mandates Reform Act of 1995. It
does 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 is the least burdensome alternative that achieves the
objective of the rulemaking.

*National Environmental Policy Act*. PHMSA has analyzed the Final Rule
for purposes of the National Environmental Policy Act (42 U.S.C. 4321 et
seq.). Because the Final Rule affects only those operators that
voluntarily use direct assessment and because it largely involves
processes of data collection and evaluation, we have determined that it
is unlikely to significantly affect the quality of the human
environment. An Environmental Assessment is available for review in the
docket.

*Executive Order 13132*. PHMSA has analyzed the Final Rule according to
the principles and criteria contained in Executive Order 13132,
"Federalism.\'\' No part of the rule (1) has substantial direct effects
on the States, the relationship between the national government and the
States, or the distribution of power and responsibilities among the
various levels of government; (2) imposes substantial direct compliance
costs on State and local governments; or (3) preempts State law.
Therefore, the consultation and funding requirements of Executive Order
13132 do not apply.

*Executive Order 13211*. This Final Rule 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**

*49 CFR Part 192*

Natural gas, Pipeline safety, Reporting and recordkeeping requirements.

*49 CFR Part 195*

Ammonia, Carbon dioxide, Incorporation by reference, Petroleum, Pipeline
safety, Reporting and recordkeeping requirements.

■ In consideration of the foregoing, PHMSA amends 49 CFR parts 192 and
195 as follows:

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

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

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

■ 2. Add §192.490 to read as follows:

**§192.490 Direct assessment.**

Each operator that uses direct assessment as defined in §192.903 on an
onshore transmission line made primarily of steel or iron to evaluate
the effects of a threat in the first column must carry out the direct
assessment according to the standard listed in the second column. These
standards do not apply to methods associated with direct assessment,
such as close interval surveys, voltage gradient surveys, or examination
of exposed pipelines, when used separately from the direct assessment
process.

  -------------------------------------------- --------------------------
  Threat                                       Standard^1^

  External corrosion                           §192.925^2^

  Internal corrosion in pipelines that         §192.927
  transport dry gas.                           

  Stress corrosion cracking                    §192.929
  -------------------------------------------- --------------------------

^1^For lines not subject to subpart O of this part, the terms "covered
segment\'\' and "covered pipeline segment\'\' in §§ 192.925, 192.927,
and 192.929 refer to the pipeline segment on which direct assessment is
performed.

^2^In §192.925(b), the provision regarding detection of coating damage
applies only to pipelines subject to subpart O of this part.

**PART 195---TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE**

■ 3. The authority citation for part 195 continues to read as follows:

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

■ 4. In §195.3(c), amend the table of referenced material by adding item
G.(2) to read as follows:

**§195.3 Matter incorporated by reference in whole or in part.**

\* \* \* \* \*

\(c\) \* \* \*

+----------------------------------+-----------------------------------+
| G. \* \* \*                      | \* \* \*                          |
|                                  |                                   |
| \(2\) NACE Standard RP0502-2002  | §195.588                          |
| "Pipeline External Corrosion     |                                   |
| Direct Assessment                |                                   |
| Methodology\'\' (2002).          |                                   |
+----------------------------------+-----------------------------------+

■ 5. Amend §195.452 as follows:

■ a. Redesignate paragraph (c)(1)(i)(C) as (c)(1)(i)(D);

■ b. Remove "or\'\' from the end of paragraph (c)(1)(i)(B);

■ c. Redesignate paragraph (j)(5)(iii) as (j)(5)(iv);

■ d. Remove "or\'\' from the end of paragraph (j)(5)(ii); and

■ e. Add new paragraphs (c)(1)(i)(C) and (j)(5)(iii) to read as follows:

**§195.452 Pipeline integrity management in high consequence areas.**

\* \* \* \* \*

\(c\) \* \* \*

\(1\) \* \* \*

\(i\) \* \* \*

\(C\) External corrosion direct assessment in accordance with §195.588;
or

\* \* \* \* \*

\(j\) \* \* \*

\(5\) \* \* \*

\(iii\) External corrosion direct assessment in accordance with
§195.588; or

\* \* \* \* \*

■ 6. In §195.553, add definitions for "direct assessment\'\' and
"external corrosion direct assessment (ECDA)\'\' as follows:

**§195.553 What special definitions apply to this Subpart?**

\* \* \* \* \*

*Direct assessment* means an integrity assessment method that utilizes a
process to evaluate certain threats (i.e., external corrosion, internal
corrosion and stress corrosion cracking) to a pipeline segment\'s
integrity. The process includes the gathering and integration of risk
factor data, indirect examination or analysis to identify areas of
suspected corrosion, direct examination of the pipeline in these areas,
and post assessment evaluation.\* \* \* \* \*

*External corrosion direct assessment (ECDA)* means a four-step process
that combines pre-assessment, indirect inspection, direct examination,
and post-assessment to evaluate the threat of external corrosion to the
integrity of a pipeline.

\* \* \* \* \*

■ 7. Add §195.588 to read as follows:

**§195.588 What standards apply to direct assessment?**

\(a\) If you use direct assessment on an onshore pipeline to evaluate
the effects of external corrosion, you must follow the requirements of
this section for performing external corrosion direct assessment. This
section does not apply to methods associated with direct assessment,
such as close interval surveys, voltage gradient surveys, or examination
of exposed pipelines, when used separately from the direct assessment
process.

\(b\) The requirements for performing external corrosion direct
assessment are as follows:

\(1\) *General.* You must follow the requirements of NACE Standard
RP0502-2002 (incorporated by reference, see §195.3). Also, you must
develop and implement an ECDA plan that includes procedures addressing
pre-assessment, indirect examination, direct examination, and
post-assessment.

\(2\) *Pre-assessment*. In addition to the requirements in Section 3 of
NACE Standard RP0502-2002, the ECDA plan procedures for pre-assessment
must include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;

\(ii\) The basis on which you select at least two different, but
complementary, indirect assessment tools to assess each ECDA region; and

\(iii\) If you utilize an indirect inspection method not described in
Appendix A of NACE Standard RP0502-2002, you must demonstrate the
applicability, validation basis, equipment used, application procedure,
and utilization of data for the inspection method.

\(3\) *Indirect examination*. In addition to the requirements in Section
4 of NACE Standard RP0502-2002, the procedures for indirect examination
of the ECDA regions must include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;

\(ii\) Criteria for identifying and documenting those indications that
must be considered for excavation and direct examination, including at
least the following:

\(A\) The known sensitivities of assessment tools;

\(B\) The procedures for using each tool; and

\(C\) The approach to be used for decreasing the physical spacing of
indirect assessment tool readings when the presence of a defect is
suspected;

\(iii\) For each indication identified during the indirect examination,
criteria for---

\(A\) Defining the urgency of excavation and direct examination of the
indication; and

\(B\) Defining the excavation urgency as immediate, scheduled, or
monitored; and

\(iv\) Criteria for scheduling excavations of indications in each
urgency level.

\(4\) *Direct examination*. In addition to the requirements in Section 5
of NACE Standard RP0502-2002, the procedures for direct examination of
indications from the indirect examination must include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;

\(ii\) Criteria for deciding what action should be taken if either:

\(A\) Corrosion defects are discovered that exceed allowable limits
(Section 5.5.2.2 of NACE Standard RP0502-2002 provides guidance for
criteria); or

\(B\) Root cause analysis reveals conditions for which ECDA is not
suitable (Section 5.6.2 of NACE Standard RP0502-2002 provides guidance
for criteria);

\(iii\) Criteria and notification procedures for any changes in the ECDA
plan, including changes that affect the severity classification, the
priority of direct examination, and the time frame for direct
examination of indications; and

\(iv\) Criteria that describe how and on what basis you will reclassify
and re-prioritize any of the provisions specified in Section 5.9 of NACE
Standard RP0502-2002.

\(5\) *Post assessment and continuing evaluation.* In addition to the
requirements in Section 6 of NACE Standard UP 0502-2002, the procedures
for post assessment of the effectiveness of the ECDA process must
include---

\(i\) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in pipeline segments; and

\(ii\) Criteria for evaluating whether conditions discovered by direct
examination of indications in each ECDA region indicate a need for
reassessment of the pipeline segment at an interval less than that
specified in Sections 6.2 and 6.3 of NACE Standard RP0502-2002 (see
Appendix D of NACE Standard RP0502-2002).

#  Issued in Washington, DC, on October 19, 2005.

# Brigham A. McCown,

# *Acting Administrator, **PHMSA**.*

# \[FR Doc. 05-21233 Filed 10-24-05; 8:45 am\]

# 

# BILLING CODE 4910-60-P

[^1]: The Norman Y. Mineta Research and Special Programs Improvement Act
    (Pub. L. 108-426, 118; November 30, 2004) reorganized RSPA into two
    new DOT administrations: the Pipeline and Hazardous Materials Safety
    Administration (PHMSA) and the Research and Innovative Technology
    Administration. RSPA\'s regulatory authority over pipeline and
    hazardous materials safety was transferred to PHMSA.

[^2]: The standard on external corrosion direct assessment § 192.925)
    requires operators to integrate data on physical characteristics and
    operating history, conduct indirect aboveground inspections,
    directly examine pipe surfaces, and evaluate the effectiveness of
    the assessment process. Under the standard for direct assessment of
    internal corrosion (§ 192.927), operators must predict locations
    where electrolytes may accumulate in normally dry-gas pipelines,
    examine those locations, and validate the assessment process. The
    standard for direct assessment of stress corrosion cracking (§
    192.929) involves collecting data relevant to stress corrosion
    cracking, assessing the risk of pipeline segments, and examining and
    evaluating segments at risk.

[^3]: Section 192.903 defines "direct assessment\'\' as "an integrity
    assessment method that utilizes a process to evaluate certain
    threats (i.e., external corrosion, internal corrosion and stress
    corrosion cracking) to a covered pipeline segment\'s intergrity. The
    process includes the gathering and integration of risk factor data,
    indirect examination or analysis to identify areas of suspected
    corrosion, direct examination of the pipeline in these areas, and
    post assessment evaluation.\'\'